# U.S. DOT/PHMSA - Final Environmental Assessment of the Longhorn Pipeline Reversal - Volume 1 of 2: Chapters 1-6 **Citation:** 09000064811add8f **Type / status:** rulemaking / current **Agency:** Pipeline and Hazardous Materials Safety Administration **Effective:** Not stated **Published:** Not stated FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL VOLUME 1: CHAPTERS 1 - 6 PHMSA-2012-0175 December 2012 FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.3.3.5 Process Hazard Analysis ....................................................... 5-37 5.3.3.6 Preventive and Mitigative Measures Analysis ........................ 5-38 5.3.4 CONTROL SYSTEMS (SCADA)... ## Document text <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL VOLUME 1: CHAPTERS 1 - 6 PHMSA-2012-0175 December 2012 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL CONTENTS 1.0 INTRODUCTION .................................................................................................. 1-1 1.1 THE ENVIRONMENTAL ASSESSMENT PROCESS.......................................................... 1-1 1.2 PROJECT DESCRIPTION ............................................................................................ 1-1 1.3 ROLE OF FEDERAL AGENCIES ................................................................................... 1-2 1.4 ORGANIZATION OF THE FEA ..................................................................................... 1-3 2.0 PURPOSE AND NEED FOR THE PROPOSED PROJECT ................................ 2-1 2.1 PURPOSE ................................................................................................................. 2-1 2.2 NEED ....................................................................................................................... 2-1 3.0 DESCRIPTION OF PROPOSED PROJECT, CONNECTED ACTIONS, AND ALTERNATIVES ......................................................................................... 3-1 3.1 DESCRIPTION OF THE PROPOSED PROJECT ............................................................... 3-1 3.1.1 PROJECT OVERVIEW ..................................................................................... 3-1 3.1.2 PROJECT DETAIL .......................................................................................... 3-2 3.2 CONNECTED ACTIONS .............................................................................................. 3-5 3.3 3.2.1 ORION EXPANSION ........................................................................................ 3-5 3.2.2 3.2.3 3.2.4 3.2.5 ODESSA TO CRANE ....................................................................................... 3-6 EL PASO GATEWAY ....................................................................................... 3-6 CRANE TO EL PASO ...................................................................................... 3-6 9TH STREET JUNCTION TO SPEED JUNCTION ................................................... 3-6 3.2.6 EAST HOUSTON TO HOLLAND AVENUE ........................................................... 3-6 OPERATION AND MAINTENANCE ................................................................................ 3-6 3.4 3.3.1 PROPOSED PROJECT .................................................................................... 3-6 3.3.2 CONNECTED ACTIONS ................................................................................... 3-8 ELIMINATION OF ALTERNATIVES FROM DETAILED CONSIDERATION ............................ 3-8 3.5 NO-ACTION ALTERNATIVE ........................................................................................ 3-9 4.0 AFFECTED ENVIRONMENT ............................................................................... 4-1 4.1 HUMAN RESOURCES AND LAND USES ....................................................................... 4-1 4.1.1 REGIONAL SETTING ...................................................................................... 4-1 4.1.1.1 4.1.1.2 4.1.1.3 Potentially Affected Communities ............................................ 4-2 Regional Land Uses ................................................................. 4-3 Regional Population Density .................................................... 4-4 4.1.1.3.1 Housing .............................................................. 4-4 4.1.1.3.2 Population .......................................................... 4-5 4.1.1.4 Transportation Networks .......................................................... 4-5 4.1.1.5 Parks and Natural Areas .......................................................... 4-5 4.1.2 OTHER RECEPTORS IN THE HOUSTON AND AUSTIN AREAS ............................. 4-6 4.1.2.1 Houston Area ........................................................................... 4-6 4.1.2.1.1 Special Use Areas ............................................. 4-6 4.1.2.2 Austin Area .............................................................................. 4-6 4.1.2.2.1 Special Use Areas ............................................. 4-7 I <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 4.2 PHYSICAL RESOURCES ............................................................................................. 4-7 4.2.1 GROUNDWATER RESOURCES ........................................................................ 4-7 4.2.1.1 Aquifers Traversed by the Zone of Potential Impact and General Nature ........................................................................ 4-7 4.2.1.2 Relative Vulnerability of Aquifers within the Zone of Potential Impact ....................................................................... 4-8 4.2.1.2.1 Relative Aquifer Vulnerability Evaluation Methodologies .................................................... 4-8 4.2.1.2.2 Relative Aquifer Vulnerability Evaluation ......... 4-11 4.2.1.3 Potentially Vulnerable Public Water Supply (PWS) Water Wells ...................................................................................... 4-22 4.2.1.4 Identification of Sensitive Groundwater Resource Areas ....... 4-24 4.2.2 SURFACE WATER ........................................................................................ 4-26 4.2.2.1 Description of Surface Water Resources ............................... 4-26 4.2.2.1.1 Description of Significant Stream Crossings Along Route .................................... 4-27 4.2.2.1.2 Water Quality Downstream of Pipeline Crossings ......................................................... 4-29 4.2.2.1.3 Identification of Downstream Water Users ....... 4-30 4.2.2.2 Surface Water Resources, Including Vulnerable Areas ......... 4-34 4.2.2.2.1 Data Sources ................................................... 4-34 4.2.2.2.2 Identification of Surface Water Vulnerability to Spills ............................................................ 4-35 4.2.2.2.2.1 Spill Mobility ..................................................... 4-35 4.2.2.2.2.2 Ability to Contain and Remediate a Spill .......... 4-37 4.2.2.2.2.3 Relative Importance of Potentially Impacted Surface Waters ................................ 4-37 4.2.2.2.3 Summary Ranking of Stream Vulnerabilities ................................................... 4-38 4.2.2.3 Wetlands ................................................................................ 4-38 4.2.3 GEOLOGIC HAZARDS ................................................................................... 4-39 4.2.3.1 Earthquake/Seismic Hazards ................................................. 4-40 4.2.3.2 Landslide/Mass Movement Hazards ...................................... 4-40 4.2.3.3 Faulting/Subsidence Hazards ................................................ 4-40 4.2.3.4 Soil Stress Hazards ............................................................... 4-41 4.2.3.5 Scour at Stream Crossings .................................................... 4-41 4.2.4 CLIMATE AND AIR QUALITY .......................................................................... 4-41 4.2.4.1 Climate ................................................................................... 4-41 4.2.4.2 Air Quality .............................................................................. 4-42 4.3 ECOLOGICAL RESOURCES ...................................................................................... 4-44 4.3.1 TERRESTRIAL RESOURCES .......................................................................... 4-44 4.3.1.1 Terrestrial Fauna and Flora ................................................... 4-45 4.3.2 AQUATIC RESOURCES ................................................................................. 4-48 4.3.2.1 Aquatic Fauna and Flora ........................................................ 4-51 4.3.2.1.1 San Jacinto River Basin ................................... 4-52 II <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 4.3.2.1.2 4.3.2.1.3 Brazos River Basin .......................................... 4-53 Colorado River Basin ....................................... 4-53 4.3.3 THREATENED AND ENDANGERED SPECIES ................................................... 4-54 4.3.3.1 4.3.3.2 Protected Terrestrial Species ................................................. 4-55 Federally Protected Species .................................................. 4-56 4.3.3.2.1 State Protected Species .................................. 4-57 4.4 CULTURAL RESOURCES ......................................................................................... 4-59 4.4.1 PIPELINES................................................................................................ 4-59 4.4.1.1 Proposed Project (East Houston to Crane) ............................ 4-59 4.4.2 PUMP STATIONS ..................................................................................... 4-64 4.4.2.1 Buckhorn Station .................................................................... 4-64 4.4.2.2 Industry Station ...................................................................... 4-64 4.4.2.3 Warda Station ........................................................................ 4-64 4.4.2.4 Bastrop Station ...................................................................... 4-65 4.4.2.5 Eckert Station ......................................................................... 4-65 4.4.2.6 James River Station ............................................................... 4-65 4.4.2.7 Cartman Station ..................................................................... 4-66 4.4.2.8 Barnhart Station ..................................................................... 4-66 4.4.2.9 Texon Station ......................................................................... 4-66 4.4.2.10 East Houston Terminal .......................................................... 4-66 4.5 REFERENCES ......................................................................................................... 4-67 5.0 PIPELINE INTEGRITY ANALYSIS ...................................................................... 5-1 5.1 INTRODUCTION ......................................................................................................... 5-1 5.1.1 APPLICABLE REGULATIONS ........................................................................... 5-2 5.1.1.1 5.1.1.2 5.1.1.3 Pipeline Safety Regulations ..................................................... 5-3 Longhorn Mitigation Plan (LMP) .............................................. 5-3 National Oil and Hazardous Substance Pollution Contingency Plan ..................................................................... 5-3 5.1.1.4 Spill Prevention, Control, and Countermeasures Plan (SPCC) ..................................................................................... 5-4 5.1.1.5 Hazardous Waste Operations and Emergency Response (HAZWOPER) .......................................................................... 5-4 5.1.1.6 Transportation Security Administration (TSA) Pipeline Security .................................................................................... 5-4 5.1.2 INFORMATION ANALYZED ............................................................................... 5-4 5.1.2.1 Key Documents ........................................................................ 5-5 5.1.2.2 Databases ................................................................................ 5-6 5.2 CONSTRUCTION/EXISTING SYSTEM ........................................................................... 5-6 5.2.1 GENERAL ATTRIBUTES .................................................................................. 5-6 5.2.2 5.2.3 5.2.4 5.2.5 EFFECTS OF AGE .......................................................................................... 5-7 MANUFACTURING AND CONSTRUCTION METHODS .......................................... 5-8 COUNTERING AGE EFFECTS .......................................................................... 5-9 MAINTENANCE REPAIRS AND REHABILITATION ............................................. 5-10 5.2.6 FACILITIES .................................................................................................. 5-11 III <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.2.6.1 Tanks ..................................................................................... 5-11 5.2.6.1.1 External or In-Service Inspections ................... 5-11 5.2.6.1.2 Internal or Out-of-Service Inspection ............... 5-11 5.2.6.2 Pump Stations ........................................................................ 5-11 5.2.6.3 Mainline Block Valves ............................................................ 5-12 5.3 NORMAL OPERATIONS ............................................................................................ 5-13 5.3.1 THREATS .................................................................................................... 5-14 5.3.1.1 Commodity Characteristics .................................................... 5-14 5.3.1.2 Internal Corrosion .................................................................. 5-14 5.3.1.3 Hydrogen Blistering ................................................................ 5-15 5.3.1.4 Surge and Hydraulic Profile ................................................... 5-16 5.3.1.5 Cracking/Fatigue Monitoring .................................................. 5-18 5.3.1.6 Stress Corrosion Cracking (SCC) .......................................... 5-18 5.3.1.7 Incorrect Operations .............................................................. 5-19 5.3.1.8 Security .................................................................................. 5-19 5.3.1.9 Atmospheric Corrosion .......................................................... 5-19 5.3.1.10 External Corrosion ................................................................. 5-20 5.3.1.10.1 Pipe Coating. ................................................... 5-21 5.3.1.10.2 Cathodic Protection .......................................... 5-22 5.3.1.10.3 IR Drop (CP Voltage Measurement Criteria) ............................................................ 5-23 5.3.1.10.4 Casings ............................................................ 5-24 5.3.1.10.5 Microbiologically Influenced Corrosion (MIC) ................................................................ 5-25 5.3.1.10.6 AC Induced Corrosion. ..................................... 5-25 5.3.1.10.7 Stray Currents .................................................. 5-26 5.3.1.10.8 Selective Seam Corrosion ............................... 5-26 5.3.1.11 Third Party Damage ............................................................... 5-27 5.3.1.11.1 One Call ........................................................... 5-27 5.3.1.11.2 Public Education .............................................. 5-27 5.3.1.11.3 Excavator Education ........................................ 5-28 5.3.1.11.4 Depth of Cover and Exposed Pipe ................... 5-29 5.3.1.11.5 Pipeline Markers .............................................. 5-30 5.3.1.11.6 Pipeline Surveillance ........................................ 5-30 5.3.1.11.7 Encroachments and ROW Maintenance .......... 5-31 5.3.1.12 External Forces ...................................................................... 5-31 5.3.1.12.1 Flooding ........................................................... 5-32 5.3.1.12.2 Geohazards ..................................................... 5-32 5.3.1.12.3 Crossings ......................................................... 5-32 5.3.2 5.3.3 STAFFING AND TRAINING ............................................................................. 5-33 RISK ASSESSMENT PROCESSES .................................................................. 5-33 5.3.3.1 Operational Reliability Assessment (ORA) ............................ 5-34 5.3.3.2 Data Management ................................................................. 5-35 5.3.3.3 Pipeline Risk Assessment ...................................................... 5-36 5.3.3.4 Facility Risk Assessment ....................................................... 5-37 IV <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.3.3.5 Process Hazard Analysis ....................................................... 5-37 5.3.3.6 Preventive and Mitigative Measures Analysis ........................ 5-38 5.3.4 CONTROL SYSTEMS (SCADA) .................................................................... 5-38 5.3.4.1 Leak Detection ....................................................................... 5-39 5.3.4.2 Control Room Procedures ..................................................... 5-41 5.3.5 PIPELINE INSPECTION AND TESTING ............................................................ 5-41 5.3.5.1 Pressure Testing .................................................................... 5-42 5.3.5.2 In-Line Inspection (ILI) ........................................................... 5-43 5.3.5.2.1 ILI Findings ...................................................... 5-44 5.3.5.2.2 Follow-up Excavations ..................................... 5-46 5.3.5.3 Visual and NDE Inspections .................................................. 5-47 5.4 ACCIDENTAL RELEASES ......................................................................................... 5-47 5.4.1 LEAK ANALYSIS ........................................................................................... 5-47 5.4.1.1 Leak Causes .......................................................................... 5-47 5.4.1.2 Comparisons with Other Pipeline Leak Data ......................... 5-48 5.4.2 SPILL AND EMERGENCY RESPONSE PLAN .................................................... 5-48 5.4.2.1 Compliance with Regulations ................................................. 5-48 5.4.2.2 Sensitive Areas Response ..................................................... 5-50 5.4.2.3 Recent Emergency Response Experience ............................ 5-52 5.4.2.4 Trench Integrity Assessment – Edwards Aquifer Recharge Zone ...................................................................... 5-52 5.4.3 CONSEQUENCE POTENTIAL (COF) ............................................................... 5-53 5.5 CONCLUSIONS ........................................................................................................ 5-54 5.6 REFERENCES ......................................................................................................... 5-54 6.0 PIPELINE RISK ASSESSMENT .......................................................................... 6-1 6.1 INTRODUCTION ......................................................................................................... 6-1 6.2 THREATS .................................................................................................................. 6-1 6.2.1.1 Internal Corrosion .................................................................... 6-2 6.2.1.2 Hydrogen Blistering .................................................................. 6-5 6.2.1.3 Surge and Hydraulic Profile ..................................................... 6-6 6.2.1.4 Cracking/ Fatigue Monitoring ................................................... 6-7 6.2.1.5 Stress Corrosion Cracking (SCC) ............................................ 6-8 6.2.1.6 Incorrect Operations ................................................................ 6-8 6.2.1.7 Security .................................................................................... 6-9 6.2.1.8 Atmospheric Corrosion .......................................................... 6-10 6.2.1.9 External Corrosion ................................................................. 6-10 6.2.1.9.1 Pipe Coatings ................................................... 6-11 6.2.1.9.2 Cathodic Protection and CP Verifications ........ 6-11 6.2.1.9.3 IR Drop (CP Voltage Measurement Criteria) ............................................................ 6-12 6.2.1.9.4 Casings ............................................................ 6-13 6.2.1.9.5 Microbiological Influenced Corrosion (MIC) ..... 6-13 6.2.1.9.6 AC Induced Corrosion ...................................... 6-14 6.2.1.9.7 Stray Currents .................................................. 6-14 V <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 6.2.1.9.8 Selective Seam Corrosion (SSC) ..................... 6-15 6.2.1.10 Third Party Damage ............................................................... 6-15 6.2.1.10.1 One Call ........................................................... 6-16 6.2.1.10.2 Public Education .............................................. 6-16 6.2.1.10.3 Excavator Education ........................................ 6-17 6.2.1.10.4 Depth of Cover and Exposed Pipe ................... 6-18 6.2.1.10.5 Pipeline Markers .............................................. 6-18 6.2.1.10.6 Pipeline Surveillance ........................................ 6-19 6.2.1.10.7 Encroachments and ROW Maintenance .......... 6-19 6.2.1.11 External Forces ...................................................................... 6-20 6.2.1.11.1 Flooding ........................................................... 6-20 6.2.1.11.2 Geohazards ..................................................... 6-21 6.2.1.11.3 Crossings ......................................................... 6-21 6.2.2 6.2.3 STAFFING AND TRAINING ............................................................................. 6-21 RISK ASSESSMENT PROCESSES .................................................................. 6-21 6.2.3.1 ORA ....................................................................................... 6-21 6.2.3.2 Data Management ................................................................. 6-22 6.2.3.3 Pipeline Risk Assessment ...................................................... 6-22 6.2.3.4 Facility Risk Assessment ....................................................... 6-22 6.2.3.5 PHA/LOPA ............................................................................. 6-23 6.2.4 CONTROL SYSTEMS (SCADA) .................................................................... 6-23 6.2.4.1 Leak Detection ....................................................................... 6-23 6.2.4.2 Control Room Procedures ..................................................... 6-24 6.2.5 PIPELINE INSPECTION AND TESTING ............................................................ 6-24 6.2.5.1 Pressure Testing .................................................................... 6-24 6.2.5.2 In-Line Inspections (ILI) ......................................................... 6-25 6.2.6 SPILL AND EMERGENCY RESPONSE PLANS .................................................. 6-25 6.2.7 WORST CASE SPILL VOLUME ...................................................................... 6-25 6.3 CONSEQUENCE POTENTIAL (COF) .......................................................................... 6-26 6.4 CONCLUSIONS ........................................................................................................ 6-27 6.5 REFERENCES ......................................................................................................... 6-27 VI <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL TABLES Table 4.1.1-1 Apartment Facilities within the Zone of Potential Impact of Proposed Project Table 4.1.1-2 Population within the Zone of Potential Impact of Proposed Project by MP Segment Table 4.1.2-1 Vulnerable Receptors within the Zone of Potential Impact of the Proposed Project in the Houston Area Table 4.1.2-2 Vulnerable Receptors within the Zone of Potential Impact of the Proposed Project in the Austin Area Table 4.2.1-1 Table 4.2.1-2 Aquifers Within the Zone of Potential Impact of the Proposed Project TCEQ Aquifer Average DRASTIC Index and Vulnerability Ranking of Aquifers within the Zone of Potential Impact of the Proposed Project Table 4.2.1-3 Pettyjohn et. al. Aquifer Classification and Vulnerability of Aquifers Within the Zone of Potential Impact of the Proposed Project Table 4.2.1-4 Table 4.2.1-5 Table 4.2.2-1 Groundwater Resource Area Sensitivity Ranking Public Water Supply Wells Within the Zone of Potential Impact Summary of Chemical Analyses on Surface Water Samples from STORET Stations Within the Zone of Potential Impact of the Proposed Project Table 4.2.2-2 Summary of 2008 Texas 303(d) Stream Segments Within the Zone of Potential Impact of the Proposed Project Table 4.2.2-3 Distances from Stream Crossings to Downstream Water Rights Within the Zone of Potential Impact of the Proposed Project Table 4.2.2-4 Table 4.2.2-5 Table 4.2.2-6 Ranking of Stream Crossings in Terms of Spill Transport Potential Ranking of Stream Crossings in Terms of Spill Control Potential Ranking of Stream Crossings in Terms of Downstream Resource Importance as a Water Supply Table 4.2.2-7 Table 4.2.2-8 Summary of Vulnerability Rankings, Surface Water Crossings Wetlands Inventory for Proposed Project from East Houston/9th Street Junction to Crane Table 4.3.1-1 Threatened and Endangered Species of Possible Occurrence Within the Zone of Potential Impact of the Proposed Project1 Table 5.1.1-1 Compliance Audit Findings Table 5.2.1-1a Pipe Characteristics Table 5.2.1-1b Pipe Characteristics Detail by Manufacturer Table 5.2.1-1c Pipe Characteristics Detail by Coating Type Table 5.2.1-2 Overview of Pipeline Construction Specifications Table 5.2.6-1 Valve Locations and Types for the Longhorn Pipeline Table 5.2.6-2 Locations of Check Valves Installed per LCRA Settlement and Valve Studies Table 5.2.6-3 Estimated Maximum Release Volumes Table 5.3.1-1 ILI Tool Runs Table 5.3.1-2 ILI Features Summary Table 5.3.1-3 Pressure-Cycle-Induced Fatigue Cracking Analysis from the 2010 ORA for the Current Westward Product Flow Direction VII <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Table 5.3.1-4 Table 5.3.4-1 Table 5.3.4-1a Table 5.3.5-1 Table 5.3.5-2 Table 5.3.5-3 Table 5.3.5-4 Table 5.4.1-1 Table 5.4.1-2 Table 5.4.1-3 Table 5.4.1-4 Table 5.4.1-5 Table 5.4.1-6 Test Point Exceptions for 2011 Alarm and Shutdown Devices Leak Detection System Alarm and Response Table Basic Inspection and Test Methods Summary of Hydrostatic Tests Summary of Hydrostatic Tests (2005 to 2011) Summary of ILI Repair Criteria Pipeline and Facility Spill Data Since 2002 Summary of Cause of Release for Facilities Summary of Cause of Release for Pipeline (Not Facilities) Texas Reportable Incidents and Frequencies US Reportable Incidents and Frequencies Longhorn Reportable Incident Frequencies VIII <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL FIGURES Figure 3.1-1 Project Location of Longhorn Pipeline Figure 3.2-1a Project Location of Connected Actions Figure 3.2-1b Project Location of Connected Actions Figure 4.1.2-1a Houston Area Land Use and Housing Density Figure 4.1.2-1b Houston Area Land Use and Housing Density Figure 4.1.2-1c Houston Area Land Use and Housing Density Figure 4.1.2-1d Houston Area Land Use and Housing Density Figure 4.1.2-1e Houston Area Land Use and Housing Density Figure 4.1.2-1f Houston Area Land Use and Housing Density Figure 4.1.2-1g Houston Area Land Use and Housing Density Figure 4.1.2-1h Houston Area Land Use and Housing Density Figure 4.1.2-1i Houston Area Land Use and Housing Density Figure 4.1.2-2a Austin Area Land Use and Housing Density Figure 4.1.2-2b Austin Area Land Use and Housing Density Figure 4.1.2-2c Austin Area Land Use and Housing Density Figure 4.1.2-2d Austin Area Land Use and Housing Density Figure 4.1.2-2e Austin Area Land Use and Housing Density Figure 4.1.2-2f Austin Area Land Use and Housing Density Figure 4.1.2-2g Austin Area Land Use and Housing Density Figure 4.2.1-1 Major Aquifers Figure 4.2.1-2 Minor Aquifers Figure 4.2.1-3a Public Water Supply Wells within Zone of Impact Figure 4.2.1-3b Public Water Supply Wells within Zone of Impact Figure 4.2.1-3c Public Water Supply Wells within Zone of Impact Figure 4.2.1-3d Public Water Supply Wells within Zone of Impact Figure 4.2.2-1 Hydrography with Surface Water Rights per TCEQ Database Figure 4.2.2-2 Hydrography with STORET Stations Figure 4.2.2-3 Houston Area TMDLs Figure 4.2.2-4 Satsuma Area TMDLs Figure 4.2.2-5 Austin Area TMDLs Figure 4.2.2-6 Pedernales Falls State Park API Figure 4.2.2-7 Pipeline Crossings within Pedernales State Park API Figure 4.2.2-8 Surface Water Vulnerability Methodology Flow Chart Figure 4.3.1-1 ECO Regions IX <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDICES Appendix 3 SIP Overview Appendix 4A Highway and Railroad Crossings Appendix 4B Biological Assessment Appendix 4C Programmatic Agreement Appendix 4D SHPO Concurrence Letter Appendix 5A Referenced Procedures of the 2012 Magellan SIP Appendix 5B Valve Schematic Appendix 5C Trench Integrity and Construction Methodology of the Magellan Longhorn Pipeline from Mile Post 169.88 to 188.8 Appendix 5D Trench Integrity Inspection Report of the Magellan Longhorn Pipeline from Mile Post 169.88 to 173.38 Appendix 6A Risk Assessment Methodology Appendix 6B Crude Oil Specifications Appendix 6C EnhanceCo. Report Appendix 6D Drag Reducing Agent Material Safety Data Sheet Appendix 6E Referenced Procedures of the 2012 Magellan SIP Appendix 6F Surge Analysis Summary Appendix 6G Risk Implication Matrix Appendix 6H Spartan Engineering Report X <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL ACRONYMS µm Micrometers AAQS Ambient Air Quality Standards ACHP Advisory Council on Historic Preservation AHPA archeological high probability area APE area of potential effect API Area of Primary Influence BA Biological Assessment BEG Bureau of Economic Geology BFZ Balcones Fault Zone BG Block Group bgl below ground level BLM Bureau of Land Management BMP best management practices BO Biological Opinion bpd barrels per day BSEACD Barton Springs/Edwards Aquifer Conservation District CDC Center for Disease Control CDP census designated place CEQ Council on Environmental Quality CFR Code of Federal Regulations CO carbon monoxide CO2 carbon dioxide COA City of Austin CoF Consequence of Potential CP Cathodic Protection CPM Computational Pipeline Monitoring CT census tract DEM Digital Elevation Model DOC depth of cover DOI Department of Interior DOT US Department of Transportation DRASTIC EPA Methodology Standardized System used for evaluating groundwater EA Environmental Assessment EFRD emergency flow reduction devices EGP Electronic geometry pig EIS Environmental Impact Statement EJ Environmental Justice EO Executive Order EPA US Environmental Protection Agency ESA Endangered Species Act ESL Effects Screening Level XXX <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL FBE fusion bonded epoxy FEA Final Environmental Assessment FM Farm-to-Market FR Federal Register FRP Facility Response Plan ft2/d feet squared per day USFWS U.S. Fish and Wildlife Service GAM Groundwater Availability Modeling GHG greenhouse gas GIS Geographic Information System GLO General Land Office gpm gallons per minute GW groundwater H2S hydrogen sulfide HAP hazardous air pollutant HAZWOPER Hazardous Waste Operations and Emergency Response HC Hill Country HCA High Consequence Area HCFCD Harris County Flood Control District HHS Department of Health and Human Services HIC hydrogen induced cracking IH Interstate Highway ILI in-line inspection IMP Integrated Management Plan IP implementation plan LAER lowest achievable emission rate LCRA Lower Colorado River Authority LDAR leak detection and repair LMC Longhorn Mitigation Commitment LMP Longhorn Mitigation Plan LOPA layer of protection analysis LST Localized Significance Thresholds MASP maximum allowable surge pressure MCL maximum contaminant level mg/l milligrams per liter MIC microbiological influenced corrosion MOCR Management of Change Request MP milepost MS4 municipal separate storm sewer systems (MS4s) MSL mean sea level MTBE Methyl Tertiary Butyl Ether MUD Municipality Utility District NAAQS National Ambient Air Quality Standards NACE National Association of Corrosion Engineers XXXI <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL NAIP National Agricultural Inventory Program NDE non-destructive examination NEIC National Enforcement Investigations Center NEPA National Environmental Policy Act NFPA National Fire Protection Agency NHD National Hydrography Dataset NHPA National Historic Preservation Act NLCD National Land Cover Database NNSR nonattainment new source review NO2 nitrogen dioxide NOx oxides of nitrogen NPDES National Pollutant Discharge Elimination System NPMS National Pipeline Mapping System NPS National Park Service NRCS Natural Resources Conservation Service NRHP National Register of Historic Places NWI National Wetland Inventory O3 ozone OPS Office of Pipeline Safety ORA Operational Reliability Assessment OSHA Occupational Health and Safety Administration PA Programmatic Agreement Pb lead PGA peak ground acceleration PHA Process Hazard Analysis PHMSA Pipeline and Hazardous Materials Safety Administration PLDS pipeline leak detection system POE probability of exceedance PoF probability of failure PM particulate matter PM10 particulate matter with a diameter of 10 micrometers (um) or less PM2.5 particulate matter with a diameter of 2.5 micrometers (um) or less ppb parts per billion PWS Public Water System QRA quantitative risk assessment REMM Riparian Emergency Management Model ROW right-of-way RRC Texas Railroad Commission RSPA Research and Special Programs Administration SCADA Supervisory Control and Data Acquisition Systems SCAQMD South Coast Air Quality Management District SCC stress corrosion cracking SDWA Safe Drinking Water Act SHPO State Historic Preservation Officer XXXII <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL SIP System Integrity Plan SO2 sulfur dioxide SO4 Sulfates SPCC spill prevention, control, and countermeasure SSESR Site Specific Environmental Study Report STORET EPA database SWSA Source Water Susceptibility Assessment T&E threatened and endangered TAS Turpin & Sons, Inc. TCEQ Texas Commission on Environmental Quality TDS total dissolved solids TEA Texas Education Agency THC Texas Historical Commission THPO Tribal Historic Preservation Officer TMDL Total Maximum Daily Load TNRIS Texas Natural Resources Information System TPDES Texas Pollutant Discharge Elimination System TPWD Texas Parks and Wildlife Department TWDB Texas Water Development Board TxDOT Texas Department of Transportation TXNDD Texas Natural Diversity Database USACE United States Army Corp of Engineers USC United States Code USGS United States Geologic Survey UT University of Texas UTPB University of Texas Permian Basin VOC volatile organic compounds WCID Water Control and Improvement District WPP watershed protection plans WSD water supply district XXXIII <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 1.0 INTRODUCTION 1.1 THE ENVIRONMENTAL ASSESSMENT PROCESS The Pipeline and Hazardous Safety Administration (PHMSA) has prepared this final environmental assessment (FEA) in accordance with the National Environmental Policy Act (NEPA) (42 USC §§ 4321–4347) and the Council on Environmental Quality’s (CEQ) NEPA Implementing Regulations (40 CFR Parts 1500–1508). NEPA provides a framework to evaluate a proposed project or “Federal action” and the potential of that action to have significant effects the human environment. The NEPA process helps the decision maker and the public understand and evaluate the potential environmental impacts of a proposed action prior to an agency’s final decision on the proposal. Another goal of NEPA is to facilitate public involvement. Therefore, PHMSA prepared a draft FEA and sought comments from interested members of the public. This FEA reflects changes in responses to these comments. Additionally, a list of the comment’s and PHMSA’s responses are posted in the docket at regulations.gov, docket “PHMSA-2012-0175.” 1.2 PROJECT DESCRIPTION The existing Longhorn Pipeline runs from El Paso, Texas to Houston, Texas and is owned and operated by Magellan Pipeline Company, L.P (Magellan). The Longhorn Pipeline currently transports refined petroleum products east to west, from Houston to El Paso. The proposed project would convert a segment of the Longhorn Pipeline from Crane, Texas to East Houston, Texas to crude oil service and reverse the flow, so that crude oil would flow west to east, from Crane to Houston. Longhorn would continue to transport refined products east to west, from Crane to El Paso, by connecting to the existing Orion West Pipeline that is located to the north of the Longhorn Pipeline and runs from Frost, Texas to El Paso, Texas. In the proposed project, refined products would flow from the Orion West Pipeline to the Longhorn Pipeline via an existing pipeline segment from Odessa, Texas to Crane, Texas. The refined products would then enter the Longhorn Pipeline at Crane and flow west to El Paso. The Longhorn Pipeline System’s current operations are subject to the Longhorn Mitigation Plan (LMP). A summary of the Longhorn Mitigation Commitments is provided in Appendix 9A of this document. The LMP was developed following litigation regarding a reversal that took place in 2005. At that time, the Longhorn Pipeline transported crude oil west to east, and the proposed action was to reverse the flow to transport refined petroleum. As part of the LMP, the Research and Special Programs Administration (RSPA)1 and the U.S. Environmental Protection Agency (EPA), Region 6 agreed to conduct an “Enhanced EA”, (1999 EA) for that project. RSPA and EPA Region 6 issued a joint finding of no significant impact (FONSI) on November 3, 2000. The 1 At the time of the litigation, PHMSA was the Research and Special Programs Administration. 1-1 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 1999 EA and the FONSI documents are available of the EPA Region 6 website at http://www.epa.gov/region6/6en/xp/longhorn.htm. Although PHMSA does not normally serve as a lead agency for pipeline construction projects because it has no authority over pipeline siting, the LMP includes a provision for NEPA adherence for some future construction activities. Therefore, PHMSA has prepared this FEA for the proposed changes to the pipeline. Although this EA is independent of the 1999 EA, PHMSA incorporates applicable sections within the 1999 EA by reference to avoid repetitive discussions and focus on pertinent issues for discussion (40 CFR 1502.21). Like the 1999 EA, an environmental contractor helped prepare this FEA by assisting with the technical analyses and preparing drafts of the FEA. PHMSA approved the hiring of Zephyr Environmental Corporation (hereinafter, Contractor), which is based in Austin, Texas, to prepare drafts of this FEA. Magellan funded the technical analyses performed by the Contractor. This arrangement puts the cost burden on the project proponent while ensuring that the study direction and decision-making is solely in the control of the Federal Government. 1.3 ROLE OF FEDERAL AGENCIES PHMSA is responsible for regulating the transportation of hazardous liquids via pipeline pursuant to the Pipeline Safety Laws, 49 USC § 60101 et seq. PHMSA has promulgated and enforces the Pipeline Safety Regulations that dictate requirements for construction, design, testing, operation, and maintenance of hazardous liquid (including crude oil, petroleum products, and anhydrous ammonia) pipelines. 49 CFR Parts 190, 195, and 199. PHMSA does not typically serve as lead agency for pipeline construction projects, as it has no authority over pipeline siting and does not issue any approval or authorization to commence a pipeline construction project. Under the Clean Water Act (CWA), as amended by the Oil Pollution Act, PHMSA has responsibility for review and approval of oil spill response plans for transportation-related onshore pipeline facilities. The CWA and PHMSA’s oil spill response plan regulations dictate the criteria required for approval of spill response plans. 33 USC §§ 1231, 1321; 49 CFR Part 194. EPA, Region 6 served as co-lead agency for the 1999 EA. On January 31, 2011, PHMSA invited EPA, Region 6 to serve as a cooperating agency, and EPA accepted on February 10, 2011. The Proposed Project is not federally owned, operated, or funded. It is a private undertaking initiated by Magellan. Neither PHMSA nor EPA has the statutory authority to grant overall project approval or to determine the routing or placement of pipelines. The final agency action in this matter will be the issuance of a Finding of No Significant Impact (FONSI). 1-2 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 1.4 ORGANIZATION OF THE FEA The body of this FEA includes Chapters 1 through 9 that are written to be consistent with the structure of the 1999 EA in order to facilitate comparison of the two documents. Each chapter in this EA references applicable information from the 1999 EA, provides updated or new information where applicable, and summarizes information as appropriate. A tenth chapter has been added to include a thorough evaluation of Connected Actions to the Proposed Project (Connected Actions). Chapter 11 has been added to evaluate cumulative impacts that may result from the Proposed Project and Connected Actions and other substantial projects. The contents of these chapters are described below: • Chapter 1 - Introduction: This chapter of the FEA provides a brief description of the environmental process, references the 1999 EA, describes the roles of the lead agency, and describes the organization of this FEA. • Chapter 2 - Purpose and Need for the Proposed Project: This chapter describes the purpose and the underlying needs for the currently proposed project. • Chapter 3 - Description of the Proposed Project and Alternatives: This chapter describes the proposed features of the project and the alternatives. It identifies the route, operation and maintenance, control systems, and the construction of Connected Actions. • Chapter 4 - Affected Environment: This chapter describes the existing environment for each component of the Proposed Project. Reference is made to pertinent information provided in the 1999 EA, providing summary of information, updated information, and new information as necessary. This chapter focuses on those resources that are considered sensitive from both public safety and environmental impact criteria. • Chapter 5 - Pipeline Integrity Analysis: This chapter discusses the integrity of the existing pipeline system. • Chapter 6 - Overall Pipeline Risk Assessment: This chapter is a probabilistic risk assessment of the integrity for the entire Longhorn Pipeline with greater emphasis on those areas deemed sensitive. This risk assessment seeks to identify the probability and magnitude of product releases along the pipeline. • Chapter 7 - Potential Impacts Analysis: For the Longhorn portion of the project, Chapter 7 draws from Chapter 6 to describe how potential releases could affect human safety, water quality, wildlife, and other environmental assessment categories. Potential impacts to relevant resources are provided for all components of the project. • Chapter 8 - Environmental Justice: This chapter describes whether the impacts described in Chapter 7 disproportionately affect minority and low-income populations. 1-3 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • Chapter 9 - Analysis of Mitigation: This chapter identifies and provides analyses of mitigation activities for the Proposed Project. • Chapter 10 - Connected Actions: This chapter describes the existing environment and potential impacts analysis for each of the Connected Actions of the Proposed Project. Like Chapter 4, this chapter focuses on those resources that are considered sensitive from both public safety and environmental impact criteria. It will also describe an assessment of risk as conducted within the current Integrated Management Plan (IMP). This information will be used to describe how potential releases could affect human safety, water quality, wildlife, and other environmental assessment categories consistent with NEPA review. Potential impacts to relevant resources are provided for all components of the Connected Actions. • Chapter 11 – Cumulative Impacts: This chapter describes potential cumulative impacts resulting from the Proposed Project and associated Connected Actions with the impacts of substantial projects within the zone of potential impact that have occurred in the past, are currently occurring, or are proposed for the reasonably foreseeable future. The evaluation focuses on resources potentially affected by the proposed project and uses information publicly available for other projects noting effects on the same resources. 1-4 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 2.0 PURPOSE AND NEED FOR THE PROPOSED PROJECT 2.1 PURPOSE The purpose of the Proposed Project is to allow West Texas crude oil and Eagle Ford shale production to be transported to Houston area refineries. The Connected Actions will expand access to the Proposed Project for transport of West Texas crude oil to Houston while allowing continued supply of refined petroleum products to El Paso, Texas. 2.2 NEED The Proposed Project would address the underlying need for West Texas and Eagle Ford shale crudes to be transported to Houston area refineries. Crude supply patterns are changing due to increased production in the West Texas area, oversupply of crude in Cushing, Oklahoma, and a relatively new crude and natural gas play in the Eagle Ford shale area. Permian Basin (West Texas) has shown steady increases in crude production primarily due to enhanced oil recovery techniques and this trend is projected to continue. The oversupply in Cushing, Oklahoma (where the majority of West Texas production moves today) was primarily caused by a new large diameter pipeline constructed from Canada into Cushing which has created an oversupply of crude for the mid-continent market. This oversupply has or will result in crude production to be stranded or pricing discounts for West Texas crude to move to this distribution hub. West Texas crude needs another outlet for their production, with Houston area refineries being the logical choice. The Eagle Ford shale area is evolving, but geographically the Longhorn Pipeline is a logical pipeline outlet for some of this crude production. In addition, there continues to be a need for Gulf Coast refined petroleum products to supply the El Paso, Texas; Juarez, Mexico; Albuquerque, New Mexico, and Arizona markets. These dynamics both for crude and refined products distribution have created the underlying basis for the Proposed Project and the Connected Actions. 2-1 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 3.0 DESCRIPTION OF PROPOSED PROJECT, CONNECTED ACTIONS, AND ALTERNATIVES This chapter provides a detailed description of the Proposed Project, Connected Actions, and Alternatives, including the No-Action Alternative. 3.1 DESCRIPTION OF THE PROPOSED PROJECT 3.1.1 Project Overview The Proposed Project will convert segments of Magellan’s existing Longhorn Pipeline (from Crane, Texas to Houston, Texas) into a crude oil pipeline and reverse the current flow to transport West Texas and Eagle Ford crude production to the U.S. Gulf Coast at Houston. The Proposed Project will require constructing and modifying infrastructure, but will not require constructing any new pipeline segments. The Proposed Project is defined as the existing pipeline and associated infrastructure requirements beginning at Crane, Texas and ending nine miles south of the existing East Houston Terminal (i.e. 9th Street Junction) (see Figure 3.1-1). The route generally goes east- southeast across parts of 18 counties. The Proposed Project will have an initial capacity of 134,000 barrels per day (bpd) of crude oil with the potential capacity to expand to 225,000 bpd. New pump stations are proposed to be constructed as capacity requirements are needed along the pipeline at Texon, Barnhart, Cartman, James River, Eckert, Bastrop, Warda, Industry, and Buckhorn Stations along with reversing the existing pump stations at Crane, Kimble County, Cedar Valley, and Satsuma Stations. New crude oil tanks (three 250,000-barrel tanks) and a truck unloading facility are proposed to be constructed at Crane Station. New crude oil tanks (six 250,000-barrel tanks), along with additional pumping capacity are also proposed to be constructed at East Houston Terminal. Magellan proposes to construct new infrastructure (metering stations, manifolds, etc.) at Crane, Texon, Barnhart, Bastrop, Warda, and Industry with the existing metering at East Houston Terminal reversed. The Proposed Project also anticipates conversion of existing check valves to emergency flow reduction devices (EFRD), potential replacement of existing mainline gate valves as needed, engineering reviews of surge pressure, leak modeling and detection, facility response plan and public education updates, along with other modifications necessary to comply with the LMP. All assets currently subject to the LMP will continue to be subject to the LMP. In other words, Magellan will continue to operate the existing pipeline assets and infrastructure that are part of the Proposed Project and subject to the LMP under the LMP. The Longhorn Pipeline segment remaining in refined products service (from Crane to El Paso and Odessa to Crane) will continue to be operated under the LMP. 3-1 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 3.1.2 Project Detail The Proposed Project will be conducted in two separate phases. Phase I will facilitate the reversal in flow direction, and Phase II will facilitate the expansion to a capacity of 225,000 bpd. The following section provides a brief itemized list of infrastructure improvements and construction needed in each phase. Phase I: The Longhorn Pipeline will be reversed from Crane to East Houston by modifying the piping at existing pump stations (Kimble County, Cedar Valley, Satsuma) along with adding a pump unit at the existing Crane station. Hydraulic analysis indicates that the maximum flow rate for the pipeline will be 134,000 bpd based upon the viscosity, gravity, and drag reducing agent (DRA) injection rate of the crude that will be transported. Crane Station: • A mainline unit consisting of pump and motor associated with boosting the product down the pipeline will be installed at Crane Station. • Drag Reducing Agent (DRA) will be installed downstream of the mainline unit. • A new meter station will be constructed to provide supervisory measurement for Crane to East Houston operations. • Three 50,000-bbl tanks currently in refined product service will be converted to crude service and three 250,000-bbl crude tanks will be constructed. • Tank lines to the unit suction manifold and metering will be installed. • A connection for third party facilities consisting of manifold and metering will be installed. • A crude unloading system to unload crude tank trucks into tankage will be installed. • A corrosion inhibitor injection system will be installed. Kimble Station: • The existing Kimble County Station will be re-piped to pump from Crane to East Houston. • DRA will be installed downstream of the mainline unit. • A pressure reducing valve will be installed to control static head pressure resulting from elevation changes. Cedar Valley Station: • The existing Cedar Valley Station will be re-piped to pump from Crane to East Houston. • DRA will be installed downstream of the mainline unit. • A pressure reducing valve will be installed to control static head pressure resulting from elevation changes. Bastrop Junction: • A pressure reducing valve will be installed to control static head pressure resulting from elevation changes. • DRA will be installed downstream of the pressure reducing valve. 3-2 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Satsuma Station: • The existing mainline unit at Satsuma will be taken out of service and re- piped to allow crude oil to flow to East Houston. • DRA will be installed downstream of the mainline unit. • A pressure reducing valve will be installed to control static head pressure resulting from elevation changes. Ft. McKavett, Warda, and Eckert Trap Sites: • Scraper traps will be reversed. East Houston: • Metering system will be reversed. • Six 250,000-bbl tanks for crude with tank pumps will be constructed. • Tank lines from crude manifold to tank will be installed. • Crude manifold for new crude tanks will be expanded. • Line from Longhorn incoming manifold to crude manifold will be constructed. • Line from Crude manifold to outgoing pipelines will be constructed. Check Valve Replacement: • Emergency flow check valves at 27 sites with motor operated gate valves will be replaced. • Power and SCADA connection will be provided. Pipeline Integrity: • Pipeline repairs based upon new hydraulic surge analysis will be performed. Line Displacement: • Refined petroleum product will be displaced with nitrogen then the pipeline will be filled with crude oil. Phase II: The Crane to East Houston pipeline will be expanded to a capacity of 225,000 bpd. This will be accomplished by installing larger mainline units at existing pump stations plus addition of intermediate pump stations along the pipeline. Crane Station: • Two mainline units will be installed at existing station. Texon Station: • A new intermediate pump station consisting of two mainline units will be constructed. • DRA will be installed downstream of the mainline units. • A connection to third party facilities consisting of manifold and metering will be installed. • A corrosion inhibitor injection system will be installed. 3-3 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Barnhart Station: • A new intermediate pump station consisting of two mainline units will be constructed. • DRA will be installed downstream of the mainline units. • A connection to third party facilities consisting of manifold and metering will be installed. • A corrosion inhibitor injection system will be installed. Cartman Station: • A new intermediate pump station consisting of two mainline units will be constructed. • DRA will be installed downstream of the mainline units. Kimble Station: • Two mainline units will be installed at existing station. James River Station: • A new intermediate pump station consisting of two mainline units will be constructed. • DRA will be installed downstream of the mainline units. Eckert Station: • A new intermediate pump station consisting of two mainline units will be constructed. • DRA will be installed downstream of the mainline units. Cedar Valley Station: • Two mainline units at existing station will be installed. Bastrop Station: • A new intermediate pump station consisting of two mainline units will be constructed. • DRA will be installed downstream of the mainline units. • A connection to third party facilities consisting of manifold and metering will be installed. • A corrosion inhibitor injection system will be installed. Warda Station: • A new intermediate pump station consisting of two mainline units will be constructed. • DRA will be installed downstream of the mainline units. • A connection to third party facilities consisting of manifold and metering will be installed. • A corrosion inhibitor injection system will be installed. 3-4 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Industry Station: • A new intermediate pump station consisting of two mainline units will be constructed. • DRA will be installed downstream of the mainline units. • A connection to third party facilities consisting of manifold and metering will be installed. • A corrosion inhibitor injection system will be installed. Buckhorn Station: • A new intermediate pump station consisting of two mainline units will be constructed. • DRA will be installed downstream of the mainline units. Satsuma Station: • Two mainline units will be installed at existing station. East Houston: • Mainline units will be installed at East Houston to pump crude south to Speed Junction will be installed. • Outbound metering for flow-rate and operating pressure will be revised. • Manifold to connect crude tanks to mainline units will be constructed. East Houston to Speed Junction: • 20” pipeline from East Houston to 9th Street Junction will be hydro-tested to establish higher MOP. • A 2.5 mile, 20” pipeline from 9th Street Junction to Speed Junction will be constructed. 3.2 CONNECTED ACTIONS Connected Actions are those that are “closely related” to the Proposed Project. Connected Actions are interdependent parts of a larger action and depend on the larger action for their justification. Although these projects would not necessarily require a NEPA review, they are dependent on the Proposed Project and are therefore included in the scope of this FEA. See 40 CFR §1508.25. Figures 3.2-1a and 1b show the Connected Actions. 3.2.1 Orion Expansion The Orion West Pipeline expansion will consist of an increase in pipeline throughput capacity and storage capacity, and equipment upgrades. The increase in pipeline throughput capacity will be provided by the addition of two new pump stations located at DeLeon and Iatan. Storage capacity for refined product at the existing Frost Terminal will be expanded to include one 250,000-barrel tank, one 200,000-barrel tank, and one 125,000-barrel tank. Refined petroleum storage capacity at the East Houston Terminal will be expanded to include four 150,000-barrel tanks and additional pumping capacity. Additional expansion includes infrastructure upgrades at existing facilities at Frost, Walnut Springs (including DRA facilities), Clyde, Midland, and Odessa 3-5 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Terminal. The addition of the two facilities and existing infrastructure upgrades will increase pump rates from approximately 72,000 bpd to approximately 110,000 bpd along this pipeline system. 3.2.2 Odessa to Crane The Orion West Pipeline expansion will include an existing 8-inch refined product pipeline that extends approximately 29 miles from the Odessa Terminal to the Crane Station. The pipeline will continue to be in refined petroleum service, but the flow reversed and a mainline pumping unit (including DRA) added at Odessa. 3.2.3 El Paso Gateway This Connected Action includes a new 6-inch pipeline (approximately 6 miles) from the Longhorn El Paso Terminal to the proposed El Paso Gateway. The proposed activity will allow continued supply of refined product to a local refinery and includes the addition of a pump unit and meter station at the Longhorn El Paso Terminal. 3.2.4 Crane to El Paso This Connected Action includes an existing segment of the Longhorn Pipeline from Crane to El Paso that will increase pipeline capacity throughput from approximately 72,000 bpd to approximately 110,000 bpd. This segment will require a new pump station at Cottonwood Station, new pump units at the existing Crane Station, and upgraded metering at the El Paso Terminal. 3.2.5 9th Street Junction to Speed Junction This Connected Action is the construction of a 20-inch crude oil pipeline from the existing 9th Street Junction to Speed Junction (approximately 2.8 miles). This segment will allow crude oil to be further distributed in the Houston area. 3.2.6 East Houston to Holland Avenue This Connected Action is the construction of an 8-inch refined product pipeline from the existing East Houston Terminal to Holland Avenue (approximately 8.0 miles). This segment will allow refined petroleum to be further distributed in the Houston area. 3.3 OPERATION AND MAINTENANCE 3.3.1 Proposed Project Operation and maintenance of the current assets will follow the operating practices set forth in Magellan’s System Integrity Plan (SIP) and the LMP to the extent applicable. The SIP is a 3-6 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL management system designed to minimize the risks associated with operating Magellan assets. The SIP is a comprehensive, process-focused approach to operation and maintenance. See Appendix 3 for high-level summary of SIP categories. The identification and management of risks associated with the operation of the pipeline system is critical to ensure long-term safety to the public and employees, and to minimize negative impacts to the environment. Of equal importance, the SIP is intended to function in coordination with the DOT PHMSA Pipeline Safety Regulation, Title 49, Subchapter D, Part 195 (Transportation of Hazardous Liquids by Pipeline). Both the SIP and the LMP are focused on two fundamental areas in relation to the risk management process: 1) Management of risks of current pipeline assets, and 2) Mitigation of existing and minimization of future pipeline risks. The LMP consists of certain specific Process Elements. Implementation of the Process Elements will ensure that the Longhorn components of the Proposed Project will effectively identify, analyze, and responsibly manage the most critical threats to the System. The Process Elements form an effective approach to operation and maintenance, and are as follows: 1) Corrosion Management Plan - Activities such as system surveys and evaluations, pipe design, coating section and application, and cathodic protection are designed to maintain the System in a manner that ensures safety and environmental protection, with special attention paid to discrete concerns associated with Tier I, Tier II and Tier III segments of the pipeline. 2) In-Line Inspection and Rehabilitation Program - Employs current technology in a range of in-line inspection tools, uses a 360-degree end-to-end look at the System, and the benefit of a risk-based system of re-inspection. 3) Key Risk Areas Identification and Assessment - Magellan will maintain its focus on risk mitigation, analysis, and management, drawing input from a variety of sources. 4) Damage Prevention Program - Mitigates the risk of injury to the public and environment through a program of pipeline marking, aggressive aerial surveillance, and multi-focused education. 5) Encroachment Procedures - Ensures the maintenance of a clear and unobstructed right- of-way (ROW), which is crucial to the safe operation of any pipeline system. 6) Incident Investigation Program - Uses a root cause analysis so that preventive action may be taken to prevent recurrences. 7) Management of Change – Magellan gives full consideration to the operational basis of change through design review, risk assessment, team communication, and training protocols. 3-7 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 8) Depth of Cover Program - Designed to mitigate risks to the public and the environment, by identifying and mitigating shallow or exposed pipe locations under dynamic circumstances, with special attention paid to sensitive and hypersensitive areas. 9) Fatigue Analysis and Monitoring Program - A program that identifies and mitigates pressure-cycle-induced fatigue-related cracking through the evaluation of data generated in the course of pipeline operations. 10) Scenario Based Risk Mitigation Analysis - An analysis to determine appropriate preventive measures and system modification to reduce the risk of release of product (refined product or crude oil), on a pipeline segment by pipeline segment basis. 11) Incorrect Operation Mitigation - Evaluates potential human error (design, construction, maintenance, and operation) and prevention strategies. 12) System Integrity Plan Scorecarding and Performance Metrics Plan - Provides specific program performance monitoring and continual improvement through a structure featuring its ongoing System Integrity Plan Audit, direct accountability, and regular reporting to PHMSA. 3.3.2 Connected Actions Magellan will operate and maintain the Connected Actions consistent with Magellan’s SIP and the IMP, Title 49 Part 195, and where applicable, the LMP. See Appendix 3 for a high-level summary of Magellan’s SIP. 3.4 ELIMINATION OF ALTERNATIVES FROM DETAILED CONSIDERATION The only other potentially viable alternative to the Proposed Project is the conversion of the Orion West Pipeline System into a crude oil pipeline and reversing the flow from Odessa, Texas to Frost, Texas. As part of this conversion, a new pipeline from Frost to East Houston would have been constructed since the existing pipeline (East Houston to Frost) supplies refined petroleum to markets in Dallas and various points in Oklahoma which must continue. This alternative was dismissed from detailed consideration for the following reasons: 1) Orion West Pipeline reversal would not satisfy the projected pipeline capacity needed to move West Texas crude to Houston refineries and would not be geographically positioned to capture Eagle Ford crude production. 2) The construction of new pipeline from Frost Station to East Houston Terminal would be more environmentally disruptive (i.e. the Orion reversal would require over 200 miles of new pipeline construction in heavily populated areas, whereas the Proposed Project and Connected Actions would require less than 17 miles of new pipeline). 3-8 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 3) The Orion West Pipeline reversal would not be cost effective compared to the Proposed Project. 3.5 NO-ACTION ALTERNATIVE The No-Action Alternative is the environmental baseline against which the Proposed Project is compared. In this FEA, the No-Action Alternative is the continuation of refined product shipments along the current Longhorn and Orion West pipeline systems. The environmental impacts from the No-Action Alternative include those identified and analyzed in the 1999 EA. Also, an examination of the Longhorn Pipeline’s operations and leak history is included in Chapter 5 of this FEA, which identify the environmental impacts from releases that have occurred during its startup and operation since the 1999 EA. In addition to the impacts identified in the 1999 EA, the No-Action Alternative would require the use of existing delivery systems, including rail deliveries, to move capacity that cannot be transported by existing pipelines from West Texas and Eagle Ford. Therefore, additional air quality impacts associated with transporting by rail would remain. No permitting or additional mitigative measures would be required if the No-Action Alternative was selected. The No-Action Alternative does not meet the purpose and need to bring West Texas and Eagle Ford crude oil to Gulf Coast refineries. 3-9 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL CHAPTER 3 FIGURES 3-1 <<>> Andrews Martin Abilene -Howard Hood 377 Mitchell Nolan 20 Midland 273 Taylor Callahan Eastland Houston Area Inset Ector 283 Erath 15 Odessa Midland 20 Glasscock Coke 833 2843 Comanché 610 Sterling Runnels 281 Bosque -Coleman Brown EAST HOUSTON Crane - CRANE Hamilton Upton Reagan San Angelo TEXON Tom Green Mills Irion 183 9TH STREET Concho 5283 Coryell 184} C61g 259} 6673 833 Mcculloch San Saba ·190 5 BARNHART 277 Lampass Menard Killeen 203 45 Pecos •enterchen Bell 11905 Robertson Crockett CARȚMAN FT MCKAVETT {873 190 Madison Mason Llano Burnet 2190 285 KIMBLE COUNTY JAMES RIVER 2183 walison Brazos Walker 190 Sutton Kimble Round Reck Burleson i Grimes San Jacinto Terrell ECKERT a vs - 2903 Gillespie CEDAR VALLEY 833 52905 Blánco Austin Lee Montgomery - BASTROP Washington Kerr 281 Hays WARDA + BUCKHORN 1593 277 war varde Edwards Kendall Bastrop 290 •SATSUMA Real 873 Comal Caldwell 'INDUSTRY Austin Bandera Fayette Houston EAST HOUSTON Guadalupe 50} Colorado Pasadena Fort Bend Kinney Uvalde 410 Bexar San Antonio Gonzales 183 9TH STREET 45 {903 Lavaca Maverick {833 Wilson {873 wenarton Brazorial Atascosa 2131 De Witt 1593 Jackson — Longhorn Pipeline Interstate Environmental Assessment Longhorn Pipeline Reversal Texas Crude Oil Service 371 US Highway Figure 3.1-1 N Project Location of A Proposed Magellan Pipeline Facility Expansion City Boundary Longhorn Pipeline • Existing Magellan Pipeline Facility Improvement County Boundary 29 1 Miles Job No.: 100019708 ts|M_NiMagellan_Midstream_Partners|100019708 geolfig_EAV Date: Jul 19, 2012 <<>> Cochran £ ¤380 £ ¤82 Yoakum £ ¤83 King £ ¤62 Gaines £ ¤67 Presidio £ ¤90 Jeff Davis JUNCTION GATEWAY § ¨ ¦10 § ¨ ¦20 Reeves COTTONWOOD ! ! ! ! ! ! ! ! ! ! ! ! ! ! ! " ! ! ! ! ! ! Hudspeth ! £ ¤285 Culberson ! ! ! ! ! § ¨ ¦10 ! ! ! ! ! ! ! ! ! Loving £ ¤62 ! ! ! ! ! " " ! El Paso £ ¤54 EL PASO El Paso Winkler ! CRANE Upton £ ¤67 Reagan Irion Ward ! ! ! ! £ ¤67 £ ¤385 Brewster £ ¤385 § ¨ ¦27 £ ¤62 £ ¤385 £ ¤82 £ ¤82 Wichita Falls £ ¤377 Lubbock Baylor Crosby Dickens Knox Clay £ ¤287 Montague Hockley Archer £ ¤82 Cooke Lubbock £ ¤84 Grayson £ ¤183 £ ¤281 § ¨ ¦35 £ ¤62 £ ¤75 Terry £ ¤277 £ ¤81 Garza £ ¤380 Lynn Haskell Jack Kent Young £ ¤380 Denton McKinney Collin £ ¤87 Stonewall Throckmorton Wise £ ¤380 Denton Plano £ ¤81 Lewisville Dawson £ ¤180 Garland Borden Fisher £ ¤180 £ ¤180 § ¨ ¦820 Irving Dallas § ¨ ¦635 Palo Pinto Scurry £ ¤84 Jones § ¨ ¦20 Fort Worth § ¨ ¦30 Dallas £ ¤80 £ ¤83 Shackelford Stephens Parker Tarrant § ¨ ¦20 Arlington § ¨ ¦20 Mitchell Grand Prairie £ ¤67 § ¨ ¦45 Howard CLYDE Martin £ ¤183 § ¨ ¦20 Hood £ ¤377 § ¨ ¦35 Andrews £ ¤385 § ¨ ¦20 ) Abilene " Nolan Johnson Eastland Erath Midland IATAN Ellis £ ¤287 Callahan Taylor £ ¤67 " ODESSA DELEON ) § ¨ ¦35 FROST Odessa MIDLAND £ ¤87 £ ¤84 " " " Glasscock Midland Coke £ ¤277 £ ¤377 Comanche Hill Sterling Bosque Navarro § ¨ ¦45 Ector £ ¤83 Brown £ ¤281 Runnels Coleman WALNUT £ ¤67 Hamilton Crane SPRINGS ! ! ! £ ¤84 ! ! ! ! ! ! " ! £ ¤83 £ ¤283 San Angelo Mills £ ¤183 Mclennan Waco Limestone £ ¤84 Concho Coryell § ¨ ¦35 Tom Green £ ¤87 £ ¤77 Mcculloch £ ¤190 Falls San Saba Killeen £ ¤190 Bell Pecos £ ¤190 Menard Robertson Burnet Milam £ ¤190 Mason Williamson Llano £ ¤79 £ ¤377 £ ¤183 £ ¤277 Kimble Sutton Round Rock Burleson £ ¤87 Gillespie £ ¤281 Travis £ ¤83 Austin Lee £ ¤290 Blanco £ ¤290 £ ¤377 £ ¤87 Bastrop Kerr Hays Edwards Austin Kendall Real Comal Caldwell Fayette Bandera £ ¤77 § ¨ ¦10 § ¨ ¦35 § ¨ ¦10 Bexar £ ¤183 Colorado Kinney Uvalde Medina § ¨ ¦410 Gonzales Lavaca San Antonio £ ¤90 £ ¤90 £ ¤83 £ ¤90 § ¨ ¦37 Wilson § ¨ ¦35 I 0 39 78 Miles Environmental Assessment Longhorn Pipeline Reversal Figure 3.2-1a Project Location of Connected Actions Prepared By: Atkins/19685 Scale: 1" = 39 mi Job No.: 100019708 Date: Apr 26, 2012 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_3.2-1a_ProjectLocation_ConnectedActions_a.mxd £ ¤190 Schleicher Crockett § ¨ ¦10 Terrell £ ¤90 Val Verde £ ¤277 ) § ¨ ¦20 Proposed Magellan Pipeline Facility " Existing Magellan Pipeline Facility £ ¤ 87 Refined Product Service Texas Connected Actions Odessa to Crane Pipeline Midland to Crane Pipeline El Paso to GatewayJunction Pipeline Orion Expansion Pipeline Odessa to Black River Pipeline ! ! ! Crane to El Paso Pipeline Interstate US Highway City Boundary County Boundary <<>> § ¨ ¦45 HOUSTON £ ¤ 59 GRIMES MONTGOMERY HARRIS FORT BEND WHARTON BRAZORIA SAN JACINTO POLK LIBERTY CHAMBERS GALVESTON £ ¤ 59 £ ¤ 90 § ¨ ¦610 EAST HOUSTON " § ¨ ¦10 § ¨ ¦10 HOLLAND AVE " " 9TH STREET § ¨ ¦610 SPEED JUNCTION " £ ¤ 90 PASADENA § ¨ ¦45 Connected Actions Holland Ave. to East Houston 9th St. to Speed Junction ) § ¨ ¦20 Proposed Magellan Pipeline Facility " Existing Magellan Pipeline Facility £ ¤ 87 Refined Product Service Crude Oil Service Interstate US Highway City Boundary County Boundary I 0.75 0 1.5 3 Miles Environmental Assessment Longhorn Pipeline Reversal Figure 3.2-1b Project Location of Connected Actions Prepared By: Atkins/24125 Scale: 1" = 39 mi Job No.: 100019708 Date: Apr 10, 2012 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_3.2-1b_ProjectLocation_ConnectedActions_b.mxd <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL CHAPTER 3 APPENDICES <<>> SYSTEM INTEGRITY PLAN Magellan Management Commitment and Support INTRODUCTION The Magellan Midstream Partners, L.P. (MMP) System Integrity Plan (SIP) is a management system designed to minimize the risks associated with operating MMP assets. It is a comprehensive, process-focused approach to operational excellence defining how we design, construct, operate, maintain and manage our assets. As such, the SIP is integral to the success of our business. Incorporated into the SIP is Magellan’s commitment to continuous improvement of environmental, health and safety performance. MMP’s successful execution of the SIP will enable continued improvement in: • Safe and efficient operations • Compliance with applicable laws and regulations • Stewardship of Company resources The SIP will further allow MMP to: • Operate our assets as a “prudent” operator • Ensure that our facilities are built and operated on sound technical and business principles, in compliance with regulatory requirements and in accordance with industry standards • Facilitate full and open discussion to address responsible standards and practices where laws and regulations do not exist or apply • Provide a safe and secure environment for our employees and the communities in which we serve • Ensure that all employees are trained to safely perform their respective duties • Ensure that all parties working on MMP’s behalf operate to our expectations • Ensure that the processes that are the backbone of SIP are routinely reviewed MMP Leadership is committed to ensure that: • Each business plan includes measurable SIP goals • MMP’s SIP performance is openly reported and routinely shared with employees • Pursuit of SIP performance improvement is expected and recognized MMP strongly believes that the success of the SIP is dependent upon the actions and attitudes of its employees. The foundation for the success of the SIP is MMP leadership commitment. Ultimately, MMP’s success is dependent upon having each employee recognizing his or her SIP identified responsibilities and holding themselves accountable for SIP implementation within his or her area of responsibility. The responsibilities of the SIP are directly focused on the employees who operate, maintain and commercially develop Magellan assets. However, other Magellan employees have an indirect role in maintaining the integrity of MMP’s assets and as such, are encouraged to familiarize themselves with the SIP. Through the individual and collective execution of the SIP, MMP expects to optimize our resources, improve our profitability and minimize the risks to our employees and to the communities in which we operate. MMP embraces implementation, execution and pursuit of continual improvement of the SIP as the fundamental strategy necessary in its pursuit of operational excellence. Magellan Midstream Partners Management <<>> 2012 SYSTEM INTEGRITY PLAN PREFACE The System Integrity Plan (SIP) is Magellan’s system for managing the risks of operating the Company’s assets. Therefore, the SIP applies to all Company operated assets. Operations, Technical Services and Commercial have the primary responsibility for asset operation, maintenance and management, and the SIP applies directly to the employees in those areas. SIP references to “the leadership” or “the supervisors” apply only to the leadership or supervisors in the Operations, Technical Services or Commercial groups, not all leadership or supervisors in the Company. The role listed as responsible party is accountable for ensuring the requirement is met. SIP establishes the minimum standards and procedures for operating, maintaining and managing Magellan’s assets. A business group or work area may establish more stringent requirements depending on the need and subject to approval processes established by the respective business unit; however, they cannot develop less stringent standards than those specified by SIP. Mitigation Plan specific requirements have been incorporated into the SIP and are thus subject to the same level of management, authority and responsibility as any other SIP requirement. Within the SIP are all the initiatives, procedures, forms and other supporting documents for the element. The SIP utilizes hyperlinks to “link” all these documents together. In some cases, there are links to documents that are not SIP documents, such as Company policies, or external websites. These particular linked documents are not considered part of SIP, meaning that the Element Owners and teams do not “own” them and cannot change them. However, if an SIP standard requires the use of one of these documents, their use is required per SIP. The most up-to-date version of SIP is available electronically in Livelink, which all employees have access to. Any printed documents, including the SIP book, may not be the most current version of SIP. Although Magellan strives to minimize changes throughout the year, changes to the SIP may occur if a midyear modification is deemed critical. Employees are encouraged to use the electronic source documents in Livelink whenever possible to make sure they are using the most current version of SIP. For newly acquired assets, Magellan management has established an SIP implementation period of one year from the date Magellan commences operations, unless regulatory requirements, or other Company requirements, mandate a more rigorous timeframe (such as with Facility Response Plans; Spill Prevention, Control & Countermeasure Plans; Facility Security Plans and Operator Qualification). Other implementation periods may be established with the permission of the Vice President of the asset. <<>> SIP ROLES AND RESPONSIBILITIES Most employees understand that SIP is our operational playbook, or our procedure manual for operating the assets and for ensuring that we comply with applicable regulations. But the SIP is also our documented method of reducing the operational risks of operating and managing the assets. That is, each element within SIP contains written instructions that when implemented and executed properly, should reduce the risk associated with that element. For example, following the preventive maintenance procedures and inspections in Asset Integrity (Element 7) helps reduce the risk of equipment failure and potential subsequent releases or injuries. Similarly, completing the training listed in the Training Matrix (Element 2) helps reduce the risk of injuries that could occur during certain activities like working in a confined space. Because SIP is a comprehensive and integrated playbook, it is the “way we do things around here”, and thus makes up a large part of our Company culture. Four teams have specific responsibilities towards developing and maintaining SIP. These teams and their roles in managing the SIP are described below. • SIP Oversight Council • SIP Council • EHS&S • Element Review Teams (Element Owners and Stakeholders) SIP Oversight Council Responsibilities The SIP Oversight Council is comprised of senior management and is primarily focused on the cultural aspects of SIP. In other words, they concentrate on ensuring that management sends a consistent message about SIP goals through metrics, incentives, organizational structure and resources. Additionally, they actively seek best practices throughout the energy industry and from other experts. Finally, they work closely with Audit Services to develop the SIP audit schedule and review results from those audits. They meet twice per year. The Oversight Council Chair is responsible for establishing the agenda and scheduling and facilitating the meetings. SIP Council Responsibilities The SIP Council is comprised of mid-senior level management, and is the steering team for SIP. Their main purpose is to develop and track SIP Council goals and ensure that the appropriate level of resources is allocated to meet the SIP Council goals. They meet quarterly or more often if needed. A summary of the Council’s responsibilities is below. • Selects Element Owners • Reviews and approve proposed significant changes to the SIP • Establishes SIP Council goals and set direction • Determines priorities within SIP should resources become limited • Approves personnel and financial resources for SIP necessary to meet goals • Resolves conflict, if needed • Reviews implementation and compliance progress, adjust timelines, priorities or resources if necessary • Analyzes the Operational Performance Metrics to identify opportunities to improve performance related to SIP processes and procedures. There are specific roles within the Council that ensure the Council meetings run smoothly, are efficient and that the Council addresses emergent and priority issues. These roles are the Council Chair and the Council Facilitator. Revised 1/1/12 <<>> The Council Chair approves the agenda, sets the priorities and runs the meetings. The Chair is also the Element Owner for Element 1, Magellan Commitment. The Council nominates a new chair annually; the nomination is approved by the Chief Executive Officer. The Council Facilitator schedules meetings, drafts the agenda, prepares pre-read materials for the meetings, monitors completion of action items, and issues meeting notes. The Facilitator also provides support to the Council Chair. Finally, the facilitator communicates any messages from the Council to the Element Owners and Element teams. EHS&S EHS&S has organizational responsibility for developing and maintaining SIP including SIP Program management, CMS Project management and SIP Council Meeting facilitation. Additional SIP responsibilities include: • Provide quality assurance to the SIP to minimize corporate liability and substantiate regulatory compliance. • Manages the Conflict Resolution Process for the element teams • Act as a focal point and SIP subject matter expert for the organization. • Manage SIP documentation in Livelink including document control and version history. • Manages the SIP suggestion process • Manages SIP change management, including Change Communications • Leads the annual SIP review process • Oversees CMS • Distributes monthly SIP metrics • Prepares and distributes the quarterly analysis and assessment of incident investigations • Prepares, facilitates and coordinates the quarterly operational performance results and meeting SIP Review Teams These teams are composed of the Element Owner and stakeholders. The teams are responsible for establishing, maintaining and improving the documents within their element. Specifically, they review employee suggestions and make updates if needed, ensure the element meets any applicable regulations, and ensure the documents within the element support all aspects of SIP including: • Providing instructions to employees • Reducing the operational risk of operating and managing the assets • Supporting an improved safety culture Element Owner Responsibilities The primary responsibility for an element owner is to lead the review process for their element. In other words, they are project managers accountable for reviewing their element. Specific responsibilities are shown below. • Lead the annual review • Perform their regular jobs in addition to their element owner responsibilities • In conjunction with the SMEs, ensure SIP meets regulatory requirements • Get input from Legal department if needed • Complete annual review on time; communicate if delays occur • Address feedback on suggestions and responds to the person who made the suggestion • Select stakeholders who represent impacted areas within MMP • Ensure stakeholders are actively engaged • Work with other element owners to resolve conflicts, changes or in other elementsRevised 1/1/12 <<>> • Manage the first level of conflict resolution • Simplify initiatives, procedures, forms when practical • Work with the SME to update regulatory cross-references Stakeholders Stakeholders are individuals whose work group is affected by the element. They may be subject matter experts, have experience with the element, or just be very interested in the subject. Their primary role is to ensure that their work group’s perspective is heard during the review process. Additional responsibilities include: • Actively participate in the review process • Support the team’s decisions • Understand the purpose of the element • Provide constructive feedback to your work group on the review process and on their suggestions • Provide subject matter expertise as applicable • Manage time commitments; notify element owner and leadership if time conflicts develop Revised 1/1/12 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 4.0 AFFECTED ENVIRONMENT This chapter describes the human, physical, biological, and cultural environment that may be affected by the Proposed Project. Similar to the scope of analysis that was performed in the 1999 EA, this FEA analyzes a potential impact corridor that is at a minimum 1,250 feet from each side of the Longhorn Pipeline centerline and extends outward to include an overland flow boundary, which considers the land surface area that could be potentially affected by a spill. The overland flow boundary was created using a model which uses worst-case drain down volumes for selected points along the pipeline, which are then overlaid onto a United States Geologic Survey (USGS) Digital Elevation Model (DEM) 30-meter grid. The volume of crude oil used in the modeling was defined as a worst-case spill which includes a worst-case drain down volume plus the volume generated by 12.5 minutes of pumping prior to shut-down. An algorithm was used to determine a topographical flow direction across the DEM grid. The algorithm assumes one-half inch of crude oil volume to flow along the spread path until the total product volume for the selected point is exhausted. A 500 foot buffer extends the overland flow boundary beyond this point. The measured thicknesses of released product (crude oil) from ten documented U. S. crude oil pipeline releases were between 2-4 inches. A thickness of one-half inch of crude oil was used in the algorithm because it assumed a greater spread and resulted in an added level of conservatism. This zone of potential impact is used consistently throughout this section, unless otherwise provided. 4.1 HUMAN RESOURCES AND LAND USES Human resources were evaluated to identify the distribution of population, vulnerable receptors (e.g., schools, parks, health care facilities, and overnight lodging facilities), existing and planned land uses, and transportation features along the Proposed Project. The human resources analysis identifies segments of the pipeline that were determined to be environmentally vulnerable areas due to population density and/or proximity to vulnerable land uses and receptors. 4.1.1 Regional Setting Human resources and land uses along the entirety of the Proposed Project are discussed in a regional perspective in the following text. The context of the discussion includes: • Potentially affected communities; • Regional land uses; • Regional population density; • Transportation network; and • Parks and natural areas. Detailed analyses of the Houston and Austin metropolitan areas are provided in Sections 4.1.2.1 and 4.1.2.2, respectively. 4-1 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 4.1.1.1 Potentially Affected Communities The Proposed Project crosses 20 counties in the State of Texas. Five incorporated areas are crossed: • Galena Park (Harris County); • Houston (Harris County); • Jacinto City (Harris County); • Jersey Village (Harris County); and • Austin (Travis County). The Proposed Project is adjacent to several rural and unincorporated neighborhoods and subdivisions, including: • Indian Lake Estates (Bastrop County); • Lake Thunderbird Estates (Bastrop County); • Oak River Estates (Bastrop County); • Stony Point (Bastrop County); • Stoney Ridge (Travis County); • Lookout Point (Travis County); and • Cedar Valley (Travis County). Officials with the Cities of Austin, Bastrop, and Houston, as well as Travis County, were contacted to determine if any new developments had occurred since publication of the 1999 EA. The City of Austin did not identify any large developments within the zone of potential impact, but did have records of some individual platted lots. Travis County reportedly provides all development plans to the City of Austin for inclusion in the City’s Geographic Information System (GIS). The City of Houston and surrounding metropolitan area within Harris County is densely populated with a limited potential for large residential developments. The City of Bastrop did not identify any large developments within the zone of potential impact. Large municipalities in the vicinity of the Proposed Project include: • Johnson City (4 miles south of the pipeline in Blanco County); • Junction (12 miles south of the pipeline in Kimble County); • Eldorado (2 miles north of the pipeline in Schleicher County); • Big Lake (2 miles south of the pipeline in Reagan County); and • Crane (3 miles south of the pipeline in Reagan County). The Proposed Project crosses through, and is in proximity to, numerous unincorporated communities between Austin and Houston, including: • Pleasant Grove (approximately 1.5 miles north of the pipeline in Rusk County); • Eckert (1.5 miles south of the pipeline in Gillespie County); • Travis and Scranton Grove (0.5 miles north of the pipeline in Austin County); 4-2 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • Shelby (crossed by the pipeline in Austin County); • Blieblerville (crossed by the pipeline in Austin County); • Welcome (crossed by the pipeline in Austin County); • Walhalla (crossed by the pipeline in Fayette County); • Nechanitz and Warda (1.5 miles north of the pipeline in Fayette County); • St. Martin (0.5 miles north of the pipeline in Fayette County); • Shiloh (0.5 miles south of the pipeline in Bastrop County); • Wrights (1.0 mile north of the pipeline in Bastrop County); • Pilot Knob (crossed by the pipeline in eastern Travis County); and • Willow City (2.0 miles south of the pipeline in Gillespie County). 4.1.1.2 Regional Land Uses Data from the 2006 National Land Cover Database (NLCD) was obtained in an effort to characterize the land uses crossed by the Proposed Project. The table below summarizes the types of land uses within the zone of potential impact along the pipeline from Crane to East Houston. Land Use Types Traversed by the Proposed Project NLCD Class Description Acres Percent Barren Land (Rock/Sand/Clay) 347.7 0.16% Cultivated Crops 3,756.3 1.76% Deciduous Forest 10,097.8 4.77% Developed, High Intensity 1,765.3 0.83% Developed, Low Intensity 6,553.8 3.10% Developed, Medium Intensity 6,592.9 3.12% Developed, Open Space 10,534.5 4.98% Emergent Herbaceous Wetlands 584.9 0.28% Evergreen Forest 13,061.2 6.18% Grassland/Herbaceous 8,304.4 3.93% Mixed Forest 1,502.0 0.71% Open Water 554.4 0.26% Pasture/Hay 21,910.0 10.36% Scrub-shrub 119,443.5 56.47% Woody Wetlands 6,490.9 3.07% Total 211,499.9 100.00% As shown above, the majority of the area is characterized as scrub-shrub, which is defined by the NLCD as “areas dominated by shrubs; less than five meters tall with shrub canopy typically greater than 20% of total vegetation. This class includes true shrubs, young trees in an early successional stage, or trees stunted from environmental conditions” (NLCD, 2001). Though not 4-3 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL defined as such by the NLCD, this type of land in Texas is frequently dedicated to cattle grazing and other agricultural activities. Other agricultural uses crossed by the pipeline include pasture/hay and cultivated crops. Developed land (high, medium, and low intensity, and open space) accounts for only 12.03% of the land crossed by the pipeline. These areas are within and surrounding Houston and Austin, and include a range of uses from “highly developed areas where people reside or work in high numbers” (high intensity) to “areas with a mixture of constructed materials and vegetation often including single-family residences” (low intensity). Open space developed land is typically comprised of vacant lots and open spaces in urban and suburban areas (NLCD, 2001). 4.1.1.3 Regional Population Density 4.1.1.3.1 Housing The number of housing units within the zone of potential impact was determined through the interpretation of 2010 National Agricultural Imagery Program (NAIP) aerial photography. This count was then used as the basis for estimating the population within an area adjacent to the pipeline defined as the area of potential impact. The photo-interpretation process included an initial identification of single-family and multi-family units, and health care facilities. If possible, the names and number of units of apartment buildings and other multi-family facilities were determined. If unit numbers could not be found, they were estimated based on approximate size. Locations of schools were determined using Texas Education Agency (TEA) data. Dwelling unit numbers along the pipeline route were compiled by 1-mile segments along the pipeline from Crane to East Houston and numbers of persons per household were applied to estimate total population numbers within each 1-mile segment, as described in the following section “Population”. Areas along the pipeline were classified by a measure of population density. Three zones were defined according to the number of residential units within the zone of potential impact: low density is 0-20 residential units per mile; moderate density is 21 to 1,000 residential units per mile; and high density is greater than 1,000 residential units per mile. Of the 466 miles of pipeline from Crane to East Houston, 19 miles (4.1%) are categorized as high density; 62 miles (13.3%) are categorized as medium density; and the remaining 385 miles (82.6%) are categorized as low density. The greatest concentration of housing and population is in the Houston area where approximately 37,898 dwelling units were identified within the zone of potential impact. The second-most concentrated area of housing occurs within the Austin area, where approximately 8,927 dwelling units were identified within the pipeline’s zone of potential impact. A list of multi- family facilities (apartments, condominiums, and townhomes) within the Houston and Austin metropolitan areas is provided in Table 4.1.1-1. 4-4 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 4.1.1.3.2 Population The total population of the 19 counties (Harris, Waller, Austin, Lee, Fayette, Bastrop, Travis, Hays, Blanco, Gillespie, Llano, Mason, Kimble, Menard, Schleicher, Crockett, Reagan, Upton, and Crane, Counties) crossed by the Longhorn Pipeline was an estimated to be 5,509,531 in 2009 (U.S. Census Bureau 2009). Population estimates along the Crane to East Houston pipeline were based on an inventory of dwelling units and average population per household numbers by county as determined by 2000 U.S. Census Bureau data. Results of that analysis indicate that approximately 131,477 persons reside within the zone of potential impact. Detailed information is included in Table 4.1.1-2. Of the 131,477 persons living within the zone of potential impact, approximately 105,726 (80.4%) reside between milepost (MP) 1 and MP 40 of the Longhorn Pipeline and along MP1 and MP 9 of the East Houston to 9th Street segment. Most of the remaining 4,453 (3.4%) persons along the pipeline reside between Houston and Austin. Approximately 994 (1.5%) persons live within the zone of potential impact between Austin and Crane. 4.1.1.4 Transportation Networks The Proposed Project crosses 23 federal highways, 24 state highways, and numerous state- designated Farm-to-Market (FM) and Ranch roads. The pipeline also crosses numerous city streets (primarily in the Houston and Austin metropolitan areas), county roads, and 22 railroads. Highway and railroad crossings are listed by county in Appendix 4A. 4.1.1.5 Parks and Natural Areas The Proposed Project crosses Buescher and Pedernales Falls State Parks, and portions of the zone of potential impact cover areas of McKinney Falls State Park. In addition to these state parks, several other recreational areas are either crossed by the pipeline or have areas within the zone of potential impact. These include Fox Creek Golf Club (Waller County), Pine Forest Golf Club (Bastrop County), Scallorn Cemetery (Bastrop County), Big Lake (Reagan County), and the Crane Country Club (Crane County). Additional recreational areas in the Houston and Austin areas are discussed in sections 4.1.2.1 and 4.1.2.2, respectively. Buescher State Park, Bastrop County. The park consists of 1,017 acres in the Lost Pines region of Texas. Amenities include camping, non-motorized boating, fishing, hiking, and biking (TPWD, 2011). Pedernales Falls State Park, Blanco County. According to Texas Parks and Wildlife Department (TPWD), the park consists of 5,212 acres and typifies the Edwards Plateau terrain of the surrounding region. Activities offered include camping, picnicking, hiking, river swimming, tubing, wading, mountain biking, fishing, bird watching, and horseback riding (TPWD, 2011). McKinney Falls State Park, Travis County in South Austin. The park consists of 744 acres and includes historic structures dating to the mid-1800s. Activities offered at the park include 4-5 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL camping, hiking, mountain biking, road biking, picnicking, fishing, wildlife observation, and swimming in Onion Creek (TPWD, 2011). 4.1.2 Other Receptors in the Houston and Austin Areas 4.1.2.1 Houston Area The Proposed Project originates nine miles south of the East Houston Terminal in an industrial area of the Houston metropolitan area and extends to the north through portions of the City of Houston and unincorporated areas of Harris County. Although residential land uses dominate much of the area adjacent to the alignment, industrial/commercial use areas are concentrated in the Galena Park Station industrial area and along major arterials such as Market Street, Wallisville Road, Interstate Highway 10 (IH-10), and US 90. Subdivisions and neighborhoods crossed by the pipeline within the eastern Houston area include Groveland Terrace, Holiday Forest, Songwood, Wood Bayou, Wallisville Gardens, Ralston Acres, Houmont Park, and Green River. Urban undeveloped land is scattered as small parcels throughout the area. Land uses along the East Houston portion of the pipeline are shown on Figure 4.1.2-1a and 1b. The pipeline turns toward the west at Green River Road and crosses through urban residential areas and urban undeveloped land to the northwestern city limits, as shown on Figure 4.1.2-1c through Figure 4.1.2-1i. Neighborhoods and subdivisions along the alignment include Parkwood East, Lake Forest Estates, Glenwood Forest, Kentshire Place, Park North, Scenic Woods, Fontaine Place, Sherwood Place, Oakwilde, Melrose Place, Willow Run, Heather Glen, West Mount Houston, Inwood North, Inwood North Estates, Rolling Fork, Arbor Vineyards, Willowbridge, Winchester Country, Steeplechase, Steeplechase Park, Crossroads, Northmead Village, and Aberdeen Trails. Rural residential land use areas begin approximately 2 miles west of US 290 and extend as relatively isolated subdivisions and population centers from the Houston metropolitan area to central Waller County. 4.1.2.1.1 Special Use Areas Special use areas along the pipeline include numerous schools, parks and recreation centers, and health care facilities. A special use area and potential vulnerable receptor within the area includes Herman Brown Park which is located in Houston. Public and private schools in the area occur in residential areas of Jacinto City, Houston, and unincorporated Harris County. The Proposed Project crosses seven school districts in the Houston metropolitan area. Thirty-one public schools, five private schools, one health care facility, and 30 parks and recreational facilities are within the zone of potential impact. These are summarized in Table 4.1.2-1 and are shown on Figures 4.1.2-1a through 4.1.2-1i. 4.1.2.2 Austin Area Land uses within the Austin area, including eastern and western Travis County, are shown on Figures 4.1.2-2a through 4.1.2-2g. The uses are predominantly urban residential with the heaviest concentration east of Brodie Lane. Rural residential and agricultural/rangeland land 4-6 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL uses within the Austin metropolitan area are limited to those within unincorporated western Bastrop County and eastern and western Travis County. Subdivisions/neighborhoods crossed by the alignment (east to west) include: Onion Creek Forest, Silverstone, Indian Hills, Meadow Creek, Park Ridge, Buckingham Estates, Parkwood, Tanglewood Forest, Shiloh, Southwest Oaks, Cherry Creek, Sendera Oaks, Sendera Glen, and Village at Western Oaks. Other subdivisions within the metropolitan area include: Indian Lake, Lake Thunderbird, Oak River Estates, and Stony Point in Bastrop County and East Travis Hills and Stoney Ridge in eastern Travis County. The planning department for the City of Austin was contacted to determine if any new developments were planned for the area surrounding the pipeline. The City of Austin did not identify any large developments within the overland flow boundary, but did have records of some individual platted lots. 4.1.2.2.1 Special Use Areas The Proposed Project crosses four school districts in the Austin area. Within the overland flow boundary there are four public schools, one private school, one healthcare facility, and 12 recreational areas. These are identified in Table 4.1.2-2 and shown on Figures 4.1.2-2a through 4.1.2-2g. 4.2 PHYSICAL RESOURCES 4.2.1 Groundwater Resources 4.2.1.1 Aquifers Traversed by the Zone of Potential Impact and General Nature The Texas Water Development Board (TWDB) Groundwater Availability Modeling (GAM) program recognizes and has differentiated 9 major and 21 minor aquifers within Texas. The names used by the TWDB GAM program for those major and minor aquifers traversed by the zone of potential impact are also used in this FEA. One unclassified aquifer, a smaller, localized aquifer that is not officially designated by the TWDB as an aquifer, is also traversed by the zone of potential impact. Those major, minor and unclassified aquifers identified as underlying the zone of potential impact for the Proposed Project are listed in Table 4.2.1-1. The aquifers are listed on this table in the order encountered by the Proposed Project from east to west. A summary of the characteristics of each aquifer is also provided in Table 4.2.1-1. The locations where the Proposed Project traverses these aquifers are shown on Figures 4.2.1-1 and 4.2.1-2. The land surface exposure, or outcrop area, of the formation(s) comprising an aquifer is the area corresponding to the principal recharge zone for the aquifer. Groundwater encountered within the recharge zone is normally under a watertable or unconfined condition, and has a high degree of vulnerability to contamination. When water-bearing strata dip below the surface and 4-7 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL are covered by less permeable strata, such as clay, and hydrostatic pressure within the strata increased, the aquifer becomes confined or under an artesian condition. Confined aquifers, “covered aquifers”, have a very low degree of vulnerability to contamination. 4.2.1.2 Relative Vulnerability of Aquifers within the Zone of Potential Impact 4.2.1.2.1 Relative Aquifer Vulnerability Evaluation Methodologies General. The relative drinking water resource vulnerability of those aquifers listed on Table 4.2.1-1 to a crude oil release within the zone of potential impact was systematically evaluated using both the Pettyjohn et al. Aquifer Classification Scheme (EPA, 1991), and the TCEQ aquifer vulnerability ranking system based on the average DRASTIC index of each Texas aquifer. The DRASTIC and Pettyjohn et al. methodologies were developed for the EPA as standardized techniques for evaluating the relative vulnerability of aquifers to surface or near surface sources of pollution. The qualitative vulnerability rankings of high, medium and low are assigned to each aquifer using the average TCEQ DRASTIC index and Pettyjohn et al. methodologies separately. Aquifer drinking water vulnerability under both methods was numerically ranked from 1 (high vulnerability) to 3 (low vulnerability). The sum of TCEQ DRASTIC index and Pettyjohn et al. numerical ranking is used along with potential public water supply water well vulnerability numerical rankings to aquifer drinking water vulnerability within the zone of potential impact. More detailed explanations of the qualitative analyses, numerical ranking system and use in determining aquifer sensitivity are presented in following paragraphs, Section 4.2.1.2 and Section 4.2.1.4. The Pettyjohn et al. aquifer classification scheme was also utilized to qualitatively identify those aquifers traversed by the zone of potential impact that potentially serve as, or are hydraulically connected to, aquatic habitats. DRASTIC. The DRASTIC methodology was developed for the EPA as a standardized system for systemically evaluating groundwater pollution potential. The DRASTIC methodology is presented in detail in the EPA document: “DRASTIC: A Standardized System for Evaluating Groundwater Pollution Potential Using Hydrogeologic Settings” (EPA/600/2-87/035 June 1987). The DRASTIC acronym is composed of letters for each of the measurable parameters for which data are generally available from a variety of sources. These measurement parameters from which the DRASTIC acronym is derived are: D - Depth to water R - net Recharge A - Aquifer media S - Soil media T - Topography I - Impact of the vadose zone media C - Hydraulic Conductivity of the aquifer 4-8 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL The TCEQ developed an aquifer vulnerability ranking system based on the average DRASTIC indices calculated using the above-referenced parameters for the major and minor aquifers of Texas. The TCEQ uses this ranking system because it is a reasonable method of determining the relative vulnerability of aquifers to surface activities. The information sources from which the TCEQ obtained the above-referenced measurement parameters included, but were not limited to, the TWDB, Natural Resource Conservation Service, Bureau of Economic Geology and USGS. In the DRASTIC methodology, each of these factors has a "range" and associated "rating". Appendix D of the TCEQ document “Texas Nonpoint Source Management Program Report” dated December 2005, lists the average DRASTIC index and aquifer vulnerability ranking assigned by the TCEQ to each of the major and minor aquifers. The qualitative vulnerability rankings assigned by the TCEQ to these aquifers are high, medium and low. As indicated in Appendix D, an average DRASTIC index and vulnerability ranking have not been calculated and assigned for one minor aquifer. The absence of an index and ranking are most likely due to this minor aquifer being recently recognized as an official aquifer by the TWDB at the time the TCEQ was preparing the rankings. It should also be noted that the TCEQ has not assigned an average DRASTIC index or aquifer vulnerability ranking for the unclassified alluvium aquifer traversed by the zone of potential impact, most likely because this aquifer is not recognized by the TWDB as a major or minor aquifer. The formation that comprises the recently recognized minor aquifer belongs to the same geologic group as those formations comprising older aquifers in that same geologic group. These formations have similar lithologies and environments of deposition. Therefore, the more conservative DRASTIC index and aquifer vulnerability ranking for a ranked aquifer of that geologic group is appropriate for the recently recognized minor aquifer. Following this same rationale, an average DRASTIC index and aquifer vulnerability ranking equal to that of the recognized minor alluvium aquifer traversed by the zone of potential impact is fitting for the unclassified alluvium aquifer. Table 4.2.1-2 lists the major and minor aquifers along with their average DRASTIC indices and aquifer vulnerability rankings as assigned by the TCEQ or determined using the above-described rationale. Pettyjohn et al. Aquifer Classification Scheme. The Pettyjohn et al. Aquifer Classification Scheme was developed for the EPA to assess the vulnerability of surficial and relatively shallow aquifers to contamination from shallow injection wells, as well as, surface or near surface sources of contamination. The EPA attempted to evaluate all aquifers in the conterminous United States on the basis of their reported physical properties, hydrologic characteristics and behavior as reported in published reports and maps. Details pertaining to this aquifer classification scheme are presented in the EPA document: “Regional Assessment of Aquifer Vulnerability and Sensitivity in the Conterminous United States” (EPA/600/ 2-91/043 August 1991). This classification scheme is used by the DOT to identify aquifers that are unusually sensitive drinking water resources as defined in 49 CFR Part 195, Pipeline Safety: Areas Unusually Sensitive to Environmental Damage. 4-9 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL The Pettyjohn et al. Aquifer Classification Scheme divides aquifers into four classes. The first two classes are further subdivided based on various characteristics. The aquifer classifications and their characteristics are described below. Class I aquifers are surficial or shallow, permeable and highly vulnerable to contamination. This class of aquifer includes the following four subdivisions: Class Ia. This class of aquifer consists of surficial, unconsolidated, and permeable sand and gravel, commonly interbedded to some degree with silt and clay lain down as alluvial, terrace, outwash, beach, dune and other similar deposits. A Class 1a aquifer generally contains layers. Class Ib. Soluble and fractured bedrock consisting of limestone, dolomite, and, locally, evaporites are the lithologies that make up a Class Ib aquifer. This aquifer class contains documented karst features or solution channels, of which size is not important. A Class Ib aquifer generally exhibits a wide range in permeability and well yields. Groundwater movement is largely controlled by the secondary openings, potentially allowing for the rapid vertical and horizontal groundwater movement, and a high degree of vulnerability. Also, included in this class are aquifers comprised of sedimentary, metamorphic and igneous (intrusive and extrusive) rocks that are significantly faulted, fractured, or jointed. Class Ic. Aquifers falling under Class Ic are semi-consolidated; contain poorly to moderately-indurated sand and gravel, and are interbedded with clay and silt. The semi- consolidated condition may be from the introduction of clay and caliche matrix into primarily unconsolidated to poorly consolidated strata. Class Id. Any Class I aquifer overlain by less than 50 feet of low permeability, unconsolidated material, such as glacial till, lacustrian, and loess deposits. Class II aquifers are consolidated bedrock aquifers that are moderately vulnerable. There are three subdivisions within this aquifer class, which are described below: Class IIa. This subdivision includes higher yield bedrock aquifers generally consisting of fairly permeable sandstone or conglomerate containing lesser amounts of interbedded shale, siltstone and/or mudstone. Interbedded carbonate strata may also be present. To be included in this aquifer class, well yields must exceed 50 gpm. Local fracturing or jointing may contribute to the dominant primary porosity and permeability of this class of aquifer. Class IIb. For the most part, Class IIb aquifers are lower yield bedrock aquifers consisting of sedimentary or crystalline rocks of the same types present in Class IIa aquifer. However, grain size in the Class IIb rocks is generally smaller and cementation or induration is greater, resulting in lower permeability. Well yields are generally less than 50 gpm, but may be greater in some areas. 4-10 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Class IIc. This aquifer class consists of any Class IIa or lIb aquifer that is overlain by less than 50 feet of unconsolidated material of low permeability. Class III aquifers are unconsolidated and consolidated aquifers overlain by more than 50 feet of low permeability material, and are the least vulnerable of all the classes. These aquifers are naturally protected by a thick layer of fine-grained material, such as clay or shale. There are no subdivisions within this aquifer class. Undifferentiated aquifers are designated as Class U. This classification is used when a map- able area contains several lithologic and hydrologic conditions that cannot be differentiated due to mapping scale constraints, the presence of undelineated members within a formation or group, or the presence of non-uniformly occurring features, such as fracturing or joints. This class suggests a wider range of vulnerability than is usually contained within any other aquifer class. For consistency, the TCEQ qualitative rankings of high, medium and low were used to rank aquifer vulnerability. These rankings are based on the aquifer lithology, confining layer thickness, confined condition and well yield. All Class I group aquifers and Class IIa aquifers have a high vulnerability ranking. Class IIb, Class IIc and Class U aquifers are ranked as medium vulnerability. Class III aquifers are ranked as low vulnerability. Section 2 of EPA/600/ 2-91/043, August 1991 presents an evaluation of the aquifers in the conterminous US using the Pettyjohn et al. Aquifer Classification Scheme. With regard to Texas, this evaluation concluded that approximately: • 25% of Texas is covered by Class la aquifers; • 13% of Texas has Class Ib aquifer outcrops; • 25% of Texas is Class Ic aquifer outcrops; • 7% of Texas has surface exposures of Class lIa aquifers; • 24% of Texas is covered by Class III aquifers and, • 6% of Texas is covered by undifferentiated aquifers. This indicates that about 70% of Texas is covered by Classes I and IIa aquifers that are potentially unusually sensitive areas of drinking water resources. The above percentage breakdown of aquifer classes also points out that approximately 45% of Texas aquifers are Class Ia (alluvium), Ib (karst) and IIa (outcropping bedrock) aquifers which potentially serve as or are hydraulically connected to aquatic habitats. Table 4.2.1-3 lists the major and minor aquifers crossed by the zone of potential impact and the associated Pettyjohn et al. Aquifer Classification. 4.2.1.2.2 Relative Aquifer Vulnerability Evaluation Aquifer drinking water vulnerability within the zone of potential impact was qualitatively analyzed on two levels, the TCEQ DRASTIC aquifer vulnerability ranking and the Pettyjohn et al. Aquifer Classification Scheme. Aquifer drinking water vulnerability for both evaluation levels was ranked 4-11 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL from 1 (high vulnerability) to 3 (low vulnerability) as shown in Table 4.2.1-4. The vulnerability of aquifer associated aquatic habitats was also qualitatively evaluated using the Pettyjohn et al. Aquifer Classification Scheme and literature documentation that natural discharge to streams is a common and frequent occurrence. Aquifer aquatic habitat vulnerability is also a numerical ranking of 1 (high vulnerability) to 3 (low vulnerability). The aquifer aquatic habitat ranking is also shown on Table 4.2.1-4. The relevant aquifer information used and the findings of the above referenced qualitative analyses for each aquifer traversed by the potential zone of impact from east to west are summarized below. Gulf Coast Aquifer System. The Gulf Coast Aquifer System is a major aquifer that occupies a wide belt along the Gulf Coast of Texas. This aquifer system is a complex of interbedded clay silt, sand, and gravel strata of several formations that are hydrologically interconnected forming a large, leaky artesian aquifer system. Recharge to the Gulf Coast Aquifer is mainly by rainfall infiltrating outcropping sand and gravel (permeable) strata. Water also enters the aquifer from some of the numerous streams that cut into the permeable strata of this aquifer. However, there are a few area seeps and springs that do discharge into some streams as base flow where those streams cut into groundwater-bearing strata. The relative drinking water vulnerability rankings established for the Gulf Coast Aquifer System using the two qualitative methodologies were high and medium. The TCEQ calculated a 95 average DRASTIC Index, a medium vulnerability ranking for this aquifer. This medium TCEQ vulnerability ranking equates to a numerical ranking of 2. Outcrop areas of this aquifer system comprised of sand and gravel qualify as Pettyjohn et al. Classes Ia and Ic, with the remaining outcrop areas being Class U. Therefore, the drinking water vulnerability is high for all Class I areas, and medium for all Class U areas, with FEA drinking water vulnerability numerical rankings of 1 and 2, respectively. The above Pettyjohn et al. classifications indicate that the aquifer aquatic habitat vulnerability ranking for the Gulf Coast Aquifer System is medium. This ranking takes into account that hydraulic communication between this aquifer and those streams that cross it is not continuous along the zone of potential impact. Hence, the overall FEA aquifer aquatic habitat numerical ranking is 2. Brazos River Alluvium Aquifer. The Brazos River Alluvium Aquifer is a minor aquifer that occupies the Brazos River Valley. This aquifer consists of alluvial terrace and floodplain deposits of sand, gravel, silt, and clay sediments. The aquifer is generally unconfined with the watertable surface generally sloping towards the Brazos River, indicating that the aquifer naturally discharges to the river as seeps and springs above the river water line. Recharge to this aquifer is primarily from infiltrating rainfall. The average TCEQ DRASTIC Index calculated for the Brazos River Alluvium Aquifer is 144, a high drinking water vulnerability ranking. This aquifer also meets the Pettyjohn et al. criteria for Class Ia, which point to a high drinking water vulnerability. The above qualitative evaluations show that FEA numerical drinking water vulnerability rankings of 1 are applicable for the finding of both evaluation methods. 4-12 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL The Pettyjohn et. al. Aquifer Classification given above signifies that the Brazos River Alluvium Aquifer is ranked high with regard to aquatic habitat vulnerability. Accordingly, the FEA numerical ranking is 1 for aquatic habitat vulnerability. Yegua-Jackson Aquifer. The Yegua-Jackson Aquifer was recognized as a minor aquifer in 2002. It is present as a narrow band extending from East Texas to South Texas, and inland of the Gulf Coast Aquifer System. Interbedded sand, silt, and clay strata of the Yegua Formation and Jackson Group, along with some occurrences of lignite, limestone, tuff, shells, and gypsum, make up this aquifer. Groundwater is under watertable (unconfined) conditions in the Yegua- Jackson Aquifer outcrop areas and under artesian (confined) conditions in the deeper, dipping sediments. Groundwater flow in the unconfined portion of the aquifer is influenced by the topography and generally flows from the topographically high areas to topographically low areas into creeks and rivers as springs and seeps. Recharge to the Yegua-Jackson aquifer occurs by precipitation, irrigation subsurface return flow, and stream or reservoir leakage at the outcrop area. A TCEQ calculated DRASTIC Index and vulnerability ranking were not given in the previously referenced 2005 TCEQ report. A surrogate DRASTIC Index and vulnerability ranking were developed by comparing the Yegua-Jackson Aquifer hydrogeologic characteristics to those characteristics of the Sparta and Queen City Aquifers. All three of these aquifers belong to the same geologic group and have similar lithology and environment of deposition. Therefore, the more conservative DRASTIC index and aquifer vulnerability ranking of the Queen City Aquifer, 108 and medium, were determined to be appropriate for the Yegua-Jackson Aquifer. The above surrogate TCEQ DRASTIC drinking vulnerability ranking for the Yegua-Jackson Aquifer points to an FEA drinking vulnerability numerical ranking of 2. The Pettyjohn et al. Aquifer Classification Scheme qualitative analysis established that this aquifer is Class Ic. This indicates the drinking water vulnerability ranking is high, with an FEA numerical ranking of 1 for this vulnerability type. The Pettyjohn et al. Aquifer Classification given above denotes that the aquatic habitat vulnerability ranking for the Yegua-Jackson Aquifer is high at outcrop areas. Therefore, the FEA aquifer aquatic habitat vulnerability numerical ranking is 1 for the outcrop area of this aquifer. Sparta Aquifer. The Sparta Aquifer is a minor aquifer that extends in a narrow band from the Frio River in South Texas northeastward to the Texas-Louisiana state line, and inland of the Yegua-Jackson Aquifer. This aquifer is comprised entirely of the Sparta Formation and consists of sand and interbedded clay with small amounts of lignite in some locations. Groundwater within the Sparta Aquifer is under watertable conditions in its outcrop areas and artesian conditions downdip of its outcrops where the aquifer is overlain by low permeable formations. Infiltrating precipitation, stream or reservoir leakage, or irrigation return flow infiltration provide recharge to this Sparta at outcrop areas. Springs usually occur in topographically low areas in stream valleys or in areas of the outcrop where hydrogeologic conditions preferentially reject recharge. 4-13 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL The TCEQ calculated an average DRASTIC Index of 98 for the Sparta Aquifer giving it a medium drinking water vulnerability ranking and a FEA numerical ranking of 2. Under the Pettyjohn et al. Aquifer Classification Scheme, the outcrop area of this aquifer qualifies as Class Ic, with the subcrop, confined portion being Class III. Therefore, the drinking water vulnerability ranking based on Pettyjohn et al. is high for the outcrop area and low for the confined portion. The above Pettyjohn et al. qualitative evaluations show that FEA numerical drinking water rankings of 1 and 3 are applicable to the outcrop and subcrop areas, respectively. The Pettyjohn et al. classifications given above signify that the Sparta Aquifer aquatic habitat vulnerability change greatly going from the outcrop areas to the subcrop areas. The Class Ic classification and natural discharge via springs to topographically low areas in stream valleys of the outcrop area being common ranks the outcrop areas as having high aquatic habitat vulnerability, for a FEA numerical ranking of 1. A low aquifer aquatic vulnerability ranking, corresponding to a FEA numerical ranking of 3, is appropriate for the subcrop portion of the Sparta Aquifer due to being Class III under Pettyjohn et al., and having little to no natural discharge by way of springs to stream valleys. Queen City Aquifer. The Queen City Aquifer is a minor aquifer that extends in a narrow band across Texas from the Frio River in South Texas northeastward to the Texas-Louisiana state line. This aquifer is comprised entirely of sand, loosely cemented sandstone, and interbedded clay strata of the Queen City Formation. The Queen City Aquifer is under watertable conditions in its outcrop areas and under artesian conditions downdip of the outcrops where overlain by younger low permeable formations. Sources for recharge to this aquifer include precipitation and stream or reservoir leakage infiltrating the outcropping strata. Springs usually occur in topographically low areas in stream valleys or in areas of the outcrop where hydrogeologic conditions preferentially reject recharge. The average DRASTIC Index assigned by the TCEQ to the Queen City Aquifer is 108 for a medium drinking water vulnerability ranking for a FEA numerical ranking of 2. As with the Sparta Aquifer, the Queen City Pettyjohn et al. classification is Class Ic in outcrop areas and Class III in subcrop areas. Accordingly, Queen City Aquifer outcrops have a high drinking water vulnerability ranking and subcrop portions are ranked as being low with regard to drinking water vulnerability. The above Pettyjohn et al. classifications equate to FEA drinking water vulnerability numerical rankings of 1 for outcrop areas and 3 where the Queen City is in subcrop. As with the Sparta Aquifer, the Queen City aquatic habitat vulnerability ranking differs in outcrop and subcrop. The Pettyjohn et al. classification of Class Ic, and the frequent occurrence of natural discharge as springs in stream valleys indicate that outcrop areas have high aquatic habitat vulnerability ranking. Therefore, the Queen City Aquifer outcrop areas are given a FEA numerical ranking of 1. The Pettyjohn et al. Class III designation and little to no natural discharge by way of springs where in subcrop earns this portion of the Queen City Aquifer a low aquifer aquatic vulnerability ranking and a FEA numerical ranking of 3 for this vulnerability category. 4-14 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Colorado River Alluvium Aquifer. The Colorado River Alluvium Aquifer has not been classified as a major or minor aquifer by the TWDB. This aquifer is restricted, for the most part, to the Colorado River Valley and is comprised of groundwater saturated alluvium and terrace sand and gravel strata. The aquifer outcrop areas, which generally coincide with the river valley, receive recharge from infiltrating rainfall and from the tributaries of the Colorado River that cross the outcrop areas. Groundwater in the Colorado River Alluvium Aquifer is unconfined with the watertable surface generally sloping towards the river and naturally discharging to the river as springs. A TCEQ DRASTIC Index and vulnerability ranking were not given in the previously referenced 2005 TCEQ report. A surrogate DRASTIC Index and vulnerability ranking (Brazos River Alluvium Aquifer) was assigned to the Colorado River Alluvium Aquifer based on similar hydrogeologic characteristics and depositional environments. The TCEQ DRASTIC index and aquifer drinking water vulnerability ranking given to the Queen City Aquifer are 144 and high, respectively, for a FEA numerical ranking of 1. The qualitative analysis under the Pettyjohn et al. Aquifer Classification Scheme established that this aquifer is Class Ia with a high drinking water vulnerability ranking. Accordingly, the FEA scheme established that this aquifer is Class Ia with a high drinking water vulnerability numerical ranking of 1. The Pettyjohn et al. aquifer classification given above denotes that the Colorado River Alluvium Aquifer has a high aquatic habitat vulnerability ranking. Therefore, the FEA aquatic habitat vulnerability numerical ranking is 1 for this aquifer. Carrizo-Wilcox Aquifer. The Carrizo-Wilcox Aquifer is a major aquifer extending from the Texas-Louisiana state line to the Texas-Mexico border as a narrow band that runs parallel with the Gulf Coast. This aquifer consists primarily of sand strata locally interbedded with gravel, silt, clay, and lignite beds of the Wilcox Group and Carrizo Formation, which are hydrologically connected. Groundwater within the Carrizo-Wilcox Aquifer is under watertable conditions in the outcrop areas and confined conditions downdip of the outcrop areas. Sources for recharge to the Carrizo-Wilcox Aquifer include precipitation and stream or reservoir leakage infiltrating the outcropping permeable strata. Natural discharge usually occurs as springs in topographically low areas in river valleys or in areas of the outcrop where hydrogeologic conditions preferentially reject recharge. The TCEQ assigned an average DRASTIC Index of 117 to the Carrizo-Wilcox Aquifer and a medium drinking water vulnerability ranking for a FEA numerical ranking of 2. The qualitative evaluation following the Pettyjohn et al. Aquifer Classification Scheme produced two results. The Carrizo-Wilcox outcrop area meets the Class Ic criteria, and thereby, a high drinking water vulnerability ranking. The subcrop portion of this aquifer is Class III for a low drinking water vulnerability ranking. Hence, Carrizo-Wilcox Aquifer outcrop areas have a FEA numerical ranking of 1 with subcrop portions being ranked as 3 under the Pettyjohn et al. Aquifer Classification Scheme evaluation. 4-15 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL The Carrizo-Wilcox Aquifer aquatic habitat vulnerability ranking is dependent on whether the aquifer is outcropping or in subcrop. The Class Ic Pettyjohn et al. classification for the outcrop area, and natural discharge commonly occurring as springs in river valleys in this area point out a high aquatic habitat vulnerability ranking for the outcrop area. This high aquifer aquatic habitat vulnerability ranking for Carrizo-Wilcox outcrop areas lead to a FEA aquifer aquatic habitat vulnerability numerical ranking of 1. The Class III Pettyjohn et al. designation for the subcrop portion and little to no natural discharge by way of springs where the Carrizo-Wilcox is covered by low permeability strata brings about a low aquifer aquatic vulnerability ranking, and a FEA numerical ranking of 3 for this vulnerability type. Edwards (Balcones Fault Zone) Aquifer-Barton Springs Segment. The Edwards (Balcones Fault Zone or BFZ) Aquifer is a major aquifer in South-Central Texas. This karst, sole-source aquifer occupies a narrow belt extending from the eastern half of Kinney County through the San Antonio area northeastward to the Leon River in Bell County. The Barton Springs Segment of the Edwards (BFZ) Aquifer is hydrologically distinct from the rest of the Edwards (BFZ) Aquifer. The northeastern banks of Onion Creek and Plum Creek near Kyle, Texas serve as the southern boundary for the Barton Springs Segment when flow conditions are high. During low- flow drought conditions, the southern boundary shifts further south to the Blanco River (Save Barton Creek Association Newsletter, 2010). The northern limit of the Edwards (BFZ) Aquifer is defined by the southwestern bank of the Colorado River. The Barton Springs Segment of the Edwards (BFZ) Aquifer consists of dissolution-modified, faulted, and fractured limestone of the Edwards Group. The Barton Springs Segment of the Edwards (BFZ) Aquifer is unconfined in its outcrop area and confined in subcrop where overlain by younger formation. Recharge to the Edwards (BFZ) Aquifer is not restricted to karst features with surface expression. Hauwert (2009) and Hauwert and others (2010) concluded that upland recharge (i.e. non-cave/sinkhole or non-creek direct recharge) could contribute a significant percentage of the total recharge to the aquifer. Detailed evaluation of the Longhorn Pipeline trench across the outcrop of the Edwards (BFZ) Aquifer indicated numerous smaller karst features across the outcrop. Sources of recharge to this aquifer include the downward percolation of surface water from streams crossing the outcrop area, by direct infiltration of precipitation on the outcrop area and cross- formational flow from the underlying Trinity Aquifer. The aquifer feeds several well-known recreational springs, as well as lesser known springs, and underlies some of the most environmentally sensitive areas in the state. A recent study by the City of Austin (COA) and the Barton Springs/Edwards Aquifer Conservation District (BSEACD) has shown that most of the outcrop of the Edwards in Travis County should be considered as highly vulnerable. A key sensitive receptor within the Barton Springs system is the Barton Spring salamander. This amphibian lives only at the spring out flows of Barton Springs (TPWD, 2012). Turner and O’Donnell (2004) developed a four-tiered Barton Springs salamander rescue plan in case an instantaneous gasoline pipeline spill occurred on the outcrop of the Barton Springs Segment of the Edwards (BFZ) Aquifer. Available dye tracer study results for the Barton Springs Segment were used to validate peak concentration predictions derived using a published regression equation developed from dye tracing data in a number of carbonate aquifers. The tiered responses are based on the estimated volume of gasoline entering the aquifer under various flow scenarios and spill distance from Barton Springs. 4-16 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL The TCEQ calculated an average DRASTIC Index of 126 for the Edwards (BFZ)-Barton Springs Segment Aquifer, and a high drinking water vulnerability ranking giving a FEA numerical ranking of 1. The Pettyjohn et al. Aquifer Classification Scheme qualitative evaluation placed the Edwards (BFZ)-Barton Springs Segment Aquifer outcrop area in Class Ib for a high drinking water vulnerability ranking. The subcrop portion, also known as the Confined Zone, of this aquifer meets the Class III criteria and low drinking water vulnerability ranking. Based on the Pettyjohn et al. Aquifer Classification Scheme evaluation, the Edwards (BFZ)-Barton Springs Segment outcrop areas have a FEA numerical ranking of 1, while subcrop portions have a ranking of 3 for drinking water vulnerability. The Edwards (BFZ)-Barton Springs Segment Aquifer aquatic habitat vulnerability ranking is dependent on whether a spill occurs in the outcrop or subcrop areas. A high aquatic habitat vulnerability ranking for the outcrop area of this aquifer is warranted because of 1) the Class Ib Pettyjohn et al. Classification for the outcrop area; 2) well-documented natural discharge via numerous springs in this area, and 3) the presence of no critical aquatic habitat to which aquifer-supplied springs discharge into. The aquifer aquatic habitat vulnerability ranking of high scores the Edwards (BFZ)-Barton Springs Segment outcrop areas a FEA numerical ranking of 1. The Class III Pettyjohn et al. designation for the Confined Zone of the Edwards (BFZ)-Barton Springs Segment and little to no natural discharge by way of springs in this portion of the aquifer leads to a low aquifer aquatic vulnerability ranking, and a FEA numerical ranking of 3. Trinity Aquifer System-Hill Country. The Trinity Aquifer System-Hill Country (Trinity-HC) of South-Central Texas is part of the Trinity Aquifer, and is a major aquifer system. The Trinity-HC includes all or parts of Bandera, Bexar, Blanco, Comal, Gillespie, Hays, Kendall, Kerr, Kimble, Medina, Travis, and Uvalde Counties. The Trinity-HC Aquifer is comprised of the formations that belong to the Trinity Group. The Upper and Middle portions of the Trinity-HC Aquifer consist of limestone with groundwater occurring primarily in fractures, along bedding planes and in karst features. The Lower Trinity-HC is predominately sand and gravel. The Upper and Middle Trinity- HC are unconfined in outcrop areas with the Middle Trinity-HC becoming semi-confined in its eastern reaches. The Lower Trinity-HC is artesian and covered by a shale stratum that forms a leaky confining layer. Rainfall infiltration and seepage from streams and lakes on outcrop areas are the primary sources of recharge to the Upper and Middle Trinity-HC. Recharge to the Lower Trinity-HC is mainly by leakage from overlying and underlying aquifers, although some stream seepage contributes a small amount of recharge where a limited outcrop of the Lower Trinity- HC occurs along the Pedernales River. Springs and seeps originating from the Upper and Middle Trinity-HC provide most of the base flow in waterways such as Barton Creek, Onion Creek, and the Pedernales River. The average DRASTIC Index assigned by the TCEQ to the Trinity-HC is 95 with a medium drinking water vulnerability ranking. These TCEQ rankings correspond to a FEA numerical ranking of 2. The Upper and Middle Trinity-HC quality for Pettyjohn et al. classifications of Class IIa in outcrop and where this upper portion of this aquifer is in contact with the Edwards (BFZ) aquifer. The Lower Trinity-HC being overlain by a confining shale stratum and being present mainly in subcrop is Class III. The drinking water vulnerability rankings for the Upper and Middle 4-17 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Trinity-HC are high, while the Lower Trinity-HC ranks low for drinking water vulnerability. Based on the above Pettyjohn et al. classifications, the FEA numerical rankings for the Upper and Middle Trinity-HC are 1, and the ranking for the Lower Trinity-HC is 3 with regard to drinking water vulnerability. The Pettyjohn et al. classification of Class IIa and the frequent occurrence of natural discharge as springs in stream valleys dictate that the Upper and Middle Trinity-HC be assigned high aquatic habitat vulnerability rankings. As a result, the Upper and Middle Trinity-HC have FEA aquatic habitat vulnerability numerical rankings of 1. The Pettyjohn et al. Class III designation and no natural discharge by way of springs directly from an outcrop of the Lower Trinity-HC warrants a low aquifer aquatic vulnerability ranking and a FEA numerical ranking of 3 for this vulnerability category. Marble Falls Aquifer. The Marble Falls Aquifer is a minor aquifer, the subsurface extent of which is unknown. This aquifer is restricted to the flanks of the Llano Uplift region of Texas, and provides groundwater to parts of Blanco, Burnet, Lampasas, McCulloch, and San Saba Counties, and smaller areas of Kimble, Llano, and Mason Counties. The Marble Falls Limestone comprises the entire aquifer, with groundwater occurring in fractures and karst features such as solution cavities and channels in this formation. Groundwater in the outcrop areas is under watertable conditions with artesian conditions occurring downdip where younger formations overlie the Marble Falls Limestone. In most areas, the artesian portion is not extensive. Recharge to the Marble Falls Aquifer occurs in the outcrop areas where rainfall enters through karst features and stream seepage through faults at stream crossings. Springs and seeps from this aquifer are often associated with faults that also add considerably to the ease of recharge to the aquifer. The Marble Falls Aquifer is assigned an average DRASTIC Index of 126 and a high drinking water vulnerability ranking by the TCEQ resulting in a FEA numerical ranking of 1. The qualitative evaluation by the Pettyjohn et al. Aquifer Classification Scheme places this aquifer in Class Ib for a high drinking water vulnerability ranking. Based on the Pettyjohn et al. Aquifer Classification Scheme results, the Marble Falls Aquifer FEA numerical ranking is 1 for drinking water vulnerability. As with the Edwards (BFZ)-Barton Springs Segment Aquifer, the Marble Falls Aquifer aquatic habitat vulnerability ranking is dependent on whether a spill occurs in its outcrop areas. The Class Ib Pettyjohn et al. classification and documented natural discharge via numerous springs to streams justify a high aquatic habitat vulnerability ranking for this aquifer. The high aquatic habitat vulnerability ranking also equates a FEA numerical ranking of 1 for this ranking category. The vulnerabilities of the confined portion of the Marble Falls Aquifer were not ranked given that this aquifer is overlain by younger aquifer strata. The strata of the overlying younger aquifers offer a degree of protection for this aquifer, inhibiting the vertical migration of released crude oil. Ellenburger-San Saba Aquifer. The Ellenburger-San Saba Aquifer is a minor aquifer that occupies a roughly circular area in parts of 16 counties within and adjacent to the Llano Uplift 4-18 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL region. Hydrologically connected limestones and dolomites of the San Saba Limestone Member of the Wilberns Formation and formations of the Ellenburger Group make up this aquifer. Groundwater occurs within karst features, fractures and faults within the strata comprising this aquifer. Groundwater in the outcrop areas of the Ellenburger-San Saba Aquifer is under watertable conditions. Downdip, artesian conditions exist where strata of younger aquifers overlie the strata of this aquifer. Precipitation and stream seepage are the main sources of recharge to the Ellenburger-San Saba Aquifer. Sinkholes, caves, and other karst features, most associated with faults, are present on the aquifer outcrop and add considerably to the ease of recharge to the aquifer. Springs and seeps from this aquifer are often associated with faults that also add considerably to the ease of recharge to the aquifer. The TCEQ assigned an average DRASTIC Index of 126 and a high drinking water vulnerability ranking to the Ellenburger-San Saba Aquifer, which corresponds to a FEA numerical ranking of 1. A qualitative evaluation of the lithologic and hydrologic characteristics of this aquifer produced a Pettyjohn et al. classification of Class Ib and a high drinking water vulnerability ranking. Based on the Pettyjohn et al. classification results, the Ellenburger-San Saba Aquifer has a FEA numerical ranking of 1 with regard to drinking water vulnerability. The Ellenburger-San Saba Aquifer aquatic habitat vulnerability ranking is similar to the Marble Falls Aquifer, being dependent on whether a spill occurs in its outcrop areas. A high aquatic habitat vulnerability ranking for this aquifer is warranted because of the 1) Class Ib Pettyjohn et al. classification; 2) presence of karst features; and 3) documented natural discharge via numerous springs to streams. The above Pettyjohn et al. classification therefore warrants an FEA numerical ranking of 1 for aquifer aquatic habitat vulnerability. Ranking of the confined portion of the Ellenburger-San Saba Aquifer was not performed due to the aquifer being covered by younger aquifer strata. The strata of the overlying aquifers afford a measure of protection for this aquifer, inhibiting the vertical migration of released crude oil. Hickory Aquifer. The Hickory Aquifer, a minor bedrock aquifer, occupies parts of 19 counties in the Llano Uplift region. This aquifer consists exclusively of the Hickory Sandstone Member of the Riley Formation. The Hickory Sandstone is a mixture of sandstones, siltstones, and mudstones. Outcrops of the Hickory Sandstone are discontinuous and overlie the flanks of the exposed Precambrian rocks that form the central core of the Llano Uplift. The aquifer is unconfined in outcrop areas and becomes artesian downdip of the outcrop areas. Block faulting has compartmentalized the Hickory Aquifer thereby restricting groundwater flow across the fault planes. Recharge to the Hickory Aquifer is from rainfall infiltrating the sandy outcrop and where streams cross the aquifer outcrop areas. Springs and seeps from this aquifer are often associated with faults which also add considerably to the ease of recharge to the aquifer. An average DRASTIC Index of 114 and a medium drinking water vulnerability ranking were assigned to the Hickory Aquifer by the TCEQ. The medium ranking is concurrent with a FEA drinking water vulnerability numerical ranking of 1. The lithologic and hydrologic characteristics of this aquifer point to a Pettyjohn et al. classification of Class IIa and a high drinking water 4-19 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL vulnerability ranking. Based on the Pettyjohn et al. classification results, the Hickory Aquifer has a FEA drinking water vulnerability numerical ranking of 1. The Hickory Aquifer aquatic habitat vulnerability ranking is comparable to the Marble Falls and the Ellenburger-San Saba aquifers, in that secondary structures (faults and fractures) increase vulnerability to crude oil releases that occur in the outcrop areas. A high aquatic habitat vulnerability ranking for this aquifer is warranted because of the 1) Class IIa Pettyjohn et al. classification; 2) porous medium comprising this aquifer; 3) presence of faults and fractures at the outcrop surface; and 4) documented natural discharge via numerous springs to streams. The above Pettyjohn et al. classification and associated vulnerability merits an FEA numerical ranking of 1 for aquifer aquatic habitat vulnerability. As with the Marble Falls and Ellenburger-San Saba Aquifer, the vulnerabilities of the confined portion of the Hickory Aquifer were not ranked since this aquifer is covered by younger aquifer strata. The overlying younger aquifer strata offer a degree of protection for this aquifer, hindering the vertical migration of released crude oil. Edwards-Trinity (Plateau) Aquifer. The Edwards-Trinity (Plateau) Aquifer is a major aquifer that underlies the Edwards Plateau extending from the Hill Country of Central Texas to the Trans-Pecos region of West Texas. The water-bearing strata comprising the Edwards-Trinity (Plateau) Aquifer are predominantly karst-modified limestone and dolomite formations of the Edwards Group and limestones and sands of the Trinity Group. The aquifer is generally unconfined; but, may be confined to semi-confined locally where relatively impermeable sediments of the overlying basal member of the Edwards Group exist. Recharge to the Edwards-Trinity (Plateau) Aquifer occurs mainly from precipitation infiltrating joints, crevices, and solution openings on the Edwards Group outcrop area and from stream losses from the many intermittent streams crossing this outcrop. The Trinity Group, having few outcrops areas to receive direct recharge, gets much of its water by cross-formational flow from the overlying Edwards Group. Springs and seeps from the Edwards-Trinity (Plateau) Aquifer occur mostly along the margins of the aquifer from where the watertable intersects the land surface, and provide base flow to many streams of the plateau. The Edwards-Trinity (Plateau) Aquifer is assigned an average DRASTIC Index of 107 and a medium drinking water vulnerability ranking by the TCEQ, which equates to a FEA drinking water vulnerability numerical ranking of 1. The qualitative evaluation performed using the Pettyjohn et al. Aquifer Classification Scheme qualified this aquifer as meeting the criteria for Class Ib, and a high drinking water vulnerability ranking. Based on the Pettyjohn et al. Aquifer Classification Scheme results, the Edwards-Trinity (Plateau) Aquifer FEA numerical ranking is 1 with regard to drinking water vulnerability. The Pettyjohn et al. classification of Class Ib and the frequent occurrence of natural discharge as springs and seeps from the Edwards-Trinity (Plateau) Aquifer are evidence for a high aquatic habitat vulnerability ranking. Thus, this aquifer warrants a FEA aquatic habitat vulnerability numerical ranking of 1. 4-20 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Pecos Valley Aquifer. The Pecos Valley Aquifer is a major aquifer located in the upper part of the Pecos River Valley of West Texas and provides water to parts of Andrews, Crane, Ector, Loving, Pecos, Reeves, Upton, Ward, and Winkler Counties. Lacustrine sediments, sand, mudstone, siltstone, conglomerate, limestone, shale, and gypsum deposited in several structural basins of the Pecos Valley comprise this aquifer. The Pecos Valley Aquifer is an unconfined aquifer that occurs only in outcrop. The Pecos Valley Aquifer receives recharge from infiltrating precipitation and from cross-formational flow from the Edwards-Trinity (Plateau) Aquifer. Surface water diverted from the Pecos River also recharges the Pecos Valley Aquifer as seepage from irrigation fields. The Pecos Valley Aquifer also sustains numerous springs that discharge into the Pecos River. The TCEQ calculated an average DRASTIC Index of 95 and assigned a medium drinking water vulnerability ranking for the Pecos Valley Aquifer. The above TCEQ drinking water vulnerability ranking amounts to a FEA numerical ranking of 2 for drinking water vulnerability. The qualitative evaluation using the Pettyjohn et al. classification scheme produced a Class Ia result pointing to a high drinking vulnerability. The above qualitative evaluation shows that a FEA numerical drinking water vulnerability ranking of 1 is applicable. The Pettyjohn et al. aquifer classification given above and the fact that Pecos Valley Aquifer also sustains numerous springs to the Pecos River denotes that this aquifer ranks high with regard to aquifer aquatic habitat vulnerability. Accordingly, the FEA numerical ranking is 1 for aquatic habitat vulnerability. Southern Ogallala Aquifer. The Southern Ogallala Aquifer is a major aquifer in the High Plains region of Texas extending south of the Canadian Breaks to Winkler, Ector, Midland, and Glasscock Counties and from the eastern escarpment of the Southern High Plains westward to the Texas-New Mexico border. Fluvial gravel, sand, silt, clay, and eolian sand and silt of the Ogallala Formation comprise the Southern Ogallala Aquifer. The Southern Ogallala outcrops throughout the Southern High Plains Region and is under watertable conditions. Recharge to this aquifer occurs principally by infiltration of precipitation on the surface and, to a lesser extent, by upward leakage from underlying formations. The primary sources of recharge to the Southern Ogallala Aquifer are direct rainfall infiltration on the outcrop, indirect rainfall infiltration through playas and headwater creeks, irrigation return flow, and upward cross-formational flow from underlying minor aquifers such as the Edwards-Trinity (High Plains) Aquifer and the Dockum Aquifer. Numerous springs and seeps occur along the eastern High Plains escarpment, within the draws, and along the margins of salt lake basins. For many municipalities, the Southern Ogallala Aquifer is the sole source of drinking water. The average DRASTIC Index of 99 and medium drinking water vulnerability ranking assigned by the TCEQ for the Southern Ogallala Aquifer corresponds to a FEA drinking water vulnerability numerical ranking of 2. The Pettyjohn et al. qualitative evaluation shows that this aquifer meets the Class Ic criteria, and thereby, qualifies for a high drinking water vulnerability ranking. Under the above Pettyjohn et al. evaluation, the Southern Ogallala Aquifer has a FEA drinking water vulnerability numerical ranking of 1. 4-21 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL The Class Ic Pettyjohn et al. classification for the Southern Ogallala Aquifer and natural discharge occurring as numerous springs draws and basins point out a high aquatic habitat vulnerability ranking for this aquifer. This high aquifer aquatic habitat vulnerability ranking for the Southern Ogallala Aquifer yields a FEA aquifer aquatic habitat vulnerability numerical ranking of 1. 4.2.1.3 Potentially Vulnerable Public Water Supply (PWS) Water Wells The 1996 Safe Drinking Water Act (SDWA) Amendments required all states to assess the susceptibility of every public drinking water source within that state. In response, the TCEQ assessed every PWS for susceptibility to certain chemical constituents by May 2003 to comply with this federal regulation. A PWS is defined as a public water system that supplies water to the public (more than 15 individuals) and is regulated by the TCEQ. The results of this source water susceptibility assessment were provided to the PWS for use in implementing local source water protection projects. The TCEQ placed the spatial datasets created during the source water susceptibility assessment process into a web-based GIS viewer titled “The Source Water Assessment Viewer” that is accessible through the TCEQ website. This web-based viewer is designed to allow public access to the PWS source water susceptibility assessment spatial datasets. The information contained in these spatial datasets are specific to each PWS, such as but not limited to aquifer used, water well depth, well screen depth, and the area that comprises a PWS water well capture zone. A capture zone is a three-dimensional area that surrounds a pumping water well. Groundwater within the capture zone flows to and is captured by that water well. Groundwater outside the capture zone boundary will not flow to or be captured by that pumping well. A well capture zone is usually determined from aquifer characteristics, pumping rate and well construction details. The TCEQ calculated “time-of-travel capture zones” for public supply water wells using computer algorithms based upon the hydrogeology of the area specific to a well and parameters specific to that well. A time-of-travel capture zone is delineated by an isochronal boundary. A water particle and any contaminant associated that water particle located at that isochronal boundary will take “x” number of years to migrate to the associated pumping water well and be “captured” by that water well. For example, a water particle located at a 2-year time-of-travel capture zone boundary will take two years to reach and be captured by that zone’s pumping water well. When some of the required information was missing for a PWS water well, the TCEQ, by default, assigned a half-mile diameter circle, a fixed radius, to delineate the capture zone for that particular PWS water well. This fixed radius is not based on well-specific construction and hydrogeologic information. A qualitative analysis was performed on spatial datasets of PWS water wells exported from the TCEQ Source Water Assessment Viewer website and loaded into a GIS. The first step in the qualitative analysis process was to filter out from the spatial datasets those PWS water wells located outside the area of review (AOR). The AOR runs parallel with and extends approximately five miles on either side of the zone of potential impact. The resulting spatial datasets for those PWS water wells located within the AOR were evaluated to identify those 4-22 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL PWS water wells with the greatest potential vulnerability risk to a crude oil release from the System. The next qualitative analysis step involved sorting the spatial datasets into groups and subgroups. The initial grouping placed the AOR PWS water wells into one of two groups: • Group 1 - Those PWS water wells located within the zone of potential impact boundary; and, • Group 2 - Those PWS water wells located outside the zone of potential impact boundary. Those PWS water wells belonging to Group 1, due to being located within the zone of potential impact, have the greatest potential vulnerability risk to a crude oil release from the System. The PWS water well placed within Group 2 required further evaluation to ascertain the degree of potential vulnerability risk to a release within the zone of potential impact. The spatial datasets for those PWS water wells located outside the zone of potential impact were sorted and placed into four subgroups: • Subgroup 2a - Those PWS water wells with 2-year time-of-travel and 0.5-mile fixed radius capture zones that do not encroach into the potential zone of impact; • Subgroup 2b - Those PWS water wells with 2-year time-of-travel capture zones that encroach into the potential zone of impact; • Subgroup 2c - Those PWS water wells with 0.5-mile fixed radius capture zones that encroach into the potential zone of impact, and do not encompass and/or are not immediately adjacent to 2-year time-of-travel capture zones; and, • Subgroup 2d - Those PWS water wells with 0.5-mile fixed radius capture zones that encroach into the potential zone of impact, and do encompass and/or are immediately adjacent to 2-year time-of-travel capture zones. The 2-year time-of-travel capture zone (the shortest calculated by the TCEQ) was selected to identify those PWS water wells located outside the zone of potential impact having the highest probable vulnerability to a release. The rationale for using the 2-year time-of-travel capture zones is that those wells having 2-year time-of-travel capture zones that encroach into the zone of potential impact would be affected much sooner than those public supply wells having 2-year time-of-travel capture zones that do not encroach into the zone of potential impact. The 0.5-mile fixed radius capture zone was used when a 2-year time-of-travel capture zone was not calculated by the TCEQ. The Subgroup 2a PWS water wells have the least potential vulnerability risk to a crude oil release occurring within the zone of potential impact. Groundwater underlying the zone of potential impact is least likely to be captured by the Subgroup 2a water wells. Those PWS water wells belonging to Subgroups 2b and 2c have the same potential vulnerability risk to a System crude oil release as do the Subgroup 1 PWS water wells. Groundwater underlying the zone of potential impact would flow to and be captured by those PWS water well belonging to Subgroups 2b and 2c. 4-23 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL The incursion of Subgroup 2d PWS water well capture zones into the zone of potential impact indicates by default that this subgroup of water well has a potential vulnerability risk equal to that of Subgroup 1. However, the presence of 2-year time-of-travel capture zones within the boundaries of and/or immediately adjacent to a 0.5-mile fixed radius capture zones are usable as a secondary line of evidence for a more in-depth qualitative analysis of the Subgroup 2d potential vulnerability risk. The coverage areas of 2-year time-of-travel capture zones that are present within and/or surrounding a 0.5-mile fixed radius capture zone reflect the hydrogeologic characteristics of the aquifer within that fixed radius capture zone coverage area. Therefore, it is reasonable that a 2-year time-of-travel capture zone for the same water well, if had been calculated by the TCEQ, would have a coverage area of similar size as those time-of-travel capture zones located within and immediately surrounding the fixed radius capture zone of interest. This in-depth qualitative analysis was performed by relocating the largest 2-year time- of-travel capture zone within the limits of or immediately adjacent to the 0.5-mile fixed radius capture zone of interest to the fixed radius capture zone PWS water well location. Those Subgroup 2d PWS water wells with relocated 2-year time-of-travel capture zones not encroaching into the zone of potential impact have the least potential vulnerability risk to a crude oil release occurring within the zone of potential impact, and were filtered from the spatial dataset. Those Subgroup 2d PWS water wells having relocated 2-year time-of-travel capture zones encroaching into the zone of potential impact have the same potential vulnerability risk to a System crude oil release as do the Subgroup 1 PWS water wells. The qualitative analysis identified 134 PWS wells in total that are present within or have qualified capture zones incursions into the zone of potential impact. The locations of these 134 PWS water wells are shown on Figures 4.2.1-3a through 3d. Table 4.2.1-5 lists the PWSs associated with those potentially vulnerable PWS water wells; the aquifers utilized by these water wells; and, the cross-reference PWS water well ID number for Figures 4.2.1-3a to 3d. 4.2.1.4 Identification of Sensitive Groundwater Resource Areas In this FEA, a sensitive groundwater resource area is a drinking water resource, as generally defined in 49 CFR Part 195.6 as related to aquifers, within the zone of potential impact, and aquifer with a potential connection to an aquatic habitat that is sensitive to environmental damage from a crude oil release from the Proposed Project. A qualitative numerical ranking system was devised for this assessment to identify sensitive groundwater resource areas within the zone of potential impact. The criteria by which a sensitive groundwater resource area was determined to be present are discussed in Sections 4.2.1.1 through 4.2.1.3 of this assessment. Aquifer drinking water vulnerability within the zone of potential impact was determined on two levels, the TCEQ DRASTIC Aquifer Vulnerability Ranking and the Pettyjohn et al. Aquifer Classification Scheme. Vulnerability for both levels was ranked from 1 (high vulnerability) to 3 (low vulnerability) as shown in Table 4.2.1-4. The vulnerability of aquifer-associated aquatic habitats was also qualitatively evaluated using the Pettyjohn et al. Aquifer Classification Scheme and literature documentation that natural 4-24 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL discharge to streams is a common and frequent occurrence. Aquifer aquatic habitat vulnerability was ranked from 1 (high vulnerability) to 3 (low vulnerability). The aquifer aquatic habitat ranking is also shown on Table 4.2.1-4. The vulnerability ranking for PWS water wells within the zone of potential impact was based on 1) the presence or absence of PWS water wells within the zone as determined in Section 4.2.1.3; and 2) well depth. Drinking water resource vulnerability was given a ranking of either 1 (wells present, <50 feet below ground level (bgl), or wells producing from a karst sole-source aquifer); 2 (wells present, >50 feet bgl producing from an aquifer not sole-source); or 3 (wells not present). A GIS was used to overlay map files of 1) the major/minor aquifers from the TWDB; 2) PWS water wells and capture zones from the TCEQ; and 3) the zone of potential impact. This mapping method allowed for the reasonable ranking of aquifer and drinking water resource vulnerability within the zone of potential impact. The pipeline MP markers were used to locate the start and end of an aquifer outcrop or subcrop within the zone of potential impact along the pipeline route. The sum of the aquifer and PWS water well vulnerability rankings was used to identify sensitive and non-sensitive groundwater resource areas. A ranking sum less than 7 indicates that an aquifer outcrop or subcrop is a sensitive groundwater resource area. The results of the sensitivity ranking along the zone of potential impact are presented in Table 4.2.1- 4. Those aquifer areas identified as sensitive groundwater resource areas are summarized below. Gulf Coast Aquifer System. That area of the Gulf Coast Aquifer System from MP 20 to MP 21 qualifies as a sensitive groundwater resource area. The Pettyjohn et al. Aquifer Classification Scheme ranking of Class Ia and the presence of PWS water wells 50 feet or less in depth within the zone of potential impact are the critical ranking parameters. Brazos River Alluvium Aquifer. The segment of the Brazos River Alluvium Aquifer located between MPs 59.5 and 66 ranks as being a sensitive groundwater resource. The TCEQ, Pettyjohn et al., and aquatic habitat vulnerability rankings are the key ranking factors. Colorado River Alluvium. Several areas of the Colorado River Alluvium Aquifer are ranked as sensitive groundwater resource areas based on the TCEQ, Pettyjohn et al., and aquatic habitat vulnerability rankings. These sensitive areas are located in the following MP intervals: 119- 120.5, 121-123, 125-126.5, 128-129.5, and 130.5-141.5. Edwards (BFZ) Aquifer-Barton Springs Segment. The outcrop area of the Edwards (BFZ) Aquifer located between MPs 170.5 and 173.5 ranks as a sensitive groundwater resource for all four ranking parameters. The sum of all rankings listed on Table 4.2.1-4 indicates this aquifer area to be the most sensitive along the zone of potential impact. Trinity Aquifer System-Hill Country. The ranking sum for the Trinity Aquifer-HC outcrop shows this aquifer to be a sensitive groundwater resource where crossed by the zone of potential impact. A Pettyjohn et al. Aquifer Classification Scheme ranking of Class IIa, high 4-25 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL aquatic aquifer habitat ranking, and the presence of PWS water wells or encroaching capture zone are the critical ranking parameters. The aquifer outcrops within the following MP intervals: 173.5-198.5, 206-207.5, 216-220, and 222.5-224.5. Marble Falls Aquifer. The sum rankings for the Marble Falls Aquifer outcrop area located between MPs 198.5 and 199 qualify this area as a sensitive groundwater resource. The critical factors for this ranking are the TCEQ ranking, Pettyjohn et al. Class Ib classification, and high aquifer aquatic habitat ranking. Ellenburger-San Saba Aquifer. The Ellenburger-San Saba Aquifer sum ranking indicates that this aquifer is a sensitive groundwater resource where traversed by the zone of potential impact with the TCEQ ranking, Pettyjohn et al. Class Ib classification, and high aquifer aquatic habitat ranking being the critical rankings. Those MP intervals crossing the Ellenburger-San Saba are: 199-206, 249.5-254.5, 264-270, 272-274, and 275.5-276.5. Edwards-Trinity (Plateau) Aquifer. The ranking sum for the Edwards-Trinity (Plateau) Aquifer outcrop show this aquifer to be a sensitive groundwater resource where crossed by the zone of potential impact. A Pettyjohn et al. Aquifer Classification Scheme ranking of Class Ib and high aquatic aquifer habitat ranking are the key ranking parameters. The aquifer outcrops within the following MP intervals: 222-222.5, 227-227.5, 232.5-233, 237-237.5, 238-238.5, 246-246.5, 254.5-257.5, 270-272, 274-275.5, and 277.5-447. 4.2.2 Surface Water 4.2.2.1 Description of Surface Water Resources The surface water bodies associated with the Proposed Project are unchanged from those contained in the 1999 EA. Accordingly, much of the spatial information regarding surface water is extracted from the 1999 EA. Because the pipeline from Crane Station to El Paso will not change product service and is a “connected action” of the Proposed Project, it is not addressed in this section. Changes were also made to update information that has changed since the time of preparation of the 1999 EA. The Proposed Project intersects the following major river basins, from east to west: San Jacinto River, Brazos River, and Colorado River. This section identifies the streams crossed by the pipeline and defines the characteristics relevant in comparing stream size, water quality, and use (i.e., public water supply and irrigation). The Proposed Project crosses 58 streamlines according to the USGS 1:100,000 hydrography. Thirty-eight of the streams crossed are of second-order or higher (meaning the streams are downstream of a junction of at least two streamlines). The pipeline crosses the mainstem of the Brazos River, Colorado River, Pedernales River, and the Llano River. A number of significant tributaries of these rivers are also crossed, e.g., the James River (a tributary of the Llano River) and Onion Creek (a tributary of the Colorado River). Each tributary has a basin area exceeding 200 square miles upstream of the pipeline. The watersheds upstream of the pipeline for each of the second-order (or higher) streams crossing the pipeline are delineated in Figure 4.2.2-1. The basin areas of the bayous in 4-26 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Harris County (White Oak Bayou, Greens Bayou, Halls Bayou, and Hunting Bayou) were not delineated and are represented in later tables by data collected from nearby flow/water quality gauges. The crossings are numbered using the Longhorn Pipeline mileposts in increasing order from east to west. 4.2.2.1.1 Description of Significant Stream Crossings Along Route The descriptions of individual major streams crossed by the Proposed Project are provided below. These descriptions include the general uses of these streams as they are stated in the Texas Water Quality Standards which are codified in Title 30, Chapter 307 of the Texas Administrative Code. These Standards establish explicit goals for the quality of streams, rivers, lakes, and bays throughout the state. The Standards identify appropriate uses for the state’s surface waters, including aquatic life, recreation, and sources of public water supply (or drinking water). The criteria used by the TCEQ for evaluating support of those uses include dissolved oxygen, temperature, pH, dissolved minerals, toxic substances, and bacteria. Greens Bayou. The Proposed Project crosses Greens Bayou in Harris County near MP 7. Greens Bayou is located within the San Jacinto River Basin and is designated by the TCEQ to be suitable for primary contact recreation and limited aquatic life use. The water uses do not include public water supply. Greens Bayou is channelized with sloping banks that contain very little native vegetation and are mainly covered with Bermuda grass. The water is slow-moving over a bottom substrate partially composed of gravel and silt. White Oak Bayou. The Proposed Project crosses White Oak Bayou in Harris County near MP 32. White Oak Bayou is located within the San Jacinto River Basin and is designated by the TCEQ to be suitable for primary contact recreation and limited aquatic life use. The water uses do not include public water supply. White Oak Bayou is a completely channelized body of water. The banks are steeply sloped and covered in Bermuda grass. There is very little native vegetation near the channel. Water flow is slow but constant. Cypress Creek. The Proposed Project crosses Cypress Creek in Harris County near MP 47. Cypress Creek is located within the San Jacinto River Basin and is designated by the TCEQ to be suitable for primary contact recreation and high aquatic life use. The water uses include public water supply. Cypress Creek is partially channelized due to the installation of flood control measures. Vegetation in the vicinity of the creek consists primarily of native cypress, the creek’s namesake. Brazos River. The Proposed Project crosses the Brazos River at the Waller-Washington County line near MP 65. The Brazos River is located within the Brazos River Basin and is designated by the TCEQ to be suitable for primary contact recreation and high aquatic life use. The water uses include public water supply. The Brazos River is a slow-moving, meandering river with turbid water and a silt-dominated substrate. Its tree-lined banks are relatively wide and steep. The river supports many fish species and is a popular location for recreational fishing. 4-27 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Colorado River. While passing through Bastrop County, the pipeline crosses the Colorado River near MP 136. The Colorado River is located within the Colorado River Basin and is designated by the TCEQ to be suitable for primary contact recreation and high aquatic life use. The water uses include public water supply. Generally, the Colorado River is a wide and slow- moving flow over a substrate of silt. The riverbanks are lined with willow, cottonwood, pecan, elm, and sycamore trees, which help to prevent erosion and provide excellent cover for fish. Onion Creek. Onion Creek is crossed in Travis County 167. Onion Creek is located within the Colorado River Basin and is designated by the TCEQ to be suitable for primary contact recreation and high aquatic life use. The water uses include public water supply and Aquifer Protection use. The Aquifer Protection use applies to the contributing, recharge, and transition zones of the Edwards Aquifer. The creek flows through both the Edwards Plateau and the Blackland Prairies regions. In the Edwards Plateau region, the banks of Onion Creek are limestone and lined with bald cypress, sycamore, cottonwood, American and cedar elm, and pecan trees. In the Blackland Prairie natural region, the vegetation remains the same, but the banks are more erodable due to deeper soils. Barton Creek. The pipeline crosses Barton Creek in Travis County near MP 184. Barton Creek is located within the Colorado River Basin and is designated by the TCEQ to be suitable for primary contact recreation and high aquatic life use. While not designated as a public water supply, the water uses include Aquifer Protection use. The Aquifer Protection use applies to the contributing, recharge, and transition zones of the Edwards Aquifer. Barton Creek is spring-fed with limestone banks and substrate. The creek flows between multiple pools and riffles throughout its length. The banks are vegetated with bald cypress, sycamore, cottonwood, American and cedar elm, and pecan trees, and the creek provides good habitat for numerous fish species. Pedernales River. The Pedernales River is crossed in Blanco County near MP 202. The Pedernales River is located within the Colorado River Basin and is designated by the TCEQ to be suitable for primary contact recreation and high aquatic life use. The water uses include public water supply. The Pedernales River is generally shallow and flows clear along rocky banks that are lined with bald cypress and cottonwood trees. Flows of this river can increase dramatically after a heavy rain. Llano River. The pipeline encounters the Llano River in Kimble County near MP 281. The Llano River is located within the Colorado River Basin and is designated by the TCEQ to be suitable for primary contact recreation and high aquatic life use. The water uses include public water supply. The river is spring-fed and flows over limestone and gravel substrate, which produces many small riffles. Limestone banks vary in slope and are lined with trees and dense vegetation. The river provides excellent habitat for fish with abundant cover and shade. Although the Llano River produces one of the best fisheries in Texas, it is relatively under-utilized due to limited access. 4-28 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 4.2.2.1.2 Water Quality Downstream of Pipeline Crossings In the 1999 EA, the surface water quality sampling sites downstream of the Proposed Project were identified using the EPA database, STORET. Sites were selected which were the closest to the pipeline crossings and that had significant analyses since 1985. The locations for these sites are shown in Figure 4.2.2-2. The inorganic and coliform analytical data for each of these sites were aggregated as averages into Table 4.2.2-1. This table is intended for relative comparisons of general water quality along the route, and the averaging was performed on the raw numbers provided in the database. Measurements reported as equal to the analytical detection limit were included in the averages. Outliers of more than two standard deviations from the statistical mean were not included in these averages. The STORET database was reviewed for the period from the year 2000 through 2011 for the same STORET station numbers provided on Table 4.2.2-1 in the 1999 EA. The only additional surface water analytical data identified was for TCEQ stations 11576, 12451, 12377, and 14231. Analysis of this data indicated that there were no significant changes in the average value of the reported concentrations of the water quality parameters monitored versus those presented in the 1999 EA for the same station numbers. Table 4.2.2-1 is modified to include this updated data. An important aspect of the water quality concerns is the water bodies that have been identified by the TCEQ to be impaired. In this regard, the TCEQ maintains what is referred to as a Total Maximum Daily Load (TMDL) Program that is authorized by and created to fulfill the requirements of Section 303(d) of the Federal Clean Water Act and its implementing regulations. The TMDL Program was developed with the purpose of improving the water quality in rivers, lakes, and estuaries in the state. TMDLs are developed for surface waters that are impaired, i.e., quality limited, due to a pollutant or adverse condition. Based on the environmental target in the TMDL, the state develops an implementation plan (IP) to mitigate sources of pollution within the watershed and restore impaired uses. A TMDL is like a budget for pollution, i.e., determining the extent to which pollutant concentrations must be reduced to meet quality standards. An IP usually puts the TMDL into action by outlining the steps necessary to reduce pollutant loads through regulatory and voluntary activities. In some instances, TMDLs are implemented through watershed protection plans (WPPs). Since the time that the 1999 EA was prepared, there have been changes in the surface waters that have been designated as being subject to TMDLs. Certain streams have been added, removed, and in some cases remain subject to the 303(d) requirements. A summary of 303(d)-listed stream segments that are located within the zone of potential impact along the Proposed Project is provided on Table 4.2.2-2. This table also provides the year that the segment was first listed and the type of impairment that caused it to be listed. None of these 303(d)-listed segments are impaired due to the presence of petroleum hydrocarbons. Figures 4.2.2-3, 4.2.2-4, and 4.2.2-5 depict the locations of these segments. 4-29 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 4.2.2.1.3 Identification of Downstream Water Users The 1999 EA identified potentially vulnerable surface water resources along the Longhorn Pipeline and quantifies their relative importance and vulnerabilities. This information is relatively unchanged in this FEA. Since the time the 1999 EA was prepared, the TCEQ has prepared Source Water Susceptibility Assessment (SWSA) reports for every public water supply in the State as required by the 1996 SDWA Amendments. The SDWA Amendments required all states to assess the susceptibility of public drinking water sources to contamination. The TCEQ provided the results of the assessments to each PWS in 2003. These comprehensive SWSA reports represent years of research, analysis, and investigation by state officials, trade organizations, federal, state and local agencies, and water service providers. The assessments contain information specific to each PWS, its source waters, and areas of concern which may impact source waters. The information is intended to enhance the ability of a PWS to protect its source waters and ensure their continued reliability. Within the context of the FEA, the SWSA program did take into consideration potential impacts associated with petroleum pipelines such as the Longhorn Pipeline. The TCEQ and the USGS developed procedures to assess the susceptibility of PWS source waters to 227 selected drinking-water contaminants. The procedures, as implemented in automated software, enable TCEQ staff, PWSs, and others to (1) identify the most susceptible PWSs on which to focus source-water protection efforts, (2) reduce monitoring costs associated with ensuring safe drinking water, (3) enhance public understanding of source-water protection, and (4) identify land-management practices needed to protect source waters. A surface water susceptibility assessment for a PWS has eight components. Several of the components result in relative susceptibility ratings of high, medium, or low. These ratings are designed to support an overall susceptibility rating for the PWS sources and system. The components are: 1. Identification Component - determination of hydrologic attributes (for example, topography and drainage network) used to delineate the area(s) that potentially contribute source water for a PWS. 2. Delineation Component - delineation of PWS source area(s) based on attributes determined by the identification component. 3. Intrinsic Susceptibility Component - determination of the intrinsic attributes (for example, soil erodibility or mean annual runoff) within PWS source areas and evaluation of their potential to make the PWS more or less susceptible to contamination. This component produces a relative susceptibility rating for all contaminants. 4. Nonpoint-Source Susceptibility Component - determination of statistical relations between measured contaminants in surface water and watershed characteristics (for example, land use or pesticide use) within PWS source areas. Statistical model results will determine the probability that a drinking-water contaminant will exceed a TCEQ- specified threshold concentration. In cases of few or no data, a relative susceptibility 4-30 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL rating is assigned and is based on the frequency of contaminant detection or level of land-use activities within the PWS source area associated with contaminant production or use. 5. Point-Source Susceptibility Component - determination of potential point sources of contaminants to the PWS. A relative susceptibility rating is produced for each contaminant and is based on the permitted discharges from known point-source locations (for example, oil refineries). Estimates of contaminant concentrations at low streamflow will be calculated from permitted releases from point sources within the PWS source area. A relative susceptibility rating is assigned to each contaminant and is based on the ratio of total permitted releases to mean annual streamflow. 6. Area of Primary Influence (API) Component - determination of the proximity of a potentially adverse land use (for example, pipeline or railroad). An analysis is performed for the potential contaminants associated with the potentially adverse land use that is within a limited area (2-hour travel or 1,000-foot buffer) around the PWS surface water intake (or reservoir). A relative susceptibility rating is produced for each contaminant and is based on number, type, size, and location of the potentially adverse activities in the PWS source area. 7. Contaminant Occurrence Component - determination of contaminant detections (at or greater than TCEQ specified threshold concentrations) at water-quality monitoring sites or other nearby PWS. A relative susceptibility rating of “high” is assigned to the contaminant if it has been detected greater than the threshold concentration at a nearby site. No relative susceptibility rating is assigned to the contaminant if it has not been detected greater than the contaminant threshold concentration. 8. Susceptibility Summary Component - combination of the seven components into a summary relative susceptibility rating for each PWS source and a single summary rating for the PWS. For this assessment, the locations of PWS were obtained from the May 2011, version of the TCEQ SWSA Viewer files. The viewer contains the spatial datasets used and created during a source water susceptibility assessment process that was conducted by the TCEQ. These files were then imported into the GIS database depicting the location of the Proposed Project and the zone of potential impact. The exact locations of all PWS intakes with an API within the zone of potential impact were then identified and included in this FEA. Based upon this database, the only API located within the zone of potential impact is the surface water intake for the Pedernales Falls State Park (PWS ID No. 0160004) located on the Pedernales River. Figure 4.2.2-6 depicts this API boundary and the location of State Park water intake. This intake is 3.58 stream miles from the Proposed Project crossing of the Pedernales River. Figure 4.2.2-7 identifies three petroleum pipelines, including the Proposed Project that cross the Pedernales River. An assessment was performed by the TCEQ for the API of the Pedernales Falls State Park water supply system. The findings of the TCEQ assessment are as follows: 4-31 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Pedernales Falls State Park Water System The SWSA susceptibility ratings are divided into three divisions: “High”, “Medium”, and “Low”. In the case of the Pedernales Falls State Park, the potential for contamination from volatile organic chemicals (i.e., the category that would include oil pipelines) was rated as being “Medium”. The meanings of the SWSA ratings are provided below: “High” susceptibility means there are activities near the source water and the natural conditions of the aquifer or watershed make it very likely that chemical constituents may come into contact with the source water. It does not mean that there are any health risks present. “Medium” susceptibility means there are activities near the source water and the natural conditions of the aquifer or watershed make it somewhat likely that chemical constituents may come into contact with the source water. It does not mean that there are any health risks present. “Low” susceptibility means there are activities near the source water and the natural conditions of the aquifer or watershed make it unlikely that chemical constituents may come into contact with the source water. The API boundary for the headwaters of Lake Travis are located 6.1 stream miles downstream of the Proposed Project and the Mansfield dam is located 66.1 stream miles from the pipeline. Besides Pedernales Falls State Park, there are currently 10 water supply users located within Lake Travis and downstream of this stream crossing (see following table). PWS Name Miles Downstream of Pedernales Stream Crossing Lago Vista 39.8 Village of Briarcliff 40.3 Travis County Municipality Utility District (MUD) 10 43.4 4-32 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL PWS Name Miles Downstream of Pedernales Stream Crossing 47.1 50.4 50.9 51.6 52.0 55.7 62.2 Inverness Point Lakeway MUD Hurst Creek MUD Travis County WCID Point Venture Lakeway MUD Travis County Water Control and Improvement District (WCID) 17 Sail Haven City of Austin Water Treatment Plant (WTP) No. 41 64.7 1 The City of Austin is in the process of constructing Water Treatment Plant No. 4. Lake Austin is located downgradient of Lake Travis and upgradient of Lady Bird Lake. The length of this segment is 20.25 stream miles and starts at Mansfield Dam and ends at the Tom Miller Dam. There are nine water supply intakes from Lake Austin including private and public water supplies. The only avenue of contaminants to Lake Austin from the Longhorn Pipeline would be through the Mansfield Dam. This is due to the fact that there is no other hydrologic connection between the Longhorn Pipeline and Lake Austin. The discharge through Mansfield Dam is a controlled release below the water surface that flows through a hydroelectric generator. Any impacts to Lake Austin would likely to be associated with dissolved constituents. The concentrations of any dissolved constituents, most likely benzene, would be expected to be below levels of human health concern for any of these nine water supply intakes. Accordingly, both the 1999 EA and this FEA make the assumption that there would be no harmful impacts to Lake Austin as a result of a pipeline release. Although located outside of the zone of potential impact, the API for Hill Country Springs is located on Slaughter Creek at a point 1.42 miles beyond the zone of potential impact and its water supply intake is located 8.2 miles downstream. Because of this, the Hill Country Springs water supply intake was added to the list of stream crossings ranked in terms of resource importance. In the 1999 EA, potential water users downstream of the pipeline were identified using the TCEQ Water Rights Database (as available from TNRIS). This information is provided in Table 4.2.2-3. For this FEA, the TCEQ Water Rights Database File was downloaded and compared to the data presented in the 1999 EA for the period from the year 2000 through June 2011. For this period, there were 744 additional water rights added to the database. This list was modified to retain those water rights evaluated in the 1999 EA (municipal/domestic, industrial, mining, irrigation, and recreation). The list was further modified to delete those water right amendments included in the 1999 EA, the water rights on the Highland Lakes that were already addressed as APIs, and water rights terminations. The remaining water rights were systematically reviewed for their locations downstream of the pipeline crossing. No other water users besides those 4-33 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL categories addressed above were noted in the remaining water rights listed in the TCEQ Water Rights Database. The TCEQ database of public surface water supplies identifies numerous additional water users downstream of the pipeline. In the 1999 EA, the locations for these public water users were imported into the study area mapping, were edited to contain only users downstream of the pipeline, and were identified in Figure 4.2.2-1 with a symbol designating the water use. This database was the source for the identification of the location of the numerous water users contiguous to the Highland Lakes. For this FEA, the locations of public water supply intakes were reviewed for their proximity of their API to the zone of potential impact. The water intake on Slaughter Creek for Hill Country Springs was added to the list of downstream water supplies due its close proximity to the zone of potential impact. The 1999 EA identified the closest surface water supply source to a pipeline stream crossing as being the small water right (30 acre-ft) for Pedernales Falls State Park. The next closest surface water supply is that of the Hill Country Springs located on Slaughter Creek approximately 8.2 miles from the zone of potential impact. This water supply was not addressed in the 1999 EA. The next closest water rights are on the Llano and San Saba rivers and consist of the municipal water use for the communities of Llano and Menard. There is also a large municipal water right on the Brazos River held by the Galveston County Water Authority about 50 miles downstream of the pipeline crossing of the Brazos River. As noted above, the Highland Lakes and Lady Bird Lake (formerly Town Lake) are the major water supply source for numerous communities along the lakes. The distance from the lakes (that is, the centerlines of Lake LBJ, Lake Travis, or Lady Bird Lake) to the closest pipeline stream crossing ranges from about 26 to 35 miles. In addition, there are a number of shallow public water supply wells located downstream of the pipeline in stream/river alluvium. These include: 24 wells between Lady Bird Lake and the pipeline crossing over the mainstem of the Colorado River, within the river alluvium. One of these is along Dry Creek about eight miles downstream of the pipeline crossing. These shallow wells are hydrologically connected to surface water and therefore would be at a higher risk in the event of a pipeline spill. 4.2.2.2 Surface Water Resources, Including Vulnerable Areas The purpose of this section is to identify vulnerable surface water resources along the pipeline route. The focus of this evaluation is water supplies, both public water supplies and irrigation supplies, along the route. Recreational, biological, and cultural resources associated with water are discussed in Sections 4.1, 4.3, and 4.4, respectively. 4.2.2.2.1 Data Sources In the 1999 EA, the primary data sources for the identification of vulnerable surface water resources were: (1) hydrologic and water quality data available from water resource agencies, (2) water rights data maintained and assembled into a spatial database by the TCEQ, (3) available topographic mapping, (4) regional water studies for various water resources along the 4-34 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL pipeline route, and (5) data provided by interested parties, including comments provided on the draft Longhorn EA. The result of this research was a spatial database that includes the following layers: • 1:100,000 scale streamlines (hydrography); • Vulnerable geology affecting surface-water transport (karst area contributing and recharge zone boundaries); • Delineations of watershed areas draining to pipeline crossings; • Identification of downstream water rights for a variety of uses (primarily municipal, irrigation, mining, and industrial); • Identification of public water supply sources downstream of the pipeline stream crossings; • Identification of water quality sampling stations on streams downstream of pipeline stream crossings; and • Identification of impaired stream segments downstream of the pipeline crossings per the Federal Clean Water Act Section 303(d). 4.2.2.2.2 Identification of Surface Water Vulnerability to Spills This section provides an assessment of the vulnerability of surface water to spills along the pipeline route. The assessment considers surface water vulnerability to be a function of: • Spill mobility; • Ability to contain and remediate a spill; and • Relative importance of potentially impacted surface waters. For each of these three considerations, the entire pipeline route was assessed for relative vulnerability at each pipeline stream crossing location. The relative vulnerabilities at these locations were assigned a level of impact using a separate rating system for each of the three types of vulnerability evaluated. Once the relative vulnerabilities were assigned for each pipeline stream crossing, a cumulative vulnerability of each pipeline stream crossing location was calculated by adding the vulnerability rating from all three considerations. The total vulnerability scores were then ranked based upon their combined score, with the lowest total scores representing the highest assigned vulnerability. Figure 4.2.2-8 illustrates the ranking methodology to determine vulnerability. 4.2.2.2.2.1 Spill Mobility The pipeline stream crossings were ranked on a scale of 1 (highest) to 6 (lowest) for their ability to transport a spill. The factors considered in this FEA with regard to spill movement are the pipeline location relative to the regional occurrence of rainfall, size of river and stream crossings, the size of the watersheds where the stream crossing occurs, and the stream flow during flood conditions. A discussion of these ranking factors is provided in more detail below: 4-35 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Regional Occurrence of Rainfall As was the case in the 1999 EA, annual rainfall across the pipeline length varies by over a factor of three, with over 48 inches of annual rainfall in Houston, over 32 inches of annual rainfall in Austin, and about 16 inches of annual rainfall in Crane. Watersheds in east Texas have significantly larger base flows than watersheds of a similar size in west Texas, which typically only flow seasonally. Streams west of the Llano River basin have small base flows and median flows, and can generally be considered to have less transport power, regardless of tributary basin area upstream of the pipeline, than watersheds to the east. Size of River and Stream Crossings Major Crossings At major river and stream crossings in central and east Texas, where there are significant base flows, spills are transported more quickly than for the bulk of the pipeline crossings. Several large rivers and tributaries (stream order greater than third-order) occur in this region (Colorado River, Brazos River, Llano River, Pedernales River, James River, and Onion Creek). These streams were given a ranking of 1 in the 1999 EA. The ranking system provided in the 1999 EA remains valid and is adopted in this FEA. Minor Crossings As noted in the 1999 EA, there are 12 third-order and above streams in the east/central region (i.e. between MP I – 250) that are likely to have relatively more transport power than lesser streams. These streams were given a ranking of 2 in the 1999 EA. The ranking provided in the 1999 EA remains valid and is adopted in this FEA. Mean Annual Flood The remaining streams (west Texas streams and second order and below streams in east/central Texas) are ranked by mean annual (two-year) flood. This flood can be estimated by Texas hydrologic region, and watershed parameters (basin area, basin shape factor, and basin slope). Those with relatively high, medium, medium-low, and low two-year floods were assigned rankings of 3, 4, or 5; respectively. The resulting ranking of streams in terms of relative ability for a spill movement is summarized in Table 4.2.2-4. Seventeen of the 56 total streams for the Longhorn Pipeline segment from East Houston to Crane were rated based upon characteristics such as basin size, “major crossing,” and high stream order rather than upon actual stream flows. On average, the major streams had a flow of greater than 20,000 cubic feet per second and high stream order water bodies had a flow of approximately 2,500 cubic feet per second. Minor changes in these stream characteristics resulted from the recalculation of the 2-year flood flows based upon updated data. Six of 56 streams in this table are listed as having the highest ability to transport. All six of these listings are based upon the characteristic described as “major crossing” on Table 4.2.2-4. 4-36 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 4.2.2.2.2.2 Ability to Contain and Remediate a Spill In the 1999 EA the pipeline stream crossings were ranked on a scale of 1 (most difficult to remediate) to 6 (least difficult) based on the degree of difficulty associated with the control and remediation of spills to surface water bodies along the pipeline route. For purposes of consistency, this same methodology is used in this FEA. The factors used in the ranking are as follows: Location on Main Stem Mainstems have substantially higher flows (greater transport power) and a greater volume of streambed and bank alluvium (providing greater pore volume for contaminant storage). These major crossings are assigned a vulnerability of 1. Location on Karst Aquifer Stream crossings within karst aquifers having a high DRASTIC Index (as described in Section 4.2.1.2.2) are assigned a vulnerability ranking of 1 because of the extreme difficulty in remediating or preventing pollutant spread in these formations. Along this pipeline route, the Edwards/Balcones contributing zone falls into this category. Location Near Karst Aquifer or On Alluvium Stream crossings near karst aquifers that have a high DRASTIC Index or are located on vulnerable alluviums are assigned a vulnerability ranking of 2 because of the relative difficulty in remediating or preventing pollutant spread in these formations. Along the pipeline route these ranking includes those stream crossings that are near the Ellenburger-San Saba aquifer and those that are on the Colorado River Alluvium. Location Proximity to Main Stem In the absence of other considerations as discussed above, the vulnerability of a water body to a pipeline crossing is assumed to decrease as the distance of the location of the spill increases. Stream crossings that are located within two miles of a main stem are assigned a vulnerability of 2, crossings located 3 to 10 miles from a main stem are assigned a vulnerability of 3, crossings within 10-20 miles of a stem are assigned a vulnerability of 4, crossings within 20-30 miles of a stem are assigned a vulnerability of 5, and crossings greater than 35 miles from a stem are assigned a vulnerability of 6. Table 4.2.2-5 provides the ranking of streams in terms of relative ability to control a spill. 4.2.2.2.2.3 Relative Importance of Potentially Impacted Surface Waters In the 1999 EA, municipal water supply sources, which require water of a higher quality than needed for other uses (e.g., mining, industrial, and irrigation), were considered more vulnerable than other sources. Because human health is a prime concern, they were also considered relatively more important than other sources, particularly where the source is the prime source for consumption. This FEA adopts the same methodology as was used in the 1999 EA. Table 4.2.2-6 provides a ranking of the pipeline stream crossings on a scale from 1 (most important) to 4-37 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 6 (least important) in terms of the importance of the water resource downstream. The ranking criteria are summarized in the table below: Ranking Basis 1 Within approximately 15 miles of Colorado Alluvium; or within 40 miles of Highland Lakes; or Alluvial Public Well within two miles 2 Municipal water right within 75 miles; or within 75 miles of Highland Lakes 3 Large irrigation water right within 20 miles downstream 4 Small irrigation right within 20 miles downstream or Colorado River Alluvium between 40 to 75 miles downstream 5 Small water right within 40 to 60 miles downstream or poor water quality 6 Small irrigation within 40 to 60 miles 7 No uses identified 4.2.2.2.3 Summary Ranking of Stream Vulnerabilities The rankings for each crossing performed in the preceding section were assembled into a summary table, Table 4.2.2-7. The rankings for each crossing were summed and then sorted, so that the lowest sum is shown at the top of the table. The “sum of ranks” value of 3 represents the crossings most vulnerable to a spill. The crossings listed thereafter in the table are progressively less vulnerable. As noted above, these rankings do not include an evaluation of the recreational, biological, and cultural resource characteristics of each stream crossing, since these issues are addressed in Sections 4.1, 4.3, and 4.4, respectively. 4.2.2.3 Wetlands An inventory of wetlands present within the zone of potential impact from East Houston to Crane shows that 2,898 wetlands, consisting of approximately 5,852 acres, are present. This inventory also shows a total of approximately 449 stream locations accounting for approximately 121.2 miles or 642,048 linear feet. The U.S. Fish and Wildlife Service (USFWS) National Wetland Inventory (NWI) maps were evaluated through GIS to determine specific numbers (density per linear mile), types, and aerial extent of wetlands that are located within the zone of potential impact. Digital NWI maps at a scale of 1:24,000 were used for wetland identification in Harris County to approximately 55 miles west. Scanned and digitized NWI maps at a scale of 1:100,000 were used for the remaining of the pipeline from MP 55 to Crane. The digital NWI maps used at a scale of 4-38 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 1:24,000 portray all wetland data in a polygon, including stream segments. The scanned NWI maps at 1:100,000 do not have polygons for stream segments. Results of these stream segments from MP 55 and westward are provided in the table below and Table 4.2.2-8 for the entire route from East Houston to Crane and were used in this evaluation. The Proposed Project from the East Houston Terminal to the Crane Terminal is within 1,250 feet or within the overland flow boundary of three different wetland types: riverine, palustrine and lacustrine. The greatest concentration of wetlands along the pipeline (approximately 13.7 per linear mile) is located between MP 20 and MP 160, which includes western Harris County, Waller County, Austin County, Fayette County, Bastrop County, and eastern Travis County. The density of wetlands (per linear mile) decreases to a range of approximately 5 per linear mile between MP 160 and MP 280, which includes western Travis, Hays, Blanco, Gillespie, Llano, Mason and Kimble Counties. West of Kimble County to Crane, the density of wetlands decreases steadily to an average of 1.3 per mile. By using GIS and NWI maps, the aerial extent of wetlands were calculated for each type of wetland where a polygon was located within the zone of potential impact. Rivers and streams where a line was used in GIS rather than a polygon was measured in total miles/linear feet crossed within the zone of potential impact. The following table summarizes these acreages and miles of each wetland. Wetland Polygons Wetland Lines Wetland Classification Count Acres Count Miles Intermittent 10 20.1 383 113.32 Lacustrine Open Water 5 34.0 Lacustrine Unconsolidated Bottom 2 41.9 Lacustrine Unconsolidated Shore 1 23.81 Lower Perennial 107 533.7 62 6.67 Palustrine Aquatic Bed 6 13.7 Palustrine Emergent 613 2877.2 Palustrine Forested 941 1179.1 Palustrine Open Water 520 295.3 2 1.08 Palustrine Scrub-shrub 107 293.3 Palustrine Unconsolidated Bottom 295 225.2 Palustrine Unconsolidated Shore 291 314.6 2 0.19 Total 2,898 5,851.9 449 121.16 The wetlands identified within the zone of potential impact are compiled by MP and county and presented on Table 4.2.2-8. 4.2.3 Geologic Hazards The geologic hazards (geohazards) discussed in this section are limited to earthquake/seismic hazards, landslide/mass movement hazards, soil stress-induced hazards (shrink-swell), 4-39 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL subsidence associated with active faulting in the Gulf Coastal Plain, and erosion (scour) at stream crossings. 4.2.3.1 Earthquake/Seismic Hazards There is no appreciable difference between the findings of this section and those presented in the 1999 EA. Therefore, Section 4.2.3.1 (Earthquake/Seismic Hazards) of the 1999 EA is included by reference in this FEA. (See http://www.epa.gov/region6/6en/xp/longhorn_nepa_documents/lppchap4.pdf) 4.2.3.2 Landslide/Mass Movement Hazards There is no appreciable difference between the findings of this section and those presented in the 1999 EA. Therefore, Section 4.2.3.2 (Landslide/Mass Movement Hazards) of the 1999 EA is included by reference in this FEA. (See http://www.epa.gov/region6/6en/xp/longhorn_nepa_documents/lppchap4.pdf) 4.2.3.3 Faulting/Subsidence Hazards Aseismic faulting occurs in the Houston metropolitan area. It is considered aseismic because the movements are too small and too frequent to cause measurable earth tremors. The faulting is primarily due to consolidation of unconsolidated marine soils as water and petroleum products are pumped from these materials. As pore water pressures decrease in these formations due to pumping, the effective overburden stress increases resulting in consolidation. The result of the consolidation is seen at the ground surface as subsidence defined by movement across small faults. Review of elevation data from 1906 to 2000 indicates total subsidence on the order of 7 ft in the area of the pipeline (Harris Galveston Subsidence District http://mapper.subsidence.org/). This area of magnitude occurs along the pipeline over a distance of approximately 55 miles within the Houston metropolitan area (Harris Galveston Subsidence District http://mapper.subsidence.org/). Movements of this magnitude over such a distance will not pose a threat to the integrity of the pipeline. The Proposed Project crosses several faults between East Houston/Galena Park and Crane. None of the faults west of Harris County are known to be active. Within Harris County, the pipeline crosses three aseismic faults, at five separate locations, that are considered to be active. Selected faults in Harris County have been monitored since March 2004 in accordance with the Operational Reliability Assessment. The data collected and analyzed indicate no measurable movement over time on two of the faults (Melde and Breen faults), with only slight movement of 0.06 inches over the last 5½ years for the Akron fault and -0.08 inches during the same period for the Hockley fault. 4-40 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 4.2.3.4 Soil Stress Hazards There is no appreciable difference between the findings of this section and those presented in the 1999 EA. Therefore, Section 4.2.3.4 (Soil Stress Hazards) of the 1999 EA is included by reference in this FEA. (See http://www.epa.gov/region6/6en/xp/longhorn_nepa_documents/lppchap4.pdf) 4.2.3.5 Scour at Stream Crossings The process of scour, or washout, may occur at stream crossings typically during a flood event and pose a geologic hazard to a pipeline. The scour could remove the depth of cover, expose the pipe, and/or remove needed support from the pipe, thereby threatening the integrity of the pipeline. Conditions which affect the scour potential include topography, stream velocity, soil conditions, grain size, depth of cover, and pipe position. If specific conditions exist common to a flood event such as high stream velocity and absence of cover, the pipeline could float up into the stream flow and be exposed to flood velocity-induced stresses causing a leak. The Proposed Project crosses a total of 63 streams. Some stream crossings are elevated over the stream, while most are subsurface and buried under the stream bed. An extensive study (Longhorn Pipeline Stream Crossing Study: A summary of Stream Scour Potential and Potential for Pipeline Failure, April 7, 2000) was conducted in 2000 to evaluate scour and erosion potential during flooding at all stream crossings along the pipeline. Stream crossings were evaluated by their hydrologic and hydraulic characteristics, history of scour-related leaks, evidence of channel instability, and other physical characteristics. Fifteen crossings were selected for detailed, site-specific analysis. These included the six major river crossings (Brazos River, Colorado River, Onion Creek, Pedernales River, Llano River, and Pecos River), four crossings identified by an aerial photographic analysis (JD Creek, Long Branch, Barton Creek, and Sandy Creek at MP 236.7), all hypersensitive (Tier 3) crossings with alluvial (as opposed to rock) streambeds (Marble Creek, Boggy Creek, Slaughter Creek), and all sensitive (Tier 2) crossings identified as potentially having excessive flood velocities (Alum Creek). The Rabbs Creek and Cedar Creek crossings, which were known from earlier observation to be unstable, were also studied as part of the remedial design process. The studies identified recommended mitigation efforts to reduce the likelihood of damage to the pipeline as a result of scour. Furthermore, the measures identified in the LMP are designed to maintain and proactively identify areas of shallow or exposed pipe at all stream crossings through regular inspections and aerial surveys. 4.2.4 Climate and Air Quality 4.2.4.1 Climate The findings of this section are identical to those presented in the 1999 EA. Therefore, Section 4.2.4.1 (Climate) of the 1999 EA is included by reference in this FEA. 4-41 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL (See http://www.epa.gov/region6/6en/xp/longhorn_nepa_documents/lppchap4.pdf) 4.2.4.2 Air Quality The EPA has established National Ambient Air Quality Standards (NAAQS) for six “criteria” air pollutants: ozone (O3), particulate matter (PM), nitrogen dioxide (NO2), sulfur dioxide (SO2), carbon monoxide (CO), and lead (Pb). NAAQS have been developed for two forms of PM: PM with a diameter of 10 micrometers (µm) or less (PM10) and PM with a diameter of 2.5 µm or less (PM2.5), which is sometimes referenced as “fine” PM. EPA has designated these pollutants as criteria air pollutants because it regulates them by developing human health-based and/or environmentally-based criteria (science-based guidelines) for setting permissible levels. The sources of the criteria air pollutants are varied. Ozone is not usually emitted directly into the air, but is formed at ground-level through a series of complex reactions between oxides of nitrogen (NOx) and volatile organic compounds (VOC) – ozone precursors – in the presence of sunlight. In the earth's lower atmosphere, this ground-level ozone, at elevated concentrations, is harmful to human health. Motor vehicle exhaust and industrial emissions, gasoline vapors, and chemical solvents as well as natural sources emit NOx and VOC that help form ozone. PM is emitted directly from a variety of sources and is also formed in the atmosphere through chemical processes. PM is a complex mixture of small solid particles and liquid droplets that may be composed of a number of constituents, including acids (e.g., sulfates and nitrates), organic compounds, metals, and soil or dust particles. NO2 is an indirect product of combustion processes that quickly forms in the atmosphere from emissions from cars, trucks and buses, power plants, and off-road equipment. In addition to contributing to the formation of ground-level ozone, as well as fine PM, NO2 is linked with a number of adverse effects on the respiratory system. SO2 is a direct product of the refining and combustion of fossil fuels (e.g., coal and oil) that contain sulfur as a natural component. CO is a colorless, odorless gas emitted as a byproduct of combustion processes (e.g., mobile sources and power plants). The most significant sources of lead emissions have historically been motor vehicles (more specifically, the lead additives in vehicle fuels) and industrial sources (e.g., lead smelters). County or multi-county regions of a state, such as Texas, where measured ambient levels of a criteria pollutant exceed a NAAQS (based on a statistical analysis of the data) are considered to be in “nonattainment” of that pollutant’s NAAQS, and are formally designated as nonattainment areas. Knowledge of the attainment/nonattainment status of an area can provide a representative description of the air quality in that area. The current attainment/nonattainment status of each geographic area of Texas through which the Proposed Project (Crane to East Houston) traverses is discussed below. In addition to the above-described, historically-regulated criteria pollutants, EPA now regulates “greenhouse gases” (GHGs). The six key GHGs are carbon dioxide (CO2), methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. Air quality permitting is required for GHG emissions from the nation’s largest GHG sources, most notably power plants, refineries, and cement production facilities. 4-42 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL For this assessment, the primary GHGs of concern are CO2, resulting from fuel-burning in construction equipment, and methane, resulting from the transport/storage of crude oil. Emissions of these GHGs are being estimated (and presented in this FEA) for anticipated construction and operational activities associated with the Proposed Project and Connected Actions. Note that, unlike for the criteria pollutants, there are no ambient monitoring programs for GHGs that could be used to establish current background levels in the atmosphere. Southeast Texas The Houston-Galveston-Brazoria area (comprised of Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery, and Waller Counties) in southeast Texas is designated a “severe” nonattainment area for the 8-hr ozone NAAQS2 (40 CFR 81.344). As a result, this area has an EPA-imposed attainment deadline of June 2019. Except for the ozone nonattainment designation for the Houston-Galveston-Brazoria area, southeast Texas is designated to be in attainment of the NAAQS for all other criteria pollutants. However, since promulgation of the 8-hr ozone NAAQS in 1997, exceedances of the standard have been measured (as recently as 2010) at one or more ambient monitors in the Beaumont-Port Arthur area (comprised of Hardin, Jefferson, and Orange Counties), which currently is not formally designated as an ozone nonattainment area (see TCEQ website http://www.tceq.state.tx.us/cgi- bin/compliance/monops/8hr_attainment.pl). Note that a 3-year average, as opposed to individual 8-hr measurements, that exceeds the NAAQS for ozone is required in order for a region to receive the nonattainment designation. South Central Texas South Central Texas is currently in attainment of the NAAQS for all criteria pollutants (40 CFR 81.344), although exceedances of the ozone NAAQS have been measured at one or more ambient monitors in the Austin and San Antonio metropolitan areas in recent years (see TCEQ website http://www.tceq.state.tx.us/cgi-bin/compliance/monops/8hr_attainment.pl). Therefore, despite the current attainment designation, ozone levels are currently a concern in both areas. West Texas West Texas is currently in attainment of the NAAQS for all criteria pollutants (40 CFR 81.344), primarily because this region has relatively little industrial development and a low population density. Based on these factors, air quality does not appear to be a concern in this region. 2 In July 1997, EPA stipulated an 8-hour NAAQS for ground-level ozone of 0.08 parts per million (ppm). The EPA phased out and replaced the previous 1-hour standard with this 8-hour standard to protect public health against longer exposure to this pollutant. In March 2008, the EPA revised the 8-hour NAAQS for ozone, lowering it to 0.075 ppm. However, EPA’s formally-designated attainment/nonattainment status for ozone is based on the originally- promulgated NAAQS. 4-43 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 4.3 ECOLOGICAL RESOURCES Ecological resources pertain to biomes (communities of living organisms of a single major ecological region), flora and fauna, and threatened and endangered (T&E) species that could be affected by pipeline operations, maintenance, or an accidental release of crude oil. The following sections describe natural regions, vegetation, aquatic biology, and terrestrial biology. The information presented was obtained primarily from the USFWS and the TPWD. This assessment considers all federal and state listed threatened or endangered species and federal listed candidate species that are known to be within counties that are crossed by the pipeline from East Houston to Crane. The list provided in Table 4.3.1-1 includes 67 threatened or endangered species and 3 candidate species. Table 4.3.1-1 is compiled from the Annotated County List of Rare Species from both TPWD and USFWS. 4.3.1 Terrestrial Resources Natural Regions Traversed by the Proposed Project from East Houston to Crane The TPWD lists 11 natural regions within the state (TPWD, 1978), of which four are crossed by the Proposed Project from East Houston/Galena Park to Crane. The regions crossed, listed from east to west, are: Gulf Coast Prairies and Marshes, Blackland Prairies, Oak Woodlands and Prairies, and Edwards Plateau (see Figure 4.3.1-1). The pipeline also crosses the “Lost Pines” subregion of the Oak Woodlands and Prairie natural region. These regions are summarized in the following text. Gulf Coast Prairies and Marshes Harris and Waller counties are located at the northern edge of the Gulf Coast Prairies and Marshes natural region that extends inland approximately 50 miles. The area exhibits little topographic relief and is comprised of sluggish rivers, creeks, bayous, swamps, and freshwater marshes. Climax vegetation in the area is principally grassland (tall-grass prairie) and post oak savannah; however, much of the area has been invaded by trees and brush such as mesquite (Prosopis glandulosa), live oak (Quercus virginiana), prickly pear (Opuntia spp.), and several species of acacias. Dominant grasses include big bluestem (Andropogon gerardi), eastern grama (Tripsacum dactyloides), gulf muhly (Muhlenbergia capillaris), and several species of panicum. Portions of the natural region crossed by the pipeline extend from MP 0.0 to MP 71.2, as shown on Figure 4.3.1-1. Blackland Prairies The Blackland Prairies natural region consists of two relatively narrow zones separated with zones of oak woodlands and prairies. The eastern portion of the region extends from the Gulf Coast Prairies and Marshes at MP 71.2; the western extent of the Blackland Prairies region lies along the eastern margin of the Balcones Escarpment and the Edwards Plateau natural region (MP 167.2). A relatively narrow band of Oak Woodlands and Prairies natural region crosses the Blackland Prairies region from MP 105.8 to MP 148.9. Regional topography of the Blackland Prairies region is characterized as gently rolling prairies dissected by well-defined streams and drainages. Tall-grass communities dominate the native vegetation within the region, and post 4-44 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL oak (Quercus stellata) and blackjack oaks (Quercus marilandica) are common. Important grass species include hairy grama (Bouteloua hirsuta) and dropseed (Sporobolus spp.). Oak Woodlands and Prairies The Oak Woodlands and Prairies natural region (also known as the Cross Timbers and Prairies Vegetational Area) supports a wide variety of flora and fauna species. The region consists of woodlands dominated by oaks and hickories, interspersed with a mosaic of prairie. Dominant woody species include post oak and blackjack oak; however, cedar elm (Ulmus craassifolia) and pecan (Carya illinoinensis) are common along streams and rivers. Common grasses include little bluestem (Schizachrium scoparium), big bluestem (Andropogon gerardi), Indian grass (Sorghastrum avenaceum), switchgrass (Panicum virgatum), and Canada wild-rye (Elymus canadensis). Parts of the region were historically used for grazing, which has contributed to the development of thickets of yaupon (Ilex vomitoria) and brumelia, and extensive areas that have become dominated by mesquite. Approximately 43 linear miles of the Proposed Project crosses the region, from MP 105.8 to MP 148.9. The Lost Pines subregion, which lies within the Oak Woodlands and Prairies natural region, is comprised of mature loblolly pines (Pinus taeda) within a unique sandy soil environment. The pipeline crosses the subregion in central Bastrop County from MP 127.5 to MP 128.8. Edwards Plateau The Edwards Plateau natural region extends from the Balcones Escarpment in Austin through west central Texas to the Stockton Plateau. Streams and rivers within the region typically are fast flowing and clear or nearly clear. The region is comprised of cedar breaks with dense growths of juniper, scrub oaks, and mesquite. Dominant grasses of the Plateau include switchgrass and several species of bluestems and gramas. Rocky soils of the area typically support a tall-grass understory and a brush overstory that is generally comprised of oaks, junipers, and mesquite. Streams throughout the area are often well-drained ephemeral drainages that provide habitat for a variety of plant and animal species not common in more upland areas of the Plateau. Approximately 278.9 linear miles of the pipeline cross the Plateau, including approximately 66.3 miles that cross the Llano Uplift, which is a subregion of the Plateau. 4.3.1.1 Terrestrial Fauna and Flora The Proposed Project traverses a variety of wildlife habitats and passes through the distributional ranges of many species from East Houston to Crane. As the route crosses the state from east to west, species composition is influenced by the vegetation present, water availability, and to a large degree, by land ownership and land management practices. From East Houston to Crane, the pipeline crosses three of the seven biotic provinces of Texas described by Blair (1950). From east to west, the Proposed Project traverses the Austroriparian, Texan and Balconian Biotic Provinces. The following provides a brief description of each province and associated wildlife. 4-45 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Austroriparian Province This province includes the Gulf Coast plain from the Atlantic to eastern Texas. The Proposed Project begins just inside the western boundary of this province in Harris County. The Austroriparian Province is home to a wide variety of different species throughout Texas. Common species found throughout the Austroriparian Province are described in the following paragraphs. Mammals typical of this province include Virginia opossum (Didelphis virginaiana), eastern mole (Scalopus aquaticus), eastern pipistrelle (Pipistrellus subflavus), eastern red bat (Lasiurus borealis), eastern gray squirrel (Sciurus carolinesis), eastern flying squirrel (Glaucomys volans), Baird's pocket gopher (Geomys breviceps), white-footed mouse (Peromyscus leucopus), hispid cotton rat (Sigmodon hispidus), eastern woodrat (Neotoma floridana), eastern cottontail (Sylvilagus floridanus), and swamp rabbit (Sylvilagus aquaticus). Land turtles common to this province are ornate box turtle (Terrapene ornata) and eastern box turtle (Terrapene carolina). Common snake species found in this Texas region include: cottonmouth moccasin (Agkistrodon piscivorus leucostoma), copperhead (Agkistrodon contortirx), rough green snake (Opheodrys aestivus), rat snake (Elaphe obsoleta), coachwhip (Masticophis flagellum) and speckled kingsnake (Lampropeltis geluta holbrooki). Other species include the spotted salamander (Ambystoma maculatum), marbled salamander (Ambystoma opacum), mole salamander (Ambystoma talpoideum), pig frog (Rana grylio), and pickerel frog (Rana palustris). Texan Province This province is located within a transitional area between forests of the Austroriparian province and the grasslands to the west in Texas. The integration of woodlands and grasslands within the region results in a mixture of wildlife species typical of the two general habitats. The vertebrate fauna of the Texan Biotic Province consists of at least 49 species of mammals, 16 lizards, two land turtles, 39 snakes, 18 anurans (frogs and toads), and five urodeles (salamanders, newts, etc.) (Blair, 1950). Mammals typical of this province include the Virginia opossum (Didelphis virginiana), eastern mole (Scalopus aquaticus), fox squirrel (Sciurus niger), Louisiana pocket gopher (Geomys breviceps), fulvous harvest mouse (Reithrodontomys fulvescens), white-footed mouse (Peromyscus leucopus), hispid cotton rat (Sigmodon hispidus), eastern cottontail (Sylvilagus floridanus), and swamp rabbit (S. aquaticus). Animals typical of grasslands of this province include the thirteen-lined ground squirrel (Spermophilus tridecemlineatus), hispid pocket mouse (Chaetodipus hispidus), deer mouse (Peromyscus maniculatus), and black-tailed jackrabbit (Lepus californicus). Typical anuran species to this province are the Hurter's spadefoot (Scaphiopus holbrookii hurteri), Gulf Coast toad (Bufo valliceps), Woodhouse's toad (Bufo woodhousii), gray treefrog (Hyla versicolor/chrysoscelis), green treefrog (Hyla cinerea), bullfrog (Rana catesbeiana), southern leopard frog (Rana sphenocephala), and eastern narrowmouth toad (Microhylla carolinensis). 4-46 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Balconian Province This province is located primarily within the Edwards Plateau region of Texas. The Balconian Biotic Province is a mixture of species characteristic of surrounding major provinces, even though its primary vegetation is distinctly different. The vertebrate fauna consists of 57 species of mammals, 16 lizards, 1 land turtle, 36 snakes, 15 anurans, and 7 urodeles (Blair 1950). Mammals common to this province are the nine-banded armadillo (Dasypus novimcinctus), fox squirrel (Sciurus niger), white-footed mouse (Peromyscus leucopus), black rat (Rattus rattus), house mouse (Mus musculus), raccoon (Procyon lotor), and white-tailed deer (Odocoileus virginiana). Approximately 400 avian species have been recorded as occurring in the Balconian Biotic Province. Common species include mourning dove (Zenaida macroura), yellow-billed cuckoo (Coccyzus americanus), chimney swift (Chaetura pelagica), black-chinned hummingbird (Archilochus alexandri), red-bellied woodpecker (Melanerpes carolinus), purple martin (Progne subis), cliff swallow (Hirundo pyrrhonota), blue jay (Cyanocitta cristata), Carolina chickadee (Parus carolinensis), tufted titmouse (Parus bicolor), Carolina wren (Thryothorus ludovicianus), Bewick's wren (Thryomanes bewickii), northern mockingbird (Mimus polyglottos), white-eyed vireo (Vireo griseus), black-and-white warbler (Mniotilta varia), northern cardinal (Cardinalis cardinalis), rufous-crowned sparrow (Aimophila ruficeps), lark sparrow (Chodestes grammacus), great-tailed grackle (Quiscalus mexicanus), and house sparrow (Passer domesticus). Dominant vegetation and habitat types for much of the wildlife are described in Section 4.3.1 above. All four ecoregions crossed have different plant species and other particular habitat types that determine the distribution of wildlife from East Houston to Crane along the pipeline route. White-tailed deer (Odocoileus virginianus) is an important big game animal in areas along the pipeline and throughout other parts of the state. Other big game animals along the pipeline include javelina (Pecari tajacu), mule deer (Odocoileus hemionus), and pronghorn antelope (Antilocapra americana). Javelina populations are scattered, but are highest in the Trans-Pecos natural region. Mule deer and pronghorn antelope are found primarily in the Trans-Pecos but also inhabit areas of isolated habitat in the Edwards Plateau natural region. In addition to the native big game species, many landowners along the western portions of the route augment their income through commercial hunting of imported or exotic game species. More than 80% of the exotic species that are raised for hunting comprise six species: axis deer, blackbuck antelope, nilgai, Barbary sheep, Sika deer, and fallow deer. The axis deer (Axis axis) is an abundant exotic ungulate in Texas and are free-ranging in southern Texas; however, the majority are in captivity in ranches spread over 67 counties. The second most abundant exotic species is the blackbuck antelope (Antilopa cervicapra), with the highest concentration in the Edwards Plateau region. The nilgai (Boselaphus tragocamelus) is an abundant free-ranging exotic ungulate in Texas. The fifth-ranked Barbary sheep (Ammotragus lervia) was introduced in Palo Duro Canyon and has since spread to the Edwards Plateau, Trans-Pecos, Oak Woodlands, and other parts of Texas. Sika deer (Cervus hippon) is widely distributed in central 4-47 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL and south Texas, including counties along the Proposed Project (Traweek 1985). Fallow deer (Cervus dama) occur in 93 Texas counties, predominantly within the Edward’s Plateau Region. A variety of nongame mammals, birds, reptiles, and amphibians are supported by the varied habitats that exist along the pipeline route. Depending on the type of ecosystem, dominant mammals may include raccoon (Procyon lotor), coyote (Canis latrans), bobcat (Lynx rufus), badger (Taxidea taxus), and gray fox (Urocyon cinereoargenteus). These species, along with the armadillo (Dasypus novemcinctus), opossum (Didelphis virginiana), blacktailed jackrabbit (Lepus californicus), and striped skunk (Mephitis mephitis) comprise the most common mammals found in proximity to the pipeline (TPWD, 1994). Over 620 species of birds are known to occur in Texas (TPWD, 1994), many of which are migratory. Most permanent resident species have some economic or recreational value. Raptors provide a level of rodent control, and vultures are important as common scavengers. Species of gamebirds include dove (Columba spp.), quail (Callipepla spp.), turkey (Meleagris gallopavo), ducks, and geese. Songbirds, such as sparrows, finches, and warblers, serve as insectivores, as well as being important species for recreational bird watchers. Amphibian and reptilian species present along the Proposed Project route are diverse. Amphibians such as the Texas Toad (Bufo speciosus), Red-spotted Toad (Bufo punctatus), and Barred Tiger Salamander (Ambystoma tigrinum mavortium) are restricted to rivers, lakes, and springs along the route and increase in frequency of occurrence from west to east. 4.3.2 Aquatic Resources The Proposed Project crosses approximately 450 streamlines (based on USGS 1:24,000-scale hydrography) from East Houston/Galena Park to Crane. Of the streams in which the Proposed Project crosses, ten were considered ecologically important because they reflect the natural regions discussed in the previous section. These streams and the MP crossings are listed in the following table and their location is illustrated in Figure 4.3.1-1. Each of the nine streams and their tributaries support fish species indigenous to Texas. In addition, each of the nine streams support multiple game fish species. Ecologically Important River Crossings and Associated Natural Region from East Houston to Crane Surface Water Feature County MP Associated Natural Region Greens Bayou Harris 3.2, 6.0 Gulf Prairies and Marsh White Oak Bayou Harris 32.0 Gulf Prairies and Marsh Cypress Creek Harris 47.1 Gulf Prairies and Marsh Brazos River Austin/Waller 64.0 Blackland Prairies Colorado River Bastrop 134.5 Oak Woodlands and Prairies Onion Creek Travis 164.0 Oak Woodlands and Prairies Barton Creek Travis 180.9 Edwards Plateau Pedernales River Blanco 198.8 Edwards Plateau Llano River Kimble 276.5 Edwards Plateau/Llano Uplift James River Mason 293.9 Edwards Plateau 4-48 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Gulf Prairies and Marsh Greens Bayou, White Oak Bayou, and Cypress Creek The Proposed Project crosses Greens Bayou at two locations (MP 3.2 and MP 6.0). White Oak Bayou and Cypress Creek are crossed at MP 32.0 and MP 47.1, respectively. Greens Bayou and White Oak Bayou are within an urban setting, and both have been channelized for flood control. Both bayous have sloping banks that are maintained with invasive and native grasses to aid in bank stabilization. Available fish habitat in White Oak and Greens bayous is exceptionally limited. The drainages are maintained free of woody debris and aquatic vegetation to improve flood drainage. Base flow in the bayous is dominated by the discharge of reclaimed wastewater. Velocity is relatively low with most substrates consisting of clay, sand, fine gravel, and silt. Since the channels are maintained for flood control, there is little riparian vegetation. The water is slow-moving over a bottom substrate partially comprised of gravel and silt. The Proposed Project crosses Cypress Creek in rural Harris County. The creekstream channel is partially channelized due to the installation of flood control measures; however, a large portion of the waterway has not been modified. Vegetation along the creek margin is comprised of bald cypress (Taxodium distichum), hackberry (Celtis occidentalis), and willow (Salix spp). Greens Bayou and White Oak Bayou are classified by the USFWS as palustrine with scrub- shrub vegetation (Moring, 1999). Cypress Creek, at the pipeline crossing, is classified by the USFWS as palustrine. Blackland Prairie Brazos River The Brazos River is crossed at MP 64, which is in the Gulf Coast Parries and Marshes ecoregion. The Brazos River is characterized as among the widest of the Texas rivers, with gentle relief and low velocities. The river maintains a very heavy silt load, resulting in perennially high turbidity. Substrates consist of clay, sand, and silt. Coarse woody debris is abundant in the river channel and is among important aquatic habitats in the river. Riverbanks are lined with willow, cottonwood and elm, which provide cover for many aquatic species. This portion of the river is located within the Blackland Prairies region. Oak Woodlands and Prairies Colorado River The Colorado River is crossed at MP 134.5, and is in a transitional area between the Blackland Prairie and Post Oak Savannah ecoregions. The Colorado River in the vicinity of the Proposed Pipeline crossing is highly modified by the highland lakes, return wastewater flows from Austin, and hydroelectric station pulsed-flow releases. The river is generally wide with alternating riffles, runs, and pools. Due to broad variations in channel morphology and substrates, habitats vary widely. Coarse woody debris is an important habitat within the river. Substrates consist of clay, sand, gravel, and cobble. Turbidity is generally low under low-flow conditions, but can increase with higher flows. Aquatic plants are present in the river, which provide important nursery cover for fish and food for over-wintering waterfowl. River banks are lined with willow, cottonwood, elm, and sycamore, which aid in bank stability and provide cover for fish. Large areas within the river floodplain are under cultivation and used for pecan production. The Proposed Project 4-49 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL crossing is classified by the USFWS as open water and forested palustrine (Bonn, 1980; Hubbs, 1982). Onion Creek Onion Creek is crossed at MP 164.0, within the Austin city limits. The creek flows from the Edwards Plateau to the Blackland Prairies natural ecoregions, and the location crossed by the proposed Pipeline Project pipeline is approximately 3 linear miles from the transition of the two natural areas. Onion Creek discharges into the Colorado River downstream of Austin in Travis County. Reaches along within the Edward’s Plateau are characteristically deeply incised with steep river banks that are cut to Cretaceous limestone. Along this reach, the substrates consist of bedrock, boulders, cobble, gravel, and deposits of sand and silt. The channel within the Blackland Prairies ecoregion (including the pipeline crossing location) is broader with less defined slopes. Substrates generally consist of clay and gravel. The flow in Onion Creek is intermittent, although perennial pools exist during most dry periods. Due to the intermittent nature of Onion Creek, aquatic life use is highly variable. Important aquatic habitats include boulders, cobble, gravel, and coarse woody debris. Dominant species associated with the river include sycamore (Platanus occidentalis), cottonwood (Populus deltoides), American elm (Ulmus americana), cedar elm, and pecan trees. NWI data for the Onion Creek crossing indicate that area wetlands are classified as emergent palustrine, forested palustrine, and intermittent riverine. Edwards Plateau Barton Creek The pipeline crosses Barton Creek in Travis County at MP 180.9. Barton Creek is on the Edward’s Plateau and the reach of stream near the proposed Pipeline Project crossing is intermittent and prone to scouring flows during storm events. During wet periods, spring flows maintain flow in the stream, which is typically low in turbidity and very clear. During dry periods, springs flows cease and the stream flows cease. The lower reach of Barton Creek maintains perennial flow via Barton Springs. This reach of stream is very clear and the substrates consist of bedrock, boulders, cobble, gravel, and silt. This reach of stream is extensively used for contact recreation, paddling sports, and fishing. Barton springs/Barton Creek discharges into the south shore of Lady Bird Lake. Barton Creek is on the Edwards Plateau, is spring-fed, and has limestone banks and substrate. The creek flows between multiple pools and riffles throughout its length, and vegetation composition along Barton Creek is characteristic of the Edwards Plateau natural ecoregion. Dominant species along the creek margin include bald cypress, sycamore, cottonwood, American elm, cedar elm, and pecan trees. The USFWS classifies this pipeline crossing location as palustrine, scrub- shrub palustrine with an unconsolidated bottom. Pedernales River The Proposed Project crosses the Pedernales River in Blanco County at MP 198.8. The river is on the Edward’s Plateau and is typical of a hill country stream with alternating riffles, runs, and pools. Due to steep watershed gradients, stream flow can be highly variable after storm events. Numerous seeps and springs throughout the watershed maintain base flow that is typically 4-50 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL clear. The streambed is mostly scoured bedrock with deposits of cobble, gravel, sand, and silt. The Pedernales River discharges into Lake Travis, which is an impoundment of the Colorado shallow throughout much of its length and generally flows clear along rocky banks that are lined with bald cypress and cottonwood trees. River flows can increase dramatically after a heavy rain, and flooding of riverine areas is common. The Pedernales River crossing location is classified by the USFWS as forested palustrine (Simmons, In Press). Edwards Plateau/Llano Uplift Llano River The Llano River is crossed in Kimble County at MP 276.5. The Llano River is also on the Edward’s Plateau and is typical of a hill country stream with alternating riffles, runs, and pools. Due to steep watershed gradients, stream flow can be highly variable after storm events. Numerous seeps and springs throughout the watershed maintain base flow that is typically clear. The streambed is mostly scoured bedrock with deposits of cobble, gravel, and sand, although clay banks and substrate are also common. The Llano River discharges into Lake LBJ, which is an impoundment of the Colorado River. The spring-fed river flows over limestone and gravel substrate, producing many small riffles. Limestone banks vary in slope. Wetlands at the crossing are classified by the USFWS as scrub-shrub palustrine and lower perennial riverine (Simmons, In Press). James River The James River is a 37-mile tributary of the Llano River, which begins near the Kimble and Kerr County line and intersects the Llano River approximately seven miles south of Mason, Texas. The James River is crossed by the Proposed Project in Mason County at MP 264. The James River is similar to the Llano River, but is considered less spoiled by adverse land use and habitat alteration. The stream channel is mostly gravel as it crosses the Edwards Plateau and changes to primarily bedrock at the edge of the Llano Uplift. The channel widens to over 200 feet in places and forms canyons up to 100 feet tall. Springs, which form fractures and faults along the margins of the uplift, contribute additional flow to the river (Broad, 2010). The NWI data for the James River crossing indicate that the river is classified as lower perennial riverine and the area wetlands are classified as palustrine emergent and scrub-shrub. 4.3.2.1 Aquatic Fauna and Flora Aquatic resources habitats within Proposed Project study area consist of open-water perennial and intermittent streams, man-made impoundments, playa lakes, and stock tanks, as well as other various wetland features. Hydric habitats are generally associated with streams, creeks, impoundments, and topographic lows. Bottomland/riparian hardwood forests are often associated with the streams and creeks. Impoundments generally result in either permanent or ephemeral freshwater wetlands, marshes, or fringe marshes. The Proposed Project crosses four river basins from East Houston to Crane. These river basins include the San Jacinto, Brazos and Colorado rivers and the eastern most portion of the Rio Grande. The Proposed Project also crosses numerous tributaries of these rivers. The food webs in these dynamic ecosystems are very complex. In general, benthic macro invertebrates are 4-51 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL important food resources among lotic systems, whereas zooplankton is important in lentic systems and, to some extent, in larger streams. Emergent and submerged aquatic vascular plants and algae provide important food and cover where water clarity is supporting, but is less important in the more turbid environments. In the eastern streams, coarse woody debris and organic material is among the most important habitats in lotic systems, whereas in the western streams, boulder, cobble, and rock substrates are more important. Similarly, water quality can be highly variable. Eastern streams often consist of soft water with higher turbidity and oxygen concentrations can be limiting due to heavy shading and higher biochemical oxygen demand associated with organic loading. To the west, the stream gradients become steeper, with higher velocity, less riparian shading and allochthonous inputs, and typically less turbid waters. As such, the fish communities can vary widely across the state. Faunal communities important in aquatic habitats include phytoplankton, zooplankton, benthic macro invertebrates, infauna and epifauna, as well as nekton species. These communities vary according to aquatic habitat characteristics and the habitat requirements and distribution of species. Collectively, these species often construct complex food webs within aquatic systems. 4.3.2.1.1 San Jacinto River Basin The streams within the San Jacinto River basin, including the San Jacinto River, are typically more turbid, with heavy riparian shading, organic inputs, and abundant coarse woody debris. With the exception of the streams in the Houston metropolitan area, most of the drainages have natural riparian corridors and the fish communities are generally unaltered. The exception to this is the San Jacinto River, which has been impacted by the construction of reservoirs, and the Houston-area bayous that have been channelized for flood control and the flows are dominated by reclaimed wastewater. The habitats in those streams have been severely impacted and the fish communities have been greatly altered. Greens and White Oak bayous have little or no riparian corridor since they are maintained for flood control. Aquatic vegetation is limited to filamentous algae or invasive species, such as alligator weed (Alternanthera philoxeroides). Although some of the channel has been modified, riparian vegetation can be found along Cypress Creek. The riparian community is dominated by willow (Salix ssp.), Chinese tallow, hackberry (Celtis occidentalis), and, along the lower reaches, some bald cypress (Taxodium distichum). Some of the most common fish species in the Houston bayous are invasive exotics, including grass carp (Ctenopharyngodon idella), common carp (Cyprinus carpio), suckermouth catfish (Hypostomus plecostomus), Amazon molly (Poecilia latipinna), and a variety of other species that have been introduced through the aquarium trade. Native species are typically those that are ubiquitous and adapted to altered environments, such as bluegill (Lepomis macrochirus), western mosquitofish (Gambusia affinis), red shiner (Cyprinella lutrensis), bullhead catfish (Ameiurus spp.), and in the larger bayous, smallmouth buffalo (Ictiobus bubalus). Streams outside of the Houston area that are less altered have communities typical of southeast Texas. Common fish species that occur in the San Jacinto River basin include spotted gar (Lepisosteus oculatus), bowfin (Amia calva), gizzard shad (Dorosoma cepedianum), blacktail shiner (Cyprinella venusta), blacktail redhorse (Moxostoma poecilurum), yellow bullhead (A. natalis), grass pickerel (Esox americanus), blackstripe topminnow (Fundulus notatus), western 4-52 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL mosquitofish (Gambusia affinis), bluegill, green sunfish (L. cyanellus), white crappie (Pomoxis annularis), largemouth bass (Micropterus salmoides), and bluntnose darter (Etheostoma chlorosoma) (Bonner, 2011; Hubbs et al, 2008; Thomas et al., 2007). 4.3.2.1.2 Brazos River Basin The riparian corridor along the Brazos River consists of coastal prairie and riparian forest that include willow, cottonwood (Populus deltoids), pecan (Carya illinoinensis), and elm (Ulmus spp.). Due to periodic flooding and high turbidity, aquatic plants are scarce along the river. Common fish species that occur in the Brazos River in the vicinity of the proposed Pipeline Project crossing are characteristic of large, Texas coastal rivers. The species in the river are generally those adapted to high turbidity and soft substrates. These include longnose gar (L. osseus), gizzard shad, common carp, sharpnose shiner (Notropis oxyrhynchus), which is a species of concern, red shiner, mimic shiner (N. volucellus), smallmouth buffalo, channel catfish (Ictalurus punctatus), flathead catfish (Pylodictis olivaris), and freshwater drum (Aplodinotus grunniens), Guadalupe bass (Micropterus treculii), and black crappie (Pomoxis nigromaculatus) (Thomas et al., 2007). The fish communities in the tributaries of the Brazos River in the vicinity of the proposed Pipeline Project are generally reflective of small streams of east Texas. Common species include spotted gar, bowfin, blacktail shiner, blackspot shiner, ribbon shiner (Lythrurus fumeus), spotted sucker (Minytrema melanops), bullhead catfish, blackstripe topminnow, western mosquitofish, and bluntnose darter (Bonner, 2011; Hubbs et al, 2008; Thomas et al., 2007). 4.3.2.1.3 Colorado River Basin Colorado River - The Colorado River downstream of Austin is an area of transition between the habitats and species common to east Texas and those in the Edwards Plateau and west Texas. The riparian corridor along the river consists of willow, sycamore (Platanus occidentalis), cottonwood, elm, and pecan. During prolonged low-flow or drought conditions, the Colorado River downstream of Austin is typically clear, supporting a variety of submerged aquatic plants including waterstargrass (Heteranthera dubia), water milfoil (Myriophyllum spicatum), coontail (Ceratophyllum demersum) , and occasionally hydrilla (Hydrilla verticillata). Since the flows are highly regulated by the upstream dams, sunfish are among the most common species immediately downstream of Austin. These include longear sunfish, bluegill, green sunfish, largemouth bass, and hybridized Guadalupe/spotted/smallmouth bass, the genetics of which are not clearly understood. Although within their historic range, most experts agree that the Guadalupe bass in the lower Colorado River are hybrids or intergrades of other black bass. Other common species include longnose and spotted gar, gizzard shad, blacktail shiner, bullhead minnow, shoal chub (Macrhybopsis hyostoma), smallmouth buffalo, blue sucker (Cycleptus elongatus), which is a state-listed threatened species, channel catfish, flathead catfish, inland silverside (Menidia beryllina), white bass (Morone chrysops), dusky darter 4-53 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL (Percina sciera), Texas logperch (P.carbonaria), and freshwater drum (Bonner, 2011; Hubbs et al, 2008; Thomas et al., 2007). Onion Creek – Due to scouring flows and periodic dry conditions, aquatic plants are generally scarce along Onion Creek. Filamentous algae is the most common plant, often forming dense mats along the margin of the stream. Dominant tree species associated with Onion Creek include sycamore, cottonwood, American elm, cedar elm, box elder, and pecan. Fish species common to Onion Creek and other area tributaries of the lower Colorado River include spotted gar, red shiner, blacktail shiner, mimic shiner, central stoneroller (Campostoma anomalum), bullhead catfish, various sunfish, and greenthroat darter (E. lepidum) [Bonner, 2011; Hubbs et al, 2008; Thomas et al., 2007]. Barton Creek – Since Barton Creek is subject to scouring flows and the upper reach is intermittent, submerged aquatic plants are uncommon throughout most of the stream. However, submerged plants, including Eurasian milfoil (M. spicatum) and pondweeds (Potomogeaton spp.) are common at the confluence of Lady Bird Lake. Dominant tree species associated with Barton Creek include sycamore, cottonwood, American elm, cedar elm, box elder, pecan, and along the lower reach, bald cypress. The fish community in the vicinity of the Proposed Project crossing (upstream of Barton Spring) is limited since flows are intermittent. Downstream of Barton Springs, common fish include gray redhorse (M. congestum), bluegill, redear sunfish (L. microlophus), green sunfish, largemouth bass, channel catfish, orangethroat darter (E. spectabile) and Mexican tetra (Astyanax mexicanus), an introduced species (TCEQ, 2012). Pedernales and Llano Rivers - The Pedernales and Llano rivers share similar fish communities. Due to their typically clear water, the most common fish species include sunfish, such as bluegill, longear sunfish, green sunfish, largemouth bass, and Guadalupe bass, which have hybridized with smallmouth bass that were historically stocked by the TPWD. Other common species include spotted gar, gizzard shad, common carp, blacktail shiner, red shiner, bullhead minnow, mimic shiner, gray redhorse, bullhead catfish, channel catfish, western mosquitofish, Texas logperch, and dusky darter (Bonner, 2011; Hubbs et al, 2008; Thomas et al., 2007). Due to periodic scouring flood flows along these rivers, the growth of submerged aquatic plants is limited. However, filamentous algae can be common. In addition, water willow (Justicia americana) is a common and important emergent plant that provides important nursery cover for fish along pools and runs. Riparian tress, along these rivers, include bald cypress, sycamore, cedar elm, cottonwood, and pecan. 4.3.3 Threatened and Endangered Species The Endangered Species Act (ESA) (16 USC 1531 et seq.) of 1973, as amended, was enacted to provide a program for the preservation of threatened and endangered (T&E) species and to provide protection for the ecosystems upon which these species depend for their survival. All federal agencies are required to implement protection programs for these designated species and to use their authorities to further the purposes of the Act. Responsibility for identification of 4-54 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL T&E species and any potential recovery plans lies within the Secretary of the Interior and the Secretary of Commerce. In February 2000, a Biological Assessment (BA) was conducted for the 1999 EA from East Houston to Crane. This BA was prepared in two phases in accordance with the ESA to determine the potential impacts to federally-listed T&E species through consultation with the USFWS. The Phase I portion of the BA and Biological Opinion (BO) addressed ROW maintenance operations. The Phase II BA and USFWS concurrence letter addressed long-term operation, maintenance, and emergency response issues. Phase I and II BAs are included in Appendix 4B. The results of the Phase I BA (Crane to East Houston) concluded that eight federally-listed T&E species could potentially be affected by maintenance, construction activities, or a potential release of product from the pipeline. The eight species of the Phase I BA include four avian birds, one amphibian species, and three plant species. Potential impacts to federally-listed T&E species are addressed in Sections 7.4 and 7.5. Habitat assessments were conducted at all proposed pump station locations to evaluate the potential for habitat for federally and/or state-listed T&E and candidate species. The habitat assessments were conducted by experienced biologists authorized by the FWS to conduct presence/absence surveys for many of the same species identified in the BA. 4.3.3.1 Protected Terrestrial Species In 2000, an extensive biological survey for T&E species, as well as their habitats, was conducted along the Longhorn Pipeline ROW from East Houston to Crane, Texas. Along with the survey, other sources of information were obtained for all listed T&E species. Other sources aside from the ground survey included various published, agency files, personal communication sources through TPWD and USFWS and recognized experts for certain species, published species documentation, and published reference books. Through previous consultation and studies which are outlined in the Phase I BA described in Section 4.3.3, it was determined that eight terrestrial species would require further attention and were deemed susceptible to potential impacts. All other listed species were ruled out due to lack of habitat, population, or other variables. The following eight species were either documented to occur or have been identified within the area of potential impact for pipeline safety operations and maintenance due to the presence of potential suitable habitat. None of the eight species had been documented to occur within the pipeline ROW. These potential species include the Texas prairie dawn flower (Hymenoxys texana), Navasota ladies-tresses (Spiranthes paksii), Tobusch fishhook cactus (Ancistrcactus tobuschii), Houston toad (Bufo houstonensis), golden cheeked warbler (Dendroica chrysoparia), black-capped vireo (Vireo atricapillus), bald eagle (Haliaeetus leucocephalus), and the interior least tern (Sterna antillarum athalassos). Since the Phase I BA and concurrence from USFWS in 2000, several new species have been listed in several counties along the Longhorn Pipeline route. These species identified in the 4-55 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL latest Annotated County List of Rare Species from both TPWD and FWS, are listed in Table 4.3.1-1 along with their status and counties of occurrence, and are described below. One reptile, the Trans-Pecos black headed snake (Tantilla cucullata), is listed as threatened by the TPWD in Crockett County. There have been no recent sightings of this snake in Crockett County. Most recently, most sightings have occurred south of the pipeline location in Val Verde, Jeff Davis, Brewster and Presidio Counties. This snake is typically found in mesquite-creosote and pinyon-juniper-oak type habitats. Two new mammal species are listed in counties crossed by the Proposed Project. The ocelot (Leopardus pardalis) is listed as endangered by TPWD in Crockett County. The ocelot is primarily found in dense chaparral thickets, mesquite-thorn scrub and live oak mottes. Ocelots will typically avoid open areas. The Louisiana black bear (Ursus americanus luteolus) is listed as threatened by TPWD in Harris County. This species would be considered a possible transient in Harris County and preferable habitat includes bottomland hardwoods and large tracts of inaccessible forested areas. One new avian species was listed in counties crossed by the Proposed Project. The red- cockaded woodpecker (Picoides borealis) is listed as endangered in Harris County by the TPWD. The red cockaded woodpecker will have cavity nests in older mature pines (60+years), but may forage in younger pines (30+years). This species prefers to nest or forage in longleaf, shortleaf and loblolly pines. One invertebrate is listed as a candidate species. The Warton’s cave meshweaver (Cicurina wartoni) is listed in Travis County. This is a very small cave dwelling spider found only in Travis County. 4.3.3.2 Federally Protected Species One amphibian is listed as endangered by both USFWS and TPWD in Travis and Hays Counties. The Barton Springs salamander (Eurycea sosorum) is epigean and is mostly restricted to subterranean cavities of the Edwards Aquifer. This salamander is dependent upon water flow/quality from the Barton Springs segment of the Edwards Aquifer. This salamander is only known to be in the outlets of Barton Springs. These outlets that form Barton Springs include Upper Barton Springs, Sunken Garden Spring, Eliza Spring and Parthenia Spring. One mammal is listed as endangered by the USFWS in Harris County. The West Indian manatee (Trichechus manatus) is a marine mammal found in marine, estuarine, and freshwater environments. Suitable habitat for these species is not located along the pipeline corridor or zone of potential impact. Two amphibians are listed federally as candidate species. The Austin blind salamander (Eurycea waterlooensis) and Jollyville Plateau salamander (Eurycea tonkawae) are both candidate species in Travis County. The Austin blind salamander is known only from the outflows of Barton Springs in the City of Austin, Travis County, Texas. The Austin blind 4-56 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL salamander is thought to spend its entire life in the aquifer. Those individuals observed are presumably washed through the spring outlets of Barton Springs (www.austintexas.gov, 2012). The Jollyville Plateau salamander occurs in the Jollyville Plateau and Brushy Creek areas of the Edwards Plateau in Travis and Williamson Counties, Texas. This amphibian lives primarily in the springs and streams of northwest Austin and southern Williamson County (www.austintexas.gov, 2012). 4.3.3.2.1 State Protected Species Fish An annotated list of aquatic species, listed as threatened or endangered by the TPWD that may potentially occur in the counties related to the Longhorn pipeline portion of the Proposed Project (East Houston to Crane), is provided in Table 4.3.1-1. There are two state-listed threatened species listed for the counties in which the Proposed Project is located. These are the creek chubsucker (Erimyzon oblongus) and blue sucker. The creek chubsucker inhabits small tributaries in east and southeast Texas, including tributaries of the San Jacinto River (Thomas, 2007; TPWD, 2012). Within the zone of potential impact of the Proposed Project, the creek chubsucker is restricted to Harris County. The species may occur within small intermittent and perennial streams and may be found in riffles, pools, and spring areas. The blue sucker inhabits large rivers ranging from the Colorado River to the Rio Grande (Thomas, 2007; Hubbs, 2008; TPWD, 2012). Within the Proposed Project area, the blue sucker may be found in the vicinity of the Colorado River crossing. The fish has been well studied in the Lower Colorado River (LCRA, 2008). The fish inhabits all habitat types and often migrates from the lower basin to near Austin to spawn. Mussels Approximately 52 species of native freshwater mussels in the mussel family, Unionidae, live in Texas waters. On November 5, 2009, TPWD added 15 to the state’s list of threatened species (TPWD, 2009). Of those 15 mussels, seven species are listed as potentially occurring within counties from Harris in the east to Crane in the west (TPWD, 2011) (Table 4.3.1-1). Below is a list of those seven species and summaries of their previously known occurrence in the counties included in the Proposed Project. Those streams include: Greens Bayou, White Oak Bayou, and Cypress Bayou (Harris County), Brazos River, Colorado River, Onion Creek, Barton Creek, Pedernales River, and Llano River. Four reports summarizing occurrence of mussels in Texas were reviewed. Howells et al. (1996) summarized the known occurrence of freshwater mussels in Texas based on review of published and unpublished literature and Howell’s field investigations. Burlakova et al. (2010) sampled 139 sites in 11 river basins in Texas over the period from 2003 to 2009. Winemiller et al. (2010) conducted an intensive review of museum records focused on mussels collected in 4-57 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Texas waters. The USFWS (Federal Register, 2011) describes the historical distribution and known current distribution of five mussels it has listed as candidate species. On October 6, 2011, the USFWS announced it had completed a status review of five Texas mussel species: Texas fatmucket (Lampsilis bracteata), Texas pimpleback (Quadrula petrina), golden orb (Quadrula aurea), Texas fawnsfoot (Truncilla macrodon), and smooth pimpleback (Quadrula houstonensis) (Federal Register, 2011). When resources allow in the future, the USFWS will determine if these species should be considered as threatened or endangered and if critical habitat should be designated for them. The USFWS status review of these five species includes detailed information about their distribution in Texas waters. Additional information was gathered from annual reports written by Howells (2000, 2001, 2002, 2004, 2005, and 2006) that summarized annual results of mussel surveys in Texas by Texas Parks and Wildlife Department biologists and trained volunteers. These surveys did not include all river basins each year. Survey of the Colorado River between the cities of Austin and Bastrop during 2003 did not encounter any state-listed species of mussels (Howells, 2004). Barton Springs in Travis County was also surveyed in 2003 without state-listed mussels being found (Howells, 2004). Readily available literature did not identify mussels collected from Greens Bayou, White Oak Bayou, or Cypress Creek in Harris County. The following describes areas where the listed mussels were collected or were sampled for, but not collected with respect to the watersheds within the Proposed Project. False spike (Quadrula mitchelli): • Llano River in Mason County (Howells et al., 1996); • Llano River (Winemiller et al., 2010); and • Burlakova et al. (2010) surveyed the Llano River during their statewide study from 2003 through 2009 and did not encounter it there. Golden orb (Quadrula aurea): • Llano River drainage (Howells et al., 1996); • Burlakova et al. (2010) did not find it at any of their sampling sites in the Brazos or Colorado River basins; • Colorado and Llano drainages (Winemiller et al., 2010); and • Federal Register’s (2011) review of literature indicates that golden orb has not occurred in the Colorado, Brazos, or Rio Grande watersheds. Reports of its occurrence in these drainages are attributed to misidentifications. Sandbank pocketbook (Lampsilis satura): • Although reported as possibly occurring in the San Jacinto River basin in Harris County, it has never been documented from the San Jacinto watershed (Howells et al., 1996; Burlakova et al., 2010; and Winemiller et al., 2010). Smooth pimpleback (Quadrula houstonensis): • Llano River and Colorado River drainage in Travis County (Howells et al., 1996); 4-58 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • Burlakova et al. (2010) and Winemiller et al. (2010) indicate it has been found in the Colorado and Brazos River drainages; • Llano River drainage (Winemiller et al., 2010); and • Federal Register (2011) indicates its historical distribution included the Llano River, Onion Creek, and the mainstems of the Colorado and Brazos rivers. Texas fatmucket (Lampsilis bracteata): • Pedernales River drainage and Llano River (Howells et al., 1996); • Colorado, Pedernales, Llano, and Onion Creek drainages (Winemiller et al., 2010); • Llano River and Live Oak Creek (Burlakova et al., 2010); • Live Oak Creek portion of the Pedernales River watershed (Howells 2002, 2005, and 2006); and • Colorado River upstream of Travis County, Pedernales and Llano rivers, and Onion Creek (Federal Register, 2011). Texas fawnsfoot (Truncilla macrodon): • Lower Colorado and Brazos rivers, Colorado River drainage in Travis County, and the Llano River (Howells et al., 1996). Although it was not reported from those rivers in Waller, Austin, Fayette, or Bastrop counties; • Burlakova et al. (2010) report it from the Colorado and Brazos rivers; • Winemiller et al. (2010) report Texas fawnsfoot from the Colorado and Llano rivers; and • Historically this species inhabited the Llano River, Onion Creek, and much of the Colorado River. Texas pimpleback (Quadrula petrina): • Howells et al. (1996) report this species from the Pedernales and Llano River watersheds; • Neither Burlakova et al. (2010) or Winemiller et al. (2010) reported this species in the counties covered in this report; and • Federal Register (2011) describes historical records of this species from much of the mainstem Colorado River, Llano and Pedernales rivers, and Onion Creek. 4.4 CULTURAL RESOURCES 4.4.1 PIPELINES 4.4.1.1 Proposed Project (East Houston to Crane) The Proposed Project ROW extending between Crane, Texas and Houston/Galena Park, Texas was constructed in the 1950s, prior to the passing of Section 106 of the National Historic Preservation Act (NHPA) of 1966, as amended, which requires federal agencies to take into consideration the effects of federally-permitted or funded actions on significant cultural resources. As a result, no formal cultural resources surveys were conducted prior to the original construction of the pipeline, and any undocumented cultural resources that may have been present within the ROW were disturbed to some degree during the original construction efforts 4-59 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL and subsequent maintenance activities. Because of this, there exists little to no potential for significant, intact cultural deposits within the original trench that was excavated for the pipeline installation. However, the potential for intact cultural deposits still exists within the limits of the ROW beyond the limits of the previously disturbed trench. In compliance with Section 106 of the NHPA, cultural resources survey and monitoring efforts were conducted at select locations along the proposed ROW in the 1990s during upgrades to the pipeline. These survey and monitoring efforts served to identify a number of previously undocumented archeological sites within the limits of the ROW. In 2000, the EPA and the DOT, in consultation with the Texas State Historic Preservation Officer (SHPO), Tribal Historic Preservation Officer(s) (THPO) (or other Tribal officer), and the Advisory Council on Historic Preservation (ACHP), executed a Programmatic Agreement (PA) to comply with Section 106 of the NHPA. Stipulations of the PA include requirements that Longhorn enter into consultation with the SHPO/THPO to identify all archaeological or historic properties within the ROW that are listed on or considered eligible for listing on the National Register of Historic Places (NRHP) and that may be affected directly or indirectly by subsequent ground-disturbing activities within the ROW. In accordance with the requirements of the PA, resource recovery plans are to be developed and implemented when adverse impacts to identified cultural resources listed on or considered eligible for listing on the NRHP cannot be avoided. A copy of the PA can be found in Appendix 4C. As per the PA for the Longhorn Pipeline, Horizon Environmental Services, Inc. (Horizon), on behalf of Magellan conducts cultural resources surveys at the locations of all necessary maintenance activities along the ROW. In an effort to allow these maintenance activities to comply with the time constraints of DOT requirements for identified pipeline anomalies and the Section 106 consultation process, Horizon designated archeological high and low probability areas along the length of the ROW based on a variety of factors including the locations of previously recorded archeological sites, distance from water sources, topographic settings, and the results of previous cultural resources surveys along the ROW. In compliance with Section 106 of the NHPA, the maps of the delineated high and low archeological probability areas were submitted to the SHPO for review. This submittal also included recommendations that: 1) no cultural resources surveys were warranted within the delineated low probability areas; 2) maintenance activities be allowed to proceed in the delineated low probability areas without further consultation with the SHPO; and 3) cultural resources surveys only be required within delineated archeological high probability areas (AHPAs). The SHPO concurred with these recommendations on 23 May 2007 (Appendix 4D). Since that time, the full extent of each delineated AHPA has been surveyed for cultural resources as maintenance activities arise in each. In compliance with the PA and Section 106 of the NHPA, a review of the Texas Historical Commission’s (THC’s) Texas Archeological Sites Atlas (Atlas) website was performed by Horizon for this FEA. The cultural resources review was conducted for an area defined as the area of potential effect (APE), which is 1,250 feet from the pipeline. This area is consistent with 1999 EA. The review of the THC’s Atlas website indicated the presence of 103 previously- 4-60 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL recorded archeological sites and eight cemeteries within the APE, while a review of the National Park Service’s (NPS) NRHP Google Earth map layer indicated the presence of no historic properties listed within the APE. These cultural resources and their distances from the ROW are summarized below. Documented Cultural Resources within 1,250 feet of Proposed Project Centerline Site Trinomial, Cemetery, or Historic Property Site Type NRHP Eligibility Status Distance/Direction from Centerline 41HR806 Historic dairy Undetermined 787.4 feet north 41HR401 Historic homestead Undetermined 262.5 feet north 41HR328 Prehistoric lithic scatter Undetermined 557.7 feet south 41WL14 Prehistoric campsite Undetermined 131.2 feet south 41WL15 Prehistoric campsite Undetermined 213.3 feet north 41WL17 Prehistoric campsite Undetermined 918.6 feet north 41AU72 Historic well Ineligible 1,148.3 feet south 41AU96 Prehistoric campsite Undetermined On centerline 41AU71 Historic homestead Ineligible On centerline 41FY448 Historic farmstead Ineligible 131.2 feet north 41FY534 Prehistoric campsite Ineligible On centerline 41FY497 Prehistoric lithic procurement area Ineligible 1,017.1 feet south 41FY532 Prehistoric lithic procurement area Ineligible On centerline 41LE40 Undetermined Undetermined 557.7 feet south 41FY495 Prehistoric lithic procurement area Ineligible 557.7 feet south 41FY533 Prehistoric campsite Ineligible On centerline 41FY508 Prehistoric campsite Undetermined On centerline 41FY496 Prehistoric lithic scatter Ineligible 295.3 feet south 41BP299 Prehistoric campsite Undetermined On centerline 41FY498 Prehistoric lithic scatter Ineligible 885.8 feet north 41BP673 Prehistoric campsite/Historic scatter Ineligible 49.2 feet north 41BP280 Prehistoric campsite Ineligible 492.1 feet southeast 41BP856 Prehistoric campsite and lithic procurement area Undetermined On centerline 41BP48 Prehistoric campsite Undetermined 131.2 feet north 41BP51 Prehistoric campsite Undetermined 131.2 feet north 41BP645 Prehistoric campsite Ineligible On centerline 41TV1665 Undefined prehistoric site Undetermined 98.4 feet south 41TV2000 Historic farmstead Undetermined 1,099.1 feet south 41TV1394 Historic homestead Ineligible 705.4 feet north 41TV1393 Prehistoric lithic procurement area Ineligible 1,279.5 feet north 41TV1396 Historic schoolhouse Ineligible 754.6 feet north 41TV1095 Prehistoric lithic procurement area Ineligible 754.6 feet north 41TV401 Prehistoric campsite and lithic procurement area Undetermined On centerline 4-61 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Site Trinomial, Cemetery, or Historic Property Site Type NRHP Eligibility Status Distance/Direction from Centerline 41TV399 Prehistoric campsite Undetermined On centerline 41TV400 Prehistoric campsite Undetermined 246.1 feet north 41TV402 Prehistoric campsite and lithic procurement area Undetermined 787.4 feet north 41TV1827 Prehistoric lithic procurement area Undetermined 591.0 feet southwest 41TV683 Prehistoric lithic procurement area Ineligible 607.0 feet southwest 41TV358 Prehistoric campsite Undetermined 951.4 feet southwest 41TV1826 Historic homestead Undetermined 98.4 feet north 41TV1825 Prehistoric lithic procurement area Ineligible 492.1 feet northeast 41TV2331 Historic homestead/Prehistoric lithic scatter Ineligible On centerline 41TV362 Prehistoric campsite with burned rock midden features Undetermined 1,049.9 feet south 41TV329 Prehistoric lithic scatter Undetermined 557.7 feet south 41TV1824 Prehistoric lithic procurement area Undetermined 1,164.7 feet northeast 41TV1061 Prehistoric campsite Ineligible 869.4 feet south 41TV1060 Prehistoric lithic scatter Ineligible 524.9 feet south 41TV555 Prehistoric campsite Ineligible 377.3 feet north 41TV1077 Prehistoric campsite Ineligible 492.1 feet north 41TV1076 Prehistoric campsite Ineligible 738.2 feet northeast 41TV1071 Prehistoric lithic procurement area Ineligible 1,082.7 feet north 41TV1068 Prehistoric campsite and lithic procurement area Undetermined 393.7 feet northeast 41TV1066 Prehistoric campsite and lithic procurement area Ineligible 49.2 feet north 41TV1069 Prehistoric campsite and lithic procurement area Ineligible 1,181.1 feet northeast 41TV1067 Prehistoric campsite and lithic procurement area Ineligible 262.5 feet north 41TV1065 Prehistoric campsite and lithic procurement area Ineligible 360.9 feet northeast 41TV344 Historic homestead Undetermined 1,033.5 feet northeast 41BC137 Prehistoric campsite Ineligible 377.3 feet southeast 41BC146 Prehistoric lithic scatter Ineligible On centerline 41BC91 Prehistoric rock shelter and lithic scatter Undetermined 131.2 feet south 41GL301 Prehistoric campsite Ineligible On centerline 41GL300 Prehistoric campsite Ineligible On centerline 41GL410 Prehistoric lithic Undetermined 853.0 feet south 4-62 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Site Trinomial, Cemetery, or Historic Property Site Type NRHP Eligibility Status Distance/Direction from Centerline scatter 41GL310 Prehistoric campsite Ineligible On centerline 41GL367 Prehistoric lithic scatter Ineligible On centerline 41GL299 Prehistoric lithic scatter Ineligible On centerline 41GL368 Prehistoric campsite Ineligible On centerline 41GL335 Prehistoric lithic procurement area Ineligible 1,066.3 feet north 41LL469 Prehistoric campsite Ineligible On centerline 41MS79 Prehistoric lithic scatter Ineligible On centerline 41MS80 Prehistoric lithic scatter Ineligible On centerline 41MS81 Prehistoric campsite Ineligible On centerline 41MS27 Prehistoric campsite Undetermined On centerline 41MS65 Prehistoric campsite with burned rock midden features Undetermined On centerline 41KM234 Prehistoric lithic scatter Ineligible On centerline 41KM206 Prehistoric campsite Ineligible On centerline 41KM165 Prehistoric campsite with burned rock midden features Undetermined On centerline 41KM231 Prehistoric lithic scatter Ineligible On centerline 41KM207 Prehistoric lithic scatter Undetermined On centerline 41KM103 No site form available Undetermined On centerline 41KM102 No site form available Undetermined On centerline 41KM232 Prehistoric lithic scatter Ineligible On centerline 41KM164 Prehistoric lithic scatter Ineligible On centerline 41KM163 Prehistoric campsite with burned rock midden features Ineligible 164.0 feet south 41KM233 Prehistoric lithic scatter Ineligible On centerline 41SL23 Prehistoric lithic scatter Ineligible On centerline 41SL22 Prehistoric campsite and lithic procurement area Ineligible On centerline 41RG42 Prehistoric lithic scatter Ineligible 853.0 feet northeast 41RG43 Prehistoric campsite Ineligible 591.0 feet northeast 41RG44 Prehistoric campsite Ineligible 721.8 feet northeast 41RG45 Historic stone structure Ineligible 164.0 feet northeast 41RG46 Prehistoric campsite Ineligible 229.7 feet northeast 41RG50 Prehistoric campsite Ineligible 1,181.1 feet southwest 41RG47 Prehistoric campsite Ineligible 229.7 feet northeast 41RG48 Prehistoric campsite Ineligible 164.0 feet southwest 41RG49 Prehistoric campsite Ineligible 262.5 feet southwest 4-63 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Site Trinomial, Cemetery, or Historic Property Site Type NRHP Eligibility Status Distance/Direction from Centerline 41RG51 Prehistoric campsite Ineligible 607.0 feet southwest 41RG52 Prehistoric campsite Ineligible 984.3 feet southwest 41RG59 Prehistoric campsite Ineligible On centerline 41RG57 Prehistoric campsite Ineligible On centerline 41RG54 Prehistoric campsite Ineligible 1,082.7 feet northeast 41RG27 Prehistoric campsite Ineligible 721.8 feet northwest 41RG56 Prehistoric campsite Ineligible 1,148.3 feet northeast Ellerbracht Cemetery Cemetery N/A 1250.0 feet south Schneider Cemetery Cemetery N/A 1,250.0 feet southwest Unnamed Cemetery Cemetery N/A 100.0 feet northeast Community Cemetery Cemetery N/A 542.0 feet north Higgins Cemetery Cemetery N/A Immediately adjacent to ROW Claiborne Cemetery Cemetery N/A 200.0 feet south Thompson-Morris Cemetery Cemetery N/A 930.0 feet north Travis Cemetery Cemetery N/A 620.0 feet north 4.4.2 PUMP STATIONS 4.4.2.1 Buckhorn Station A review of the THC’s Atlas website performed by Horizon for this FEA indicated the presence of no previously recorded archeological sites or cemeteries within a 1,250.0-foot radius of the proposed Buckhorn Station. Similarly, a review of the NPS NRHP Google Earth map layer indicated the presence of no historic properties listed on the NRHP within the review perimeter. Based on the Atlas data, this location has not been previously assessed for cultural resources. However, this station is located within a portion of the existing Longhorn Pipeline ROW that is defined within the PA as having a low probability for archeological sites. Therefore, no further investigation is warranted. 4.4.2.2 Industry Station A review of the THC’s Atlas website performed by Horizon for this FEA indicated the presence of no previously recorded archeological sites or cemeteries within a 1,250.0-foot radius of the proposed Industry Station. Similarly, a review of the NPS NRHP Google Earth map layer indicated the presence of no historic properties listed on the NRHP within the review perimeter. Based on the Atlas data, this location has not been previously assessed for cultural resources. However, this station is located within a portion of the existing Longhorn Pipeline ROW that is defined within the PA as having a low probability for archeological sites. Therefore, no further investigation is warranted. 4.4.2.3 Warda Station A review of the THC’s Atlas website performed by Horizon for this FEA indicated the presence of no previously recorded archeological sites or cemeteries within a 1,250.0-foot radius of the 4-64 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL existing Warda Station. Similarly, a review of the NPS NRHP Google Earth map layer indicated the presence of no historic properties listed on the NRHP within the review perimeter. This is an existing, previously disturbed facility that was previously assessed for cultural resources by TAS in 2005. This site was previously assessed and documented in a Site Specific Environmental Study Report (SSESR) to contain no significant cultural resources eligible for the NRHP exist within the APE of the project. 4.4.2.4 Bastrop Station A review of the THC’s Atlas website performed by Horizon for this FEA indicated the presence of two cemeteries within 1,250.0 feet of the Bastrop Station, while a review of the NPS NRHP Google Earth map layer indicated the presence of no historic properties listed on the NRHP within the review perimeter. These cultural resources and their distances from the proposed ROW are summarized below. Based on the Atlas data, this location has not been previously assessed for cultural resources, although it does border a section of ROW that was surveyed in 2006 with negative results. The proposed site is located within a portion of the Longhorn Pipeline ROW that is defined within the PA as having a low probability for archeological sites. Therefore, no further investigation is warranted. Documented Cultural Resources within 1,250 feet of the Bastrop Station Site Trinomial, Cemetery, or Historic Property Site Type NRHP Eligibility Status Distance/Direction from Centerline Community Cemetery Cemetery N/A 900.0 feet east Unnamed Cemetery Cemetery N/A 1,200.0 feet east 4.4.2.5 Eckert Station A review of the THC’s Atlas website performed by Horizon for this FEA indicated the presence of no previously recorded archeological sites or cemeteries within a 1,250.0-foot radius of the existing Eckert Station. Similarly, a review of the NPS NRHP Google Earth map layer indicated the presence of no historic properties listed on the NRHP within the review perimeter. This is an existing, previously disturbed facility. According to the Atlas data, TAS surveyed this site in 2005 with negative results. This site was previously assessed and documented in a SSESR to contain no significant cultural resources eligible for the NRHP. 4.4.2.6 James River Station A review of the THC’s Atlas website performed by Horizon for this FEA indicated the presence of no previously recorded archeological sites or cemeteries within a 1,250.0-foot radius of the proposed James River Station. Similarly, a review of the NPS NRHP Google Earth map layer indicated the presence of no historic properties listed on the NRHP within the review perimeter. Based on the Atlas data, this location has not been previously assessed for cultural resources. However, it is located within a Longhorn Pipeline AHPA that Horizon surveyed with negative results. 4-65 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 4.4.2.7 Cartman Station A review of the THC’s Atlas website performed by Horizon for this FEA indicated the presence of no previously recorded archeological sites or cemeteries within a 1,250.0-foot radius of the proposed Cartman Station. Similarly, a review of the NPS NRHP Google Earth map layer indicated the presence of no historic properties listed on the NRHP within the review perimeter. Based on the Atlas data, this location has not been previously investigated for cultural resources. However, this station is located within a portion of the Longhorn Pipeline ROW that is defined within the PA as having a low probability for archeological sites. Therefore, no further investigation is warranted. 4.4.2.8 Barnhart Station A review of the THC’s Atlas website performed by Horizon for this FEA indicated the presence of no previously recorded archeological sites or cemeteries within a 1,250.0-foot radius of the proposed Barnhart Station. Similarly, a review of the NPS NRHP Google Earth map layer indicated the presence of no historic properties listed on the NRHP within the review perimeter. This station is located within a section of the Longhorn Pipeline that TAS, in 2005, and Horizon, in 2008, surveyed with negative results. This site was previously assessed and documented in a SSESR to contain no significant cultural resources eligible for the NRHP. 4.4.2.9 Texon Station A review of the THC’s Atlas website performed by Horizon for this FEA indicated the presence of no previously recorded archeological sites or cemeteries within a 1,250.0-foot radius of the proposed Texon Station. Similarly, a review of the NPS NRHP Google Earth map layer indicated the presence of no historic properties listed on the NRHP within the review perimeter. Based on the Atlas data, this location has not been previously assessed for cultural resources. However, this station is located within a portion of the Longhorn Pipeline ROW that is defined as having a low probability for archeological sites. Therefore, no further investigation is warranted. 4.4.2.10 East Houston Terminal A review of the THC’s Atlas website indicated the presence of no previously recorded archeological sites or cemeteries within 1,250.0 feet of the boundaries of the existing East Houston Terminal. Similarly, a review of the NPS NRHP Google Earth map layer indicated the presence of no historic properties listed on the NRHP within the review perimeter. Based on the Atlas data, the majority of the area of this existing terminal has not been previously surveyed for cultural resources. However, the banks of Hunting Bayou, which runs through this terminal, were assessed via a reconnaissance level survey with negative results for an assessment conducted for the Harris County Flood Control District (HCFCD) in 2001. This existing facility is to undergo infrastructure improvements within the existing facility footprint. 4-66 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 4.5 REFERENCES Anaya, R. 2001. An Overview of the Edwards-Trinity Aquifer System, Central–West Texas: Mace, R.E., Mullican III, W.F., and Angle, E.S. eds. Aquifers of West Texas: Texas Water Development Board Report 356. pp. 107 – 116. Anaya, R. 2004. Conceptual Model for the Edwards–Trinity (Plateau) Aquifer System, Texas: Mace, R.E., Angle, E.S., and Mullican, W.F., III, eds. Aquifers of the Edwards Plateau: Texas Water Development Board Report 360, pp. 42 – 53. Anaya, R. and Jones, I. 2009. Groundwater Availability Model for the Edwards-Trinity (Plateau) and Pecos Valley Aquifers of Texas: Texas Water Development Board Report 373. pp. 25 -34 and 42 – 48. Ashworth, J.B. 1983. Ground-water Availability of the Lower Cretaceous Formations in the Hill Country of South-Central Texas: Texas Water Development Board Report 273. pp. 9 – 33, 39 – 44 and 47 – 48. Ashworth, J.B. 1990. Evaluation of Ground-Water Resources in EI Paso County, Texas: Texas Water Development Board Report 324. pp. 5 – 6. Ashworth, J.B. and Hopkins, J. 1995. Aquifers of Texas: Texas Water Development Board Report 345. pp. 10 – 21, 24 – 27, 31 – 37, 39 -40, 47 – 48, 57 – 58 and 61 – 66. Asquith, W.H. and Raymond M. Slade, Jr., Regional Equations for Estimation of Peak- Streamflow Frequency for Natural Basins in Texas. US Geological Survey, Water- Resources Investigations Report 96-4307, p 62, 1997. Asquith, W.H., Raymond M. Slade, Jr., and Jennifer Lanning-Rush, US Department of the Interior, US Geological Survey, Peak-Flow Frequency and Extreme Flood Potential for Streams in the Vicinity of the Highland Lakes, Central Texas. US Geological Survey, Water-Resources Investigations Report 96-4072, 1996. Asquith, W.H., USGS, Peak-Flow Frequency for Tributaries of the Colorado River Downstream of Austin, Texas, Water-Resources Investigations Report 98-4015, p 18, 1998. Austin, City of, Watershed Protection Department. The Official Website of the City of Austin. http://www.austintexas.gov/department/salamander Baker, E.T., Personal Communication, USGS, 1999. Barker, Rene A. and Ardis, Ann F., “Hydrogeologic Framework of the Edwards-Trinity Aquifer US Geological Survey Professional Paper 1421-B, 1996. Blair, W.F. 1950. The biotic provinces of Texas. Texas Journal of Science 2:93–117. Blandford, T.N., Blazer, D.J., Calhoun, K.C., Dutton, A.R., Naing, T., Reedy, R.C., and Scanlon, B.R. 2003. Groundwater Availability of the Southern Ogallala Aquifer in Texas and New Mexico: Numerical Simulations Through 2050: Texas Water Development Board Report No. __. pp. 14 – 20 and 25 – 56. Boghici, R. and Van Broekhoven, N.G. 2001. Hydrogeology of the Rustler Aquifer, Trans-Pecos Texas: Mace, R.E., Mullican III, W.F., and Angle, E.S. eds. Aquifers of West Texas: Texas Water Development Board Report 356. pp. 207 – 219. Bonn, T.D., Existing Reservoir and Steam Management Recommendations: Lower Colorado River, 1979, TPWD, Job Completion Report, 1980. 4-67 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Bradley, R.G., and Kalaswad, S. 2001. The Dockum Aquifer in West Texas: Mace, R.E., Mullican III, W.F., and Angle, E.S. eds. Aquifers of West Texas: Texas Water Development Board Report 356. pp. 167 – 172. Bradley, R.G., and Kalaswad, S. 2003. The Groundwater Resources of the Dockum Aquifer in Texas: Texas Water Development Board Report 359. pp. 8 – 35. Bradley, R.G., and Kalaswad, S. 2004. The Dockum Aquifer in the Edwards Plateau: Mace, R.E., Angle, E.S., and Mullican, W. F., III, eds. Aquifers of the Edwards Plateau: Texas Water Development Board Report 360, pp. 152 – 157. Burlakova, L. E., Karatayev, A. Y., Karatayev, V. A., Mays, M. E., Bennett, D. L., and M. J. Cook. 2010. Endemic species: Contribution to community uniqueness, effect of habitat alteration, and conservation priorities. Biological Conservation (2010), doi: 10.1016/j.biocon.2010.08.010. Campbell, Linda. 1996. Exploring Texas Ecoregions. Texas Parks and Wildlife Department. Austin Carr, J.T., Jr., The Climate and Physiography of Texas, Texas Water Development Board Report 53, p 27, 1967. Chowdhury, A.H. and Turco, M.J. 2006. Geology of the Gulf Coast Aquifer, Texas: Mace, R.E., Mullican III, W.F., and Angle, E.S. eds. Aquifers of the Gulf Coast of Texas: Texas Water Development Board Report 365. pp. 37 – 44. Davidson, S.C. and Mace, R.E. 2006. Aquifers of the Gulf Coast of Texas: An Overview: Mace, R.E., Mullican III, W.F., and Angle, E.S. eds. Aquifers of the Gulf Coast of Texas: Texas Water Development Board Report 365. pp. 1 – 10. Davidson, S.C. Brown, B.J. and Mace, R.E. 2009. Aquifers of the Upper Coastal Plains: Hutchison, W.R., Davidson, S.C., Brown, B.J. and Mace, R.E. eds. Aquifers of the Upper Coastal Plains of Texas: Texas Water Development Board Report 374. pp. 5 – 10. DeCook, K.J. 1960. Geology and Ground-Water of Hays County, Texas: Texas Board of Water Engineers (TBWE) Bulletin 6004. pp. 11 – 36 and 50 – 54. Deeds, N.E., Fryar, D., Dutton, A., and Nicot, J. 2009. Hydrogeology of the Carrizo-Wilcox Aquifer: Hutchison, W.R., Davidson, S.C., Brown, B.J. and Mace, R.E. eds. Aquifers of the Upper Coastal Plains of Texas: Texas Water Development Board Report 374. pp. 35 - 50. Department of Transportation (DOT), Federal Highway Administration, “Stream Stability at Highway Structures,” Hydraulic Engineering Circular No. 20, February 1991. Dixon, J.R. 2000. Amphibians and Reptiles of Texas. Texas A&M University Press, College Station. Dunn, David, “Trends in Nutrient Inflows to the Gulf of Mexico From Streams Draining the Conterminous United States, 1972-1983,” US Geological Survey, Water-Resources Investigations Report 96-4133, 1996. Dutton, A.R., Harden, B., Nicot, J., and O’Rourke, D. 2003. Groundwater Availability Model for the Central Part of the Carrizo-Wilcox Aquifer in Texas: Texas Water Development Board Contract Number 2001-483-378. pp. 19 – 28 and 32 – 34. El-Hage, Albert; Moulton, Daniel. 1998. Evaluation of Selected Natural Resources in El Paso County, Texas. Texas Parks and Wildlife, Austin 4-68 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Escabar, R., Personal Communication, Facilities Manager, Ysleta ISD, 1999. Federal Register. 2011. 62166 / Vol. 76, No. 194 / Thursday, October 6, 2011 / Proposed Rules Department of the Interior Fish and Wildlife Service 50 CFR Part 17 [FWS–R2–ES– 2011–0079; MO 92210–0–0008 B2] Endangered and Threatened Wildlife and Plants; 12-Month Finding on a Petition To List Texas Fatmucket, Golden Orb, Smooth Pimpleback, Texas Pimpleback, and Texas Fawnsfoot as Threatened or Endangered AGENCY: Fish and Wildlife Service, Interior. ACTION: Notice of 12-month petition. Fish and Wildlife Service (FTWS), 2011. Endangered species list: list of species by county for Texas. http://www.fws.gov/southwest/es/EndangeredSpecies/ (accessed June 10, 2011). Google Earth Pro (Accessed June 2011) Gould, F.W., G.O. Hoffman, and C.A. Rechenthin. 1960. Vegetational areas of Texas. Texas Agricultural Extension Service. L-492. Griffith, G., Bryce, S., Omernik, J., Comstock, J., Rogers, A., Harrison, B., Hatch, S., and Bezanson, D. 2004. Ecoregions of Texas (color poster with map, descriptive text, and photographs): Reston, Virginia, U.S. Geological Survey (map scale 1:2,500,000). Harris Galveston Subsidence Districts website with 1906-2000 Subsidence Contour map: http://mapper.subsidence.org/Static%20Maps/SubsidenceMap1906-2000.pdf) Hatch, S.L., K.N. Gandhi, and L.E. Brown. 1990. Checklist of the vascular plants of Texas. Texas Agricultural Experiment Station, College Station. Hauwert, N., Hunt, B., Gary, M., and Johnson, S., 2010, Blanco River Recharges Barton Springs During Drought, Save Barton Creek Association. http://savebartoncreek.org/blanco-river-recharges-barton-springs-during-drought/. Accessed on April 11, 2012. Hauwert, N.M. 2009. Groundwater Flow and Recharge within the Barton Springs Segment of the Edwards Aquifer, Southern Travis and Northern Hays Counties, Texas: The University of Texas, Austin, Doctoral Dissertation CM-CM-2009-1. Hauwert, N.M. and Hiers, S.E. 2010. Understanding Upland Recharge for Geologic Assessment: Austin Geological Society Guidebook TM-2009-1. Howells, R. G. 2000. Distributional Surveys of Freshwater Bivalves in Texas. Progress Report for 1999. TPWD Data Series 170. Howells, R. G. 2001. Distributional Surveys of Freshwater Bivalves in Texas. Progress Report for 2000. TPWD Data Series 187. Howells, R. G. 2002. Distributional Surveys of Freshwater Bivalves in Texas. Progress Report for 2001. TPWD Data Series 200. Howells, R. G. 2004. Distributional Surveys of Freshwater Bivalves in Texas. Progress Report for 2003. TPWD Data Series 222. Howells, R. G. 2005. Distributional Surveys of Freshwater Bivalves in Texas. Progress Report for 2004. TPWD Data Series 233. Howells, R. G. 2006. Statewide Freshwater Mussel Survey. State Wildlife Grant Report to TPWD. Howells, R. G., Neck, R. W., and H. D. Murray. 1996. Freshwater Mussels of Texas. 218 pp. 4-69 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Jones, I.C. 2001. Cenozoic Pecos Alluvium Aquifer: Mace, R.E., Mullican III, W.F., and Angle, E.S. eds. Aquifers of West Texas: Texas Water Development Board Report 356. pp. 121 – 128. Jones, I.C. 2004. Cenozoic Pecos Alluvium Aquifer: Mace, R.E., Angle, E.S., and Mullican, W.F., III, eds. Aquifers of the Edwards Plateau: Texas Water Development Board Report 360, pp. 135 – 144. Jones, I.C., Anaya, R. and Wade, S. 2009. Groundwater Availability Model for the Hill Country Portion of the Trinity Aquifer System, Texas: Texas Water Development Board Report. pp. 6 – 14 and 15 – 17. Kasmarek, M.C. and Robinson, J.L. 2004. Hydrogeology and Simulation of Ground-Water Flow and Land-Surface Subsidence in the Northern Part of the Gulf Coast Aquifer System, Texas: U.S. Geological Survey Scientific Investigations Report 2004–5102. pp 10-36. Kelley, V.A., Deeds, N.E., Fryar, D.G. and Nicot, J. 2004. Groundwater Availability Models for the Queen City and Sparta Aquifers: Texas Water Development Board, Austin. pp. 2-25 – 2-28 and 4-1. Kelley, V.A., Fryar, D.G. and Deeds, N.E. 2009. Hydrogeology of the Queen City and Sparta Aquifers with an Emphasis on Regional Mechanisms of Discharge: Hutchison, W.R., Davidson, S.C., Brown, B.J. and Mace, R.E. eds. Aquifers of the Upper Coastal Plains of Texas: Texas Water Development Board Report 374. pp. 90 – 104. Land, L. F., Hunt, B.B., Smith, B.A., and Lemonds, P.J., 2011. Hydrologic Connectivity in the Edwards Aquifer between San Marcos Springs and Barton Springs during 2009 Drought Conditions: Texas Water Journal, Volume 2, Number 1, Texas Water Resources Institute. pp. 39, 40, 47 and 50. Mace, R.E. 2001. Aquifers of West Texas: An Overview: Mace, R.E., Mullican III, W.F., and Angle, E.S. eds. Aquifers of West Texas: Texas Water Development Board Report 356. pp. 3 – 9. Mace, R.E., Angle, E.S. 2004 Aquifers of the Edwards Plateau: Mace, R.E., Angle, E.S., and Mullican, W.F., III, eds. Aquifers of the Edwards Plateau: Texas Water Development Board Report 360. pp. 6 – 12. McMahan, C.A., R.G. Frye, and K.L. Brown. 1984. The vegetation types of Texas, including cropland. Wildlife Division, Texas Parks and Wildlife Department, Austin. National Park Service’s National Register of Historic Places Google Earth Map Layer – South Region. http://nrhp.focus.nps.gov/natreg/docs/Google_Earth_Layers.html. O’Rourke, D. 2006. Conjunctive Use of the Brazos River Alluvium Aquifer: Mullican III, W.F., and Angle, E.S. eds. Aquifers of the Gulf Coast of Texas: Texas Water Development Board Report 365. pp. 61 – 67. Pemberton, E.L., and J.M Lara, “Computing Degradation and Local Scour,” Technical Guideline for Bureau of Reclamation, 1984. Pettyjohn, W.A., Savoca, M.E., and Self, Dale, “Regional Assessment of Aquifer Vulnerability and Sensitivity in the Continental United States,” US Environmental Protection Agency Report EPA/600/2-91/043, p 319, 1991. Preston, R.D. 2006. The Yegua-Jackson Aquifer: Mace, R.E., Mullican III, W.F., and Angle, E.S. eds. Aquifers of the Gulf Coast of Texas: Texas Water Development Board Report 365. pp. 53 – 56. 4-70 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Rines, T.N., Peak-Discharge Frequency and Potential Extreme Peak Discharge for Natural Rose, P.R. 1972. Edwards Group, Surface and Subsurface, Central Texas: The University of Texas, Austin, Bureau of Economic Geology Report of Investigations 74. pp. 18 – 20 and 24 – 25. Schertz, Terry L., Frank C. Wells, and Dane J. Ohe, Sources of Trends in Water-Quality Data for Selected Streams in Texas, 1975-89 Water Years, US Geological Survey, Water- Resources Investigations Report 94-4213, 1994. Simmons, E., Public Waters of Texas, TPWD, In Press. Small, T.A., Hanson, J.A., and Hauwert, N.M. 1996. Geologic Framework and Hydrogeologic Characteristics of the Edwards Aquifer Outcrop (Barton Springs Segment), Northeastern Hays and Southwestern Travis Counties, Texas: U.S. Geological Survey Water- Resources Investigations Report 96–4306. pp 4-11. Smith, R. 2004. Paleozoic Aquifers of the Llano Uplift: Mace, R.E., Angle, E.S., and Mullican, W.F., III, eds. Aquifers of the Edwards Plateau: Texas Water Development Board Report 360, pp. 183 -191 Standen, A. and Ruggiero, R. 2007. Llano Uplift Aquifers Structure and Stratigraphy: 0604830614. pp. 2 – 7. Standen, A.R., and Opdyke, D.R. 2004. Contamination Migration, Characteristics, and Responses for the Edwards–Trinity (Plateau) Aquifer: Mace, R.E., Angle, E.S., and Mullican, W.F., III, eds. Aquifers of the Edwards Plateau: Texas Water Development Board Report 360, pp. 211-218. Stoeser, D.B., Green, G.N., Morath, L.C., Heran, W.D., Wilson, A.B., Moore, D.W., and Van Gosen, B.S. 2005. Preliminary integrated geologic map databases for the United States: Central States: Montana, Wyoming, Colorado, New Mexico, North Dakota, South Dakota, Nebraska, Kansas, Oklahoma, Texas, Iowa, Missouri, Arkansas, and Louisiana: U.S. Geological Survey Open-File Report 2005-1351. http://pubs.usgs.gov/of/2005/1351/#TX. Accessed on April 28, 2011. Streams in the Brazos River Basin, Texas, US Geological Survey, Water-Resources Investigations Report 98-4178, p 34, 1998. Texas Commission on Environmental Quality (TCEQ) database, TNRIS database, http://www.tceq.state.tx.us/gis/. Texas Commission on Environmental Quality (TCEQ), 2002. Effects of Leaking Petroleum Storage Tanks on the Trinity Group Aquifer: TCEQ publication SFR-073. pp. vii – viii, 6 and 15 – 30. Texas Commission on Environmental Quality (TCEQ), 2005. Texas Nonpoint Source Management Program: SFR-068/04. Appendix D: Aquifer Vulnerability Ranking System. pp. 254 – 256. Texas Commission on Environmental Quality (TCEQ), 2011. Website: http://www.tceq.state.tx.us/cgi-bin/compliance/monops/8hr_attainment.pl Texas Commission on Environmental Quality (TCEQ), 2012. Underwater life in Barton Springs. Available on the internet at: http://www.tec.org/bartonsprings/hansen_1.html. Accessed on February 21, 2012. 4-71 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Texas Commission on Environmental Quality (TCEQ). Source Water Assessment Viewer. http://gis3.tceq.state.tx.us/swav/Controller/index.jsp?wtrsrc= Texas Historical Commission (THC). Atlas Texas Archeological Sites Atlas Restricted Database. http://www.pedernales.thc.state.tx.us/. Texas Parks and Wildlife Department (TPWD), 1984. The Vegetation Types of Texas Map. Austin, Texas. Texas Parks and Wildlife Department (TPWD), 2009. Commission Agenda Item No. 7. Action Listing of Certain Mussel Species as State-Threatened. November 5, 2009. http://www.tpwd.state.tx.us/business/feedback/meetings/2010/1105/agenda/item_7/ Texas Parks and Wildlife Department (TPWD), 2011. “The Rare, Threatened, and Endangered Species by County” web page. http://www.tpwd.state.tx.us/landwater/land/maps/gis/ris/endangered_species/ Texas Parks and Wildlife Department (TPWD), 2011. Annotated County Lists of Rare, Threatened, and Endangered Species for Austin, Bastrop, Blanco, Crane, Crockett, Culberson, Ector, El Paso, Fayette, Gillespie, Harris, Hays, Hudspeth, Kimble, Mason, Menard, Pecos, Reagan, Reeves, Schleicher, Travis, Upton, Waller, and Ward Counties Texas Parks and Wildlife Department (TPWD), 2011. Find a park. Accessed 15 June 2011 at http://www.tpwd.state.tx.us/spdest/findadest/. Texas Parks and Wildlife Department (TPWD), 2011. Natural Regions of Texas Map. Adapted from Preserving Texas’ Natural Heritage, LBJ School of Public Affairs Policy Research Project 31, 1978. Texas Parks and Wildlife Department (TPWD), 2011. Plant Guidance by Ecoregions. http://www.tpwd.state.tx.us/huntwild/wild/wildscapes/guidance/plants/ecoregions/ (Accessed June1, 2011) Texas Parks and Wildlife Department (TPWD), 2012. Factsheet, Barton Springs Salamander (Eurycea sosorum), http://www.tpwd.state.tx.us/huntwild/wild/species/bartonspringssalamander/ Texas Parks and Wildlife Department (TPWD), Nov. 5, 2009. 15 Texas Freshwater Mussels Placed on State Threatened List. http://www.tpwd.state.tx.us/newsmedia/releases/?req=20091105c&nrtype=all&nrspan=2 009&nrsearch= (accessed June 2, 2011). Texas Water Development Board (TWDB), 2011. Source Water Assessment Viewer. http://gis3.tceq.state.tx.us/swav/Controller/index.jsp?wtrsrc= . PWS Wells and Intakes database. Well Capture Zones database. Accessed on April 28, 2011. Texas Water Development Board (TWDB). 2007. GIS Data. Major Aquifers of Texas Shapefiles and Minor Aquifers of Texas Shapefiles. http://www.twdb.state.tx.us/mapping/gisdata.asp. Accessed on April 28, 2011. Texas Water Development Board (TWDB). 2007. Water for Texas: Document No. GP-8-1. Volume II. Ch. 7. pp. 176-186, 190-195, 197-201, 205, 207-209, 211, 213-214, and 216- 217. Thomas, C., Bonner, T., and Whiteside, B. 2007. Freshwater Fishes of Texas: A Field Guide. Texas A&M Press, College Station, Texas. 4-72 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Turner, M. and O’Donnell, L. 2004. Response Tier Development Document Barton Springs Salamander Catastrophic Spill Plan. SR-05-01. U.S. Census Bureau. 2009. 2009 population estimates. Retrieved 15 June 2011 from http://factfinder.census.gov/servlet/SAFFPopulation?_submenuId=population_0&_sse=o n U.S. Department of Transportation (DOT). 2000. Pipeline Safety: Areas Unusually Sensitive to Environmental Damage: 49 CFR Part 195. Federal Register, Vol. 65, No. 246. pp. 80532 and 80544. U.S. Environmental Protection Agency (EPA), 1999. Region 6 Office, Final Longhorn Environmental Assessment (original) for the Longhorn Pipeline: See http://www.epa.gov/region6/6en/xp/longhorn.htm. U.S. Environmental Protection Agency (EPA), 2011. Watersheds Homepage. http://water.epa.gov/type/watersheds/ (Accessed June 13, 2011). U.S. Environmental Protection Agency (EPA), DRASTIC: A Standardized System for Evaluating Groundwater Pollution Potential Using Hydrogeologic Settings” (EPA/600/2-87/035 June 1987). U.S. Environmental Protection Agency (EPA), Region 6, EPA STORET database records @ http://www.epa.gov/storpubl U.S. Environmental Protection Agency (EPA). 1991. Regional Assessment of Aquifer Vulnerability and Sensitivity in the Conterminous United States: EPA/600/2-91/043. pp. 5 – 8 and 207. URS Dames & Moore, Calculation of Fluid Loads on Pipeline, May 9, 2000. URS Radian. Summary of Scour-related Study, June 2000. Veenhuis, J.E., US Geological Survey, "Water-Quality Management" section by David Buzan, Texas Water Commission, National Water Summary 1990-91 - Stream Water Quality: Texas, US Geological Survey Water Supply Paper 2400, 1992. Walker, L.E. 1979. Occurrence, Availability and Chemical Quality of Ground Water in the Edwards Plateau Region of Texas: Texas Water Development Board Report 235. pp. 47 – 55. Wierman, D.A., Broun, A.S., and Hunt, B.B. 2010. Hydrogeologic Atlas of the Hill Country Trinity Aquifer, Blanco, Hays, and Travis Counties, Central Texas: Prepared by the Hays- Trinity, Barton Springs/Edwards Aquifer, and Blanco Pedernales Groundwater Conservation Districts. Winemiller, K., Lujan, N. K., Wilkins, R. N., Snelgrove, R. T., Dube, A. M., Skow, K. L., and A. G. Snelgrove. 2010. Status of Freshwater Mussels in Texas. 64 pp. http://irnr.tamu.edu/media/297520/status_of_freshwater_mussels_in_texas_tamu- irnr_05-2010_1.pdf Young, S.C., Knox, P.R., Baker, E., Budge, T., Hamlin, S., Galloway, B., Kalbouss, R., and Deeds, N. 2010. Hydrostratigraphy of the Gulf Coast Aquifer from the Brazos River to the Rio Grande: Report ###: Texas Water Development Board, Austin, Texas. pp 7-28, 47-61 and 88-95. 4-73 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL CHAPTER 4 TABLES <<>> Table 4.1.1-1 Apartment Facilities within the Zone of Potential Impact of Proposed Project Facility Name Address Estimated Number of Units Houston Area Justill’s Apartments Holland between Munn St. and Flaxman St. 20 Lake Crest Village Apartments 9393 Tidwell Rd. 224 Commons of Grace 9110 Tidwell Rd. 108 Sterlingshire 9002 Sterlingshire St. 200 Dyersdale Village 9700 Mesa Dr. 152 Glenwood Forest Apartments 8600 Sterlingshire St. 159 Swiss Village 9603 Homestead Rd. 32 Unnamed duplex Haddick Street and Caddo Road 2 Unnamed duplex Madera Road between Wiloak St. and Haddick St. 2 Unnamed duplex Madera Road between Wiloak St. and Haddick St. 2 Unnamed duplex Madera Road and Wiloak Street 2 Unnamed duplex Charlesmont St. and Wiloak St. 2 Unnamed duplex Charlesmont St. and Rhobell St. 2 Unnamed triplex Caddo Road between Greenwich St. and Wiloak St. 3 Unnamed duplex Caddo Road between Greenwich St. and Wiloak St. 2 Unnamed duplex Rhobell St. and Greenwich St. 2 Unnamed duplex Rhobell St. and Greenwich St. 2 Unnamed duplex Greenwich St. and Bigwood St. 2 Unnamed duplex Cabot St. and Greenwich St. 2 Unnamed duplex Cabot St. and Greenwich St. 2 Unnamed duplex Claiborne St. and Greenwich St. 2 Unnamed duplex Claiborne St. and Greenwich St. 2 Unnamed duplex Gallahad St. between Greenwich St. and Wiloak St. 2 North Forest Trails Apartments 9550 North Wayside Dr. 168 Unidentified structure Galaxy St. and Wayside Dr. 7 Unnamed duplex Okay St. and Langley Rd. 2 Unidentified structure North end of Meadowshire St. 14 Coppertree Village 1415 West Gulf Bank Rd. 168 Unidentified complex W Mount Houston Rd. and W Montgomery Rd. 288 Oaks of Inwood 5300 West Gulf Bank Rd. 376 Park Lane 5714 West Gulf Bank Rd. 48 Chesapeake Village 8430 Antoine Dr. 72 Unidentified Rodney Ray Blvd. and Windfern Rd. 16 Tiburon Apartments 8989 West Rd. 336 Watermarke Apartments 9404 West Rd. 288 Villas At West Road 9500 West Rd. 352 Unidentified complex Jones Rd. and Steeplepark Dr. 39 <<>> Table 4.1.1-1 Apartment Facilities within the Zone of Potential Impact (continued) Facility Name Address Estimated Number of Units Winchester Place 10910 Gold Point Dr. 256 Ascot Court 10910 West Rd. 149 Ranchstone 10901 Ranchstone Dr. 160 Stone Canyon 10919 West Rd. 216 Pointe At Steeplechase 8901 Jones Rd. 316 Camden Steeplechase 9001 Jones Rd. 390 Trails At Corinthian Creek 8655 Jones Rd. 36 Trails At Rock Creek 12502 Seattle Slew 656 Bristol Place 11245 West Rd. 390 Meadowlands 12424 Steeple Way Blvd. 192 Sugar Creek 11501 West Rd. 288 Sprucewood 12200 Steeple Way Blvd. 152 Unidentified Steepleway Blvd. and Thoroughbred Dr. 104 Steepleway Downs 11910 Thoroughbred Dr. 224 Unidentified Thoroughbred Dr. and Saville Ln. 64 Unidentified Saville Ln. and Castlebridge Dr. 96 Falls At Copper Lake 9140 Highway 6 North 374 Villas At Huffmeister 15050 Copper Grove Blvd. 294 Villa Toscana 9125 Highway 6 576 Lodge At Copperfield 15125 West Rd. 96 Villages of Copperfield 8727 Point Park Dr. 964 Landmark At Cypress Falls 15511 Tuckerton Dr. 312 Austin Area Unidentified complex Misty Slope Ln. and Lovely Ln. 100 Bluff Springs Townhomes 7100 Bluff Springs Rd. 104 Waters At Bluff Springs 7707 South IH-35 304 Circle S Apartments 7201 South Congress Ave. 200 Unidentified complex S Congress Ave. between Olguin St. and W Dittmar Rd. 8 Unidentified complex S Congress Ave. between Olguin St. and W Dittmar Rd. 4 Villages of Bella Vista 8515 Brodie Ln. 402 Ridgeview Apartments 8600 Brodie Ln. 336 Camden Stoneleigh 4825 Davis Ln. 432 Legacy at Western Oaks 8801 La Cresada Dr. 479 Unidentified complex Davis Ln. and Beckett Rd. 4 <<>> Table 4.1.1-2 Population within the Zone of Potential Impact of Proposed Project by MP Segment Mile Segment Single-Family Units Multi-Family Units County Persons Per Household Estimated Population From To 0.0 1.0 277 0 Harris 2.79 773 1.0 2.0 342 20 Harris 2.79 1,010 2.0 3.0 547 0 Harris 2.79 1,526 3.0 4.0 248 0 Harris 2.79 692 4.0 5.0 14 0 Harris 2.79 39 5.0 6.0 140 0 Harris 2.79 391 6.0 7.0 33 0 Harris 2.79 92 7.0 8.0 22 0 Harris 2.79 61 8.0 9.0 71 0 Harris 2.79 198 3.0 4.0 32 0 Harris 2.79 89 4.0 5.0 29 0 Harris 2.79 81 5.0 6.0 138 0 Harris 2.79 385 6.0 7.0 18 0 Harris 2.79 50 7.0 8.0 96 0 Harris 2.79 268 8.0 9.0 190 0 Harris 2.79 530 9.0 10.0 208 0 Harris 2.79 580 10.0 11.0 226 0 Harris 2.79 631 11.0 12.0 467 684 Harris 2.79 3,211 12.0 13.0 1,028 359 Harris 2.79 3,870 13.0 14.0 1,368 7 Harris 2.79 3,836 14.0 15.0 1,657 34 Harris 2.79 4,718 15.0 16.0 704 0 Harris 2.79 1,964 16.0 17.0 1,425 0 Harris 2.79 3,976 17.0 18.0 771 0 Harris 2.79 2,151 18.0 19.0 602 0 Harris 2.79 1,680 19.0 20.0 817 0 Harris 2.79 2,279 20.0 21.0 885 14 Harris 2.79 2,508 21.0 22.0 1,422 0 Harris 2.79 3,967 22.0 23.0 1,678 168 Harris 2.79 5,150 23.0 24.0 727 0 Harris 2.79 2,028 24.0 25.0 551 712 Harris 2.79 3,524 25.0 26.0 969 72 Harris 2.79 2,904 26.0 27.0 353 1 Harris 2.79 988 27.0 28.0 713 0 Harris 2.79 1,989 28.0 29.0 451 16 Harris 2.79 1,303 29.0 30.0 347 336 Harris 2.79 1,906 30.0 31.0 1,118 640 Harris 2.79 4,905 31.0 32.0 708 1,526 Harris 2.79 6,233 <<>> Table 4.1.1-2 Population within the Zone of Potential Impact by MP Segment (continued) Mile Segment Single-Family Units Multi-Family Units County Persons Per Household Estimated Population From To 32.0 33.0 274 2,202 Harris 2.79 6,908 33.0 34.0 139 0 Harris 2.79 388 34.0 35.0 9 1,244 Harris 2.79 3,496 35.0 36.0 2,679 1,372 Harris 2.79 11,302 36.0 37.0 2,174 0 Harris 2.79 6,065 37.0 38.0 1,282 0 Harris 2.79 3,577 38.0 39.0 280 0 Harris 2.79 781 39.0 40.0 192 0 Harris 2.79 536 40.0 41.0 0 0 Harris 2.79 0 41.0 42.0 0 0 Harris 2.79 0 42.0 43.0 0 0 Harris 2.79 0 43.0 44.0 3 0 Harris 2.79 8 44.0 45.0 0 0 Harris 2.79 0 45.0 46.0 0 0 Harris 2.79 0 46.0 47.0 0 0 Harris 2.79 0 47.0 48.0 0 0 Harris 2.79 0 48.0 49.0 0 0 Harris 2.79 0 49.0 50.0 0 0 Harris 2.79 0 28,491 9,407 Harris Total 105,735 50.0 51.0 0 0 Waller 2.79 0 51.0 52.0 0 0 Waller 2.79 0 52.0 53.0 0 0 Waller 2.79 0 53.0 54.0 0 0 Waller 2.79 0 54.0 55.0 0 0 Waller 2.79 0 55.0 56.0 6 0 Waller 2.79 17 56.0 57.0 2 0 Waller 2.79 6 57.0 58.0 6 0 Waller 2.79 17 58.0 59.0 7 0 Waller 2.79 20 59.0 60.0 4 0 Waller 2.79 11 60.0 61.0 0 0 Waller 2.79 0 61.0 62.0 1 0 Waller 2.79 3 62.0 63.0 0 0 Waller 2.79 0 63.0 64.0 2 0 Waller 2.79 6 28 0 Waller Total 78 64.0 65.0 2 0 Austin 2.67 5 65.0 66.0 12 0 Austin 2.67 32 66.0 67.0 3 0 Austin 2.67 8 67.0 68.0 8 0 Austin 2.67 21 68.0 69.0 14 0 Austin 2.67 37 69.0 70.0 11 0 Austin 2.67 29 70.0 71.0 1 0 Austin 2.67 3 <<>> Table 4.1.1-2 Population within the Zone of Potential Impact by MP Segment (continued) Mile Segment Single-Family Units Multi-Family Units County Persons Per Household Estimated Population From To 71.0 72.0 3 0 Austin 2.67 8 72.0 73.0 7 0 Austin 2.67 19 73.0 74.0 2 0 Austin 2.67 5 74.0 75.0 34 0 Austin 2.67 91 75.0 76.0 36 0 Austin 2.67 96 76.0 77.0 12 0 Austin 2.67 32 77.0 78.0 1 0 Austin 2.67 3 78.0 79.0 0 0 Austin 2.67 0 79.0 80.0 7 0 Austin 2.67 19 80.0 81.0 5 0 Austin 2.67 13 81.0 82.0 1 0 Austin 2.67 3 82.0 83.0 7 0 Austin 2.67 19 83.0 84.0 10 0 Austin 2.67 27 84.0 85.0 10 0 Austin 2.67 27 85.0 86.0 3 0 Austin 2.67 8 86.0 87.0 7 0 Austin 2.67 19 87.0 88.0 7 0 Austin 2.67 19 88.0 89.0 4 0 Austin 2.67 11 89.0 90.0 4 0 Austin 2.67 11 90.0 91.0 2 0 Austin 2.67 5 91.0 92.0 5 0 Austin 2.67 13 92.0 93.0 5 0 Austin 2.67 13 93.0 94.0 20 0 Austin 2.67 53 243 0 Austin Total 649 94.0 95.0 3 0 Fayette 2.44 7 95.0 96.0 3 0 Fayette 2.44 7 96.0 97.0 5 0 Fayette 2.44 12 97.0 98.0 4 0 Fayette 2.44 10 98.0 99.0 1 0 Fayette 2.44 2 99.0 100.0 4 0 Fayette 2.44 10 100.0 101.0 13 0 Fayette 2.44 32 101.0 102.0 15 0 Fayette 2.44 37 102.0 103.0 13 0 Fayette 2.44 32 103.0 104.0 1 0 Fayette 2.44 2 104.0 105.0 5 0 Fayette 2.44 12 105.0 106.0 2 0 Fayette 2.44 5 106.0 107.0 5 0 Fayette 2.44 12 107.0 108.0 4 0 Fayette 2.44 10 108.0 109.0 2 0 Fayette 2.44 5 109.0 110.0 4 0 Fayette 2.44 10 110.0 111.0 2 0 Fayette 2.44 5 <<>> Table 4.1.1-2 Population within the Zone of Potential Impact by MP Segment (continued) Mile Segment Single-Family Units Multi-Family Units County Persons Per Household Estimated Population From To 111.0 112.0 3 0 Fayette 2.44 7 112.0 113.0 6 0 Fayette 2.44 15 113.0 114.0 4 0 Fayette 2.44 10 114.0 115.0 3 0 Fayette 2.44 7 115.0 116.0 4 0 Fayette 2.44 10 116.0 117.0 1 0 Fayette 2.44 2 107 0 Fayette Total 261 117.0 118.0 2 0 Lee 2.65 5 118.0 119.0 3 0 Lee 2.65 8 5 0 Lee Total 13 119.0 120.0 6 0 Fayette 2.44 15 6 0 Fayette Total 15 120.0 121.0 Bastrop 2.77 0 121.0 122.0 4 0 Bastrop 2.77 11 122.0 123.0 3 0 Bastrop 2.77 8 123.0 124.0 46 0 Bastrop 2.77 127 124.0 125.0 9 0 Bastrop 2.77 25 125.0 126.0 18 0 Bastrop 2.77 50 126.0 127.0 1 0 Bastrop 2.77 3 127.0 128.0 1 0 Bastrop 2.77 3 128.0 129.0 2 0 Bastrop 2.77 6 129.0 130.0 18 0 Bastrop 2.77 50 130.0 131.0 10 0 Bastrop 2.77 28 131.0 132.0 1 0 Bastrop 2.77 3 132.0 133.0 19 0 Bastrop 2.77 53 133.0 134.0 18 0 Bastrop 50 134.0 135.0 30 0 Bastrop 2.77 94 135.0 136.0 0 4 Bastrop 2.77 0 136.0 137.0 0 0 Bastrop 137.0 138.0 0 0 Bastrop 138.0 139.0 1 0 Bastrop 139.0 140.0 5 0 Bastrop 2.77 14 2.77 0 2.77 0 2.77 3 2.77 140.0 141.0 2 0 Bastrop 2.77 6 141.0 142.0 5 0 Bastrop 2.77 14 142.0 143.0 14 0 Bastrop 2.77 39 143.0 144.0 27 0 Bastrop 2.77 75 144.0 145.0 31 0 Bastrop 2.77 86 145.0 146.0 40 0 Bastrop 2.77 111 146.0 147.0 20 0 Bastrop 2.77 55 147.0 148.0 31 0 Bastrop 2.77 86 148.0 149.0 10 0 Bastrop 2.77 28 <<>> Table 4.1.1-2 Population within the Zone of Potential Impact by MP Segment (continued) Mile Segment Single-Family Units Multi-Family Units County Persons Per Household Estimated Population From To 149.0 150.0 0 0 Bastrop 2.77 0 150.0 151.0 1 0 Bastrop 2.77 3 151.0 152.0 1 0 Bastrop 2.77 3 152.0 153.0 95 0 Bastrop 2.77 263 153.0 154.0 175 0 Bastrop 2.77 485 638 4 Bastrop Total 1,778 154.0 155.0 73 0 Travis 2.47 180 155.0 156.0 2 0 Travis 2.47 5 156.0 157.0 9 0 Travis 2.47 22 157.0 158.0 33 0 Travis 2.47 82 158.0 159.0 148 0 Travis 2.47 366 159.0 160.0 25 0 Travis 2.47 62 160.0 161.0 100 0 Travis 2.47 247 161.0 162.0 22 0 Travis 2.47 54 162.0 163.0 6 0 Travis 2.47 15 163.0 164.0 109 0 Travis 2.47 269 164.0 165.0 606 100 Travis 2.47 1,744 165.0 166.0 756 408 Travis 2.47 2,875 166.0 167.0 295 212 Travis 2.47 1,252 167.0 168.0 520 0 Travis 2.47 1,284 168.0 169.0 622 0 Travis 2.47 1,536 169.0 170.0 835 0 Travis 2.47 2,062 170.0 171.0 342 738 Travis 2.47 2,668 171.0 172.0 634 911 Travis 2.47 3,816 172.0 173.0 805 4 Travis 2.47 1,998 173.0 174.0 267 0 Travis 2.47 659 174.0 175.0 99 0 Travis 2.47 245 175.0 176.0 41 0 Travis 2.47 101 176.0 177.0 50 0 Travis 2.47 124 177.0 178.0 47 0 Travis 2.47 116 178.0 179.0 14 0 Travis 2.47 35 179.0 180.0 55 0 Travis 2.47 136 180.0 181.0 39 0 Travis 2.47 96 6,554 2,373 Travis Total 22,050 181.0 182.0 30 0 Hays 2.69 81 182.0 183.0 65 0 Hays 2.69 175 183.0 184.0 34 0 Hays 2.69 91 184.0 185.0 6 0 Hays 2.69 16 185.0 186.0 10 0 Hays 2.69 27 186.0 187.0 11 0 Hays 2.69 30 187.0 188.0 14 0 Hays 2.69 38 <<>> Table 4.1.1-2 Population within the Zone of Potential Impact by MP Segment (continued) Mile Segment Single-Family Units Multi-Family Units County Persons Per Household Estimated Population From To 188.0 189.0 13 0 Hays 2.69 35 189.0 190.0 29 0 Hays 2.69 78 190.0 191.0 5 0 Hays 2.69 13 191.0 192.0 5 0 Hays 2.69 13 192.0 193.0 5 0 Hays 2.69 13 227 0 Hays Total 611 193.0 194.0 8 0 Blanco 2.50 20 194.0 195.0 0 0 Blanco 2.50 0 195.0 196.0 0 0 Blanco 2.50 0 196.0 197.0 0 0 Blanco 2.50 0 197.0 198.0 1 0 Blanco 2.50 3 198.0 199.0 1 0 Blanco 2.50 3 199.0 200.0 0 0 Blanco 2.50 0 200.0 201.0 0 0 Blanco 2.50 0 201.0 202.0 0 0 Blanco 2.50 0 202.0 203.0 2 0 Blanco 2.50 5 203.0 204.0 4 0 Blanco 2.50 10 204.0 205.0 3 0 Blanco 2.50 8 205.0 206.0 0 0 Blanco 2.50 0 206.0 207.0 0 0 Blanco 2.50 0 207.0 208.0 0 0 Blanco 2.50 0 208.0 209.0 0 0 Blanco 2.50 0 209.0 210.0 4 0 Blanco 2.50 10 210.0 211.0 0 0 Blanco 2.50 0 211.0 212.0 2 0 Blanco 2.50 5 212.0 213.0 0 0 Blanco 2.50 0 213.0 214.0 2 0 Blanco 2.50 5 214.0 215.0 0 0 Blanco 2.50 0 215.0 216.0 0 0 Blanco 2.50 0 216.0 217.0 0 0 Blanco 2.50 0 217.0 218.0 0 0 Blanco 2.50 0 27 0 Blanco Total 68 218.0 219.0 0 0 Gillespie 2.38 0 219.0 220.0 2 0 Gillespie 2.38 5 220.0 221.0 0 0 Gillespie 2.38 0 221.0 222.0 0 0 Gillespie 2.38 0 222.0 223.0 1 0 Gillespie 2.38 2 223.0 224.0 0 0 Gillespie 2.38 0 224.0 225.0 1 0 Gillespie 2.38 2 225.0 226.0 1 0 Gillespie 2.38 2 226.0 227.0 3 0 Gillespie 2.38 7 <<>> Table 4.1.1-2 Population within the Zone of Potential Impact by MP Segment (continued) Mile Segment Single-Family Units Multi-Family Units County Persons Per Household Estimated Population From To 227.0 228.0 1 0 Gillespie 2.38 2 228.0 229.0 1 0 Gillespie 2.38 2 229.0 230.0 0 0 Gillespie 2.38 0 230.0 231.0 0 0 Gillespie 2.38 0 231.0 232.0 1 0 Gillespie 2.38 2 232.0 233.0 3 0 Gillespie 2.38 7 233.0 234.0 1 0 Gillespie 2.38 2 234.0 235.0 1 0 Gillespie 2.38 2 235.0 236.0 2 0 Gillespie 2.38 5 236.0 237.0 0 0 Gillespie 2.38 0 237.0 238.0 0 0 Gillespie 2.38 0 238.0 239.0 1 0 Gillespie 2.38 2 239.0 240.0 0 0 Gillespie 2.38 0 240.0 241.0 7 0 Gillespie 2.38 17 26 0 Gillespie Total 62 241.0 242.0 2 0 Llano 2.13 4 2 0 Llano Total 4 242.0 243.0 0 0 Mason 2.31 0 243.0 244.0 0 0 Mason 2.31 0 244.0 245.0 1 0 Mason 2.31 2 245.0 246.0 1 0 Mason 2.31 2 246.0 247.0 0 0 Mason 2.31 0 247.0 248.0 0 0 Mason 2.31 0 248.0 249.0 0 0 Mason 2.31 0 249.0 250.0 1 0 Mason 2.31 2 250.0 251.0 0 0 Mason 2.31 0 251.0 252.0 0 0 Mason 2.31 0 252.0 253.0 2 0 Mason 2.31 5 253.0 254.0 0 0 Mason 2.31 0 254.0 255.0 0 0 Mason 2.31 0 255.0 256.0 0 0 Mason 2.31 0 256.0 257.0 0 0 Mason 2.31 0 257.0 258.0 1 0 Mason 2.31 2 258.0 259.0 0 0 Mason 2.31 0 259.0 260.0 0 0 Mason 2.31 0 260.0 261.0 0 0 Mason 2.31 0 261.0 262.0 0 0 Mason 2.31 0 262.0 263.0 0 0 Mason 2.31 0 263.0 264.0 1 0 Mason 2.31 2 264.0 265.0 0 0 Mason 2.31 0 265.0 266.0 0 0 Mason 2.31 0 <<>> Table 4.1.1-2 Population within the Zone of Potential Impact by MP Segment (continued) Mile Segment Single-Family Units Multi-Family Units County Persons Per Household Estimated Population From To 266.0 267.0 0 0 Mason 2.31 0 267.0 268.0 1 0 Mason 2.31 2 268.0 269.0 0 0 Mason 2.31 0 269.0 270.0 0 0 Mason 2.31 0 270.0 271.0 0 0 Mason 2.31 0 271.0 272.0 0 0 Mason 2.31 0 272.0 273.0 2 0 Mason 2.31 5 273.0 274.0 1 0 Mason 2.31 2 11 0 Mason Total 25 274.0 275.0 0 0 Kimble 2.37 0 275.0 276.0 0 0 Kimble 2.37 0 276.0 277.0 3 0 Kimble 2.37 7 277.0 278.0 0 0 Kimble 2.37 0 278.0 279.0 0 0 Kimble 2.37 0 279.0 280.0 0 0 Kimble 2.37 0 280.0 281.0 2 0 Kimble 2.37 5 281.0 282.0 0 0 Kimble 2.37 0 282.0 283.0 0 0 Kimble 2.37 0 283.0 284.0 0 0 Kimble 2.37 0 284.0 285.0 0 0 Kimble 2.37 0 285.0 286.0 0 0 Kimble 2.37 0 286.0 287.0 1 0 Kimble 2.37 2 287.0 288.0 3 0 Kimble 2.37 7 288.0 289.0 2 0 Kimble 2.37 5 289.0 290.0 0 0 Kimble 2.37 0 290.0 291.0 1 0 Kimble 2.37 2 291.0 292.0 0 0 Kimble 2.37 0 292.0 293.0 1 0 Kimble 2.37 2 293.0 294.0 0 0 Kimble 2.37 0 294.0 295.0 0 0 Kimble 2.37 0 295.0 296.0 0 0 Kimble 2.37 0 296.0 297.0 0 0 Kimble 2.37 0 297.0 298.0 0 0 Kimble 2.37 0 298.0 299.0 1 0 Kimble 2.37 2 299.0 300.0 0 0 Kimble 2.37 0 300.0 301.0 0 0 Kimble 2.37 0 301.0 302.0 0 0 Kimble 2.37 0 302.0 303.0 0 0 Kimble 2.37 0 303.0 304.0 0 0 Kimble 2.37 0 304.0 305.0 0 0 Kimble 2.37 0 305.0 306.0 1 0 Kimble 2.37 2 <<>> Table 4.1.1-2 Population within the Zone of Potential Impact by MP Segment (continued) Mile Segment Single-Family Units Multi-Family Units County Persons Per Household Estimated Population From To 306.0 307.0 1 0 Kimble 2.37 2 307.0 308.0 0 0 Kimble 2.37 0 308.0 309.0 0 0 Kimble 2.37 0 309.0 310.0 1 0 Kimble 2.37 2 17 0 Kimble Total 40 310.0 311.0 1 0 Menard 2.34 2 311.0 312.0 0 0 Menard 2.34 0 312.0 313.0 0 0 Menard 2.34 0 1 0 Menard Total 2 313.0 314.0 0 0 Schleicher 2.59 0 314.0 315.0 1 0 Schleicher 2.59 3 315.0 316.0 0 0 Schleicher 2.59 0 316.0 317.0 0 0 Schleicher 2.59 0 317.0 318.0 0 0 Schleicher 2.59 0 318.0 319.0 0 0 Schleicher 2.59 0 319.0 320.0 0 0 Schleicher 2.59 0 320.0 321.0 0 0 Schleicher 2.59 0 321.0 322.0 0 0 Schleicher 2.59 0 322.0 323.0 0 0 Schleicher 2.59 0 323.0 324.0 0 0 Schleicher 2.59 0 324.0 325.0 0 0 Schleicher 2.59 0 325.0 326.0 1 0 Schleicher 2.59 3 326.0 327.0 0 0 Schleicher 2.59 0 327.0 328.0 2 0 Schleicher 2.59 5 328.0 329.0 1 0 Schleicher 2.59 3 329.0 330.0 2 0 Schleicher 2.59 5 330.0 331.0 3 0 Schleicher 2.59 8 331.0 332.0 0 0 Schleicher 2.59 0 332.0 333.0 0 0 Schleicher 2.59 0 333.0 334.0 0 0 Schleicher 2.59 0 334.0 335.0 1 0 Schleicher 2.59 3 335.0 336.0 0 0 Schleicher 2.59 0 336.0 337.0 0 0 Schleicher 2.59 0 337.0 338.0 0 0 Schleicher 2.59 0 338.0 339.0 0 0 Schleicher 2.59 0 339.0 340.0 1 0 Schleicher 2.59 3 340.0 341.0 0 0 Schleicher 2.59 0 341.0 342.0 0 0 Schleicher 2.59 0 342.0 343.0 2 0 Schleicher 2.59 5 343.0 344.0 0 0 Schleicher 2.59 0 344.0 345.0 1 0 Schleicher 2.59 3 <<>> Table 4.1.1-2 Population within the Zone of Potential Impact by MP Segment (continued) Mile Segment Single-Family Units Multi-Family Units County Persons Per Household Estimated Population From To 345.0 346.0 1 0 Schleicher 2.59 3 346.0 347.0 2 0 Schleicher 2.59 5 347.0 348.0 6 0 Schleicher 2.59 16 348.0 349.0 0 0 Schleicher 2.59 0 349.0 350.0 0 0 Schleicher 2.59 0 350.0 351.0 2 0 Schleicher 2.59 5 351.0 352.0 0 0 Schleicher 2.59 0 352.0 353.0 0 0 Schleicher 2.59 0 353.0 354.0 0 0 Schleicher 2.59 0 354.0 355.0 0 0 Schleicher 2.59 0 355.0 356.0 0 0 Schleicher 2.59 0 356.0 357.0 1 0 Schleicher 2.59 3 357.0 358.0 0 0 Schleicher 2.59 0 358.0 359.0 1 0 Schleicher 2.59 3 359.0 360.0 3 0 Schleicher 2.59 8 360.0 361.0 0 0 Schleicher 2.59 0 361.0 362.0 0 0 Schleicher 2.59 0 362.0 363.0 0 0 Schleicher 2.59 0 363.0 364.0 0 0 Schleicher 2.59 0 364.0 365.0 0 0 Schleicher 2.59 0 365.0 366.0 0 0 Schleicher 2.59 0 31 0 Schleicher Total 80 366.0 367.0 0 0 Crockett 2.65 0 367.0 368.0 0 0 Crockett 2.65 0 368.0 369.0 0 0 Crockett 2.65 0 369.0 370.0 0 0 Crockett 2.65 0 370.0 371.0 0 0 Crockett 2.65 0 371.0 372.0 0 0 Crockett 2.65 0 372.0 373.0 0 0 Crockett 2.65 0 373.0 374.0 0 0 Crockett 2.65 0 374.0 375.0 0 0 Crockett 2.65 0 375.0 376.0 0 0 Crockett 2.65 0 376.0 377.0 0 0 Crockett 2.65 0 377.0 378.0 0 0 Crockett 2.65 0 378.0 379.0 0 0 Crockett 2.65 0 379.0 380.0 0 0 Crockett 2.65 0 380.0 381.0 0 0 Crockett 2.65 0 381.0 382.0 0 0 Crockett 2.65 0 382.0 383.0 0 0 Crockett 2.65 0 383.0 384.0 0 0 Crockett 2.65 0 384.0 385.0 0 0 Crockett 2.65 0 <<>> Table 4.1.1-2 Population within the Zone of Potential Impact by MP Segment (continued) Mile Segment Single-Family Units Multi-Family Units County Persons Per Household Estimated Population From To 385.0 386.0 0 0 Crockett 2.65 0 386.0 387.0 0 0 Crockett 2.65 0 387.0 388.0 0 0 Crockett 2.65 0 388.0 389.0 0 0 Crockett 2.65 0 389.0 390.0 0 0 Crockett 2.65 0 390.0 391.0 0 0 Crockett 2.65 0 391.0 392.0 0 0 Crockett 2.65 0 0 0 Crockett Total 0 392.0 393.0 Reagan 2.96 0 393.0 394.0 0 0 Reagan 2.96 0 394.0 395.0 0 0 Reagan 2.96 0 395.0 396.0 0 0 Reagan 2.96 0 396.0 397.0 0 0 Reagan 2.96 0 397.0 398.0 0 0 Reagan 2.96 0 398.0 399.0 1 0 Reagan 2.96 3 399.0 400.0 0 0 Reagan 2.96 0 400.0 401.0 0 0 Reagan 2.96 0 401.0 402.0 0 0 Reagan 2.96 0 402.0 403.0 0 0 Reagan 2.96 0 403.0 404.0 0 0 Reagan 2.96 0 404.0 405.0 0 0 Reagan 2.96 0 405.0 406.0 1 0 Reagan 2.96 3 406.0 407.0 0 0 Reagan 2.96 0 407.0 408.0 0 0 Reagan 2.96 0 408.0 409.0 0 0 Reagan 2.96 0 409.0 410.0 0 0 Reagan 2.96 0 410.0 411.0 0 0 Reagan 2.96 0 411.0 412.0 0 0 Reagan 2.96 0 412.0 413.0 0 0 Reagan 2.96 0 413.0 414.0 0 0 Reagan 2.96 0 414.0 415.0 0 0 Reagan 2.96 0 415.0 416.0 0 0 Reagan 2.96 0 416.0 417.0 0 0 Reagan 2.96 0 417.0 418.0 0 0 Reagan 2.96 0 418.0 419.0 0 0 Reagan 2.96 0 419.0 420.0 0 0 Reagan 2.96 0 2 0 Reagan Total 6 420.0 421.0 0 0 Upton 2.68 0 421.0 422.0 0 0 Upton 2.68 0 422.0 423.0 0 0 Upton 2.68 0 423.0 424.0 0 0 Upton 2.68 0 <<>> Table 4.1.1-2 Population within the Zone of Potential Impact by MP Segment (continued) Mile Segment Single-Family Units Multi-Family Units County Persons Per Household Estimated Population From To 424.0 425.0 0 0 Upton 2.68 0 425.0 426.0 0 0 Upton 2.68 0 426.0 427.0 0 0 Upton 2.68 0 427.0 428.0 0 0 Upton 2.68 0 428.0 429.0 0 0 Upton 2.68 0 429.0 430.0 0 0 Upton 2.68 0 430.0 431.0 0 0 Upton 2.68 0 431.0 432.0 0 0 Upton 2.68 0 432.0 433.0 0 0 Upton 2.68 0 433.0 434.0 0 0 Upton 2.68 0 434.0 435.0 0 0 Upton 2.68 0 435.0 436.0 0 0 Upton 2.68 0 436.0 437.0 0 0 Upton 2.68 0 437.0 438.0 0 0 Upton 2.68 0 438.0 439.0 0 0 Upton 2.68 0 439.0 440.0 0 0 Upton 2.68 0 440.0 441.0 0 0 Upton 2.68 0 441.0 442.0 0 0 Upton 2.68 0 442.0 443.0 0 0 Upton 2.68 0 443.0 444.0 0 0 Upton 2.68 0 444.0 445.0 0 0 Upton 2.68 0 445.0 446.0 0 0 Upton 2.68 0 446.0 447.0 0 0 Upton 2.68 0 447.0 448.0 0 0 Upton 2.68 0 448.0 449.0 0 0 Upton 2.68 0 449.0 450.0 0 0 Upton 2.68 0 450.0 451.0 0 0 Upton 2.68 0 451.0 452.0 0 0 Upton 2.68 0 452.0 453.0 0 0 Upton 2.68 0 453.0 454.0 0 0 Upton 2.68 0 0 0 Upton Total 0 454.0 455.0 0 0 Crane 2.91 0 455.0 456.0 0 0 Crane 2.91 0 456.0 457.0 0 0 Crane 2.91 0 Crane Total 0 Grand Total 131,477 <<>> Table 4.1.2-1 Vulnerable Receptors within the Zone of Potential Impact of the Proposed Project in the Houston Area Facility Approximate Location Public Schools Kipp North Forest Lower School 9634 Mesa Rd. Kipp Voyage Academy for Girls 10711 Kipp Way Kipp Legacy Preparatory School 10711 Kipp Way Kipp Polaris Academy for Boys 10711 Kipp Way Kipp North Forest Lower Girls School 10711 Kipp Way Kirby Middle School 9709 Mesa Dr. Yes Prep North Forest Campus 9709 Mesa Dr. W.E. Rogers Elementary School 10550 James L. Reaux Dr. Fonwood Elementary School 10710 Seneca St. Scarborough Elementary School 3021 Little York Rd. Texas Serenity Academy 530 N Sam Houston parkway, Suite 213 Carroll Academy 423 W Gulfbank Rd. Keeble EC/Pre-K Center 203 W Gulfbank Rd. Eiland Elementary School 6700 N Klein Circle Dr. Klein Intermediate 4710 W Mount Houston Rd. Labay Middle School 15435 Willow River Dr. Nitsch Elementary School 4702 W Mount Houston Rd. Ralph G. Goodman Elementary School 9325 Deer Trail Dr. Fiest Elementary School 8425 Pine Falls Bang Elementary School 8900 Rio Grande Gleason Elementary School 9202 Willowbridge Park Blvd. Cypress Fall High School 9811 Huffmeister Rd. Rennell Elementary School 19500 Tuckerton Blvd. Eisenhower Ninth Grade School 3550 West Gulf Bank Rd. Cook Middle School 9811 Huffmeister Rd. Reed Elementary School 8700 Tami Renee Eisenhower Senior High School 7922 Antoine Dr. Worsham Elementary School 3007 Hartwick Rd. B.C. Elmore Middle School 8200 Tate Pyburn Elementary School 12302 Coulson St. Private Schools Northeast Christian School 7300 Langley Rd. Sandcastle Montessori Academy 15226 West Rd. Cypress Montessori School 9507 Huffmeister Rd. Leading Stars Montessori School 15330 Willow River Dr. Woodland Acres Christian School 12338 Coulson St. Healthcare Facilities Houston Community Hospital (St. Anthony’s) Parks <<>> Table 4.1.2-1 Vulnerable Receptors within the Zone of Potential Impact in the Houston Area (continued) Facility Approximate Location Clark Henry Park Equador St. north of Jersey Dr. Groveland Terrace Park 3921 Herald St. Circle Drive Park Circle Dr. at US 90 Smith Park Smith Park Rd. and Market Street Rd. Stuebner-Airline Park 9201 Veterans Memorial Dr. West Mount Houston Park 10300 N. Houston Rosslyn Rd. Pinewood Village Park 2800 Briarwick Ln. Withers Park 10400 Royal Pine Dr. Keith Wiess Park 12300 Aldine Westfield Rd. Gleason Park 7200 Gleason Rd. Lake Forest Park Lake Park St. and E Houston Dyersdale Rd. Scenic Woods Park Gleason Rd. and Cheeves Dr. Tidwell Park 9720 Spaulding St. Hirsch Road Park 10800 Hirsch Rd. Brock Park 8201 John Ralston Rd. Strickland Park 300 High Ridge St. Cool Green Corridor 12800 Coolgreen Ave. Herman Brown Park 400 Mercury Dr. Circle Drive Park 90 Circle Dr. Cullen Park 19008 Saums Rd. East Tidwell Park 9300 E. Tidwell Rd. Halls Bayou Park 8000 Tidwell Rd. Langham Creek Park 9701 Barker Cypress Rd James Driver Park 10918 ½ Bentley St. Paul D. Rushing Park 9114 Katy Hockley Rd. Ella Hike and Bike Trail 8700 Ella Blvd. John Paul's Landing Katy Hockley Cutoff Other Recreational Facilities Texaco Country Club 12800 Texaco Road Houston National Golf Club 16500 Houston National Blvd. Hearthstone Country Club 7615 Ameswood <<>> Table 4.1.2-2 Vulnerable Receptors within the Zone of Potential Impact of the Proposed Project in the Austin Area Facility Location Public Schools Texas Neurorehabilitation Center Campus 1106 W Dittmar Rd. Langford Elementary School 2206 Blue Meadow Dr. Boone Elementary School 8101 Croftwood Dr. Williams Elementary School 500 Mairo Private Schools Legacy Oaks Christian School 7915 Manchaca Rd. Hospitals Texas Neurorehabilitation Center 1106 W Dittmar Rd. Parks Dick Nichols Park 8011 Beckett Rd. McKinney Falls State Park 5808 McKinney Falls Parkway Circle C Ranch Metropolitan Park 6301 W. Slaughter Ln. Goat Cave Karst Nature Preserve 3900 Deer Ln. Davis Hill Neighborhood Park 3402 Davis Ln. Dittmar Park and Recreation Center 1009 W. Dittmar Rd. South Boggy Creek Greenbelt 7701 Circle S Rd. Onion Creek Greenbelt 7004 Onion Creek Dr. Richard Moya Park 10001 Burleson Rd. Onion Creek Soccer Complex 5600 E. William Cannon Other Recreational Facilities Jimmy Clay Golf Course 5400 Jimmy Clay Dr. <<>> Table 4.2.1-1 Aquifers Within the Zone of Potential Impact of the Proposed Project Aquifer Age Lithology TWDB Designation Gulf Coast Aquifer System Quaternary- Tertiary Sand, silt clay, and gravel Major Aquifer Brazos River Alluvium Aquifer Quaternary Unconsolidated alluvium including sand, gravel, with interbedded silts and clays Minor Aquifer Yegua-Jackson Aquifer Tertiary Complexly interbedded sand, silt and clay Minor Aquifer Sparta Aquifer Tertiary Interbedded sands and clays Minor Aquifer Queen City Aquifer Tertiary Sand, loosely cemented sandstone with interbedded clay Minor Aquifer Carrizo-Wilcox Aquifer System Tertiary Sand, sandstone, clay, silt, lignite, gravel Major Aquifer Colorado River Alluvium Quaternary Unconsolidated alluvium, terrace and high gravel deposits including sand, gravel, with interbedded silts and clays Other1 Edwards Aquifer-Barton Springs Segment Cretaceous Solutioned and fractured limestones and dolomites Major Trinity Aquifer-Hill Country Cretaceous Upper and Middle are solutioned and fractured limestones and dolomites, Lower is sand, gravel, and conglomerate with interbedded clay Major Marble Falls Aquifer Pennsylvanian Solutioned, faulted and fractured limestones and dolomites Minor Ellenburger-San Saba Aquifer Cambrian - Ordovician Solutioned, faulted and fractured limestones and dolomites Minor Hickory Aquifer Cambrian Fractured and faulted sandstone, medium to coarse grained Minor Edwards-Trinity (Plateau) Aquifer Cretaceous Solutioned and jointed limestone, dolomite and sandstones Major Pecos Valley Aquifer Quaternary- Tertiary Discontinuous alluvium, lacustrine, eolian and valley fill deposits of sand, silt, conglomerate, limestone, mudstone, shale and gypsum Major Southern Ogallala Aquifer Quaternary- Tertiary Fluvial, lacustrine and eolian deposits of sand, gravel, silt and clay Major Source: Texas Water Development Board Note: 1 – Not designated as a Major or Minor Aquifer by the Texas Water Development Board <<>> Table 4.2.1-2 TCEQ Aquifer Average DRASTIC Index and Vulnerability Ranking of Aquifers within the Zone of Potential Impact of the Proposed Project Major Aquifers Average DRASTIC Index Vulnerability Ranking Gulf Coast 95 Medium Carrizo-Wilcox 117 Medium Edwards (BFZ)-Barton Springs 126 High Trinity (Hill Country) 95 Medium Edwards-Trinity (Plateau) 107 Medium Pecos Valley 95 Medium Southern Ogallala 99 Medium Minor Aquifers Average DRASTIC Index Vulnerability Ranking Brazos River Alluvium 144 High Yegua-Jackson1 108 Medium Sparta 98 Medium Queen City 108 Medium Marble Falls 126 High Ellenberger-San Saba 126 High Hickory 114 Medium Other Aquifers Average DRASTIC Index Vulnerability Ranking Colorado River Alluvium2 144 High 1 -- Average DRASTIC Index and Vulnerability Ranking was not available; index and ranking determination based on most conservative value for the Sparta and Queen City aquifers which are geologically similar to the Yegua-Jackson Aquifer. 2 -- Average DRASTIC Index and Vulnerability Ranking was not available; index and ranking determination based on Brazos River Alluvium Aquifer which is geologically similar to the Colorado River Alluvium Aquifer. <<>> Table 4.2.1-3 Pettyjohn et. al. Aquifer Classification and Vulnerability of Aquifers Within the Zone of Potential Impact of the Proposed Project Major Aquifers Pettyjohn et. al. Classification Rationale Vulnerability Gulf Coast Class Ia, Ic and Class U Classes Ia & Ic where sands of Lissie and Oakville formations outcrop, respectively; Class U where Beaumont and Cataholu formations outcrop High – All Class I Medium – Class U Carrizo-Wilcox - Outcrop Class Ic Sandstone, sand and gravel outcrops of the Carrizo Formation and Wilcox Group High Carrizo-Wilcox - Subcrop Class III Overlain by more than 50 feet of low permeability strata of the Reklaw Formation Low Edwards (BFZ)-Barton Springs - Outcrop Class Ib Outcropping limestone, dolomite and some evaporates containing known karst features High Edwards (BFZ)-Barton Springs - Subcrop Class III Overlain by more than 50 feet of low permeability strata of the Upper Cretaceous Low Trinity (Hill Country)-Outcrop and Under Edwards Outcrop Class IIa Bedrock aquifer having well yield commonly exceeding 50 gpm High Trinity (Hill Country)-Subcrop Class III Overlain by more than 50 feet of low permeability strata of the Upper Cretaceous Low Edwards-Trinity (Plateau) Class Ib Outcropping limestone, dolomite and some evaporates containing known karst features High Pecos Valley Class Ia Massive unconfined alluvium, lacustrine and eolian deposits High Southern Ogallala Class 1c sand and gravel outcrops of the Ogalalla Formation High Minor Aquifers Pettyjohn et. al. Classification Rationale Vulnerability Brazos River Alluvium Class Ia Unconfined, Pleistocene terrace and Holocene alluvium deposits shallow watertable High Yegua-Jackson Class Ic Sandstone, sand and gravel outcrops of the Yegua Formation and Jackson Group High <<>> Table 4.2.1-3 Pettyjohn et. al. Aquifer Classification and Vulnerability (continued) Minor Aquifers Pettyjohn et. al. Classification Rationale Vulnerability Sparta-Outcrop Class Ic Sandstone, sand and gravel outcrops of the Yegua Formation and Jackson Group High Sparta-Subcrop Class III Overlain by more than 50 feet of low permeability strata of the Cook Mountain Formation Low Queen City-Outcrop Class Ic Sandstone, sand and gravel outcrops of the Yegua Formation and Jackson Group High Queen City-Outcrop Class III Overlain by more than 50 feet of low permeability strata of the Weches Formation Low Marble Falls Class Ib Outcropping limestone containing known karst features High Ellenberger-San Saba Class Ib Outcropping limestone and dolomite known karst features High Hickory Class IIa Bedrock aquifer having well yield commonly exceeding 50 gpm High Colorado River Alluvium Class Ia Unconfined, Pleistocene terrace and High Gravel deposits and Holocene alluvium deposits shallow watertable High <<>> Table 4.2.1-4 Groundwater Resource Area Sensitivity Ranking Starting MP Ending MP Aquifer TCEQ Vulnerability Ranking Pettyjohn et al Ranking Aquatic Habitat Ranking PWS Water Well Ranking Sum of Rankings Sensitive Area 9.47a 3 Gulf Coast Aquifer1 2 2 2 3 9 No 3 2.5 Gulf Coast Aquifer1 2 2 2 2 8 No 2.5 0a Gulf Coast Aquifer1 2 2 2 3 9 No 0b 16 Gulf Coast Aquifer1 2 2 2 2 8 No 16 20 Gulf Coast Aquifer2 2 1 2 2 7 No 20 21 Gulf Coast Aquifer2 2 1 2 1 6 Yes 21 38 Gulf Coast Aquifer2 2 1 2 2 7 No 38 58 Gulf Coast Aquifer2 2 1 2 3 8 No 58 59.5 Gulf Coast Aquifer2 2 1 2 2 7 No 59.5 66 Brazos River Alluvium 1 1 1 3 6 Yes 66 93 Gulf Coast Aquifer2 2 1 2 3 8 No 93 94 Gulf Coast Aquifer2 2 1 2 2 7 No 94 105 Gulf Coast Aquifer2 2 1 2 3 8 No 105 108 Gulf Coast Aquifer1 2 2 2 3 9 No 108 119 Yegua-Jackson 2 1 1 3 7 No 119 120.5 Colorado River Alluvium 1 1 1 3 6 Yes 120.5 121 Sparta-Subcrop 2 3 3 3 11 No 121 123 Colorado River Alluvium 1 1 1 3 6 Yes 123 125.5 Sparta-Subcrop 2 3 3 2 10 No 125.5 126.5 Colorado River Alluvium 1 1 1 3 6 Yes 126.5 127.5 Sparta-Outcrop 2 1 1 3 7 No 127.5 128.5 Queen City-Subcrop 2 3 3 3 11 No 1 1 1 3 129.5 130.5 Queen City-Subcrop 2 1 3 3 130.5 141.5 128.5 129.5 Colorado River Alluvium Colorado River Alluvium 1 3 2 3 6 Yes 9 No 141.5 150.5 1 1 156.5 166.5 Trinity (Hill Country)- Subcrop Edwards (BFZ)- Barton Springs - Subcrop 3 3 6 Yes Carrizo-Wilcox- Outcrop 2 1 1 3 7 No 150.5 156.5 No Major/Minor Aquifer Present 3 3 3 3 12 No 11 No 166.5 170.5 1 3 3 2 9 No 170.5 173.5 Edwards (BFZ)- Barton Springs - Outcrop 1 1 1 1 4 Yes 173.5 198.5 Trinity (Hill Country)- Outcrop 2 1 1 2 6 Yes 198.5 199 Marble Falls 1 1 1 2 5 Yes <<>> Table 4.2.1-4 Groundwater Resource Area Sensitivity Ranking (continued) Starting MP Ending MP Aquifer TCEQ Vulnerability Ranking Pettyjohn et al Ranking Aquatic Habitat Ranking PWS Water Well Ranking Sum of Rankings Sensitive Area 199 206 Ellenberger-San Saba-Outcrop 1 1 1 2 5 Yes 206 207.5 Trinity (Hill Country)- Outcrop 2 1 1 2 6 Yes 207.5 209 Hickory-Subcrop 2 1 3 3 9 No 209 209.5 Hickory-Outcrop 2 1 1 3 7 No 209.5 210 No Major/Minor Aquifer Present 3 3 3 3 12 No 210 214.5 Hickory-Outcrop 2 1 1 3 7 No 214.5 216 Hickory-Subcrop 2 1 3 3 9 No 216 220 Trinity (Hill Country)- Outcrop 2 1 1 2 6 Yes 220 220.5 Hickory-Subcrop 2 1 3 3 9 No 220.5 221 Hickory-Outcrop 2 1 1 3 7 No 221 222 Hickory-Subcrop 2 2 3 3 9 No 222 222.5 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 222.5 224.5 Trinity (Hill Country)- Outcrop 2 1 1 2 6 Yes 224.5 226 No Major/Minor Aquifer Present 3 3 3 3 12 No 226 226.5 Hickory-Outcrop 2 1 1 3 7 No 226.5 227 No Major/Minor Aquifer Present 3 3 3 3 12 No 227 227.5 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 227.5 232.5 232.5 233 3 3 237 237.5 Edwards-Trinity (Plateau)3 1 2 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 233 237 No Major/Minor Aquifer Present 3 3 3 3 12 No No Major/Minor Aquifer Present 3 3 2 1 12 No 6 Yes 237.5 238 No Major/Minor Aquifer Present 3 3 3 3 12 No 238 238.5 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 238.5 240 Hickory-Subcrop 2 1 3 3 9 No 240 245 Hickory-Outcrop 2 1 1 3 7 No 245 246 Hickory-Subcrop 2 1 3 3 9 No 246 246.5 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 245.5 248.5 Hickory-Subcrop 2 1 3 3 9 No 248.5 249.5 Hickory-Outcrop 2 1 1 3 7 No 249.5 254 Ellenberger-San Saba-Subcrop 1 1 2 2 6 Yes 254 254.5 Ellenberger-San Saba-Outcrop 1 1 1 2 5 Yes 254.5 257.5 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes <<>> Table 4.2.1-4 Groundwater Resource Area Sensitivity Ranking (continued) Starting MP Ending MP Aquifer TCEQ Vulnerability Ranking Pettyjohn et al Ranking Aquatic Habitat Ranking PWS Water Well Ranking Sum of Rankings Sensitive Area 257.5 261.5 Hickory-Subcrop 2 1 3 3 9 No 261.5 263.5 Ellenberger-San Saba-Outcrop 1 1 1 2 5 Yes 263.5 264 Hickory-Subcrop 2 1 3 3 9 No 264 270 Ellenberger-San Saba-Outcrop 1 1 1 2 5 Yes 270 272 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 272 274 Ellenberger-San Saba-Outcrop 1 1 1 2 5 Yes 274 275.5 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 275.5 276.5 Ellenberger-San Saba-Marble Falls- Outcrops 1 1 1 2 5 Yes 276.5 277.5 Hickory-Subcrop 2 1 3 3 9 No 277.5 294.5 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 295 329.5 330.5 339.5 2 1 346.0 349.0 Edwards-Trinity (Plateau)3 1 2 340.5 341.5 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes Edwards-Trinity (Plateau)3 1 2 2 1 6 Yes Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 6 Yes 350 352.5 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 353 354 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 358 359 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 360 366.5 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 367.5 368 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 369 369.5 370 372 2 1 376.5 377 Edwards-Trinity (Plateau)3 1 2 372.5 374 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes Edwards-Trinity (Plateau)3 1 2 2 1 6 Yes Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 6 Yes 386 388 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 390 392.5 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 393.5 394 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 395.5 405 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 406 407 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes <<>> Table 4.2.1-4 Groundwater Resource Area Sensitivity Ranking (continued) Starting MP Ending MP Aquifer TCEQ Vulnerability Ranking Pettyjohn et al Ranking Aquatic Habitat Ranking PWS Water Well Ranking Sum of Rankings Sensitive Area 431 434 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 14.5 16.5 Edwards-Trinity (Plateau)3 2 1 1 2 6 Yes 24.5 29 Southern Ogallala 2 1 1 3 7 No a-East Houston to 9th Street Junction b-East Houston to Crane 1-Beaumont or Catahula Outcrop (Clay Dominant) 2-Lissie or Oakville Outcrop (Sand Dominant) 3-Edwards Group Outcrop, Includes Hensell Sand Formation <<>> Table 4.2.1-5 Public Water Supply Wells Within the Zone of Potential Impact PWS ID Number Figure 4.2.1-3 PWS Well ID Number PWS Name Aquifer Used Number of Water Wells 1013224 1 Galena Park ISD Gulf Coast Aquifer System 1 1011057 2 and 3 Greens Bayou Electric Generating S Gulf Coast Aquifer System 2 1013100 4 Garlock Metallic Gaskets Gulf Coast Aquifer System 1 1010196 5 and 6 Ralston Acres Water Supply Corp Gulf Coast Aquifer System 2 1013171 7 Texas Steel Conversion Gulf Coast Aquifer System 1 1012135 8 Parkway Grocery & Hardware Center Gulf Coast Aquifer System 1 1013001 9 The Rhodes School Gulf Coast Aquifer System 1 1010307 10 Redwood Estates Mobile Home Park Gulf Coast Aquifer System 1 1010013 11,12, 13, 14, 15, 16, 17, 22, 23, 44, 45, 81, 82, 83, 89 and 95 City of Houston Gulf Coast Aquifer System 16 1013455 18 Sigma Askins Houston Facility Gulf Coast Aquifer System 1 1013386 19 La Sultana Refresqueria Gulf Coast Aquifer System 1 1012940 20 Winners Corner 2 Gulf Coast Aquifer System 1 1013232 21 Dagoberto Silva Well Gulf Coast Aquifer System 1 1010011 24, 25, 26, 27 and 28 Greenwood Village Gulf Coast Aquifer System 5 1010022 29, 30, 31 and 32 Sunbelt FWSD Oakwilde Subdivision Gulf Coast Aquifer System 4 1010100 33, 37 and 38 Mary Francis Subdivision Gulf Coast Aquifer System 3 1010533 34 and 35 Sundown Mobile Home Park Gulf Coast Aquifer System 2 1012885 36 Houston Well Screen Company Gulf Coast Aquifer System 1 1011713 39 and 40 Hooks Mobile Home Park LTD Gulf Coast Aquifer System 2 1013245 41 and 42 Mesquite Mobile Home Park Gulf Coast Aquifer System 2 1011609 43 Ashbrook Corp Gulf Coast Aquifer System 1 1010746 46 and 47 Fatima Family Village MHP Gulf Coast Aquifer System 2 1010664 48 and 49 Lone Willow Mobile Home Park Gulf Coast Aquifer System 2 <<>> Table 4.2.1-5 Public Water Supply Wells Within the Zone of Potential Impact (continued) PWS ID Number Figure 4.2.1-3 PWS Well ID Number PWS Name Aquifer Used Number of Water Wells 1011971 50 and 51 Rosewood Mobile Home Park Gulf Coast Aquifer System 2 1010658 52 and 53 Aldine Oaks MHP Gulf Coast Aquifer System 2 1011947 54 and 55 Westfield Garden Mobile Home Park Gulf Coast Aquifer System 2 1010663 56 Lone Willow West Mobile Home Park Gulf Coast Aquifer System 1 1011618 57 Hungry Farmer BBQ & Catering Gulf Coast Aquifer System 1 1010452 58 and 59 Mercado-Sabadomingo Gulf Coast Aquifer System 2 1013010 60 Taqueria Buey de Y Vaca Gulf Coast Aquifer System 1 1012700 61 and 65 Sunny Flea Market Gulf Coast Aquifer System 2 1012625 62 and 63 Sinta Flea Market Gulf Coast Aquifer System 2 1012666 64 Airline Square Gulf Coast Aquifer System 1 1010689 66 Balaban Apartments 1 Gulf Coast Aquifer System 1 1011028 67 Balaban Apartments 2 Gulf Coast Aquifer System 1 1010826 68, 69 and 70 Pin Oak Mobile Home Park Gulf Coast Aquifer System 3 1010744 71 Meadowview MHP Gulf Coast Aquifer System 1 1010832 72 North Point Villa Gulf Coast Aquifer System 1 1011118 73 and 75 New Oasis of Faith Cathedral Gulf Coast Aquifer System 2 1012157 74 Sweetwater Business Park Gulf Coast Aquifer System 1 1010117 76 and 77 Northline Terrace Subdivision Gulf Coast Aquifer System 2 1010012 78 and 79 Hidden Valley Subdivision Gulf Coast Aquifer System 2 1012952 80 Raceway 6772 Gulf Coast Aquifer System 1 1012890 84 and 85 Chevron 249 Gulf Coast Aquifer System 2 1010419 86 and 87 Heather Glen Subdivision Gulf Coast Aquifer System 2 1012892 88 Kingmont Mobile Home Park Gulf Coast Aquifer System 1 1010670 90 West Montgomery Utility Gulf Coast Aquifer System 1 1010897 91 and 92 Harris County MUD 118 Gulf Coast Aquifer System 2 <<>> Table 4.2.1-5 Public Water Supply Wells Within the Zone of Potential Impact (continued) PWS ID Number Figure 4.2.1-3 PWS Well ID Number PWS Name Aquifer Used Number of Water Wells 1010626 93 and 94 Harris County MUD 119 Gulf Coast Aquifer System 2 1010357 96 Rolling Fork PUD Gulf Coast Aquifer System 1 1011647 97 Creekside Estates South Gulf Coast Aquifer System 1 1010322 98 White Oak Manor Mobile Home Park Gulf Coast Aquifer System 1 1010924 99 Windfern Forest Utility District Gulf Coast Aquifer System 1 1012858 100 West Harris County MUD 11 Gulf Coast Aquifer System 1 1012058 101 West Harris County MUD 10 Gulf Coast Aquifer System 1 1011798 102 West Harris County MUD 9 Gulf Coast Aquifer System 1 1011783 103 Harris County MUD 168 Gulf Coast Aquifer System 1 1010016 104 City of Jersey Village Gulf Coast Aquifer System 1 1012293 105 Northwest Harris County MUD 29 Gulf Coast Aquifer System 1 1011412 106, 107 and 108 SPX Process Equipment Houston Gulf Coast Aquifer System 3 1012097 109 and 110 Harris County MUD 130 Gulf Coast Aquifer System 2 1010583 111, 112 and 113 West Houston Mobile Home Community Gulf Coast Aquifer System 3 1010237 114 Harris County FWSD 61 Gulf Coast Aquifer System 1 1011848 115 Harris County MUD 179 Gulf Coast Aquifer System 1 1011982 116 Harris County MUD 188 Gulf Coast Aquifer System 1 1012214 117 Harris County MUD 186 Gulf Coast Aquifer System 1 1011612 118 Harris County MUD 162 Gulf Coast Aquifer System 1 1012213 119 Harris County MUD 163 Gulf Coast Aquifer System 1 1012001 120 W. Harris County MUD 15 Gulf Coast Aquifer System 1 1012970 121 Harris County MUD 172 Gulf Coast Aquifer System 1 1013074 122 and 123 Remington MUD 1 Gulf Coast Aquifer System 2 1011690 124 and 125 Harris County MUD 70 Gulf Coast Aquifer System 2 0080005 126 West End WSC Gulf Coast Aquifer System 1 <<>> Table 4.2.1-5 Public Water Supply Wells Within the Zone of Potential Impact (continued) PWS ID Number Figure 4.2.1-3 PWS Well ID Number PWS Name Aquifer Used Number of Water Wells 0110013 127, 128 and 129 Aqua WSC Carrizo-Wilcox Aquifer 3 130 2270004 City of Sunset Valley Edwards (BFZ)- Barton Springs Segment 1 131 and 132 2270212 Shady Hollow Estates WSC Edwards (BFZ)- Barton Springs Segment 2 133 and 134 0160015 Flat Creek Crossing Ranch Trinity Aquifer System-Hill Country 2 <<>> Table 4.2.2-1 Summary of Chemical Analyses on Surface Water Samples from STORET Stations Within the Zone of Potential Impact of the Proposed Project Mean Analytical Results / # of Samples Analyzed Arsenic (µg/L) Chloride, Total in Water (mg/L) Fluoride, (mg/L) Iron (µg/L) Nitrite Plus Nitrate (mg/L, as N) Oxygen (mg/L) Phos- Phorus, Total (mg/L as P) Sulfate, Total (Mg/L) Standard 50 250 4.0 300 100 5 or 6 exceptional 0.01 to 0.3 250 Type of Standard Map ID STORET Station Year Station Name Primary Secondary Primary Secondary Primary Aquatic Secondary 4 8075770 2006 Hunting Bayou at I- 610, Houston, Texas 6.0/ 26 52.7/ 30 0.59/ 30 27.6/ 25 3.9/ 13 6.8/ 33 1.12/ 26 49.9/ 29 5 8076000 Greens Bayou near Houston, Texas 6.2/ 30 72.1/ 29 0.30/ 29 26.7/ 29 3.7/ 13 6.9/ 36 2.28/ 25 32.6/ 27 7 11332 Cypress Creek at Grant Rd Near Cypress 32.7/ 51 7.2/ 49 1.24/ 51 13.0/ 53 9 11848 Brazos River at FM 1093 118.0/ 13 9.0/ 15 0.00/ 14 90.0/ 11 10 11578 Clear Creek at FM 1887 Northwest of Monaville 48.8/ 6 7.5/ 5 0.00/ 6 15.0/ 4 2006 Mill Creek at Hwy 36 5.0/ 4 44.8/ 13 0.00/ 5 53.8/ 4 8.1/ 9 0.00/ 8 15.3/ 12 12 11576 2010 39.9/ 17 0.28/ 1 7.8/ 13 12/ 16 13 11574 Mill Creek at County Road 2.8 Miles Southwest of Bellville 48.7/ 6 7.1/ 26 0.00/ 6 13.5/ 6 15 12290 Colorado River at Old Hwy 71 1.8/ 5 50.5/ 87 0.33/ 53 12.6/ 5 0.9/ 5 8.0/ 109 0.37/ 92 46.0/ 84 16 12249 Cummins Creek at FM 109 north of Columbus 3.5/ 13 66.3/ 46 80.3/ 4 7.8/ 67 0.00/ 47 11.4/ 44 Fecal Coliform, MF,M-FC, 0.7 µm (cols/ 100 mL) 400 Recreation 2,611/ 33 2,336/ 37 2,430/ 6 <<>> Map ID 17 18 20 21 22 23 25 26 27 29 30 31 Table 4.2.2-1 Summary of Chemical Analyses on Surface Water Samples from Study Area Streams (per STORET) (continued) Mean Analytical Results / # of Samples Analyzed Arsenic (µg/L) Chloride, Total in Water (mg/L) Fluoride, (mg/L) Iron (µg/L) Nitrite Plus Nitrate (mg/L, as N) Oxygen (mg/L) Phos- Phorus, Total (mg/L as P) Sulfate, Total (Mg/L) Standard 50 250 4.0 300 100 5 or 6 exceptional 0.01 to 0.3 250 Type of Standard STORET Station Year Station Name Primary Secondary Primary Secondary Primary Aquatic Secondary 12292 Colorado River at Hwy 71 at La Grange 51.6/ 16 7.8/ 29 0.00/ 14 40.1/ 16 12457 Colorado River at Hwy 95/Hwy Loop 230 at Smithville 58.0/ 29 8.4/ 30 0.31/ 29 51.6/ 29 8159200 Colorado River at Bastrop, Texas 63.0/ 52 0.35/ 54 2.1/ 10 8.2/ 54 0.45/ 44 53.7/ 53 12466 Colorado River at County Park 64.2/ 53 8.7/ 54 0.53/ 55 56.5/ 55 8158650 Colorado River below Austin, Texas 1.0/ 32 60.9/ 55 0.34/ 57 6.3/ 34 2.2/ 16 9.1/ 56 0.38/ 41 48.5/ 55 12435 Onion Creek upstream from FM 973 29.7/ 37 7.8/ 51 0.14/ 35 48.6/ 38 8158000 Colorado River at Austin, Texas 1.0/ 25 60.6/ 36 0.23/ 37 6.2/ 31 0.3/ 34 9.0/ 33 0.02/ 34 45.8/ 34 8155505 Barton Creek below Barton Springs, Austin, Texas 1.0/ 1 13.0/ 1 0.10/ 1 16.0/ 1 0.6/ 11 8.5/ 1 0.15/ 11 25.0/ 1 8155500 Barton Springs at Austin, Texas 1.0/ 43 26.9/ 46 0.22/ 45 4.1/ 41 1.3/ 32 6.5/ 55 0.02/ 59 29.8/ 46 8155300 Barton Creek at Loop 360, Austin, Texas 1.0/ 27 13.5/ 31 0.16/ 32 10.2/ 27 0.2/ 66 8.9/ 25 0.10/ 112 22.8/ 30 12448 Onion Creek 0.7 mile north of Buda next to Mopac 22.3/ 62 9.3/ 60 0.00/ 62 30.8/ 57 8155240 Barton Creek at Lost Creek Blvd. near Austin, Texas 1.0/ 23 28.6/ 25 0.19/ 24 5.9/ 22 0.2/ 94 8.1/ 34 0.08/ 110 52.3/ 24 Fecal Coliform, MF,M-FC, 0.7 µm (cols/ 100 mL) 400 Recreation 252/ 54 166/ 34 11,758/ 10 184/ 56 12,268/ 99 5,236/ 102 <<>> Map ID 32 34 35 36 36 37 38 39 46 47 Table 4.2.2-1 Summary of Chemical Analyses on Surface Water Samples from Study Area Streams (per STORET) (continued) Mean Analytical Results / # of Samples Analyzed Arsenic (µg/L) Chloride, Total in Water (mg/L) Fluoride, (mg/L) Iron (µg/L) Nitrite Plus Nitrate (mg/L, as N) Oxygen (mg/L) Phos- Phorus, Total (mg/L as P) Sulfate, Total (Mg/L) Standard 50 250 4.0 300 100 5 or 6 exceptional 0.01 to 0.3 250 Type of Standard STORET Station Year Station Name Primary Secondary Primary Secondary Primary Aquatic Secondary 8155220 Barton Creek at Barton Creek Blvd., Austin, Texas 1.0/ 5 35.8/ 5 0.30/ 5 7.4/ 5 0.1/ 8 7.5/ 9 0.01/ 9 44.2/ 5 8154510 Colorado River below Mansfield Dam, Austin, Texas 80.3/ 39 0.23/ 37 6.4/ 40 0.00/ 40 59.2/ 39 8155200 Barton Creek at Hwy 71 near Oak Hill, Texas 1.0/ 26 17.1/ 27 0.20/ 22 4.2/ 23 0.1/ 124 8.1/ 42 0.05/ 124 26.4/ 25 8158700 Onion Creek near Driftwood, Texas 1.0/ 36 14.2/ 38 0.19/ 40 5.1/ 34 0.2/ 24 8.6/ 47 0.02/ 51 31.8/ 38 8158700 Onion Creek near Driftwood, Texas 1.0/ 36 14.2/ 38 0.19/ 40 5.1/ 34 0.2/ 24 8.6/ 47 0.02/ 51 31.8/ 38 2007 Onion Creek at FM 150 1.0/ 29 13.9/ 34 0.19/ 33 5.1/ 28 0.1/ 6 8.6/ 87 0.02/ 41 30.8/ 33 12451 2011 19.2/ 13 9.2/ 6 60.8/ 13 12369 Pedernales River at Cr 962 at Hammett's Crossing 40.5/ 11 8.0/ 32 0.00/ 11 24.9/ 10 12260 Flat Creek at Blanco Cr 201 11.5/ 2 7.0/ 8 0.00/ 2 31.0/ 2 12383 Llano River County Road 6.5 Miles upstream from Lake LBJ 20.7/ 30 9.2/ 48 0.00/ 31 16.3/ 30 12265 North Grape Creek at FM 1320 44.0/ 2 7.8/ 8 0.00/ 2 20.5/ 2 Fecal Coliform, MF,M-FC, 0.7 µm (cols/ 100 mL) 400 Recreation 25/ 8 5,898/ 114 1,171/ 60 1,171/ 60 589/ 45 <<>> Map ID 48 49 50 51 53 54 55 56 Table 4.2.2-1 Summary of Chemical Analyses on Surface Water Samples from Study Area Streams (per STORET) (continued) Mean Analytical Results / # of Samples Analyzed Arsenic (µg/L) Chloride, Total in Water (mg/L) Fluoride, (mg/L) Iron (µg/L) Nitrite Plus Nitrate (mg/L, as N) Oxygen (mg/L) Phos- Phorus, Total (mg/L as P) Sulfate, Total (Mg/L) Standard 50 250 4.0 300 100 5 or 6 exceptional 0.01 to 0.3 250 Type of Standard STORET Station Year Station Name Primary Secondary Primary Secondary Primary Aquatic Secondary 12386 Llano River 0.4 mile downstream from bridge on State Hwy 16. 2.2/ 6 20.1/ 9 0.26/ 7 6.5/ 6 0.1/ 6 8.9/ 8 0.01/ 9 15.7/ 9 8151500 Llano River at Llano, Texas 2.2/ 6 21.3/ 7 0.26/ 7 6.5/ 6 0.1/ 6 8.9/ 7 0.02/ 7 15.4/ 7 2006 Pedernales River Goehman Lane 66.8/ 12 8.7/ 20 0.00/ 12 29.5/ 10 12377 2010 60.3/ 16 0.375. 4 9.2/ 6 9.3/ 23 12380 Pedernales River US 290 SE of Fredericksburg 59.8/ 26 0.00/ 14 8.6/ 8 0.00/ 26 33.8/ 16 12208 James River on private Ranch Road 1.2 miles upstream 30.0/ 1 7.9/ 28 0.00/ 1 20.0/ 1 12210 James River at upper Mason County Road Crossing 28.0/ 1 8.8/ 4 0.00/ 1 20.0/ 1 Llano River at Yates Crossing 14.0/ 8 8.0/ 7 0.00/ 8 7.4/ 8 14231 14.5/ 23 1.2/ 6 9.3/ 23 12389 Llano River at County Road 9.5 mi. northeast of Junction 14.4/ 30 8.4/ 28 0.00/ 30 12.0/ 28 Fecal Coliform, MF,M-FC, 0.7 µm (cols/ 100 mL) 400 Recreation 63/ 6 63/ 6 <<>> Table 4.2.2-2 Summary of 2008 Texas 303(d) Stream Segments Within the Zone of Potential Impact of the Proposed Project MP Segment No. Segment Name Yr First Listed Impairment Category* Type Impairment(s) 2002 5a Bacteria 2.31 - 5 1007R Hunting Bayou Above Tidal 2002 5c Depressed dissolved oxygen 7 1006_03 Houston Ship channel Tidal/Greens Bayou Tidal 1996 5a Dioxin in edible tissue 2002 5a PCBs in edible tissue 7 – 8 1006H Spring Gully Above Tidal 2002 5a Bacteria 10 - 16 1006D Halls Bayou 2002 5a Bacteria 10 1016 Greens Bayou Above Tidal 1996 5a Bacteria 16 1006J Unnamed Tributary of Halls Bayou 2002 5a Bacteria 34 1017 Whiteoak Bayou Above Tidal 1996 5a Bacteria 47 1009 Cypress Creek 1996 5a Bacteria 172 - 178 1427A Slaughter Creek 2002 5b Impaired macrobenthic community 152 - 164 1428 Colorado River Below Town Lake 2006 5c Bacteria Category 5a - A TMDL us underway, scheduled, or will be scheduled Category 5b - A review of the water quality standards of this water body will be conducted before a TMDL is scheduled. Category 5c - Additional data and information will be collected before a TMDL is scheduled. <<>> Table 4.2.2-3 Distances from Stream Crossings to Downstream Water Rights Within the Zone of Potential Impact of the Proposed Project Municipal Irrigation Industrial Mining Distance to Rights (ac-ft/no. of rights) Within: Rights (ac-ft/no. of rights) Rights (ac-ft/no. of rights) Rights (ac-ft/no. of rights) Within: Within: Within: Crossing No. 5 mi 20 mi 40 mi 60 mi 5 mi 20 mi 40 mi 60 mi 5 mi 20 mi 40 mi 60 mi 5 mi 20 mi 40 mi 60 mi Downstrea m Lake Mainstream (mi) Lake Name Cypress Creek 34 3,041/ 2 3,041/ 2 3,041/ 2 Mound Creek 37 Live Oak 38 75,000/ 1 Clear Creek 44 48 75,000/ 1 Unnamed Trib. to Cypress Creek 36 Harris Creek Harris Creek Trib. Trib. 41 75,000/ 1 42 Brazos River 45 Muddy Branch East Fork Mill Creek 57 Dogwood Creek 60 West Fork Mill Creek 61 Cummins Creek Rabbs Creek 78 JD Creek 82 Alum Creek 3,041/ 2 3,041/ 2 3,041/ 2 3,041/ 2 3,041/ 2 3,041/ 2 3,041/ 2 3,041/ 2 3,041/ 2 136/ 1 136/ 1 136/ 1 136/ 1 10/ 1 10/ 1 136/ 1 136/ 1 136/ 1 136/ 1 10/ 1 10/ 1 10/ 1 10/ 1 10/ 1 10/ 1 10/ 1 10/ 1 10/ 1 10/ 1 10/ 1 Jacks Creek 67 73/ 1 73/ 1 68 73/ 1 73/ 1 74 33/ 2 33/ 2 148/ 6 148/ 6 Knobbs Creek 77 35/ 1 150/ 5 150/ 5 Dreissner Branch 35/ 1 150/ 5 150/ 5 Pin Oak Creek 80 35/ 1 150/ 5 150/ 5 Gravelly Creek 81 35/ 1 150/ 5 150/ 5 35/ 1 35/ 1 150/ 5 86 35/ 1 150/ 5 Little Alum Creek 87 89 35/ 1 150/ 5 Colorado River 35/ 1 35/ 1 <<>> Table 4.2.2-3 Distances from Stream Crossings to Downstream Water Rights (continued) Municipal Rights (ac-ft/no. of rights) Within: Irrigation Rights (ac-ft/no. of rights) Within: Industrial Rights (ac-ft/no. of rights) Within: Mining Rights (ac-ft/no. of rights) Within: Crossing No. 5 mi 20 mi 40 mi 60 mi 5 mi 20 mi 40 mi 60 mi 5 mi 20 mi 40 mi 60 mi 5 mi 20 mi 40 mi 60 mi Distance to Downstrea m Lake Mainstream (mi) Lake Name Unnamed 92 35/ 1 35/ 1 Cedar Creek 93 35/ 1 35/ 1 35/ 1 67/ 1 67/ 1 67/ 1 Marble Creek 101 67/ 1 67/ 1 67/ 1 67/ 1 67/ 1 67/ 1 40/ 1 40/ 1 Flat Creek 112 34/ 1 34/ 1 34/ 1 Maha Creek 97 Dry Creek Cottonmouth Creek 99 100 Onion Creek 103 Barton Creek 109 Pedernales Cottonwood Creek River 115 30/ 1 30/ 1 30/ 1 30/ 1 34/ 1 34/ 1 34/ 1 119 Hickory Creek White Oak Creek 125 127 Cherry Spring Creek 142 1,200/ 1 1,200/ 1 46/ 1 46/ 1 187/ 5 247/ 6 Marshall Creek Squaw Creek 32.9 Town Lake 26.8 Lake Travis 33.2 Lake Travis 30/ 1 30/ 1 30/ 1 34/ 1 34/ 1 34/ 1 41.1 Lake Travis 30/ 1 30/ 1 34/ 1 34/ 1 53.7 Lake Travis 30/ 1 Lake Travis Crabapple Creek 135 1/ 1 1/ 1 1/ 1 4/ 1 4/ 1 4/ 1 33.3 Bernst Creek 140 1,200/ 1 1,200/ 1 46/ 1 46/ 1 187/ 5 247/ 6 143 30/ 1 1,200/ 1 34/ 1 34/ 1 59.9 Lake LBJ 51.3 Lake LBJ 50.2 Lake LBJ 1,200/ 1 46/ 1 46/ 1 187/ 5 247/ 6 50.7 Lake LBJ 150 1,200/ 1 49/ 2 139/ 4 163/ 6 304/ 10 31/ 2 31/ 2 63.2 Lake LBJ Threadgill Creek 151 1,200/ 1 49/ 2 139/ 4 163/ 6 304/ 10 31/ 2 31/ 2 63.5 Lake LBJ 161 Lake LBJ Mill Creek 164 James River 166 168 173 1,200/ 1 1,200/ 1 46/ 1 222/ 5 351/ 10 492/ 14 31/ 2 31/ 2 Rocky Creek Llano River 237/ 6 53/ 1 Unnamed 46/ 1 84/ 3 351/ 10 492/ 14 31/ 2 31/ 2 69.5 71 Lake LBJ 46/ 1 46/ 1 351/ 9 492/ 14 31/ 2 95.1 Lake LBJ 53/ 1 358/ 9 358/ 10 31/ 2 79.7 Lake LBJ 2,651/18 2,704/19 116.3 Lake <<>> Table 4.2.2-3 Distances from Stream Crossings to Downstream Water Rights (continued) Crossing No. 5 mi Municipal Rights (ac-ft/no. of rights) Within: 60 mi Irrigation Rights (ac-ft/no. of rights) Within: Industrial Rights (ac-ft/no. of rights) Within: Mining Rights (ac-ft/no. of rights) Within: 20 mi 40 mi 5 mi 20 mi 40 mi 60 mi 5 mi 20 mi 40 mi 60 mi 5 mi 20 mi 40 mi 60 mi Distance to Downstrea m Lake Mainstream (mi) Tributary (first- order) Unnamed Tributary (first- order) 174 192/ 4 1,338/30 3,664/41 60/ 1 60/ 1 128 Unnamed Tributary (first- order) 175 76/ 5 1,227/31 3,513/40 60/ 1 60/ 1 129.8 Terret Draw 185 1,016/ 1 1,016/ 1 531/ 6 6,068/37 7,997/62 3/ 1 6/ 2 6/ 2 Middle Valley 192 1,016/ 1 1,016/ 1 285/ 3 5,302/28 7,997/62 3/ 1 6/ 2 6/ 2 Antelope Draw 197 1016/ 1 110/ 1 559/ 9 7,178/44 3/ 1 3/ 1 6/ 2 Lake Name LBJ Lake LBJ Lake LBJ <<>> Table 4.2.2-4 Ranking of Stream Crossings in Terms of Spill Transport Potential Stream at Crossing Map ID Pipeline Crossing (MP) Slope of Channel at Crossing Basin Area (sq mi) Stream Order 2-Year Flood (cfd) Rank in Potential to Transports Spill (1- highest) Basis for Rank Hunting Bayou 1 0.1 0.0006 14.4 Urban Urban 4 Basin size Greens Bayou 3 3.2,6.0 0.0000 182 Urban Urban 2 High Stream Order Halls Bayou 8 13.2 0.0009 24.7 Urban Urban 4 Basin size Cypress Creek 34 47.1 0.0009 89.9 3 2701 2 High Stream Order Unnamed Tributary to Cypress Creek 36 48.7 0.0010 3.9 2 311 5 Med-Iow 2-year flood Mound Creek 37 50.4 0.0013 43.0 2 1,211 4 Med 2-year flood Live Oak 38 53.9 0.0017 10.1 2 782 4 Med 2-year flood Harris Creek Tributary 41 58.7 0.0033 7.5 2 576 5 Med-Iow 2-year flood Harris Creek Tributary 42 59.7 0.0020 8.0 2 596 5 Med-Iow 2-year flood Clear Creek 1 44 62.6 0.0010 74.3 3 2,245 2 High Stream Order Brazos River 45 64.0 0.00013 44,000 Major 57,800 1 Major Crossing Muddy Branch 48 69.2 0.0022 9.2 2 1,172 4 Med 2-year flood East Fork Mill Creek 57 81.2 0.0007 126.0 3 3,539 2 High Stream Order Dogwood Creek 60 89.2 0.0025 11.1 2 988 4 Med 2-year flood West Fork Mill Creek 61 90.8 0.0013 44.0 3 2,034 2 High Stream Order Jacks Creek 67 98.3 0.0030 11.8 2 1,019 4 Med 2-year flood Cummins Creek 68 99.2 0.0018 94.3 3 4,155 2 High Stream Order Rabbs Creek 74 112.3 0.0013 81.3 3 4,366 2 High Stream Order Knobbs Creek 77 118.8 0.0033 23.2 2 1,453 4 Med 2-year flood Dreissner Branch 78 119.9 0.0033 6.8 2 761 5 Med-Iow 2-year flood Pin Oak Creek 80 122.5 0.0014 50.1 3 3,668 2 High Stream Order Gravelly Creek 81 123.0 0.0025 18.7 2 1,297 4 Med 2-year flood JD Creek 82 126.7 0.0050 6.7 2 755 5 Med-Iow 2-year flood Alum Creek 86 131.5 0.0028 46.1 3 3,884 2 High Stream Order Little Alum Creek 87 132.3 0.0056 4.6 2 622 5 Med-low 2-year flood Colorado River 89 134.5 0.00033 39.8 Major 48,300 1 Major Crossing Unnamed 92 142.9 0.0048 7.3 2 691 5 Med-Iow 2-year flood Cedar Creek 2 93 142.8 0.0014 90 3 4,079 2 High Stream Order Maha Creek 3 97 151.7 0.0029 32.7 2 2,677 3 High 2-year flood Dry Creek 99 157.4 0.0029 22.2 2 1,312 4 Med 2-year flood Cottonmouth Creek 100 162.3 0.0040 2.2 1 324 5 Med-Iow 2-year flood Marble Creek 101 163.5 0.0143 3.8 1 449 5 Med-Iow 2-year flood Onion Creek 103 164.0 0.0014 284.4 Large 6,983 1 Major Crossing Barton Creek 109 180.9 0.0050 40.9 2 2,392 3 High 2-year flood Flat Creek 112 193.2 0.0091 31.0 3 1,919 2 High Stream Order <<>> Table 4.2.2-4 Ranking of Stream Crossings in Terms of Spill Transport Potential (continued) Stream at Crossing Map ID Pipeline Crossing (MP) Slope of Channel at Crossing Basin Area (sq mi) Stream Order 2-Year Flood (cfd) Rank in Potential to Transports Spill (1- highest) Basis for Rank Pedernales River 115 198.8 0.0026 1,000.0 Large 15,488 1 Major Crossing Cottonwood Creek 119 203.2 0.0111 10.3 2 901 4 Med 2-year flood Hickory Creek 125 209.9 0.0063 12.2 2 1,024 4 Med 2-year flood White Oak Creek 127 213.3 0.0100 7.5 2 829 4 Med 2-year flood Crabapple Creek 135 229.3 0.0100 63.4 3 2,876 2 High Stream Order Bernst Creek 140 237.8 0.0100 3.8 2 543 5 Med-Iow 2-year flood Cherry Spring Creek 142 241.7 0.0040 11.0 2 1,011 4 Med 2-year flood Marshall Creek 143 242.7 0.0059 10.9 2 947 4 Med 2-year flood Squaw Creek 150 24S.5 0.0063 39.6 2 2,231 3 High 2-year flood Threadgill Creek 151 250.0 0.0042 1,17.3 4 4,363 2 High Stream Order James River 161 263.9 0.0029 322.1 Large 8,030 1 Major Crossing Mill Creek 164 267.9 0.0067 7.3 2 786 4 Med 2-year flood Rocky Creek 166 273.7 0.0100 10.5 2 993 4 Med 2-year flood Llano River 168 276.5 Major 1 Major Crossing Terret Draw 185 315.9 0.0028 34.6 3 1,711 3 High 2-year flood Middle Valley 192 324.2 0.001 I 137.2 3 3,545 3 High 2-year flood Antelope Draw 197 334.3 0.0018 62.0 3 2,273 3 High 2-year flood Big Lake Draw 211 402.6 0.0030 46.0 2 627 5 Med-low 2-year flood Garrison 216 415.8 0.0022 24.5 2 499 5 Med-Iow 2-year flood China Draw 224 433.1 0.0026 17. 1 2 374 5 Med-Iow 2-year flood Mayfield Draw 234 450.2 0.0025 76.3 3 508 5 Med-Iow 2-year flood 1 Clear Creek does not cross the pipeline, but at one location parallels the pipeline at a distance of 85 meters. 2 Cedar Creek does not cross the pipeline, but at one location parallels the pipeline at a distance of 320 meters. 3 Maha Creek does not cross the pipeline, but at one location parallels the pipeline at a distance of 180 meters. <<>> Table 4.2.2-5 Ranking of Stream Crossings in Terms of Spill Control Potential Stream at Crossing Map ID Pipeline Crossing (MP) Distance to Main Stem of River Downstream (mi) Rank in Potential to Control a Spill (1 = most difficult to control) Basis for Rank Hunting Bayou 1 0.1 N/A 6 In urban setting, within levees Greens Bayou 3 3.2,6 N/A 6 In urban setting, within levees Halls Bayou 8 13.2 N/A 6 In urban setting, within levees Cypress Creek 34 47.1 0.0 1 Main stem Unnamed Tributary to Cypress Creek 36 48.7 1.9 2 Within 2 miles of main stem Mound Creek 37 50.4 7.5 3 3 to 10 miles from main stem Live Oak 38 53.9 9.9 3 3 to 10 miles from main stem Harris Creek Tributary 41 58.7 20.9 5 20-30 miles from main stem Harris Creek Tributary 42 59.7 20.6 5 20-30 miles from main stem Clear Creek 1 44 62.6 1.2 2 Within 2 miles of main stem Brazos River 45 64.0 0.0 1 Main stem Muddy Branch 48 69.2 7.0 3 3 to 10 miles from main stem East Fork Mill Creek 57 81.2 26.5 5 20-30 miles from main stem Dogwood Creek 60 89.2 38.1 6 Over 35 miles from main stem West Fork Mill Creek 61 90.8 38.7 6 Over 35 miles from main stem Jacks Creek 67 98.3 37.0 6 Over 35 miles from main stem Cummins Creek 68 99.2 36.9 6 Over 35 miles from main stem Rabbs Creek 74 112.3 6.9 3 3 to 10 miles from main stem Knobbs Creek 77 118.8 9.6 3 3 to 10 miles from main stem Dreissner Branch 78 119.9 9.0 3 3 to 10 miles from main stem Pin Oak Creek 80 122.5 9.6 3 3 to 10 miles from main stem Gravelly Creek 81 123.0 9.8 3 3 to 10 miles from main stem JD Creek 82 126.7 2.2 2 Near main stem Alum Creek 86 131.5 3.3 2 On Colorado River Alluvium Little Alum Creek 87 132.3 3.3 2 On Colorado River Alluvium Colorado River 89 134.5 0.0 1 Main stem Unnamed 92 142.9 13.2 2 On Colorado River Alluvium Cedar Creek 2 93 142.8 13.0 2 On Colorado River Alluvium Maha Creek 3 97 151.7 26.5 2 On Colorado River Alluvium Dry Creek 99 157.4 14.9 4 10-20 miles from main stem Cottonmouth Creek 100 162.3 4.0 3 3 to 10 miles from main stem Marble Creek 101 163.5 0.2 1 Essentially at main stem Onion Creek 103 164.0 15.3 1 Major tributary Barton Creek 109 180.9 26.3 1 On Edwards/Balcones Contributing Zone Flat Creek 112 193.2 3.8 3 3 to 10 miles from main stem Pedernales River 115 198.8 33.2 1 Main stem, major tributary Cottonwood Creek 119 203.2 1.2 2 Within 2 miles of main stem Hickory Creek 125 209.9 2.6 2 Very near main stem <<>> Table 4.2.2-5 Ranking of Stream Crossings in Terms of Spill Control Potential (continued) Stream at Crossing Map ID Pipeline Crossing (MP) Distance to Main Stem of River Downstream (mi) Rank in Potential to Control a Spill (1 = most difficult to control) Basis for Rank White Oak Creek 127 213.3 6.0 2 Near Ellenburger-San Saba Aquifer (karst) Crabapple Creek 135 229.3 33.3 2 Near Ellenburger~SanSaba Aquifer (karst) Bernst Creek 140 237.8 22.7 5 20-30 miles from main stem Cherry Spring Creek 142 241.7 21.6 5 20-30 miles from main stem Marshall Creek 143 242.7 22.1 5 20~30 miles from main stem Squaw Creek 150 248.5 14.2 1 On Ellenburger·San Saba Aquifer (karst) Threadgill Creek 151 250.0 14.5 2 On Ellenburger·San Saba Aquifer (karst) James River 161 263.9 9.1 1 Main stem, major tributary Mill Creek 164 267.9 7.0 2 On Ellenburger-San Saba Aquifer (karst) Rocky Creek 166 273.7 2.8 2 Near Ellenburger-San Saba Aquifer (karst) Llano River 168 276.5 0.0 1 On Ellenburger-San Saba Aquifer (karst), major river Terret Draw 185 315.9 9.5 2 On Edwards-Trinity (karst) Middle Valley 192 324.2 14.9 2 On Edwards-Trinity (karst) Antelope Draw 197 334.3 24.6 2 On Edwards-Trinity (karst) Big Lake Draw 211 402.6 35.5 1 On Edwards-Trinity (karst), near known karst feature Garrison 216 415.8 40.3 2 Cenozoic Pecos Alluvium China Draw 224 433.1 28.2 2 Cenozoic Pecos Alluvium Mayfield Draw 234 450.2 22.6 2 Cenozoic Pecos Alluvium 1 Clear Creek does not cross the pipeline, but at one location parallels the pipeline at a distance of 85 meters. 2 Cedar Creek does not cross the pipeline, but at one location parallels the pipeline at a distance of 320 meters. 3 Maha Creek does not cross the pipeline, but at one location parallels the pipeline at a distance of 180 meters. <<>> Table 4.2.2-6 Ranking of Stream Crossings in Terms of Downstream Resource Importance as a Water Supply Stream at Crossing Map ID Pipeline Crossing (MP) Rank in Importance of Proximity and Type of Downstream Water Supply (1= most important) Basis for Rank Hunting Bayou 1 2.5 6 Low quality water Greens Bayou 3 7.0 6 Low quality water Halls Bayou 8 16.0 6 Low quality water Cypress Creek 34 47.1 3 Large irrigation right within 20 miles Unnamed Tributary to Cypress Creek 36 48.7 3 Large irrigation right within 20 miles Mound Creek 37 50.4 3 Large irrigation right within 20 miles Live Oak 3& 53.9 3 Large irrigation right within 20 miles Harris Creek Tributary 41 51.0 3 Large irrigation right within 20 miles Harris Creek Tributary 42 59.7 3 Large irrigation right within 20 miles Clear Creek1 44 62.6 5 Small irrigation right within 20 miles Brazos River 45 64.0 5 Small irrigation right within 20 miles Muddy Branch 48 69.2 2 Municipal right within 75 miles downstream East Fork Mill Creek 57 81.2 6 Small right, within 40/60 miles Dogwood Creek 60 89.2 6 Small right, within 40/60 miles West Fork Mill Creek 61 90.8 6 Small right, within 40/60 miles Jacks Creek 67 98.3 6 Small right. within 40/60 miles Cummins Creek 68 99.2 6 Small right, within 40/60 miles Rabbs Creek 74 112.3 5 Small irrigation right within 20 miles Knobbs Creek 77 118.8 5 Small irrigation right within 20 miles Dreissner Branch 78 119.9 5 Small irrigation right within 20 miles Pin Oak Creek 80 122.5 5 Small irrigation right within 20 miles Gravelly Creek 81 123.0 5 Small irrigation right within 20 miles JD Creek 82 126.7 5 On Colorado River Alluvium Alum Creek 86 131.5 5 Alluvial irrigation well within 20 miles Little Alum Creek 87 132.3 5 Alluvial irrigation well within 20 miles Colorado River 89 134.5 5 Alluvial irrigation well within 20 miles Unnamed 92 142.9 5 Alluvial irrigation well within 20 miles Cedar Creek1 93 142.8 5 Alluvial irrigation well within 20 miles Maha Creek1 97 151.7 5 Alluvial irrigation well within 20 miles Dry Creek 99 157.4 1 14.9 miles to Colorado River Alluvium Cottonmouth Creek 100 162.3 1 12.7 miles to Colorado River Alluvium Marble Creek 101 163.5 1 13.7 miles to Colorado River Alluvium Onion Creek 103 164.0 1 15.3 miles to Colorado River Alluvium Slaughter Creek NS 174.0 1 8.2 miles to Hill Country Springs water intake Barton Creek 109 180.9 1 26.3 miles to Edwards Balcones recharge Flat Creek 112 193.2 1 Highland Lake within 40 miles downstream <<>> Table 4.2.2-6 Ranking of Stream Crossings in Terms of Downstream Resource Importance as a Water Supply (continued) Stream at Crossing Map ID Pipeline Crossing (MP) Rank in Importance of Proximity and Type of Downstream Water Supply (1= most important) Basis for Rank Pedernales River 115 198.8 1 Highland Lake within 40 miles downstream Cottonwood Creek 119 203.2 2 Highland Lake within 75 miles downstream Hickory Creek 125 209.9 2 Highland Lake within 75 miles downstream White Oak Creek 127 213.3 2 Highland Lake within 75 miles downstream Crabapple Creek 135 229.3 2 Highland Lake within 75 miles downstream Sandy Creek1 138 234.9 1 Alluvial public water supply well within 2 mi Sandy Creek1 139 236.6 1 Alluvial public water supply well within 2 mi Bernst Creek 140 237.8 1 Highland Lake within 40 miles downstream Cherry Spring Creek 142 241.7 2 Highland Lake within 40 miles downstream Marshall Creek 143 242.7 2 Highland Lake within 75 miles downstream Squaw Creek 150 248.5 2 Highland Lake within 75 miles downstream Threadgill Creek 151 250.0 2 Highland Lake within 75 miles downstream James River 161 263.9 2 Highland Lake within 75 miles downstream Mill Creek 164 267.9 2 Highland Lake within 75 miles downstream Rocky Creek 166 273.7 5 Small irrigation right within 20 miles Llano River 168 276.5 5 Small irrigation right within 20 miles Terret Draw 185 315.9 2 Alluvial public water supply well within 60 mi Middle Valley 192 324.2 4 Large irrigation right within 40 miles Antelope Draw 197 334.3 4 Large irrigation right within 40 miles Big Lake Draw 211 402.6 7 No uses identified within 60 miles Garrison 216 415.8 7 No uses identified within 60 miles China Draw 224 433.1 7 No uses identified within 60 miles Mayfield Draw 234 450.2 7 No uses identified within 60 miles 1 - Does not cross the pipeline, but is within the zone of potential impact. <<>> Table 4.2.2-7 Summary of Vulnerability Rankings, Surface Water Crossings Stream at Crossing Map ID Pipeline Station for Crossing (miles) Rank in Importance of Proximity and Type of Downstream Water Supply (1= most important) Rank in Potential to Control a Spill (1 = most difficult to control) Rank in Potential to Transport a Spill (1= highest) Sum of Ranks Onion Creek 103 164.0 I 1 1 3 Pedernales River 115 198.8 I 1 1 3 James River 161 263.9 2 1 1 4 Barton Creek 109 180.9 1 1 3 5 Threadgill Creek 151 250.0 2 1 2 5 Cypress Creek 34 47.1 3 1 2 6 Flat Creek 112 193.2 1 3 2 6 Crabapple Creek 135 229.3 2 2 2 6 Squaw Creek 150 248.5 2 1 3 6 Terret Draw 185 315.9 2 1 3 6 Brazos River 45 64.0 5 1 1 7 Colorado River 89 134.5 5 1 1 7 Mill Creek 164 267.9 2 1 4 7 Llano River 168 276.5 5 1 1 7 Alum Creek 86 131.5 5 1 2 8 Cedar Creek 93 142.8 5 1 2 8 Cottonwood Creek 119 203.2 2 2 4 8 Hickory Creek 125 209.9 2 2 4 8 White Oak Creek 127 213.3 2 2 4 8 Middle Valley 192 324.2 4 1 3 8 Antelope Draw 197 334.3 4 1 3 8 Clear Creek 44 62.6 5 2 2 9 Muddy Branch 48 69.2 2 3 4 9 Maha Creek 97 151.7 5 1 3 9 Dry Creek 99 157.4 I 4 4 9 Unnamed Trib to Cypress Creek 36 48.7 3 2 5 10 Mound Creek 37 50.4 3 3 4 10 Live Oak 38 53.9 3 3 4 10 Rabbs Creek 74 112.3 5 3 2 10 Pin Oak Creek 80 122.5 5 3 2 10 Cottonmouth Creek 100 162.3 I 4 5 10 Marble Creek 101 163.5 I 4 5 10 JD Creek 82 126.7 5 1 5 11 Little Alum Creek 87 132.3 5 1 5 11 Unnamed 92 142.9 5 1 5 11 Sandy Creek (1) 138 234.9 I 5 5 11 Sandy Creek (2) 139 236.6 1 5 5 11 <<>> Table 4.2.2-7 (continued) Summary of Vulnerability Rankings, Surface Water Crossings Stream at Crossing Map ID Pipeline Station for Crossing (miles) Rank in Importance of Proximity and Type of Downstream Water Supply (1= most important) Rank in Potential to Control a Spill (1 = most difficult to control) Rank in Potential to Transport a Spill (1= highest) Sum of Ranks Bernst Creek 140 237.8 I 5 5 11 Cherry Spring Creek 142 241.7 2 5 4 11 Knobbs Creek 77 118.8 5 3 4 12 Gravelly Creek 81 123.0 5 3 4 12 Harris Creek Trib 41 58.7 3 5 5 13 Harris Creek Trib 42 59.7 3 5 5 13 East Fork Mill Creek 57 81.2 6 5 2 13 Dreissner Branch 78 119.9 5 3 5 13 Big Lake Draw 211 402.6 7 1 5 13 Garrison 216 415.8 7 1 5 13 China Draw 224 433.1 7 1 5 13 Mayfield Draw 234 450.2 7 1 5 13 West Fork Mill Creek 61 90.8 6 6 2 14 Cummins Creek 68 99.2 6 6 2 14 Greens Bayou 3 10.0 6 6 2 14 Dogwood Creek 60 89.2 6 6 4 16 Jacks Creek 67 98.3 6 6 4 16 Hunting Bayou 1 4.0 6 6 4 16 Halls Bavou 8 17.3 6 6 4 16 <<>> Table 4.2.2-8 Wetlands Inventory for Proposed Project from East Houston/9th Street Junction to Crane MP From MP to Wetland Area Count Wetland Area Acres Stream Count Wetland Stream Miles County 0 10 79 195.05 0 0.00 Harris 10 20 69 131.48 0 0.00 Harris 20 30 107 264.05 0 0.00 Harris 30 40 192 555.37 0 0.00 Harris 40 50 113 2217.11 0 0.00 Harris 50 60 141 269.62 0 0.00 Harris/Waller 60 70 198 490.52 0 0.00 Austin/Waller 70 80 96 106.56 9 2.01 Austin 80 90 171 195.47 1 0.69 Austin 90 100 145 103.98 1 0.53 Austin/Fayette 100 110 151 115.54 9 1.11 Fayette 110 120 150 88.25 42 7.81 Bastrop/Fayette/Lee 120 130 151 75.29 3 1.13 Bastrop/Fayette 130 140 57 121.90 2 1.17 Bastrop 140 150 132 56.67 0 0.00 Bastrop 150 160 119 38.87 1 0.25 Bastrop/Travis 160 170 68 53.89 8 3.49 Travis 170 180 27 10.00 23 5.78 Travis 180 190 114 49.27 20 3.98 Hays/Travis 190 200 62 76.37 38 10.58 Blanco/Hays 200 210 54 17.85 26 6.35 Blanco 210 220 52 26.53 17 4.87 Blanco/Gillespie 220 230 47 18.76 34 7.07 Gillespie 230 240 44 9.47 41 12.66 Gillespie/Llano 240 250 60 71.98 18 6.84 Gillespie/Llano/Mason 250 260 28 29.58 21 6.36 Mason 260 270 22 61.31 29 7.92 Mason 270 280 20 80.72 20 6.15 Kimble/Mason 280 290 2 0.65 11 3.00 Kimble 290 300 7 3.41 37 11.52 Kimble 300 310 14 3.91 20 5.28 Kimble/Menard 310 320 5 4.17 5 1.33 Kimble/Menard/Schleicher 320 330 6 8.34 0 0.00 Schleicher 330 340 11 2.77 0 0.00 Schleicher 340 350 16 40.58 0 0.00 Schleicher 350 360 20 35.83 0 0.00 Schleicher <<>> Table 4.2.2-8 Wetlands Inventory for Proposed Project from East Houston/9th Street Junction to Crane (continued) MP From MP to Wetland Area Count Wetland Area Acres Stream Count Wetland Stream Miles County 360 370 25 96.36 0 0.00 Crockett/Schleicher 370 380 16 44.16 0 0.00 Crockett 380 390 16 28.84 0 0.00 Crockett 390 400 12 2.64 0 0.00 Crockett/Reagan 400 410 21 13.24 11 3.09 Reagan 410 420 29 24.42 2 0.19 Reagan 420 430 20 8.54 0 0.00 Reagan/Upton 430 440 3 0.53 0 0.00 Upton 440 450 5 1.65 0 0.00 Upton 450 456 1 0.40 0 0.00 Crane/Upton 2.898 5,851.90 449 121.16 <<>> Table 4.3.1-1 Threatened and Endangered Species of Possible Occurrence Within the Zone of Potential Impact of the Proposed Project1 Status3 Common Name2 Scientific Name2 FWS TPWD Counties of Potential Occurrence4 Potential for Occurrence5 BIRDS American Peregrine Falcon Falco peregrinus anatum NL T Austin, Bastrop, Blanco, Crane, Crockett, Fayette, Gillespie, Harris, Hays, Kimble, Mason, Menard, Reagan, Schleicher, Travis, Upton, Waller Attwater’s Greater Prairie- Chicken Tympanuchus cupido attawateri E E Austin, Waller Bald Eagle Haliaeetus leucocephalus DL T Blanco, Crockett, Gillespie, Hays, Kimble, Mason, Menard, Reagan, Schleicher, Travis, Upton, Potential Migrant Black-Capped Vireo Vireo atricapilla E E Blanco, Crockett, Gillespie, Hays, Pecos, Kimble, Mason, Menard, Reagan, Schleicher, Travis, Upton No Brown Pelican Pelecanus occidentalis NL E Harris No Golden-Cheeked Warbler Dendroica chrysoparia E E Blanco, Gillespie, Hays, Kimble, Mason, Menard, Travis No Interior Least Tern Sterna antillarum athalassos NL E Austin, Bastrop, Crane, Crockett, Fayette, Travis, Waller Potential Migrant Peregrine Falcon Falco peregrinus DL T Austin, Bastrop, Blanco, Crane, Crockett, Fayette, Gillespie, Harris, Hays, Kimble, Mason, Menard, Reagan, Schleicher, Travis, Upton, Waller Potential Migrant Red-cockaded Woodpecker Picoides borealis NL E Harris Reddish Egret Egretta rufescens NL T Pecos, Reeves White-Faced Ibis Plegadis chihi NL T Austin, Harris, Waller Potential Migrant White Tailed Hawk Buteo albicaudatus NL T Austin, Harris, Waller <<>> Table 4.3.1-1 Threatened and Endangered Species of Possible Occurrence Within the Zone of Potential Impact of the Proposed Project (continued) Status3 Common Name2 Scientific Name2 FWS TPWD Counties of Potential Occurrence4 Potential for Occurrence5 Whooping Crane Grus americana E E Austin, Bastrop, Blanco, Fayette, Gillespie, Harris, Hays, Kimble, Mason, Menard, Reagan, Schleicher, Travis, Waller Potential Migrant Wood Stork Mycteria americana NL T Austin, Bastrop, Fayette, Harris, Waller No Zone-Tailed Hawk Buteo albonotatus NL T Blanco, Crockett, Gillespie, Hays, Kimble, Mason, Menard Potential Migrant Fishes Blue Sucker Cycleptus elongatus NL T Bastrop, Fayette, Hays No Clear Creek gambusia Gambusia heterochir E E Menard No Creek Chubsucker Erimyzon oblongus NL T Harris, Waller No Fountain Darter Etheostoma fonticola E E Hays No Pecos Pupfish Cyprinodon pecosensis NL T Crane, Crockett No Proserpine Shiner Cyprinella proserpina NL T Crockett No Rio Grande Darter Etheostoma grahami NL T Crockett No San Marcos Gambusia Gambusia georgei E E Hays No Smalltooth Sawfish Pristis pectinata NL E Harris No Mammals Black Bear Ursus americanus NL T Austin, Blanco, Crane, Crockett, Gillespie, Kimble, Mason, Reagan, Schleicher, Upton No Gray Wolf Canis lupus EXP E Blanco, Crane, Crockett, Gillespie, Kimble, Mason, Menard, Reagan, Schleicher, Upton Louisiana Black Bear Ursus americanus luteolus NL T Austin, Harris No Ocelot Leopardus pardalis NL E Crockett No Rafinesque’s Big-eared Corynorhinus rafinesquii NL T Harris <<>> Table 4.3.1-1 Threatened and Endangered Species of Possible Occurrence Within the Zone of Potential Impact of the Proposed Project (continued) Status3 Common Name2 Scientific Name2 FWS TPWD Counties of Potential Occurrence4 Potential for Occurrence5 Bat Red Wolf Canis rufus NL E Austin, Bastrop, Blanco, Fayette, Gillespie, Harris, Hays, Kimble, Mason, Menard, Schleicher, Travis, Waller Trichechus manatus West Indian Manatee E NL Harris No Mollusks and other Invertebrates False Spike Mussel Quadrula mitchelli NL T Austin, Bastrop, Blanco, Crane, Crockett, Fayette, Gillespie, Hays, Kimble, Mason, Menard, Travis, Waller Golden Orb Quadrula aurea NL T Blanco. Gillespie, Hays Louisiana Pigtoe Pleurobema riddellii NL T Harris Sandbank Pocketbook Lamsilis satura NL T Harris Smooth Pimpleback Quadrula houstonensis NL T Austin, Bastrop, Blanco, Fayette, Mason, Menard, Travis, Waller Texas Hornshell Popenaias popeii NL T Crane, Crockett, Schleicher Texas Fatmucket Lampsilis bracteata NL T Crane, Gillespie, Hays, Kimble, Mason, Menard, Travis Texas Fawnsfoot Truncilla macrodon NL T Austin, Bastrop, Blanco, Fayette, Kimble, Mason, Menard, Travis Texas Pigtoe Fusconaia askewi NL T Harris Texas Pimpleback Quadrula petrina NL T Bastrop, Blanco, Fayette, Gillespie, Hays, Kimble, Mason, Menard, Travis Bee Creek Cave Harvestman Texella reddelli E NL Travis Bone Cave Harvestman Texella reyesi E NL Travis <<>> Table 4.3.1-1 Threatened and Endangered Species of Possible Occurrence Within the Zone of Potential Impact of the Proposed Project (continued) Status3 Common Name2 Scientific Name2 FWS TPWD Counties of Potential Occurrence4 Potential for Occurrence5 Comal Springs Dryopid Beetle Stygoparnus comalensis E NL Hays Comal Springs Riffle Beetle Heterelmis comalensis E NL Hays Tooth Cave Ground Beetle Rhadine persephone E NL Travis Tooth Cave Pseudoscorpion Tartarocreagris texana E NL Travis Tooth Cave Spider Neoleptoneta myopica E NL Travis Warton’s Cave Meshweaver Cicurina wartoni C C Travis Reptiles Alligator Snapping Turtle Macroclemys temmincki NL T Austin, Harris, Waller Cagle’s Map Turtle Graptemys caglei NL T Hays Green Sea Turtle Chelonia mydas NL T Harris No Kemp’s Ridley Sea Turtle Lepidochelys kempii NL E Harris No Leatherback Sea Turtle Dermochelys coriacea NL E Harris No Loggerhead Sea Turtle Caretta caretta NL T Harris No Smooth Green Snake Liochlorophis vernalis NL T Austin, Harris Texas Horned Lizard Phyrnosoma cornutum NL T Austin, Bastrop, Blanco, Crane, Crockett, Fayette, Gillespie, Harris, Hays, Kimble, Mason, Menard, Reagan, Schleicher, Travis, Upton, Waller Timber/canebrake Rattlesnake Crotalus horridus NL T Austin, Bastrop, Fayette, Harris, Waller Trans-Pecos Black Headed Snake Tantilla cucullata NL T Crockett <<>> Table 4.3.1-1 Threatened and Endangered Species of Possible Occurrence Within the Zone of Potential Impact of the Proposed Project (continued) Status3 Common Name2 Scientific Name2 FWS TPWD Counties of Potential Occurrence4 Potential for Occurrence5 Amphibians Austin Blind Salamander Eurycea waterlooensis C C Hays, Travis Barton Springs Salamander Eurycea sosorum E E Hays, Travis Houston Toad Bufo houstonensis E E Austin, Bastrop, Harris, Waller Jollyville Plateau Salamander Eurycea tonkawae C NL Travis San Marcos Salamander Eurycea nana T T Hays Texas Blind Salamander Eurycea rathbuni E E Hays Plants Navasota Ladies’-tresses Spiranthes parksii E E Bastrop, Fayette Texas Prairie dawn Hymenoxys texana E E Harris Texas Snowbells Styrax texana E NL Kimble Texas Wild-rice Zizania texana E E Hays Tobusch Fishhook Cactus Ancistrocactus tobuschii E E Kimble 1According to TPWD (2011) and FWS (2011) 2Nomenclature follows Hubbs et al. (2008), AOU (1998, 2000, 2002, 2003, 2004, 2005, 2006, 2007, 2008, 2009), Crother et al. (2000, 2001, 2003, 2008), Baker et al. (2003), TPWD (2011), and FWS (2011) 3E – Endangered; T – Threatened; T/SA – Threatened by similarity of appearance; DL – Federally delisted; PDL – Proposed for Federal Delisting; PE – Federally proposed endangered; PT – Federally proposed threatened; C – Federal candidate species; NL – Not listed. 4 Counties included are for both state and federal lists. More often, the state listed more counties for potential occurrence than the federal list. 5 Potential for occurrence within or immediately adjacent to new construction sites for Longhorn. <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL CHAPTER 4 FIGURES <<>> £ ¤ 90 ilibert Elbert Kirkpatrick £ ¤ 90 Tree Path Oak Brook " " )7 " )5 " Needham Maxey Pecan Pecan Grove Grand Hewrick Exchange Terminal Salina Iris Alderson Force Gainesville Longview Texarkana Eagle Pass Victoria Meters Exchange Terminal Laredo Hillsboro Waxahachie Hershe Hershe Terminal East Grimes Waller Fort Bend Birmingham Parkhurst Nashville King Queen Amy Miley Attwater Barton Sparta Ina Amy Fairchild Clu Peab Eastover Nashville Betty Boop Henson Henson Queensl Mesa Railspu Belroit Nielan Spikewood Express " Earhart Nielan Midway Haight Sunbury Ethel Ethel Fleta Chateau Saint Louis Bacher Blue Bobby Burns Queensland Norwich Wileywood Crim Foxfern Howton Turtlewood Lewiston Fairchild Boy Howton Filltop Wedgefield Dollar Danshire Lodgepole Little Wayside Jeffery Fitzhugh Oates Miley Knute Perch Creek Foxhunter Attwater Attwater Harris County Cemetery Barnesworth Edenglen Kenton Pinewest Nordic Angus Northlake Pinewest Sandy Fowlie Fernlake Hanna Hanna Thrasher Cinderella Sparta Hollow Pines Northport Homeview Wood Bend Flair Dartwood Sparta Bonaire Tommye Barlow Bonaire Queensland Teal Teal Rainy Sun Javelina Beau Harp Tatefield Tate Manton Wonfour Booker Eastland Kelford Nielan Tate Penelope Callixtus Comets Run Lourdes Wayside Fields Balfour Fields Evangeline BC ELMORE MIDDLE Swoopes Wynnewood Amayas Lake Houston Ina Amy Fairchild Sexton Hollow Pines Lorne Lorne Merry Meadow Meyersville Hopetown Pandora Gorman Graycliff n n Gates " )4 " )8 " )7 Seclusion Morinscott Pardee " Gloria " )6 " Janeths Ranger Rand Rand Liberty " " ï " )6 Circle Drive Park Debra " Hollow Pines Trail Wind Callahan Wood Bend Wallisville § ¨ ¦610 Millard Settegast Millard Romea " )3 Shadrack Normandy Ranger " Citypark O S T Guessena Clara G Herschell Colvin Royce Green Dolphin r e en " )9 Cibolo Holland Dattner s " £ ¤ 90 Saltillo Harvey Bayou Manitou Coahuila Groveland Terrace Park Rafael San Pedro Texaco Thornhill Oaks Wayside Carlos ï Banner Santa Cruz Zaballos Old Pine Killene Ophelia Old Spring Old Pine Ripplewood Amoor Beaver San Carlos Herald Mesa Texaco Country Club " )2.31 Alsuma Aguila Villita Eve Claudia s Forestwood Wood Hidden Castle " Farqueson EAST HOUSTON " " Trailmobile Baca Profet " )9.47 La Retama Coolgreen Corridor (PB 4) Coolgreen ï Stillington " )5 Hunt " Glenstone Strickland Park Tammarack i Wild Plum Highridge ï Oates o u B a Eastbrook n g y Spaniel Labelle Woodforest Labelle Rauch Brown (Herman) Park Charlie Voix ï Glesby Wood Forest La Grove Province Point Chambly La Riviera Aire Neuville Bienville Aire § ¨ ¦610 Wood Forest Bowhead Woodbuck Badgerwood Wood Smoke Woodforest Coolwood Wood Vista Woodhurst Saint Edwards Green Dijon Beaupre Point Toulouse La Rochelle Halifax Saint Michel Chalmette Versailles Corsica Nice Rue Fontaine Cheam Woodshaver White Water Borderwood Wood Mist Joliet Wood Bayou Dijon Joliet Laredo Dividend Crystalwood Coolwood Woodcliff Touche Fawn Corpus Christi Peoria Orleans Hillsboro Ranger Waxahachie Pearl Aleen Hershe Portwall Currency East Community College Broadstairs Dunvegan Brockhampton Heysham Oldcastle Cappamore Garrick Rainy Meadow Baca Garrick Filey Soft Shadows Wild Wind Donnacorey Caney Buffalo Falloon Fox Elk Royale Addicks Normandy Crossing Grand Oaks Peoria Redondo Rosewick Emporia Lafferty Oaks Falloon Knollcrest Lafferty Oaks Lyons East " Mile Post Land Use Montgomery Switzer Fleming Valencia Housing Density Kilroy Wild Wind " " )4 Wood Shadows Summerwood Church Maple Liberty Westshire Valencia Wood Shadows Coolwood Bluemist Mae Westmont Æ P Healthcare Facility Developed Duncum Aleen 0 - 20 Units/Mile Duncum n School Forest East 21 - 100 Units/Mile John Ralston Centerwood Autumnwood Fleming Greatwood Sachamo I Roundtree Environmental Assessment Longhorn Pipeline Reversal ï Park § ¨ ¦10 Lear Gellhorn Wetlands >100 Units/Mile Luther Greens Bayou Garber Dawnwood Figure 4.1.2-1a Harris s Country Club/Golf Course Agricultural Rumar La Crosse La Crosse Walkway Baca Verano Maxey Sheffield Halsey McNair Houston Area Land Use Akron ² ¶ Overnight Lodging Loop Loop La Crosse Open Water Muscatine Dacus Muscatine Shrub/Scrub Fidelity Oates Flint Challenger 7 Invierno Hunting Bayou Mae Keyport Falcon and Housing Density East § ¨ ¦10 Nimitz Portwall SHEET 1 OF 9 Longhorn Pipeline Brazoria Galveston 0 0.5 1 Candy Laurentide Siesta Oates Keyport Oswego Meris Prepared By: Atkins/19685 Market St Dove Barcus Scale: 1:24,000 Barren Land (Rock/Sand/Clay) Kilroy Mae Maxey Job No.: 100019708 Dwight Lear Land Use Source: USGS 2006 NLCD Fannette Palestine Falcon Miles Dewey Date: Apr 10, 2012 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Market Street Berndale Switzer Palestine Akron Fig_4.1.2-1a-i_Houston_HousingDensity.mxd Rye tville Silverdale Tilgham Wiggins Gellhorn Cowart Norvic Kilroy Cowart Mercury Walkway Sheryl Horatio Tilia Judy Kathryn Yancy Kathryn Alice Elsies Sarahs Capistra Yancy Vickie irley Nola Nolas Blythe Berwick Vicksbur Chelto Laguna Candlewick Rockglen <<>> Laredo Hillsboro Waxahachie Hershe East Pearl Aleen Lyons Aleen Rye Silverdale Portwall Wiggins Gellhorn Munn Demaree Silverdale Fillmore Cargill Richcroft Northton Grimes Waller Portwall Teanaway Pleasantville Demaree Teanaway Bucroft High Level Fort Bend end Currency Community College Broadstairs Dunvegan a Brockhampton Heysham Oldcastle Cappamore Garrick Rainy Meadow Baca Garrick Filey Soft Shadows Wild Wind Donnacorey Caney Buffalo Falloon Fox Elk Royale Addicks mandy Crossing Grand Oaks Peoria Redondo Rosewick Emporia Lafferty Oaks East Falloon Knollcrest Lafferty Oaks Switzer Fleming Valencia Kilroy Wild Wind " " )4 Wood Shadows Summerwood Church Duncum Westshire Valencia Wood Shadows Coolwood Bluemist Mae Duncum East John Ralston Centerwood Autumnwood Fleming e n s Ba y ou § ¨ ¦10 Greatwood Sachamo Roundtree Gellhorn Luther Garber Greens Bayou Dawnwood Rumar La Crosse La Crosse Walkway Baca Verano Maxey Sheffield Halsey McNair Akron Loop Loop La Crosse Muscatine Dacus Fidelity Muscatine Oates Flint ² ¶ Hunting Bayou Mae Keyport Falcon East Gr e Maple Westmont Lear § ¨ ¦10 Candy Laurentide Challenger 7 Invierno Siesta Market St Oates Oswego Keyport Nimitz Meris Dove Barcus Kilroy Mae Fannette Maxey Dwight Lear Palestine Berndale Tilgham Wiggins Switzer Palestine Falcon Dewey Market Street Akron Cowart Cowart Norvic Kilroy Mercury Walkway Sheryl Horatio Tilia Judy Kathryn Yancy Wiggins Burman Kathryn Alice Elsies Sarahs Pattibob Pillot " )3 Celtis Seagram Capistrano Yancy Vickie Dorwayne Powell Josie Munn Hart " Lord Chadwick Flossie Mae Maryknoll Falcon Shirley Celia Berthas Century Kerbey Hiller Myrtle Othello Ledwicke Quaker Flaxman Flaxman Fairfax Guinevere Chazen Cheston Caspersen Serpentine Peppertree Coulson Adelia Coulson PYBURN EL Industrial Mylla Sheffield n Peggys Lanewell Lane Lanewell Jennifer Maricopa Watkin Rita Belin Janey Samuel Lila Strick Fillmore Flagship § ¨ ¦610 Cargill Harcroft Miles Bucroft Dunaway Pinky Birdie Parkey Ellen Richcroft Kerr Claudia Cain Tuffly Holland Masterson Turning Basin Kayla Garcroft Kitty Signet Plummer Main Stedman Ledger Bennett Industrial Turnbow Veyblum " )2 Nedwald " Racine Mimbrough Pelsey Fidelity 19th 18th Tite Tite Tennessee 16th Benson Westway 18th 17th Eastway 17th Parkside 18th 17th Sol Mississippi 15th Hunter 16th Calloway Wolfe Calloway 14th Borden Clearwater Leggett 15th 15th 15th Crown Pugh 14th Keene Maxine Georgia 13th Cartersville Craig Westway 14th 13th 13th 13th American Petroleum Teal Defender 12th Zuber Owens 12th 12th Owens North Carolina 11th Center 12th De Haven 10th Sage Zachary Leggett 11th 11th 10th 10th " )1.23 Gate 1 De Haven Midway Bolden Clinton Park Bolden Bank 9th Craig 9th Delaware 8th 8th Pennsylvania 7th Westway 9th 8th 8th Sinclair 9th Galena Crown " River 7th Parkside Wolfe 8th 7th Rhode Island 7th Armstrong Armstrong 6th 6th 6th 6th 6th 6th Gans Loop 5th 5th Gans Loop Connecticut 4th Graham McConnico Westway 5th 5th 5th 5th 4th 3rd 3rd Westway 3rd Sinclair 4th 4th Eastway Stewart 3rd Crown 2nd " Witter Mile Post Land Use Housing Density Liberty Æ P Healthcare Facility Developed 0 - 20 Units/Mile n School Forest 21 - 100 Units/Mile I ï Park Wetlands >100 Units/Mile Harris s Country Club/Golf Course Agricultural ² ¶ Overnight Lodging Open Water Longhorn Pipeline Shrub/Scrub Brazoria Barren Land (Rock/Sand/Clay) Galveston 0 0.5 1 Land Use Source: USGS 2006 NLCD Miles Blythe Berwick Cimarron Mobile Oakstone Vicksburg Chelton Laguna Candlewick Glenalbyn Rockglen Kokomo Bandera Utica Evanston Duluth Boise Topeka Uvalde Haden Taylor Jackson Clinton Federal Montgomery Jefferson Olin Mathieson 1st Environmental Assessment Longhorn Pipeline Reversal Figure 4.1.2-1b Houston Area Land Use and Housing Density 1st SHEET 2 OF 9 Prepared By: Atkins/19685 Scale: 1:24,000 Job No.: 100019708 Date: Apr 10, 2012 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.1.2-1a-i_Houston_HousingDensity.mxd Ironwood <<>> Shady ï Tidwell Park Lockern Styling Barnham Bainbridge Wicklowe Onslow Bucknell Castleton Wolbrook Envoy Bretton Hollyglen Royal Oaks Rockaway rwick Bainbri Langley Onsl Briarwick Wo S Allwood Ferol Ina Fala NORTHEAST CHRISTIAN Okay n Marilyn Orlando Lera " )14 Tully W E ROGERS EL Spinet Navasota Melanie J L Reaux n n " Saunders Gleason Park Scenic Woods Park ï Woodwick Forest Hollow Gore Blades ï Rebel Lakewood Kelburn Mayberry Lakewood Colton Boggess Cockburn Lakewood Boggess Deanna Lebra Harmaston " )13 Parker Everglade " Wiley Yoe Yoe Stonewood Madera Nyssa Haddick Nyssa Yoe Rhobell Cheeves Rhobell Charlesmont Rhobell Caddo Ribbonwood Kentshire Thorn League Madera Deanna Caddo Rebel Bigwood Woodwick Hillis Caddo Bigwood Sterlingshire Haddick Arvin Bella Pine Sterlingshire Cabot Matson Cabot Maddox Sterlingshire " )12 Thorn Cabot Claiborne Galaxy Claiborne Farragut Bretshire Locksley Claiborne Maddox Greenwich Cabot Hillis " Gillman Lum Denning YES PREP NORTH FOREST CAMPUS Claiborne n n n n Trumpet Kerry Glen Caballero Courben Alcanterra Linares Shive ll s B a y o u H a Hallshire Hamlet Hanford Locksley Hillis Guest KIRBY MIDDLE Alcala Gallahad KIPP VOYAGE ACADEMY FOR GIRLS Tidwell Maddox KIPP POLARIS ACADEMY FOR BOYS Hamlet KIPP LEGACY PREPARATORY n n n n n n Halls Bayou Park (PB2) Balsam Tidwell Pereida ï Mosswood KIPP NORTH FOREST LOWER KIPP NORTH FOREST LOWER GIRLS " )11 Wiloak ï " Sundown Count Count Seeker Hillis Parkette East Tidwell Park Record Record Haddick Bean Lake Forest Park Southwark ï Firnat Teesdale Snowden Snowden Arvin Fringewood Forest View Pembrook Bellingham Sunderland Lanewood Kelburn Crofton Levering Lynette Tremont Kellett Kellett Kellett Lake Park Mirawood Spaulding Sherbourne Kellett Way Lazydale Lake Forest Sundown Wayside Talton Monterrey Talton Talton Roane Livings Surry Chatwood Leighton Shreveport Fawnridge Homewood Seeker Burl Homewood Spode Glen Manor Compton Laura Koppe Darien Woodwick Woodlyn Woodlyn Arlen Sultan Homewood Laura Koppe Laura Koppe Laura Koppe Touchstone Springdale Settegast Oak Knoll Oak Knoll Linda Vista Las Cruces Woodlyn Grandriver Linda Vista Oak Knoll Strathmore Banting Touchstone Denton Westcott Bywood Parkhurst Richland Feland Linda Vista Weyburn Leben Weyburn Wayside Crestview Mestina Crestview Richland Carolwood Carolwood Hall Flintridge Flintridge Knoll Darlington Darlington Carothers Palo Blanco DeWitt Palo Alto Orville Green River Orville Winship Green River Delavan Larkstone Weaver Herschell Houston Leycrest Ley Landor Elbert Darien Finch Furray Tremont Furray Fitzhugh Las Cruces Tipton Finch Finch Dockal Pond Kittridge Lebate Brim Safebuy Roundhouse Senna Ritz Safebuy Banyan Penrod Cluett Peabody Joy Birmingham Tommye Railwood Parkhurst Eastover Nashville Nashville Betty Boop Henson Queensland Mesa Railspur Belroit Henson Nielan Spikewood Apache Express Elbert Earhart Philibert Nielan Midway Haight Sunbury King Ethel Grimes Kirkpatrick Ethel Queen Fleta Chateau " Saint Louis Bacher Mile Post Land Use Montgomery Blue Bobby Burns Queensland Norwich Liberty Æ P Healthcare Facility Howton Amy Fairchild Boy Howton Filltop Wedgefield Dollar Housing Density Developed Miley Waller n School Little Wayside Jeffery Forest Fitzhugh 0 - 20 Units/Mile Miley Knute 21 - 100 Units/Mile ï Park Attwater Wetlands Attwater Attwater >100 Units/Mile Harris County Cemetery Harris s Country Club/Golf Course Kenton Agricultural Angus ² ¶ Overnight Lodging Sandy Fowlie Open Water Hanna Hanna Fort Bend Longhorn Pipeline Barton Shrub/Scrub Cinderella Sparta Sparta Brazoria Sparta Barlow Barren Land (Rock/Sand/Clay) Galveston 0 0.5 1 Land Use Source: USGS 2006 NLCD Bonaire Tommye Bonaire Queensland Tree Path Oak Brook Ina Amy Fairchild Tatefield Tate Tate Manton Penelope Wonfour Kelford Nielan Callixtus Comets Run Miles rchild Wayside Booker Fields Eastland Balfour Fields Evangeline BC ELMORE MIDDLE Swoopes Wynnewood Amayas Pandora Meadow Bend Garden Gale Roxdale Ridge John Ralston Cay Sol Kona Cay Islamorada Jasamine Path Island Song Hazy Hill Valley Hollow Valley Lake Valley Mill Valley Park Valley Side Brock Park Valley Sun Valley Breeze Valley Flag Valley Club Valley Club Valley Meadow Valley Ledge Valley Wind Valley Wind Valley Rock Valley Song Valley Forest s Brook Park and Golf Course " )10 " Brock Park ï Scenic River Rio Verde Palo Verde Cyrl Spicewood Ley-Green River Housely Danvers Park Trail Drifting Winds Coral Reef Blue Island Aloha Trail Ginger Lei San Fern Forest Enchanted Path Drifting Winds Parkway Forest Yvonne Barker Crenshaw Lambert Ticonderoga Nodding Pines Robert E Lee Redbird Green River " " )9 Bridle Path Heather Row Westgard Jeanne Pamela Clark Wheeler Kindred " )8 " C E King Gregdale Westbay Bracrest Lake Houston Charpiot £ ¤ 90 Greens Bayou £ ¤ 90 Oates I Crim Foxfern Wileywood Lodgepole Turtlewood Danshire Environmental Assessment Longhorn Pipeline Reversal Perch Creek Figure 4.1.2-1c Barnesworth Houston Area Land Use Foxhunter and Housing Density SHEET 3 OF 9 Thrasher " Prepared By: Atkins/19685 " )7 Scale: 1:24,000 Teal Teal Javelina Job No.: 100019708 Date: Apr 10, 2012 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.1.2-1a-i_Houston_HousingDensity.mxd Lake Houston Seclus <<>> Slater Hill Erwin Chrisman Collins dy Hartwick Wedgewood Birchwood Mooney Hardy Toll Chamberlain Kitchener Woodcourt Cliffside Parkstone Oak Glen Brooklyn Mesquite Isom Aldine Westfield " )18 " Aldine Park Exeter Havner Sunny Maymount Norlinda Rusty July Hartley Gloger Winfield Eastex Hillside Collins Illene Gaston Charwon Hartwick Harmon Van Zandt Percy Haile Allwood Hanley Mohawk Warner Askins Lakeside Royal Lake Pine Island Smith Westway Peaceful Hermann Mount Houston Sheridan Sherway Cayey Micollet Tomahawk Indian Spring Cobble Hill Arrowrock Flatrock Knotty Pine Lone Shadow Furay Palmala Moray Owl Roost Fernlea Leedale Ledford Burningbush Hedgewood Pinehook Haverton Pittswood Heath Ensworth Thackery Lone Oak Michulka Hardy Hardy Toll Hardy Toll Hardy Irvington Grimes Waller Exeter Exeter Fort Bend Bethany Winfield Fall Meadow Blue Meadow Sandy Meadow Pear Meadow Pine Meadow Hay Meadow Shady Meadow Plum Meadow Connor Hirsch Sugar Ridge Vickery Hermann Mandy Brunswick Orange Grove Orange Northington Daun Varnell Magnolia Sachar Elberta Huse Keith-Wiess Park ï Ashworth Northpost Justin Justin Collins Danford Foxhill Mierianne Oakville Washington Collins Gaston Roughlock Mierianne Gaston Gaston Suburban Ruby Rose Rechelle Gaston Bertrand Korpink Charwon Task Mesquite Sam Houston Monitor Micollet Fishel Lera Micollet Merrimac Cobalt Castledale WORSHAM EL Castledale Cobalt 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Maddox Claiborne Environmental Assessment KIRBY MIDDLE Hamlet Hanford Locksley Hillis Guest Longhorn Pipeline Reversal Gallahad KIPP VOYAGE ACADEMY FOR GIRLS Tidwell Wetlands Maddox KIPP POLARIS ACADEMY FOR BOYS Hamlet Figure 4.1.2-1d KIPP LEGACY PREPARATORY n n n n ï Park >100 Units/Mile Halls Bayou Park (PB2) Houston Area Land Use Harris s Country Club/Golf Course Agricultural Pereida ï and Housing Density Mosswood KIPP NORTH FOREST LOWER KIPP NORTH FOREST LOWER GIRLS Wiloak ² ¶ Overnight Lodging Open Water Hillis Shrub/Scrub Sundown Count Count Seeker Record Record Haddick Bean SHEET 4 OF 9 Southwark Longhorn Pipeline Barren Land (Rock/Sand/Clay) Firnat Prepared By: Atkins/19685 Scale: 1:24,000 Brazoria Galveston 0 0.5 1 Land Use Source: USGS 2006 NLCD Pembrook Teesdale Snowden Snowden Arvin Fringewood Job No.: 100019708 Bellingham Date: Apr 10, 2012 Sunderland Lanewood Kelburn Lynette Spaulding Sherbourne Crofton Levering Miles File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.1.2-1a-i_Houston_HousingDensity.mxd Tremont Kellett Kellett Kellett Sundown Wayside Way Talton Talton Roane Livings Surry Leighton Shreveport Fawnridge Homewood Seeker Burl dwick York Skinner Margaret Trippel Charles Cresline Mayberry Lakewood Cockburn Wellington Roxella Exeter Schilder Montgomery <<>> Stuebner Park Halls Bayou Hardy Walston Luthe Connorvale Anice Reeveston Sandydale Charriton Debeney Washington Lincoln NITSCH EL Lovington T C Jester Fort Royal McKinley Big John Royal Place Royal Village Royal Sage Colter Forest " )24 " Jorent Paradise Cemetery McCrarey Cliffmarshall Bonazzi Proswimmer Gloyna Whitehead Lonallen Cadiz Mallorca Travelers Gibraltar Avila Piedmont Hermitage Estaril Spur Manacor Almenar Cordoba Tara Cordoba Pine Desert Jorent Fallen Pine Joseph Pine Drayton Anthony Pine Rosslyn Pine Landing Logger Pine Trails Hardy Toll Regena Slater Chrisman ¬ «249 Cora Isom Carmilenda Hill Erwin Lone 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Hambrick Dogwood Tree Holtman Busch Dale Aldine Mail Hawkins Nicar Lorino Connorvale Corvette Walston Corvette Isetta Charriton Sweeney Dalewood Sunwick Burtcliff Landfair Sellers Stoneshire Henry Lillja Kershaw Lyngrove RALPH G GOODMAN Twin Falls n n Rim Rock Dormstom Still River Helms Valwood Mosher Valley Stream Westbrook Helms Cheswick Aldsworth Beaver Bend Sprads Helms Hill Scoregga Burford Barnsley Glen Shadow Deer Trail Beaver Bend Twinbrooke Twinbrooke Mosher Hidden Valley Mosher Hidden Valley Cobbleshire Beaver Bend Beaver Bend Rainy River Rocky Mount Rocky Mountain Roberts Robertsvale Courrege Woodmoss Jaycrest Faber Pine Vale Braunston Twinbrooke Ella Ella Boulevard Hike and Bike Trail Deer Trail Saddle Rock Rainy River Bunzel ï Hidden Valley Saddle Rock Colendale Donley Terrydale " )23 Rainy River Rainy River Saddle Rock Rutherford Ivy Spring Glen Echo Peach Spring Peach Spring Peach Spring Cobbleshire Glenbury Rockcliff " Ryton Bedworth Brackley Bisley Glenhouse GLF Bank 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Figure 4.1.2-1f >100 Units/Mile Houston Area Land Use Harris s Country Club/Golf Course Agricultural and Housing Density ² ¶ Overnight Lodging Open Water SHEET 6 OF 9 Shrub/Scrub Fort Bend Longhorn Pipeline Brazoria Barren Land (Rock/Sand/Clay) Galveston 0 0.5 1 Land Use Source: USGS 2006 NLCD Miles Battleoak Battle Plains GLF Bank Gulf Bank Empire Central Regal Brookhollow West Prepared By: Atkins/19685 Scale: 1:24,000 Job No.: 100019708 Date: Apr 10, 2012 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.1.2-1a-i_Houston_HousingDensity.mxd <<>> Berwick Berwick Whithorn Splintered Oak Wimbledon Oaks Overton Fallsbridge Turnbridge Azalea Creek Apple Forest Birch Falls Hillside Glen Carriage Lake Rabbit Oak Tara Oak Belmont Piney Oaks Oak Acres Pecan Oak Oak Limb Pear Oak Den Oak White Cliff Wolsley Wortham Grove Durbridge Trail Bretford Bainbridge Wortham £ ¤ 290 Wortham Center Dr Village Trail Wortham Park Sam Houston Wolfe Fox Highway 6 ² ¶ " )34 " " 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Satsuma Land Use Source: USGS 2006 NLCD Hertford Park Miles File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Regal Fig_4.1.2-1a-i_Houston_HousingDensity.mxd Brookhollow West aldron llfield Manor Covesville Ringfield Felgate Creek aurel Windfall Beltway 8 Brookside Forest Payette Oak Pines Windfern Fore Wind Free Windell Windoak Wind Cave Windy Oaks Windlea Wind Forest M W Wind Law Philippine Prepared By: Atkins/19685 Smithstone <<>> I Harris Fort Bend Waller Montgomery Liberty Brazoria Grimes Galveston 0 0.5 1 Miles s ï ï ï n n n LEADING STARS MONTESSORI LABAY MIDDLE Park Cullen Park (Lease) Hearthstone Country Club FM 529 Jackrabbit Forest Heights Greenhouse Gummert Sandalfoot Coventry Park Silver Sky Shangrila Judyleigh Kite Hill Glenledi Blazey River Garden Elmont Lerwick Sommerall Lyford Royal Gardens Rebel Yell Lobo Wimbledon Kentwick Club Lake Santrey Wild Willow Ridge Park Huffmeister Queenston Alden Glenpatti Laurel Macleish Bouldgreen Vanlynn Allerton 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Place Broken Ridge Scarlet Oak Riverglade Plantation Tree Morrisglen Travis Point Longdale Golden Pond Waylord Brook Springs Caldermont Dewcrest Stratwood Morningshine Rittenberg Cashel Point Cedar Point Blushing Pear Barley Mill Langbrook Holly Falls Wicker Willowland Black Gap Arbor Park Westhall Pleasant Lily Sand Hill Glen Tree Lark Belleshire Glen Shady Palms Dawson Mill Elm Point Wisteria Ridge Pipingwood Millbrae Autumn Hills Weatherhill Clan MacIntosh Grackle Sunny Ridge Sky Blue Concord Dew Drop Wild Willow Poppy Trails Somersworth Sky Blue Ash Wild Willow Glenpatti Clan MacGregor Grampin Sunbury Stone Pine Capri Stonerun Sonnet Glen Fieldglen Sugar Ridge Goodman Applecross Macleish Maplemont Kilwinning Rigdale Prairie Village Greenhouse Langham Andiron Langham Summer Dew Oak Glen Harrow Carbridge Livery Grackle York Spring Forest Trails Glenmark Battlecreek Carbridge Laguna Maplemont Autumn Hills Brenwood Trailside Owens Langham ¬ «6 ¬ «6 Langham Creek Dinner Creek H o r s e pe n C r e e k Environmental Assessment Longhorn Pipeline Reversal Figure 4.1.2-1h Houston Area Land Use and Housing Density Prepared By: Atkins/19685 Job No.: 100019708 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.1.2-1a-i_Houston_HousingDensity.mxd Scale: 1:24,000 Date: Apr 10, 2012 Land Use Source: USGS 2006 NLCD SHEET 8 OF 9 " Mile Post Æ P Healthcare Facility n School ï Park s Country Club/Golf Course ² ¶ Overnight Lodging Longhorn Pipeline Land Use Developed Forest Wetlands Agricultural Open Water Shrub/Scrub Barren Land (Rock/Sand/Clay) Housing Density 0 - 20 Units/Mile 21 - 100 Units/Mile >100 Units/Mile <<>> Village Kolbe Laura £ ¤ 290 Telge Berwick " )42 " Berwick " )41 " Fry Whithorn Grimes Montgomery Waller Harris Fort Bend Cypress Villa Hilltop Park Jadestone Creek Barker Gate Barket View Woodwind Shadows Mystic Grove Bandit Trail Cactus Point Muleshoe Trail Brook Riata Ranch Desert Stoney Falls Ruby Canyon Stone Prairie Lake Riata Belwood 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Cottonwood Canyon Falcons Cove Cliff Haven Bald Ridge " )38 Caldera Canyon Palisade Lakes " RENNELL EL Meridian Lakes Hahns Peak Pinon Vista Red Mesa Port Erroll Pine Flats Temple Houston National Golf Club Barrett Post Adobe Bluff Springs s n n Tuckerton Mesa Point Kirkton Wakefield Village Chestnut Bluff " )37 Oxford Grove Cape Breeze " Tuckerton Drif Copper Mist Danbury Bridge Burkhart Ridge Beckwood Post Coleburn Walford Mill Bark Ridge Wheaton Edge Locust Springs Pine Bank Queenston Coyote Creek Pine Castle Sperry Gardens Libson Falls Greenbriar Point Torridon Mammoth Springs Shorewood Lakes Dunain Park Find Horn Balvenie Rosewell Brechin Appin Bowmore " )36 Speyburn " Farley Pass Gaslamp Curry Landing Copperbluff Bristle Creek Vander Rock Aberdeen Green Starlamp Sunlamp Aberdeen Lake Abergreen Newburgh Newlight Bend Copper Cove Grenada Falls Catawissa Aberdeen Park Aber Trail Green Castle Guiness Shango Bonnyview Swandale Sweetrose Green House Taftsberry Berkshire Forest Green Smoke Aberdeen Oaks Angel Hill Whitaker Creek Sherina Park Rosehe Blaire Tall Aberdeen Trails Wheat Cross Raven Canyon Mosbriar Distant Woods Dawnblush Apple Mill Red Hill Cade Kentwa Jamie Lee Spring Jamie Lee Rock Arbor Lilac Spring Ambermist Red Falls Floralgate Lasting Light Light Fall M Hollow Bay Gentle Stone Brinton Golden Sands Oak Mountain H o Kinrush rs e p Pool Creek Laurel Trails Pine Falls Spruce Mill Sunny Ridge Canton Park Canton Park Wheaton Forest Cascade Hollow e n Torry View Gentlewood Star Hollow Country Brook Cree k Crystal View Sparkling Springs Spring Green Oak Mountain Greenleaf Lake Copperbluff Shoal Lake Rippling Brook Timbercraft Lake Crystal Bright Grove River Cliff Drystone Copper Village Broken Timber Plum Lake Highfie Secret Branch Meadow Crossing Sandestine Candlerock Lake Crystal Misty Trail Langham Creek Park Windy Thicket Morning Oak Woodland Knoll ï Bending Branch Sunrise Meadow Shining Rock Cypress Laurel Amber Mist Summer Reef Island Manor Stoneside Innisbrook Moncur Harvester Crossfield Willingham Elmbank Hot Springs n n Pinyon Creek Ferncliff FIEST EL Town Creek Silent Cedars Oak Park Bend Quiet Dawn Oak Glen Fairgrove Park Copper Lakes Millrun Ashton Millers Lakedale Wellers Timber Mist Gable Oak Laguna Springs Copper Shore Millridge Millshire Oat Mill Battlecreek Sweetwater Creek Silver Fir Chimneystone Wemyss Bay Cairngorm Maple Brook Ivy Bridge Willow River Ri Longenbaugh Sun Terrace Morning Rose Mill Village Crescent Canyon Preston Springs Barley Mill Salinas Dawson Mill Leamington Kintyre Point Sunny Ridge Highland Canyon McCormick Viney Creek LABA Ashton Hickory Cove n n Holly Falls Park Hollow Villa Lake " Mile Post Tawny Bluff Æ P Healthcare Facility Chatham Springs Redwoo Manor High Knoll Rustling Aspen Leaf Point Land Use Housing Density Tall Maple Silver Ash Ivy Trail Scenic Lakes High Village ï Cross Falls Developed Rustic Lake Forest Terra Canyon Dusty Yaupon Poppy Grove Indian Desert Royal Gardens 0 - 20 Units/Mile I Peach Forest Highland Farms Hidden Oaks Environmental Assessment Heather Heights Springville Spruce Haven Shady Palms Knolls Lodge S n School 21 - 100 Units/Mile Wetlands ï Park Galleon Field Cliffsage Desert Moon Yaupon Ranch Praire Bluff Black Gap Wild Willow West Gate Park >100 Units/Mile Crestbrook Manor Mossy Ridge Feather Springs Forest Heights Meadow Heights Colony Point Misty Fern Granite Ridge Autumn Laurel Shangrila Longhorn Pipeline Reversal View Park Park Falls Signal Creek Rainbow Lake Crested Hill Agricultural Westhall Lone Meadow Western Pass Figure 4.1.2-1i Brook Springs Hayward s Country Club/Golf Course Laurel Trail Brockland Windgate Garnercrest Gable Saxon Almond Springs Poplar Hill Garden Hill Hidden Shadow Open Water Sisterdale Prarie Fire Sundance Trail Kenmark Ridgegrove Masonridge Wildwood Brook Forest Dawn ² ¶ Overnight Lodging River Pines American Holly Crown Meadow Magnolia Shadows Plumtree Forest Wisteria Ridge and Housing Density Evergreen Brook Houston Area Land Use Elm Point Club Lake Creek Glen Windy Glen ¬ «6 Stratwood Pheasant Grove Shrub/Scrub Yaupon Mist Yucca Field Knoll Lake Hollow Cove Autumn Manor Hickory Point SHEET 9 OF 9 Longhorn Pipeline Maple Point Clairson Colefield Grand Terrace Hamilwood Dogwood Falls Sheffield Bend Narcissus Brook Kransburg Ranch Eastwood Scarlet Oak Barren Land (Rock/Sand/Clay) Haley Falls Wimberly Park Brazoria Galveston 0 0.5 1 Land Use Source: USGS 2006 NLCD Stoney Haven Winston Hill Bubbling Brooks Maplemont Maplemont Maplemont Prepared By: Atkins/19685 Pebbleglen Job No.: 100019708 Odinglen Lakeview Haven Scale: 1:24,000 Ridge Park Mesa Gardens Pleasant R Date: Apr 10, 2012 Echo Lodge Hollow Ridge Broken Ridge Westcliffe Village Lake Greenwood Point Oleander Ridge Livery Swan Valley Connemara Heathridge Liner Boysenberry Daylight Foxton Place Sutton Falls Prairie Village Lapis Meadow Remington Grove Grackle Dove Field Legacy Pines Headland Haughland Crestbury Andalusian Hollow Field Ivory Crossing Broadelm Augusta Pine Terrace Park Slippery Elm Barton Oaks Sonnet Glen Miles File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.1.2-1a-i_Houston_HousingDensity.mxd Sunlight Skylight Dew Mist Silver Sky Crystalglen Postwick Starbridge Sugar Ridge Clear Valle Larkspur Hills Grackle Hazel Cove Lost Fable Dew Drop llant Glen Summer Dew Skybright Dew Drop Glenbrook Knoll nbank mmer Mist Summer Dew Palisades Heights Valley Creek Arbor Park berry River Garden Glen Chase L angh a m C re e k Liberty Raven Creek Bellwick <<>> Wolf " )156 " Fagerquist Jacobson Swiss Chalet Alps Alpine Bern Zurick Vevey Dobush Forest Glenn Panorama Timber Hills " )155 " High Noon " )154 Hayride " Fagerquist Maha Creek Maschmeier Wolf Pearce " )153 " High Ridge Stony Creek Maha Point Post Oak Stony Point Rock Creek Stony Mont High Ridge Algarita County Road 41 Edgemount Edge Rock Linden Burnet Blanco Hays Williamson Travis Bastrop Comal Caldwell County Road 255 County Road 364 Reines Brents Scrappers County Road 354 " Mile Post Æ P Healthcare Facility n School ï Park s Country Club/Golf Course ² ¶ Overnight Lodging Longhorn Pipeline Land Use Source: USGS 2006 NLCD Rainbow County Road 355 Land Use County Road 414 County Road 386 Developed Forest Headquarters Wetlands Agricultural Open Water Shrub/Scrub Barren Land (Rock/Sand/Clay) Caballo Privada County Road 256 Housing Density 0 - 20 Units/Mile 21 - 100 Units/Mile >100 Units/Mile Cottonwood Creek Shadow Wood Mockingbird County Road 110 Winecup Oriole County Road 301 High Point " )152 " " )151 " " )150 " Private County Road 348 County Road 350 County Road 347 I 0 0.5 1 Miles Environmental Assessment Longhorn Pipeline Reversal Figure 4.1.2-2a Austin Area Land Use and Housing Density SHEET 1 OF 7 Prepared By: Atkins/19685 Scale: 1:24,000 Job No.: 100019708 Date: Apr 10, 2012 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.1.2-2a-g_Austin_HousingDensity.mxd <<>> Colton Hillmoore Airline anda Foley Reservist Feller Dearbonne Gilwell Diwa Mathra Vizquel Bahan Lofton Cliff Sexson Ridge Tabitha Manowar Stretch Sea Biscuit Alysheba War Admiral Fryman Hill Clouds Reach Overlook Ranch Country View Rangeland Community Center La Guardia Algel Las Alas Los Dios Sky Harbor Paloma Blanca Country Meadow Country Mesa Campana Sky Park Sky Park Ross Los Cielos La Paz Quirin Thome Valley Coomes Winters Malarkey Alomar Nijmegn Perconte Lipton Welsh Pearce Night Sky Vida Nueva Ross Randleman Onion Creek Cottonmouth Creek General Aviation Richard Moya Park ï " )160 " FM 812 McKenzie Moores Bridge Linda Vista FM 973 " )159 " Bain San Jose Lonesome North Fork Dry Creek FM 973 Dry Creek Ponder Citation Man O War Ruidosa Engler Park Moores Crossing Darrin Hewers Tickford Apperson Gemmer Railton Maybach Kellner Wardman Proud Panda Iwanna Schebler Morning View Great Panda Arrowmound Towery Williamson Burnet " Mile Post Æ P Healthcare Facility n School Travis Blanco Bastrop ï Park s Country Club/Golf Course ² ¶ Overnight Lodging Hays Longhorn Pipeline Comal Caldwell Land Use Source: USGS 2006 NLCD Black Panda White Panda " )158 " Kellam " )157 " Elroy McAngus Housing Density 0 - 20 Units/Mile 21 - 100 Units/Mile >100 Units/Mile Land Use Developed Forest Wetlands Agricultural Open Water Shrub/Scrub Barren Land (Rock/Sand/Clay) Navarro Creek Alice " )156 " Fagerquist Plover Jacobson Swiss Chalet Alps Alpine Bern Zurick Vevey Dobush 0 0.5 1 Maha Creek I Miles Forest Glenn Panorama Timber Hills " )155 " Maha Creek Environmental Assessment Longhorn Pipeline Reversal Figure 4.1.2-2b Austin Area Land Use Linden and Housing Density Maschmeier SHEET 2 OF 7 Scale: 1:24,000 Date: Apr 10, 2012 Prepared By: Atkins/19685 Job No.: 100019708 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.1.2-2a-g_Austin_HousingDensity.mxd <<>> Clearday Star Meteor guin Congress Circle S elt Foremost § ¨ ¦35 Chaparral Corral North Bluff § ¨ ¦35 Boggy Creek " )166 " Boggy Creek Omni Shallowbrook Hayride Charles Goodnight Shaw McKinney Fa Onion Creek Williamson Creek Williamson Creek Meadow Atascosa Parell Ferret Galen Palo Blanco Walnut Grove China Berry Mesquite Grove Hickory Blackjack George Teri Jimmy Clay Icon McKinney Falls State Park ï Wagon Crossing Wagon Dove Springs Lakehurst Eastridge Bluff Westwood Commodore Stonleigh Bendridge Rockridge Bitter Creek Branchwood Blue Dawn Spruce Gum Elm Creek Deer Run LANGFORD EL Blue Meadow n Trendal Bitteroot Hyland Nogales Alegre Encanto Tranquilo Lendall Patsy Dan Eds Silverstone Quicksilver Ashley Edge Park Jenibeth Sunny Hills Muirlands Ardmore Barkdale Village Palo Verde Encinal Dove Dovemeadow Dovewood Dovehill Pino Dove Creek Leatherleaf Candletree Hammermill Turnstone Turtle Dove Wing Feather Softwood Flicker Creek Bend Teewood Brushy Ridge Avalon Ripple Raleigh Lambs Fontenay Bucks Granger Glade Line Meadow Lake Tournus Loire Misty Slope Magin Meadow Cliffridge Deep " )165 " Borage Vinca Saguaro Savorey Chateau Village Edge Creek Hidden Brook Ainez Village Square Nuckols Crossing Nesting Brassiewood Onion Creek Soccer Complex Vougeot Jimmy Clay Golf Course Canella Pleasant Valley Onion Creek Sand Hill Little Cypress Onion Crossing Onion Crossing Shady Cedar Catclaw Thornhill Springville Wild Onion Ladybug Thatch Firefly Vine Hill Glowworm Walkingstick Honeybee Onion Creek Katydid ï s William Cannon " )164 " Onion Creek Greenbelt ï Orleans Lake Charles Conti Rhett Green Grass Spring Fever Asa Running Water Crepe Myrtle Dixie Tupelo Salt Springs Marble Crest Redrick Cats Eye Springtime Tara Marl Piedras Blanco Marble Creek Bixler Roseborough Ringsby Villa Acuna Bannock Eudora Thaxton Verbank Villa Ken Caryl Rosenberry Bramble Bush Panadero " )163 " Zequiel Brockman Mozelle Cecil Perkins Old Lockhart Fall Meadow Forbsdale Georgie Trace Quinton Wiley Colton Bluff Springs Alum Rock Marble Ridge Briarton Marble Creek Broad Brook Flaxen Felipe Sabrina Doyal Walkup Deja Brandt Land Use Developed Forest Wetlands Agricultural Open Water Shrub/Scrub Barren Land (Rock/Sand/Clay) Cottonmouth School " )162 " North Fork Dry Creek Housing Density 0 - 20 Units/Mile 21 - 100 Units/Mile >100 Units/Mile Perimeter Burleson Norwood £ ¤ 183 Colton Cottonmouth Creek Colton Hillmoore Dee Gabriel Collins Colton " )161 Airline " Viewing Wanda Creedmoor Lava Hill £ ¤ 183 FM 1625 I 0 0.5 1 Miles " )160 " FM 812 Environmental Assessment Longhorn Pipeline Reversal Figure 4.1.2-2c Austin Area Land Use and Housing Density SHEET 3 OF 7 FM 973 Scale: 1:24,000 McKenzie Date: Apr 10, 2012 Prepared By: Atkins/19685 Burnet Blanco Grelle Nuckols Crossing Slaughter Cheryl Lynn " Mile Post Williamson Æ P Healthcare Facility n School Travis ï Park Bastrop Hays s Country Club/Golf Course ² ¶ Overnight Lodging Longhorn Pipeline Comal Caldwell Land Use Source: USGS 2006 NLCD Job No.: 100019708 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.1.2-2a-g_Austin_HousingDensity.mxd <<>> I Travis Hays Bastrop Williamson Comal Caldwell Burnet Blanco 0 0.5 1 Miles ï ï ï ï ï n n n n Æ P " " " " " " " " )171 " )166 " )167 " )172 " )168 " )169 " )170 LEGACY OAKS CHRISTIAN BOONE EL WILLIAMS EL TEXAS NEUROREHABILITATION CTR Dick Nichols Park South Boggy Creek Greenbelt Davis Hill Neighborhood Park Dittmar Park/Recreation Center Goat Cave Karst Nature Preserve 1st Dittmar Manchaca Old Lockhart Latta Deer Lunar Matthews Curlew Bluff Eskew Circle S Palace Doe Libyan Sahara Berkett Cooper Shiloh Nairn Eberhart Marsh Ramble Beckett Emerald Forest Woodhue Riddle Monarch Alexandria Leo Dunn Speer Cullen Longview Lear Lost Echo Miles Congress Mairo Tello Hubach Wynne Quicksilver Holt Davis Turtle Creek Armadillo Paisano Brodie Kandy Minturn Manassas Albert Ralph Ablanedo Convict Hill Drew Copano Wolftrap Lindshire Alcott Milford Norman Beard Forest Wood Squirrel Chisholm Idalia Finch Great Britain Mauai Aldford Oak Baxter Blarwood Shadywood Tetbury Iriona Windrift Wasson Coastal Harpers Ferry Elijah Strickland Stassney Sawmill Plantation Inridge Wyldwood Ovalla Norfolk Peaceful Hill Cannonleague Bissel Magee Corral Allred Willet Ganttcrest Tamil Thelma Toulouse Shep Nancy Slaughter Creek Radam Natali Yarsa Dixon Frock Sherwood Minnie Soho Cameron Lilac Croftwood Clarno Dalton Aftonshire La Cresada Pratt Nightjar Cecil Gail Blake Bill Hughes Cougar United Kingdom Vassal Mimosa Taylorcrest Parkside Blumie Hoffman Carlow Cloudview Keepsake Cortina Eganhill Headly Whispering Oaks Stonecroft Gobi Alta Loma Tiombe Elm Forest Silk Oak Axis Tecate Collingwood Sanford Shady Valley Stoneoak Seminary Ridge Bramble Francia Blackberry Islander Gate Jorwoods Nesbit Cedar Little Texas Avocet Texas Sun Berkeley Trede Reynosa Shadow Gettysburg Tiffany Verona Gaines Mill North Bluff Queenswood Evaline Treys Sunstrip Campfield Meadow Lea Capriola Reno Notches Wagtail Zuniga Salida Chaparral Cohoba Kentish Boxcar Clubway Capistrano Antelope Empress Cattle Loganberry Woodshire Hitcher Rochelle Huxley Creekline Trace Crow Sweet Clover Bilbrook Kempler Aldea Skynook Western Crownspoint Lancret Hill Kimono Ridge Wessex Texas Oaks Ramies West Gate Graybuck Buffalo Stanley Clearday Willers Neider Arbor Blue Valley Middleham Tensley Indian Point Whispering Winds Wilcrest Tea Rose Chippeway Red Bird Leadville Washita Idlewood Stormy Ridge Mockingbird Merriwood Ampezo Doliver Skyloop Jubilee Bremner Deatonhill Ranch Krollton Mojave Starstreak Meadow Creek Anna Spearson Brantley Blanco River McGregor Blueberry Foremost Brookhill Treehouse Struie Forest Heights Molokai Roxanna Stone River Zeke Harley Sunny Vista Eureka Oak Ledge Bankside Sir Gawain Piney Creek Latteridge Kavanagh Burly Oak Devine Bluestar Bradner King Albert Bodark Kestrel Reaburn Castlewood Hillston Kellywood Shady Hollow Clarksburg Steamboat Wakefield Alabama Glen Oak Redleaf Mozelle Dan Jean Taline Bobby Epping Calico Sendera Mesa Manzanillo Kearsarge Birmingham Flournoy Kenyon Cedardale Perkins Keota Alfred Romney Linton Wommack Barnsdale Darnell Steed Dunliegh Austin Highlands Tyhurst Silkgrass Greenock Old Manchaca Blythewood Trout Genoa Dulwich Alegre Austral Olguin Waycross Lazy Oaks Cache Firecrest Pecanwood Comburg Castle Salem Hill Mount Carrell Galesburg Bushnell Cannonwood Dunstan Hale Lancaster Linnet Sandra Bernoulli Goldbridge Dempsey Whitestone Hethcock Evanston Appomattox Salem Walk Rocky Ford Mulberry Navarro Lynnbrook Escabosa Hood Corran Ferry Cockburn Leafield Rocking Horse Dobbin Heartwood Hibiscus Valley Tinmouth Glenhollow Boggy Creek Starbright Aspen Creek Tranquil Hove Keswick Star Amber Moose Whitt Vigen Bannockburn Culberson Marchmont Sedgemoor Ruddington Chesney Ridge Simonetti Comburg Okner Molera Sarasota Campden David Moore Cornwall Baldridge Barge Lowdes Emerald Wood Jesse James Dryden Saloma Harwin Whitsun Heatherwood Raspberry La Naranja Linkmeadow Skycrest Stage Coach Acorn Oaks Swindon Roehampton Piping Rock Briar Ridge Walsall Lochinvar Wood Cliff Falcon Hill Hill Wood Brisbane Dulcet Bluesky Pannier Hackamore Shant Sugar Hill Harvest Jacky Bradsher Woodcroft Sika Fitchwood Korth Keilbar Wykeham Bender Greenland Huebinger Thistlewood Dandelion Margra Bryonhall Winterstein Hedgewood N Kings Brasher Tavistock Garden Oaks Deeringhill Broken Oak Brown Rock Foxton Canus Persimmon Mosquero Harleyhill Alderwood Glen Meadow Hyde Park Breezewood Buckingham Danli Meteor Teaberry Greycloud Grasshopper Velasco Rearden King Edward Palacios Pectoral Brecon Grennock Barasinga Caspian Counselor Saffron Hillside Oaks Doncaster Craigmont Boleynwood Minot Muskdeer Keneshaw Humming Bird Lenora Ainsworth Encanto Barnsley Malvern Hill Wood Bine Sunnysky Apache Forest Meacham Cheney Pusch Ridge Wales Fitzroy Kalama Arrow Edenwood Cayuga Wycombe Wishing Well Malone Shackelford Quivira Creekmere Bavaria Sheri Oak Swansons Ranch Croydon Brockman Loch Lommond Lambeth Estancia Bill Hickcock Lyric Collazo Gwendolyn Snapdragon Ivanhoe Towering Oaks Emerald Cretys York Bridge Holly Springs Hazen Fentonridge Lillian Huntingdon Hornet Rustic Oak Lagerway Twisted Oaks Crosswood China Nordham Sissinghurst Manipari Southwind Shelby Oak Teresina Brock Mabry Dillion Hill Charlesworth Sirocco Granberry Caladium Aylesbury Lanna Bluff Meadows Courtney Collins Wordham Garrettson Brodie Springs Cherry Meadow Steamline Denbar Jaffna Scottish Thistle Wilton Ibis Mesa Verde Silmarillion Tockington Wadsworth Siskin Dos Cabezas Boggy Ridge Triboro Cherry Mitchell Galapagos Fuente Belclaire Beaconcrest Azalea Blossom Copperas Rose Hill Independence Bloomfield Broomflower Fancy Gap Aoudad Plumpton Dee Tawny Tobago Gee Coyote Kansas River Chickasaw Dominic Galliano Lomita Verde Cannes Beauregard Dowling Barrow Glen Spruce Gum Ramblewood Ferndale Cherrydale Edge Park Treasure Gallop Oak Hedge Aletha Uvalde Whiteworth Salmon Evadean Leah Dan Ardmore Castledale Caymen Blue Lightwood Salem Meadow Bordley Amber Oak Saint Amant Grigsby Centralia Alcorn Mosswood Constantino Sarong Lewood Leisure Run Lishill Clydesdale Puckett gewell Orr Kittyhawk Apricot Shier Turquoise Star Grass Larson San Paublo Moat Apple Carrie Brickford Cloudberry Melville Cedrick Glen Hollow Kangaroo Ivory Key Irish Bend Tabor Calumet Shale Bexton Darvone Clearsky Kellywood Ranch Harvest William Cannon Glen Meadow Davis Cherry Gail Berkeley Gettysburg Meadow Chisholm Cattle Slaughter Creek Davis Oak Valley § ¨ ¦35 § ¨ ¦35 ¬ «1 ¬ «1 ¬ «1 Boggy Creek Slaughter Creek Williamson Creek Williamson Creek Slaughter Creek Williamson Creek Environmental Assessment Longhorn Pipeline Reversal Figure 4.1.2-2d Austin Area Land Use and Housing Density Prepared By: Atkins/19685 Job No.: 100019708 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.1.2-2a-g_Austin_HousingDensity.mxd Scale: 1:24,000 Date: Apr 10, 2012 " Mile Post Æ P Healthcare Facility n School ï Park s Country Club/Golf Course ² ¶ Overnight Lodging Longhorn Pipeline Land Use Developed Forest Wetlands Agricultural Open Water Shrub/Scrub Barren Land (Rock/Sand/Clay) Housing Density 0 - 20 Units/Mile 21 - 100 Units/Mile >100 Units/Mile Land Use Source: USGS 2006 NLCD SHEET 4 OF 7 <<>> " )178 " Antler Bend Weir Loop Michael Kay Rod Vikki Geneva Weir Loop Eitel Ledgestone Hillside Tangleridge Circle Grape Creek Oliver Cemetary Baxter " )177 " Valley Vista Spring Valley Oliver Schmidt Clemente Derecho Shallowford Hourglass Bronzewood Spring Rock Way Twilight Elm Grove Peak Ridge " )176 " Sandstone £ ¤ 290 Friar Villa Rimrock Morningstar Morninghill Morningsun County Road 355 Kit Carson Signal Hill Burnet Blanco Jim Bridger Davy Crockett Old Baldy Bisson Buckskin Appaloosa Run Cedar Paw " Mile Post Williamson Æ P Healthcare Facility n School Travis ï Park Midmorning McMeans Trailmaster Appaloosa Bastrop Hays s Country Club/Golf Course ² ¶ Overnight Lodging Longhorn Pipeline Comal Caldwell Land Use Source: USGS 2006 NLCD Fenton Banpass Circle Mowinkle Thunderbird Circle Scenic Brook Thunderbird Haskel Boling South Bend South View Candelaria Butler Scarlet Tara View Feather Hill Oak Valley Cima Crest View Deer Haven La Fauna Espanola Putt San Diego Flintrock Sisquoc Vera Cruz San Juan Honeycomb Ramble Three " )175 " El Dorado Kali Young Silver Mountain Shankel McGrath Fleenor Lewis Mountain La Plata Boxtree Arterial 12 Edgecomb Swelfling Blazyk La Crosse Aldenburgh Spruce Canyon Zyle Via Grande Brecourt Manor Sky Rock Split Stone Tera Land Slaughter CR FM 1826 Doswell Pairnoy Cusseta Spruce Canyon McMeans Jess Sharl ¬ «45 Housing Density ¬ «45 0 - 20 Units/Mile 21 - 100 Units/Mile >100 Units/Mile Land Use Developed Forest Wetlands Agricultural Open Water Shrub/Scrub Barren Land (Rock/Sand/Clay) Old Bee Caves Williamson Creek South Brook Whispering Creek ¬ «71 Silver Dale Oak Meadow Callbram Landsman Upslope El Rey Acton Rosson Hudson Phoenix La Tosca Apache Springs Granada Hills Summervale High Valley Crazy Horse Broken Lance Adobe Gallant Fox Callbram Tiverton Amicus Landsman Dark Ridge Twilight Terrace £ ¤ 290 Breezy La Concha Corrie Debcoe Telluride Shadowridge Orrick Kenosha Wolfcreek Hill Oaks Latigo Gentle Oak Kenosha Samar Poncha Bending Oak Jumano Ridge Oak Robert Kleburg Convict Hill Zadock Woods Oliver Loving John Chisum Whistlestop Open Range Twilight Mesa Dark Valley Rotan Hot Springs Twilight Shadow Colberg Bella Vista " )174 " J C Ranton McKown Seranton Hachita Beatty Allerton Gabion Gaur Edwardson Fainwood Auckland Barstow Taylorcrest Donner Ruxton " )173 " Slaughter Hopeland Bungalow Argyle Carrington Prescott Vinemont La Siesta Siringo Oasis Cheno Cortina Richard King Henry Kinney Isaac Pryor Clay Allison Clairmont Dunsmere Abilene Farmdale La Naranja San Paublo Clarion Lantana Salcon Cliff Hillside Terrace Sommerland Wampton Sautelle Colebrook Kayview Wheel Rim Doe Meadow Brown Rock Blanco River Forest Heights Ganttcrest Beckett Magee Tyhurst Fitchwood Marchmont Pecanwood Mesa Verde Lomita Verde Taylorcrest Meacham Ridgewell Sunny Vista York Bridge Bavaria Manipari Neider Hitcher Tiombe Mabry La Cresada Korth " " )172 Chesney Ridge Norman Zuniga S Cap Stone Seneca Falls Nubian Maelin ï Slaughter Creek Hansa Tollesboro Tasajillo Circle C Ranch Metropolitan Park Escarpment Esquel ¬ «1 Estancia Van Winkle Austral Dedham La Crosse Natick Danvers Orourk Nusser Freesia Ames Redmond Needham Goodall Walpole Roxbury Ariock Walebridge Old Harbor Londonshire I Rhett Butler Dahlgreen Ballenton Stellar Bluestar Scottish Thistle Eclipse ¬ «1 Environmental Assessment Hibiscus Valley Longhorn Pipeline Reversal Broomflower Figure 4.1.2-2e Austin Area Land Use Snapdragon and Housing Density SHEET 5 OF 7 Scale: 1:24,000 Prepared By: Atkins/19685 Date: Apr 10, 2012 Job No.: 100019708 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ 0 0.5 1 Miles Fig_4.1.2-2a-g_Austin_HousingDensity.mxd Salmo <<>> dwood County Hwy 184 Stillman Silver Creek BBB BBB Triple Creek B Crumley Ranch Bonham Ranch Johnson " )183 " Fitzhugh Crumley Ranch " )182 " Fitzhugh " )181 " Pauls Valley Cambrian Creek Roy Branch Summit Circle G Ranch Lookout High Sierra Red Gate Wells Fargo Piasano Pass Canyonwood Timberline Blue Hills Paisano Canyon Rim Oak Crest Upland Cottonwood Branch Cottonwood Creek Oakwood Terrace Canyon Bending Oak Creek Clear Creek Burnet Roy Creek " Mile Post Williamson County Road 185 Land Use Æ P Healthcare Facility n School Developed Forest Travis Wetlands Blanco ï Park Bastrop Hays s Country Club/Golf Course ² ¶ Overnight Lodging Agricultural Open Water Shrub/Scrub Longhorn Pipeline Comal Caldwell Barren Land (Rock/Sand/Clay) Land Use Source: USGS 2006 NLCD Fitzhugh Carol Ann Shoshoni Trail Driver Bonham Bonham Barton Creek Little Thicket White Tail Long Branch " )180 " Sleepy Hollow Sickle Drift Winding Creek Cole Sundown Housing Density Garrett Trails End 0 - 20 Units/Mile 21 - 100 Units/Mile >100 Units/Mile Tall Oaks D Morgan White Branch Kinser Long " )179 Wagon " Myrtle Creek Hillside Fitzhugh Long Branch Longwood Laurel Oaks Antler Bend Oak Branch Long Creek I 0 0.5 1 Miles " " )178 Tangleridge Circle £ ¤ 290 Slaughter Creek Friar Villa Environmental Assessment Rimrock Longhorn Pipeline Reversal Figure 4.1.2-2f Austin Area Land Use and Housing Density SHEET 6 OF 7 Valley Vista Spring Valley " )17 " Prepared By: Atkins/19685 Scale: 1:24,000 Job No.: 100019708 Date: Apr 10, 2012 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.1.2-2a-g_Austin_HousingDensity.mxd <<>> Lost Creek " )188 " Oak Oak River Oak Forest Bell Springs Cordwood Bell Springs " )187 " Medlin Creek Barton Creek Darter Harmon Hills Farm-To-Market Road 348 Sullivan Patricks Burnet Williamson Hart Travis " Mile Post Spring Valley Æ P Healthcare Facility n School Blanco ï Park Bastrop Hays s Country Club/Golf Course ² ¶ Overnight Lodging Longhorn Pipeline Comal Caldwell Land Use Source: USGS 2006 NLCD Sunrise Lander Stirrup Winchester Bridal Lariat Fitzhugh Creek Barton " )186 " Kevins Land Use Barton Ted Burger Barton Developed Forest Wetlands Agricultural Open Water Shrub/Scrub Barren Land (Rock/Sand/Clay) " )185 " Barton Barton Ranch Housing Density 0 - 20 Units/Mile 21 - 100 Units/Mile FM 12 >100 Units/Mile view Horseshoe The Entrance Horseshoe Brooks Ranch Hill Country Skyline Surveyors Compass Twin Lake Linkhill Linkwood West Cave Shepherds Corral West Cave Hideaway Saddletree Cave Cave West Cave Turkey Trot Montecito Fawns Montevista Westward Look Mason Dixon Bubbas Bubbas Longhorn Hilltop VL Parkwood Village Sandy Beach Thomas Janet George Hill Little Creek Westlake Earl Lake Park Rocky Creek Lakeshore Creekwood Lake Beach Cave Eastward Look Panorama Lakewood Oak Cliff Brooks Ranch Glenview Wildwood Oakwood Timber Timber Deer Creek Scenic Green Oak Twin Creek Bonham Ranch Bonham Ranch " )184 Wildwood " Bonham Ranch Crossroads " )183 " Fitzhugh Silver Creek Triple Creek Barton Creek Brooks County Hwy 184 BBB BBB Stillman Johnson Crumley Ranch " )182 " Barton Creek I Environmental Assessment Longhorn Pipeline Reversal Figure 4.1.2-2g Austin Area Land Use and Housing Density SHEET 7 OF 7 0 0.5 1 Miles Crumley Ranch Prepared By: Atkins/19685 Scale: 1:24,000 Job No.: 100019708 Date: Apr 10, 2012 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.1.2-2a-g_Austin_HousingDensity.mxd <<>> 450 400 350 300 250 200 150 100 50 0 50 Miles Mile Post Overland Spread Longhorn Longhorn Pipeline Existing Major Aquifers of Texas Carrizo - Wilcox (outcrop) Carrizo - Wilcox (subcrop) Edwards BFZ (outcrop) Edwards BFZ (subcrop) Edwards - Trinity Plateau (outcrop) Edwards - Trinity Plateau (subcrop) Gulf Coast Hueco - Mesilla Bolson Ogallala Pecos Valley Seymour Trinity (outcrop) Trinity (subcrop) Environmental Assessment Longhorn Pipeline Reversal Figure 4.2.1-1 Major Aquifers Prepared By: Atkins/13029 Scale: 1" = 50 miles Job No.: 100019708 Date: June 6, 2012 N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.2.1-1_Major_Aquifers.mxd <<>> 450 400 350 300 250 200 0 50 Miles Mile Post Overland Spread Longhorn Longhorn Pipeline Existing Minor Aquifers of Texas Blaine (outcrop) Blaine (subcrop) Brazos River Alluvium Captain Reef Complex Dockum (outcrop) Dockum (subcrop) Edwards-Trinity (High Plains) Ellenburger-San Saba (outcrop) Ellenburger-San Saba (subcrop) Hickory (outcrop) Hickory (subcrop) Lipan (outcrop) Lipan (subcrop) Marathon Marble Falls Nacatoch (outcrop) 150 100 50 Nacatoch (subcrop) Queen City (outcrop) Queen City (subcrop) Rustler (subcrop) Sparta (outcrop) Sparta (subcrop) Woodbine (outcrop) Woodbine (subcrop) Yegua Jackson Environmental Assessment Longhorn Pipeline Reversal Figure 4.2.1-2 Minor Aquifers Prepared By: Atkins/13029 Scale: 1" = 50 miles Job No.: 100019708 Date: June 6, 2012 N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.2.1-2_Minor_Aquifers.mxd <<>> - 68 - 67 60 69 -66 70 - 65 59 -64 58 • 63 56 55 • SATSUMA 72- 71 105 80 79 77 114- 78 76 123 102 85 84 1537 120 83 103 * 101 82 100 99 92 122 94 121 115 - 104 ~ 95 125 - 106 97 93 15 119— Harris 124 118— 107 - 98 •13 91 57 117- L 109 - 108 90- 45- 26 - 110 89 87 44- /25 22 116 -111 88 86 24 17 23 - 112 38- 16 10 14 12 0 LO - 113 81 37 36 Waller 75— 74- 73- EAST HOUSTON Harris Fort Bend * Cross reference well ID number to Table 4.2.1-2 Public Water Supply Wells within Zone of Potential Impact for public water system name. 9TH STREET Environmental Assessment • Public Water Supply Well • Proposed Magellan Pipeline Facility Longhorn Pipeline Reversal Texas 2-Year Capture Zone • Existing Magellan Pipeline Facility Figure 4.2.1-3a 0.5-Mile Fixed Capture Zone - Longhorn Pipeline Public Water Supply Wells within Zone of Potential Impact Orion Expansion Overland Spread Sheet 1 of 4 County Boundary 0 3.5 7 10.5 = Miles Prepared By: Atkins/19685 Scale: 1' = 3 mi Job No.: 100019708 le: N:ClientsIM_NIMagellan_Midstream_Partnersl100019708lgeolfig_EA Date: Jul 19, 2012 g 4.2.1-38-a PWo wells Longnorn.m. <<>> Washington -INDUSTRY 126 • BUCKHORN Waller Fayette Austin Colorado *Cross reference well ID number to Table 4.2.1-2 Public Water Supply Wells within Zone of Potential Impact for public water system name. Environmental Assessment • Public Water Supply Well Proposed Magellan Pipeline Facility Longhorn Pipeline Reversal Texas 2-Year Capture Zone Existing Magellan Pipeline Facility Figure 4.2.1-3b 0.5-Mile Fixed Capture Zone Public Water Supply Wells Longhorn Pipeline within Zone of Potential Impact Orion Expansion Overland Spread Sheet 2 of 4 County Boundary 3.5 7 10.5 = Miles Prepared By: Atkins/19685 Job No.: 100019708 le: N:ClientsIM_NIMagellan_Midstream_Partners|1000 19708 geolfig_EA Date: Jul 19, 2012 <<>> Lee Washington Bastrop - WARDA Fayette * Cross reference well ID number to Table 4.2.1-2 Public Water Supply Wells within Zone of Potential Impact for public water system name. Environmental Assessment • Public Water Supply Well Proposed Magellan Pipeline Facility Longhorn Pipeline Reversal Texas 2-Year Capture Zone Existing Magellan Pipeline Facility Figure 4.2.1-3c 0.5-Mile Fixed Capture Zone Longhorn Pipeline Public Water Supply Wells within Zone of Potential Impact Orion Expansion Overland Spread Sheet 3 of 4 County Boundary 0 3.5 10.5 Prepared By: Atkins/19685 = Miles Job No.: 100019708 le: N:ClientsIM_NIMagellan_Midstream_Partners1100019708lgeolfig_EA Date: Jul 19, 2012 9_4.2.1-3a-d_PWS wells_Longhorn.mx <<>> Blanco Travis < 134) 133- CEDAR VALLEY 130 132 - 131 Hays Bastrop * Cross reference well ID number to Table 4.2.1-2 Public Water Supply Wells within Zone of Potential Impact for public water system name. Caldwell Environmental Assessment • Public Water Supply Well Proposed Magellan Pipeline Facility Longhorn Pipeline Reversal Texas 2-Year Capture Zone Existing Magellan Pipeline Facility Figure 4.2.1-3d 0.5-Mile Fixed Capture Zone Longhorn Pipeline N Public Water Supply Wells within Zone of Potential Impact Orion Expansion Overland Spread Sheet 4 of 4 County Boundary 3.5 7 10.5 - Miles Scale: 1" = 3 mil Job No.: 100019708 ile: N:ClientsIM_NIMagellan_Midstream_Partners|100019708 geolfig_EAl Date: Jul 19, 2012 1g 4.2.1-sa-a Po wells Longnom.mx: <<>> Source data: Texas Commission on Environmental Quality (TCEQ) Environmental Assessment Longhorn Pipeline Reversal Figure 4.2.2-1 Hydrography with Surface Water Rights per TCEQ Database Prepared By: Atkins/13029 Scale: Job No.: 100019708 Date: June 6, 2012 N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.2.2-1_Water_Rights_TCEQ.mxd <<>> Source data: Texas Commission on Environmental Quality (TCEQ) Environmental Assessment Longhorn Pipeline Reversal Figure 4.2.2-2 Hydrography with STORET Stations Prepared By: Atkins/13029 Scale: Job No.: 100019708 Date: June 6, 2012 N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.2.2-2_STORET_Stations.mxd <<>> GS-6 Seg ID: 1006J Seg ID: 1006D Seg ID: 1007R " )17 " )16 " )15 " )14 Seg ID: 1006B " )13 " )12 ! . " )11 MESA ROAD " )10 " )9 Seg ID: 1006I Seg ID: 1006 " )8 " )7 " )4 " )5 " )6 " )3 " )2.31 ! . EAST HOUSTON Seg ID: 1007R Seg ID: 1016 Seg ID: 1006H Seg ID: 1006F Seg ID: 1006 Seg ID: 1006 9TH STREET ! . Grimes Montgomery Waller Harris Fort Bend Liberty Chambers Chambers Galveston Brazoria I 0 1 2 Miles ! . Facilities Magellan Pts Railroads Impaired Streams 2008 # 0 Magellen Mile Post Existing Magellen Pipeline Seg ID: 1007R ! ! County Line Overland Spread City Limits ! ! Seg ID: 1006 ! . Environmental Assessment Longhorn Pipeline Reversal Figure 4.2.2-3 Houston Area TMDLs Prepared By: Atkins/13029 Scale: 1" = 1.5 miles Job No.: 100019708 Date: Apr 10, 2012 N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.2.2-3_Houston_TMDL.mxd <<>> Seg ID: 1009 " )49 " )48 " )47 " )46 " )45 " )44 " )43 Brazos San Jacinto Grimes Washington Waller Austin Colorado Montgomery Harris Fort Bend Wharton Brazoria I 0 1 2 Miles Seg ID: 1009E Seg ID: 1016 Seg ID: 1017 " )42 " )41 " )40 " )39 " )38 " )37 " )36 " )35 " )34 ! . " )33 " )32 " )31 " )30 SATSUMA " )29 JERSEY VILLAGE Jersey Village Houston HOUSTON Seg ID: 1014E ! . Facilities Magellen Pts Railroads Impaired Streams 2008 # 0 Magellen Mile Post Existing Magellen Pipeline County Line ! ! ! Overland Spread City Limits ! Environmental Assessment Longhorn Pipeline Reversal Figure 4.2.2-4 Satsuma Area TMDLs Prepared By: Atkins/13029 Scale: 1" = 2 miles Job No.: 100019708 Date: Apr 10, 2012 N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.2.2-4_Satsuma_TMDL.mxd <<>> Seg ID: 1429B Seg ID: 1428 " )179 " )178 " )177 " )176 " )175 ! . " )174 " )173 " )172 WEST EDWARDS AQUIFER " )171 " )170 " )169 " )168 " )167 ! . " )166 " )165 EAST EDWARDS AQUIFER " )164 " )163 " )162 " )161 " )160 " )159 " )158 " )157 " )156 " )155 " )154 " )153 " )152 " )151 " )150 " )149 Seg ID: 1427A Burnet Blanco Williamson Travis Hays Caldwell Comal Milam Lee Bastrop Fayette I 0 1 2 3 Miles ! . Facilities Magellen Pts Railroads Impaired Streams 2008 # 0 Magellen Mile Post Existing Magellen Pipeline County Line ! ! ! ! Overland Spread City Limits Water Supply API TCEQ Environmental Assessment Longhorn Pipeline Reversal Figure 4.2.2-5 Austin Area TMDLs Prepared By: Atkins/13029 Scale: 1" = 3 miles Job No.: 100019708 Date: Apr 10, 2012 N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.2.2-5_Austin_TMDL.mxd <<>> Pedernales State Park Water Intake Pedernales State Park API Zone " )202 " )201 " )200 " )199 ! . EAST PEDERNALES RIVER " )198 " )197 Pipeline Crossing Lake Travis API Zone " )196 " )195 " )194 " )193 " )192 " )191 Llano Burnet I Gillespie Kendall Blanco Comal Hays Williamson Travis Caldwell ! A # 0 Public Water Supply Water Intake ! . Magellan Facility Magellan Pipeline Existing Mile Post Existing Magellan Pipeline API Boundary Longhorn Overland Spread ! ! ! ! ! City Limit Subwatershed Boundary 0 1 2 Miles Environmental Assessment Longhorn Pipeline Reversal Figure 4.2.2-6 Pedernales Falls State Park API Prepared By: Atkins/19685 Scale: 1" = 1 mi Job No.: 100019708 Date: Apr 10, 2012 N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.2.2-6_API_PedernalesFallsSP.mxd <<>> Llano Gillespie Kendall Burnet Williamson Travis Blanco Hays Comal Caldwell p o Public Water Supply Water Intake Stream River Existing Pipeline I Major Road Road API Boundary Water Body 0 1 2 Miles Environmental Assessment Longhorn Pipeline Reversal Figure 4.2.2-7 Pipeline Crossings within Pedernales Falls State Park API Prepared By: Atkins/19685 Scale: 1" = 1 mi Job No.: 100019708 Date: Apr 10, 2012 N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.2.2-7_API_PedernalesFallsSP_PipelineXing.mxd <<>> Rank Stream Crossing for Importance Environmental Assessment Longhorn Pipeline Reversal Figure 4.2.2-8 Surface Water Vulnerability Methodology Flow Chart Prepared By: Atkins/13188 Scale: N/A Job No.: 100019708 Date: June 22, 2012 File: N:\Clients\M_N\Magellan_Midstream_Partners\100019708\geo\fig_EA\ Fig_4.2.2-8_Flow_Diagram.mxd <<>> " )450 # 0 " )400 # 0 " )350 # 0 I 0 50 Miles " )300 # 0 " )250 # 0 " )200 # 0 " )150 # 0 # 0 Mile Post Gulf Prairies Overland Spread Longhorn High Plains Longhorn Pipeline Existing Piney Woods ECO Regions Post Oak Savanah Blackland Prairie Cross Timbers Edwards Plateau Rolling Plains South Texas Plains Trans-Pecos " )100 # 0 " )50 # 0 Environmental Assessment Longhorn Pipeline Reversal Figure 4.3.1-1 ECO Regions Prepared By: Atkins/13029 Scale: 1" = 50 miles Job No.: 100019708 Date: Apr 26, 2012 N:\Clients\M_N\Mag_Mid_Part\100019708\geo\fig_EA\Fig_4.3.1-1_ECO_Regions_Longhorn.mxd <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL CHAPTER 4 APPENDICES <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 4A HIGHWAY AND RAILROAD CROSSINGS <<>> Appendix 4A Highway and Railroad Crossings – LONGHORN PIPELINE Harris County –I-610, Union Pacific Railroad (14), US Hwy 90, Mesa Dr. (E. Houston Dyersdale Rd.), US Hwy 59, Hardy Toll Road (2), I-45, Veterans Memorial Dr. (State Hwy 261), Burlington Northern Santa Fe Corporation Railroad, Sam Houston Pkwy (2), SH Beltway 8, US 290 Frontage, US Hwy 290, SH 6. Waller County – FM 362, FM 359, FM 1887. Austin County – FM 331, SH 159, FM 1456, Burlington Northern Santa Fe Railroad, SH 36, FM 2754, FM 2502, FM 109, FM 1457, FM 389. Fayette County – SH 237, FM 1291, FM 2145, US 77, FM 448Union Pacific Railroad. Lee County – None Crossed Bastrop County – FM 2104, SH 71, Union Pacific Railroad, SH 304, FM 20, SH 21. Travis County – SH 130, FM 973, FM 812, US 183, I-35, Loop 275 (S. Congress Ave.), Union Pacific Railroad, FM 2304 (Manchaca Rd.), Loop 1 (S. Mopac Expressway/SH 1), FM 1826, US 290. Hays County – FM 12. Blanco County – Park Road 6026, US 281, FM 1323, FM 1320. Gillespie County – FM 1323, SH 16, FM 965, FM 2323. Llano County – None crossed. Mason County –US 87, FM 783, FM 1871. Kimble County –US 377, US 83, FM 2291. Menard County – FM 1674. Schleicher County –FM 864, FM 2596, US 277, US 190, FM 1828. Crockett County – SH 163. Reagan County – SH 137, FM 1676, Texas Pacifico Transportation Limited Railroad, South Orient Railroad, US 67, FM 1555. Upton County – State Highway 349, State Highway 329 (2). Crane County – US 385 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 4B BIOLOGICAL ASSESSMENT <<>> Phase 1 Biological Assessment February 14, 2000 <<>> HJN 990144 BIOLOGICAL ASSESSMENT LONGHORN PIPELINE PROJECT MAINTENANCE ACTIVITIES AND MINOR CONSTRUCTION HOUSTON TO CRANE, TEXAS Prepared For: Longhorn Partners Pipeline, L.P. US Environmental Protection Agency Region 6 US Department of Transportation Office of Pipeline Safety Prepared By: Horizon Environmental Services, Inc. Austin - Beaumont - Houston - Shreveport February 14, 2000 990144BA.v-6 - 2/14/2000 <<>> TABLE OF CONTENTS Section Page 1.0 INTRODUCTION. .1 2.0 PROJECT OVERVIEW. .7 3.0 EXISTING ENVIRONMENT... ...9 3.1 GENERAL... .9 3.2 VEGETATION........ ..9 3.2.1 Gulf Prairies and Marshes Vegetational Area. ...9 3.2.2 Post Oak Savannah Vegetational Area... 12 3.2.3 Blackland Prairies Vegetational Area ... .12 3.2.4 Edwards Plateau Vegetational Area....... ..13 3.2.5 The Trans-Pecos, Mountains and Basins Vegetational Area... ..13 3.3 WILDLIFE.............. ..14 3.3.1 Austroriparian Biotic Province ..14 3.3.2 Texan Biotic Province. ..14 3.3.3 Balconian Biotic Province ..16 3.3.4 Kansan Biotic Province.. 16 3.3.5 Chihuahuan Biotic Province ..16 3.4 THREATENED AND ENDANGERED SPECIES 17 4.0 PROJECT DESCRIPTION... .37 4.1 RIGHT-OF-WAY CLEARING AND MARKING. .37 4.2 PIPELINE MAINTENANCE-CONSTRUCTION PLANNING. 39 4.3 PROJECT ENVIRONMENTAL INSPECTORS 45 4.4 SITE PREPARATION......... 45 4.5 SITE ENTRY....... ..46 4.6 PIPELINE LOWERING AND/OR REPLACEMENT - OPEN TERRAIN 47 4.7 PIPELINE LOWERING AND/OR REPLACEMENT - CREEK CROSSINGS 51 990144BA.v-6 - 2/14/2000 <<>> 4.8 TRENCHING... .51 4.9 BORING.. 4.10 HYDROSTATIC TESTING - OVERVIEW OF ACTIVITIES 4.11 HYDROSTATIC TESTING - POTENTIAL FAILURE OF PIPELINE. 4.12 CATHODIC PROTECTION ENHANCEMENTS 4.13 SURGE PRESSURE PROTECTION 4.14 INVESTIGATIONS........ 59 5.0 POTENTIAL IMPACTS (TAKE) AND COMPENSATION. 60 5.1 SPECIES-BY-SPECIES IMPACT ANALYSIS 64 5.2 AVOIDANCE AND MINIMIZATION 69 5.3 PROPOSED COMPENSATION FOR POTENTIAL TAKE 71 6.0 REFERENCES................... ............77 990144BA.v-6 2/14/2000 <<>> LIST OF FIGURES Figure Page 1 LOCATION MAP ...... 10 2 VEGETATIONAL AREAS OF TEXAS TRAVERSED BY THE LONGHORN PIPELINE 11 3 BIOTIC PROVINCES OF TEXAS TRAVERSED BY THE LONGHORN PIPELINE 15 4 - 12 AREAS OF FEDERALLY LISTED, THREATENED, OR ENDANGERED SPECIES TRAVERSED BY THE LONGHORN PIPELINE - HOUSTON TO CRANE . ..22-30 LIST OF TABLES Table Page 1 FEDERALLY LISTED THREATENED OR ENDANGERED SPECIES WHICH OCCUR IN COUNTIES TRAVERSED BY THE LONGHORN PIPELINE -HOUSTON TO CRANE 18 2 2000 MAINTENANCE CONSTRUCTION, TESTING AND CLEARING, LONGHORN PIPELINE .. 40 3 ROW CLEARING AND ADDITIONAL MAINTENANCE CONSTRUCTION IMPACTS - LONGHORN PIPELINE - HOUSTON TO CRANE. 62 4 LONGHORN PIPELINE TAKE COMPENSATION |.........75 APPENDIX PROJECT DOCUMENTATION APPENDIX ACCOMPANYING DOCUMENT 990144BA.v-6 2/14/2000 <<>> 1.0 INTRODUCTION This Biological Assessment (BA) is prepared in connection with the draft Environmental Assessment of the Longhorn Pipeline owned by Longhorn Partners Pipeline, L.P. (Longhorn). That Environmental Assessment was the product of a settlement reached in the matter of Spiller, et al v. Walker, et al pending in the United States District Court in Austin, Texas. The plaintiffs in that lawsuit alleged failure on the part of numerous federal agencies to adequately analyze the potential environmental impacts of the Longhorn Pipeline. Though the federal defendants and Longhorn denied the plaintiffs' allegations, the parties reached a negotiated settlement that was approved by the Court on March 5, 1999. Parties to that settlement included Longhorn, the US Environmental Protection Agency (EPA), the US Department of Transportation (DOT), the US Department of Justice, the City of Austin, the Lower Colorado River Authority, and the remaining plaintiffs. As part of that Court ordered settlement, the agencies involved in the original litigation were required to conduct an Environmental Assessment, including specific consideration of species protected under the Endangered Species Act (ESA). The Court ordered EPA and DOT, acting as Lead Agencies, to be responsible for the Environmental Assessment, and ordered the Department of Army to act as a cooperating agency. A draft Environmental Assessment, with a preliminary Finding of No Significant Impact (FONSI), was prepared by Radian International LLP at the direction of and pursuant to a work plan approved by the Lead Agencies. As a result of the Environmental Assessment, and with the support of the Lead Agencies, Longhorn has committed to implement a slate of 34 pipeline mitigation measures. (The pipeline mitigation measures are identified and described in the Longhorn Mitigation Plan included in the accompanying Project Documentation Appendix at Tab 2). The pipeline mitigation measures focus on two general areas: first, the enhancement of pipeline integrity to reduce the probability of a pipeline release and to reduce risks to pipeline integrity, and second, enhancement of emergency response capability and development of plans for corrective action in the unlikely event of a pipeline release. Both categories of pipeline mitigation measures are discussed below in greater detail in Section 4.0, Project Description. 990144BA.v-6 - 2/14/2000 <<>> Pursuant to Section 7 of the ESA, the Lead Agencies have requested consultation with the US Fish and Wildlife Service (the Service) regarding the Draft Environmental Assessment and the package of pipeline mitigation measures upon which the Lead Agencies' preliminary FONSI is predicated. In connection with the inter-agency consultation, Longhorn prepared and submitted to the Service a draft BA on the entire pipeline project on September 27, 1999. The Service responded to the September draft BA with comments and requests for additional information in the form of a letter to Horizon Environmental Services, Inc., dated December 15, 1999 (the Comment Letter - see accompanying Project Documentation Appendix at Tab 12). On February 3, 2000, the Lead Agencies designated Longhorn has a non- federal representative for the purpose of consultation with the Service and preparation of a BA on the Longhorn project. The Spiller Court's order provides that issuance of any FONSI with regard to the Longhorn project "shall be conditioned upon implementation" of measures to protect public safety and the environment. Settlement Stipulation at 6. The order also prohibits the DOT from authorizing Longhorn to commence operations until Longhorn has implemented those mitigation measures upon which the FONSI is conditioned. Settlement Stipulation at 7. The order contemplates that Longhorn will apply for, and accept, such ESA permits as may be required in connection with the implementation of any mitigation measures upon which a FONSI may be conditioned. Id. The results of this consultation by the Lead Agencies with the Service are expected to be incorporated in the Record of Decision issued by the Lead Agencies. If the Lead Agencies issue an EA/FONSI, the terms and conditions, mitigatory measures and protections incorporated herein for the benefit of species will be adopted and incorporated by Longhorn in its operating and maintenance manuals submitted to, and enforceable by, DOT pursuant to the Pipeline Safety Act (49 U.S.C. §60101, et seq.) or the Longhorn mitigation commitments. The Office of Pipeline Safety (OPS) administers DOT's regulatory program to ensure the safe transportation of various hazardous liquids by pipeline under 990144BA.v-6 2 - 2/14/2000 <<>> the Pipeline Safety Act. OPS is responsible for inspecting pipelines before they are placed in service to ensure that they are in accordance with DOT's regulations and are being operated safely. The OPS's published statement of its authority is set out below: The Department of Transportation's (DOI) Research and Special Programs Administration (RSPA), acting through the Office of Pipeline Safety (OPS), administers the Department's national regulatory program assure the safe other transportation of natural gas, petroleum, and hazardous materials by pipeline. OPS develops regulations and other approaches to risk management assure safety in design, construction, testing, operation, maintenance, emergency response of pipeline facilities. Although the Service and the Lead Agencies are in consultation with respect to the entire proposed Longhorn Project, this consultation is being approached in two distinct, yet related phases'. The first phase of the consultation (Phase I) relates to pipeline maintenance, pipeline testing and the first category of measures that Longhorn will take to fulfill its commitment to ensure pipeline safety and integrity. These measures focus on pipeline integrity enhancements such as a number of pipe replacements, lowering of some sections of pipe, investigation of possible pipe flaws, hydrostatic pressure testing, and similar actions. The second phase of the consultation (Phase I) will be more directly related to the actual operation of the pipeline, specifically the operation and maintenance of the pipeline system and the potential effects of the unlikely event of a pipeline release. Additional mitigation measures, such as internal pipeline inspections and construction in two particular areas, also will be addressed in Phase II. Those areas are (a) Houston toad habitat and (b) areas of potential effect to the Barton Springs Salamander over the Edwards Aquifer Recharge Zone. A two-stage consultation offers the most protection to the species, because the second phase will benefit from and build upon species information gathered in the first stage of review, while allowing the most efficient route to 402.14(k) provides a mechanism for the Service to review a project, and provide biological opinions on each U.S. Fish and Wildlife regulations allow for a staged consultation. 50 C.F.R § 402.14(k). Section incremental step. 990144BA.v-6 - 2/14/2000 <<>> startup of the pipeline. The Spiller settlement specifically contemplates that Longhorn will undertake certain construction and maintenance activities prior to issuance of a final agency decision in this matter. Settlement Stipulation at 8-11. The parties to the settlement specifically agreed that any such investments by Longhorn in Kimble, Menard, Hays, Travis, Caldwell, Bastrop and any counties within the jurisdiction of the LCRA after August 25, 1998 would not be considered "for the purposes of determining the reasonableness of alternatives" (Settlement Stipulation at 11), meaning that these investments would not constitute irretrievable commitments of resources for the purposes of the National Environmental Policy Act or Section 7(d) of the ESA. Phase I of the consultation focuses on near-term discrete tasks that are requisite preliminary activities-tasks that Longhorn must complete before it can place the pipeline into operation, such as right-of-way clearing and pipeline safety mitigation measures. They will be implemented in a manner that avoids and minimizes potential effects upon species and habitat. Phase II of the consultation will focus on long-term programmatic activities, operation and maintenance of the pipeline, and the possibility of an emergency response. These activities are either (a) not necessarily discrete or (b) not precisely estimable before the fact. Phase II activities carry different risks from Phase I activities. For example, the operation and maintenance activities are ongoing and long-term. Further, though the probability of a pipeline release will be minimized as a result of the Longhorn Mitigation Plan, should a release occur, it has the potential to result in adverse effects to species and habitat at locations and of magnitudes that are difficult to predict with precision. Nevertheless, because of the low risk of such a release and the comprehensive nature of the Longhorn Mitigation Plan, Longhorn and the Lead Agencies believe that it is appropriate to conclude that there is a reasonable likelihood that the entire project is not likely to jeopardize the continued existence of any endangered or threatened species or result in the destruction or adverse modification of critical habitat. This is because the Phase I review is being conducted against the backdrop of a larger mitigation package, which the Service has had an opportunity to review. The Service had an opportunity to review and 990144BA.v-6 4 - 2/14/2000 <<>> comment on the entire project based upon the September draft BA. The two phases thus can be logically separated. Phase I of the Service's review (this BA) will focus on those actions that are designed to make the pipeline safer. The Service can complete this stage of review without pre-judging whether or not the pipeline will be used. Phase II of the Service's review will focus on whether and how the pipeline will be used. The Phase I procedures are routine in the US pipeline industry, during operation, for periodic maintenance, testing and repair of hazardous liquids and gas pipelines. However, to ensure that the pipeline is safe, the Longhorn Mitigation Plan specifies that these activities shall be conducted prior to startup of the Longhorn Pipeline under its proposed use. This BA encompasses Phase I of the consultation. Included in this phase are maintenance of the pipeline right-of-way; maintenance construction to replace and/or lower certain segments of the pipeline, along with investigation and repair of possible flaws in the pipe at an identified number of locations; enhancements to the pipeline cathodic protection system; and hydrostatic pressure testing of the pipeline to ensure the integrity of the pipe for its intended service. None of these activities constitutes an irreversible or irretrievable commitment of resources, natural or monetary, which have the effect of foreclosing the formulation or implementation of any reasonable and prudent alternative measures. This BA is provided to facilitate a formal Section 7 consultation between the EPA, the DOT, and the Service to evaluate the potential for adverse effects to listed species resulting from activities related to the implementation of pipeline mitigation measures to improve pipeline integrity and thereby enhance pipeline safety. Those pipeline mitigation measures are referred to hereafter in this BA as projects. The specific maintenance and testing projects to be implemented are described in detail in Section 4.0 of this BA. Where appropriate, this BA generally comports with EPA Guidelines for Ecological Risk Assessment. See Guidelines for Ecological Risk Assessment, 63 Fed. Reg. 26,846 (1998). For example, EPA guidelines suggest that a suitable 990144BA.v-6 5 - 2/14/2000 <<>> assessment approach will identify the explicit, ecologically relevant expressions of environmental value that are to be protected. See 63 Fed. Reg. at 26,858. To that end, the BA guides project development, in part, by identifying particular species of concern within the project area, and suggesting mitigation efforts which will minimize exposure and impact to those species. Where uncertainty has been encountered, doubt has been resolved in favor of the species, and in this regard, the results of a precise application of EPA Guidelines have likely been exceeded. Precise application of the Guidelines would likely reveal far fewer areas of ecological sensitivity than have been assumed. 990144BA.v-6 6 • 2/14/2000| <<>> 2.0 PROJECT OVERVIEW Longhorn proposes to operate a 723-mile refined petroleum products pipeline system from the GATX Terminal in Galena Park, Texas, to a refined petroleum products terminal in El Paso, Texas. The pipeline also has a 28-mile intermediate connection from a station in Crane County to a planned meter station in Odessa, Texas. The pipeline consists of a combination of 20-inch and 18-inch diameter pipe from Galena Park Station to El Paso Terminal and an 8- inch diameter pipeline from a station in Crane County to a meter station in Odessa, Texas. Finally, three as yet to be built pipelines will connect the El Paso terminal to interstate common carrier pipelines west of El Paso. The pipeline's initial capacity of 72,000 barrels per day (bpd) will be supplied by a new pump station at Galena Park and five newly constructed booster pump stations at the following locations: Satsuma (Harris County), Cedar Valley (Hays County), Kimble County (Kimble County), Crane (Crane County), and El Paso (El Paso County). Two new pipeline construction projects remain to be completed. An 8-inch diameter, 2500-foot lateral that originates at the terminus of the existing Odessa lateral will connect to a terminal facility in Odessa, Texas, owned by Equilon. Three 8.3-mile lateral pipelines, which originate at the El Paso Terminal, will connect with Kinder Morgan (formerly the Santa Fe Pacific pipeline) and Chevron pipelines in the El Paso area. The connection to Kinder Morgan will consist of one 8-inch diameter pipeline and one 12-inch diameter pipeline. The Chevron connection will consist of an 8-inch diameter pipeline. The purpose of the lateral pipelines is to connect into Kinder Morgan and Chevron pipelines to distribute product into the Phoenix, Tucson, and Albuquerque (New Mexico) markets. Chevron operates an 8-inch pipeline that delivers product to the Albuquerque market; Kinder Morgan operates one 12-inch pipeline and one 8-inch pipeline serving the Tucson market. Other Kinder Morgan pipelines connect Tucson to the Phoenix market. The proposed project includes both new construction and refurbishment of 990144BA.v-6 7 - 2/14/2000 <<>> an existing pipeline that has been converted from its former use of transporting crude oil from West Texas to the Gulf Coast area, the majority of which is complete. As described in this chapter, the existing pipeline has been modified to transport refined petroleum products, with flow going from east to west. Williams Pipeline Company (later to become part of Williams Energy Services) will be the contract operator of the Longhorn Pipeline System. Longhorn intends to transport multiple grades of gasoline and distillates, which will include special reformulated grades of gasoline needed to control air emissions in certain areas of the Southwest. The Longhorn Pipeline System is designed for service in excess of 50 years and is made up of four main pipeline segments, several stations, and one terminal, as listed below: • New and refurbished 20-inch diameter pipeline from Galena Park Station to Satsuma Station • Refurbished 18-inch diameter pipeline from Satsuma Station to Crane Station New 18-inch diameter pipeline from Crane Station to El Paso Terminal New lateral pipeline connections to Odessa and to other pipelines at El Paso • New Pump Stations • El Paso Terminal • Odessa Meter Station A detailed description of the Longhorn Pipeline System is included in the Longhorn Pipeline Project Description section of the accompanying Project Documentation Appendix at Tab 1. More detailed descriptions of the project components that are subject to this BA are included in Section 4.0. Future pipeline upgrades, repairs, and maintenance beyond that identified in this document will be addressed in Phase II of the consultation. 990144BA.v-6 8 - 2/14/2000 <<>> 3.0 SEXISTING ENVIRONMENT 3.1 GENERAL The Longhorn Pipeline traverses the State of Texas from east to west originating in east Houston, Harris County and extending westward to Crane Station, Crane County (Figure 1). Auxiliary lines extend from Crane Station northward to Odessa and westward to El Paso in far west Texas. The area traversed by the pipeline varies physiographically from flat or rolling coastal prairie in the Houston region to hilly woodlands of the Edwards Plateau in central Texas to the xeric Permian Basin region of west Texas. 3.2 VEGETATION From east to west, the Longhorn Pipeline traverses the Gulf Prairies and Marshes, Post Oak Savannah, Blackland Prairies, Edwards Plateau, and Trans- Pecos, Mountains and Basins Vegetational Areas (Gould, 1975; Figure 2). The following provides a summary description of each ecological region. 3.2.1 Gulf Prairies and Marshes Vegetational Area This ecological region, approximately 9.5 million acres in extent, is divided into the Coastal Prairie and Gulf Coast Marshlands. The Coastal Prairie is a nearly level plain less than 150 feet above mean sea level (MSL) and dissected by streams and rivers flowing into the Gulf of Mexico while the Gulf Coast Marshlands are limited to narrow belts of low wet marsh immediately adjacent to the coast and along waterways. Surface soils are acid sands, sandy loams, and clays with low permeability and droughty in nature. Annual precipitation averages from 20 inches in the west to 50 inches in the east (Gould, 1975). The climax vegetation is largely grassland or post oak savannah (Gould, 1975). Ranches and rangelands are interspersed by farms. Most of the marsh areas are grazed by cattle within large land holdings. 990144BA.v-6 9 - 2/14/2000 <<>> MARILO Coo Oklahoma Mexico New LuBBOCK • Т корт орт райм Louisiana ODESSA MIDLAND SAN ANGELO Mexico Mexico DEL RIO LAREDO Mexico Gulf of - Longhor Refined Products Pipeline for far: 2003 • 7i21 No. FIGURE I NOT TO SCALE LONGHORN PIPELINE LOCATION MAP MAP SOURCES: TEXAS NATURAL RESOURCE INFORMATION SYSTEM LONGHORN PIPELINE <<>> Longhorn Refined Products Pipeline 10 MEXICO GULF VEGETATIONAL AREAS OF TEXAS 1. . 2. Gulf Prairies and Marshes Pineywoods 3. 4. Post Oak Savannah 5. Blackland Prairies 6. South Texas Plains Cross Timbers and Prairies :50 8. Rolling Plains 7. Edwards Plateau Mile 100 10. Trans-Pecos, Mountains and Basins High Plains Horizon ENVIRONMENTAL SERVICES, INC. FIGURE 2 LONGHORN PIPELINE IN RELATION TO THE Source: Gould, 1975. VEGETATIONAL AREAS OF TEXAS <<>> 3.2.2 Post Oak Savannah Vegetational Area This ecological region, approximately 8.5 million acres in extent, is bordered by the Pineywoods region to the east and the Blackland Prairie region to the west. The topography is gently rolling to hilly, and elevations range from 300 to 800 feet above mean sea level (MSL). Generally, surface soils of higher elevations are light-colored, acidic sandy loams or sands while those of lower elevations are darker, acidic sandy loams or clays. Annual precipitation averages from 35 to 45 inches, and May or June is generally the high rainfall month (Gould, 1975). The Post Oak Savannah was historically dominated by prairie climax grasses and scattered trees. The most prevalent trees were oaks and cedar elm. The deterioration of the climax plant communities in the region is evidenced by an increase of certain grass species, forb species, and woody species (Gould, 1975). Moderate to dense post oak dominated woodlands have developed in many areas as a result of man's suppression of fire. The bottomland woodland remains the most diverse vegetation type of this ecological area. 3.2.3 Blackland Prairies Vegetational Area This ecological region, approximately 11.5 million acres in extent, includes the San Antonio and Fayette Prairies. Land surface ranges in elevation from 300 to 800 feet, gently rolling to nearly level, and well dissected and rapidly drained. Surface soils are fairly uniform, dark-colored calcareous clays interspersed with gray acid sandy loams. Annual precipitation averages from 30 inches in the west to 40 inches in the east (Gould, 1975). The climax native vegetation is true prairie (Gould, 1975). The majority of this ecological area has been brought under cultivation. Farms are interspersed among ranches and rangelands. 990144BA.v-6 12 - 2/14/2000 <<>> 3.2.4 Edwards Plateau Vegetational Area This ecological region encompasses approximately 24 million acres in west-central Texas. Land surface ranges in elevation from 100 to 3000 feet above MSL, rough and well drained, and dissected by several river systems. Surface soils are usually shallow and underlain by material ranging from limestone or caliche to granite. Annual precipitation averages from 15 inches in the west to over 33 inches in the east, and droughts are not uncommon (Gould, 1975). The Edwards Plateau Vegetational Area is predominantly rangeland (Gould, 1975). Bottomland areas of this ecological area having deeper soils have been brought under cultivation. Small farms are interspersed among ranches and rangelands. 3.2.5 Trans-Pecos, Mountains and Basins Vegetational Area This ecological region encompasses approximately 19 million acres of mountains and arid valleys in extreme west Texas. Land surface ranges in elevation from 2500 to over 8500 feet, rough and well drained, and dissected by several river systems. Surface soils have developed from out-wash materials from mountains, varied in texture, calcareous, and some areas are alkaline due to poor drainage. Surface conditions include stony hills, clay flats, sands, salty-saline soils, gypsum flats, deep upland, rough stony mountains, gravelly outwash, and badlands (Gould, 1975). The average annual precipitation for the area is less than 12 inches while higher elevations can range from 16 to 20 inches (Gould, 1975). Cultivated areas are confined largely to irrigable valleys. The majority of land is in large holdings as native range. Ranch operations include cattle, sheep, and goats. 3.3 WILDLIFE 990144BA.v-6 13 - 2/14/2000 <<>> From east to west, the Longhorn Pipeline traverses the Austroriparian, Texan, Balconian, Kansan, and Chihuahuan Biotic Provinces described by Blair (1950; Figure 3). The following provides a summary description of each biotic province. 3.3.1 Austroriparian Biotic Province This province includes the Gulf coast plain from the Atlantic to eastern Texas. The western boundary of this province in Texas is along a line running approximately north from western Harris County to western Red River County. The pine and hardwood forest of the Austroriparian is limited to the west by available moisture. The vertebrate fauna of the Austroriparian Province in Texas is typical of the species in the province to the east. At least 47 species of mammals occur in this province in Texas. Some 29 species of snakes, 10 lizards, 2 land turtles, 17 anurans, and 18 urodels are known to occur in the Texas part of this province (Blair, 1950). 3.3.2 Texan Biotic Province This province is a transitional area and is recognized as a broad ecotone between the forests of the Austroriparian and Carolinian provinces of eastern Texas and Oklahoma, and the grasslands of the western parts of these states. The integration of woodlands and grasslands within the region results in a mixture of wildlife species typical of the 2 general habitats. The vertebrate fauna of the Texan Biotic Province consists of at least 49 species of mammals, 16 lizards, 2 land turtles, 39 snakes, 18 anurans (frogs and toads), and 5 urodeles (salamanders, newts, etc.) (Blair, 1950). No endemic vertebrates are known from the Texan Province. 990144BA.v-6 14 - 2/14/2000 <<>> Kansan Navahonian Texan Balconian Chihuahuan MEXICO Tamaulipan of GULF Longhorn Refined Products Pipeline we 3 070€ 50 100 Miles Horizon ENVIRONMENTAL SERVICES, INC FIGURE 3 LONGHORN PIPELINE IN RELATION TO THE BIOTIC PROVINCES OF TEXAS <<>> 3.3.3 Balconian Biotic Province This province is synonymous with the Edwards Plateau and is a physiographically discrete unit. The name Balconian is derived from the Balcones Fault Zone which forms the southern and eastern boundaries of this province. The vertebrate fauna of the Balconian Biotic Province is a mixture of species characteristic of surrounding major provinces, even though its characteristic vegetation is distinctly different. The vertebrate fauna consists of 57 species of mammals, 16 lizards, 1 land turtle, 36 snakes, 15 anurans (frogs and toads), and 7 urodeles (salamanders, newts, etc.) (Blair, 1950). There are several endemic vertebrates known from the Balconian Biotic Province. 3.3.4 Kansan Biotic Province This province is divided into 3 distinct biotic districts: the Mixed-grass District, Mesquite Plains District, and Short-grass Plains District. All of these biotic districts have areas of dune sand. Moisture is deficient throughout the Kansan Biotic Province, and there is a decrease in available moisture from east to west. The Short-grass Plains District occurs in the area of Crane, Texas. The vertebrate fauna of the Kansan Biotic Province is a mixture of species from each of its biotic provinces. The vertebrate fauna consists of 59 species of mammals, 14 lizards, 1 land turtle, 31 snakes, 9 anurans (frogs and toads), and 14 urodeles (salamanders, newts, etc.) (Blair, 1950). There are 6 endemic vertebrates known from the Balconian Biotic Province. 3.3.5 Chihuahuan Biotic Province Within Texas, the Chihuahuan Biotic Province includes all of the Trans- Pecos Texas except the Guadalupe Mountains in Culberson County. The physiography of the province includes desert basins, mountains, and major waterways and drainages. Even though the climate of most of the province in Texas is arid and seriously deficient of moisture for plant growth, vegetational communities are very diverse. 990144BA.v-6 16 - 2/14/2000 <<>> The vertebrate fauna of the Chihuahuan Biotic Province is extremely diverse and many of the same species can be found in both desert basin and mountain areas. The vertebrate fauna consists of 83 species of mammals, 22 lizards, 1 land turtle, 38 snakes, 13 anurans (frogs and toads), and 1 urodele (salamanders, newts, etc.) (Blair, 1950). There are 6 endemic vertebrates known from the Balconian Biotic Province. 3.4 THREATENED AND ENDANGERED SPECIES Horizon Environmental Services, Inc. (Horizon) has performed investigations along the existing Longhorn Pipeline right-of-way (ROW) and vicinity from Houston to Crane for the possible occurrence of all federally-listed, threatened, or endangered species which are known to exist in all counties of Texas traversed by the Longhorn Pipeline (Table 1). Following investigation of the species which potentially occur in these counties, several species were identified for which there was a possibility of occurrence within the area of potential effect for pipeline maintenance construction, routine ROW maintenance, hydrostatic pressure testing, and the remaining integrity related activities. The area of potential direct effects for the Phase I activities includes the immediate, existing 50-foot wide ROW, and those additional construction specific adjacent areas up to 100 feet either side of the ROW, and other areas that could reasonably and foreseeably be affected by the subject pipeline maintenance, construction, and testing activities (ie., hydrotest releases). No areas of indirect effect are anticipated due to avoidance and minimization procedures. A biological investigation was conducted along the pipeline ROW and immediately adjacent lands to determine if these species and/or suitable habitat were present within the area of concern. Horizon conducted habitat assessments and survey efforts throughout April, May, and June 1999 from 990144BA.v-6 17 - 2/14/2000 <<>> Kimble 18ULS1 Hays x3321 0 0o ste even are mercies 192282623002 Harris 30-92 САлЕрих ИЗ оласТЕЯ Gillespie 3003 Henbanensi Fayette densitem sida Ector 2ovi 2233 Table 1: Federally-listed Threatened or Endangered Species which occur in counties traversed by Longhorn Pipeline Crockett epot linen Crane 00г) soys boons state br 2005100228/008 nucol Sne Blanco Sub be sha X - Known or Suspected to Occur Within Area of Potential Effect TSA - Listed Threatened Due to Similarity of Appearance O - Not Likely to Occur Within Area of Potential Effect xx 20000000 254 волар и 1610р Source of Species: US Fish and Wildlife Service Bastrop PDL - Proposed to be De-listed E - Listed Endangered Austin * T - Listed Threatened Species - Federal Classification American alligator - TSA Attwater's prairie-chicken - E Barton Springs salamander - E Bee Creek Cave harvestman - E Bald eagle - T(PDL) Black-capped vireo - E Bone Cave harvestman - E Clear Creek gambusia - E Comal Springs dryopid beetle - E Comal Springs riffle beetle - E Devil's River Minnow - PE Golden-cheeked warbler - E Kretschmar Cave mold beetle - E Navasota Ladies-tresses - E Fountain darter - E Houston toad - E Interior least tem - E San Marcos gambusia - E San Marcos salamander - T Texas blind salamander - E Texas prairie dawn-flower - E Tobusch fishhook cactus - E Tooth Cave ground beetle - E Tooth Cave pseudoscorpion - E Texas snowbells - E Texas wild-rice - E Tooth Cave spider - E Whooping crane - E <<>> Downstream Waller 0 x Upton Travis 0 0 0= Schleicher Table 1: Federally-listed Threatened or Endangered Species which occur in counties traversed by Longhorn Pipeline Reagan Menard Mason X - Known or Suspected to Occur Within Area of Potential Effect TSA - Listed Threatened Due to Similarity of Appearance O - Not Likely to Occur Within Area of Potential Effect Source of Species: US Fish and Wildlife Service Llano PDL - Proposed to be De-listed E - Listed Endangered T - Listed Threatened Lee Species - Federal Classification American alligator - TSA Attwater's prairie-chicken - E Barton Springs salamander - E Bee Creek Cave harvestman - E Bald eagle - T(PDL) Black-capped vireo - E Bone Cave harvestman - E Comal Springs dryopid beetle - E Clear Creek gambusia - E Comal Springs riffle beetle - E Kretschmarr Cave mold beetle - E Devil's River Minnow - PE Golden-cheeked warbler. - E Navasota Ladies-tresses - E Fountain darter- E Houston toad - E Interior least tem - E San Marcos gambusia - E San Marcos salamander - T Texas blind salamander - E Texas prairie dawn-flower - E Tobusch fishhook cactus - E Tooth Cave ground beetle - E Tooth Cave pseudoscorpion - E Texas snowbells - E Texas wild-rice - E Tooth Cave spider - E Whooping crane - E <<>> Crane Station, Crane County, Texas to Highway 6 in Houston, Harris County, Texas. The portion of the pipeline extending from Crane to El Paso is not subject to this BA since none of the subject activities will apply to that pipeline segment area. Species which potentially occur in or near waterways downstream of the pipeline were assessed based on literature and agency file information. In 1998, the Service concurred with Longhorn's conclusion that the project was not likely to adversely affect species and habitat along the pipeline segment between Crane and El Paso (a copy of the Service's concurrence is included in the accompanying Project Documentation Appendix at Tab 13). As indicated in Table 1, many species have been excluded from further consideration due to Horizon=s determination that the activities are not likely to adversely affect these species. S Horizon's determination was based on information regarding distribution of the various species obtained from various published, agency file, or personal communication sources such as the Texas Parks and Wildlife Department, the US Fish and Wildlife Service, recognized experts for certain species, published species documentation, and published reference books. Those species indicated by an AO@ in Table 1 have been determined not likely to occur within the area of potential effect. Those additional species indicated by an AM@ are migrants that would not likely be affected. Species indicated by an AX@ are those determined by Horizon-s studies to occur or possibly occur in the area of potential effect for present purposes. Those species are addressed in more detail below and on attached maps. Texas Prairie Dawn-flower (Hymenoxys texana) Small, delicate annual to 6 inches tall with single or branching stems. Small yellow flowers blooming in late March to early April. Occurs in sparsely vegetated areas of fine-sandy compacted soil. Specifically, the species occurs in the northern part of the Gulf Coastal Prairie, where it is found in poorly drained depressions or saline swales around the periphery of low, natural mounds (mima mounds) in open grasslands. These mostly barren areas are sparsely vegetated, and the soil is often covered with a blue-green alga (Nostoc sp.). It can also occur on disturbed soils such as rice fields, vacant lots, and pastures if the soil structure remains relatively intact. 990144BA.v-6 20 - 2/14/2000 <<>> An assessment of potentially suitable habitat for the prairie dawn was conducted by Horizon in early June 1999 along the Longhorn pipeline ROW in western Harris and eastern Waller counties from the Satsuma Station on the west edge of Houston to near Monaville in Waller County. Three areas along the ROW, one in Waller County and two in Harris County, exhibited native range conditions with suitable soils that could be considered potentially suitable habitat areas for the prairie dawn (Figures 4 to 12). All other areas along the pipeline within the area investigated had been converted to row crop (corn), monoculture, hay or grazing pasture, or disturbed for land development. A survey for the prairie dawn has not been conducted within the potentially suitable habitat areas to confirm its presence or absence. Longhorn will conduct a survey of the ROW within the potential habitat areas in March of 2000 to determine if the prairie dawn is present, and if so, its distribution and abundance. Navasota Ladies-tresses (Spiranthes parksil) The Navasota Ladies-Tresses (NLT) occurs primarily in moist, sandy soils in small openings amongst Post Oak Savannah vegetation associated with the Navasota, Brazos, and Trinity River drainages. The plant has previously been found in Brazos, Burleson, Freestone, Grimes, Fayette, Leon, Madison, Jasper, Robertson, and Washington counties. NLT are typically found on erosional remnants between rills in slightly to moderately eroded areas along minor intermittent tributaries of the Navasota, Brazos, and Trinity Rivers. NLT grows on sandy loam soils and is often associated with post oak, blackjack oak, yaupon, slender bigelowia (Bigelowia nuttallii), and Spiranthes cernua. The species has also been recorded in open savannahs and shrublands that have experienced little or no grazing pressure, and in hillside seepages. 990144BA.v-6 21 _ 2/14/2000 <<>> Louisiana FIGURE 4 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT SHEET LOCATION MAP LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT LONGHORN PIPELINE Gulf of Mexico FIGURE 5 HOUSTON HARRIS WALLER FIGURE 6 AUSTIN FIGURE 8 FAYETTE FIGURE 7 RAVIST AUSTIN BASTROP HAYS FIGURE 10 LLANO BLANCO GILLESPIE MASON FIGURE 9 MENARD KIMBLE FIGURE 11 SCHLEICHER 12° NOT TO SCALE FIGURE REAGAN CROCKETT LONGHORN REFINED PRODUCTS APPROXIMATE CITY LOCATIONS FOR Mexico 2: TEXAS NATURAL SUE 10197) (http://www.tnris.state.tx.us/data__az.html),1998 UPTON PIPELINE REFERENCE ECTOR ODESSA CRANE CRANE EXPLANATION CRANE <<>> FIGURE 5 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE DT-20a(K) DAWN-FLOWE! HARRIS CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION HOUSTON TOAD - DESIGNATED HABITAT Bufo houstonenses GOLDEN-CHEEKED WARBLER (Dendracia chrysoporio) BAD CADAD MIRED (SPOTA POES -TRESSES EDWARDS RECHARGE ZONE CONTRIBUTING ZONE ROSTER OTT TEXAS PRAIRIE -10 - CR-/ - SURGE 4 PIPELINE/ COUNTY BOUNDARY 199 HIGHMAY OR MAJOR ROADS CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES HERBON AGAIN LOCATIONS LONGHORN PIPELINE ROADS BRIDGES CEMETERY —I1P-2516 MANTENICE CONSTRUCTION TEXAS PRAIRIE DAWN-FLOWER WALLER EXPLANATION ##### RAILWAYS - -50756-3 1.5 MILES PINE ISLAND 4. TROT: HOREON SNORIN SE IS 1909AE 8. HORIZON MPONMONTAL SERMICES, INC, SITE BMESTIGATION (JIME 1990) 5 PER TO PASS ME PAL BED MIS PUNTS OF 159 2. RESOURCES ORATION SET 1700 2. TS NEH MOD BIA SONG 10D, OF TEAS 529 SON SAMS <<>> USTIN, WASHINGTON FIGURE 6 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE NAVASOTA LADIES-TRESSES CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION Condo CO MARGUER BAD CAPPED VIREO EDWARDS RECHARGE ZONE CONTRIBUTING ZONE 257 OLDENBURI - CR-1 - SURGE 4 EE HONY OR MANOR ROMOS CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY — LIP-2546 MICATONICE CONSTRUCTION EXPLANATION - SITE 6-3 NAVASOTA LADIES-TRES: FAYETTE MILES 6. HORIZON EIMIRONMENTAL SERNCES, INC, SITE IMMESTGATION (JUNE 1999) * PONTES TREAD ELBERT MATE PUNTS OF 2. RESOURCES TORTON SISTEN 37/ 2. TAS ABA MO BE SERE 1OED, OF TOUS. LEE SOURCES <<>> FIGURE 7 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE SES-TEAS COLORADO HOUSTON TOAD (POTENTIAL HABITAT) PIPE REPLACEMENT CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION HOUSTON TOAD - POTENTIAL HOUSTON TOAD - DESIGNATED CRITICAL HABITAT HABITA (Bufo houstonemsis) BAD CARD VIRED MAMOTAY POTS-TRESSES EDWARDS RECHARGE ZONE CONTRIBUTING ZONE -67-1 - SURGE 4 - HIGHWAY OR MAJOR ROADS BASTROP® — COUNTY BOUNDARY CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —4P-2516 LOCATTMNICE CONSTRUCTON EXPLANATION - SITE 6-3 INC, SITE INSTIGATION (JUNE 1999) DED MATE PUNTS OF BUT SERE TOES OF TOAS 1. TOAS NATURAL DE 3. DETERMATION OF CRITICAL 8. HORIZON EMIROMMENTAL SERMICES, 2. Tot COUNTY 4. THREATE P <<>> FIGURE 8 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE EDWARDS HAYS TRAVİS CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION Tomotocette tok CTUs SANSON POTS -TRESSES EDWARDS RECHARGE ZONE CONTRIBUTING ZONE ONTRIBUTING ZONE -CR-/ - SURGE 4 DRIPPING SPRINGS HIGHWAY OR MAJOR ROADS • COUNTY BOUNDARY CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES HENDER ANG PETON LOCATIONS LONGHORN PIPEUNE GOLDEN CHEEKED MA RONDS RAILWAYS BRIDGES CEMETERY —LLP-2516 MANTEMANCE CONSTRUCTION EXPLANATION -- ###### — SITE 6-8 SITE 6- PEDES MESTICATIONS, F REGUME PONCORD SPORES, OF TEUS 6. HORIZON DRONENTAL SERMCES, INC, SITE ESTIGATON (UNE 1999) * POTES PRES LA SEPT ME FURTS OF BLANÇO ME SAMOS <<>> FIGURE 9 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE BLACK-CAPPED VIREO BLANCO • GOLDEN-CHEEKED WARBLER CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION Taco Deto TobacTS EDWARDS RECHARGE ZONE CONTRIBUTING ZONE - CR-/ - SURGE 4 HIGHWAY OR MAJOR ROADS WARBLER - COUNTY BOUNDARY CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES MEMBER AS RATIN COCATIONS LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —LP-2516 MANTENNCE CONSTRUCTION EXPLANATION — SITE 6-3 Cool PIPELINE DIGORED SPECIES NESTIOMONS, EPPELME ÇILLESPIE 3. OCTEPMATO, OE CEMEM, HA PS AR HT SIR RT &. HORIZON EMIROMMENTAL SERVICES, MC, SITE INVESTIGATION (JUNE 1999) SPORTED PRESSED FLOURE DET MIME PUNTS OF 2 TS TO ME BUT SAME TOE OF TENS LLANO SAT MATRA SEA MAP SANCES 4. THREATEN HORROR <<>> ELINE LIANO FIGURE 10 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE E BLACK-CAPPED VIREO y GOLDEN-CHÉEKED WARBLER CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION HOTTA TO NOLOTOROMENTAL GILLESPIE NAVASOTA LADIES-TRESSES (Spironthes portsil) EDWARDS RECHARGE ZONE CONTRIBUTING ZONE LOVEY CHERRY 2242 GOLDEN-CHEEKED WARBLER - CR-/ - SURGE 4 COUNTY BOUNDARY • HIGHWAY OR MAJOR ROADS CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —11P-2516 MANTERAMCE CONSTRUCTION EXPLANATION ! - S175 6-8 SITE MASON MC, SITE IMESTONOM (AME 1990) DES OF TENS: MILES 5 PRETE PASS ME UP DEPT ME RUNTS OF ENTAL SERVES PIPELINE QURASS MAR SOUPOSS 4. THREATENED OR DID &. HORIZON <<>> -GILLESPIE BLACK-CAPPED VIREO FIGURE 11 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE PIPELINE MASON 0т-90 (K) CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION HOUSTON TOAD - DESIGNATED HABITAT (Buto houstonensis) MASOTA PORS-TRESSES EDWARDS RECHARGE ZONE CONTRIBUTING ZONE - CR-/ - SURGE 4 - COUNTY BOUNDARY → I HIGHNAY OR MOR ROADS CITY STREETS - RIVERS AND STREAMS NTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY — LLP-2546 MOCATIMANCE CONSTRUCTION 1-8 ALIS SURGE 4. 871 EXPLANATION иннинин KIMBLE - SITE 6-3 LONDON TOBUSCH FISHHOOK CACTUS 3480 YATES EACUP POUNCERED SORDES oF TEMS. 6. HORIZON ENMRONMENTAL SERVICES, IMC., SITE IMVESTIGATION (JUME 1999) SO PARCE PROTEST MADE PLANTS OF MENARD HAS SOURCES I BEATENED OR EHDAN 2. THREATPNED AND <<>> BLACK-CAPPED VIREO FIGURE 12 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE CACTÚS LOCATION SITE 8-3 CPGB-s : KIMBLE CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION HOUSTON TOAD - DESIGNATED HABITAT (Bufo houstonents COLDEN-CHEEKED WARBLER Dendrocio chrysaparna LAVASOTA LADIES-TRESSES TOBUSCH FISHHOOK CACTUS Spiranthes pantsi EDWARDS RECHARGE ZONE CONTRIBUTING ZONE - CR-1 - SURGE 4 MENARD HEADER ANSARI LOCATIONS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES CITY STREETS LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —11P-2516 MANTELANCE CONSTRUCTION EXPLANATION — SITE 6-2 B-8 JUIS ANGERED SPECES, MISTATORS, EZ PROLAE 6. HORIZON EMRONMENTAL SERMCES, INC, SITE MESTONTOM (JUNE 1990) 5 PEAS TEE PRESIDE ST MINE PUNTS OF 2 RESOURCES TORMATION SITE 15P ORVETT SUTTON SCHLEICHER " Copperas MAR SORCES A THREATE <<>> In Fayette County, the species is known from one small population approximately 6 miles south of the pipeline and 2 miles north of the town of Fayette. Based on analysis of soil distribution, vegetative cover, physiographic setting, and field assessment by Horizon in November of 1999, two small areas of potential habitat for NLT are present along the pipeline corridor (Figures 4 to 12). No surveys for the species have been conducted along the pipeline. Longhorn will conduct a Fall survey (15 October to 15 November, 2000) for this species within the ROW if suitable climatic conditions occur to determine the presence or absence of this species, and if present, its distribution and abundance. Tobusch Fishhook Cactus (Ancistrocactus tobuschii) Rounded, biscuit-shaped cacti usually 2 to 3 inches tall and up to 3.5 inches in diameter. There are 3 to 5 central spines with the upper 2 to 3 erect and straight and the lower central spines hooked at the tip and spreading. Occurs on limestone gravels of stream terraces, limestone ledges, ridges, and openings on the rocky hills of live oak - juniper woodlands. The Tobusch fishhook cactus has been documented in Kimble County. An assessment of potentially suitable habitat and pedestrian survey for the cacti was conducted by Horizon in April 1999 along portions of the Longhorn pipeline ROW in Kimble County, and no specimens were observed within the ROW. However, one Tobusch fishhook cactus was observed approximately 50 feet north of the cleared ROW (Figures 4 to 12). Longhorn will conduct a blooming period survey (March to April 2000) within the ROW throughout Kimble County to determine the species' distribution and abundance. Houston Toad (Bufo houstonensis) The Houston toad is 2.0 to 3.5 inches long with general coloration varying from light brown to gray or purplish gray, sometimes with green patches. The pale ventral (underneath) surfaces often have small dark spots. The toad is a terrestrial amphibian associated with deep sandy soils within the Post Oak Savannah vegetational area of east central Texas. The vegetation type of currently known Houston toad sites can typically be described as pine or oak 990144BA.v-6 31 - 2/14/2000 <<>> woodland or savannah, with native bunchgrasses and forbs (flowering plants) present in open areas. For breeding, including egg and tadpole development, Houston toads also require still or slow-flowing bodies of water that persist for at least 30 days. The source of ephemeral or permanent water should be located within one-half to three-quarters miles of the toad=s hibernation/foraging habitat (deep sands supporting woodland or savannah). Critical habitat was designated for the Houston toad 31 January 1978, of which a portion of Longhorn pipeline traverses through in Bastrop County (Figures 4 to 12). The Longhorn Pipeline ROW within the Houston toad Critical Habitat area is immediately adjacent to the Phillips EZ Pipeline ROW which Horizon studied in 1991 for endangered species. As part of Horizon's studies, a Houston toad survey was conducted along the EZ Pipeline corridor in 1991 by Dr. James R. Dixon of Texas A&M University with negative results, although minor potential habitat areas were noted (Horizon, 1991). Horizon conducted a reevaluation of suitable habitat along the Longhorn Pipeline ROW within Bastrop County. The field reconnaissance was conducted on 2 June 1999 from the Colorado River, southeast of Bastrop, to FM 2104. Within the designated Critical Habitat, portions of the area along the pipeline had been cleared and planted in improved grasses. These areas were determined to be unsuitable for Houston toad occupation. Based on field observations, and confirmation by the Service, it was determined that two areas of potentially suitable habitat existed along and adjacent to the pipeline ROW. One area included Buescher State Park from approximately 1/2 of a mile to the east of the eastern boundary of the park westward to near Highway 71. The majority of this area contained a moderately thick understory with all drainages flowing south toward the Colorado River. The second area began approximately 500 feet to the west of FM 2104 and extended westward approximately 3/4 of a mile. This area contained two stock tanks with the majority of the surrounding area exhibiting a moderately 990144BA.v-6 32 - 2/14/2000 <<>> thick understory and pine re-growth. The drainages in this area also flowed to the south toward the Colorado River. One or more additional spring surveys (as acceptable to the Service) for the toad will be conducted along and downstream of the pipeline to determine the presence or absence of toads and their overall distribution and abundance. Golden-cheeked Warbler (Dendroica chrysoparia) The golden-cheeked warbler (GCW) is a small, migratory songbird, 4.5 to 5 inches long, with a wingspan of about 8 inches. The male has a black back, throat, and cap, and yellow cheeks with a black stripe through the eye. Females are similar, but less colorful. The lower breast and belly of both sexes are white with black streaks on the flanks. Typical nesting habitat is found in tall, dense, mature stands of Ashe juniper (cedar) mixed with trees such as Texas (Spanish) oak, Lacey oak, shin (scalybark) oak, live oak, post oak, Texas ash, cedar elm, hackberry, bigtooth maple, sycamore, Arizona walnut, escarpment cherry, and pecan. This type of woodland generally grows in relatively moist areas such as steep-sided canyons and slopes. A mix of juniper and deciduous trees on the slopes, along drainage bottoms, and in creeks and draws provide an ideal mix of vegetation for birds. Warblers are also occasionally found in drier, upland juniper-oak (i.e. live oak, post oak, blackjack oak) woodlands over flat topography. An assessment of potentially suitable habitat and surveys for the GCW was conducted by Horizon in April and May 1999 along the Longhorn pipeline ROW from Austin, Texas, to the Mason/Kimble County line. Although no potentially suitable habitat areas were observed within the Longhorn ROW, several areas were located adjacent to the previously cleared permanent ROW. All areas were surveyed by Horizon a minimum of 5 times during April and May on days with favorable weather conditions for bird activity, per US Fish and Wildlife Service guidelines (FWS, 1994). Surveys were conducted on 8, 9, 12, 27,28 April, and 3, 11, 19 May. An equivalent of 4 person-hours per 100 acres were spent at each site, based on habitat size. No GCWs were found to be utilizing any of the potentially suitable habitat areas on or immediately adjacent to the ROW. One to two additional spring breeding season surveys (as acceptable 990144BA.v-6 33 - 2/14/2000 <<>> to the Service) will be conduced for the GCW along and adjacent to the ROW within the potential habitat areas to determine habitat utilization and overall distribution and abundance. Black-capped Vireo (Vireo atricapillus) The black-capped vireo (BCV) is a 4.5 inch long, insect-eating songbird. Mature males are olive green above and white below with faint greenish-yellow flanks. The crown and upper half of the head is black with a partial white eye- ring. The iris is brownish-red and the bill black. The plumage of the female is duller than the male. Females have a dark slate gray head. In Texas, vireo habitat is found on rocky limestone soils of the Edwards Plateau, Cross Timbers and Prairies, eastern Trans-Pecos, and, to a limited extent, on igneous soils in the Chisos Mountains. BCVs require shrub vegetation reaching to ground level for nesting cover. They typically nest in shrublands. An assessment of potentially suitable habitat and surveys for the BCV was conducted by Horizon in April and May 1999 along the Longhorn pipeline ROW from Austin, Texas to Crane County. Potentially suitable habitat areas were observed within the Longhorn ROW as well as several areas located immediately adjacent to the previously cleared permanent ROW. All areas were surveyed by Horizon a minimum of 5 times during April and May on days with favorable weather conditions for bird activity, per US Fish and Wildlife Service guidelines (FWS, 1994). Surveys were conducted on 8, 9, 12, 27, 28 April, and 3, 11, 19 May. An equivalent of 4 person-hours per 100 acres were spent at each site, based on size. No BCVs were found to be utilizing any of the potentially suitable habitat areas on or immediately adjacent to the ROW. One to two additional spring breeding season surveys (as acceptable to the Service) will be conduced for the BCV along and adjacent to the ROW within the potential habitat areas to determine habitat utilization and overall distribution and abundance. Bald Eagle (Haliaeetus leucocephalus) The bald eagle is a migrant and winter resident in Texas. The bald eagle was recently down-listed from endangered to threatened due to successful conservation efforts and is now proposed for de-listing. Migrating and wintering 990144BA.v-6 34 - 2/14/2000 <<>> bald eagles typically arrive in Texas in November and depart sometime in February. They are found primarily in association with reservoirs, rivers or other large bodies of water where they feed on fish, carrion, and waterfowl. Nesting bald eagles in Texas are found in the eastern portion of the state and along the coastal plain as far south as Calhoun and Refugio counties. No bald eagle nests have been identified near the pipeline ROW, however, bald eagles may occur along major waterways (Brazos and Colorado rivers, or major tributaries with impoundments) downstream of the pipeline corridor. The Federal Register, Volume 64 No. 128 (Tuesday, July 6, 1999; Page 36454) puts forth a proposed rule to remove the bald eagle from the List of Threatened and Endangered Wildlife In the Lower 48 States of the United States and de-listing is expected in the near future. The action is proposed because available data indicates that the species has recovered. Interior Least Tern (Sterna antillarum athalassos) Premier nesting sites for the interior least tern are salt flats, broad sandbars, and barren shores along wide, shallow rivers. Important breeding habitat characteristics include: (1) presence of bare or nearly bare ground and alluvial islands or sandbars for nesting; (2) availability of food (primarily small fish); and (3) favorable water levels during the nesting season (so nests remain above water). They usually nest on sites devoid of vegetation, but have been found in areas with an average of 11 to 30% vegetative cover, composed of grasses, shrubs, and trees and ranging from 1 to 3 feet in height. Vegetation, if present, is usually located well away from the colony, with the exception of bugseed, eastern cottonwood, and sandbar willow. As natural nesting sites have become sparse, birds have used sand and gravel pits, ash disposal areas of power plants, reservoir shorelines, gravel levee roads, and other manmade sites. The typical nesting period for the least tern in Texas is mid-April to mid-August. While the interior least tern has not been documented along the pipeline corridor, potential habitat for the tern is present downstream of the pipeline along several major waterways including the Brazos, Colorado, Llano, and James Rivers, and Squaw, Beaver, and Sandy Creeks. The seasonal occurrence 990144BA.v-6 35 - 2/14/2000 <<>> (spring and summer) and potential nesting of least terns is possible in these areas. Conclusions In conclusion, of the 29 federally listed species of potential occurrence in counties traversed by the Longhorn Pipeline between Houston and Crane, only 8 of those species are documented or estimated to occur within the area of potential effect for the pipeline safety projects due to the presence of potentially suitable habitat. None of the species have been documented to occur within the existing ROW of the pipeline, but several have been documented within proximity, either by suitable habitat, or by sightings of individuals. Additional surveys for the Texas prairie dawn-flower, Navasota ladies-tresses, Tobusch fishhook cactus, Houston toad golden-cheeked warbler, and black-capped vireo will be conducted to further document their presence or absence and population densities in the vicinity of the pipeline. These surveys must be conducted during certain narrow seasons, and therefore, can only be conducted once per year. The survey season for the prairie dawn, fishhook cactus, and Houston toad is February to April. The season for the GCW and BCV are late March to late May. The season for the ladies-tresses is October to November. 990144BA.v-6 36 • 2/14/2000 <<>> 4.0 PROJECT DESCRIPTION Longhorn will implement various pipeline safety and integrity enhancements for the pipeline that include various methods of pipeline testing, anomaly investigations, ROW maintenance, section replacements, cathodic protection enhancements, and pipeline lowerings. Table 2 contains a summary of the proposed projects relating to clearing, maintenance construction, hydrostatic testing, and other integrity-related projects that are addressed in this BA (ref. Project Documentation Appendix at Tab 2). Following is a general description of these safety enhancement projects and the methods by which they will be implemented for the Longhorn Pipeline System. Additional detail may be found in Construction Specification CS4 contained in the accompanying Project Documentation Appendix at Tab 4. 4.1 RIGHT-OF-WAY CLEARING AND MARKING Longhorn has committed to bring the surface of the ground within the ROW into "excellent condition" in order to facilitate surveillance prior to startup of the pipeline (ref. Project Documentation Appendix at Tab 2). Excellent condition is that condition which provides a clear line of sight for aerial and ground surveillance patrols in order to effectively monitor and inspect the ground surface along the ROW. A clean and clearly marked ROW provides a distinctive line of demarcation, indicating a change in land use, where surrounding terrain is natural or heavily developed. ROW maintenance will include mowing, brush-hogging, back-dragging, or hand trimming of tall grass or woody re-growth, trimming of tree canopies overhanging the ROW, setting signs, marking points of intersection (horizontal bends) in the pipeline with PVC posts, and painting cross-fence posts. ROW mowing is performed by a twin-blade mower or a brush-hog drawn by a tractor, to a height between two and four inches. Back-dragging is a method of clearing in rocky terrain; back-dragging involves pulling a dozer blade backwards across the ground surface which has the effect of bending vegetation over at the ground surface. Back-dragging typically does not result in the 990144BA.v-6 37 - 2/14/2000 <<>> uprooting of vegetation. Rather, the vegetation is bent or broken just above the ground surface. Back-dragging is used only in areas where rocks on the surface pose a risk of damage to a mower or brush-hog. Weedy vegetation around surface facilities such as valve settings is at times treated with herbicides such as Roundup and Rodeo. Hand trimming involves line trimmers, chain saws, and similar hand-held equipment. Tree canopies are trimmed by workers, using chain saws, that are raised within reach of the canopies by a man-lift. Steel sign posts are typically set by driving the posts directly into the ground. PVC posts are set into shallow holes dug by post-hole digger. In limited circumstances such as when vandals repeatedly remove pipeline markers, sign- posts are dug by post-hole digger to allow the posts to be set into concrete. Clearing within areas identified as endangered species habitat will not result in any ground disturbance because only mechanical or hand cutting will be employed. The term ground disturbance is intended to mean soil disturbance that would result from grubbing brush and tree stumps; rather, they will be cut at ground level. In limited circumstances, stumps directly over the pipeline, which could have adverse effects on the pipe, will be hand-treated with minimal amounts of non-aromatic and non-persistent herbicide to retard re-growth. Herbicides will be applied in accordance with EPA-approved label directions. These activities are routine and are conducted periodically by pipeline operators in the United States. All areas of the ROW are subject to periodic clearing form time to time. ROW clearing occurs at intervals that depend upon the rate of vegetation growth, typically averaging once per year in arid and semi-arid territory (generally, from Austin to Crane) and typically averaging twice per year in territory with greater rainfall (generally, Houston to Austin). Further, metropolitan areas may be mowed as frequently as monthly to meet municipal ordinance requirements and in response to landowner requests. ROW clearing will be conducted on a schedule that avoids impacts to species; for example, Houston toad habitat will be avoided during the warmer seasons (February through November) when 990144BA.v-6 38 - 2/14/2000 <<>> toads are typically active and potentially upon the surface of the ROW, and plant habitat areas are avoided during the respective blooming seasons. 4.2 PIPELINE MAINTENANCE - CONSTRUCTION PLANNING Prior to project engineering and scheduling, each site is surveyed by qualified personnel to determine whether or not the activity (a) may affect threatened or endangered species and habitat, (b) may cause disturbance of cultural resources, (c) may be subject to Clean Water Act Section 404 (U.S. Army Corps of Engineers jurisdiction over dredge and fill materials in waters of the United States), or (d) may be subject to other federal, state or local laws, regulations or ordinances. Appropriate authorizations are obtained (such as this consultation), and necessary requirements are identified and incorporated into project planning and engineering documentation. Project engineers and technicians perform site inspections to identify site- specific conditions and features that require consideration in project planning, such as site ingress/egress routes, workspace requirements, spoil management, equipment storage, servicing and parking needs, and the like (ref. Tab 5, Environmental Protection Plan, and Tab 6, Storm Water Pollution Prevention Plan in the accompanying Project Documentation Appendix). Such considerations are incorporated into project planning and engineering activities. Unless required by the particular project or by site conditions, workspace is limited to the established ROW. Where workspace is required beyond the limits of the established ROW, those areas have been incorporated into project documentation. 990144BA.v-6 39 - 2/14/2000 <<>> Comments Avoid February through April Avoid February through April Avoid February through April Avoid October through November Avoid October through November Avoid February through October Avoid February through October Avoid March 15 through September 1: Avold March 15 through September 1. Avoid March 15 through September 1 Avoid March 15 through September 1 Avoid March 15 through September 1 Avoid March 15 through September 1 Avold March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Avold March through July Avold March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Species Texas Prairie Dawni Texas Prairie Dawn Texas Prairie Dawn Navasota Ladies-Tresses Navasota Ladies-Tresses Houston Toad Houston Toad :: EA Contributing Zone Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Black-Capped Vireo Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Black-Capped Vireo Golden-Cheeked Warbler Black-Capped Vireo Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Black-Capped Vireo Black-Capped Vireo Black-Capped Vireo Tobusch Fishhook Cactus TABLE 2 2000 MAINTENANCE ACTIVITIES TESTING AND CLEARING LONGHORN PIPELINE County Harris Harris Waller Fayette Fayette Bastrop Bastrop Travis/Hays Hays Hays Hays Hays Hays/Blanco Blanco Blanco Blanco Blanco Gillespie Gillespie Gillespie Gillespie Gillespie i Gillespie Mason Mason Mason Mason Mason Mason Kimble End Station 2279+20 2411+20 2831+84 5128+64 5948+80 6638+72 6864+00 9961+60 9674+72 9762+72 9926+40 10036+40 10199+20 10461+44 11036+96 11105+60 11441+76 11751+52 11821+92 12149+28 12606+88 12631+52 12728+32 12953+60 13110+24 13217+60 13305+60 13437+60 13578+40 16329+28 Right-of-Way Clearing (Maintenance) - See Comments for Avoidance Timing Begin Station 2013+44 2310+88 2684+00 5095+20 5936+48 6600+00 6723+20 9152+00 9657+12 9724+00 9850+72 9945+76 10164+00 10266+08 11008+80 11080+96 11295+68 11691+68 11791+28 12114+08. 12513+60 12596+32 12633+28 12921+92 13043+36 13203+52 13277+44 13381+28 13513+28 14476+00 Site Right-of-Way (50) Right-of-Way (50) Right-of-Way 50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-or-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50*) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) <<>> Comments Avoid March 15 through September 1 nvestigation of possible dent; access from improved road to ROW, then 1000 feet down nvestigation of possible anomaly: access from improved road to ROW, then 3000 feet Site entry only, via 5936+48-5948+80 Lowering / Replacement; access. under mproved road to ROW, then 1000 feet down Lowering / Replacement; access from Lowering / Replacement: access from improved road to ROW, then 1000 feet down improved road to field road, then via field road Lowering / Replacement: access from Lowering / Replacement; access from improved road to ROW, then 600 feet down Lowering / Replacement; access 800 feet down ROW from Site LPP-2751 Lowering / Replacement; access from improved road to ROW, then 2500 feet down Investigation of possible dent; access from improved road and dirt road to ROW, then nvestigation of possible dent; access from improved road to ROW, then 1000 feet down nvestigation of possible dent; access from Improved road, 3700 feet of unimproved road to ROW. then 7000 feet to project site ROW down ROW development ROW to project site. ROW to project site 1300 feet down ROW ROW ROW Species Black-Capped Vireo Texas Prairie-Dawn Texas Prairie Dawn Navasota Ladies-Tresses Barton Springs Salamander (EA Contributing Zone) Barton Springs Salamander (EA Contributing Zone) Barton Springs Salamander (EA Contributing Zone) Barton Springs Salamander (EA Contributing Zone) Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Black-Capped Vireo Black-Capped Vireo Black-Capped Vireo EA Contributing Zone County Kimble Harris Harris Fayette Travis Travis Travis Hays Blanco Blanco Gillespie Gillespie Gillespie Mason Travis End Station 15234+56 2073+52 2737+37 5931+12 9197+24 9222+24 9488+24 9807+42 10373+24 10381+24 11725+71 12659+39 12682+16 14012+73 Begin Station 15153+60 2073+52 2737+37 5926+74 9195+80 9220+80 9483+31 9807+10 10369+55 10380+60 11725+22 12659+39 12682+16. 14012+73 Hydrostatic Pressure Test - Header Installation Locations 9338+50 Site Maintenance Construction Right-of-Way (50") DT-20a (K) Crossing (K) 2008 (K) Ph. 1 LPP-2467 LPP.2471 LPP-2546 LPP-2627 LPP-2751 LPP-2753 2016 DT-12a (K) DT-11 DT-9a (K). Site 5-5 <<>> Comments CP Ground Bed - Kimble County Station Coating Reconditioning Coating Reconditioning Coating Reconditioning Species Near Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Black-Capped Vireo Tobusch Fishhook Cactus Tobusch Fishhook Cactus Tobusch Fishhook Cactus Tobusch Fishhook Cactus Texas Prairie Dawn Texas Prairie Dawn Navasota Ladies-Tresses Barton Springs Salamander (EA Contributing Zone) and Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler and Black-Capped Vireo Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler and Black-Capped Vireo Golden-Cheeked Warbler and Black-Capped Vireo Black-Capped Vireo Tobusch Fishhook Cactus and Black-Capped Vireo Tobusch Fishhook Cactus and Black Capped Vireo Texas Prairie Dawn Houston Toad Houston Toad Tobusch Fishhook Cactus County Blanco Blanco Blanco Mason Kimble Kimble Kimble Kimble Harris-Waller Waller Fayette Travis-Hays Hays-Blanco Blanco Blanco Blanco Blanco-Gillespie Gillespie Gillespie-Mason Mason Mason Kimble Kimble Harris Bastrop Bastrop Kimble 2128+97 6612+99 7085+24 End Station 2415+50 3385+00 5966+47 10163+00 10265+00 10504+50 11188+00 11385+50 12033+73 12360+00 13040+00 13435+00 13910+00 14606+00 16992+40 15592+90 10163+00 10265+00 10742+50 11188+00 11385+50 12033+73 12360+00 13040+00. 13435+00 14373+00 2127+97 14606+00 6609+49 7084+74 Begin Station: 10163+00 10280+00 11385+50 13435+00 14606+00 15143+00 15586+00 16167+00 1802+63 2415+50 5039+00 9647+00 15592+90 Hydrostatic Pressure Test - Test Segments Cathodic Protection Enhancements Site Site 6-1 Site 6-2 Site 6-6 Site 7-3 Site 8-1 Site 8-2 Site 8-3 Site 8-4 Segment 2 ›Section 1 ›Section 2 Segment 3 Section 2 ›Section 6 Surge Pressure Protection Segment 5. Segment 6 > Section 1 > Section 2 ›Section 4 > Section 5. ›Section 6 ›Section 7 Segment7 ›Section 1 ›Section 2 ›Section 3. ›Section 6 Segment 8 (all) CR-1 CRA CR-5 CPGB-5 <<>> P 42 (aloiasua pota o, pus berapie is0 2: :2 AN25 CACOODCE DuNG. шо д : w Й becseegepe extnogou of Aru0o20. DA caco sabuo anioos Osgow S s 0020 .. i. god me bbonte noucu po erockhon Bypass Valve - Liano River East Bank; Same Location as Hydrostatic Test Header Location, s0 monic no s000sa0 at a 8 ¡ oise to omel oi obreco biba. mos miepentee sust uecoeism sit.et 600. r gognno tuondu bicly sompue i homo grin bioleg ais coucy pes ga. piar exebueur co.coon .23- .3CS0 32 ir moa pA 700 i 0u0 Species Tobusch Fishhook Cactus O4 2! •.txcile sucotubaer : a00 0 00l00ne) touecs Colp piespo Biotect pear wansdos trciecr bpumuo msi •A . :3G County Kimble 280 s.::00.sm1bou e bebstey o spo bucioct aLoDü: 3 LeME0 A O3DeOU: End Station 14606+51 amoura ne sioleci 7 ue pipee eug ynoigee Begin Station 14606+51 W500 wedmustene iiK:W0N S.00ORDU Site 2 JGane Surge 4. nosge sednpen its pudneuce o exeup) S слома higig roosgon sisb. <<>> Workspace beyond the limits of the established ROW may be required for a number of reasons. First, avoidance of habitat or the natural terrain along one side of the ROW may necessitate expansion of workspace along the opposite side of the ROW. Second, a sloping surface gradient at a project site may require that spoil removed from the pipeline trench be stockpiled with a wider base, extending off of the ROW, than would be required at a project site with a level surface. Further, a project to lower or replace pipe at a creek crossing may require water diversion measures that necessitate a workspace wider than the established ROW. In addition, though project equipment is typically aligned along the existing pipeline ROW, project site conditions such as size, shape and/or slope may require that equipment be centralized in an equipment marshalling area (typically 25 ft. wide by 100 ft. long). for temporary storage, security and/or service. Biological surveys encompass both areas of potential surface disturbance and areas within the zone of potential indirect construction impacts, such as noise. In addition, applicable project best management practices (BMPs) are identified at this stage of project planning and incorporated into planning documentation. A Project Construction Plan is prepared for each individual project location to document project planning. The Project Construction Plan contains the following sections of detailed information: a. Description of Work for the Project b. Responsibilities and Authorities Safety Requirements d. Job Contacts and Notification Requirements Matrix e. Pre-Job Training Requirements a. Environmental Protection b. Project Schedule C. Forms / Documents Required a. Chronological Sequence of Events b. Appendices as follows: i. Appendix 1 - Location Map ii. Appendix 2 - Drawings, Calculations, and 990144BA.v-6 43 - 2/14/2000 <<>> ili. Specifications iV. Appendix 3 - Environmental Protection Plan V. Appendix 4 - Storm Water Pollution Vi. Prevention Plan vii. Appendix 5 - Safety Procedures Document vili. Appendix 6 - Sample Forms An example Project Construction Plan (Site LPP-2627, pipeline lowering/replacement in Hays County, Texas) is included in the accompanying Project Documentation Appendix, at Tab 3, for reference. A Project Construction Plan relating to each project identified in Table 2 is presently under development; Longhorn will provide to the Service a copy of each Project Construction Plan as it is completed. Project BMPs are defined as procedures and specifications by which environmental controls will be implemented and include such items as sedimentation and erosion controls, reclamation procedures, minimization and avoidance procedures, inspection and reporting procedures, spill containment and cleanup procedures, procedures for addressing unforeseen circumstances, procedures for addressing foreseen, but unpredictable circumstances, and others. Project BMPs are identified and adapted from technical guidance manuals generally accepted as providing the appropriate environmental protection measures, such as the Texas Natural Resource Conservation Commission (TNRCC) technical guidance manual, Federal Energy Regulatory Commission (FERC) Environmental Guidance Manuals, and the City of Austin Environmental Criteria Manual. BMPs are incorporated within the Longhorn Storm Water Pollution Prevention Plan (SWPPP); an example of an SWPPP is included the accompanying Project Documentation Appendix at Tab 6. 990144BA.v-6 44 2/14/2000 <<>> 4.3 PROJECT ENVIRONMENTAL INSPECTORS Longhorn and Williams shall employ the services of environmental inspectors (such as Horizon and 3D/International) at every project site with associated species-related constraints. These environmental inspectors are qualified under FERC guidelines. The environmental inspector will remain at each project site during the period of activity to ensure compliance with all project constraints and project BMPs. The inspector is authorized to dictate any additional project BMPs that may become necessary during the activity and to modify work activities and progress to the extent necessary to ensure compliance with project environmental constraints. However, in the event of a conflict between project constraints and sound engineering practices, the inspector shall consult with project engineers and the Service, as appropriate, to achieve project goals while minimizing any impacts to the environment. The environmental inspector retains oversight of site closure and performs, or supervises the performance of, post-activity inspections of project BMPs until site stabilization is achieved. The environmental inspector will produce appropriate documentation for each construction location to include BMP compliance logs, photographs, as- built dimensions of disturbance, and any encounters with listed species during the construction process. The reports will be provided to the Service after completion. 4.4 SITE PREPARATION Prior to site entry, at locations where avoidance and/or minimization of species effects has been recommended, a qualified biologist will clearly identify areas for avoidance and will stake and/or flag such areas. The project environmental inspector also surveys the site to ensure that all such avoidance areas are clearly identified in accordance with conditions approved in the consultation process and confirms other site-specific areas in which disturbances may occur such as routes of ingress/egress, spoil management areas, equipment marshalling areas, workspace areas, and the like. Project BMPs are reviewed prior to site entry, and the locations of any necessary physical control measures to be employed are identified. A survey crew will precede the project equipment and mark the project 990144BA.v-6 45 - 2/14/2000 <<>> boundaries. In addition, the pipeline centerline is marked at 100 foot to 200 foot intervals. 4.5 SITE ENTRY Upon site entry, the necessary project equipment is transported to the site via the designated route for ingress/egress. Site access is achieved via improved roadways and the established ROW, using the shortest available route between improved roadways and the project site. Routes of ingress/egress take into account any potential for effects to threatened and endangered species and habitat that may exist along the ROW between the improved roadway and the project site, as well as accounting for other potential impacts to the environment. At times, equipment will remain on-site only during the time that it is in active use to allow it to be shared between project sites in close proximity. Prior to any excavation, site vegetation is removed, and project BMPs are installed. Site vegetation is cleared to the extent necessary for project completion, so long as the vegetation is not located in areas identified for avoidance. Clearing is accomplished by the methods described in Section 4.1, Right-of-Way Clearing, though vegetation within the workspace may require removal. Project BMPs are installed in accordance with project planning documentation and in accordance with the site-specific SWPPP. The following task descriptions identify process steps that occur once all authorizations are obtained and regulatory requirements are identified and incorporated into project planning and engineering documentation. Detailed procedures for each of the activities summarized below are available in Pipeline Construction Specification CS4, which is included in the accompanying Project Documentation Appendix at Tab 4. In the event of a conflict between Construction Specification CS4 and the site-specific components of the Project Construction Plan, the Project Construction Plan controls. 4.6 PIPELINE LOWERING AND/OR REPLACEMENT - OPEN TERRAIN Once the project site has been prepared and equipment brought onto the location, the following major activities take place: 990144BA.v-6 46 - 2/14/2000 <<>> • Isolate pipeline segment to be replaced by cutting and plugging at boundaries. Williams operating personnel will establish that the line is unpressurized and properly isolated such that the contractor may cut the pipeline at the project limit boundaries. Mechanical plug devices will be utilized to prevent residual product leakage from the pipeline segments or entry of foreign materials into the pipeline. These devices shall be secured to prevent their loss or tampering. • Remove large rocks, if any, from ROW work area to appropriate disposal/storage area. Trackhoes with buckets are used, unless larger rocks require grapple capable (clam) buckets. • Remove and set aside topsoil spoil (double ditch practices). Double-ditching will be required in areas where native plant communities need to be re-established, or there are topsoil improvements, such as sodded lawn areas and cultivated fields. Double-ditching allows topsoil management by making two passes to remove and segregate spoil; one to remove and set aside topsoil and one to remove and set aside subsoils. • Remove overburden and expose pipe. Utilizing track hoes, remove and set aside overburden from the pipeline and load and remove excess amounts from the work site for disposal. Unsuitable overburden (i.e., large rocks) will be disposed of in approved sites. • Cut pipe into subsections at road and water crossings. Expose and cut the pipeline at road crossing boundaries to isolate the removal section into subsections. Utilize drain pans to recover any remaining liquids as the cut is made. Install mechanical plugs in all exposed pipe ends. • Raise and crib pipe on side of trench. Properly manage any coating which comes loose from the pipe. 990144BA.v-6 47 - 2/14/2000 <<>> Prepare and wrap pipe for disposal. Double wrap the pipe sections with 6-mil thickness plastic wrap, taping and sealing each wrapping separately. Ensure that the ends are sealed to prevent any release of coating. • Remove pipe from ROW. Load and remove the wrapped pipe sections by truck. Care will be taken to preserve the plastic wrapping on the pipe. Secure the pipe to the trailer and haul to the disposal site for final disposition. • Cleanup and grade ROW for survey and trenching operations • Capture, contain, and remove any remaining coating materials/scraps using project-prescribed methods for asbestos containing materials. Prepare the grade on either side of the ditch to accommodate the trenching machinery, removing any large rocks. Survey crew should mark and stake the centerline offsets as required by the trenching crew. • Deepen trench to new depth. Depending upon the length of the desired lowering and/or replacement, and depending upon whether the trench is in soil or rock, a track-hoe or wheel trencher (rock saw") deepens the trench to the new depth. A wheel trencher is typically used for longer trenches and trenches in consolidated rock. Dust generation is monitored during trenching, and a water fog of the trenching mechanism may be employed to minimize airborne dust in non-rural areas. • String new pipe along trench. As the ditch is prepared, the pipe may be strung along the workpad in anticipation of measuring and marking for bending, welding, and lowering operations. The survey crew will note the pipe heat and identification numbers sequence for the individual pieces as they are placed. The survey crew will survey the new ditch profile and mark the pipe for calculated field bends. 90144BA.v- 48 2/14/200 <<>> • Make field bends. The field bending crew will proceed ahead of the welding crew to make any required field bends. The contractor may also elect to set up field bending in one of the equipment marshalling areas and perform bending there rather than on the ROW. Weld and Radiograph new pipeline. The welding crew will proceed to weld the pipeline. Inspectors and survey will note the weld numbers and identification of the welders for this activity. The radiography crew will follow the welding crew. Inspection will be per standard specification API 1104 and include 100% radiography of all girth welds. • Apply weld joint coating and inspect pipeline coating for "holidays"; a holiday is a point where the coating fails to electrically insulate the pipe. Weld joint coating will be applied as specified in the Project Construction Plan. This will be by field-applied FBE (fusion bond ероху). Following weld joint coating, the entire coating system will be inspected for holidays and repaired as required. • Pad and lower pipe. Pad the ditch and lower the pipeline as specified in Construction Specification CS4. Install ditch plugs as required to stabilize pipeline during hydrotest and backfilling. The pipeline coating will receive a final "jeeping" as the pipe is lowered to ensure its integrity. Jeeping is the process of electrically inspecting the pipeline coating to ensure that no "holidays" exist in the coating, so named due to the "jeeping" sound the inspection device emits when a holiday is identified. • Complete as-built survey. Complete as-built survey activities, noting weld locations, pipe identification codes, and location and stationing of bends, fittings and other such features for inclusion in alignment sheet drawings. • Backfill and compact trench. Backfill and compact the ditch according to Construction Specification CS4, maintaining sufficient 990144BA.v-6 49 - 2/14/2000 <<>> cover to allow for settling. Install ditch breakers and silt fencing as appropriate for surface erosion control until the site is stabilized. • Perform hydrostatic pressure test on new pipeline segment. Obtain fresh water for pressure test and begin line fill behind a pig. The test pressure and test duration will be established and specified in the Project Construction Plan or in separate hydrostatic testing plans. Drain and dispose of hydrostatic test water. Upon completion of the hydrostatic test, the test water is either pushed with nitrogen to a subsequent test site or removed into mobile tanks for hauling to a disposal facility. Test water is controlled to ensure that it is fully contained in order to prevent discharge to the environment. • Perform Final Tie-Ins. Remove the test headers and make the final tie-ins of the new pipe segment to the existing pipeline. The tie-in welds will be 100% radiographed to ensure their integrity. Coat the tie-in welds with an appropriate joint coating system compatible with both FBE and coal tar coatings. The coating is inspected, or "jeeped," and any holidays are repaired. The tie-in locations are backfilled and compacted. • Clean, Grade, and Seed Right-of-Way. Following installation of erosion control measures, re-seed the right-of-way with native grass seed and/or sod as prescribed for the location. Re-install pipeline markers and any traffic control devices to limit or restrict ROW access by motor vehicles. • Perform Site Cleanup and Restoration. Clean up equipment marshalling and material storage sites, ensure that the worksite access roads are restored to prime condition, and that any road access ways are cleaned and restored. 4.7 PIPELINE LOWERING AND/OR REPLACEMENT - CREEK CROSSING 50 <<>> Pipeline lowering and/or replacement at creek crossings follows generally the same sequence of activities described above for open terrain; however, the additional activities described below apply to the actual creek crossing area. In addition, creeks may be crossed by either trenching or boring. Each crossing method is summarized separately below. 4.8 TRENCHING A trenched crossing is lowered and replaced in much the same manner as an open terrain project; however, incremental measures are employed to ensure both that erosion and sedimentation are minimized and that no potentially harmful materials are discharged to the waterway. Pipeline Construction Specification CS4 provides additional details. Cut Pipe at Creek Crossings. Expose and cut the pipeline at the creek crossing boundaries to isolate the removal section into subsections. Utilize drain pans to recover any remaining liquids as the cut is made. Install mechanical plugs in all exposed pipe ends. • Implement Water Quality Protection Measures. Staging areas, spoil storage areas, and additional workspace areas are located in upland areas above the creek bed. Hazardous materials such as chemicals, fuels, lubricating oils and any other potentially harmful materials are maintained at least 100 feet from the water body. BMPs are installed to prevent sedimentation. Flumes, dams, equipment bridges and other diversion devices are installed as necessary to perform "dry ditch" excavation. • Erosion control measures are employed after project completion to ensure that stream flows do not cause erosion of disturbed areas and subsequent sedimentation. Erosion controls protect against sedimentation and prevent stream flow from removing pipeline cover which could expose the pipe to steam bed forces. Erosion control measures are site-specific, depending upon site conditions, and include berms, dikes, water bars (perpendicular to the pipeline 990144BA.v-6 51 - 2/14/2000 <<>> alignment), silt fences, staked hay bales, seeding, mulching, hydromulching, riprap, and trench plugs. 4.9 BORING Stream crossings may be installed by boring rather than trenching, depending upon hydrologic and engineering considerations and soil types. The existing pipeline may be abandoned in place after obtaining approvals from the landowner and, if necessary, state and federal authorities, and after (a) filling the pipe with an inert material such as grout or concrete, or (b) sealing the ends of the pipe. The pipe may not be abandoned in place if its presence could interfere with stream flows or interfere with future uses of the waterway. Boring a stream crossing requires the use of a work space for installation of bore pits in which the boring equipment operates. The boring operations typically require a workspace approximately 100 to 250 feet wide by 150 feet long. The workspaces are located above the high water mark unless topography or other factors dictate otherwise. Typically, no instream soil disturbance occurs, and BMPs are employed to ensure that spoil storage and other project activities do not cause erosion or sedimentation. From within the bore pits, the boring equipment creates a parabolic pathway to the pit on the other side of the stream bed. Bored material is circulated out of the bore and retained at the upland spoil storage area. The bore is sealed with grout or bentonite to fill fissures along the course and to ensure bore stability. The new pipe is then pulled through the bore using equipment designed for that purpose. Once the pipe is welded, inspected, surveyed, coated and tested, the excavations are filled and compacted, and the site is restored. Site restoration and stabilization is achieved in the same manner as described in Section 4.6, Pipeline Lowering and/or Replacement - Open Terrain. Any necessary erosion and sedimentation controls are employed, and the site is inspected and maintained until final stabilization is reached. 990144BA.v-6 52 - 2/14/2000 <<>> 4.10 HYDROSTATIC TESTING - OVERVIEW OF ACTIVITIES A hydrostatic pressure test is scheduled to be performed to ensure the integrity of the system. This test is scheduled to commence in February 2000 and conclude in May 2000. Hydrostatic testing will start at the Longhorn GATX pump station in Galena Park (Houston) and proceed westward to Crane Station. The test medium will be potable water from a local municipal supply source. In the event some water is lost due to pipe failure, or if water is needed to fill longer test sections, fresh make-up water will be acquired, by permit, from sources crossed by the pipeline (i.e., from rivers or streams). The hydrostatic testing occurs in segments, which are subdivided into test sections of varying lengths. Factors that contribute to test section length include (a) target test pressures; (b) pipe size and grade; (c) the presence or absence of species and habitat; (d) the location of valves and pump stations; and (e) elevation changes along the pipeline. Due to additional factors, two test sections will not be tested during the Houston to Crane hydrostatic testing project. Those two sections are (a) Segment 4, Section 1, which encompasses habitat for the endangered Houston toad and (b) Segment 5, Section 4, which encompasses the recharge zone of the Edwards Aquifer and part of the adjacent contributing zone, areas of potential effect to the endangered Barton Springs Salamander. Rather, those sections will be tested after Phase II consultation relating to pipeline operation, maintenance and emergency response, and after maintenance construction to replace pipeline segments in those areas is completed. The current hydrostatic testing schedule is as follows: TEST SEGMENT START DATE - END DATE Segment 1 February 11 - February 13 Segment 2 February 14 - February 20 Segment 3 February 21 - February 27 53 221420 <<>> Segment 4 February 28 - March 5 (Section 1 after completion of maintenance construction (May)) Segment 5 After completion of maintenance construction (May) Segment 6 March 6 - March 15 Segment 7 March 16 - March 26 Segment 8 March 27 - April 2 Segment 9 April 3 - April 9 Segment 10 April 10 - April 16 Segment 11 April 17 - April 23 As noted above, the test sections traversing Houston toad habitat and the Edwards Aquifer Recharge Zone will not be tested until after the completion of maintenance construction in those areas, which will not commence until after completion of Phase II of this consultation. The start date for Segment 1 identifies the date that actual testing is scheduled to begin; however, for the remaining test segments, the start date identifies the date on which test water is scheduled to be introduced into that segment from the preceding segment. In addition, any delay encountered during testing, such as to replace a failed segment of pipe, will result in equivalent delays in the remainder of the test schedule. To facilitate hydrostatic testing of the pipeline, headers will be installed on the pipeline at intervals along its length which divide the pipeline into segments for discrete testing. There are forty (40) header sites involved in the test. A general description of the installation of the test headers follows. Additional information is provided in the accompanying Project Documentation Appendix at Tab 8, including a graphic depiction of a typical header site. Headers vary in configuration; however, all function similarly to allow the introduction of test water, the pressurization of the test segment and the displacement, after testing, of the test water to the following test section. Prior to any work, the sites will be subject to an environmental, endangered species, and archeological survey conducted by qualified third-party biologists and archeologists. The headers will be installed by excavating an area approximately 20 ft. wide x 80 ft. long × 4 ft. deep around and under the pipeline. The spoil will be 990144BA.v-6 54 - 2/14/2000 <<>> stored on the temporary work easement. The topsoil will be segregated from the sub-grade for restoration of the site following the hydrostatic test. Storm water management during construction and testing will be by methods prescribed in the SWPPP, an example of which is included in the Project Documentation Appendix at Tab 6. • The exposed pipe will be cut and spread apart horizontally, and pre-fabricated headers will be welded to each section. The downstream header shall have a wire brush pig and displacement pig inserted in it before it is welded on the pipeline. A 6-inch temporary crossover pipe with valve will be installed between the upstream and downstream header. Upon completion of the test, the hydrostatic test water will be displaced into the next test segment by nitrogen. The test section will be vented to atmosphere and the temporary piping and headers will be removed. The pipeline will be tied back together with a joint of new pre-tested pipe and the joints will then be coated and wrapped to provide corrosion protection. Coating is inspected for holidays, and repairs are made if holidays are identified. The excavated area will be backfilled and compacted with the subgrade material in the spoil pile followed by the topsoil to finished grade to match the surrounding terrain. The disturbed area is seeded with native grasses or sod, and BMPs are inspected and maintained until the site is stabilized. Total surface workspace requirements for test header installations are about 100 feet wide by 150 feet long along the pipeline. 4.11 HYDROSTATIC TESTING - POTENTIAL FAILURE OF PIPE Hydrostatic testing of the existing Longhorn Pipeline between Houston and Crane is expected to result in a number of failures. Some of those failures, and actions taken to locate failure locations, could have effects upon both species and habitat. However, the calculation of the effects of such failures is difficult to estimate since the location of any such failure cannot be predicted and since the volume of test water that may be discharged is difficult to predict. 990144BA.v-6 55 - 2/14/2000 <<>> Calculations by a pipeline integrity consulting firm estimate that approximately 18 to 20 failures will occur at the high test pressures planned. Since the most likely failure location is at pipeline flaws, the location of the expected failure cannot be predicted with any accuracy; at most, a minimal number of recently replaced sections of pipe may be eliminated from consideration. Therefore, the expected failures will approximate a random distribution over the Houston to Crane segment. A finite number of failures could be assigned to the habitat areas based upon the proportional share of pipeline mileage in habitat areas; however, that methodology would probably result in either overestimation or underestimation of the number of failures in habitat areas. In addition, the potential volume of test water discharged in the event of failure is difficult to estimate. First, if a failure results in rapid depressurization of the test segment, the volume of test water discharged will be the sum of (a) water expelled as the pipe returns to atmospheric pressure, which depends upon test pressure and test segment length, and (b) drainage from any adjacent segments at elevations higher than the failure location. Second, if a failure results in a slow depressurization of the test segment, it may be readily identifiable and quickly contained. If a slow leak is difficult to locate, one or more investigative excavations could be required to either search for the failure or plug a portion of the segment so that lengths of pipe may be eliminated from the search. Therefore, given that failure location and size cannot be predicted, potential effects on species and/or habitat cannot be reasonably estimated in advance. Another factor that makes such estimates difficult is the existence of residual amounts of diesel fuel that remain in the pipeline from cleaning during 1998. As the hydrostatic testing proceeds from east to west, the test water may be expected to reflect relatively higher levels of hydrocarbon content; however, those concentrations cannot be predicted. Spill response equipment such as booms, sorbant pads, and other containment and cleanup equipment will be maintained in the vicinity of the test sites during the procedure. In summary, the locations of hydrostatic test failures cannot be predicted, the volume of test water discharged may not be calculated, and the number of investigative excavations cannot be predicted. 990144BA.v-6 56 - 2/14/2000 <<>> 4.12 CATHODIC PROTECTION ENHANCEMENTS Enhancements of the pipeline cathodic protection system consist of (a) installation of anode beds and (b) re-coating of sections of existing pipe. The cathodic protection system protects the pipe from corrosion. These enhancements are identified and described in the accompanying Project Documentation Appendix at Tab 2, and the locations where activities may affect species and habitat are identified in Table 2. Project planning is performed in a manner similar to that described in Sections 4.3 through 4.5 above. Installation of deep anode ground beds requires a series of vertical bores within which sacrificial anodes are placed; the anodes within each bore and among the series of bores are connected by subsurface wiring that is then connected to the pipeline. The bores and wiring trenches are installed within the existing ROW. During boring, a circulating pit is dug to contain cuttings removed from the bore. After project completion, the pit is filled, excess cuttings are removed for disposal, and the site is closed in the manner described in previous discussions of construction site closure. An example project work plan and related diagrams that provide additional detail about deep ground-bed installation are included in the accompanying Project Documentation Appendix at Tab 11. Pipeline coating reconditioning involves the same activities required for a pipeline lowering or replacement, with the exception of the process steps to remove existing pipe and install new pipe. A coating replacement site undergoes the project planning, site preparation, site entry, and site closure steps much as described above in Sections 4.2 through 4.6. Since the pipe is not cut, any residual liquids within the pipe do not present contamination potential. Asbestos containing pipe coating is managed in accordance with the provisions of the Environmental Protection Plan and the Project Construction Plan (ref. the accompanying Project Documentation Appendix at Tabs 5 and 3, respectively). All coating reconditioning is inspected, or "jeeped," and any holidays are repaired. 4.13 SURGE PRESSURE PROTECTION 990144BA.v-6 57 - 2/14/2000 <<>> To reduce the risk of over-pressurization of the pipeline, Longhorn will implement system changes and operating practices to limit surge pressures to no more than maximum operating pressure in sensitive and hypersensitive areas identified by the Lead Agencies (ref. Project Documentation Appendix at Tab 2). One system change involves the installation of over-pressure activated by- pass systems that will allow a pressure spike to be relieved around certain gate valves. The installation of a by-pass system involves the same process steps as the installation and removal of a hydrostatic test header; see Section 4.10. The by-pass system to be installed at the east bank of the Llano River will use the same work location as the hydrostatic test header to be installed at that valve site. 4.14 INVESTIGATIONS Projects to investigate possible pipe dents and corrosion anomalies follow the same planning and preparation procedures for a pipeline lowering/replacement, but on a lesser scale. Table 2 identifies relevant information for, and the locations of, projects to investigate possible pipe dents and corrosion anomalies. Typical investigation sites require a trench approximately 20 feet in length. If a dent or anomaly cannot be field repaired, a segment of pipe will be removed and replaced, with the length replaced at least twice the pipe diameter. Coating and coating inspection and repair, as well as site closure, follow the procedures described in Section 4.0. 990144BA.v-6 58 - 2/14/2000 <<>> 5.0 POTENTIAL IMPACTS (TAKE) AND COMPENSATION ATake@ of listed species is defined in the ESA and implementing regulations as the act or attempted act of pursuing, hunting, shooting, wounding, killing, trapping, capturing, collecting, harming, or harassing. Harm and harass are defined as the act of disturbing individuals or modifying habitat to the extent that wildlife are actually killed or injured by impairment of essential behavioral patterns such as breeding, feeding, or sheltering. Potential take of certain listed species could occur from a number of actions or events associated with the implementation of the subject project activities described in Section 4.0, including maintenance construction, hydrostatic testing, ROW maintenance, and cathodic protection enhancements. No individuals of any listed species have thus far been documented within the existing pipeline ROW; however, the potential for incidental take cannot be eliminated. Surveys and detailed habitat assessments have been conducted for a number of species of concern, and additional surveys are scheduled for the near future; however, the Service has recommended in the December 15, 1999 Comment Letter that additional surveys be conducted for several years into the future to confirm the presence or absence of species within areas of potential habitat. Furthermore, the hydrostatic testing project could affect habitat areas, but no reasonable means exists to predict or to quantify the potential for take. Alternatively, take may be assumed without reference to the presence or absence of species. Assumed take will very likely result in overcompensation; that is, since surveys have not identified individuals in the pipeline ROW, assumed take will result in compensation for areas of potential habitat where species utilization has, to date, not been confirmed. That overcompensation will provide a net benefit to the species for several reasons. First, surveys to date have not identified individuals in the area of impact for the subject maintenance construction activities; thus, compensation occurs even though there is no documented take. Second, Longhorn will implement numerous controls to ensure that the project activities are conducted first to avoid, and otherwise to minimize, potential effects to species and habitat. Examples include identifying and marking habitat areas for avoidance; planning project implementation to minimize the potential for any effects; use of FERC- 990144BA.v-6 59 - 2/14/2000 <<>> qualified inspectors with authority to alter a project in areas with species related concerns; adjusting project timing to avoid periods of activity and blooming seasons; and implementing storm water pollution control BMPs even when not required by permit. Thus, any potential adverse effects will be avoided or minimized. Third, potential habitat has been assumed over broad areas when, in fact, detailed surveys could reveal that occupied habitat is either absent or of doubtful viability to a species. The end result is that the potentially affected species benefit by conservation efforts on a scale greater than any likely incidental take. Longhorn proposes, therefore, to assume an incidental take for the entire width of the pipeline ROW traverse of broad areas of potential habitat. This conservative assumption will result in overcompensation to the benefit of the potentially affected species and habitats. Take is calculated based on the extent of potentially suitable habitat within the established ROW (50-foot width x length) and within temporary workspaces that exceed the ROW (i.e., equipment staging areas, spoil management areas, and stream diversion areas, the size of which varies by location). On that basis, the take for each species is calculated as indicated in Table 3. As discussed in Section 4.11, Hydrostatic Testing - Potential Failure of Pipe, the locations of potential hydrostatic test failures cannot be accurately predicted, the volume of test water discharged cannot be accurately predicted or calculated, and the number of investigative excavations cannot be predicted. The inability to accurately predict the potential impacts of hydrostatic test failures precludes any pre-activity attempt to predict and/or estimate the potential effects of test failures. Any such attempt would be likely to result in inaccurate estimates. Therefore, Longhorn proposes to provide for a contingent methodology for calculating any such effects. 990144BA.v-6 60 _ 2/14/2000| <<>> Table 3: ROW Clearing/Maintenance and Additional Construction Impacts* Within Listed Species Habitat - Longhorn Pipeline ROW Clearing/Maintenance Area: Texas Prairie Dawn 53,392 linear feet × 50 feet 61.3 acres Navasota Ladies-tresses 4,576 linear feet x 50 feet 5.2 acres Houston Toad 17,952 linear feet x 50 feet 20.6 acres Golden-cheeked Warbler 90,096 linear feet x 50 feet 103.4 acres Black-capped Vireo 36,256 linear feet x 50 feet 41.6 acres Tobusch Fishhook Cactus 185,328 linear feet × 50 feet 212.7 acres TOTAL ROW IMPACTS = 444.8 acres Additional Maintenance Construction Area Construction Dimensions** Species Impact Site Stationing Acres LPP-2753 LPP-2751 10369+55 - 10373+24 200 × 1033 200 × 1000 GCW 4.7 2016 10380+60 - 10381+24 200 × 806 GCW GCW 4.6 Hydrostatic Header 3.7 And Test Sites Site 6-6 Site 6-2 10280+00 50 × 100 GCW 50 × 100 GCW 0.1 0.1 11385+50 Site 8-2 Site 7-3 13435+00 15143+00 50 × 100 50 × 100 TFC BCV 0.1 Site 8-3 15586+00 16167+00 50 × 100 TFC 0.1 Hydrostatic Transfer Site 8-4 0.1 50 x 100 TFC 0.1 Sites Site 6-1 Site 8-1 10163+00 50 x 150 GCW 0.2 And Surge-4 14606+00 50 × 150 TFC 0.2 TOTAL MAINTENANCE CONSTRUCTION IMPACTS 14.0 TOTAL IMPACTS 458.8. Of the methodologies available for calculating the effects of activities upon 2214200 G <<>> species and habitat, the most applicable is the Habitat Equivalency Analysis (HEA) methodology developed by the National Oceanic and Atmospheric Administration for Natural Resources Damages Assessments (NRDAs). The HEA methodology is briefly described by the following steps: The duration and extent of injury are documented and estimated from the time of injury until the resource recovers to baseline; • The services provided by a compensatory project are documented and estimated over the full life of the project; • The size of a compensatory project is calculated such that the total increase in services provided by the compensatory project equals the total interim loss of services due to the injury; and • The cost of the compensatory project is calculated. A more detailed description of the HEA methodology is provided in accompanying Project Documentation Appendix at Tab 10. Longhorn's proposal, then, is to execute the following sequence of measures in the event a hydrostatic test discharge occurs in areas of concern for species and/or habitat: • In the event of a test failure, immediately notify a qualified biologist, who will be maintained on standby along the test segment, and direct the biologist to the failure site; • If a discharge occurs, the biologist will assist the identification of response actions to minimize potential impacts to the environment; and, • The biologist will perform a field survey to document the loss of, destruction of, or injury to natural resources (a) at the location of any excavation, whether the excavation is for location of a failure or for repair of pipe; (b) within the area of impact of the test water; and (c) in any other areas affected by the response to the test failure, as at any other construction site. The effects, if any, of the hydrostatic test failure upon species and/or habitat will then be calculated pursuant to the HEA methodology. Longhorn shall 990144BA.v-6 62 • 2/14/2000| <<>> compensate for the value of any such adverse effects by paying the monetary value of an appropriate compensation project to conservation efforts directed at the preservation and recovery of the affected species and habitat in the region where the impact occurred. For example, if a hydrostatic test resulted in a take of golden-cheeked warbler or black-capped vireo habitat, Longhorn would contribute the requisite monies to appropriate conservation entities acceptable to the Service, such as Balcones Canyonlands Conservation Plan, The Texas Nature Conservancy, or similar initiatives. 5.1 SPECIES BY SPECIES IMPACT ANALYSIS Texas Prairie Dawn (Hymenoxys texana) Potential impacts to the Texas prairie dawn may result from a number of activities. Right-of-way maintenance will occur with the periodic (typically twice per year) use of tractor drawn mowers. Tractors will be rubber-tired, but crushing of plants could occur from time to time, particularly during blooming periods. Mowing height will typically be 3 to 4 inches. Since only the blooming shoot is usually that high, impacts from mowing are deemed to be minimal, except during blooming. Impacts, while not believed to be significant, are quantified as the total ROW (50') through the entire area of identified potential habitat. As indicated in Table 3, this area constitutes approximately 61.3 acres. As an avoidance and minimization measure, mowing will be scheduled to avoid the February through April blooming season. A blooming season survey of the ROW and adjacent areas is recommended to identify any plant locations for specific avoidance, if present. Three construction sites have been identified for completion in the near- term, two dent investigations, and one anomaly investigation (ref. to Table 2). Impact for these three construction areas will be contained within the existing 50' ROW for relatively short distances along the pipeline (see Table 3). Within these areas, excavation, temporary spoil storage, equipment movement, and grading will likely result in elimination of any prairie dawn plants that may occur within the ROW in the construction areas. The area of these impacts is already included in the total ROW impact mentioned above. 990144BA.v-6 63 - 2/14/2000 <<>> Navasota Ladies-tresses (Spiranthes parksil) As in the case of the prairie dawn, periodic (twice per year) mowing with rubber-tired tractor mowers may result in sporadic crushing of plants under tractor tires or mower wheels, or cutting of bloom stalks. Impacts from periodic mowing are again not expected to be significant, but in the absence of detailed plant inventory information for the ROW, an assumed total impact for the ROW through the identified potential habitat areas constitutes 5.2 acres (Table 3). As an avoidance and minimization measure, mowing will be scheduled to avoid the October and November blooming season. A blooming season survey of the ROW and adjacent areas is recommended to identify any plant locations for specific avoidance, if present. No areas of construction are identified in the two potential habitat areas. However, construction will occur just east of the most westerly potential habitat area. The ROW is to be used for access to the construction zone (see Table 3). It is presumed that heavy equipment movement along this portion of the ROW will result in destruction of any plants growing at that locality. Access will be kept within the existing 50' ROW; therefore, potential impacts have already been calculated in the ROW maintenance value above. Houston Toad (Bufo houstonensis) Right-of-way maintenance will again include periodic mowing with rubber- tired tractors. Mowing could generally reduce grass thickness and height, thereby improving mobility for Houston toads. However, since Houston toads are mobile, the possibility exists for run-overs by tractor tires or jumping into the mower blades by toads. Toads are predominantly active during a few months of the year; therefore, the possibilities of encounter are fairly remote. As a means of providing additional avoidance procedures, pipeline ROW maintenance will be timed to occur in the late fall through early spring (November to January) when the toads are generally inactive to limit the possibility of direct impact. In addition to these avoidance procedures and the low likelihood of encounters, Longhorn will assume that all areas of potential habitat traversed by the pipeline ROW are suitable and will commit to compensate for the entire ROW width. From Table 3, this amount is approximately 20.6 acres. Horizon has recommended a spring 990144BA.v-6 64 - 2/14/2000 <<>> breeding season survey for the toad in the vicinity of, and downstream of the pipeline to determine possible toad presence, population, and breeding areas that could be affected. No construction impacts to Houston toads are contemplated in this consultation. Pipe replacements within the toad habitat area will be addressed in the second phase consultation. Edwards Aquifer Contributing Zone - Barton Springs Salamander Right-of-way maintenance and four construction locations are presently contemplated to occur within the contributing zone of the Edwards Aquifer in Travis and Hays counties. The principal concern for impacts to listed species in this area is by siltation from disturbed areas being transported by storm runoff to streams that eventually run onto the Edwards Aquifer Recharge Zone, potentially entering the aquifer, and lowering the quality of water utilized by the Barton Springs salamander. While single projects are not likely to have any demonstrable effects on the salamander, the cumulative effects of many development projects throughout the recharge zone and contributing zone may collectively cause negative impacts. Right-of-way maintenance, consisting of mowing and trimming, is not likely to result in any level of sedimentation or impacts since the activity will not result in ground disturbance. Enhanced Best Management Practices (BMPs) will be utilized throughout construction in disturbed areas to prevent sediment loads from reaching the aquifer or significantly reduce such loads. BMPs are identified in the Project Documentation Appendix, Stormwater Pollution Prevention Plan (Tab 6). The BMPs will also include reclamation of disturbed areas immediately following construction for rapid growth and stabilization of grasses and annuals. As a result of these enhanced BMPs, no significant impacts to the aquifer or Barton Springs salamander are contemplated. Golden-cheeked Warbler - (Dendroica chrysoparia) Golden-cheeked warbler habitat does not exist in the established ROW, 990144BA.v-6 65 - 2/14/2000 <<>> but is presently adjacent to the ROW in a number of locations from Hays County westward to Mason County. Right-of-way maintenance will not directly affect warbler habitat, except for hand pruning of canopies which overhang the ROW. Indirect effects may result from mowing noise or activity if birds are present in the vicinity during maintenance activities. As a minimization procedure, Longhorn will schedule maintenance activities to occur during the non-nesting season (September 1 to March 1) within or near warbler habitat areas to avoid indirect impacts. While no significant impacts are anticipated to occur, Longhorn will mitigate for the full ROW width (50') through potential warbler habitat areas. The area of potential effect is determined to be 103.4 acres (Table 3). Six areas of pipeline maintenance construction or investigation are anticipated to occur along the pipeline within areas identified as potential warbler habitat (Table 2). Each of those areas are estimated to require additional construction space in excess of the existing ROW by variable widths (Table 3). The total additional impact to warbler habitat resulting from construction clearing is 13.4 acres. The additional areas of temporary work space are needed in these areas to facilitate temporary spoil storage, machinery access, pipe stacking, and miscellaneous construction related activities. As avoidance and minimization procedures, Longhorn will to the extent possible, schedule construction activities, particularly clearing, to occur during the non-nesting period (September 1 to March 1). As with the immediately impending construction schedule, clearing will commence prior to March 1st and construction activities will continue continuously until completion. Total estimated impacts to potential warbler habitat are 116.8 acres. Black-capped Vireo - (Vireo atricapillus) Seven areas of potential black-capped vireo habitat exist along the ROW between Blanco and Kimble counties. Black-capped vireo habitat, being an early successional stage of brushy regrowth, does exist within the existing ROW in locations where previous maintenance activities have not occurred in several years. In this case, ROW maintenance will directly impact potential habitat within the existing ROW. The area of direct impact for the full 50' width of the ROW through the various habitat areas constitutes approximately 41.6 acres. Indirect 990144BA.v-6 66 - 2/14/2000 <<>> impacts from ROW maintenance are not likely since maintenance activities will be conducted during the non-nesting season (September 1 to March 15) for vireos. Four maintenance construction locations have been proposed within the areas identified as potential vireo habitat (Table 2). Only one of those construction sites will require clearing beyond the 50' ROW width. An additional 50' of temporary work space will be needed to facilitate temporary spoils storage, equipment access, pipe layout and construction room. The additional acreage of disturbance for this construction site is 0.1 acre. The total area of impact to potential black-capped vireo habitat is 41.7 acres. Tobusch Fishhook Cactus - (Ancistrocactus tobuschit) Potential habitat for the fishhook cactus is very generally estimated from general soils and plant distribution information to include the entire reach of the pipeline's traverse of Kimble County. Without specific survey information for the cactus, it is assumed that the entire ROW across Kimble County is potential cactus habitat. As with the Texas prairie dawn and Navasota ladies-tresses, the Tobusch fishhook cactus is low growing and not likely to be directly affected by mowing, except for possible crushing by tractor tires. However, due to the significant extent of large rocks within the ROW, mowing is not always feasible in this region. A preferred method in rocky terrain is to back drag a bulldozer blade across the ground which knocks down undesirable woody vegetation. This activity can disrupt the ground surface and possibly injure or destroy cactus plants. Therefore, direct impacts to fishhook cactus habitat may occur from time to time. The total area occupied by the ROW across Kimble County is 212.7 acres. Four test header installation locations are planned within the potential fishhook cactus habitat. Each site will disturb an additional 50' width beyond the ROW for the construction of the headers. The additional space is required to facilitate temporary spoils storage, equipment access, pipe construction, and testing equipment. The additional area of impact per site is between 0.1 and 0.2 990144BA.v-6 67 - 2/14/2000 <<>> acre. The total additional impact to cactus habitat is 0.5 acre. The total impact acreage for Tobusch fishhook cactus is 213.2 acres. Other Species Listed species that may occur away from or downstream of the pipeline corridor (ie., bald eagle, interior least tern, American alligator, Barton Springs salamander) are not likely to be adversely affected by the proposed maintenance and minor construction activities. Any discharges of hydrotest waters are not expected to contain levels of hydrocarbons or other toxic materials sufficient to result in adverse impacts. 5.2 AVOIDANCE AND MINIMIZATION Longhorn will, to the extent reasonably possible, conduct the maintenance construction, testing, and other subject activities in a manner that avoids potential effects to species and habitat. If avoidance is reasonably and practically unachievable, Longhorn will conduct the activities in a manner that minimizes any potential effects. Controls and other measures designed to achieve that goal are described in the foregoing descriptions of the various activities. A number of those controls and measures are summarized as follows: 1. Identifying and marking habitat areas for avoidance; 2. Planning project implementation to minimize the potential for any effects; 3. Use of FERC-qualified environmental inspectors with authority to alter project implementation procedures in sensitive areas; Adjusting project timing to avoid breeding populations; for example, projects in Houston toad habitat will avoid the months of February through November, and projects in GCW and BCV habitat areas will avoid March through August and April through September, respectively; Implementing storm water pollution control BMPs even when not required by permit; 6. Maintaining qualified biologists in hydrostatic test project areas for 990144BA.v-6 68 - 2/14/2000 <<>> immediate response in the event of a test water release in a habitat area; Avoiding, until project planning is accomplished, hydrostatic testing over the Edwards Aquifer recharge zone, portions of the contributing zone, and in Houston Toad habitat areas; and Conducting additional species surveys along the pipeline ROW to determine actual presence or absence of species and populations where present. Additionally, work in areas of noise-sensitive species (i.e., GCW, BCV) will be avoided during the breeding/nesting season. If work must occur in habitat areas during a noise-sensitive seasons, the Service will immediately be notified. Biological surveys of the habitat areas will be conducted prior to construction to determine the presence or absence of species and specific locations if present. Avoidance and minimization procedures, as appropriate to protect the species, will be implemented based on these surveys. 5.3 PROPOSED COMPENSATION FOR POTENTIAL TAKE Longhorn proposes the following steps for calculating compensation, for funding that compensation, for implementing the process by which the compensation is valued initially and in the future, and for assuring the Service, the public and interested parties that the total compensation will be funded in full. Longhorn has applied a formula recommended by the Service to determine appropriate compensation. The formula is: Impact acreage × 1.2 x fair market value of land in the area. This formula is modified for Houston toad habitat to use a 3x multiplier instead of 1.2 due to the more critically imperiled nature of the toad population in general. The Service also recommends the application of a one-time 10% inflation factor to anticipate increases in land values over time. Longhorn has calculated compensation for purposes of this BA on the basis of this formula and best estimates of land values in the area of each respective species. Longhorn proposes that actual land values be determined for purposes of calculating compensation on the basis of land appraisals according to the following process. 990144BA.v-6 69 - 2/14/2000 <<>> Within 60 days following the Biological Opinion, Longhorn will engage two licensed appraisers to determine the average value of land in the vicinity of the impact areas for each species along the pipeline. If the two appraisals differ by greater than 5%, then a third appraisal shall be engaged to reach a determination. All appraisals shall take into account land uses and conditions in such vicinity. The current calculation of compensation, set out below, will then be revised based upon the average of the two or three, as the case may be, appraisals. Longhorn proposes a series of payments over time to fund the necessary compensation, with such payments being made in a manner which will maximize benefits to the potentially affected species. For example, maximum benefit to the species may be achieved through Service concurrence that the initial payment go toward conservation efforts directed to the Houston toad and the Tobusch fishhook cactus; since those species face a relatively greater prospect of decline than the remaining species. Longhorn proposes to provide this compensation amount to one or more conservation funds devoted to conservation of the affected species, on an annual basis over a six year period. Future land values shall be determined on the basis of appraisals performed every second year following the initial appraisals and determined employing the same methodology as described above. The remaining compensation due from Longhorn shall then be recalculated based upon the compensation acreage remaining to be funded and the most recent land appraisals for such acreage. Longhorn has solicited the participation of the Service in the identification of conservation funds that provide the greatest benefit to the affected species as a whole. In particular, Longhorn's intent is for the funds to support conservation efforts that employ preservation and recovery actions at least as comprehensive as the actions recommended in the Service's December 15, 1999 Comment Letter and in the relevant species recovery plans. Potential recipients may include the National Fish and Wildlife Foundation, the Texas Parks and Wildlife Department (TPWD), Texas Nature Conservancy, Texas Land Trust, Trust For Public Lands, and similar comprehensive conservation initiatives. Longhorn 990144BA.v-6 70 - 2/14/2000 <<>> prefers that the payments be directed to the National Fish and Wildlife Foundation and TPWD. This amortized payment scale will provide a reliable funding stream for the subject species for an extended period to purchase and manage habitat areas, enhance habitats, fund artificial propagation, and conduct other recovery efforts identified by the various species' recovery plans. The amortized payment schedule encourages an adaptive approach to managing these species by allowing the Service to redirect the funds over time to their highest and best use. As scientific research on the needs of these species continues, the Service may find that resources for the protection of the species should be redirected-perhaps to management and recovery practices of which the scientific community is not yet aware. Rather than committing all the conservation funds to one particular endeavor now, the amortized payment schedule allows the Service to apply the funds strategically over time as conservation priorities change and the understanding of the species grows. An amortized payment schedule also allows the regulated community, such as Longhorn, to commit a greater amount of funds than might otherwise be available. A payment schedule such as this one may establish a useful precedent that will provide an incentive for other private entities, including pipelines, to enter into conservation agreements that otherwise may seem financially prohibitive. This encourages voluntary compliance which ultimately benefits the species. The implementation of the Longhorn proposal will require that appraisals be obtained for calculation of present-day compensation. Longhorn proposes to accomplish the foregoing over the 60 day period following issuance of the Service's biological opinion. Longhorn may at its discretion, at any point in time, (a) pay all outstanding compensation on the basis of the most recent appraised values; or (b) purchase required acreage acceptable to the Service for any given species. Exercise of the foregoing discretion shall reduce remaining obligations and security requirements. 990144BA.v-6 71 - 2/14/2000 <<>> Given the timing matters identified above, Longhorn will provide assurance to the Service that the calculated compensation (refined on the basis of actual land appraisals) will be funded on time and in full. Such assurance will take the form of security that assures the Service that the compensation will be funded. Longhorn proposes such methods as a bond, a letter of credit, an escrow, or similar such mechanism reasonably acceptable to the Service. The security will cover compensation not proposed for immediate funding and the one-time 10% escalation value applied to same. Longhorn makes this proposal conditioned upon the requirement that, as payments are made or in-kind compensation is provided, a corresponding reduction be made in the compensation acreage outstanding and thus in the amount of security required. At issuance of the Biological Opinion, Longhorn shall provide to the Service reasonable evidence that the security is in place. The proposed payments, as secured, will assure that the compensation acreage is in fact acquired to benefit the species. Based upon the Service's recommended formula, the impacts described in Section 5.1, and best estimates of present land values, the present calculation of compensation would be as follows: Texas Prairie Dawn 61.3 acres × 1.2 = 73.56 acres x $3,000/ac + 10% = $242,748 Navasota Ladies-Tresses 5.2 acres × 1.2 = 6.24 acres x $1,000/ac + 10% = $ 6,864 Houston Toad 20.6 acres × 3.0 = 61.80 acres x $2,000/ac = $123,600 Golden-Cheeked Warbler 116.8 acres × 1.2 = 140.16 acres x $2,000/ac + 10% = $308,352 Black-Capped Vireo 990144BA.v-6 72 - 2/14/2000 <<>> 41.7 acres × 1.2 = 50.04 acres × $1,000/ac + 10% = $ 55,044 Tobusch Fishhook Cactus 213.2 acres × 1.2 = 255.84 acres x $1,000/ac = $255,840 Total Compensation $992,448 The total compensation figure stated above is to be funded according to the schedule in Table 4. 990144BA.v-6 73 2/14/2000 <<>> Table 4 Longhorn Pipeline Take Compensation Bonded Amounts Year HT TFC TPD/NLT/GCW/BCV TOTAL• 2000 123,600 255,840 379,440 2001 102,168 102,168 2002 102,168 102,168 2003 102,168 102,168 2004 102,168 102,168 2005 102,168 102,168 2006 102,168 102,168 TOTAL 123,600 255,840 613,008 992,448 Prepay Option Longhorn may elect to prepay amounts earlier than scheduled with corresponding drop in security and compensation requirements. In-Kind Option Longhorn may purchase required acreage acceptable to the Service with corresponding drop in security and compensation requirements. Subject to adjustment based upon appraisals to be obtained by Longhorn. 990144BA.v-6 74 - 2/14/2000 <<>> Thus, the Longhorn proposal, which is tabulated in Table 4, may be summarized as follows: At issuance of Biological Opinion: Provide security for total estimated compensation of $992,448; During 60 days following Biological Opinion: Obtain land appraisals to determine current value of total compensation; 3. Within 30 days of Appraisals: Fund acreage attributable to Houston Toad and Tobusch fishhook cactus based upon initial appraisals; Adjust security requirement to reflect appraised values and initial payment; Annually following Biological Opinion: a. Scheduled payments are made; and b. A corresponding reduction is made in the compensation acreage outstanding, and the required security is reduced to an amount necessary to secure the then outstanding compensation acreage; and 6. Bi-Annually following Biological Opinion: Obtain appraisals to determine average land values, and adjust security requirement to reflect changes in land uses. This commitment is being made without regard to whether or not the pipeline is eventually placed into service; rather, this commitment is based upon the level of take that occurs as described above. 990144BA.v-6 75 2/14/2000 <<>> 6.0 REFERENCES Arroyo, Bryan. Threatened and Endangered Species of Texas. Austin, Texas: US Fish and Wildlife Service, Revised June 1995. Blair, W.F., The Biotic Provinces of Texas. Texas Journal of Science. 2:93-117, 1950. Campbell, Linda. Endangered and Threatened Animals of Texas. Austin, Texas: Texas Parks and Wildlife Department; Resource Protection Division, Davis, W.D. & Schmidly, D.J.. The Mammals of Texas. Texas Parks and Wildlife Department. Austin, Texas, 1994. Gould, F.W.. Texas Plants: A Checklist and Ecological Summary. Texas A&M University Agricultural Experiment Station. MP-585/Revised. College Station, Texas, 1975. Horizon Environmental Services, Inc. Threatened or Endangered Species Investigations - EZ Pipeline Project. 1991. Poole, Jackie M. and David H. Riskind. Endangered, Threatened, or Protected Native Plants of Texas. Austin, Texas: Texas Parks and Wildlife Department, 1987. United States Fish and Wildlife Service. Determination of Critical Habitat for the Houston toad. Federal Register 43(21):4022-4026. 1978. United States Fish and Wildlife Service. Minimum Procedures for Determining the Presence/Absence of Golden-Checked Warblers and Black-Capped Vireos. March 7, 1994 Memorandum, Austin Field Office. 1994. 990144ba.v-6 - 2/14/2000 76 <<>> Phase I FWS Biological Opinion February 17, 2000 <<>> ted States aND mere see the Inter gre Ecological Services Field Office FISH AND WILDLIFE SERVICE 10711 Burnet Road, Suite 200 (512) 490-0057 / 490-0974 Austin, Texas 78758 (iax) MARCH 18A9 February 17, 2000 Consultation Number 2-15-00-F-413 Gregg Cooke Regional Administrator, Region 6 U.S. Environmental Protection Agency 1445 Ross Avenue, Suite 1200 Dallas, Texas 75202-2733 Rodrick Seeley Regional Director, Southwest Region U.S. Department of Transportation, Office of Pipeline Safety 2320 LaBranch Road, Room Number 2116 Houston, Texas 77004 Dear Mr. Cooke and Mr. Seeley: The U.S. Environmental Protection Agency, Region 6 (EPA) (February 10, 2000) and the U.S. Department of Transportation, Office of Pipeline Safety, Southwest Region (OPS) (February 17, 2000) submitted letters requesting consultation with a Biological Assessment for the proposed Longhorn Pipeline Project, Maintenance Activities and Minor Construction, Houston to Crane, Texas. This letter acknowledges the U.S. Fish and Wildlife Service's (Service) receipt of your requests for the initiation of formal consultation under the Endangered Species Act of 1973 as amended (U.S.C. 1531 et seq.) (ESA). The Longhorn Pipeline Partners L.P., is the applicant and designated "non-federal Representative" for this project, and Horizon Environmental Services, Incorporated, prepared the Biological Assessment for EPA, OPS, and Longhorn. All information required of you to initiate consultation was either included with your letters or is otherwise accessible for our consideration and reference. We have assigned this consultation the number 2-15- 00-F-413 and this number should be included in all future correspondence. This letter also transmits the Service's biological opinion on the Longhorn Pipeline Project Maintenance Activities and Minor Construction, Houston to Crane, Texas, proposed for authorization by EPA and OPS. The Service is able to complete this consultation in the short time frame because of the extensive coordination that occurred during informal consultation. This Biological Opinion is only related to the activities proposed in this Phase One of the overall consultation. The phased approach to this consultation is explained in further detail below. 1 <<>> BIOLOGICAL OPINION Longhorn Pipeline - Phase One INTRODUCTION This document represents the Service's biological opinion on the effects of the proposed actions on the species listed in Texas. The Service has reviewed the proposed plans for the Longhorn Pipeline Project Maintenance Activities and Minor Construction from Houston to Crane, Texas, as outlined in the Biological Assessment provided by EPA and OPS. The first phase of the consultation (Phase One) relates to pipeline right-of-way (ROW) maintenance (clearing and marking, selected pipeline maintenance construction activities (pipe replacements and lowering), and pipeline testing (investigation of possible flaws and hydrostatic pressure testing). The Biological Assessment is hereby incorporated into this Biological Opinion by reference. The Service will not duplicate all maps, tables, and figures but will instead refer to the Biological Assessment. There are no species proposed for listing that would be impacted by the proposed action, therefore, no conference opinion will be issued. The draft Environmental Assessment on Longhorn Pipeline, and the associated Biological Assessment are the product of a settlement reached in the matter of Spiller et al. v. Walker et al. pending in the United States District Court in Austin, Texas (Appendix One). As part of the Court ordered settlement, the agencies involved in the original litigation were required to conduct an Environmental Assessment, including specifically, consideration of species listed under the ESA. The Court ordered EPA and OPS, acting as Lead Agencies, to be responsible for the Environmental Assessment. The Court order provides that issuance of any finding of no significant impact (FONSI) with regard to the proposed Longhorn Pipeline project "shall be conditioned upon implementation" of measures to protect public safety and the environment (Settlement Stipulation at 6). The order also prohibits the OPS from authorizing Longhorn to commence operations until Longhorn has implemented those mitigation measures upon which any FONSI is conditioned (Settlement Stipulation at 7). The order contemplates that Longhorn will apply for such ESA permits as may be required in connection with the implementation of any mitigation measures upon which a FONSI may be conditioned. (Settlement Stipulation at 7). The results of this consultation by the Lead Agencies with the Service are expected to be incorporated in the Record of Decision issued by the Lead Agencies. The terms and conditions, mitigatory measures and protections incorporated herein for the benefit of species are expected to be adopted and incorporated by Longhorn in its enforceable mitigation commitments or in its operating and maintenance manuals subject to inspection by, and enforceable by OPS, pursuant to the Pipeline Safety Act (49 USC 60101 et seq.). The Court settlement specifies that Longhorn will undertake certain construction and maintenance activities prior to issuance of a final agency decision in this matter (Settlement Stipulation at 8-11). The parties to the settlement specifically agreed that any such investments by Longhorn in Kimble, Menard, Hays, Travis, Caldwell, Bastrop and any counties within the jurisdiction of the Lower Colorado River Authority after August 25, 1998 would not be considered "for the purposes of determining the reasonableness of alternatives" (Settlement Stipulation at 11). 2 <<>> Although the Service and the Lead Agencies are in consultation with respect to the entire proposed Longhorn project, this consultation is being approached in two distinct, yet related phases. Service regulations allow for a staged consultation (50 CFR 402.14(k)) where the Service reviews a project, and provides biological opinions on each incremental step provided that no irreversible or irretrievable commitments of resources are made. The first phase of the consultation (Phase One) relates to pipeline ROW maintenance (clearing and marking), selected pipeline maintenance construction activities (pipe replacements and lowering), and pipeline testing (investigation of possible flaws and hydrostatic pressure testing). The proposed actions for Phase One are focused on activities that Longhorn wishes to perform before the final decision on the environmental review process is made by EPA and OPS. The Service believes that, by submitting the proposed action, EPA and OPS have made a determination that these activities can proceed before the final environmental decision is made because these activities are consistent with the current operational approvals for this pipeline and the settlement agreement. The Longhorn Pipeline Partners wish to conduct these activities before a final decision is made because of the potential delay in accomplishing this work due to seasonal constraints placed on the activities by the presence of endangered or threatened species. The golden-cheeked warbler and black-capped vireo are migratory birds that would be impacted less if this work were to commence before the birds return to Central Texas from their wintering habitat in Mexico. Because the pipeline is existing, routine maintenance is supposed to be occurring, and the construction impacts proposed are prudent for whatever liquid would flow through the pipeline, the Service believes that none of these activities constitute an irreversible or irretrievable commitment of resources, natural or monetary, which have the effect of foreclosing the formulation or implementation of any reasonable and prudent alternatives or measures. The Service believes that these investments would not constitute irretrievable commitments of resources for the purposes of Section 7(d) of the ESA. The Service has evaluated the proposed activities only with regard to the potential impacts to listed species and compliance with the ESA. This Biological Opinion does not indicate Service support for any alternatives, including routing, in the EPA and OPS environmental review process and in no way should be viewed as a factor in deciding the outcome of that process. Alternative routes may have less potential impact to listed species. In the opinion of the Service, implementing the proposed projects before completion of the environmental review process is a business decision made by the Longhorn Pipeline Partners. The second phase of the consultation (Phase Two) will be more directly related to the actual operation of the pipeline, specifically the operation and maintenance of the pipeline system and the potential effects of a pipeline release. The two phases can be logically separated. Phase One of the Service's review will focus on those actions that are designed to make the pipeline safer. The Service can complete this stage of review without pre-judging whether or not the pipeline will be used. Phase Two of the Service's review will focus on whether and how the pipeline will be used. It is anticipated that the consultation for the Longhorn Pipeline will also include a Phase Two Biological Assessment and Biological Opinion that will address issues directly related to the actual long-term operation and maintenance of the pipeline, specifically the operation and maintenance of the pipeline system and the potential effects of emergency response activities in the event of a pipeline release. Both EPA and OPS, within the Biological 3 <<>> Assessment, have committed to continuing the next phase (Phase Two) of consultation. Based on information available on the proposed project, the Service determines that there is a reasonable likelihood that the entire project is not likely to jeopardize the continued existence of any endangered or threatened species or result in the destruction or adverse modification of critical habitat. During the Phase Two consultation, the Service may change this determination, based on further review of the existing information or new information gathered during the Environmental Assessment process or the Phase Two consultation. This biological opinion is based on: (1) the information that EPA and OPS provided with a request for formal consultation including the Biological Assessment, (2) the information previously provided as part of the informal consultation (including the draft Environmental Assessment), (3) information in our office (including information provided by the public and the plaintiffs in the lawsuit on the Longhorn Pipeline), (4) field investigations, and (5) other sources of information. In the request for formal consultation, EPA and OPS attached the Biological Assessment and copies of all consultation documents for the activities proposed to be addressed by this Biological Opinion on Phase One activities associated with the Longhorn Pipeline. CONSULTATION HISTORY Informal consultation between the Service, Longhorn, and the EPA has been in process since February 1999. Longhorn was formally designated as the Non-federal Representative for conducting informal consultation on behalf of the EPA and OPS on February 3, 2000. The history of consultation (both informal and formal) actions follows in Table One. Table One. CONSULTATION HISTORY DATE HISTORY 10 February, 1999 Meeting Between Service and Longhorn Representatives 25 February, 1999 Meeting Between Service and Longhorn Representatives 9 March, 1999 Meeting of Service and Radian (consultants writing EA for EPA and OPS) 22 March, 1999 Meeting Between Service and Longhorn Representatives 30 April, 1999 Meeting Between Service and Longhorn Representatives 11 May, 1999 Meeting Between Service and Longhorn Representatives 12 May, 1999 Meeting with the Plaintiffs to discuss the Settlement Agreement 1 June, 1999 Meeting with Barton Springs/Edwards Aquifer Conservation District 8 June, 1999 Meeting Between Service and Longhorn Representatives 11 June, 1999 Multi-Agency Field Tour of Longhorn Pipeline in and near Austin, Texas 29 June, 1999 Meeting Between Service and Longhorn Representatives 4 <<>> Table One. CONSULTATION HISTORY 30 June, 1999 Telephone Conference Between Service and Department of Justice 19 July, 1999 Meeting Between Service and Longhorn Representatives 27 August, 1999 Meeting Between Service and Longhorn Representatives 10 September, 1999 Meeting Between Service and Longhorn Representative Meeting Between Service and EP/ 13 September, 1999 Meeting Between Service, Austin and Regional Director 27 September, 1999 leeting between Service Austin Office and Washington Offic Original Draft Biological Assessment Submitted to Servic 30 September, 1999 Meeting Between Service and Longhorn Representatives 4 November, 1999 Meeting Between Service and Longhorn Representatives 9 November, 1999 Meeting Between Service and Longhorn Representatives 16 November, 1999 EPA and OPS Longhorn Public Meeting, Austin 22 November, 1999 Meeting Between Service and Longhorn Representatives 7 December, 1999 Meeting Between Service and Longhorn Representatives 8 December, 1999 Meeting Between Service and EPA 15 December, 1999 Meeting Between Service and Longhorn Representatives Service Issues Comments on Original Draft Biological Assessment "Not Likely to Adversely Affect" Determination. Service Issues Response to EPA Regarding EPA's initial Request for Concurrence on a 17 December, 1999 Meeting Between Service and Longhorn Representatives 6 January, 2000 Meeting Between Service and Longhorn Representatives Maintenance and Construction Activities in Non-habitat Areas for Listed Species. Longhorn Requests Concurrence from Service for "Not Likely to Adversely Affect" for 10 January, 2000 EPA and OPS Longhorn Public Meeting, Austin 11 January, 2000 Meeting Between Service, EPA and OPS 17 January, 2000 Meeting Between Service and Longhorn Representatives 18 January, 2000 Meeting Between Service and Longhorn Representative 28 January, 2000 Draft First Phase Biological Assessment received for review 7 February, 2000 Meeting Between Service and Longhorn Representatives 1 February, 2000 Telephone Conference Between Service and Congressman Doggett's Staff 3 February, 2000 consultation EPA and OPS designate Longhorn the "non-federal repersentative" for purposes of 10 February, 2000 Received EPA Request for Formal Consultation 5 <<>> Table One. CONSULTATION HISTORY 17 February, 2000 Received Revised Phase One Biological Assessment 17 February, 2000 Received OPS Request for Formal Consultation DESCRIPTION OF THE PROPOSED ACTION Project Overview - (Both Phase One and Phase Two) The following is an overview of the project as proposed by Longhorn Pipeline and is provided to give an overall context of the proposed project. The specific activities proposed for this Biological Opinion are detailed in the next section. Longhorn proposes to operate a 723-mile refined petroleum products (gasoline and jet fuel) pipeline system from the GATX Terminal in Galena Park, Texas, (near Houston, Texas) to a refined petroleum products terminal in El Paso, Texas. The pipeline also has a 28-mile intermediate connection from a station in Crane County to a planned meter station in Odessa, Texas. The pipeline consists of a combination of 20-inch and 18-inch diameter pipe from Galena Park Station to El Paso Terminal and an 8-inch diameter pipeline from a station in Crane County to a meter station in Odessa, Texas. Finally, three as yet to be built pipelines will connect the El Paso terminal to interstate common carrier pipelines west of El Paso. The pipeline's initial capacity of 72,000 barrels per day (bpd) will be supplied by a new pump station at Galena Park and five newly constructed booster pump stations at the following locations: Satsuma (Harris County), Cedar Valley (Hays County), Kimble County (Kimble County), Crane (Crane County), and El Paso (El Paso County). Two new pipeline construction projects remain to be completed. An 8-inch diameter, 2500-foot lateral that originates at the terminus of the existing Odessa lateral will connect to a terminal facility in Odessa, Texas, owned by Equilon. Three 8.3-mile lateral pipelines, which originate at the El Paso Terminal, will connect with Kinder Morgan (formerly the Santa Fe Pacific pipeline) and Chevron pipelines in the El Paso area. The connection to Kinder Morgan will consist of one 8-inch diameter pipeline and one 12-inch diameter pipeline. The Chevron connection will consist of an 8-inch diameter pipeline. The purpose of the lateral pipelines is to connect into Kinder Morgan and Chevron pipelines to distribute product into the Phoenix, Tucson, and Albuquerque markets. Chevron operates an 8-inch pipeline that delivers product to the Albuquerque market; Kinder Morgan operates one 12-inch pipeline and one 8-inch pipeline serving the Tucson market. Other Kinder Morgan pipelines connect Tucson to the Phoenix market. The proposed project includes both new construction and refurbishment of an existing pipeline that has been converted from its former use of transporting crude oil from West Texas to the Gulf Coast area, the majority of which has been completed. As described in this chapter, the existing pipeline has been modified to transport refined petroleum products, with flow going from east to west. Williams Pipeline Company will be the contract operator of the Longhorn 6 <<>> Pipeline System. Longhorn intends to transport multiple grades of gasoline and distillates, which will include special reformulated grades of gasoline needed to control air emissions in certain areas of the Southwest. The Longhorn Pipeline System is designed for service in excess of 50 years and is made up of four main pipeline segments, several stations, and one terminal, as listed below: 1. New and refurbished 20-inch diameter pipeline from Galena Park to Satsuma; 2. Refurbished 18-inch diameter pipeline from Satsuma Station to Crane Station; 3. New 18-inch diameter pipeline from Crane Station to El Paso Terminal; 4. New lateral pipeline connections to Odessa and to other pipelines at El Paso; New Pump Stations; 6. El Paso Terminal; and 7. Odessa Meter Station. A detailed description of the Longhorn Pipeline System is included in the Biological Assessment (Project Documentation Appendix at Tab One). Future pipeline upgrades, repairs, and maintenance beyond that identified in the Biological Assessment will be addressed in Phase Two of the consultation. Project Description (Actions addressed under this Biological Opinion) This Biological Opinion only covers those portions of the overall project that have been specifically identified in the Phase One - Biological Assessment. Appendix Two contains a list of all of the activities covered in this Phase One consultation including ROW clearing and maintenance, pipeline maintenance and construction, pipeline testing, and other integrity-related projects. Following is a description of each of these procedures and the methods by which they will be implemented for the Longhorn Pipeline System. Additional detail may be found in Construction Specification CS4 contained in the Biological Assessment (Project Documentation Appendix at Tab Four. Right-of-way (ROW) Clearing, Marking, and Maintenance The existing pipeline ROW is about 50 feet wide and 723 miles long and most of it has been routinely maintained and cleared for over 50 years. Longhorn has committed to bring the surface of the ground within the ROW into "excellent condition" in order to facilitate surveillance prior to startup of the pipeline (Biological Assessment - Project Documentation Appendix at Tab 2). Excellent condition is that condition which provides a clear line of sight for aerial and ground surveillance patrols in order to effectively monitor and inspect the ground surface along the ROW. A clean and clearly marked ROW provides a distinctive line of demarcation, indicating a change in land use, where surrounding terrain is natural or heavily developed. These activities are routine and are conducted periodically by pipeline operators in the United States. 7 <<>> ROW maintenance will include mowing, brush-hogging, back-dragging, and/or hand trimming of tall grass or woody re-growth, trimming of tree canopies overhanging the ROW, setting signs, marking points of intersection (horizontal bends) in the pipeline with PVC posts, and painting cross-fence posts. ROW mowing is performed by a twin-blade mower or a brush-hog drawn by a tractor, to a height between two and four inches. Back-dragging is a method of clearing in rocky terrain; back-dragging involves pulling a dozer blade backwards across the ground surface which has the effect of bending vegetation over at the ground surface. Back-dragging typically does not result in the uprooting of vegetation. Rather, the vegetation is bent or broken just above the ground surface. Back-dragging is used only in areas where rocks on the surface pose a risk of damage to a mower or brush-hog. Vegetation around surface facilities such as valve settings is at times spot-treated, by hand application, with herbicides such as Roundup and Rodeo. Hand trimming involves line trimmers, chain saws, and similar hand-held equipment. Tree canopies are trimmed by workers, using chain saws, that are raised within reach of the canopies by a man-lift. Steel sign posts are typically set by driving the posts directly into the ground. PVC posts are set into shallow holes dug by post-hole digger. In limited circumstances such as when vandals repeatedly remove pipeline markers, sign-posts are dug by post-hole digger to allow the posts to be set into concrete. Clearing within areas identified as endangered species habitat will not result in any substantial ground disturbance because only mechanical or hand cutting will be employed. The term ground disturbance is intended to mean soil disturbance that would result from grubbing brush and tree stumps. Back-dragging will result in some minor disturbance of the soil surface similar to grubbing. In limited circumstances, stumps directly over the pipeline, which could have adverse effects on the pipe, will be spot-treated by hand application, with minimal amounts of non- aromatic and non-persistent herbicide to retard re-growth. Herbicides will be applied in accordance with EPA-approved label directions. All areas of the ROW are subject to periodic clearing from time to time. ROW clearing occurs at intervals that depend upon the rate of vegetation growth, typically averaging once per year in arid and semi-arid territory (generally, from Austin to Crane) and typically averaging twice per year in territory with greater rainfall (generally, Houston to Austin). Further, metropolitan areas may be mowed as frequently as monthly to meet municipal ordinance requirements and in response to landowner requests. ROW clearing will be conducted on a schedule that avoids impacts to species. 8 <<>> Pipeline Maintenance - Construction Planning Prior to project engineering and scheduling, each site is surveyed by qualified personnel to determine whether or not the activity (a) may affect threatened or endangered species and habitat, (b) may cause disturbance of cultural resources, (c) may be subject to Clean Water Act Section 404 (U.S. Army Corps of Engineers jurisdiction over dredge and fill materials in waters of the United States), or (d) may be subject to other federal, state or local laws, regulations or ordinances. Appropriate authorizations are obtained (such as this consultation), and necessary requirements are identified and incorporated into project planning and engineering documentation. Project engineers and technicians perform site inspections to identify site-specific conditions and features that require consideration in project planning, such as site ingress/egress routes, workspace requirements, spoil management, equipment storage, servicing and parking needs, and the like (Biological Assessment - Project Documentation Appendix at Tab 5 and Tab 6). Such considerations are incorporated into project planning and engineering activities. Unless required by the particular project or by site conditions, workspace is limited to the established ROW. Where workspace is required beyond the limits of the established ROW, those areas have been incorporated into project documentation. Workspace beyond the limits of the established ROW may be required for a number of reasons. First, avoidance of habitat or the natural terrain along one side of the ROW may necessitate expansion of workspace along the opposite side of the ROW. Second, a sloping surface gradient at a project site may require that spoil removed from the pipeline trench be stockpiled with a wider base, extending off of the ROW, than would be required at a project site with a level surface. Further, a project to lower or replace pipe at a creek crossing may require water diversion measures that necessitate a workspace wider than the established ROW. In addition, though project equipment is typically aligned along the existing pipeline ROW, project site conditions such as size, shape and/or slope may require that equipment be centralized in an equipment marshaling area (typically 25 ft. wide by 100 ft. long) for temporary storage, security and/or service. Biological surveys encompass both areas of potential surface disturbance and areas within the zone of potential indirect construction impacts, such as noise. In addition, applicable project best management practices (BMPs) are identified at this stage of project planning and incorporated into planning documentation. A Project Construction Plan is prepared for each individual project location to document project planning. The Project Construction Plan contains the following sections of detailed information: Description of Work for the Project; Responsibilities and Authorities; Safety Requirements; Job Contacts and Notification Requirements Matrix; Pre-Job Training Requirements; Environmental Protection; Project Schedule; Forms / Documents Required; 9 <<>> Chronological Sequence of Events; and Appendices as follows: Appendix 1 - Location Map Appendix 2 - Drawings, Calculations, and Specifications Appendix 3 - Environmental Protection Plan Appendix 4 - Storm Water Pollution Prevention Plan Appendix 5 - Safety Procedures Document Appendix 6 - Sample Forms Project BMPs are defined as procedures and specifications by which environmental controls will be implemented and include such items as sedimentation and erosion controls, reclamation procedures, minimization and avoidance procedures, inspection and reporting procedures, spill containment and cleanup procedures, procedures for addressing unforeseen circumstances, procedures for addressing foreseen, but unpredictable circumstances, and others. Project BMPs are identified and adapted from technical guidance manuals generally accepted as providing the appropriate environmental protection measures, such as the Texas Natural Resource Conservation Commission (TNRCC) technical guidance manual, Federal Energy Regulatory Commission (FERC) Environmental Guidance Manuals, and the City of Austin Environmental Criteria Manual. BMPs are incorporated within the Longhorn Storm Water Pollution Prevention Plan (SWPPP); an example of an SWPPP is included the Biological Assessment (Project Documentation Appendix at Tab 6). Project Environmental Inspectors Longhorn and Williams shall employ the services of environmental inspectors (such as Horizon Environmental Service Inc. and 3D/International) at every project site with associated species- related constraints. These environmental inspectors are qualified under FERC guidelines. The environmental inspector will remain at each project site during the period of activity to ensure compliance with all project constraints and project BMPs. The inspector is authorized to dictate any additional project BMPs that may become necessary during the activity and to modify work activities and progress to the extent necessary to ensure compliance with project environmental constraints. However, in the event of a conflict between project constraints and sound engineering practices, the inspector shall consult with project engineers and the Service, as appropriate, to achieve project goals while minimizing any impacts to listed species or the environment. The environmental inspector retains oversight of site closure and performs, or supervises the performance of, post-activity inspections of project BMPs until site stabilization is achieved. The environmental inspector will produce appropriate documentation for each construction location to include BMP compliance logs, photographs, as-built dimensions of disturbance, and any encounters with listed species during the construction process. The completion reports for projects listed in Appendix Two, will be provided to the EPA, OPS, and the Service, annually. Site Preparation Prior to site entry, at locations where avoidance and/or minimization of species effects has been recommended, a qualified biologist will clearly identify areas for avoidance and will stake and/or flag such areas. The project environmental inspector also surveys the site to ensure that all such avoidance areas are clearly identified in accordance with conditions approved in the consultation process and confirms other site-specific areas in which disturbances may occur such as routes of 10 <<>> ingress/egress, spoil management areas, equipment marshaling areas, workspace areas, and similar areas needed for construction. Project BMPs are reviewed prior to site entry, and the locations of any necessary physical control measures to be employed are identified. A survey crew will precede the project equipment and mark the project boundaries. In addition, the pipeline centerline will be marked at 100-foot to 200-foot intervals. Site Entry Upon site entry, the necessary project equipment is transported to the site via the designated route for ingress/egress. Site access is achieved via improved roadways and the established ROW, using the shortest available route between improved roadways and the project site. Routes of ingress/egress account for any potential for effects to threatened and endangered species and habitat that may exist along the ROW between the improved roadway and the project site, as well as accounting for other potential impacts to the environment. At times, equipment will remain on-site only during the time that it is in active use to allow it to be shared between nearby project sites. However, impacts to potential habitat for listed species from site ingress/egress will be minimized to the maximum extent practicable. Prior to any excavation, site vegetation is removed, and project BMPs are implemented. Site vegetation is cleared to the extent necessary for project completion, so long as the vegetation is not located in areas identified for avoidance. Clearing is accomplished by the methods described in above (ROW Clearing), though vegetation within the workspace may require removal. Project BMPs are installed in accordance with project planning documentation and in accordance with the site-specific SWPPP. Task Descriptions - (Process Once All Authorizations Are Obtained) The following task descriptions identify process steps that occur once all authorizations are obtained and regulatory requirements are identified and incorporated into project planning and engineering documentation. Detailed procedures for each of the activities summarized below are available in Pipeline Construction Specification CS4, which is included in the Biological Assessment (Project Documentation Appendix at Tab 4). In the event of a conflict between Construction Specification CS4 and the site-specific components of the Project Construction Plan, the Project Construction Plan will be followed. Pipeline Lowering and/or Replacement - Open Terrain Once the project site has been prepared and equipment brought onto the location, the following major activities take place. • The pipeline segment to be replaced is isolated by cutting and plugging at boundaries. Williams operating personnel will establish that the line is not pressurized and is properly isolated such that the contractor may cut the pipeline at the project limit boundaries. Mechanical plug devices will be utilized to prevent residual product leakage from the pipeline segments or entry of foreign materials into the pipeline. These devices shall be secured to prevent their loss or tampering. 11 <<>> Remove large rocks, if any, from ROW work area to appropriate disposal/storage area. Track hoes with buckets are used, unless larger rocks require grapple capable (clam) buckets. Remove and set aside topsoil spoil (double ditch practices). Double-ditching will be required in areas where native plant communities need to be re-established, or there are topsoil improvements, such as sodded lawn areas and cultivated fields. Double-ditching allows topsoil management by making two passes to remove and segregate spoil; one to remove and set aside topsoil and one to remove and set aside subsoils. Remove overburden and expose pipe. Utilizing track hoes, remove and set aside overburden from the pipeline and load and remove excess amounts from the work site for disposal. Unsuitable overburden (i.e., large rocks) will be disposed of in approved sites. Cut pipe into subsections at road and water crossings. Expose and cut the pipeline at road crossing boundaries to isolate the removal section into subsections. Utilize drain pans to recover any remaining liquids as the cut is made. Install mechanical plugs in all exposed pipe ends. Raise and crib pipe alongside the trench. Properly manage any coating which comes loose from the pipe. • Prepare and wrap pipe for disposal. Double wrap the pipe sections with 6-mil thickness plastic wrap, taping and sealing each wrapping separately. Ensure that the ends are sealed to prevent any release of coating. • Remove pipe from ROW. Load and remove the wrapped pipe sections by truck. Care will be taken to preserve the plastic wrapping on the pipe. Secure the pipe to the trailer and haul to the disposal site for final disposition. • Cleanup and grade ROW for survey and trenching operations. • Capture, contain, and remove any remaining coating materials/scraps using project-prescribed methods for asbestos containing materials. Prepare the grade on either side of the ditch to accommodate the trenching machinery, removing any large rocks. Survey crew should mark and stake the centerline offsets as required by the trenching crew. • Deepen trench to new depth. Depending upon the length of the desired lowering and/or replacement, and depending upon whether the trench is in soil or rock, a track-hoe or wheel trencher (rock saw") deepens the trench to the new depth. A wheel trencher is typically used for longer trenches and trenches in consolidated rock. Dust generation is monitored during trenching, and a water fog of the trenching mechanism may be employed to minimize airborne dust in non-rural areas. 12 <<>> • String new pipe along trench. As the ditch is prepared, the pipe may be strung along the workpad in anticipation of measuring and marking for bending, welding, and lowering operations. The survey crew will note the pipe heat and identification numbers sequence for the individual pieces as they are placed. The survey crew will survey the new ditch profile and mark the pipe for calculated field bends. Make field bends. The field bending crew will proceed ahead of the welding crew to make any required field bends. The contractor may also elect to set up field bending in one of the equipment marshaling areas and perform bending there rather than on the ROW. Weld and Radiograph new pipeline. The welding crew will proceed to weld the pipeline. Inspectors will survey and note the weld numbers and identification of the welders for this activity. The radiography crew will follow the welding crew. Inspection will be per standard specification API 1104 and include 100% radiography of all girth welds. • Apply weld joint coating and inspect pipeline coating for "holidays". A holiday is a point where the coating fails to electrically insulate the pipe. Weld joint coating will be applied as specified in the Project Construction Plan. This will be by field-applied FBE (fusion bond epoxy). Following weld joint coating, the entire coating system will be inspected for holidays and repaired as required. Pad and lower pipe. Pad the ditch and lower the pipeline as specified in Construction Specification CS4. Install ditch plugs as required to stabilize pipeline during hydrotest and backfilling. The pipeline coating will receive a final "jeeping" as the pipe is lowered to ensure its integrity. Jeeping is the process of electrically inspecting the pipeline coating to ensure that no holidays exist in the coating, so named due to the "jeeping" sound the inspection device emits when a holiday is identified. • Complete as-built survey. Complete as-built survey activities, noting weld locations, pipe identification codes, and location and stationing of bends, fittings and other such features for inclusion in alignment sheet drawings. Backfill and compact trench. Backfill and compact the ditch according to Construction Specification CS4, maintaining sufficient cover to allow for settling. Install ditch breakers and silt fencing as appropriate for surface erosion control until the site is stabilized. Perform hydrostatic pressure test on new pipeline segment. Obtain fresh water for pressure test and begin line fill behind a pig. The test pressure and test duration will be established and specified in the Project Construction Plan or in separate hydrostatic testing plans. • Drain and dispose of hydrostatic test water. Upon completion of the hydrostatic test, the test water is either pushed with nitrogen to a subsequent test site or 13 <<>> removed into mobile tanks for hauling to a disposal facility. Test water is controlled to ensure that it is fully contained in order to prevent discharge to the environment. • Perform final tie-ins. Remove the test headers and make the final tie-ins of the new pipe segment to the existing pipeline. The tie-in welds will be 100% radiographed to ensure their integrity. Coat the tie-in welds with an appropriate joint coating system compatible with both FBE and coal tar coatings. The coating is inspected, or jeeped, and any holidays are repaired. The tie-in locations are backfilled and compacted. • Clean, grade, and seed ROW. Following installation of erosion control measures, re-seed the ROW with native grass seed and/or sod as prescribed for the location. Re-install pipeline markers and any traffic control devices to limit or restrict ROW access by motor vehicles. • Perform site cleanup and restoration. Clean up equipment marshaling and material storage sites, ensure that the worksite access roads are restored to prime condition, and that any road access ways are cleaned and restored. Pipeline Lowering and/or Replacement - Creek Crossing Pipeline lowering and/or replacement at creek crossings follows generally the same sequence of activities described above for open terrain; however, the additional activities described below apply to the actual creek crossing area. In addition, creeks may be crossed by either trenching or boring. Each crossing method is summarized separately below. Trenching A trenched crossing is lowered and replaced in much the same manner as an open terrain project; however, incremental measures are employed to ensure both that erosion and sedimentation are minimized and that no potentially harmful materials are discharged to the waterway. Pipeline Construction Specification CS4 in the Biological Assessment (Project Documentation Appendix at Tab 4) provides additional details. • Cut pipe at creek crossings. Expose and cut the pipeline at the creek crossing boundaries to isolate the removal section into subsections. Utilize drain pans to recover any remaining liquids as the cut is made. Install mechanical plugs in all exposed pipe ends. • Implement water quality protection measures. Staging areas, spoil storage areas, and additional workspace areas are located in upland areas above the creek bed. Hazardous materials such as chemicals, fuels, lubricating oils and any other potentially harmful materials are maintained at least 100 feet from the water body. BMPs are implemented to prevent sedimentation. Flumes, dams, equipment bridges and other diversion devices are installed as necessary to perform "dry ditch" excavation. 14 <<>> • Erosion control measures are employed after project completion to ensure that stream flows do not cause erosion of disturbed areas and subsequent sedimentation. Erosion controls protect against sedimentation and prevent stream flow from removing pipeline cover which could expose the pipe to stream bed forces. Erosion control measures are site-specific, depending upon site conditions, and include berms, dikes, water bars (perpendicular to the pipeline alignment), silt fences, staked hay bales, seeding, mulching, hydro-mulching, rip- rap, and trench plugs. Boring Stream crossings may be installed by boring rather than trenching, depending upon hydrologic setting, engineering considerations, and soil types. The existing pipeline may be abandoned in place after obtaining approvals from the landowner and, if necessary, state and federal authorities, and after (a) filling the pipe with an inert material such as grout or concrete, or (b) sealing the ends of the pipe. The pipe may not be abandoned in place if its presence could interfere with stream flows or interfere with future uses of the waterway. Boring a stream crossing requires the use of a work space for installation of bore pits in which the boring equipment operates. The boring operations typically require a workspace approximately 100 to 250 feet wide by 150 feet long. The work spaces are located above the high water mark unless topography or other factors dictate otherwise. Typically, no instream soil disturbance occurs, and BMPs are employed to ensure that spoil storage and other project activities do not cause erosion or sedimentation. From within the bore pits, the boring equipment creates a parabolic pathway to the pit on the other side of the stream bed. Bored material is circulated out of the bore and retained at the upland spoil storage area. The bore is sealed with grout or bentonite to fill fissures along the course and to ensure bore stability. The new pipe is then pulled through the bore using equipment designed for that purpose. Once the pipe is welded, inspected, surveyed, coated and tested, the excavations are filled and compacted, and the site is restored. Site restoration and stabilization is achieved in the same manner as described in above (Pipeline Lowering and/or Replacement - Open Terrain). Any necessary erosion and sedimentation controls are employed, and the site is inspected and maintained until final stabilization is reached. Hydrostatic Testing - Overview of Activities A hydrostatic pressure test is scheduled to be performed to ensure the integrity of the system. This test is scheduled to commence in February 2000 and conclude in May 2000. Hydrostatic testing will start at the Longhorn GATX pump station in Galena Park (Houston) and proceed westward to Crane Station. The test medium will be potable water from a local municipal supply source. In the event some water is lost due to pipe failure, or if water is needed to fill longer test sections, fresh make-up water will be acquired, by permit, from sources crossed by the pipeline (i.e., from rivers or streams) or other sources of fresh water. The hydrostatic testing occurs in segments, which are subdivided into test sections of varying lengths. Factors that contribute to test section length include: 15 <<>> (a) target test pressures; (b) pipe size and grade; (c) the presence or absence of species and habitat; (d) the location of valves and pump stations; and (e) elevation changes along the pipeline. Due to additional factors, two test sections will not be tested during the Houston to Crane hydrostatic testing project. Those two sections are areas that encompass habitat for the Houston toad and areas of potential effect to the Barton Springs Salamander (including the recharge zone and part of the adjacent contributing zone (on each side) of the Edwards Aquifer). Rather, those sections will be tested after Phase Two consultation relating to pipeline operation, maintenance and emergency response, and after maintenance construction to replace pipeline segments in those areas is completed. To facilitate hydrostatic testing of the pipeline, headers will be installed on the pipeline at intervals along its length which divide the pipeline into segments for discrete testing. There are forty (40) header sites involved in the test. A general description of the installation of the test headers follows. Additional information is provided in the Biological Assessment (Project Documentation Appendix at Tab 8). Headers vary in configuration; however, all function similarly to allow the introduction of test water, the pressurization of the test segment and the displacement, after testing, of the test water to the following test section. • Prior to any work, the sites will be subject to an environmental, endangered species, and archeological survey conducted by qualified third-party biologists and archeologists. The headers will be installed by excavating an area approximately 20 ft. wide x 80 ft. long x 4 ft. deep around and under the pipeline. The spoil will be stored on the temporary work easement. The topsoil will be segregated from the sub-grade for restoration of the site following the hydrostatic test. Storm water management during construction and testing will be by methods prescribed in the SWPPP, an example of which is included in the Biological Assessment (Project Documentation Appendix at Tab 6). • The exposed pipe will be cut and spread apart horizontally, and pre-fabricated headers will be welded to each section. The downstream header shall have a wire brush pig and displacement pig inserted in it before it is welded on the pipeline. A 6-inch temporary crossover pipe with valve will be installed between the upstream and downstream header. Upon completion of the test, the hydrostatic test water will be displaced into the next test segment by nitrogen. The test section will be vented to atmosphere and the temporary piping and headers will be removed. The pipeline will be tied back together with a joint of new pre-tested pipe and the joints will then be coated and wrapped to provide corrosion protection. Coating is inspected for holidays, and repairs are made if holidays are identified. The excavated area will be backfilled and compacted with the sub- grade material in the spoil pile followed by the topsoil to finished grade to match the surrounding terrain. The disturbed area is seeded with native grasses or sod, and BMPs are inspected and maintained until the site is stabilized. Total surface 16 <<>> workspace requirements for test header installations are about 100 feet wide by 150 feet long along the pipeline. Hydrostatic Testing - Potential Failure of Pipe The locations of potential hydrostatic test failures cannot be accurately predicted, the volume of test water discharged cannot be accurately predicted or calculated, and the number of investigative excavations cannot be predicted. The inability to accurately predict the potential impacts of hydrostatic test failures precludes any pre-activity attempt to predict and/or estimate the potential effects of test failures. Any such attempt would be likely to result in inaccurate estimates. Therefore, Longhorn proposes to provide for a contingent methodology for calculating any such effects. Of the methodologies available for calculating the effects of activities upon species and habitat, the most applicable is the Habitat Equivalency Analysis (HEA) methodology developed by the National Oceanic and Atmospheric Administration for Natural Resources Damages Assessments (NRDAs). The HEA methodology is briefly described by the following steps. • The duration and extent of injury are documented and estimated from the time of injury until the resource recovers to baseline. The services provided by a compensatory project are documented and estimated over the full life of the project. • The size of a compensatory project is calculated such that the total increase in services provided by the compensatory project equals the total interim loss of services due to the injury. • The cost of the compensatory project is calculated. A more detailed description of the HEA methodology is provided in Biological Assessment Project Documentation Appendix at Tab 10. Longhorn's will execute the following sequence of measures in the event a hydrostatic test discharge occurs in areas of concern for species and/or habitat: In the event of a test failure, immediately notify a qualified biologist, who will be maintained on standby along the test segment, and direct the biologist to the failure site; • If a discharge occurs, the biologist will assist the identification of response actions to minimize potential impacts to the environment; and, • The biologist will perform a field survey to document the loss of, destruction of, or injury to natural resources (a) at the location of any excavation, whether the excavation is for location of a failure or for repair of pipe; (b) within the area of 17 <<>> impact of the test water; and (c) in any other areas affected by the response to the test failure, as at any other construction site. The effects, if any, of the hydrostatic test failure upon species and/or habitat will then be calculated pursuant to the HEA methodology. Longhorn shall compensate for the value of any such adverse effects by paying the monetary value of an appropriate compensation project to conservation efforts directed at the preservation and recovery of the affected species and habitat in the region where the impact occurred. For example, if a hydrostatic test resulted in a take of golden-cheeked warbler or black-capped vireo habitat, Longhorn would contribute the requisite monies to appropriate conservation entities acceptable to the Service, such as Balcones Canyonlands Conservation Plan, The Texas Nature Conservancy, or similar initiatives. Cathodic Protection Enhancements Enhancements of the pipeline cathodic protection system consist of (a) installation of anode beds and (b) re-coating of sections of existing pipe. The cathodic protection system protects the pipe from corrosion. These enhancements are identified and described in the Biological Assessment (Project Documentation Appendix at Tab 2), and the locations where activities may affect species and habitat are identified in Appendix Two. Project planning is performed in a manner similar to that described above. Installation of deep anode ground beds requires a series of vertical bores within which sacrificial anodes are placed; the anodes within each bore and among the series of bores are connected by subsurface wiring that is then connected to the pipeline. The bores and wiring trenches are installed within the existing ROW. During boring, a circulating pit is dug to contain cuttings removed from the bore. After project completion, the pit is filled, excess cuttings are removed for disposal, and the site is closed in the manner described in previous discussions of construction site closure. An example project work plan and related diagrams that provide additional detail about deep ground-bed installation are included in the Biological Assessment (Project Documentation Appendix at Tab 11). Pipeline coating reconditioning involves the same activities required for a pipeline lowering or replacement, with the exception of the process steps to remove existing pipe and install new pipe. A coating replacement site undergoes the project planning, site preparation, site entry, and site closure steps much as described above. Since the pipe is not cut, any residual liquids within the pipe do not present contamination potential. Asbestos containing pipe coating is managed in accordance with the provisions of the Environmental Protection Plan and the Project Construction Plan (Biological Assessment - Project Documentation Appendix at Tabs 5 and 3, respectively). All coating reconditioning is inspected, or "jeeped," and any holidays are repaired. Surge Pressure Protection To reduce the risk of over-pressurization of the pipeline, Longhorn will implement system changes and operating practices to limit surge pressures to no more than maximum operating pressure in sensitive and hypersensitive areas identified by the EPA and OPS. (Biological Assessment - Project Documentation Appendix at Tab 2). One system change involves the installation of over-pressure activated by-pass systems that will allow a pressure spike to be relieved around certain gate valves. The installation of a by-pass system involves the same 18 <<>> process steps as the installation and removal of a hydrostatic test header; see above (Hydrostatic Testing - Overview of Activities). The by-pass system to be installed at the east bank of the Llano River will use the same work location as the hydrostatic test header to be installed at that valve site. Investigations Projects to investigate possible pipe dents and corrosion anomalies follow the same planning and preparation procedures for a pipeline lowering/replacement, but on a lesser scale. Table 2 identifies relevant information for, and the locations of, projects to investigate possible pipe dents and corrosion anomalies. Typical investigation sites require a trench approximately 20 feet in length. If a dent or anomaly cannot be field repaired, a segment of pipe will be removed and replaced, with the length replaced at least twice the pipe diameter. Coating and coating inspection and repair, as well as site closure, follow the procedures described in Section 4.0 of the Biological Assessment. Avoidance and Minimization Longhorn will, to the extent reasonably possible, conduct the maintenance construction, testing, and other subject activities in a manner that avoids potential effects to species and habitat. If avoidance is reasonably and practically not achievable, Longhorn will conduct the activities in a manner that minimizes any potential effects. Controls and other measures designed to achieve that goal are described in the foregoing descriptions of the various activities. A number of those controls and measures are summarized as follows: • Identifying and marking habitat areas for avoidance; • Planning project implementation to minimize the potential for any effects; Using FERC qualified environmental inspectors with authority to alter project implementation procedures in sensitive areas; Adjusting project timing to avoid breeding populations; for example, projects in Houston toad habitat will avoid the months of January through June and projects in golden-cheeked warbler and black-capped vireo habitat areas will be avoided March 1 through August 1 and March15 through September 1, respectively; • Implementing storm water pollution control BMPs even when not required by permit; • Maintaining qualified biologists in hydrostatic test project areas for immediate response in the event of a test water release in a habitat area; • Avoiding, until project planning is accomplished, hydrostatic testing over the Toad habitat areas; and Edwards Aquifer recharge zone, portions of the contributing zone, and in Houston 19 <<>> • Conducting additional species surveys along the pipeline ROW to determine actual presence or absence of species and populations where present. Additionally, work in areas of noise-sensitive species (i.e., golden-cheeked warbler and black- capped vireo) will be avoided during the breeding/nesting season. If work must occur in habitat areas during noise-sensitive seasons, the Service will immediately be notified. Proposed Minimization to Offset Impacts to Listed Species Land Conservation Funding The extent of the project and timetable for implementation prevent Longhorn from completing detailed surveys for threatened and endangered species in all potential habitat where disturbance or destruction may occur, due to the variable survey times for each species and extensive amounts of habitat areas involved. Exact quantification of impacts to all listed species from scheduled activities is not possible if the project is to be completed on a timely basis. Therefore, Longhorn has requested that the Service prepare a biological opinion based on an evaluation of impacts to potential habitat, rather than impacts to individuals or identified occupied habitat. Longhorn proposes to provide benefits to the species based on potential habitat impacts as if it were occupied. This will insure that all possible impacts are considered and provide maximum species benefits. Longhorn will apply a standard formula to potential impacts to determine appropriate minimization. The formula is: impact acreage × 1.2 x fair market value of land in the area. This formula is modified for Houston toad habitat to use a 3x multiplier instead of 1.2 due to the more critically imperiled nature of the toad population in general. Longhorn will also apply a one-time 10% inflation factor to anticipate increases in land values over time. Within 60 days following the Biological Opinion, Longhorn will engage two licensed appraisers to determine the average value of land in the vicinity of the impact areas for each species along the pipeline. If the two appraisals differ more than 5%, then a third appraisal shall be obtained to reach a determination. All appraisals shall take into account land uses and conditions in the vicinity. The current calculation of compensation, set out below, will then be revised based upon the average of the two or three appraisals. Longhorn proposes a series of payments over time to fund the habitat acquisition, with such payments being made in a manner which will maximize benefits to the potentially affected species. The initial payment will go toward conservation efforts directed to the Houston toad and the Tobusch fishhook cactus because those species face a relatively greater prospect of decline than the remaining species. Longhorn will provide the land conservation funding amount to one or more conservation organizations with funds devoted to conservation of the affected species. Payments will be made on an annual basis over a six-year period. Future land values shall be determined on the basis of appraisals performed every second year following the initial appraisals and determined employing the same methodology as described above. The remaining compensation due from Longhorn shall then be recalculated based upon the compensation acreage remaining to be funded and the most recent land appraisals for such acreage. 20 <<>> Longhorn and the Service will identify conservation organizations that provide the greatest benefit to the affected species as a whole. Potential recipients may include the National Fish and Wildlife Foundation, the Texas Parks and Wildlife Department (TPWD), Texas Nature Conservancy, Texas Land Trust, Trust For Public Lands, the Hill Country Conservancy and similar comprehensive conservation initiatives. The Service will also work with TPWD and other partners to accomplish the greatest benefit for listed species. Longhorn may at its discretion, at any point in time, (a) pay all outstanding compensation on the basis of the most recent appraised values; or (b) purchase required acreage acceptable to the Service for any given species. Given the timing matters identified above, Longhorn will provide assurance to the Service that the calculated compensation (refined on the basis of actual land appraisals) will be funded on time and in full. Such assurance will take the form of security that assures the Service that the compensation will be funded. Longhorn proposes such methods as a bond, a letter of credit, an escrow, or similar such mechanism reasonably acceptable to the Service. The security will cover compensation not proposed for immediate funding and the one-time 10% escalation value applied to same. Longhorn makes this proposal conditioned upon the requirement that, as payments are made or in-kind compensation is provided, a corresponding reduction be made in the compensation acreage outstanding and thus in the amount of security required. Before issuance of the Biological Opinion, Longhorn shall provide to the Service reasonable evidence that the security is in place. Based upon the formula, and the impacts described above, and assumed land values, the present calculation of land conservation funds for minimizing adverse affects would be as follows in Table Two. Table Two. Proposed Minimization to Offset Impacts to Listed Species Price Inflation Species Acres Multiplier Acres per acre factor Total ($) Texas prairie 61.3 1.2 73.56 $3000 10% 242,748 dawn Navasota 5.2 1.2 6.24 $ 1000 10% 6,864 ladies'-tresses Houston toad 20.6 3.0 61.80 $2000 pay now 123,600 Golden- 116.8 12 140.16 $2000 10% 308,352 cheeked warbler Black-capped 41.7 1.2 50.04 $ 1000 10% 55,044 vireo Tobusch 213.2 1.2 255.84 $1000 pay now 255,840 fishhook cactus 21 <<>> Total 992,448 Longhorn's Monitoring Commitment In addition to Longhorn's land conservation funding, they have also committed to survey the existing ROW to determine the presence/absence of listed species. The following summarizes the Longhorn Monitoring Commitment for each potentially affected species. Longhorn will survey for the Texas prairie dawn within the potentially suitable habitat areas to confirm its presence or absence. The survey will be conducted within the ROW in areas identified as potential habitat in March of 2000 to determine if the Texas prairie dawn is present, and if so, its distribution and abundance. Longhorn will conduct a Fall survey (15 October to 15 November, 2000) for the Navasota ladies'- tresses within the ROW if suitable climatic conditions occur to determine the presence or absence of this species, and if present, its distribution and abundance. • For the Tobusch fishook cactus, Longhorn will conduct a blooming period survey (March to April 2000) within the ROW throughout Kimble County to determine the species' distribution and abundance. One or more additional Spring surveys (as acceptable to the Service) for the Houston toad will be conducted along and downstream of the pipeline to determine the presence or absence of toads and their overall distribution and abundance. • One to two additional Spring breeding season surveys (as acceptable to the Service) will be conduced for the golden-cheeked warbler along and adjacent to the ROW within the potential habitat areas to determine habitat utilization and overall distribution and abundance. • One to two additional spring breeding season surveys (as acceptable to the Service) will be conduced for the black-capped vireo along and adjacent to the ROW within the potential habitat areas to determine habitat utilization and overall distribution and abundance. STATUS OF THE SPECIES/ENVIRONMENTAL BASELINE Status of the Species and Distribution The following is a review of the status of each species being considered in this biological opinion that may be adversely affected by the proposed action. The Service has reviewed the list of threatened and endangered species and identified potential impacts to the following species. Texas prairie dawn (Hymenoxys texana) - The Texas prairie dawn is a small, delicate annual to 6 inches tall with single or branching stems. It has small yellow flowers blooming in late March 22 <<>> to early April. It occurs in sparsely vegetated areas of fine-sandy compacted soil. Specifically, the species occurs in the northern part of the Gulf Coastal Prairie in Harris and Fort Bend counties, where it is found in poorly drained depressions or saline swales around the periphery of low, natural mounds (mima mounds) in open grasslands. These mostly barren areas are sparsely vegetated, and the soil is often covered with a blue-green alga (Nostoc sp.). It can also occur on disturbed soils such as rice fields, vacant lots, pastures, and possibly pipeline ROW if the soil structure remains relatively intact. There are fewer than 35 known sites recorded for the species, and several have been lost in recent years to urbanization in the Houston area. Most populations remaining are small, and are on private land. Very few sites currently have any form of protection. The primary threat to the species is habitat destruction as a result of urbanization, roadway construction, and conversion of habitat for agricultural purposes. An assessment of potentially suitable habitat for the Texas prairie dawn was conducted by Horizon in early June 1999 along the Longhorn pipeline ROW in western Harris and eastern Waller counties from the Satsuma Station on the west edge of Houston to near Monaville in Waller County. Three areas along the ROW, one in Waller County and two in Harris County, exhibited native range conditions with suitable soils that could be considered potentially suitable habitat areas for the prairie dawn. All other areas along the pipeline within the area investigated had been converted to row crop (corn), monoculture, hay or grazing pasture, or disturbed for land development. A survey for the prairie dawn has not been conducted within the potentially suitable habitat areas to confirm its presence or absence. Navasota ladies'-tresses (Spiranthes parksii) - The Navasota ladies' tresses was listed as endangered on May 6, 1982, without critical habitat. This member of the orchid family occurs primarily in moist, sandy soils in small openings in post oak savanna vegetation. The species is known to occur in Brazos, Burleson, Fayette, Freestone, Grimes, Jasper, Leon, Madison, Robertson, and Washington counties (USFWS 1984b). Currently, approximately 149 sites have been recorded, representing perhaps 75-80 distinct population areas, predominantly concentrated around two centers of distribution, one in southern Brazos County and one in central Grimes County. Some of these recorded sites have been damaged or destroyed since they were reported. Together these population centers contain the majority of known sites and individuals (Wilson 1993). However, the majority of sites contain fewer than 25 recorded plants. It is known that for this species not all individuals in a population are visible above ground in a given year, and most of these sites have been visited only once, so demographic data on populations is very limited. Nevertheless there is great concern among botanists that most of these sites may not represent viable populations. Navasota ladies'-tresses occur in a variety of moist sandy soils near drainages, in the Post Oak Savannah vegetation associated with the Navasota, Brazos, and Trinity River watersheds. Navasota ladies'-tresses are typically found on erosional remnants between rills in slightly to moderately eroded areas along minor intermittent tributaries, from the upper drainage head, extending along the edges of temporary streams to the flood plain of permanent streams. Navasota ladies-tresses grow on sandy loam soils and are often associated with post oak, blackjack oak, yaupon, slender bigelowia (Bigelowia nuttallii), and Spiranthes cernua.. Typical 23 <<>> habitat consists of natural openings in upland Post Oak Savanna vegetation (Poole and Riskind 1987, USFWS 1984b, Wilson 1993). Plants are believed to be situated where subsurface flow or seepage of water occurs seasonally, a common feature in other species of the genus (Arft and Ranker 1995, Kathy Parker, pers. comm.). While Navasota ladies'-tresses is found in small naturally created openings in the post oak woodlands, it cannot be regarded as a disturbance species, as it usually occurs in well developed woodland and is not a colonizer of extensively disturbed areas. There are few records in flood plain forests, open savannahs and shrublands that have experienced little or no grazing pressure, and in hillside seepages. Navasota ladies'-tresses is extremely slow-growing and long-lived. Rosette leaves support the formation of a storage tuber between November and March that sequesters resources in preparation for sending up a leafless bloom stalk at some future time. It is believed that often plants require more than one year of photosynthate storage to successfully send up a bloom stalk. If local conditions have not been favorable for forming sufficient below ground reserves, the plant may not bloom (Wilson 1993). Navasota ladies'-tresses apparently does not transplant well. In a mining project in Grimes county by Texas Municipal Power Association (TMPA), plants in the impact area were removed and transplanted into an adjacent habitat area. Plant survival has been low in most sites (TMPA 1996). Similarly, in an experiment in Lick Creek Park near College Station, Dr. Hugh Wilson planted some seedlings which survived into their second season, but died prior to the third growing season (Wilson 1993). Because of the low numbers of individuals reported from populations, the slow growing nature of the plants, its unusual habitat requirements of openings in mature vegetation, and its sensitivity to disturbance and transplanting attempts, the species is not regarded as being very resilient, and recovery following any damage to a population is expected to be slow. The primary threat to Navasota ladies'-tresses is destruction or modification of habitat due to urbanization, clearing for agricultural production, or mining (47 FR 19539, USFWS 1995, 1984b). Destruction of understory by feral pigs is also a problem in some areas. More than 40 known sites have been lost in the last ten years to mining or urbanization. Post oak savannah in many of these counties continues to be converted to bermuda grass pasture. Subsequently, habitat loss continues, particularly in the areas of Brazos and Grimes counties where most sites are located. The City of College Station in Brazos County is growing rapidly, particularly in the southern and southeastern fringes where most known populations are located. Mining in Grimes County disturbs more than 7,000 acres every 5 years (Wilson 1993). In Fayette County, the species is known from one small population approximately 6 miles south of the pipeline and 2 miles north of the town of Fayette. Based on analysis of soil distribution, vegetative cover, physiographic setting, and field assessment by Horizon in November of 1999, two small areas of potential habitat for Navasota ladies'-tresses are present along the pipeline corridor. No surveys for the species have been conducted along the pipeline. Tobusch Fishhook Cactus (Ancistrocactus tobuschii) - Tobusch fishhook cactus is a rounded, biscuit-shaped cacti usually 2 to 3 inches tall and up to 3.5 inches in diameter. There are 3 to 5 central spines with the upper 2 to 3 erect and straight and the lower central spines hooked at the tip and spreading. The plants are very inconspicuous, and produce cream to yellow flowers from February through early April. These cacti have been demonstrated to be obligate outcrossers 24 <<>> pollinated by native bees with a foraging distance of about 1/4 mile, and seeds are dispersed by native ants. The species occurs on limestone gravels of stream terraces, limestone ledges, ridges, and openings on the rocky hills of live oak - juniper woodlands in Bandera, Edwards, Kerr, Kimble, Kinney, Real, Uvalde, and Val Verde counties. A significant number of populations have been documented in Kimble County. Currently about 50 sites are recorded for the species, following a recent range - wide representative survey. Most of the populations are extremely small (5-20 plants), with individuals widely scattered. Known sites are separated by large distances. Most existing populations are on private land, and there are very few protected sites. Demographic data collected in monitoring studies over the last five years or so show that only one of the known populations is even marginally viable. The species is extremely slow growing and does not appear to reproduce until 10-17 years of age. It takes four successful flowers/fruits to produce one seedling (Jackie Poole, Texas Parks and Wildlife, pers. comm.). It is estimated that very few viable populations (10-15) remain over the 8 county range of the species. The survival and recovery of the species will require restoration and careful management, to provide sufficient numbers of populations and individuals in effective proximity to each other for successful pollination (and gene flow) to ensure the continuity of the species. Studies examining the probable reasons for population declines are underway. Threats to the species are believed to include inappropriate timing of range management practices (such as fire and clearing practices that disturb the soil), extensive predation by beetle grubs, loss of habitat to real estate development, and some collection by cactus enthusiasts. An assessment of potentially suitable habitat and pedestrian survey for the cacti was conducted by Horizon in April 1999 along portions of the Longhorn pipeline ROW in Kimble County, and no specimens were observed within the ROW. However, one Tobusch fishhook cactus was observed about 50 feet north of the cleared ROW. All of the ROW within Kimble County has been identified as potentially suitable habitat. Golden-cheeked Warbler (Dendroica chrysoparia) - The golden-cheeked warbler is a small, migratory songbird, 4.5 to 5 inches long, with a wingspan of about 8 inches. The male has a black back, throat, and cap, and yellow cheeks with a black stripe through the eye. Females are similar, but less colorful. The lower breast and belly of both sexes are white with black streaks on the flanks. Typical nesting habitat is found in tall, dense, mature stands of Ashe juniper (cedar) mixed with trees such as Texas (Spanish) oak, Lacey oak, shin (scalybark) oak, live oak, post oak, Texas ash, cedar elm, hackberry, bigtooth maple, sycamore, Arizona walnut, escarpment cherry, and pecan. This type of woodland generally grows in relatively moist areas such as steep-sided canyons and slopes. A mix of juniper and deciduous trees on the slopes, along drainage bottoms, and in creeks and draws provides ideal vegetation for birds. Warblers are also occasionally found in drier, upland juniper-oak (i.e., live oak, post oak, blackjack oak) woodlands over flat topography. An assessment of potentially suitable habitat and surveys for the golden-cheeked warbler was conducted by Horizon in April and May 1999 along the Longhorn pipeline ROW from Austin, Texas, to the Mason/Kimble County line. Although no potentially suitable habitat areas were 25 <<>> observed within the Longhorn ROW, several areas were located adjacent to the previously cleared permanent ROW. All areas were surveyed by Horizon a minimum of 5 times during April and May on days with favorable weather conditions for bird activity, per U.S. Fish and Wildlife Service guidelines (USFWS, 1994a). Surveys were conducted on 8, 9, 12, 27, 28 April, and 3, 11, 19 May. An equivalent of 4 person-hours per 100 acres were spent at each site, based on habitat size. No golden-cheeked warblers were found to be utilizing any of the potentially suitable habitat areas on or immediately adjacent to the ROW. However, three years of survey are necessary to confirm presence/absence under Service guidelines (USFWS 1994a). Black-capped Vireo (Vireo atricapillus) -The black-capped vireo is a 4.5 inch long, insect- eating songbird. Mature males are olive green above and white below with faint greenish-yellow flanks. The crown and upper half of the head is black with a partial white eye-ring. The iris is brownish-red and the bill black. The plumage of the female is duller than the male. Females have a dark slate gray head. In Texas, vireo habitat is found on rocky limestone soils of the Edwards Plateau, Cross Timbers and Prairies, eastern Trans-Pecos, and, to a limited extent, on igneous soils in the Chisos Mountains. Black-capped vireos require shrub vegetation reaching to ground level for nesting cover. They typically nest in shrublands. An assessment of potentially suitable habitat and surveys for the black-capped vireo was conducted by Horizon in April and May 1999 along the Longhorn pipeline ROW from Austin, Texas to Crane County. Potentially suitable habitat areas were observed within the Longhorn ROW as well as several areas located immediately adjacent to the previously cleared permanent ROW. All areas were surveyed by Horizon a minimum of 5 times during April and May on days with favorable weather conditions for bird activity, per Service guidelines (USFWS, 1994a). Surveys were conducted on April 8, 9, 12, 27, 28, and May 3, 11, and 19. An equivalent of 4 person-hours per 100 acres were spent at each site, based on size. No black-capped vireos were found to be utilizing any of the potentially suitable habitat areas on or immediately adjacent to the ROW. However, three years of survey are necessary to confirm presence/absence under Service guidelines (USFWS 1994a). Bald Eagle (Haliaeetus leucocephalus) - The bald eagle is a migrant and winter resident in Texas. The bald eagle was recently down-listed from endangered to threatened due to successful conservation efforts and is now proposed for de-listing. Migrating and wintering bald eagles typically arrive in Texas in November and depart around February. They are found primarily in association with reservoirs, rivers or other large bodies of water where they feed on fish, carrion, and waterfowl. Nesting bald eagles in Texas are found in the eastern portion of the state and along the coastal plain as far south as Calhoun and Refugio counties. No bald eagle nests have been identified near the pipeline ROW, however, bald eagles may occur along major waterways (Brazos and Colorado rivers, or major tributaries with impoundments) downstream of the pipeline corridor. The Federal Register, (Volume 64 No. 128, Tuesday, July 6, 1999; Page 36454) contains a proposed rule to remove the bald eagle from the List of Threatened and Endangered Wildlife in the Lower 48 States of the United States. Interior Least Tern (Sterna antillarum athalassos) - Premier nesting sites for the interior least tern are salt flats, broad sandbars, and barren shores along wide, shallow rivers. Important breeding habitat characteristics include: (1) presence of bare or nearly bare ground and alluvial islands or sandbars for nesting; (2) availability of food (primarily small fish); and (3) favorable 26 <<>> water levels during the nesting season (so nests remain above water). They usually nest on sites devoid of vegetation, but have been found in areas with an average of 11 to 30% vegetative cover, composed of grasses, shrubs, and trees and ranging from 1 to 3 feet in height. Vegetation, if present, is usually located well away from the colony, with the exception of bugseed, eastern cottonwood, and sandbar willow. As natural nesting sites have become sparse, birds have used sand and gravel pits, ash disposal areas of power plants, reservoir shorelines, gravel levee roads, and other manmade sites. The typical nesting period for the least tern in Texas is mid-April to mid-August. While the interior least tern has not been documented along the pipeline corridor, potential habitat for the tern is present downstream of the pipeline along several major waterways including the Brazos, Colorado, Llano, and James Rivers, and Squaw, Beaver, and Sandy Creeks. The seasonal occurrence (Spring and Summer) and potential nesting of least terns is possible in these areas. Barton Springs Salamander (Eurycea sosorum)- The Barton Spring salamander was listed as endangered in 1997, without critical habitat. The Barton Springs salamander belongs to a group of related salamanders that are endemic to the Edwards Plateau region of central Texas. All members of this group are obligately aquatic because the adults retain the larval, gill-breathing morphology throughout their lives. The Barton Springs salamander, formally described in 1993, was first collected from Barton Springs in 1946 and has been found only at the four hydrologically connected outlets of Barton Springs in Zilker Park within the City of Austin (Brune, 1981; Chippindale et. al., 1993). This salamander is a small species, adults reaching 2.5 inches (about 68 mm) in total length with reduced eyes and elongate, spindly limbs indicative of a semi-subterranean lifestyle. Barton Springs salamanders are found in the flowing, thermally constant water issuing from the spring outlets in association with aquatic macrophytes, leaves and organic debris, and gravel and rock substrates having little silt and sediment deposition. Water from the contributing and recharge zones of the Barton Springs segment of the Edwards Aquifer influences the conditions at Barton Springs. The main threat to the species has been identified as degradation of water quality from future growth and development on the Barton Springs segment of the Edwards Aquifer (Federal Register 62:23385). Houston Toad (Bufo houstonensis) - The Houston toad was listed as endangered in 1970 (Federal Register, October 13, 1970) and Critical Habitat was designated in Bastrop and Burleson counties in 1978 (Federal Register, January 31, 1978). Houston toads are generally brown and speckled, although individual toad coloration can vary considerably. Some may appear light brown, others almost black and they may also have a slightly reddish, yellowish, or greyish hue. Two dark bands extend down from each eye to the mouth. Their legs are also banded with darker pigment. A variable white stripe streaks along the sides of the toad's body. Their undersides are usually pale with small, dark spots. Males have a dark throat which appears bluish when distended. Adult Houston toads are 2 to 3.5 inches long and like all toads, are covered with raised skin patches that contain chemicals that make the toad distasteful and sometimes poisonous to predators. The toad was eliminated from three counties (Harris, Fort Bend, Liberty) prior to the 1970s due to habitat loss resulting from urban expansion. Although Houston toad populations have been found in nine other counties (Austin, Bastrop, Burleson, Colorado, Lavaca, Lee, Leon, Milam, 27 <<>> Robertson), the Service is concerned about the long-term viability of these populations. The small population in Lavaca County has not been seen since its discovery in 199l; the population at the critical habitat site (Woodrow Lake) in Burleson County has not been seen since 1983; and the population in Leon County lies within an expanding residential area. The largest known population of Houston toads occurs within the pine/oak woodland region of Bastrop County. This area also contains federally designated critical habitat. All known Houston toad populations occur along bands of geologic formations that support deep sands. Six populations occur on a band running through Bastrop County northeast to Freestone County. Three other populations occur on another band through Lavaca, Austin, and Colorado counties (USFWS, 1994b). Houston toad habitat consists of rolling uplands characterized by pine and/or oak woodlands (loblolly pine, post oak, blackjack or sandjack oak) underlain by pockets of deep, sandy soils. Because their skin is semi-permeable to water, Houston toads become dormant to escape harsh weather conditions, such as winter cold (hibernation) and drought (estivation). They seek protection during this time by burrowing into sand or hiding under rocks, leaf litter, logs or in abandoned animal burrows (TPWD, 1993). Although Houston toads are typically associated with woodland habitat, they also breed in and migrate across sparsely wooded and cleared areas near woodlands. They may also breed in and traverse areas that do not support deep sandy soils, including clay and gravel substrates, provided these areas are near woodlands underlain by pockets of deep sandy soils. Houston toads breed from January to June, with a peak in February and March. During the breeding season, toads appear to move randomly from one breeding site to another, achieving genetic transfer between populations that may appear isolated, thus creating a metapopulation, an aggregation of smaller populations linked genetically and demographically and functioning almost as a single population. Presently, the most reliable breeding sites are stock ponds and similar impoundments, though in wet years breeding may occur wherever sufficient standing water is present. For successful breeding, water must persist for at least 30-60 days to allow egg hatching, tadpole maturation, and emergence of toadlets. Mortality in young is high, due to predation and drying of breeding sites, with significantly less than one percent of eggs laid believed to survive to adulthood (USFWS, 1984a, 1994b, 1995). The Houston toad is vulnerable to extinction primarily due to habitat loss, degradation, and fragmentation. Over the last 50 years, the historic range of Houston toads has contracted and several populations have been lost. Threats include expanding urbanization and conversion of woodlands to agricultural production areas, such as coastal bermuda pastures, use of fertilizers and pesticides that impact the toad directly or its food supply, and loss of suitable breeding habitat because of alterations in watershed drainages and wetland alterations or destruction (such as degraded water quality, draining/filling of wetlands, stocking with predatory fish, etc.). Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the Houston toad, the Service believes this phase of the project will provide a net conservation benefit for this species. According to the Houston Toad Recovery Plan (USFWS 1984a), Houston toad breeding sights have been recorded in Buescher State Park south of Longhorn Pipeline. Houston toads have also been heard chorusing on the adjacent property owned by the University of Texas to the north of Buescher State Park and Longhorn Pipeline (USFWS, unpublished data). Dr. James R. Dixon of 28 <<>> Texas A&M University conducted a survey along the Longhorn Pipeline ROW and adjacent Phillips EZ Pipeline ROW in 1991 with negative results, although areas of potential habitat were noted (Horizon 1991). Horizon Environmental Services, Inc. conducted a reevaluation of suitable habitat along the Longhorn Pipeline ROW within Bastrop County. The field reconnaissance was conducted on 2 June 1999 from the Colorado River, southeast of Bastrop, to FM 2104. Portions of the area along the pipeline had recently been cleared and planted in improved grasses. Based on field observations and discussions with the Service, two areas of suitable habitat were identified along and adjacent to the pipeline ROW. One area includes Buescher State Park from approximately 0.5 mile east of the eastern boundary of the park westward to near Highway 71. The second area begins about 500 feet to the west of FM 2104 and extends westward approximately 0.75 mile. The drainages in both of these areas flow south toward the Colorado River. EFFECTS OF THE ACTIONS Direct and Indirect Effects Texas Prairie Dawn - Potential impacts to the Texas prairie dawn may result from a number of activities. ROW maintenance will occur with the periodic (typically twice per year) use of tractor drawn mowers. Tractors will be rubber-tired, and crushing of plants could occur from time to time, particularly during blooming periods. Mowing height will typically be 3 to 4 inches. Since only the blooming shoot is usually that high, impacts from mowing are deemed to be minimal, except during blooming. Longhorn has chosen to quantify impacts as the total ROW (50 feet) through the entire area of identified potential habitat. This area constitutes approximately 61.3 acres. As an avoidance and minimization measure, mowing will be scheduled to avoid the February through April blooming season. Three construction sites have been identified for completion in the near-term, two pipeline dent investigations, and one anomaly investigation (Appendix Two). Impact for these three construction areas will be contained within the existing 50 foot ROW for relatively short distances along the pipeline. Within these areas, excavation, temporary spoil storage, equipment movement, and grading will likely result in elimination of any prairie dawn plants that may occur within the ROW in the construction areas. The area of these impacts is already included in the total ROW impact mentioned above (61.3 acres). Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the Texas prairie dawn, the Service believes this phase of the project will provide a net conservation benefit for this species. Navasota Ladies'-tresses - As in the case of the prairie dawn, periodic (twice per year) mowing with rubber-tired tractor mowers may result in sporadic crushing of plants under tractor tires or mower wheels, or cutting of bloom stalks. Impacts from periodic mowing, in the absence of detailed plant inventory information for the ROW, are quantified as of total impact for the ROW through the identified potential habitat areas constitutes 5.2 acres. As an avoidance and minimization measure, mowing will be scheduled to avoid the October and November blooming 29 <<>> season. A blooming season survey of the ROW and adjacent areas will be conducted to identify any plant locations for specific avoidance, if present. No areas of construction are identified in the two potential habitat areas. However, construction will occur just east of the most westerly potential habitat area. The ROW is to be used for access to the construction zone. It is presumed that heavy equipment movement along this portion of the ROW will result in destruction of any plants growing at that locality. Access will be kept within the existing 50 foot ROW; therefore, potential impacts have already been calculated in the ROW maintenance value above (5.2 acres). Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the Navasota Ladies-tresses, the Service believes this phase of the project will provide a net conservation benefit for this species. Tobusch Fishhook Cactus - Potential habitat for the fishhook cactus is very generally estimated from general soils and plant distribution information to include the entire reach of the pipeline's traverse of Kimble County. Without specific survey information for the cactus, it is assumed that the entire ROW across Kimble County is potential cactus habitat. As with the Texas prairie dawn and Navasota ladies'-tresses, the Tobusch fishhook cactus is low growing and not likely to be directly affected by mowing, except for possible crushing by tractor tires. However, due to the significant extent of large rocks within the ROW, mowing is not always feasible in this region. A preferred method in rocky terrain is to back drag a bulldozer blade across the ground which knocks down undesirable woody vegetation. This activity can disrupt the ground surface and possibly injure or destroy cactus plants. Therefore, direct impacts to fishhook cactus habitat may occur. The total area occupied by the ROW across Kimble County is 212.7 acres. Four test header installation locations are planned within the potential fishhook cactus habitat. Each site will disturb an additional 50-foot width beyond the ROW for the construction of the headers. The additional space is required to facilitate temporary spoils storage, equipment access, pipe construction, and testing equipment. The additional area of impact per site is between 0.1 and 0.2 acre. The total additional impact to cactus habitat is 0.5 acre. The total impact acreage for Tobusch fishhook cactus is 213.2 acres. Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the Tobusch fishhook cactus, the Service believes this phase of the project will provide a net conservation benefit for this species. Golden-cheeked Warbler - Golden-cheeked warbler habitat does not exist in the established ROW, but is presently adjacent to the ROW in a number of locations from Hays County westward to Mason County. ROW maintenance will not directly affect warbler habitat, except for hand pruning of canopies which overhang the ROW. Indirect effects may result from mowing noise or activity if birds are present in the vicinity during maintenance activities. As a minimization procedure, Longhorn will schedule maintenance activities to occur during the non- 30 <<>> nesting season (September 1 to March 1) within or near warbler habitat areas to avoid indirect impacts. The area of potential effect is determined to be 103.4 acres. Six areas of pipeline maintenance, construction, or investigation are anticipated to occur along the pipeline within potential warbler habitat (Appendix Two). Each of those areas are estimated to require additional construction space in excess of the existing ROW by variable widths. The total additional impact to warbler habitat resulting from construction clearing is 13.4 acres. The additional areas of temporary work space are needed in these areas to facilitate temporary spoil storage, machinery access, pipe stacking, and miscellaneous construction related activities. As avoidance and minimization of project impacts, Longhorn will schedule clearing, to occur during the non-nesting period (September 1 to March 1). As with the immediately impending construction schedule, clearing will commence prior to March 1 and construction activities will be continuous until completion. Total estimated impacts to potential warbler habitat are 116.8 acres. Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the golden-cheeked warbler, the Service believes this phase of the project will provide a net conservation benefit for this species. Black-capped Vireo - Seven areas of potential black-capped vireo habitat exist along the ROW between Blanco and Kimble counties. Black-capped vireo habitat, being an early successional stage of brushy regrowth, does exist within the existing ROW in places where previous maintenance activities have not occurred in several years. In this case, ROW maintenance will directly impact potential habitat within the existing ROW. The area of direct impact for the full 50 foot width of the ROW through the various habitat areas constitutes approximately 41.6 acres. Indirect impacts from ROW maintenance are not likely since maintenance activities will be conducted during the non-nesting season (September 1 to March 15) for vireos. Four maintenance construction locations have been proposed within the areas identified as potential vireo habitat (Table 2). Only one of those construction sites will require clearing beyond the 50 foot ROW width. An additional 50 feet of temporary work space will be needed to facilitate temporary spoils storage, equipment access, pipe layout and construction room. The additional acreage of disturbance for this construction site is 0.1 acre. The total area of impact to potential black-capped vireo habitat is 41.7 acres. Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the black-capped vireo, the Service believes this phase of the project will provide a net conservation benefit for this species. Houston Toad - ROW maintenance will include periodic mowing with rubber-tired tractors. To avoid mortality of toads that may occur within the ROW during mowing, maintenance activities will be timed to occur in the late summer through fall (July through December) when the toads tend to be less active and are not breeding. In addition to these avoidance procedures and the low likelihood of encounters, Longhorn will assume that all areas of potential habitat traversed 31 <<>> by the pipeline ROW are suitable habitat. This area (ROW width of 50 feet times length) is about 20.6 acres. To minimize edge effects, the ROW will be maintained in native bunchgrasses to facilitate dispersal and provide cover from predators. No construction impacts to Houston toads are contemplated in this consultation. Pipe replacements within the toad habitat area will be addressed in the second phase of consultation. 32 <<>> Because of the toad's vulnerability to development activities, the Service believes that the combined impact of the existing and anticipated habitat fragmentation and destruction in Bastrop County could jeopardize its continued existence and adversely modify its critical habitat at some point in the future, unless immediate efforts are implemented to protect enough remaining habitat to support viable, self-sustaining populations. Several large, high quality, interconnected habitat blocks are needed to promote population viability (USFWS 1994b, Houston Toad Recovery Team 1999). The Houston Toad Recovery Team believes that 20,000-30,000 acres of suitable (undeveloped) habitat in blocks of 5,000 acres or greater are needed to support a viable, self-sustaining population of toads with low risk of extinction, with an absolute minimum of 15,000 acres provided this 15,000 acres is in large, interconnected blocks of the best habitat remaining. The Service intends to ensure the toad's long-term survival and recovery by ensuring that any activities authorized under the Endangered Species Act provide long-term protection for the Houston toad. Thus, any actions authorized by the Service must permit the persistence of at least 20,000-30,000 acres in large, unfragmented habitat blocks in Bastrop County. Toads must be able to disperse between the habitat blocks through direct connections and/or through migration corridors that allow dispersal to occur (i.e., multiple smaller upland habitat patches and riparian corridors). Currently, the habitat blocks north of Highway 21 and in and around Bastrop State Park are most likely to continue to support toad populations, provided no additional habitat destruction occurs that significantly disrupts normal feeding, breeding, and sheltering behavior. Since much of the area south of Highway 71 has already been extensively fragmented by development, the Service believes that this area is less likely to continue to support toads over the long-term. The area in and around the University of Texas Science Park and Buescher State Park has potential to support a population, provided enough habitat remains contiguous and undisturbed. Until sufficient high quality habitat has been secured and managed to provide population viability in perpetuity, the Service believes that any further development that would impact the integrity of the remaining habitat blocks or their connections would jeopardize the toad and adversely modify its critical habitat. Without permanent habitat protection to ensure the persistence of the largest known population of toads in Bastrop County, the Houston toad faces an imminent risk of extinction. Thus, it is imperative that the impacts from any activity authorized by the Service provide habitat protection and maintain migration corridors. By ensuring that all clearing and development activities implement sufficient measures to minimize impacts, the Service believes many projects in toad habitat can move forward without reducing the likelihood of survival and recovery of the species. The Service will continue to assess the impacts of existing and proposed projects and evaluate whether or not this goal is being achieved. Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the Houston toad, the Service believes this phase of the project will provide a net conservation benefit for this species. 33 <<>> Other Species - Listed species that may occur away from or downstream of the pipeline corridor (bald eagle, interior least tern, Barton Springs salamander) are not likely to be adversely affected by the proposed maintenance and minor construction activities. Any discharges of hydrotest waters are not expected to contain levels of hydrocarbons or other toxic materials sufficient to result in adverse impacts. Effects of Hydrostatic Testing - Potential Failure of Pipe Hydrostatic testing of the existing Longhorn Pipeline between Houston and Crane is expected to result in a number of failures. Some of those failures, and actions taken to locate failure locations, could have effects upon both species and habitat. However, the calculation of the effects of such failures is difficult to estimate since the location of any such failure cannot be predicted and since the volume of test water that may be discharged is difficult to predict. Calculations by a pipeline integrity consulting firm estimate that approximately 18 to 20 failures will occur at the high test pressures planned. Since the most likely failure location is at pipeline flaws, the location of the expected failure cannot be predicted with any accuracy; at most, a minimal number of recently replaced sections of pipe may be eliminated from consideration. Therefore, the expected failures will approximate a random distribution over the Houston to Crane segment. A finite number of failures could be assigned to the habitat areas based upon the proportional share of pipeline mileage in habitat areas; however, that methodology would probably result in either overestimation or underestimation of the number of failures in habitat areas. In addition, the potential volume of test water discharged in the event of failure is difficult to estimate. First, if a failure results in rapid depressurization of the test segment, the volume of test water discharged will be the sum of (a) water expelled as the pipe returns to atmospheric pressure, which depends upon test pressure and test segment length, and (b) drainage from any adjacent segments at elevations higher than the failure location. Second, if a failure results in a slow depressurization of the test segment, it may be readily identifiable and quickly contained. If a slow leak is difficult to locate, one or more investigative excavations could be required to either search for the failure or plug a portion of the segment so that lengths of pipe may be eliminated from the search. Therefore, given that failure location and size cannot be predicted, potential effects on species and/or habitat cannot be reasonably estimated in advance. Another factor that makes such estimates difficult is the existence of residual amounts of diesel fuel that remain in the pipeline from cleaning during 1998. As the hydrostatic testing proceeds from east to west, the test water may be expected to reflect relatively higher levels of hydrocarbon content. Those concentrations cannot be predicted but are not expected to contain levels of hydrocarbons or other toxic materials sufficient to result in adverse impacts. Spill response equipment such as booms, absorbent pads, and other containment and cleanup equipment will be maintained in the vicinity of the test sites during the procedure. In summary, the locations of hydrostatic test failures cannot be predicted, the volume of test water discharged can not be calculated, and the number of investigative excavations cannot be predicted. In the event of a pipeline failure in or near habitat for listed species, incidental take may occur. The level of potential take is impossible to predict. Basically, take from failure of the pipeline during this testing would require reinitiation of this consultation. 34 <<>> Cumulative Effects Cumulative effects of future State, local or private actions that are reasonably certain to occur in the action area are considered in this biological opinion. Future Federal actions that are unrelated to the proposed action are not considered in this section because they require separate consultation pursuant to Section 7 of the Act. Because of the linear nature of the pipeline and the long history of clearing (about 50 years) the Service anticipates no cumulative effects from the activities proposed. The majority of the counties involved in the project are predominantly rural, and imminent future actions identified that may affect each of the listed species are either not considered to be of sufficient magnitude to result in jeopardy to the species or will include minimization necessary to avoid jeopardy. Conclusion The Service in developing its biological opinion has thoroughly reviewed the proposed action submitted by EPA, OPS, and Longhorn Pipeline Partners. This Biological Opinion is predicated on the compliance and the full and complete adherence by EPA, OPS and the Longhorn Pipeline Partners to the Description of the Proposed Action provided earlier in this document. In consideration of the above and after reviewing the current status of the potentially affected species, the environmental baseline for the action area, the effects of the proposed action including direct, and indirect and cumulative effects, it is the Service's biological opinion that the action as proposed by EPA, OPS, and the Longhorn Pipeline Partners for Longhorn Pipeline Project Maintenance Activities and Minor Construction from Houston to Crane, Texas, is not likely to jeopardize the continued existence of any Federally listed species. In addition the proposed action is not likely to destroy or adversely modify the designated critical habitat of the Houston toad. In addition, the Service concurs with the not likely to adversely affect determination, made by EPA and OPS for areas that are not habitat for threatened or endangered species. INCIDENTAL TAKE STATEMENT Section 9 of the ESA and Federal regulations pursuant to section 4(d) of the ESA prohibit the take of endangered and threatened species, respectively, without special exemption. Take is defined as to harass, harm, pursue, hunt, shoot, wound, kill, trap, capture or collect, or to attempt to engage in any such conduct. Harm is further defined by the Service to include significant habitat modification or degradation that results in death or injury to listed species by significantly impairing essential behavioral patterns, including breeding, feeding, or sheltering. Harass is defined by the Service as intentional or negligent actions that create the likelihood of injury to listed species to such an extent as to significantly disrupt normal behavior patterns which include, but are not limited to, breeding, feeding or sheltering. Incidental take is defined as take that is incidental to, and not the purpose of, the carrying out of an otherwise lawful activity. Under the terms of section 7(b)(4) and section 7(o)(2), taking that is incidental to and not intended as part of the agency action is not considered to be prohibited taking under the Act provided that such taking is in compliance with the terms and conditions of this Incidental Take Statement. The term take in the Endangered Species Act is not defined for plants and therefore plants are not included in the incidental take statement of biological opinions. However, Federal agencies 35 <<>> are required under section 7 (a)(1) of the Act to consult with the Service on actions that may affect listed plants, and to insure that any agency action is not likely to jeopardize the continued existence of the species or result in the destruction or adverse modification of critical habitat. Further, section 7(a)(2) of the Act applies equally to plants and animals. Amount or Extent of Take The Service anticipates that the level of incidental take from the proposed activities will be low. The seasonal restrictions placed on these activities, and alternative techniques planned for sensitive habitat areas (land conservation funding), and other conservation actions planned should avoid and minimize the potential for incidental take to the maximum extent practicable. The amount or extent of incidental take resulting from the proposed action on listed species is difficult to assess since comprehensive survey information is not available for all species that could be affected. The approach taken for most of the potentially affected species is to assume that they are present in the identified potential habitat areas and that take will occur. The proposed action uses the potential habitat to define the possible extent of any take that could occur. Based on the proposed action, the Service will assume incidental take for the entire width of the pipeline ROW (and edge effects from the ROW) as it traverses broad areas of potential habitat for listed species. Take is calculated based on the extent of suitable habitat within the established ROW (50-foot width x length) and within temporary work spaces that exceed the ROW (variable by location). The following summarizes by species the amount of potentially suitable habitat that will be impacted by the proposed action (Table Three). Table Three. Potential Suitable Habitat Species Area Impacted Texas prairie dawn 61.3 acres Navasota ladies'- tresses 5.2 acres Houston toad 20.6 acres Golden-cheeked warbler 116.8 acres Black-capped vireo 41.7 acres Tobusch fishhook cactus 213.2 acres Effect of Take In the accompanying biological opinion, the Service determined that the level of anticipated take identified is not likely to result in jeopardy to the species or destruction or adverse modification of critical habitat. Implementation of this project should result in net benefit to the species listed above in Table Two, to the extent that conservation benefits planned exceed expected impacts to the species. Reasonable and Prudent Measures The Service believes the following reasonable and prudent measures are necessary and appropriate to minimize take associated with the proposed Phase One - Longhorn Pipeline Project Maintenance Activities and Minor Construction Houston to Crane, Texas. 36 <<>> The measures described below are non-discretionary, and must be undertaken by EPA and/or OPS so that they become binding conditions on the Longhorn Pipeline Partners, as appropriate, for the exemption in section 7(o)(2) to apply. EPA and OPS have a continuing duty to regulate the activities addressed by this incidental take statement. If EPA or OPS, (1) fails to assume and implement the terms and conditions or (2) fails to require the Longhorn Pipeline Partners to adhere to the terms and conditions of the incidental take statement through enforceable terms and conditions, the protective coverage of section 7(0)(2) may lapse. In order to monitor the impact of incidental take, EPA, OPS, and/or Longhorn Pipeline Partners must report the progress of the action and its impact on the species to the Service as specified in the incidental take statement (below) [50 CFR §402.14(I)(3)]. Reasonable and Prudent Measure 1: The proposed actions, as described in the above "PROJECT DESCRIPTION (Actions addressed under this Biological Opinion)" and the accompanying Biological Assessment must be followed. In areas where the Biological Assessment and the Biological Opinion are not in agreement, the Biological Opinion will be followed. The Service will be available to clarify any questions that may arise during implementation. Reasonable and Prudent Measure 2: EPA and/or OPS must ensure that the activities are carried out by the Longhorn Pipeline Partners as they are proposed. Monitoring of these activities must be accomplished to ensure compliance. The level of monitoring must include onsite review of activities with a relatively intense focus on the first year when construction will occur. EPA and/or OPS must submit a monitoring plan detailing the level of monitoring that will occur. Service concurrence with the level and type of monitoring proposed is a requirement. Terms and Conditions In order to be exempt from the prohibitions of section 9 of the Act, EPA and OPS must comply with the following terms and conditions, which implement the reasonable and prudent measures conditions are non-discretionary. described above and outline required reporting/monitoring requirements. These terms and Terms and Conditions to Implement Reasonable and Prudent Measure 1 This term and condition is effective immediately. Terms and Conditions to Implement Reasonable and Prudent Measure 2 This term and condition is effective immediately. Given that the proposed work is scheduled to begin with the issuance of this opinion, EPA and/or OPS must submit a monitoring plan detailing the level of monitoring within two weeks of the receipt of the Biological Opinion. On site review of the projects should begin before March 1, 2000. Conservation Recommendations Section 7(a)(1) of the Act directs Federal agencies to utilize their authorities to further the purposes of the Act by carrying out conservation programs for the benefit of endangered and threatened species. Conservation recommendations are discretionary agency activities to 37 <<>> minimize or avoid adverse effects of a proposed action on listed species or critical habitat, to help implement recovery plans, or to develop information. It is recommended that in areas where surveys are completed ahead of destructive project actions, any plants in the action area be protected and avoided wherever possible. Where Tobusch fishook cactus plants are found that cannot be avoided and will be destroyed by the project activities, the Service recommends these plants be removed and transferred to the conservation collection of the Desert Botanical Garden in Phoenix, Arizona, where they can be cultivated for seed production and cryopreservation for use in future restoration work for the species. Contact Desert Botanical Garden prior to removals to arrange transfer and obtain any special instruction. In general, plants should be removed by digging at least a one foot diameter area around the plant, carefully rinsing to bare root, thoroughly drying the entire subsoil area and any wounds before transport (by placing on newspapers in a cool shaded location) and then (when dry) carefully packing in newspaper in a box, and then packing in a second box surrounded by protective packing materials before express shipping. • It is recommended that maintenance practices be implemented that will help minimize impacts to the vegetation community, fragmentation of Houston toad habitat, and edge effects. To facilitate dispersal for Houston toads that cross the ROW, Longhorn Pipeline has agreed to maintain the ROW in native bunchgrasses rather than sod-forming grasses, which inhibit movement. The height of native bunchgrass communities shall be maintained several inches (i.e., ≥ 4 inches) above ground level to provide adequate cover for toads. • Avoid using herbicides and pesticides in Houston toad areas. If herbicide use cannot be avoided, direct application techniques shall be used to minimize amount of application and areas of the habitat impacted. Avoiding the use of herbicides and pesticides is particularly critical near any wetland areas and during the breeding season (January through June). Avoiding the use of chemicals in habitat minimizes the risk of harm through toxic effects to the toads and tadpoles themselves or their food base. • To protect the Houston toad from predation by red imported fire ants (Solenopsis invicta), periodically inspect the ROW for fire ant activity. Inspections should occur when fire ants are most active. If fire ants are found, individually treat fire ant mounds using commercial fire ant bait in accordance with label instructions. Bait should be placed only near fire ant mounds and not near the mounds of native ant species. To avoid affects on non-target species, apply bait when ants are actively foraging and prevent accumulations of excess bait. Reinitiation Notice This concludes formal consultation for Phase One - Longhorn Pipeline Project Maintenance Activities and Minor Construction Houston to Crane, Texas. As provided in 50 CFR $402.16, 38 <<>> reinitiation of formal consultation is required where discretionary Federal agency involvement or control over the action has been retained (or is authorized by law) and if: (1) the amount or extent of incidental take is exceeded; (2) new information reveals effects of the agency action that may affect listed species or critical habitat in a manner or to an extent not considered in this opinion; (3) the agency action is subsequently modified in a manner that causes an effect to the listed species or critical habitat not considered in this opinion; or (4) a new species is listed or critical habitat designated that may be affected by the action. In instances where the amount or extent of incidental take is exceeded, any operations causing such take must cease pending reinitiation. In closing we wish to thank EPA, OPS, and the Longhorn Pipeline Partners for the cooperation and patience shown during this consultation. Thank you for your interest in protecting our federal trust resources. If you have any questions, please contact Matthew Lechner (512) 490- 0057, extension 234. Sincerely, /s/ William M. Seawell (for) David C. Frederick Supervisor 39 <<>> Appendix One Confidential Settlement Agreement UNITED STATES DISTRICT COURT WESTERN DISTRICT OF TEXAS AUSTIN DIVISION Ethel Spiller, et al., Plaintiffs versus Robert M. Walker, et al. Defendants CIVIL NO. A-98-CA-255-SS Settlement Stipulation 40 <<>> Appendix Three Literature Cited Arft, A. and T. Ranker. 1995. Demography of the rare orchid Spiranthes diluvialis: implications for conservation. Program and Abstracts, 9*h annual meeting of the Society for Conservation Biology, June 7-11, Fort Collins, Colorado. Abstract, notes from presentation attended. U.S. Fish and Wildlife Service, Austin, Texas. Brune, G. 1981. Springs of Texas: Volume 1. Branch-Smith Inc. Fort Worth, Texas. Chippindale, P., D. Hillis, and A. Price. 1990. Central Texas Salamander Studies. Section 6 report submitted by Texas Parks and Wildlife Department to U.S. Fish and Wildlife Service. Federal Aid Project No: E-1-2, Job No. 3.4. Austin, Texas. Horizon Environmental Services, Inc. 1991. Threatened or Endangered Species Investigations - EZ Pipeline Project. Horizon Environmental Service, Inc. Austin, Texas. Poole, J.M,. and D.H. Riskind. 1987. Endangered, Threatened, or Protected Native Plants of Texas. Austin, Texas: Texas Parks and Wildlife Department, State of Texas. U.S. Fish and Wildlife Service (USFWS). 1984a. Houston toad recovery plan. U.S. Fish and Wildlife Service. Albuquerque, New Mexico. 73pp. U.S. Fish and Wildlife Service (USFWS). 1984b. Navasota ladies'-tresses recovery plan. U.S. Fish and Wildlife Service. Albuquerque, New Mexico. U.S. Fish and Wildlife Service (USFWS). 1994a. Minimum Procedures for Determining the Presence/Absence of Golden-Checked Warblers and Black-Capped Vireos. March 7, 1994 Memorandum, Austin Field Office. U.S. Fish and Wildlife Service (USFWS). 1994b. Population and habitat viability assessment: Houston toad (Bufo houstonensis). Workshop conducted by IUCN/SSC Conservation Breeding Specialist Group in partial fulfillment of USFWS contract #94-172. Apple Valley, Minnesota. U.S. Fish and Wildlife Service (USFWS). 1995. Threatened and endangered species of Texas (revised). U.S. Fish and Wildlife Service. Austin, Texas. U.S. Fish and Wildlife Service (USFWS). 1995. Threatened and Endangered Species of Texas. Austin, Texas: US Fish and Wildlife Service, Revised June, 1995. U.S. Fish and Wildlife Service (USFWS). Houston Toad Recovery Team. 1999. March 31-April 1, 1999 Meeting Minutes. U.S. Fish and Wildlife Service, Austin, Texas. Texas Parks and Wildlife. 1993. Endangered species information for Hilltop Lakes. Texas Parks and Wildlife Resource Protection Division, Austin, Texas. Wilson, H. 1993. Contractors partial draft of recovery plan revision for Navasota ladies'-tresses (unfinished contract). U.S. Fish and Wildlife Service, Austin, Texas. 41 <<>> Phase Il Biological Assessment April 10, 2000 Addendum September 14, 2000 42 <<>> Horizon Job No. 990144 PHASE TWO BIOLOGICAL ASSESSMENT OPERATION, LONG-TERM MAINTENANCE, AND EMERGENCY RESPONSE, LONGHORN PIPELINE PROJECT HOUSTON TO EL PASO, TEXAS PREPARED FOR: LONGHORN PARTNERS PIPELINE U.S. DEPARTMENT OF TRANSPORTATION AND U.S. ENVIRONMENTAL PROTECTION AGENCY REGION 6 PREPARED BY: HORIZON ENVIRONMENTAL SERVICES, INC. AUSTIN - BEAUMONT - HOUSTON - SHREVEPORT APRIL 10, 2000 Addendum September 14, 2000 99144ba2.v8 <<>> TABLE OF CONTENTS Section Page 1.0 INTRODUCTION 1 2.0 CONSULTATION HISTORY .4 3.0 DESCRIPTION OF THE PROPOSED ACTIONS. 7 3.1 Project Overview.... .7 3.2 Pipeline Operation 22 3.3 Long-Term Maintenance.. .22 3.4 Emergency Response..... 29 3.5 Edwards Aquifer Protections.. 43 3.6 Pipeline Maintenance Construction. 46 3.6.1 Buescher State Park 46 3.6.2 Edwards Aquifer Protections. 47 3.7 Hydrostatic Pressure Testing And Proof Testing 51 3.8 Right-of-Way Maintenance 52 3.9 Corrosion Inhibitor .. 52 4.0 AVOIDANCE AND CONSERVATION MEASURES 55 Avoidance 55 4.2 Status of the Species/Environmental Baseline 57 4.3 Effects of the Actions.... 68 4.4 Planned, But Unscheduled Construction .. 75 4.5 Future Additional, But Currently Unforseen Construction 76 4.6 Bays and Estuaries Issues. 76 4.7 Summary of Conservation Measures 77 5.0 REFERENCES ...81 99144ba2.v8 <<>> LIST OF TABLES Table Page 1 Consultation History - Phases One And Two. ..4 2 Chronology of Longhorn Pipeline Actions.. 10 3 List of Endangered Species Habitat Areas along the Longhorn Pipeline... ..12 4 Federally Listed Threatened or Endangered Species Which Occur In Counties Traversed By The Longhorn Pipeline Houston to El Paso........ .. 58 - 59 LIST OF FIGURES Figure Page 1 Location Map................ ...8 2 - 10 Areas of Potential Threatened or Endangered Species Habitat Along the Longhorn Pipeline - Houston to El Paso. .. 13 - 21 APPENDIX Phase Two Project Documentation Appendix Accompanying Document Longhorn Facility Response Plan Accompanying Document 99144ba2.v8 <<>> 1.0 INTRODUCTION This document is the Biological Assessment (BA) of the potential for effects, arising out of the activities proposed by Longhorn Partners Pipeline, L.P. (Longhorn), on federally-listed species in Texas. This BA presents data and information describing the proposed plans for the second phase of consultation for the Longhorn Pipeline Project -- Operation, Maintenance, and Response Activities, Houston to El Paso, Texas. The first phase of the consultation (Phase One), which has already been completed, related to pipeline right-of- way maintenance, clearing and marking, selected pipeline maintenance construction activities (pipe replacements and lowering), and pipeline testing (investigation of possible flaws and hydrostatic pressure testing). The Service found that Longhorn's Phase One activities were not likely to jeopardize the continued existence of any federally listed species, nor was it likely to destroy or adversely modify the designated critical habitat of the Houston toad. The Phase One BA, dated February 14, 2000, and the Phase One Biological Opinion (BO), dated February 17, 2000, are hereby incorporated into this Phase Two BA by reference (see Phase Two Project Documentation Appendix at Tabs 1 and 2). The draft Environmental Assessment (EA) of the proposed Longhorn Pipeline System and these BAs are the product of a settlement reached in the matter of Spiller et al. v. Walker et al. pending in the United States District Court in Austin, Texas (See Phase Two Project Documentation Appendix at Tab 3; the Settlement Stipulation). As part of the Court approved settlement, two agencies involved in the original litigation were required to conduct an EA including, specifically, consideration of species listed under the Endangered Species Act (ESA). The Court ordered the U.S. Environmental Protection Agency (EPA) and the U.S. Department of Transportation (DOT), to be responsible for the EA. EPA and the DOT Office of Pipeline Safety (OPS) act as Lead Agencies in the EA process. Radian International LLC (Radian) is a contract preparer of the EA and works at the direction of the Lead Agencies. The Court order provides that issuance of any finding of no significant impact (FONSI) with regard to the proposed Longhorn Pipeline project "shall be conditioned upon implementation" of measures to protect public safety and the environment (Settlement Stipulation at 6). The order also prohibits OPS from authorizing Longhorn to commence operations until Longhorn has implemented those mitigation measures upon which any FONSI is conditioned (Settlement Stipulation at 7). The order contemplates that Longhorn will apply for such ESA permits as may be required in connection with the implementation of any mitigation measures upon which a FONSI may be conditioned. (Settlement Stipulation at 7). The results of this consultation by the Lead Agencies with the Service are expected to be incorporated in the Record of Decision issued by the Lead Agencies. The terms and conditions, mitigatory measures and protections incorporated herein for the benefit of species are expected to be adopted and incorporated by Longhorn in its enforceable mitigation commitments or in its operating and maintenance manuals subject to inspection by, and enforceable by, OPS pursuant to the Pipeline Safety Act (49 U.S.C. 60101 et seq.). Although the Service and the Lead Agencies are in consultation with respect to the entire proposed Longhorn pipeline project, this consultation is being approached in two distinct, yet related phases. Service regulations allow for a staged consultation (50 CFR 402.14(k)) where the Service reviews a project and provides biological opinions on each 99144ba2.v8 1 <<>> incremental step, provided that no irreversible or irretrievable commitments of resources are made. This second phase of the consultation will be directly related to the actual operation of the pipeline, specifically the operation and maintenance of the pipeline system and the potential effects of a pipeline release and related emergency response. Like Phase One, Phase Two activities also include implementation of some mitigation measures, specifically the replacement of pipe in Buescher State Park (see Longhorn Mitigation Commitment 34 (LMC 34) of the Longhorn Mitigation Plan (LMP) dated September 1, 2000; see Phase Two Project Documentation Appendix at Tab 4) and the replacement of some 19 miles of pipe over the Edwards Aquifer recharge and contributing zones with thick-walled pipe. On its own initiative, Longhorn will lower two other sections of pipe in Buescher Park where the pipe crosses streams. Phase Two also includes (a) hydrostatic pressure testing of pipeline segments not tested pursuant to Phase One, specifically, Houston toad habitat areas and areas of potential effect to the Barton Springs Salamander, (b) treatment of the pipeline internally with corrosion inhibitor, and (c) right-of-way clearing in areas of potential effect to the Barton Springs Salamander. Since none of the Phase Two work will be undertaken by Longhorn until this consultation is complete, neither the federal agencies nor Longhorn will engage in any irreversible or irretrievable commitment of resources during the course of the consultation. The two phases have been logically separated. Phase One of the Service's review focused on those actions that were designed to make the pipeline safer. That review did not pre- judge whether or not the pipeline would be used. This second phase of the consultation will focus on whether and how the pipeline will be used. New construction of pipe between Crane and El Paso was reviewed by the Service in 1997 and resulted in a not likely to adversely affect determination (See Tab 5 of the Phase Two Project Documentation Appendix). The Service can logically conclude that operation and maintenance of the Longhorn Pipeline will not jeopardize the continued existence of any federally listed species, and that it is not likely to destroy or adversely modify the designated critical habitat of the Houston toad. This project, as designed, is not likely to adversely affect threatened or endangered species or habitat. There is little risk from operation of the pipeline. The risks that do exist arise in the unlikely event of an accidental release of product from the pipeline. response to this risk, and pursuant to the Settlement Stipulation, Longhorn will implement numerous mitigation measures designed to avoid a release entirely or reduce the magnitude and the impact of a release. Longhorn developed these mitigation measures in response to risks identified by the Lead Agencies. Mitigation measures such as pipe replacement and pipe lowering, in-line inspections, daily surveillance patrols over the Edwards Aquifer recharge zone, enhanced damage prevention and public education programs, and hydrostatic pressure testing greatly minimize the risk of an accidental release from the pipeline in the first place. These efforts minimize the risk a release will occur. In addition, Longhorn will install an enhanced leak detection system which will allow pipeline operators to rapidly detect even a very small release over the Edwards Aquifer recharge zone and portions of the contributing zone and respond quickly, thereby limiting the amount of product released into the environment. Longhorn will also fund a refugium for the Barton Springs Salamander. 99144ba2.v8 2 <<>> Taken together, the Service can conclude that these measures are sufficient to ensure operation of the pipeline will neither jeopardize the continued existence of any federally listed species, nor adversely affect their habitat, and is not likely to adversely affect threatened or endangered species or habitat along the pipeline route. This BA is based upon: (1) the information that Longhorn (as designated non-federal representative), provided as part of the informal consultation including the Draft Environmental Assessment and the Phase One BA), (2) information in the Service's office (including information provided by the public and the plaintiffs in the lawsuit relating to the Longhorn Pipeline), (3) field investigations, and (4) other sources of information. 99144ba2.v8 3 <<>> 2.0 CONSULTATION HISTORY Informal and formal consultation between the Service, Longhorn, EPA, and OPS has been Table 1: CONSULTATION HISTORY - PHASES ONE AND TWO DATE HISTORY 10 February, 1999 Meeting Between Service and Longhorn Representatives 25 February, 1999 Meeting Between Service and Longhorn Representatives 9 March, 1999 Meeting of Service and Radian (consultants writing EA for EPA and OPS) 22 March, 1999 Meeting Between Service and Longhorn Representatives 30 April, 1999 Meeting Between Service and Longhorn Representatives 11 May, 1999 Meeting Between Service and Longhorn Representatives 12 May, 1999 Meeting with the Plaintiffs to discuss the Settlement Agreement 1 June, 1999 Meeting with Barton Springs/Edwards Aquifer Conservation District 8 June, 1999 Meeting Between Service and Longhorn Representatives 11 June, 1999 Multi-Agency Field Tour of Longhorn Pipeline in and near Austin, Texas 29 June, 1999 Meeting Between Service and Longhorn Representatives 30 June, 1999 Telephone Conference Between Service and Department of Justice 19 July, 1999 Meeting Between Service and Longhorn Representatives 27 August, 1999 Meeting Between Service and Longhorn Representatives 10 September, 1999 Meeting Between Service and EPA Meeting Between Service and Longhorn Representatives 13 September, 1999 Meeting Between Service, Austin and Regional Director 27 September, 1999 Meeting between Service Austin Office and Washington Office Original Draft Biological Assessment Submitted to Service 30 September, 1999 Meeting Between Service and Longhorn Representatives 99144ba2.v8 4 <<>> Table 1: CONSULTATION HISTORY - PHASES ONE AND TWO DATE HISTORY 4 November, 1999 Meeting Between Service and Longhorn Representatives 9 November, 1999 Meeting Between Service and Longhorn Representatives 16 November, 1999 EPA and OPS Longhorn Public Meeting, Austin 22 November, 1999 Meeting Between Service and Longhorn Representatives 7 December, 1999 Meeting Between Service and Longhorn Representatives 8 December, 1999 Meeting Between Service and EPA 15 December, 1999 Meeting Between Service and Longhorn Representatives Service Issues Comments on Original Draft Biological Assessment Service Issues Response to EPA Regarding EPA's initial Request for Concurrence on a "Not Likely to Adversely Affect" Determination. 17 December, 1999 Meeting Between Service and Longhorn Representatives 6 January, 2000 Longhorn Requests Concurrence from Service for "Not Likely to Adversely Affect" Meeting Between Service and Longhorn Representatives for Maintenance and Construction Activities in Non-habitat Areas for Listed Species. 10 January, 2000 EPA and OPS Longhorn Public Meeting, Austin 11 January, 2000 Meeting Between Service, EPA and OPS 17 January, 2000 Meeting Between Service and Longhorn Representatives 18 January, 2000 Meeting Between Service and Longhorn Representative 28 January, 2000 Initial Draft First Phase Biological Assessment received for review 7 February, 2000 Meeting Between Service and Longhorn Representatives 1 February, 2000 Telephone Conference Between Service and Congressman Doggett's Staff 3 February, 2000 of consultation EPA and OPS designate Longhorn the "non-federal representative" for purposes 10 February, 2000 Received EPA Request for Formal Consultation 14 February, 2000 Received Second Draft of Phase One Biological Assessment For Review 17 February, 2000 Received Revised Final Phase One Biological Assessment 17 February, 2000 Received OPS Request for Formal Consultation 17 February, 2000 Service issued Phase One Biological Opinion 9 March, 2000 Il consultation with submission of initial draft of Phase Two Biological Assessment Meeting between Service and Longhorn Representatives to initiate informal Phase 12 April 2000 Received Revised Draft Phase I! Biological Assessment 26 April 2000 Meeting Between Service and Longhorn Representatives 99144ba2.v8 5 <<>> Table 1: CONSULTATION HISTORY - PHASES ONE AND TWO DATE HISTORY 6 June 2000 Meeting Between Service and Longhorn Representatives 23 June 2000 Meeting Between Service and Longhorn Representatives 30 June 2000 Meeting Between Service and Longhorn Representatives 21to 31 July 2000 Received supplemental information for the Phase II Biological Assessment 3 August 2000 Meeting Between Service and Longhorn Representatives 5 August 2000 Meeting Between Service and Longhorn Representatives 9 August 2000 Meeting Between Service and Longhorn Representatives 23 August 2000 Meeting Between Service and Longhorn Representatives 6 September 2000 Meeting Between Service, Lead Agency, and Longhorn Representatives 11 to 13 Sept. 2000 Received supplemental information for the Phase II Biological Assessment 99144ba2.v8 <<>> 3.0 DESCRIPTION OF THE PROPOSED ACTIONS The following is an overview of the project as proposed by Longhorn and is provided to give an overall context of the proposed project. The specific activities proposed for this Phase Two BA are detailed in the following sections. This project overview differs slightly from the project overview contained within the Phase One BA; specifically, this project overview describes four connecting pipelines as opposed to the three previously described. However, the differences implicate no change to the potential effects of the overall project upon species, given that no potential habitat areas have been identified along the planned route of the connecting pipelines. 3.1 Project Overview Due to the expanding demand for refined products in El Paso and other markets in the southwestern United States, the proposed Longhorn Pipeline will transport up to 225,000 barrels per day (bpd) of refined products to the El Paso Terminal and to the Equilon Terminal in Odessa. From these terminals, products will be distributed by truck transport in the El Paso and Odessa markets. Tanker trucks could transport refined products to Juarez in Mexico. The Longhorn Pipeline will connect to the Kinder Morgan and Chevron pipelines at El Paso, enabling shippers to transport products to Phoenix, Tucson, Albuquerque, and other southwestern markets. Market conditions and shipper requirements will determine the actual pattern of distribution of products to El Paso and to the Phoenix, Tucson, Albuquerque, and other southwestern markets. The Longhorn Pipeline System is designed for service in excess of fifty years from startup and is made up of four main pipeline segments, several stations, and one terminal, as listed below: 1. New and refurbished 20-inch diameter pipeline from Galena Park Station to Satsuma Station 2. Refurbished 18-inch diameter pipeline from Satsuma Station to Crane Station 3 New 18-inch diameter pipeline from Crane Station to El Paso Terminal 4. New lateral pipeline connections to Odessa and to other pipelines at El Paso 5. New Pump Stations: GATX, Satsuma, Cedar Valley, Kimble County, Crane, and El Paso 6. El Paso Terminal 7. Odessa Meter Station Longhorn has constructed and will operate a 723-mile refined petroleum products pipeline system from the GATX Terminal in Galena Park, Texas, to a refined petroleum products terminal at El Paso, Texas (Figure 1). The pipeline also has a 28-mile intermediate connection from a station in Crane County to a planned meter station in Odessa, Texas. The pipeline consists of a combination of 20-inch and 18-inch diameter pipe from Galena Park Station to El Paso Terminal and an 8-inch diameter pipeline from a station in Crane County to a meter station in Odessa, Texas. The pipeline's initial capacity of 72,000 bpd will be supplied by a new origin pump station at Galena Park and five new booster pump stations, Satsuma, Cedar Valley, Kimble County, Crane, and El Paso. 99144ba2.v8 7 <<>> 98S00 M rene ta 01 erie 493 0-r 01307o0/g pero bac ле vol ago покоо. 07501 кото AMARILLO eno 2820ag0 nsm 30270 Oklahoma Mexico es i-lo-ing New ron. Louisiana COULDNE T WORTH DALLA ODESSA TO COLOTINE TACO Mexico cApu KIMBLE COUNTY ON SaN/ ANTONIC REDO CHRISTI Mexico Gulf of EXPLANATION LONGHORN REFINED PRODUCTS PIPELINE LONGHORN PIPELINE PUMP STATION: RAD 39067 PUMP STATIONS N LONGHORN PIPELINE 1.05- STATE OF TEXAS NOT. TO SCALE MAP SQURCES: (htto:// www.tnns.state.tx.us/dota__oz.ntml), 1998 TEXAS NATURAL RESOURCE INFORMATION SYSTEM LONGHORN PIPELINE <<>> An 8-inch diameter, 2,500-toot lateral that originates at the terminus of the existing Odessa lateral will connect to a terminal facility in Odessa, Texas, owned by Equilon. Three 8.3-mile lateral pipelines, which originate at the El Paso Terminal, will connect with Kinder Morgan (formerly the Santa Fe Pacific pipeline) and Chevron pipelines in the El Paso area. The connection to Kinder Morgan will consist of one 8-inch diameter pipeline and one 12-inch diameter pipeline. The Chevron connection will consist of an 8-inch diameter pipeline. The purpose of the lateral pipelines is to connect into Kinder Morgan and Chevron pipelines to distribute product into the Phoenix, Tucson, and Albuquerque markets. Chevron operates an 8-inch pipeline that delivers product to the Albuquerque market; Kinder Morgan operates one 12-inch pipeline and one 8-inch pipeline serving the Tucson market. Other Kinder Morgan pipelines connect Tucson to the Phoenix market. One additional eight-inch pipeline, to be installed in the same right-of-way as the El Paso laterals, will create a return system between the El Paso Terminal and the point of the lateral pipeline connections to Kinder Morgan and Chevron. The return system will be used to displace product from within the lateral pipelines back to the El Paso Terminal. The return system will allow product of one type to be removed from a lateral pipeline, prior to initiating delivery of a different product into one of the Kinder Morgan or Chevron pipelines, thus facilitating quality control of products delivered to those pipelines. The return system will be accomplished by installation of a manifold at the point where the lateral pipelines connect to the Kinder Morgan and Chevron pipelines. After startup, Longhorn plans to periodically increase capacity to reach an ultimate capacity of 225,000 bpd. To reach this capacity, Longhorn will, in the future, build ten new booster pump stations and will refurbish or reconstruct three existing stations at the following locations: Approximate Location Station (milepost to milepost) Buckhorn MP 67.5 - MP 77.5 Warda Existing site Bastrop Existing site Orotaga MP 203.8 - MP 213.8 Eckert Existing site Llano MP 265.0 - MP 275.0 Cartman MP 334.0 - MP 344.0 Olson MP 410.0 - MP 420.0 Big Lake Approximately MP 373.4 Pecos MP 516.2 - MP 526.2 Utica MP 543.6 - MP 553.6 Cottonwood Approximately MP 576.3 Harris MP 642.6 - MP 652.6 The Longhorn project includes both new construction and refurbishment of an existing 99144ba2.v8 9 <<>> pipeline that has been converted from its former use of transporting crude oil from West Texas to the Gulf Coast area. The existing pipeline has been modified to transport refined petroleum products, with flow going from east to west. Williams Pipe Line Company (Williams) will be the contract operator of the Longhorn Pipeline System. Longhorn intends to transport multiple grades of gasoline and distillates (i.e., various grades of diesel fuel and jet tuel). The GATX to El Paso segment of the Longhorn Pipeline will function as an interstate common carrier pipeline for those product volumes that will be transported across state lines through the Longhorn Pipeline connections with the Kinder Morgan and Chevron pipelines that extend across the Texas border into New Mexico and Arizona. Product volumes moved from GATX to El Paso for delivery at El Paso will be intrastate movements. The Crane to Odessa segment of the Longhorn Pipeline is an intrastate common carrier pipeline since it transports products solely within the State of Texas. Table 2 lists a chronology of overall pipeline actions leading up to the present. Table 2 - Chronology of Longhorn Pipeline Actions 1949-1950 Exxon constructed the original 18"/20" pipeline, Crane to Baytown, to transport crude oil. 1950-1990 Operation and Periodic maintenance/refurbishment. 1990 An internal inspection (smart pig) of the 20" pipeline was performed. 1995 An internal inspection of the 18" pipeline was performed. 1995-1996 The 18" and 20" pipelines were subjected to a hydrostatic pressure test and purged with nitrogen. Oct 21, 1997 Longhorn acquired the existing pipeline from Exxon. 1s Qtr. 98 Longhorn cleaned the existing pipeline to remove crude oil from the inner walls, so to prepare the existing pipeline for use in petroleum products service. Construction of new pump stations, terminals, and new pipeline sections began. 1998/1999 New Construction completion dates (dates shown are dates of substantial completion): Galena Park Origin Station - August 1998 Satsuma Pump Station - August 1998 Cedar Valley Pump Station - July 1999 Crane Pump Station- March 1999 Kimble County Pump Station - July 1999 El Paso Terminal and Pump Station - August 1999 20" Pipeline, GATX to Tie-In to Existing 20" Pipeline, Houston - October 1998 8" Pipeline, Crane to Odessa - November 1998 18" Pipeline, Crane to El Paso - November 1998 (0.5 mile remains to be constructed to Odessa Meter Station) Odessa Meter Station - In design Equipment installation remaining at a few sites Cleaning and refurbishment of the existing pipeline 18"/20"- March to November 1998 Pipeline Laterals - In design (from El Paso terminal to tie-in point with three interstate 1999 Longhorn commenced implementation of Environmental Assessment mitigation measures, pipelines) 2000 including maintenance construction and investigation of potential pipeline flaws. Longhorn continued implementation of Environmental Assessment related pipeline mitigation testing of the Houston to Crane segment of the pipeline, investigation of potential pipeline measures, including ROW maintenance and marking, maintenance construction, hydrostatic flaws, and cathodic protection system improvements. Additional details about the pipeline system, and its operation and maintenance, are contained in Section 7.0 of the Longhorn Pipeline Project Description prepared in 99144ba2.v8 10 <<>> connection with the EA; a copy of the Project Description is provided in the accompanying Phase Two Project Documentation Appendix at Tab 6. For purposes of this Phase Two BA, Longhorn has identified the areas along the pipeline where operating and maintenance activities "may affect" species and habitat. Areas of potential effect include areas of potential species habitat along the pipeline route. Those areas are identified in two documents: (a) Table 3, which lists pipeline stationing numbers for potential habitat areas along the course of the pipeline; and (b) Figures 2 through 10 which graphically depict those same potential habitat areas. This BA addresses those portions of the overall project that were not specifically identified in the Phase One BA. Those items include pipeline operation, long-term maintenance, planned additional construction and future unforeseen construction, potential pipeline release and related emergency response, construction on the Edwards Aquifer recharge zone and at Buescher State Park, hydrostatic pressure testing of approximately 60 miles of pipeline that was not tested pursuant to the Phase One BA, internal treatment of the pipeline with corrosion inhibitor, and right-of-way clearing over the Edwards Aquifer recharge zone. Details of general construction procedures and environmental protection guidelines for implementation of maintenance construction and pipeline testing activities are contained in the Phase One BA and are not repeated herein. Specific construction procedures and environmental protection guidelines for the construction sites at Buescher State Park (Houston toad habitat) and the Edwards Aquifer recharge zone are provided below. Additional procedures and guidelines, as referenced in the following, are contained in various parts of the Phase Two Project Documentation Appendix. The EA assigned tier rankings to individual segments of the entire pipeline that identify environmentally sensitive areas along the pipeline route. "Areas were identified as sensitive based upon proximity and density of population, ground water (with an emphasis on drinking water supplies), surface water, presence of threatened and endangered species habitats, and proximity to recreational areas." See Draft Longhorn EA at Section 9.2.3. Sensitive areas were divided into two categories, Tier | (sensitive) and Tier I!! (hypersensitive); areas not designated as Tier II or Tier III are designated as Tier I. A description of the methodology employed by the Lead Agencies to designate such sensitive and hypersensitive areas is set forth in Appendix 9C of the EA, along with maps of those areas. This Phase Two BA refers to such sensitive and hypersensitive areas. 99144ba2.v8 11 <<>> Horizon ENVIRONMENTAL SERVICES, INC. Table 3: List of Endangered Species Habitat Areas Along The Longhorn Pipeline Houston to El Paso Begin Station 2310+88 2013+44 End Station 2411+20 2279+20 County Waller Harris Harris Texas Prairie Dawn Species 2684+00 4662+00 2831+84 Texas Prairie Dawn 5936+48 5095+20 4782+00 Fayette Austin Texas Prairie Dawn 5128+64 Navasota Ladies-Tresses Navasota Ladies-Tresses - Houston Toad 6723+20 6600+00 6638+72 5948+80 Bastrop Fayette 9152+00 9011+20 9152+00 6864+00 Bastrop Houston Toad Travis/Hays Travis EA Recharge Zone Houston Toad 9724+00 9657+12 9674+72 9961+60 Hays Hays Golden-Cheeked Warbler EA Contributing Zone 9850+72 9762+72 10164+00 9945+76 10036+40 9926+40 Hays Golden-Cheeked Warbler Hays/Blanco. Hays Golden-Cheeked Warbler 10266+08 10461+44 10199+20 Golden-Cheeked Warbler Blanco Golden-Cheeked Warbler 11008+80 11080+96 11036+96 Blanco Golden-Cheeked Warbler Golden-Cheeked Warbler 11691÷68 11295+68 11441+76 11105+60 Blanco: Blanco Golden-Cheeked Warbler Black-Capped Vireo 12114+08 11791+28 11751+52 12149+28 11821+92 Gillespie Gillespie Golden-Cheeked Warbler Golden-Cheeked Warbler 12513+60 12633÷28 12596+32 12606+88 Gillespie Gillespie Golden-Cheeked Warbler 12631+52 Gillespie Golden-Cheeked Warbier Black-Capped Vireo 12921+92 12728+32 13043+36 13110+24 12953+60 Gillespie Mason Mason Golden-Cheeked Warbler Black-Capped Vireo 13203+52 13381+28 13277+44 13305+60 13217÷60 Mason Golden-Cheeked Warbler Golden-Cheeked Warbler 13513+28 13437+60 Mason Mason Black-Capped Vireo Black-Capped Vireo 15153+60 14476+00 16329+28 13578+40 Mason Kimble Tobusch Fishhook Cactus Black-Capped Vireo 15234+56 Kimble Black-Capped Vireo 4/5/00 11 29 PM indengered species hatreat ist RAD 3907 <<>> Louisiana FIGURE 2 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT SHEET LOCATION MAP LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT LONGHORN PIPELINE FIGURE 3 HOUSTON HARRIS FIGURE 4 AUSTIN FIGURE 6 FAYETTE FIGURE 5 RAVIS AUSTIN BASTROP HAYS FIGURE 8 LLANO 3 BLANCO GILLESPIE MASON FIGURE 7 MENARD KIMBLE FIGURE 9 SCHLEICHER FIGURE 1ó NOT TO SCALE RF AGAN! CROCKETT LONGHORN REFINED PRODUCTS APPROXIMATE CITY LOCATIONS FOR AS SUCE IN ATON (10/97 state.tx.ua/dato._oz.html), 1998 Mexico UPTON PIPELINE REFERENCE ODESSA CRANE CRANE EXPLANATION CRANE SOURCES: RAD 39072 <<>> FIGURE 3 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE TEXAS PRAIRIE DAWN-FLOWER HARRIS EXAS PRAIRIE DAWN-FLOWEI Hmenarys ferono VAVASOTA LADIES -TRESSES Saronthes ports" EDWARDS RECHARGE ZONE CONTRIBUTING ZONE On DAT PIPELINE • COUNTY BOUNDARY - HIGHWAY OR MAJOR ROADS CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE RAILWAYS BRIDGES CEMETERY - LLP-2546 MAINTENANCE CONSTRUCTION LOCATION TEXAS PRAIRIE DAWN-FLOWER WALLER EXPLANATION MC. SITE MMESTIOMON (RUNE 1999) =: MILES PINE iSLAND 5 PEAS TOTA TREAD LURE DE: MATE PANTS OF NAVILLE 359 2 RESOURCES TORTOR T 579/9 2 HIS TEN MOO BUT SINGE (197D, OF TOUS 5. HORIZON ENMRONMENTAL SERVICES. * SURCES <<>> ~ un HOUSTON TOAD I (POTENTIAL HABITAT) AUSTIN, FIGURE 4 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELIN WASHINGTON ~ NAVASOTA LADIES-TRESSES TOMS PRAT DON-TOWER AMONTA PIES -TRESSES EDWARDS RECHARGE ZONE CONTRIBUTING ZONE OLDENBURE CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —12P-2516 MUCITONMCE CONSTRUCTION EXPLANATION RAD 39074 MC. SITE DMESTIGITOM (UNE 1990) NAVASOTA LADIES-TRESSES FAYETTE + ROTECTED MATHE PLANTS OF VILES 00 5 50 0/9/90 2 TO TO NO BON SONE TIES OF TOUS. OURCES NO SOURCE <<>> Hono FIGURE 5 THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE RTLEY. HOUSTON TO CRANE SEGMENT COUNTIES OF: TEXAS LONGHORN PIPELINE HOUSTON O HoL ESOTE AREAS OF POTENTIAL FEDERALLY-LISTED COLORADO HOUSTON TOAD (POTENTIAL HABITAT) REPLACEMENT. PIPE HOUSTON TO ALSTOM HOUSTON TOAD Countaco ChO OMELER AANO AAD VREO TORsto coti PoK aCTUS MAISOTA S PONt-TRESSES EDWARDS RECHARGE ZONE CONTRIBUTING ZONE LE DESIGNATED CRITICAL HABITA — COUNTY BOUNDARY → J ACHMAY OR ANOR RONOS CITY STREETS RIVERS AND STREAMS NTERMTTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE BASTROP ROADS RAILWAYS BRIDGES CEMETERY - LLP-2516 MAINTENANCE CONSTRUCTION LOCATION EXPLANATION WATTERSON OCKNE & HORIZON DIMRONMDYTAL SERMCES, INC, SITTE IMMESTIGMOM (RUNE 1999) 2. TeSORCES TORSTON S13T3 (3/87 2 TIS FSH MOO DUF SONOS 19ES, OF TOUS. S. PON TEDA PASSED MATE DER ME PRATS. OF <<>> "ZONE'T UKAWINU 990144-A29 NUMBER FIGURE 6 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE EDWARDS RECHARCE KŁVISED BY 3/8/00 HAYS DKAr 1 TRAVIS MASON POTS-TRESSES EDMARDS RECHARGE ZONE CONTRIBUTING ZONE CONTRIBUTING ZONE ORIPPING GOLDEN-CHEEKED WARBLER — COUNTY BOUNDARY 332 HIGHMAY OR MAVOR ROADS CRY STREETS RIVERS AND STREAMS INTERMITTENT STREANS COMMUNITY BOUNDARIES LONGHORN PIPELINE RAILWAYS BRIDGES CEMETERY —11P-2516 MAATRANCE CONSTRUCTON EXPLANATION RAD 39076 DOES OF TOUS: CE BE MATE PLAITS OF ACHMENTAL SERMCES, NC. STE BMESTIEATION (INE 1990) MILES 5763/9/94 Do Not Scole This Drawing BLANÇO <<>> AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE BLACK-CAPPED VIREO BLANCO MAMOTA POTS TRESSES EDMARDS RECHARGE ZONE CONTRIBUTING ZONE → CACHTY OR MANOR RONOS — COUNTY BOUNDARY CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —LLP-2516 MUNTIONICE COMSTRUCTION cORO EXPLANATION GOLDEN-CHEEKED WARBLER man 20n77 PIPELINE MILES ÇILEŚPIE DA SON (TO), OF TONS LLANO MPSOURCES 5 POET TOE <<>> ABAPPLE PIPELINE LLANÓ FIGURE 8 THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE | GOLDEN-CHEEKED WARBLER > I BLACK-CAPPED VREO HOUSTON TOND - DESIGNATED AREAS OF POTENTIAL FEDERALLY-LISTED con HILLTOR 7 GILLESPIE HABITA Buto houstone) ADO CARDO VARCO EDMARDS RECHARGE ZONE CONTRIBUTING ZONE 2242 GOLDEN-CHEEKED WARBLER COUNTY BOUNDARY CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY -IP-2516 LOCATONCE CONSTRUCTION EXPLANATION BLACK-CAPPED VIREO. RAD 39078 MASON 1.5 MILES a HORIZOM DIMRONMENTAL SERMICES, MC, SITE BESTOMOM (LUME 1990) 2 TAS TEN MONO BIA SINCE TOD, OF TOAS PIPELINE DO SOURCES. <<>> rook -GILLESPIE BLACK-CAPPED VIREO 88 FIGURE 9 THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE PIPELINE HOUSTON TOAD - DESIGNATED AREAS OF POTENTIAL FEDERALLY -LISTED MASON HABITAT Buto houstonerais) GOLDEN-CHEEKED WARBLER (Dendracio chrysoporio) Testroots tok carys JAVASOTA LADIES-TRESSES (arranthes port) EDWARDS RECHARGE ZONE CONTRIBUTING ZONE MOUNTAN COUNTY BOUNDARY → Je HIGHMAY OR MUOR RONDS CITY STREETS RIVERS AND STREAMS NTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY — 11-2516 MAUATINANCE CONSTRUCTION EXPLANATION KIMBLE #/** RAn LONDON cook TOBUSCH FISHHOOK CACTUS 3480 YATES & HORIZON EMIRONMENTAL SERVICES, MC, SITE IMESTIGATIOM (SUME 1999) TEACUP ST PASSED OUR UST MONE PLANTS OF 2. THE AN AND DIA SOME TODD OF TOUS. MENARD 377 <<>> NUMOLN - BLACK-CAPPED VIREO CÁCTUS LOCATION FIGURE 10 THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE PIPELINE HOUSTON TO DEED AREAS OF POTENTIAL FEDERALLY-LISTED DI 310/00 KIMBLE TOAD - POTENTIAL TRA PRAN I DONY FOWER SOOTA POES-TESSES EDWARDS RECHARGE ZONE TOBUSCH FISHHOOK CACTUS CONTRIBUTING ZONE / Pook MENARD → CONNY OR MANOR ROADS • COUNTY BOUNDARY CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —11P-2516 MANTEOANCE CONSTRUCTION EXPLANATION RAD 39080 1674 SITE MMESTOKTON (RUME 1990) MILES PIPELINE I SON (1092, OF TOUS SUTTON 2 TrOot COUNTY SCHLEICHER SOURCES: <<>> 3.2 Pipeline Operation Operation of the Longhorn Pipeline essentially involves the pumping of refined petroleum products through the pipeline to terminals at El Paso and Odessa, where the products are stored in above-ground breakout tanks. From either terminal, the products will be loaded into tank trucks for transport to distribution facilities (such as gas stations and fleet servicing facilities). In addition, at the El Paso Terminal the products may be re-introduced into the connecting pipelines, and then to interstate pipelines operated by Kinder Morgan and Chevron, for transport to southwestern markets. The process of pumping refined products involves the following steps. First, products from bulk storage tanks at the GATX terminal in Galena Park are introduced in batches to the pipeline at the Longhorn GATX pump station. As the products proceed through the pipeline, booster pump stations continue to move the product stream; those booster stations include Satsuma Station in northwest Houston, Cedar Valley Station in Hays County, Kimble County Station in Kimble County, and Crane Station in Crane County. Product destined for Odessa is stored in above-ground breakout tanks prior to re- introduction to the 8-inch pipeline between Crane and Odessa. The pipeline system is operated and controlled remotely from the Williams control center in Tulsa, Oklahoma, using the supervisory control and data acquisition (SCADA) system. The SCADA system allows the controller to start and stop pumps, open and close valves, and monitor the functions of the system components. Pump station and valve site operations are managed by programmable logic controllers that interpret and execute commands from the system controller. A multitude of sensors installed in the pipeline and its equipment provide data to the controller and the automated leak detection system. Primary communications are conducted by satellite, with backup provided by land line systems. Section 7.0 of the Longhorn Pipeline Project Description provides additional detail about system operation; see Phase Two Project Documentation Appendix at Tab 6. 3.3 Long-Term Maintenance Maintenance of the Longhorn Pipeline requires activities directed to specific components of the system. For example, pumps and valves receive inspections and maintenance such as lubrication; above-ground tanks receive inspections and maintenance; the right-of-way (ROW) is mowed periodically, and ROW marker signs are erected and replaced as necessary (see Phase One BA); and the pipe is periodically subjected to thorough inspection and analysis that may dictate a variety of maintenance approaches. Additionally, corrosion inhibitor is regularly injected into the product stream to prevent internal corrosion. This Phase Two BA focuses on those maintenance activities that could occur within areas of habitat identified during Phase One. Since the El Paso terminal is not within potential habitat areas, terminal maintenance activities are not treated in this BA. Since Kimble County Station is within a habitat area (Tobusch Fishhook Cactus) and Cedar Valley Station is in an area of potential effect to the Barton Spring Salamander, station maintenance descriptions will focus on activities conducted at those stations. Valve Maintenance 99144ba2.v8 22 <<>> Valve maintenance involves periodic inspections (twice per year, not to exceed 7 ½ months between inspections, per 49 C.F.R. 195.420(a)) to ensure that the valve is not leaking and to confirm that the valve is operable. Leak and overall condition inspection is visual, as described | in the Williams Operating and Maintenance Manuals, Maintenance and Calibration section, Valve Maintenance and Calibration (Phase Two Project Documentation Appendix at Tab 7). If a leak is identified, corrective action is taken to stop the leak and perform cleanup of any product released. All lubricants are managed to prevent any release to the environment; specific procedures are identified in the Williams System of Manuals, Operating Manual, Section 12 (Phase Two Project Documentation Appendix at Tab 7). Pipeline Cleaning Pipeline cleaning is conducted approximately twice per year to remove deposits from the inner walls of the pipe. Pipe cleaning involves the introduction of a spherical or cylindrical scraper (also known as a scraper pig) into the pipeline at a pump station; the scraper travels within the product stream and is removed at a downstream station, along with any debris collected along the way. Launching and receipt of the scrapers is accomplished by way of scraper launchers and scraper receivers (traps, also known as strainers) that are installed at the pump stations. Any debris removed from the pipeline is contained in drums, and drip pans are employed to prevent release to the environment; disposal of the material is conducted in accordance with applicable laws and regulations. Pump Station Maintenance Pump station maintenance protocols depend upon the equipment located at each individual station; however, only two similarly equipped stations lie within habitat or in an area of potential effect to species. Those are Kimble County station which is located in Tobusch Fishhook Cactus habitat in Kimble County and Cedar Valley Station which is located in the Edwards Aquifer contributing zone. Each of those stations contains minimal equipment, the major components of which are pumps and electric motors, scraper launcher/traps, above-ground station piping (to bypass a pump or the station as a whole), intake and outflow (suction and discharge) remote-controlled motor operated block valves, and a station control room. No tanks are located at those two stations. Maintenance of the pump station equipment follows generally the same procedures outlined above for valve maintenance, and below for painting of above-ground components. Pumps require inspection and periodic calibration. Calibration requires that the pump cases be opened for measurement of component tolerances. To do so, the pump is isolated from the pressurized pipeline system, and the case is opened; product remaining within the case is collected in a sump system for re-injection to the product stream. The sump system is sealed and cathodically protected to prevent releases to the subsurface. Drain pans are used if product cannot be drained to the sump; the drain pans are emptied to the sump system for re-injection. Any debris removed from the pump case, along with wipe rags, sorbent pads, and other disposable materials, are collected in a closed top containment drum and stored on a concrete containment skid. The waste materials are classified and then disposed of at an approved disposal facility. 99144ba2.v8 23 <<>> Pipe cleaning debris (see foregoing section) is collected in strainers located at each pump station. The strainers are located upon a concrete skid that contains any liquid from the strainer and drains to the station sump system. Drain pans are used to contain any liquid that will not drain directly to the sump system. Debris removed from the strainer is collected in closed top containment drums and stored on a concrete containment skid. The waste materials are classified and then disposed of at an approved disposal facility. Painting Above-Ground Components Above-ground pipeline components must be protected with coatings (Longhorn uses paint) to prevent atmospheric corrosion (49 C.F.R. § 195.416(i)). Above-ground facilities include pump equipment, valves, meter facilities, and the like. Maintenance of the coatings requires periodic painting, typically on a 5 to 10 year cycle. Any waste materials generated during painting are managed to prevent release to the environment. See the Williams System of Manuals, Operating Manual, Section 12 and the Longhorn Environmental Protection Plan (Phase Two Project Documentation Appendix at Tabs 7 and 8, respectively). Pipe Integrity Maintenance - Introduction Pipe integrity maintenance activities result from inspections and analyses that identify potential threats to pipe integrity; maintenance may then occur to reduce the risk associated with a particular threat. In-Line Inspection In-line inspection is the process of examining the pipe for flaws, corrosion anomalies, dents, cracks, and other flaws using sophisticated electronic inspection devices known as The technology applied is known as high resolution magnetic flux leakage (MFL) and transverse field MFL, and geometry and ultrasonic inspections are performed as well. Smart pigs identify anomalies and record the locations. The smart pig data is then processed and analyzed, both manually and by computer, to determine whether or not the identified anomalies represent pipe flaws that require corrective action. Next, the anomalies are graded and prioritized for inspection; upon inspection, repairs are made, if necessary, to offset the potential adverse effect of the specific flaw. Actions will range from re-coating of a location not requiring repair, to replacement of the flawed pipe with a cylinder of new pipe; typically minor repair such as application of a protective sleeve is all that is necessary. Maintenance construction to investigate and repair flaws identified by the in-line inspection will be conducted in accordance with the procedures set out in the Phase One BA An in-line inspection may produce data that indicates an immediate threat to pipeline integrity, prompting an immediate inspection by excavating the pipe. If an actual threat exists, a repair is made, and otherwise the pipe is coated and buried. In either event, the protection of human health and safety and of the environment is accomplished while efforts are undertaken to avoid all potential adverse effects. See LMP at Sec. 3.5.2. Smart pigs are introduced and extracted from the operating pipeline through the scraper launcher/trap at each pump station; however, some pipeline segments between pump 99144ba2.v8 24 <<>> stations are long enough that the smart pig cannot complete the entire run. In such cases, a temporary launcher/trap assembly is installed on the pipeline to allow removal of the smart pig so that data may be downloaded, batteries recharged, and the smart pig re- launched. Construction to install and remove the temporary launcher/trap assembly is similar to construction to install a hydrostatic pressure test header as described in the Phase One BA. Electronic tracking devices that monitor and record smart pig travel are set on top of the ground during the tests. The initial in-line inspections to be performed pursuant to Longhorn Mitigation Commitment 11 shall consist of a high resolution MFL inspection within three (3) months of system startup. The timing of subsequent in-line inspections of all types will be determined by the Longhorn Pipeline System Integrity Plan and associated Operational Reliability Assessment processes.; the LMP sets maximum intervals for certain tools See Longhorn Mitigation Plan, Items 10, 11, 12, and 12A, and at Section 4.0. No more than three years shall pass without at least one in-line inspection. Temporary launcher/trap assemblies, if any are necessary, will be installed outside of areas of species habitat; thus, no effect upon species is foreseen as a result of in-line inspections. Hydrostatic Pressure Testing Integrity maintenance of the pipeline could require periodic hydrostatic pressure testing, if prompted by the Longhorn Operational Reliability Assessment (see LMP at Sec. 3.3 and 4.0). Hydrostatic pressure testing as prompted by the ORA could encompass different segments of or all of the pipeline. The Phase One BA describes in detail the processes and activities involved in hydrostatic testing, and future testing will be conducted in conformance with the Phase One BA in all respects to avoid potential adverse effects. Corrosion Inhibitor Treatment Shortly after the conclusion of this consultation, Longhorn will treat the pipeline to prevent potential internal corrosion. As a matter of course, potential internal pipe corrosion is managed through several means including the injection of corrosion inhibitors to the product stream. Due to the delays encountered during the Environmental Assessment of the Longhorn pipeline, however, product has not been transported and no corrosion inhibitor has been applied. At the urging of the Service, Longhorn elected not to inject corrosion inhibitor during the hydrostatic and proof tests commenced in February. Due to the project delays associated with the Environmental Assessment, Longhorn intends to treat the pipeline at its next opportunity to reduce the potential for internal corrosion prior to project startup. This process may be repeated from time to time as deemed necessary to maintain internal pipeline integrity; however, Longhorn's present expectation is that only one such treatment will be necessary. The treatment process involves the introduction of a water and corrosion inhibitor mixture into the pipeline at the GATX Terminal in Houston and the mixture pushed through the pipeline with injected nitrogen gas pressure. This will not constitute a pressure test or alteration of operating pressures. Maximum pressures involved in the procedure would not reach normal operating pressures. These pressures are significantly below the 1,100 to 99144ba2.v8 25 <<>> 1,500 psig pressures experienced during periodic hydrostatic testing of the pipeline. At seven intervals along the pipeline (existing valve settings), surface equipment would be needed to facilitate the handling of the water slug and pigs if the procedure is conducted independent of product flow in the line. Those points typically would be: MP 34.09 (Satsuma Station) MP 134.67 (west side of Colorado River) MP 151 (eastern Travis County) MP 182 (Cedar Valley Station) MP 227.9 (Eckert Station) MP 358.7 (west of El Dorado) MP 457.5 (Crane Station) At these points, trucks and equipment would be employed to facilitate the launching and recovery of pigs and nitrogen injection. The water mixture would be recovered into vacuum trucks at Crane Station for proper disposal. The corrosion inhibitor agent to be utilized is manufactured by Baker-Petrolite and goes by the commercial name "Magnacide 575." Material Safety Data Sheets for this product are included in the Phase Two Project Documentation Appendix. Cathodic Protection Maintenance of the cathodic protection system requires periodic inspection and testing and potential system enhancements. Testing and inspection involves pipe-to-soil surveys, close interval surveys, rectifier inspections, casing tests, and interference testing. Pipe-to-soil potential surveys require that pipe-to-soil readings, measured in volts, be taken at pre-existing test stations that are spaced along the pipeline. Survey personnel typically travel along the pipeline in a pickup truck. Pipe-to-soil surveys will occur semi-annually in EA-designated sensitive and hypersensitive areas and annually in other areas. Close interval surveys require that pipe-to-soil potential readings be taken approximately every three feet along the pipeline; thus, testing personnel walk the pipeline, typically in a group of two to five, carrying testing equipment and data loggers. Close interval surveys will be conducted annually in EA-designated hypersensitive areas and on the balance of the pipeline as dictated by the Longhorn Pipeline System Integrity Plan and associated Operational Reliability Assessment (see LMP at Sections 3 and 4, Tab 4). Rectifier inspections include monthly visual inspection and recording of voltage and amperage readings to ensure normal operation; bi-monthly inspections are required by the pipeline safety regulations (49 C.F.R. § 195.416(c)). Casing testing may involve pipe-to- soil potential readings and/or electrical current and resistance readings to determine if the 99144ba2.v8 26 <<>> casing is in direct contact or electrolytically shorted to the carrier pipe. Interterence testing involves pipe-to-soil readings and/or line current measurements to determine whether or cathodic protection system is interfering with the cathodic protection current that protects not a nearby metal object (such as a crossing or parallel pipeline) or the associated the Longhorn pipeline. Pipe-to-soil surveys, close interval surveys, casing testing, and foreign interference testing may identify sections of pipe that require additional cathodic protection or other measures, such as coating re-conditioning, shorted casing remediation, or installation of a bond between the Longhorn pipeline and a source of foreign structure cathodic protection interterence. The addition of cathodic protection current most likely will occur through the installation of sacrificial anode or impressed current ground beds. The procedure for installation of a ground bed is contained in the Phase One BA, as is the procedure for coating reconditioning. Shorted casing remediation involves removal of a direct metallic short (i.e., a spacer bolt or a short segment of the casing end in contact with the carrier pipe), or draining electrolyte (water/mud) from the casing. Some casing remediations may require installation of new pipe, often concrete coated, through the casing or the installation of heavy wall thickness pipe, also with an abrasion resistant overcoat (i.e., concrete), bored under the road/railroad crossing. Any such work in habitat areas will follow the maintenance construction procedure outlined in the Phase One BA. Installation of a bond (a cable) to a foreign source of cathodic protection interference would involve a small excavation between the Longhorn Pipeline and the foreign structure, which are by definition in close proximity. A cable is installed between the facilities and secured to the pipe, usually by thermite welding. Typically, an interference bond installation will occur at or very near a crossing of the pipelines. A bell-hole excavation of approximately ten feet by ten feet, or one-hundred square feet, is sufficient. A depth to that of the deepest line, normally six to eight feet, is needed for the installation. Note that only the top side of the deeper line, not the entire circumference, needs to be exposed to accommodate lead attachment. The cables are brought into an aboveground test station for current flow and pipe-to-soil potential monitoring. The test station will generally be set directly over the pipelines' intersection. However, in some cases, if a fence line is nearby, the leads will be extended to that fence and the test station installed at that location. The trench for leads from the pipelines' intersection to the fence could range from ten to usually not more than fifty feet and from 8 inches to three feet wide and approximately 30 inches deep or below plow depth. Typically, not more than one-hundred-fifty square feet of surface area is disturbed for this trench and it typically remains within the pipeline rights-of-way. Coating disturbed during cable installation is repaired. Any such work in habitat areas will follow the maintenance construction procedure outlined in the Phase One BA. Cathodic protection system maintenance construction is typically conducted completely within the existing ROW. Though unexpected, the possibility exists that future construction could require work to occur outside the existing ROW, since a particular site could be attended with work space constraints (see procedure in the Phase One BA). Depth of Cover 99144ba2.v8 27 <<>> In 1998 Longhorn performed a depth of cover survey to determine the burial depth of the pipeline. In response to the findings of that depth of cover survey, Longhorn has identified a number of locations where the pipeline will be lowered or replaced. Examples of such locations are represented by LMCs 5 and 18; those locations were identified through the depth of cover survey and assigned priority either by Radian in the case of sensitive and hypersensitive areas (LMC 5) or by Longhorn in the case of other lowerings (LMC 18). In the coming years, the Longhorn Pipeline System Integrity Plan, Depth of Cover element, will determine, on a risk-assessed basis, the order and timing of future pipeline lowerings. The locations are prioritized by evaluating the potential for damage to the pipe. As those locations are addressed, the activity will follow the maintenance construction procedures described in the Phase One BA. Maintenance construction is typically conducted completely within the existing ROW. Though unexpected, the possibility exists that future construction could require work to occur outside the existing ROW, since a particular site could be attended with work space constraints (see procedure in the Phase One BA). Removal of Encroachments Longhorn has identified a number of encroachments that will be removed from the pipeline ROW within one year of system startup, in accordance with the commitments of the LMP (See LMC 16). The Service has requested Longhorn's assistance to increase landowner awareness of species and habitat concerns in connection with encroachment removal. Longhorn thus hereby commits to seek to include in any agreement with an encroaching landowner the following acknowledgment: Landowner is hereby informed that threatened or endangered species and/or habitat may exist upon or in proximity to the Property [defined term to identify the Longhorn ROW], and Landowner may have responsibilities to consult with the U.S. Fish and Wildlife Service pursuant to the Endangered Species Act. Longhorn acknowledges that the foregoing does not specifically prohibit by contract Landowner activity that could cause adverse effects to species and habitat. Since any agreement for encroachment removal would be voluntary, Longhorn cannot force landowners to agree that adverse effects will be avoided. Landowners would simply refuse to agree to such prohibitions, leaving Longhorn's power of eminent domain as the remedy. The power of eminent domain does not include within its scope the authority to require landowners to contractually agree to comply with applicable statutory requirements. In summary, Longhorn agrees to raise awareness as much as it legally may. Section 7.0 of the Longhorn Pipeline Project Description provides additional detail about system operation and maintenance; see Phase Two Project Documentation Appendix at Tab 6. 3.4 Emergency Response Risk Based Approach - Longhorn Mitigation Plan 99144ba2.v8 28 <<>> The EA process included the identification of pipeline mitigation measures that Longhorn has committed to implement. Many of the pipeline mitigation measures were identified in response to potential risks identified in the EA. The pipeline mitigation measures are designed to reduce those risks by prioritizing the deployment of resources toward the following goals: Prevention: Reduce the risk of a release by focusing on the four primary categories of risk: outside force damage, corrosion, material defects, and improper operation. Detection: Rapid identification of a pipeline release through use of the best available leak detection technology system-wide, and sensor-based technology in the Edwards Aquifer recharge zone. • Release Volume Minimization: Optimal use of block valves, coupled with the installation of additional check valves, will serve to reduce potential spill volumes, including in areas of potential effect to species. Control: Enhanced emergency response capability that employs thorough, detailed pre-planning, resource identification, and resource retention. A description of the manner in which those pipeline mitigation measures reduce risk is presented in Longhorn's Risk Reduction Benefits Summary, Phase Two Project Documentation Appendix at Tab 9. Prevention - Reduce the Risk of a Release Numerous pipeline mitigation measures are focused on reducing the risk of a pipeline release; many pipeline mitigation measures reduce more than one risk category. For example, hydrostatic pressure testing of the pipeline addresses outside force damage, corrosion, and material defects by testing the pipeline to pressures that create a margin of safety above operating pressures. Flaws that would create a potential for release during operation are eliminated by raising and maintaining internal pipe pressure to at least 125% of its operating pressure over an eight hour period. The pipeline mitigation measures that reduce the risk of a release include the following: : Hydrostatic pressure testing (LMCs 1 and 2) Replacement of an 19-mile segment over the Edwards Aquifer recharge and contributing zones, with the additional protection of a concrete barrier over the pipe (LMC 3) •. Cathodic protection system enhancements (LMC 4) Lowering, replacing and/or reconditioning if necessary at least 38 locations (LMCs 5 and 18) Removal of stopple fittings (LMC 6) Investigation and repair if necessary of 7 potential pipeline flaws (LMCs 7 and 8) Replacement of the crossing of Rabbs Creek (LMC 8) Surge pressure in EA designated sensitive and hypersensitive areas will not exceed maximum operating pressure (LMC 9) 99144ba2.v8 29 <<>> • In-line inspection within 3 months of system startup and additional in-line inspections according to the LMP, the Longhorn Pipeline System Integrity Plan and associated Operational Reliability Assessment (LMCs 10, 11, and 12) Increased frequency of cathodic protection system performance testing (LMCs 14 and 32) • Documentation of adequate pipeline span support and secondary containment at tank facilities (LMCs 15 and 27) • Removal of encroachments to the pipeline ROW (LMC 16) • Clearing the ROW to excellent condition (LMC 17) Analysis and remediation if necessary of stress corrosion cracking and earth movement risks (such as water crossings and seismic activity) (LMC 19) • Increased frequency of pipeline surveillance patrols (LMC 20) • Increased frequency of pump station inspections and installation of remote cameras at all pump stations (LMC 21) Performance of a water crossing valve study, with DOT review and concurrence, of additional check valves (LMC 22) • Development of an enhanced public education program, with performance monitoring (LMC 25) The effect of the above mitigation measures is to significantly reduce risk far below pre- mitigation levels. Detect - Best Available Leak Detection Technology Longhorn has committed to employ the best available, proven leak detection technology in the pipeline industry. Pipeline mitigation measures that improve leak detection, thus reducing the risk of an undetected leak, include the following: • Enhanced, computational-based leak detection system-wide, and sensor-based leak detection over the Edwards Aquifer recharge zone and the Slaughter Creek watershed in the contributing zone (LMC 13) Removal of encroachments to the pipeline ROW (LMC 16) • Clearing the ROW to excellent condition (LMC 17; see Phase One BA and the Service's February 17, 2000 Biological Opinion) • Increased frequency of pipeline surveillance patrols (LMC 20) • Increased frequency of pump station inspections and installation of remote cameras at all pump stations (LMC 21) Development of an enhanced public education program, with performance monitoring (LMC 25) Minimize - Reduce Potential Release Volumes Pipeline mitigation measures also focus on reduction of potential leak volumes: • Enhanced, computational-based leak detection system-wide, and sensor-based leak detection over the Edwards Aquifer recharge zone and the Slaughter Creek watershed in the contributing zone (LMC 13) 99144ba2.v8 30 <<>> • Performance of a water crossing valve study, with DOT review and concurrence of additional valves (LMC 22) Install additional check valves, one over the Edwards Aquifer recharge zone and one over the Edwards Aquifer contributing zone (this Phase Two BA; see section entitled Edwards Aquifer Protections) Control --Maximize Emergency Response Capability Finally, Longhorn has committed to bolster its emergency response planning and preparedness capability to reduce response times and to be prepared, in advance, with a full response effort: Ensure maximum 2-hour full response to EA designated sensitive areas, maximum 1 to 2 hours in hypersensitive areas, and maximum 1-hour response in the Edwards Aquifer recharge zone and the Slaughter Creek watershed in the contributing zone (LMC 23) Establish a response center in South Austin (LMC 23) Enhanced facility response plan will: Address firefighting in areas without Hazardous Materials response units (LMC 24) - Provide detailed planning for areas with high populations of potentially sensitive receptors (LMC 26) Establish consistency with the City of Austin Barton Springs Oil Spill Response Plan and the Service's Barton Springs Salamander Recovery Plan (LMC 28) - Identify and provide detailed planning for multiple response locations within the Edwards Aquifer recharge and contributing zones selected on the basis of calculations of worst case times of transport to the recharge zone In addition, Longhorn has included potential habitat areas on response plan maps and included protection of such habitat areas in response planning and preparedness training, in response to the Comment Letter (see Oil Pollution Act of 1990 Facility Response Plan). Probability of Release and Risk Reduction Longhorn has calculated the pre-mitigation probability of a pipeline release for the potential habitat areas along the pipeline. Those figures are presented in the APR report at Tab 10 of the Phase Two Project Documentation Appendix. The basis for the probabilities calculated is pre-mitigation data compiled by Radian for the Environmental Assessment. Thus, the probabilities do not take into account the numerous risk-reducing pipeline mitigation measures that Longhorn has committed to implement and is in the process of implementing; see above section Prevention - Reduce the Risk of a Release, and Table 2, Chronology of Longhorn Pipeline Actions. The result, then, is that the possibility of a release in the potential habitat areas will be further reduced from those shown in APR report. System-Wide Software-Based Leak Detection 99144ba2.v8 31 <<>> The Longhorn Pipeline will employ the best available, technologically proven pipeline leak detection system. The leak detection system is described in the following excerpt from Item 13 of the LMP submitted in connection with the EA: "Objective: The objective of this program is to identify the Longhorn Release identification time and the shutdown time required to minimize the size and Detection Systems that will be employed to minimize both the leak impact of a potential leak on the Longhorn Pipeline System. Leak Detection Systems: Leak detection for the unintended escape or potential loss of product from Longhorn Pipeline incorporates the use of a combination of visual, mechanical, and analytical processes, equipment, and models. Collectively, Longhorn's Leak Detection System capabilities, which provide for several areas of overlap, are designed to significantly reduce the likelihood of a protracted period of undetected pipeline system breaches and continued that would adversely contribute to human or environmental exposure to hydrocarbon products. Heightened awareness of the designated sensitive and hypersensitive areas along the Longhorn pipeline has resulted in the employment of enhanced leak detection technology and processes. Longhorn's Leak Detection System is comprised of two primary components: External Patrols; and Technology Based systems. By design, these two areas of leak detection provide redundancy and assurance that a release will be detected within the shortest time possible using current best available technology. External Patrols: External Patrol of the Longhorn Pipeline System is primarily accomplished through the targeted activities of Longhorn Operations and directed third party surveillance contract personnel. Some of these activities include aerial patrol, inspection of water crossings, ground based right-of-way patrol, tank dike inspection, scheduled inspections of valve locations, surface facilities, buried road crossings, and DOT regulatory based activities. External Patrol is also enhanced through the incorporation of data obtained through normal pipeline maintenance activities, such as those accomplished via cathodic protection inspections, One-Call line spotting, and physical pipeline examination during pipeline exposures. Another important source of input under the category of External Patrol results from the involvement of the general public, emergency response organizations, contractors, and other third party sources. These groups are specifically targeted via • Longhorn's Damage Prevention Program (see 99144ba2.v8 32 <<>> Longhorn Pipeline System Integrity Plan) and other activities which are designed to instill awareness of the location of the pipeline corridor. Further, active public education programs are designed to result in an increase in public knowledge by which to primarily avoid, but to secondarily recognize, any activities that could reasonably lead to adverse effects to the pipeline system. With pipeline location awareness, product characteristic information, and emergency response phone numbers and points of contact, the general public, emergency responders, contractors, and other third party groups serve as further insurance that system leaks can be minimized from third party damage, may be recognized if one occurs, and in that case be communicated to Longhorn Operations personnel. External Patrol leak detection is dependent upon the physical identification of some abnormality or change from the characteristics of the surrounding area of the pipeline corridor. Physical evidence can include a hydrocarbon odor, a sheen on a water surface, spraying product, bubbles along the ground, discoloration of soil, areas of vegetation "browning," and fires in near proximity to the pipeline assets. Similar to many other methods of leak detection, External Patrol leak detection can readily identify a moderate to major product release. Smaller leaks, be they from pinhole leaks or leaking pipeline components, often require more time to trigger the physical indicators such as defoliation or odor which indicate a potential product leak. Technology Based: Longhorn will employ a leak detection software system to monitor the operation of its pipeline system. This system represents the current best available, proven technology in the industry. The leak detection software is a transient model that is designed to analyze and compare the actual pipeline operations of pressures and flow rates against theoretical values during both steady state and changing conditions. Deviations between actual and theoretical values result in alarm indications and notification to the Operations Control Center for subsequent review, analysis, investigation, and if appropriate shutdown of the pipeline system. Longhorn approached the selection of a computational based leak detection software system through the employment of a highly respected third party consultant who has demonstrated experience in the field of pipeline SCADA systems and leak detection, along with a current understanding of leak detection technologies and performance capabilities. Leak detection performance requirements, based upon demonstrated industry achievable levels and best available transient model technology, were developed by Longhorn's consultant and approved by Longhorn's management. Computational based Leak Detection "Requests For Proposals" were sent to several prospective vendors, and responses were returned to Longhorn's consultant for detailed review and evaluation. The review/analysis process included clarifying discussions with the vendors, technical presentations, and detailed reference checks with provided customer lists. This process yielded two vendors who were judged to be capable of meeting the leak detection 99144ba2.v8 33 <<>> performance requirements established by Longhorn. Further discussions with the two "finalists" resulted in the selection of the computational based leak detection software system that was determined to have the higher degree of leak detection performance. The software based leak detection system is fundamentally a volume (mass) balance system that employs a fully transient model. The flow balance calculated from flow measurements is corrected by the packing rate, which is calculated by the "real-time" model. The resulting volume balance allows calculation of potential leak indicators. A leak would be identified by comparing the node flow balances at measurement points. The model dynamically tracks changes in the pipeline's flow rate. Variation between modeled and measured flow shows up in the volume balance calculation. The rate of change of all boundary measurements affects the leak detection by affecting the model directly, as well as the dynamic thresholds. Leak alarm thresholds are provided for each volume balance section and averaging interval. The SCADA system used for the Longhorn pipeline system operates on Neles (formerly Valmet Automation) Oasys software version 5.2. Longhorn operator Williams subscribes to the Neles maintenance program which provides software program updates. Williams maintains the most a communeason and contin at the pie se components. For example, in 1999 the SCADA system experienced 99.954% reliability (after deduction for Y2K testing). The 0.046% down time for that year is attributable to a single four-hour service outage. Thus, it is very unlikely that the SCADA system would be out of service for any appreciable amount of time. A SCADA system outage could result in a loss of leak detection system sensitivity. An outage which does not affect the entire SCADA system can occur, for example, with the loss of data from a remote terminal unit (RTU) at a pump station for more than three minutes, in which case an alarm sounds in the Control Center to alert the controller. Under such circumstances, the system uses backup land line communications links to reestablish communications. However, the leak detection system is able to maintain its detection capability by modeling across the point of data loss. A loss of SCADA communications that affected the entire system, for example because of a computer malfunction, would immediately be known to the controller. If the SCADA system experiences any outage that results in a total loss of leak detection capability for all or any portion of the pipeline for a period in excess of 5 minutes, then the controller will take action to achieve system shutdown within 30 minutes. In the event that the SCADA system experiences an outage that does not result in a loss of leak detection capability, but instead results in a diminished capability of the system to detect a leak, then the controller will take action to achieve system shutdown within 30 minutes if the capability of the system to detect leaks is diminished 99144ba2.v8 34 <<>> to a level that would prevent Longhorn from meeting its "Leak Detection Performance Commitment" set out below. Further Enhancement: In addition to the computational based leak detection system, Longhorn has committed to employ additional technology to provide for more Stringent leak detection across the environmentally sensitive Edwards Aquifer Recharge Zone and the Slaughter Creek watershed in the Edwards Aquifer Contributing Zone (the "Enhanced Leak Detection System"). In order to achieve this capability, Longhorn plans to employ a hydrocarbon sensing leak detection cable system that has clearly demonstrated the leak detection capability to satisfy Longhorn's commitment contained within Mitigation Commitment 13. This system is designed to detect a leak as small as 0.0030467 barrel per hour in twelve (12) to one hundred twenty (120) minutes from contact with the leak detection cable, depending upon the product sensed by the system. Several factors will make it probable that any released product will come into contact with the leak detection cable within a minimum amount of time, including the following: (a) the construction methods that Longhorn will employ over the recharge and contributing zones during replacement of this segment of pipe, including protection of all identified subsurface voids; and (b) backfill materials used within the trench (primarily fine materials to provide padding to the pipe and otherwise relatively porous media), coupled with the primarily limestone geology of the Edwards outcrop and the fact of the in- trench materials having been disturbed will cause any released product to accumulate within the trench where the leak detection cable will be located. Longhorn has committed to having this system in place prior to start-up of the pipeline. The hydrocarbon sensing leak detection system is based upon the TraceTek hydrocarbon sensing cable manufactured by Raychem HTS. Longhorn's ultimate choice of the TraceTek cable was made after Longhorn, Williams and UTSI International Corporation performed exhaustive research of leak detection technology potentially feasible for this particular application. After detailed analysis of potentially feasible leak detection technologies, and consultation with the Office of Pipeline Safety, the TraceTek cable was identified as the current best available, proven technology in the industry. The table below identifies the sensing capabilities of the TraceTek system. Leak Detection Response: With notification typically originating through the utilization of its External Patrol and Technology Based components of its Leak Detection System Capabilities, Longhorn Pipeline will facilitate the orderly and controlled shutdown of its system within five (5) minutes of a probable leak indication. 99144ba2.v8 35 <<>> Longhorn maintains 24-hour surveillance of its pump stations, motorized valve locations (MOV), terminals (pipe, pumps, valves, meters, and tanks), and meter stations through its SCADA system. (Truck loading operations at the El Paso Terminal are monitored locally.) Twenty-four-hour surveillance will also be maintained with respect to Longhorn's Enhanced Leak Detection System. Pipeline operational data from these locations is transmitted directly to the Tulsa Operations Control Center, where trained and qualified Operations Control personnel monitor and provide equipment control commands to the Longhorn system. Operations Control personnel utilize the following methods for the determination or suspicion of a probable leak indication: • Deviation outside normal operational thresholds from the computational based transient leak detection software system in a direction that is indicative of a leak; • Receipt of an alarm by the sensor cable system over the Edwards Aquifer Recharge Zone; Unexpected deviation outside minimum or maximum alarm thresholds for system pressures and flow rates; Rate of Change alarms that compare pressure or flow value change versus time; Operations Control personnel independent analysis of flowing conditions; • Third party call of suspected or confirmed product leak; • Input from Field Operations Personnel; Automatic closure of MOV's or stoppage of pipeline pumps; and • Terminal high level alarms. Analysis of a suspected pipeline leak is accompanied by an identification of the location of the suspected leak. Upon the detection, notification, and determination of a probable leak indication, Operations Control personnel are trained to immediately shut down the pump station(s) upstream to the leak location. The pump station downstream to the leak location is either kept running or is started to assist with the orderly movement of product away from the leak location. Following the shut down of the upstream pump(s), the Operations Control personnel will close the upstream MOV's from the leak location to prevent the introduction of new product to the segment. Through the use of the SCADA system, upstream pump stoppage and MOV closure are accomplished within five (5) minutes from the identification of a probable leak indication. The Longhorn Pipeline was designed to be shut down immediately following a probable leak indication. Communication with field operations, product origination or destination points and terminals are not required to shut down the pipeline in an orderly or safe fashion. Operations Control personnel are trained to notify the appropriate supply, destination, field operations, and 99144ba2.v8 36 <<>> emergency responder personnel as soon as practical following the shut down and isolation of the pipeline. The above emergency shut down procedures will be documented and tested for Operations Control personnel training certification prior to start-up of the Longhorn Pipeline system. The Longhorn pump stations utilize a Programmable Logic Controller (PLC) to handle the start-up, sequencing, data transmittal, and shut down of the equipment within the station. The Tulsa Operations Control Center sends command signals to and receives operational data from the PLC's at each pump station. The PLC's, coupled with the instrumentation contained at each pump station, serve to protect the pump equipment from mechanical disturbances such as vibration, abnormal motor winding or pump bearing temperatures, loss of product through seal leaks, and fire sources. Internally, the pump equipment is protected from conditions of high product flow, low product flow, low system pressure, high system pressure, and excessive or low motor amperage. The PLC is programmed to provide both early indication alarm and automatic pump shutdown in the event that designated parameters are operated outside their intended range. Pressure, flow, and tank level readings from across the pipeline system are transmitted to the Tulsa Control Center via the SCADA system for computational transient modeling analysis and Operations Controller interpretation of the physical data, as is the data generated by the Enhanced Leak Detection System. The status of the sensor cable system over the Edwards Aquifer Recharge Zone also is transmitted to the Tulsa Control Center. Outside of the automatic shut down of pump units that are controlled by the local pump station PLC's, shut down of equipment and isolation of MOV's are originated by the Operations Controller. Leak Detection Performance Commitment: Longhorn is committed to implementing the best available leak detection systems with the following design specifications: SYSTEM DESIGN LOCATION SPECIFICATIONS Tier I 1% of flow detected within one-half hour. Tier lI 1% or more of flow detected within one-half hour. Tier III 0.5% - 1% of flow detected within one hour. Same as Tier II, except Edwards Aquifer recharge zone an ontributing zone (Slaughter Creek watershed Edwards Aquifer barrel/hour from contact for the following products Same as Tier Il, and sensor-based detection of 0.0030467 • Gasoline - 12 minutes watershed) : Diesel Fuel - 60 to 120 minutes Jet Fuel - 50 to 70 minutes 99144ba2.v8 37 <<>> The leak detection equipment will be installed prior to startup. The computational based system will be adjusted to become operational over approximately the first two weeks of pipeline operation and be further optimized within 6 months of startup. The sensor-based system will be fully operational, at full sensitivity, immediately upon startup. Leak detection capabilities will be demonstrated and periodically tested." UTSI International is Longhorn's third party leak detection consulting firm. Correspondence describing leak detection system development and design is included in the Phase Two Project Documentation Appendix at Tab 11, as are qualifications of the UTSI personnel directly involved in system development and design. System shutdown is achievable without field communications due to the fact that the SCADA system gives remote control of all relevant system components to the pipeline control center in Tulsa. The leak detection system software will not be inoperable during the fine-tuning period; rather, it will be adjusted to its operating status over approximately the first two weeks, and further optimized over as much as six months from startup. The sensor-based system over the Edwards Aquifer recharge zone and Slaughter Creek watershed in the contributing zone will be fully operational, at its full sensitivity, immediately upon system startup. Emergency Response Preparation - Emergency Response Plan The Williams System of Manuals contains an Emergency Response Plan volume, a copy of which is included in the Phase Two Project Documentation Appendix at Tab 12. The Emergency Response Plan provides direction to the employee first aware of an emergency situation, including emergencies that involve a release of a transported commodity. The priority for protection in the event of an emergency is appropriate: (1) human health and safety; (2) the environment; and (3) property. Among the first duties of the first aware/first responder role is to activate the applicable facility response plan (FRP; aka OPA '90 Plan). A copy of the most recent draft of the Longhorn FRP (March 24, 2000) is hereby provided as a separate Appendix; as development is completed, the final FRP will be provided to the Service. Oil Pollution Act of 1990 Facility Response Plan Longhorn developed and distributed an FRP in 1998 and submitted same to DOT for review and comment. The Settlement Stipulation that arose out of the NEPA lawsuit, however, contained DOT's agreement that it would not approve, or allow Longhorn to commence operations under, the FRP until the conclusion of the EA process. The FRP was scrutinized during the EA, and Longhorn committed to develop numerous enhancements to the FRP as listed in this Phase Two BA at Section 3.4. The Service also provided comments to enhance response capability over the EARZ/EACZ. The FRP enhancements will serve to protect the environment as a whole, and listed species and habitat in particular, as well as human health and safety. The LMP contains a number of commitments to enhance the FRP, and those enhancements have been developed and implemented to the extent possible: 99144ba2.v8 38 <<>> • Ensure maximum 2-hour full response to EA designated sensitive areas and maximum 1 to 2 hours in hypersensitive areas (LMC 23) Establish a response center in South Austin (LMC 23) • Enhanced facility response plan will: - Address firefighting in areas without Hazardous Materials response units (LMC 24) - Provide detailed planning for areas with high populations of potentially sensitive receptors (LMC 26) - Establish consistency with the City of Austin Barton Springs Oil Spill Response Plan and the Service's Barton Springs Salamander Recovery Plan (LMC 28; these enhancements depend upon promulgation by the City of Austin and the Service of their respective plans, neither of which has occurred at this writing) The EA took into account listed species and potential habitat when identifying areas to designate as sensitive and hypersensitive (see Section 3.1, above). Thus, the FRP benefits that are directed to sensitive and hypersensitive areas also are directed at species and habitat; see EA at Section 9.2.3 and Appendix 9C. The development of a new response center, to be located in south Austin, will limit the elapsed time between notification of response personnel and implementation of a full response at any release site. Longhorn will stage personnel and equipment to achieve a full response in sensitive areas in less than two hours, and in one to two hours in hypersensitive areas. A response time of 1 hour will prevail for the Edwards Aquifer recharge zone and Slaughter Creek watershed in the contributing zone. A maximum 1 to 2 hour response time will apply in the Barton Creek watershed in the contributing zone. More detailed, site-specific planning and preparation will enable more rapid and more effective deployment on-site. Sensitive and hypersensitive areas are interspersed along the pipeline route, with non-designated areas between; therefore, segments between sensitive and hypersensitive areas benefit from much the same treatment by virtue of proximity (See Longhorn FRP at Volumes II and III, Sections 4 and 5). Stated another way, a Tier I area located near a Tier II or Tier III area, or located between two areas of either Tier Il or Tier Ill status, will by definition be within the reach of response crews within the same time periods stated above for sensitive (Tier II) and hypersensitive (Tier III) areas. Emergency Response Activities The following paragraphs describe generally the sequence and character of activities that occur at a pipeline release location. Each potential release would likely involve unique circumstances, and, among other factors (see APR Companies, Phase Two Project Documentation Appendix at Tab 10), the on-site response will vary with location, terrain, weather conditions, product released, and release volume. The area of disturbance caused by a response action varies depending upon the character of the response and by nature of the release. The following description identifies the majority of typical response activities. The first responder(s) will immediately notify Longhorn Operations Control and the Area Manager. They will take appropriate action to protect life and ensure safety of personnel. They will additionally request Operations Control to notify the appropriate emergency responders. Operations Control will coordinate company response activities until company 99144ba2.v8 39 <<>> personnel arrive on scene. When a leak is detected, Operations Control will shut down the pipeline following procedures in the Operations Control Manual. Remote operated valves upstream of the release will be closed and downstream valves may be closed or left open to allow drainup, depending on conditions. The Longhorn First Responder assumes the role of Longhorn Incident Commander (IC) until relieved. The Longhorn IC will work in cooperation with the local emergency responders (reference Longhorn Emergency Response Plan from the System of Operating Manuals). Responders will conduct a preliminary assessment of the situation including potential health and safety hazards. If someone is injured or if there is the potential for a fire or explosion, emergency services will be called out. Assistance from public agencies for site control and evacuations will be requested if necessary. Proper monitoring will be conducted to ensure public and personnel safety, and that the necessary spill response contractors have been mobilized to assist in containment and cleanup operations. Response contractors are currently identified in the FRP Volume I, Section 8 and within each county-level response zone plan (Volumes II and III). All or a portion of additional resources will be activated, as necessary. For a major release, all resources may be activated. Appropriate regulatory agencies will be notified. Potentially affected sensitive areas will be identified. The designated Tier II and Tier I! areas are identified on the strip maps in FRP Volumes || & III, Section 4. Additional information on the Wildlife Sensitive Areas is located in Section 5 of Volumes || & III. The topographic maps also locate sensitive features along and down gradient from the pipeline. Any response activities will involve measures to protect the sensitive areas. If there is the potential to affect the Wildlife Sensitive Areas, the biological contractor will be included as part of the response team. A request for assistance to have potential ignition sources in the vicinity of the spill, including motors, electrical pumps, electrical power, etc. shut down will be made. Local fire departments and/or Boots & Coots, Eagle Environmental, or other release response contractors will be notified if the use of fire suppressants is required. Longhorn responders will shut down and control the source of the spill. This may include closing additional valves, collection of pooled product at the pipeline location, digging out the pipeline, collection of product from the pipeline and the pipeline ditch, and repair of the pipeline. Longhorn responders will stabilize and contain the situation in coordination with appropriate agencies. This may include berming, the deployment of containment and/or sorbent booms, construction of dams, or trenching in a manner that limits the spread of the product. The tactic used is dependent upon many factors including the location, the volume, type of sensitive areas, weather, and similar factors. General response tactics are discussed in the FRP at Volume I, Section 3. Site-specific tactical plans for selected sensitive areas are located in Section 4 of Volumes II and III. Access points and possible response strategies are identified in the tactical plans. The pre-identified access points were chosen on the basis of calculations of worst case transport times, proximity to existing roads and other access, and suitability for use. Within the Edwards Aquifer recharge and contributing zones, multiple response locations with associated tactical plans have been identified along the Barton, Slaughter and Williamson Creek watersheds in the event a release were to 99144ba2.v8 40 <<>> reach a stream or tributary and potentially be transported toward the recharge zone. (see LBG-Guyton, "Travel Times for Hypothetical Releases from Longhorn Pipeline within the Pipeline Replacement Corridor in Austin, Texas," 2000 in the Project Documentation Appendix). Additional access points may be utilized during an actual response. If indicated, wildlife protection measures will be initiated. Product recovery and removal operations will be initiated. This may include recovery of free product from ground surface, water or trenches using vacuum trucks, skimmers or sorbents. Excavation of contaminated soil may be utilized. In situ methods such as biological treatment or controlled burns may be considered. Any technique used will attempt to minimize disturbance to the environment. Additional information on recovery techniques is located in Volume I, Section 3 of the FRP. All necessary approvals must be obtained from applicable resource trustees. Documentation procedures will be initiated. Documentation of all response actions taken, including notifications, agency and media meetings, equipment and personnel mobilization and deployment, and area impacted will be made. Spill tracking and surveillance operations will be initiated. The extent of pollution may be determined via surveillance aircraft. In the event of subsurface impacts, cave monitoring or water well monitoring may be utilized. Photographers and/or videographers will be utilized. The equipment and personnel required for a response are dependent on the specific release situations. The volume, location, and the unique site characteristics will affect the necessary resources. Some of the equipment such as transport vehicles, temporary storage or tank trucks may be located at a staging area rather than at an active work site. Site-specific resources are identified in the tactical plans within the FRP. In general the major resources that may be utilized at the pipeline release response location may include: Vacuum Trucks (one or more at each recovery site depending on leak volume); : Trackhoe or backhoe for pipeline dig out; Dirt moving equipment may include an additional backhoe or bulldozer and dump trucks for containment and recovery operations; Spill response trailer; Sorbent Material; • Tanker Trucks and/or temporary storage; • Welder's Truck (for pipeline repair); • Boom Truck (for pipeline repair); Miscellaneous transport vehicles; Roll offs or drums for contaminated debris; and • Fire suppressant material if necessary. Species Habitat Areas Longhorn has implemented additional levels of planning and preparedness in the FRP 99144ba2.v8 41 <<>> since September 1999. Human health and safety must take precedence during the execution of an emergency response. If a release occurs within habitat, or at any location where the release could adversely affect species or habitat, Longhorn will employ additional measures to avoid any potential adverse effects to species or habitat. To do so, Longhorn has incorporated into the FRP maps depicting areas of potential habitat both adjacent to the pipeline and along pipeline sections from which a release could adversely affect species or habitat. Longhorn also has identified numerous pre-planned containment and recovery locations throughout the Edwards Aquifer recharge zone and the contributing zone. Further, Longhorn has included in its FRP training regimen for emergency response personnel the information necessary to identify such areas and prioritize response activities toward such areas. Habitat areas along the pipeline have been mapped, and the maps have been incorporated into the FRP along with descriptions of response actions that apply in those areas (See Longhorn FRP at Volumes Il and III, Sections 4 and 5). In addition, Longhorn will immediately engage a qualified biologist on-site to provide direction to response personnel if a release location is near an area of potential habitat. Personnel will be directed to avoid indirect effects such as traversing habitat areas to gain site access. They also will employ site and circumstance-specific measures to protect species and habitat threatened by a release and thereby avoid adverse effects; for example, were a release to ignite in Bastrop County, fire-fighting efforts would identify and give heightened protection to habitat areas near the fire (see Buescher State Park Fire Response Resources, in the Project Documentation Appendix). Longhorn acknowledges the value of Service expertise in protecting species and habitat. As such, Longhorn solicits Service participation in emergency response planning and preparedness training with respect to species and habitat protection. Longhorn invites Service participation in response training at response drills and table-top exercises. Longhorn shall notify the Service of such training exercises, provide the Service an opportunity to review and comment upon preparation for the training, and invite Service participation during such training. 3.5 Edwards Aquifer Protections The Edwards Aquifer in Travis and Hays Counties is a valued resource. In addition, the Barton Springs Salamander, which resides in several spring outlets of the Edwards Aquifer, is an endangered species that must be protected. Longhorn will implement a multitude of measures both to ensure that the quality and integrity of the aquifer is preserved, and to ensure the continued survival of the salamander. See document entitled Edwards Aquifer_ Protections, in the Project Documentation Appendix, which summarizes the various protections. Longhorn will implement conservation measures to avoid the possibility of impacts to the aquifer that could result from a pipeline release over the recharge zone or upon the contributing zone, should ever one occur. However, the Service has requested an analysis of the potential effects if released product were to enter the aquifer. Longhorn will implement a number of pipeline enhancements, including (a) replacement of the pipe over the recharge zone and the contributing zone with new thicker-walled pipe; (b) additionally protecting the new pipe with a reinforced concrete barrier; (c) installation of an 99144ba2.v8 42 <<>> enhanced, sensor-based leak detection system through the recharge zone and the Slaughter Creek watershed in the contributing zone; (d) installation of additional check valves; and (e) daily inspections of the ROW (See Section 3.5.2). An extremely sensitive, sensor-based leak detection system will complement a computational-based leak detection system; jointly the systems will be capable of rapidly identifying potential small and large leaks. Daily patrols will identify potential threats to the pipeline, and enhanced emergency response capability will provide for rapid and effective release response. Longhorn has commissioned thorough analyses of the Edwards Aquifer recharge zone and contributing zone by experienced hydrogeologists, geologists, and biologists (See resumes of Sherrod, Kreitler, Russo, Stein, Miller, Dorsey and Gasch, Phase Two Project Documentation Appendix at Tab 13). The subsurface along the pipeline traverse of the recharge zone has been studied by ground-penetrating radar, and subsequent investigations demonstrated the absence of significant voids along the pipeline (See LBG- Guyton letter to Vince Murchison dated 10 December, 1999, Phase Two Project Documentation Appendix at Tab 14). The related topography has been mapped, and surface drainage tendencies have been modeled. Local infrastructure has been surveyed and analyzed to determine the potential implications to infrastructure components in the unlikely event of a pipeline release; for example, roadways would interrupt the flow of a hypothetical release that resulted in surface flow. Storm water detention ponds in and around Austin receive detailed response planning. Analysis of areas along the pipeline traverse of the recharge and contributing zones has identified locations where the capacity of the pipeline trench to retain fluid could be exceeded. Longhorn first will backfill the trench with fill that has been sized to result in high porosity, which will have the effect of increasing the capacity of the trench to retain fluid if any is released from the pipeline. At an estimated 18 locations at lower elevations, however, the capacity of the trench could be exceeded if worst case discharge volumes are used with the assumption of complete pipe drainage. At those locations, Longhorn will install a berm containment system that has been designed both to contain any product that may reach the surface and to prevent storm water accumulations that could compromise the capacity of the containment systems. Those containment systems are described in the analysis entitled "EARZ/EACZ Pipeline Replacement Trench and Berm Product Containment Conceptual Design," "Response to Lead Agency Review of Conceptual Design for Trench and Berm Product Containment for the EARZ/EACZ Longhorn Pipeline Replacement," and "Response to USFWS' draft letter of 8/26/00," all of which are included in the Project Documentation Appendix. Included with the conceptual design are diagrams of the containment systems. The containment systems will be constructed with hydrocarbon-sensing valves that allow the passage of storm water but automatically close, without human intervention, if hydrocarbons contact the valve. Another preventive conservation measure Longhorn will employ is the installation of check valves over the Edwards Aquifer recharge zone and over the contributing zone. The check valves will be located in a manner that reduces potential volumes that could drain from the pipeline in the event of a breach. Check valves are one-way valves that allow product within the pipeline to flow in the intended direction, i.e., downstream in the pipeline. However, check valves prevent flow in 99144ba2.v8 43 <<>> the opposite direction, upstream, such that if for any reason product attempts to flow backward, the valve closes to preclude flow in the upstream direction. A hypothetical example illustrates the function of a check valve. If one assumes a pipeline breach on an incline such that the pipeline flow is uphill, the contents of the pipeline could drain out of the breach due to the forces of gravity. If one then assumes that a check valve was installed along that incline (downstream on the pipeline), then the check valve would stop the backward, downhill flow of the product from the pipeline, effectively reducing the volume of product that could drain from the breach (gravity is not the only force to be factored into the potential for draindown, as discussed below). The check valves that Longhorn will install will be located to achieve just such effect. The valve over the recharge zone will be placed at approximately milepost 171.5, near the pipeline intersection with Whiteworth Loop in the Sendera Glen subdivision, which is downhill of a gradual rise in the land surtace to the west. By being located near a low point of the pipeline traverse of the recharge zone, the check valve will prevent the potential for draindown of product from the check valve to a point approximating the western edge of the recharge zone. The valve over the contributing zone will be located at the existing Edwards Aquifer West Valve, approximately milepost 175.5, about 2.1 miles east of U.S. 290 and about 1.8 miles west of the boundary of the recharge zone. Again, this valve is located below a moderate incline to the west and will reduce the potential draindown volume of a release between the two check valves. See APR report, Phase Two Project Documentation Appendix at Tab 10. Concerns have been raised by various parties, Longhorn opponents included, to the effect that a breach in a pipeline allows all product in the pipeline between adjacent block valves to drain out, but such is not the case. The California State Fire Marshall's office has analyzed pipeline release volumes to determine the extent to which various components of release volume contribute to total release volume (see Phase Two Project Documentation Appendix at Tab 15). The analysis determined that draindown contributes only marginal volumes to a release. Of the releases studied, in only 25% of the cases did the total release volume exceed 4.5% of the potential draindown of the pipeline, while in just 10% of the cases did the total release volume exceed 28% of the potential draindown. Among the reasons for low draindown volumes is that for product to flow out of the pipeline, it must first be displaced by air, similar to the manner in which water flows from a bottle that is turned upside down. See APR Companies, Phase Two Project Documentation Appendix at Tab 10. Longhorn has calculated full line draindown for hypothetical releases to the east of the recharge zone check valve described above; that volume is 3,875 barrels (162,750 gallons). However, if one applies the lessons of the California State Fire Marshall risk assessment that volume is more realistically calculated as 1,147 barrels (48,174 gallons) at 28% draindown and 841 barrels (35,322 gallons) at 4.5% draindown. Despite the findings of the California State Fire Marshall risk assessment, Longhorn has designed the bermed areas described above using the assumption that all product escapes from the pipeline segment affected by a release. Using those more realistic assumptions, the potential threat to the Barton Springs Salamander from a pipeline release in such areas is lower than previously understood. Calculations of the effect of a release over the aquifer recharge zone performed by LBG- Guyton (see Phase Two Project Documentation Appendix at Tab 16) demonstrate that the potential for adverse effects to the salamander is greatly reduced. See Section 4.4 of this 99144ba2.v8 44 <<>> BA and LBG-Guyton, Phase Two Project Documentation Appendix at Tab 16. Nonetheless, Longhorn's conservation and mitigation measures will make it unlikely that adverse effects to the aquifer will occur. 3.6 Pipeline Maintenance Construction This section identifies and describes incremental pipeline maintenance construction activities, in addition to those that were the subject of the Phase One BA, that will be implemented in two specific areas: (a) within Houston toad habitat in Bastrop County; and (b) across and adjacent to the Edwards Aquifer recharge zone within Austin. Additional maintenance construction will include planned, but unscheduled construction and future additional, but currently unforeseen construction. Maintenance construction that occurs outside the two presently identified areas will be subject to the maintenance construction procedures described in the Phase One BA, as will maintenance construction in Houston toad habitat and the Edwards Aquifer recharge zone; however, this BA contains descriptions of additional conservation measures that Longhorn will implement during the maintenance construction activities over the Edwards Aquifer recharge zone. The maintenance construction procedures referred to herein, and presented in detail in the Phase One BA, are identified below: 1. Pipeline Maintenance -- Construction Planning 2 Project Environmental Inspectors 3. Site Preparation 4. Site Entry 5. Pipeline Lowering and/or Replacement - Open Terrain 6. Pipeline Lowering and/or Replacement - Creek Crossing 3.6.1 Buescher State Park Maintenance construction activities planned within Buescher State Park (containing Houston toad habitat) result both from the EA process and from Longhorn commitments to reduce risks to species and habitat. The EA related project is the replacement of 671 feet of pipe at mile post 127.94 (Hunt Branch) within Buescher State Park in Bastrop County, Texas. Longhorn committed in the LMP (LMC 34) to replace the pipe since data on file at the time indicated that the segment contains several shorter sections of Grade B pipe. Longhorn has since identified file documentation that demonstrates that the existing pipe is adequate for the design pressure; however, Longhorn remains willing to replace the pipe to limit the potential for surge pressure-related damage and thus lower the risk of a release in this habitat area. Two additional tasks have been identified to reduce the risk of a release in Houston toad habitat: (a) lowering and replacement of the pipeline crossing of Dry Branch in Buescher State Park (pipeline mile post 128.33); and (b) lowering and replacement of the pipeline crossing of an unnamed creek approximately 1360 feet east of the 671-foot replacement (pipeline mile post 127.72). See additional engineering information at Tab 17 of the Phase Two Project Documentation Appendix. The three projects significantly reduce the potential for damage to the pipe in and near the three creeks. Since land development does not occur within the state park, and taking into 99144ba2.v8 45 <<>> account the pervasiveness and effect of the EA mitigation measures that focus on identifying and preventing corrosion, on eliminating material defects, and on preventing adverse consequences resulting from operator error, the greatest threat to the pipeline is outside force damage within the creek beds. For a complete discussion of the risk reduction realized by the creek crossing replacements, see APR Report (Phase Two Project Documentation Appendix at Tab 10). Further, the replacements will limit the potential volume of a release, should one occur, since the thicker and higher-grade new pipe will be least likely to suffer a breach, by serving as low-point catchments for product within the pipe that could escape if a release occurred at lower elevations. The new creek crossing replacement pipe will have 0.375" wall thickness and be of American Petroleum Institute Grade X56 or better. The burial depth of the pipe will be determined on the basis of regulatory requirements (49 C.F.R. § 195.248) and site conditions such as type of stream bed material and basin and channel configuration; the pipe will be buried below a depth that would allow in-stream forces to pose a threat to pipeline integrity. 3.6.2 Edwards Aquifer Protections During informal consultation on the Longhorn Pipeline Project, the Service voiced concerns about the pipeline crossing of the Edwards Aquifer recharge zone and the potential for adverse effects to the Barton Springs Salamander. Adverse effects to the salamander may be associated with water quality degradation within the aquifer (See Barton Springs salamander listing final rule at Tab 18 of the Phase Two Project Documentation Appendix). Typically, water quality degradation originates at the aquifer recharge and contributing zones and is largely associated with residential and commercial development and the creation of impervious cover. In addition, commercial and industrial operations and vehicular roadway traffic create the potential both for chronic water quality degradation as a result of ongoing activities and for acute water quality degradation in the event of a release of deleterious materials to the watershed. System operation and ongoing, long-term maintenance of the pipeline are not likely to result in adverse effects to the salamander, for which critical habitat has not been designated. ROW maintenance, pipeline inspection, valve maintenance, and similar such activities are unlikely to result in adverse effects to the salamander inasmuch as the activities are implemented in a manner that does not affect aquifer water quality. Longhorn responded to the Service's concerns about water quality by identifying measures that will not only reduce the potential for a pipeline release, but will protect water quality and promote public efforts to ensure the survival of the species in the unlikely event of a release that threatened the Barton Springs segment of the Edwards Aquifer. Longhorn committed to implement the following measures and included the measures in its Environmental Assessment mitigation commitments: Replacement of over 3 miles of pipe over (and east of) the recharge zone and 15 miles of pipe over the full extent of the contributing zone with new, thicker walled pipe (LMC 3). • 99144ba2.v8 Installation of an enhanced, sensor-based leak detection system across the aquifer 46 <<>> recharge zone and the Slaughter Creek watershed in the contributing zone to complement the pipeline-system-wide computational-based leak detection system (LMC 13). Installation of check valves (one in the recharge zone and one in the contributing zone) to minimize the volume of a potential release should one occur (see Section 3.3, Edwards Aquifer Protection). Performance of daily pipeline surveillance patrols over the recharge zone (LMC 20). Establishment of a refugium and captive breeding program for the Barton Springs Salamander as a conservation measure to ensure the survival of the species in the event of any perturbation to the extant population (LMC 33). Further in response to concerns voiced by the Service, and concerns voiced also by the Barton Springs/Edward Aquifer Conservation District, Longhorn will implement an additional measure to reduce the risk of a release that could adversely affect water quality. Longhorn commits to install a protective concrete barrier over the 5-foot-deep replacement pipe. The barrier will be engineered with reinforced concrete to provide a protective covering over the pipeline that will alert an errant excavator to the presence of the pipeline. The concrete will be colored red to ensure ready notice of the presence of a protected structure. The protection offered by the concrete barrier will provide further reduction of a threat to the pipeline, third party damage, in the developing areas of south Austin, southwestern Travis County, and northeastern Hays County (See additional information at Tab 19 of the Phase Two Project Documentation Appendix). Analysis of the pipeline traverse of the recharge and contributing zones has identified areas where surface flow modeling indicates a tendency for surface flow toward known karst features or toward Slaughter Creek, Barton Creek or Williamson Creek (see LBG-Guyton, Phase Two Project Documentation Appendix at Tab 16 and associated figure). Those areas include (a) from the fire station west of Brodie Lane to Deer Lane, toward the Karst Preserve; (b) from the pipeline crossing of Deer Lane to a point just east of the Sendera Creek. LBG-Guyton has recommended that measures be employed to divert surface flow from those features, with the result that in the event of a release that results in surface flow, the features and thus the Edwards Aquifer will not be subject to the potential for rapid infiltration to the aquifer; see LBG-Guyton, Phase Two Project Documentation Appendix at Tab 16. Longhorn commits to employ such measures. Given the relatively low slope of surface topography across the recharge zone, slight modifications during final surface grading will accomplish the goal of protecting the sensitive features. Thus, planning for construction of the replacement pipe will include the requirement that, during final grading, a low swale or berm be created to protect those features. The precise location and design of these surface flow control features are not easily predictable in advance of construction; thus, Longhorn's geological, biological, and engineering consultants (LBG-Guyton, Horizon ESI, Paragon Engineering, Bury + Partners) will make field recommendations to the contractor as reclamation begins. These recommendations will be carried out by the Contractor at the 47 <<>> direction of the on-site Environmental Inspector. Since the Longhorn Pipeline primarily traverses the surface divide between the Williamson and Slaughter Creek drainage areas, little if any surface flow of storm water will be affected, and no adverse effect to aquifer recharge water quantity will occur. Additional analysis has been performed with respect to the recharge and contributing zones. Surface flow modeling has identified surface flow tendencies along the pipeline, and the calculations have been made of time of travel, to the recharge zone or recharge features, of a hypothetical release under worst case stream flow conditions. See Drawing 199044-C2 and LBG-Guyton, "Travel Times for Hypothetical Releases from Longhorn Pipeline within the pipeline Replacement Corridor in Austin, Texas," 2000 in the Project Documentation Appendix. Longhorn has based its emergency response planning on the results of those analyses, resulting in the multiple pre-planned response locations identified in the Travis County and Hays/Blanco sections of the FRP. Multiple pre-planned response locations enable response personnel to identify the optimum response locations for a release along any segment of the recharge and contributing zones. Longhorn also has identified locations across the recharge and contributing zones at which a release of product could fill the trench and reach the surface. At those locations, Longhorn will construct a bermed area that achieves two competing goals: (1) providing containment in the unlikely event of a release that reaches the surface; and (2) preventing the infiltration of storm water to the areas (which could otherwise compromise containment capacity). The areas will be constructed of berms and swales along and/or across the pipeline right-of-way. Storm water will be prevented from entering the bermed areas by the placement of diversion berms. The presently identified locations of potential surface presence of product, and the conceptual design of the bermed areas, is set forth in the "Longhorn Pipeline EARZ/EACZ Pipeline Replacement Trench and Berm Product Containment Conceptual Design" in the Project Documentation Appendix (note that locations #1 and #20 are outside the applicable replacement segment). Longhorn will execute replacement of the pipe section that crosses the recharge zone pursuant to a maintenance construction plan that does not include the segment across the contributing zone (See Tabs 20 and 44 of the Phase Two Project Documentation Appendix). Pipe replacement across the contributing zone shall be executed pursuant to typical project construction plans developed during the Phase One consultation (but including the sealing of identified karst features in the limestone trench; see additional details in the following paragraphs). Longhorn also has committed to replace an additional one-half mile (approximately) of pipe east of the recharge zone. That area has been identified through surface flow modeling as susceptible to seeing surface flows toward the recharge zone and Williamson Creek. All new pipe will be buried to a depth of 5 feet to top of pipe and will be protected by a red concrete barrier. This segment of the project will be executed pursuant to project construction plans containing the same protections as those developed pursuant to Phase One of this consultation. 99144ba2.v8 48 <<>> The maintenance project will employ numerous measures in excess of the maintenance construction procedures described in the Phase One BA, identified specifically and by qualified individuals and entities (See Phase Two Project Documentation Appendix at Tab 13 for resumes of Kreitler, Stein, Sherrod, Bury, and Miller) as protective of the Edwards Aquifer and thus the salamander. The procedures build upon a solid base of construction storm water best management practices (BMPs) that are implemented at every construction site; moreover, Longhorn will implement procedures at least as stringent as locally prescribed construction BMPs. Longhorn will design its construction project to employ the construction BMPs promulgated by the Texas Natural Resource Conservation Commission (TNRCC) for application during construction over the recharge zone. During pipeline replacement, Longhorn will seal any identified karst features in the limestone trench or exposed in the ROW following guidelines established by TRCC. Upon encountering any karst feature during construction, the Contractor and on-site Environmental Inspector will be required to immediately notify Longhorn's geological, biological, and engineering consultants (Sherrod, Miller, Kreitler, Stein, Bose, Bury - see resumes in Phase Two Project Documentation Appendix at Tab 13) who will promptly inspect the field situation and prescribe proper sealing methods to the contractor. _In addition, immediate notice will be made to appropriate representatives of the City of Austin and the Barton Springs/Edwards Aquifer Conservation District who may also provide additional recommendations to Longhorn's specialists on proper sealing procedures. If exceptionally large or deep voids or caverns are encountered, structural engineering specialists will provide engineered recommendations for supporting the pipeline over the void closure (example engineered recommendations encountered 20 and 44 of the Phase Two Project Documentation Appendix ). All void closure recommendations will minimize potential adverse effects to the function of the void (ie., recharge capability or faunal habitat) while providing the maximum seal from the pipeline and any potential releases. Not only does this address potential issues of impacts to species during construction, but also provides significant aquifer protection and product recovery benefits in the event of a release during operation. Pipeline releases should stay within the pipeline trench and at land surface within the ROW where they can be more easily contained and controlled. First, the volume of a spill will be limited by the installation of check valves that reduce spill volume to a probable maximum of 2100 barrels in the recharge zone. Additionally, the APR report (Tab 10 of the Phase Two Project Documentation Appendix) concludes that only about 28% of the line fill capacity between block valves might be released in 90% of the release scenarios. Third, the topography across the recharge zone is relatively flat, and rapid runoff away from the ROW will not likely occur; see LBG-Guyton Addendum Phase Two Project Documentation Appendix at Tab 16. It is anticipated that with the flat terrain and limited spill volume, potential product spills will remain on the ROW of the pipeline where any caves and other karst features will have already been identified and been sealed or protected during pipeline replacement. Longhorn has, however, committed to implement a number of bermed containment areas at locations where it is possible that product could reach the ground surface, and accumulate, in the event of a release (see Sec. 3.5). The bermed areas are designed so that any released product is captured within the trench and is captured if it rises to the 99144ba2.v8 49 <<>> surface. The bermed areas also are designed to prevent storm water infiltration by run-on and to shed storm water through outlets; however, the systems will collect product in the event of a release by means of automatic, hydrocarbon sensing valves. These systems will be designed and built of low-porosity materials but with the integrity to withstand major storm events. The capacity of the bermed areas will be calculated to contain both a worst case release (assuming complete pipe segment drainage) and precipitation generated by a 100-year storm event. Periodic inspection of the locations will be performed in conjunction with regularly scheduled pipeline surveillance patrols. Longhorn commits to perform a field test of both the trench sealing procedure and the berm construction methods in conjunction with the maintenance construction project over the recharge and contributing zones. If the field test identifies design or construction flaws, adjustments to design or construction techniques will be employed to achieve the desired effect. See "Proposal to Perform Field Tests to Verify the Design and Construction of the Pipeline Trench and Berms for the Longhorn Partners Pipeline over the Edwards Aquifer Recharge Zone in Austin, Texas," in the Project Documentation Appendix. As a result of the foregoing measures, the following defenses protect the Edwards Aquifer: 1. New, thicker pipe; 2. Five foot burial depth; 3. Concrete barrier; 4. Enhanced leak detection; 5. Sealing of all voids, fissures, vugs, and other potential recharge features in the limestone trench; 6. Trench backfill absorption enhancement; Surface containment systems and berms; and Enhanced response planning. As described in Section 4.3 below, that risk will be further reduced by implementation of the Edwards Aquifer Protection Plan during construction. 3.7 Hydrostatic Pressure Testing And Proof Testing Longhorn committed to perform hydrostatic pressure tests and proof tests of the pipeline, and those tests have proceeded during 2000. (See Phase One BA at Sec. 4.10 and LMP Items 1 and 2.) Hydrostatic and proof testing of the pipeline has been ongoing, beginning at the Longhorn GATX pump station in Galena Park (Houston) and proceeding westward to Crane Station, but skipping the segments through Houston toad habitat in Bastrop County and the Edwards Aquifer Recharge Zone in Travis County (refer to Phase One BA in the Phase Two Project Documentation Appendix at Tab 1). The hydrostatic and proof testing has occurred in segments, which were subdivided into test sections of varying lengths. Due to sensitive aquatic species concerns, the Houston toad and the Barton Springs Salamander, two test sections were not tested during the overall Houston to Crane testing project. Those two sections are (a) Segment 4, Section 1, which encompasses habitat for the endangered Houston toad and (b) all of Segment 5, which encompasses eastern Travis County, the recharge zone of the Edwards Aquifer and part of the adjacent contributing zone, areas of concern to the endangered Barton Springs 99144ba2.v8 50 <<>> Salamander. Those sections will be hydrostatic pressure tested, after completion of Phase Two consultation and after pipe replacement takes place, to complete the system integrity testing. Procedures for testing will follow those described in the Phase One BA. However, due to the heightened sensitivity of these two locations, project environmental inspectors and spill response equipment will be onsite and in constant ready status for immediate response during the testing. Makeup water for the tests will originate from the Colorado River or from local sources, and other than the potential for small amounts of residual diesel no contaminants are foreseen in the test water. Since most of the tested line sections will be newly installed pipe and since the prior hydrostatic testing will have flushed the pipe that is not slated for replacement, significant contaminants are not expected to be present in the test water. New pipe is expected to contain minimal manufacturing residue. 3.8 Right-of-Way Maintenance ROW maintenance was considered by the Service in Phase One of this consultation with the exception of one area, the Edwards Aquifer recharge zone; see Phase Two Project Documentation Appendix at Tabs 1 and 2. ROW maintenance in the recharge zone will be conducted in the same manner as described in the Phase One BA. In summary, the conservation measures described in the Phase One BA are designed to prevent disturbance of the earth, to preclude sedimentation, and to prevent the release or distribution of herbicides to the environment. 3.9 Corrosion Inhibitor The LC-50 concentrations of Magnacide 575 in the water column for freshwater fish and aquatic invertebrates ranges from 19.4 ppm (ml/I) (Daphnia- 48 hr) to 119 ppm (mg/l) (trout - 96 hr). Reproductive capacity diminution in Daphnia was demonstrated to have an EC-50 of 0.154 ppm (ml/l). No-effect concentrations for this product on fish and aquatic invertebrates was not available. LC-50 concentrations for dermal exposure to terrestrial mammals (rabbit) is 2000 ppm (mg/kg). Surface disturbance for the application of the corrosion inhibitor would be restricted to the seven valve setting sites previously noted. Access to those sites would be from public roads. The mixture ratio for the proposed inhibitor in the pipeline is approximately 3500 to 4000 ppm. These concentrations exceed the LC-50 for aquatic organisms, and are also above the lethal levels for terrestrial organisms. A release of this product in a surface tributary stream could be toxic until such time as dilution in the water body reduces the toxicity below limits. 99144ba2.v8 51 <<>> For listed species, the risk is believed to be very minimal. Terrestrial plants such as the Texas prairie dawn, Navasota ladies-tresses, and Tobusch fishhook cactus have very minimal exposure risk as spilled product on the ground would either be confined very quickly to topographically low areas or absorbed into the soil in a short distance from the pipeline. Surveys conducted for these plant species along the Longhorn ROW (Report of investigations - in progress) by Horizon in response to the requirements of the LMP did not reveal the presence of any individuals of these species within or near the ROW. The Houston toad would also be unlikely to be exposed to a spill if one occurs in Houston toad habitat areas. During the late summer period when the activity is proposed to occur, Houston toads are generally in estivation in deep sand burrows in uplands. Exposure to spilled product would be extremely low probability. Additionally, Houston toad surveys were conducted along portions of the line passing through the designated critical habitat for the Houston toad. No toads where found to occur within or adjacent to the ROW, or downstream (report in preparation). The only exposure avenue for the Barton Springs salamander would be entry of a large volume of the corrosion inhibitor directly into the Edwards Aquifer through a point recharge feature; however, the risk of a release of the corrosion inhibitor is demonstrably nominal as discussed in the following paragraphs. That the risk of a release of the inhibitor is low is based upon the fact that the inhibitor treatment water will be moved through the pipeline at pressures significantly lower than the pressure reached during the recently completed hydrostatic tests. The inhibitor will be propelled by nitrogen injected at a maximum pressure of 285 pounds per square inch gauge ("psig"). At the point of the inhibitor water batches, the pressure will range from approximately 65 psig to 140 psig. In comparison, the hydrostatic tests induced pressures ranging from approximately 1,100 psig to over 1,500 psig. Further, though some segments were not tested (22 miles across Buscher State Park in Bastrop County and 40 miles across the Edwards Aquifer recharge and contributing zones in Travis and Hays Counties), the hydrostatic test water was moved through those segments, and none was lost. The following table compares the minimum hydrostatic test pressures to the maximum treatment pressure. Corrosion Ratio Hydrostatic Inhibitor Hydrostatic Segment/Section' Minimum(psig)? Test Maximum(psig)3 Treatment Inhibitor Test to 2(1802+63 - 4024+50) 1265.0 285 4.4 3 (4024+50 - 5964+47) 1113.0 285 3.9 4-1 (5964+47 - 7110+81) 6504 285 2.3 4-2 (7112+16 - 8004+00) 1113.0 285 3.9 99144ba2.v8 52 <<>> Hydrostatic Corrosion Inhibitor Ratio Segment/Section' Minimum(psig)? Test Treatment Hydrostatic Maximum(psig) Inhibitor Test to 5 (8004+00 - 10163+00) 500° 285 1.8 6 (10163+00 - 12039+37) 1235.0 285 4.3 7 (12360+00 - 14597+72) 1265.0 285 4.4 8 (14606+00 - 16992+40) 1113.0 285 3.9 1 Segments shown are those with threatened or endangered species or habitat in proximity to the pipeline. The pressures shown are test target pressures for segments actually tested; all target pressures were met during the test. Nitrogen will be injected at 285 psig and therefore is used as the maximum; the pressures at the inhibitor batches will be lower, on the order of 65 to 140 psig; This section was not hydrostatic tested, but experience pressures as high as 650 psig (nitrogen) while adjacent sections were tested. This segment was not hydrostatic tested, but experienced pressures as high as 500 psig (nitrogen) while adjacent segments were tested. The above data demonstrate that treatment pressures will be significantly lower than were the hydrostatic test pressures. Since the hydrostatic test pressures were of such higher magnitude, and since the pipeline has been repaired at the few locations of hydrostatic test failures, the risk of a release is extremely low. In addition, regular, ongoing pipeline surveillance is monitoring activity near the pipeline to protect from third party damage that could threaten pipeline integrity. Furthermore, Longhorn will take measures to prevent a release of the inhibitor to the environment. Piping and materials management protocols that will be implemented serve to ensure that the inhibitor is controlled at all times. Nonetheless, spill equipment and supplies necessary to contain and immediately remove a release will be maintained along the pipeline segments as the treatment procedure progresses westward. Finally, a biologist will be maintained on stand-by during treatment across Bastrop, Travis and Hays Counties, in the event of a release that could affect the Houston toad or the Barton Springs salamander, to immediately advise response crews in release response and mitigation. Therefore, no adverse affects to the Barton Springs salamander would be expected. Exposure possibilities for the golden-cheeked warbler or black-capped vireo would be Studies for the presence of the warbler and vireo in the springs of 1999 and 2000 along the ROW did not reveal the presence of either bird species within or in close proximity to the ROW (report in progress). All ground activity associated with this process would be at previously disturbed valve setting locations, none of which are within or near listed species habitat. 99144ba2.v8 53 <<>> The recently completed hydrostatic testing has proven the Longhorn Pipeline to be sound. The corrosion inhibitor solution would be pumped through the pipeline at significantly lower pressures than the hydrotest. Little handling of material is required for the procedure. The risk of a significant spill or release of the inhibitor material in the environment is extremely low. Even if released, exposure or toxicity of the solution would not be significant for any of the listed species. 99144ba2.v8 54 <<>> 4.0 AVOIDANCE AND CONSERVATION MEASURES 4.1 Avoidance Longhorn will conduct pipeline operation, maintenance, construction, testing, and other subject activities in a manner that avoids potential effects to species and habitat. Controls and other measures designed to achieve that goal are described in the foregoing descriptions of the various activities. A number of those controls and measures are summarized as follows: • Full implementation of the Longhorn Mitigation Plan; • Identifying and marking habitat areas for avoidance; • Planning project implementation to avoid the potential for any effects; • Using FERC qualified environmental inspectors with authority to alter project implementation procedures in areas of potential concern to species, including application of incremental BMPs as a result of site-specific conditions; Adjusting project timing to avoid breeding populations; for example, maintenance or construction projects in Houston toad habitat will avoid the months of January through June and projects in golden-cheeked warbler and black-capped vireo habitat areas will be avoided from March 1 through August 1 and March 15 through September 1, respectively; Implementing storm water pollution control BMPs even when not required by permit; Maintaining qualified biologists in hydrostatic test project areas for immediate response in the event of a test water release in a habitat area; Avoiding work in areas of noise-sensitive species (i.e., golden-cheeked warbler and black-capped vireo) during the breeding/nesting season. If work must occur in habitat areas during noise-sensitive seasons, the Service will immediately be notified for additional avoidance procedures. Longhorn's Monitoring Commitment Longhorn has committed to survey the existing ROW to determine the presence/absence of listed species. The following summarizes the Longhorn Monitoring Commitment for each potentially affected species. • Longhorn has completed surveys for the Texas prairie dawn within the potentially suitable habitat areas to confirm its presence or absence. The surveys were conducted within the ROW in areas identified as potential habitat in early April of 2000 to determine if the Texas prairie dawn was present, and if so, its distribution and abundance. No prairie dawn were found, nor was any highly suitable habitat 99144ba2.v8 55 <<>> identified. Longhorn will conduct a fall survey (15 October to 15 November, 2000) for the Navasota ladies'- tresses within the ROW if suitable climatic conditions occur to determine the presence or absence of this species, and if present, its distribution and abundance. For the Tobusch fishhook cactus, Longhorn has conducted a blooming period survey (late February 2000) within the ROW throughout Kimble County to determine the species' distribution and abundance. No cacti were observed. • A spring survey for the Houston toad in Buescher Park was conducted along and downstream of the pipeline to determine the presence or absence of toads and their overall distribution and abundance. No toads were detected in the park. • One to two additional Spring breeding season surveys (as acceptable to the Service) will be conduced for the golden-cheeked warbler along and adjacent to the ROW within the potential habitat areas to determine habitat utilization and overall distribution and abundance. A survey for 2000 was conducted with no golden- cheeked warblers being found in or near the ROW. • One to two additional spring breeding season surveys (as acceptable to the Service) will be conduced for the black-capped vireo along and adjacent to the ROW within the potential habitat areas to determine habitat utilization and overall distribution and abundance. A survey for 2000 was conducted with no black-capped vireos being found in or near the ROW. 4.2 Status of the Species/Environmental Baseline The following is a review of the status of each species being considered in this biological opinion that may be adversely affected by the proposed action. The Service has reviewed the list of threatened and endangered species and identified potential impacts to the following species. Texas prairie dawn (Hymenoxys texana) - The Texas prairie dawn is a small, delicate annual to 6 inches tall with single or branching stems. It has small yellow flowers blooming in late March to early April. It occurs in sparsely vegetated areas of fine-sandy compacted soil. Specifically, the species occurs in the northern part of the Gulf Coastal Prairie in Harris and Fort Bend counties, where it is found in poorly drained depressions or saline swales around the periphery of low, natural mounds (mima mounds) in open grasslands. These mostly barren areas are sparsely vegetated, and the soil is often covered with a blue-green alga (Nostoc sp.). It can also occur on disturbed soils such as rice fields, vacant lots, pastures, and possibly pipeline ROW if the soil structure remains relatively intact. 99144ba2.v8 56 <<>> Kimble Hudspeth Hays • Gillespie ich occur. in counties traversed by Longhorn Pipeline Fayette Ector Page 1 of 2 Cootert Federally-listed Threatened or Endangered Species Blanco: RAD 39117 Species - Federal Classification American alligator: TSA Atwater's prairie-chicken - E Bald eagle - T(PDL?: Barton Springs salamander « Ei Ber Creek Cave harvestman E Bik-cooped vireo E Bone Cave harvestman E Clear Creek sambusia - E Comal Springs dryopid beetle - E Somal Springs diffle beetle - E Comanche Springs pupfish • E ild-buckwheat-T Devil's River Minnow. T rican spotted owe Te Footh Gave <<>> Known or Suspected to Occur Within Area of Potential Effect TSA - Listed Threatened Due to Similarity of Appearance O - Not Likely to Occur Within Area of Potential Effect M - Migrant Not Likely to be Adversely Affected ce of Species: US Fish and Wildlife Service PE - Proposed to be Listed as Endangered FEDERAL CLASSIFICATION PDL - Proposed to be De-listed E - Listed Endangered. T - Listed Threatened Ward Waller TABLE 4 Federally-listed Threatened or Endangered Species which occur in counties traversed by Longliorn Pipeline Upton Page 2 of 2 000z Schleicher Reeves: zOoO Reagan Menard Mason RAD 39118 Speciei - Federal Classificacion low flycatcher - E Smerkan Filigator - TSA Atwater's prairie-chicken • E bald eagle - T(PDL): Barton Springs salamander • E Bee Creek Cave harvestman: E Black capped vireo •E Bone Cave harvestman - E Clear Creek gambusia: E Comal Springs dryopid beetle • E Coral Springs riffle beetle • E Comanche Springs puplish • E Devil's River Minnow - T Fountan darter: E Solden-cheeked warbler - E m wild-buckwheat. T eschmar Cave mold beetle - E: Tooth Cave pseudose ooth Cive spider - E: a crane -E <<>> There are fewer than 35 known sites recorded for the species, and several have been lost in recent years to urbanization in the Houston area. Most populations remaining are small, and are on private land. Very few sites currently have any form of protection. The primary threat to the species is habitat destruction as a result of urbanization, roadway construction, and conversion of habitat for agricultural purposes. An assessment of potentially suitable habitat for the Texas prairie dawn was conducted by Horizon in early June 1999 along the Longhorn pipeline ROW in western Harris and eastern Waller counties from the Satsuma Station on the west edge of Houston to near Monaville in Waller County. Three areas along the ROW, one in Waller County and two in Harris County, exhibited native range conditions with suitable soils that could be considered potentially suitable habitat areas for the prairie dawn. All other areas along the pipeline within the area investigated had been converted to row crop (corn), monoculture hay or grazing pasture, or disturbed for land development. A survey for the prairie dawn has been conducted within the potentially suitable habitat areas during early April 2000 with negative results. Navasota ladies'-tresses (Spiranthes parksii) - The Navasota ladies' tresses was listed as endangered on May 6, 1982, without critical habitat. This member of the orchid family occurs primarily in moist, sandy soils in small openings in post oak savanna vegetation. The species is known to occur in Brazos, Burleson, Fayette, Freestone, Grimes, Jasper, Leon, Madison, Robertson, and Washington counties (USFWS 1984b). Currently, approximately 149 sites have been recorded, representing perhaps 75-80 distinct population areas, predominantly concentrated around two centers of distribution, one in southern Brazos County and one in central Grimes County. Some of these recorded sites have been damaged or destroyed since they were reported. Together these population centers contain the majority of known sites and individuals (Wilson 1993). However, the majority of sites contain fewer than 25 recorded plants. It is known that for this species not all individuals in a population are visible above ground in a given year, and most of these sites have been visited only once, so demographic data on populations is very limited. Nevertheless there is great concern among botanists that most of these sites may not represent viable populations. Navasota ladies'-tresses occur in a variety of moist sandy soils near drainages, in the Post Oak Savannah vegetation associated with the Navasota, Brazos, and Trinity River watersheds. Navasota ladies'-tresses are typically found on erosional remnants between rills in slightly to moderately eroded areas along minor intermittent tributaries, from the upper drainage head, extending along the edges of temporary streams to the flood plain of permanent streams. Navasota ladies-tresses grow on sandy loam soils and are often associated with post oak, blackjack oak, yaupon, slender bigelowia (Bigelowia nuttalli), and Spiranthes cernua. Typical habitat consists of natural openings in upland Post Oak Savanna vegetation (Poole and Riskind 1987, USFWS 1984b, Wilson 1993). Plants are believed to be situated where subsurface flow or seepage of water occurs seasonally, a common feature in other species of the genus (Arft and Ranker 1995, Kathy Parker, pers. comm.). While Navasota ladies'-tresses is found in small naturally created openings in the post oak woodlands, it cannot be regarded as a disturbance species, as it usually occurs in 99144ba2.v8 59 <<>> well developed woodland and is not a colonizer of extensively disturbed areas. There are few records in flood plain forests, open savannahs and shrublands that have experienced little or no grazing pressure, and in hillside seepages. Navasota ladies'-tresses is extremely slow-growing and long-lived. Rosette leaves support the formation of a storage tuber between November and March that sequesters resources in preparation for sending up a leafless bloom stalk at some future time. It is believed that often plants require more than one year of photosynthate storage to successfully send up a bloom stalk. If local conditions have not been favorable for forming sufficient below ground reserves, the plant may not bloom (Wilson 1993). Navasota ladies'-tresses apparently does not transplant well. In a mining project in Grimes county by Texas Municipal Power Association (TMPA), plants in the impact area were removed and transplanted into an adjacent habitat area. Plant survival has been low in most sites (TMPA 1996). Similarly, in an experiment in Lick Creek Park near College Station, Dr. Hugh Wilson planted some seedlings which survived into their second season, but died prior to the third growing season (Wilson 1993). Because of the low numbers of individuals reported from populations, the slow growing nature of the plants, its unusual habitat requirements of openings in mature vegetation, and its sensitivity to disturbance and transplanting attempts, the species is not regarded as being very resilient, and recovery following any damage to a population is expected to be slow. The primary threat to Navasota ladies'-tresses is destruction or modification of habitat due to urbanization, clearing for agricultural production, or mining (47 FR 19539, USFWS 1995, 1984b). Destruction of understory by feral pigs is also a problem in some areas. More than 40 known sites have been lost in the last ten years to mining or urbanization. Post oak savannah in many of these counties continues to be converted to bermuda grass pasture. Subsequently, habitat loss continues, particularly in the areas of Brazos and Grimes counties where most sites are located. The City of College Station in Brazos County is growing rapidly, particularly in the southern and southeastern fringes where most known populations are located. Mining in Grimes County disturbs more than 7,000 acres every 5 years (Wilson 1993). In Fayette County, the species is known from one small population approximately 6 miles south of the pipeline and 2 miles north of the town of Fayette. Based on analysis of soil distribution, vegetative cover, physiographic setting, and field assessment by Horizon in November of 1999, two small areas of potential habitat for Navasota ladies'-tresses are present along the pipeline corridor. Surveys for the species are scheduled to be conducted along the pipeline in October 2000 if suitable climactic conditions occur. Tobusch Fishhook Cactus (Ancistrocactus tobuschii) - Tobusch fishhook cactus is a rounded, biscuit-shaped cacti usually 2 to 3 inches tall and up to 3.5 inches in diameter. There are 3 to 5 central spines with the upper 2 to 3 erect and straight and the lower central spines hooked at the tip and spreading. The plants are very inconspicuous, and produce cream to yellow flowers from February through early April. These cacti have been demonstrated to be obligate outcrossers pollinated by native bees with a foraging distance of about 1/4 mile, and seeds are dispersed by native ants. 99144ba2.v8 60 <<>> Currently about 50 sites are recorded for the species, following a recent range-wide representative survey. Most of the populations are extremely small (5-20 plants), with individuals widely scattered. Known sites are separated by large distances. Most existing populations are on private land, and there are very few protected sites. Demographic data collected in monitoring studies over the last five years or so show that only one of the known populations is even marginally viable. The species is extremely slow growing and does not appear to reproduce until 10-17 years of age. It takes four successful flowers/fruits to produce one seedling (Jackie Poole, Texas Parks and Wildlife, pers. comm.). It is estimated that very few viable populations (10-15) remain over the 8 county range of the species. The survival and recovery of the species will require restoration and careful management, to provide sufficient numbers of populations and individuals in effective proximity to each other for successful pollination (and gene flow) to ensure the continuity of the species. Studies examining the probable reasons for population declines are underway. Threats to the species are believed to include inappropriate timing of range management practices (such as fire and clearing practices that disturb the soil), extensive predation by beetle grubs, loss of habitat to real estate development, and some collection by cactus enthusiasts. An assessment of potentially suitable habitat and pedestrian survey for the cacti was conducted by Horizon in April 1999 along portions of the Longhorn pipeline ROW in Kimble County, and no specimens were observed within the ROW. However, one Tobusch fishhook cactus was observed about 50 feet north of the cleared ROW. An additional survey of the entirety of the ROW through Kimble County was conducted by Horizon in late February 2000 with negative findings for the cactus. However, as a conclusion of the Phase One consultation, in the absence of complete surveys at that time, all of the ROW within Kimble County was considered as potentially suitable habitat and fully compensated. Golden-cheeked Warbler (Dendroica chrysoparia) -The golden-cheeked warbler is a small, migratory songbird, 4.5 to 5 inches long, with a wingspan of about 8 inches. The male has a black back, throat, and cap, and yellow cheeks with a black stripe through the eye. Females are similar, but less colorful. The lower breast and belly of both sexes are white with black streaks on the flanks. Typical nesting habitat is found in tall, dense, mature stands of Ashe juniper (cedar) mixed with trees such as Texas (Spanish) oak, Lacey oak, shin (scalybark) oak, live oak, post oak, Texas ash, cedar elm, hackberry, bigtooth maple, sycamore, Arizona walnut, escarpment cherry, and pecan. This type of woodland generally grows in relatively moist areas such as steep-sided canyons and slopes. A mix of juniper and deciduous trees on the slopes, along drainage bottoms, and in creeks and draws provides ideal vegetation for birds. Warblers are also occasionally found in drier, upland juniper-oak (i.e., live oak, post oak, blackjack oak) woodlands over flat topography. 99144ba2.v8 61 <<>> An assessment of potentially suitable habitat and surveys for the golden-cheeked warbler was conducted by Horizon in April and May 1999 along the Longhorn pipeline ROW from Austin, Texas, to the Mason/Kimble County line. Although no potentially suitable habitat areas were observed within the Longhorn ROW, several areas were located adjacent to the previously cleared permanent ROW. All areas were surveyed by Horizon a minimum of 5 times during April and May on days with favorable weather conditions for bird activity, per U.S. Fish and Wildlife Service guidelines (USFWS, 1994a). Surveys were conducted on 8, 9, 12, 27, 28 April, and 3, 11, 19 May. An equivalent of 4 person-hours per 100 acres were spent at each site, based on habitat size. No golden-cheeked warblers were found to be utilizing any of the potentially suitable habitat areas on or immediately adjacent to the ROW. However, three years of survey are necessary to confirm presence/absence under Service guidelines (USFWS 1994a). Additional surveys for the warbler are under way for the Spring of 2000. Black-capped Vireo (Vireo atricapillus) -The black-capped vireo is a 4.5 inch long, insect-eating songbird. Mature males are olive green above and white below with faint greenish-yellow flanks. The crown and upper half of the head is black with a partial white eye-ring. The iris is brownish-red and the bill black. The plumage of the female is duller than the male. Females have a dark slate gray head. In Texas, vireo habitat is found on rocky limestone soils of the Edwards Plateau, Cross Timbers and Prairies, eastern Trans- Pecos, and, to a limited extent, on igneous soils in the Chisos Mountains. Black-capped vireos require shrub vegetation reaching to ground level for nesting cover. They typically nest in shrublands. An assessment of potentially suitable habitat and surveys for the black-capped vireo was conducted by Horizon in April and May 1999 along the Longhorn pipeline ROW from Austin, Texas to Crane County. Potentially suitable habitat areas were observed within the Longhorn ROW as well as several areas located immediately adjacent to the previously cleared permanent ROW. All areas were surveyed by Horizon a minimum of 5 times during April and May on days with favorable weather conditions for bird activity, per Service guidelines (USFWS, 1994a). Surveys were conducted on April 8, 9, 12, 27, 28, and May 3, 11, and 19. An equivalent of 4 person-hours per 100 acres were spent at each site, based on size. No black-capped vireos were found to be utilizing any of the potentially suitable habitat areas on or immediately adjacent to the ROW. However, three years of survey are necessary to confirm presence/absence under Service guidelines (USFWS 1994a). Additional surveys for the vireos are under way for the Spring 2000. Bald Eagle (Haliaeetus leucocephalus) -The bald eagle is a migrant and winter resident in Texas. The bald eagle was recently down-listed from endangered to threatened due to successful conservation efforts and is now proposed for de-listing. Migrating and wintering bald eagles typically arrive in Texas in November and depart around February. They are found primarily in association with reservoirs, rivers or other large bodies of water where they feed on fish, carrion, and waterfowl. Nesting bald eagles in Texas are found in the eastern portion of the state and along the coastal plain as far south as Calhoun and Refugio counties. No bald eagle nests have been identified near the pipeline ROW, however, bald eagles may occur along major waterways (Brazos and Colorado rivers, or major tributaries with impoundments) downstream of the pipeline corridor. The Federal Register, (Volume 64 No. 128, Tuesday, July 6, 1999; Page 36454) contains a proposed rule to remove the bald eagle from the List of Threatened and Endangered Wildlife in the 99144ba2.v8 62 <<>> Lower 48 States of the United States. Formal delisting is now anticipated to occur in July 2000. Interior Least Tern (Sterna antillarum athalassos) - Premier nesting sites for the interior least tern are salt flats, broad sandbars, and barren shores along wide, shallow rivers. Important breeding habitat characteristics include: (1) presence of bare or nearly bare ground and alluvial islands or sandbars for nesting; (2) availability of food (primarily small fish); and (3) favorable water levels during the nesting season (so nests remain above water). They usually nest on sites devoid of vegetation, but have been found in areas with an average of 11 to 30% vegetative cover, composed of grasses, shrubs, and trees and ranging from 1 to 3 feet in height. Vegetation, if present, is usually located well away from the colony, with the exception of bugseed, eastern cottonwood, and sandbar willow. As natural nesting sites have become sparse, birds have used sand and gravel pits, ash disposal areas of power plants, reservoir shorelines, gravel levee roads, and other manmade sites. The typical nesting period for the least tern in Texas is mid-April to mid- August. While the interior least tern has not been documented along the pipeline corridor, potential habitat for the tern is present downstream of the pipeline along several major waterways including the Brazos, Colorado, Llano, and James Rivers, and Squaw, Beaver, and Sandy Creeks. The seasonal occurrence (Spring and Summer) and potential nesting of least terns is possible in these areas. Barton Springs Salamander (Eurycea sosorum)- The Barton Spring Salamander was listed as endangered in 1997, without critical habitat. The Barton Springs Salamander belongs to a group of related salamanders that are endemic to the Edwards Plateau region of central Texas. All members of this group are obligately aquatic because the adults retain the larval, gill-breathing morphology throughout their lives. The Barton Springs Salamander, formally described in 1993, was first collected from Barton Springs in 1946 and has been found only at the four hydrologically connected outlets of Barton Springs in Zilker Park within the City of Austin (Brune, 1981; Chippindale et. al., 1993). This salamander is a small species, adults reaching 2.5 inches (about 68 mm) in total length with reduced eyes and elongate, spindly limbs indicative of a semi-subterranean lifestyle. Barton Springs Salamanders are found in the flowing, thermally constant water issuing from the spring outlets in association with aquatic macrophytes, leaves and organic debris, and gravel and rock substrates having little silt and sediment deposition. Water from the contributing and recharge zones of the Barton Springs segment of the Edwards Aquifer influences the conditions at Barton Springs. The main threat to the species has been identified as degradation of water quality from future growth and development on the Barton Springs segment of the Edwards Aquifer (Federal Register 62:23385). An expanded discussion of the environmental baseline for the salamander is provided in the Project Documentation Appendix at Tab 22. Houston Toad (Bufo houstonensis) - The Houston toad was listed as endangered in 1970 (Federal Register, October 13, 1970) and Critical Habitat was designated in Bastrop and Burleson counties in 1978 (Federal Register, January 31, 1978). Houston toads are generally brown and speckled, although individual toad coloration can vary considerably. Some may appear light brown, others almost black and they may also have a slightly reddish, yellowish, or greyish hue. Two dark bands extend down from each eye to the 99144ba2.v8 63 <<>> mouth. Their legs are also banded with darker pigment. A variable white stripe streaks along the sides of the toad's body. Their undersides are usually pale with small, dark spots. Males have a dark throat which appears bluish when distended. Adult Houston toads are 2 to 3.5 inches long and like all toads, are covered with raised skin patches that contain chemicals that make the toad distasteful and sometimes poisonous to predators. The toad was eliminated from three counties (Harris, Fort Bend, Liberty) prior to the 1970s due to habitat loss resulting from urban expansion. Although Houston toad populations have been found in nine other counties (Austin, Bastrop, Burleson, Colorado, Lavaca, Lee, Leon, Milam, Robertson), the Service is concerned about the long-term viability of these populations. The small population in Lavaca County has not been seen since its discovery in 1991; the population at the critical habitat site (Woodrow Lake) in Burleson County has not been seen since 1983; and the population in Leon County lies within an expanding residential area. The largest known population of Houston toads occurs within the pine/oak woodland region of Bastrop County. This area also contains federally designated critical habitat. All known Houston toad populations occur along bands of geologic formations that support deep sands. Six populations occur on a band running through Bastrop County northeast to Freestone County. Three other populations occur on another band through Lavaca, Austin, and Colorado counties (USFWS, 1994b). Houston toad habitat consists of rolling uplands characterized by pine and/or oak woodlands (loblolly pine, post oak, blackjack or sandjack oak) underlain by pockets of deep, sandy soils. Because their skin is semi-permeable to water, Houston toads become dormant to escape harsh weather conditions, such as winter cold (hibernation) and drought (estivation). They seek protection during this time by burrowing into sand or hiding under rocks, leaf litter, logs or in abandoned animal burrows (TPWD, 1993). Although Houston toads are typically associated with woodland habitat, they also breed in and migrate across sparsely wooded and cleared areas near woodlands. They may also breed in and traverse areas that do not support deep sandy soils, including clay and gravel substrates, provided these areas are near woodlands underlain by pockets of deep sandy soils. Houston toads breed from January to June, with a peak in February and March. During the breeding season, toads appear to move randomly from one breeding site to another, achieving genetic transfer between populations that may appear isolated, thus creating a metapopulation, an aggregation of smaller populations linked genetically demographically and functioning almost as a single population. Presently, the most reliable breeding sites are stock ponds and similar impoundments, though in wet years breeding may occur wherever sufficient standing water is present. For successful breeding, water must persist for at least 30-60 days to allow egg hatching, tadpole maturation, and emergence of toadlets. Mortality in young is high, due to predation and drying of breeding sites, with significantly less than one percent of eggs laid believed to survive to adulthood (USFWS, 1984a, 1994b, 1995). The Houston toad is vulnerable to extinction primarily due to habitat loss, degradation, and fragmentation. Over the last 50 years, the historic range of Houston toads has contracted and several populations have been lost. Threats include expanding urbanization and conversion of woodlands to agricultural production areas, such as coastal bermuda pastures, use of fertilizers and pesticides that impact the toad directly or its food supply, 99144ba2.v8 64 <<>> and loss of suitable breeding habitat because of alterations in watershed drainages and wetland alterations or destruction (such as degraded water quality, draining/filling of wetlands, stocking with predatory fish, etc.). Since Phase One of the Longhorn Pipeline project involved the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities included long-term habitat protection for the Houston toad, the • Service concluded that Phase One of the project would provide a net conservation benefit for this species. According to the Houston Toad Recovery Plan (USFWS 1984a), Houston toad breeding sights have been recorded in Buescher State Park south of Longhorn Pipeline. Houston toads have also been heard chorusing on the adjacent property owned by the University of Texas to the north of Buescher State Park and Longhorn Pipeline (USFWS, unpublished data). Dr. James R. Dixon of Texas A&M University conducted a survey along the Longhorn Pipeline ROW and adjacent Phillips EZ Pipeline ROW in 1991 with negative results, although areas of potential habitat were noted (Horizon 1991). Horizon Environmental Services, Inc. conducted a reevaluation of suitable habitat along the Longhorn Pipeline ROW within Bastrop County. The field reconnaissance was conducted on 2 June 1999 from the Colorado River, southeast of Bastrop, to FM 2104. Portions of the area along the pipeline had recently been cleared and planted in improved grasses. Based on field observations and discussions with the Service, two areas of suitable habitat were identified along and adjacent to the pipeline ROW. One area includes Buescher State Park from approximately 0.5 mile east of the eastern boundary of the park westward to near Highway 71. The second area begins about 500 feet to the west of FM 2104 and extends westward approximately 0.75 mile. The drainages in both of these areas flow south toward the Colorado River. A breeding season survey of the habitat areas in Buescher State Park has been conducted by Horizon during February and March of 2000 with negative results. Comanche Springs Pupfish (Cyprinodon elegans) - The Comanche Springs pupfish seldom exceeds 2 inches in total length. It is gray-green above and pale yellow to white below, with clear to light orange fins. The sides are silvery white with blue-black blotches forming a "stripe" along the side (often faint on the male). Males have black speckling on the side and a black edge on the caudal (tail) fin. Historically, this pupfish occurred in 2 separate spring systems of the Pecos River drainage. One was Comanche Springs, with headwaters (now almost always dry) within the city limits of Fort Stockton, Texas, and the other was a group of springs near Balmorhea. The pupfish population at Comanche Springs were extirpated (lost) when the springs first went dry in 1955. At present, the species occurs primarily in aquatic habitat fed by springflow from Phantom Lake, Griffin, and San Solomon Springs near Balmorhea, Texas. The Longhorn Pipeline is not within the sub-watersheds of these springs where the pupfish occur and groundwater contamination from product releases that would affect the springs is extremely unlikely (Dr. Charles Kreitler, personal communication). Therefore, this species is not likely to be adversely affected, but is addressed herein for information purposes only. Pecos Gambusia (Gambusia nobilis) - The Pecos Gambusia is a small (2-inches long), live-bearing fish with a dark lateral stripe and a metallic gray-blue color. Females have a 99144ba2.v8 65 <<>> black area on the abdomen that surrounds the anal fin and anus. The anal fin of males is modified into a gonopodium, a tube-like structure used in fertilization of the female. Historically, the Pecos Gambusia was restricted to the Pecos River basin in southeastern New Mexico and western Texas. The species occurred from as far south as Fort Stockton, Texas to as far north as Fort Sumner, New Mexico. The populations of Pecos Gambusia that once existed at Leon Spring and Comanche Springs were lost when these springs went dry during the mid-1950s. Presently in Texas, populations of the Pecos Gambusia occur near Balmorhea in aquatic habitat supported by springflow from Phantom Lake, Griffin, San Solomon, and East Sandia Springs. A substantial population also occurs in Leon Creek and in Diamond-Y Spring outflow north of Fort Stockton. The species also occurs in a limited number of locations in New Mexico. The Longhorn Pipeline is not within the sub-watersheds that support the Pecos Gambusia and groundwater contamination that would affect any of the spring habitats is extremely unlikely (Dr. Charles Kreitler, personal communication). Therefore, this species is not likely to be adversely affected, but is addressed herein for information purposes only. Devils River Minnow (Dionda diaboli) - The Devils River minnow is a small fish, with adults reaching sizes of 1.0 to 2.1 inches standard length. The fish has a wedge-shaped caudal spot and pronounced lateral stripe with double dashes extending through the eye to the snout but not reaching the lower lip. The species has a narrow head with prominent dark markings on scale pockets above the lateral line that produce a crosshatched appearance when viewed from the top. General habitat associations for Devils River minnow have been described as channels of fast-flowing, spring-fed waters over gravel substrates. Although the species is closely associated with the stream, rather than in the spring outflow itself. The known historic range of the species includes the Devils River from Beaver Lake downstream to near its confluence with the Rio Grande and four other tributaries of the Rio Grande River not associated with the Devils River. The current distribution of Devils River minnow is at 2 sites on the Devils River, 2 sites on San Felipe Creek, and 1 site on Sycamore Creek (US Fish and Wildlife Service, 1998). The Longhorn Pipeline ROW crosses the northern most extent of the Devils River watershed, in excess of 100 river miles upstream from known populations of the minnow. At this distance, it is unlikely that released product would reach the population areas of the minnow in quantities to be toxic (James Miertschin, personal communication). This species is also unlikely to be adversely affected, but is included herein for informational purposes. Southwest Willow Flycatcher (Empidonax trailii extimus) - The southwest willow flycatcher occurs in riparian woodlands along streams and rivers in Hudspeth, Culberson, and El Paso counties. Specific localities of this species in the vicinity of the pipeline are not known. It is possible this species could occur along the Pecos and Devil's rivers downstream of the pipeline. This species would not likely be directly affected by any activitiy associated with the pipeline. However, this species utilizes riparian woodlands that could be affected by a major release of product in a waterway. The methods for assessment of such a potential, but unlikely, event are addressed in section 3.4. 99144ba2.v8 66 <<>> 4.3 Effects of the Actions Pipeline Operation Normal operation of the pipeline is not expected to result in any adverse effects to listed species. There is a risk of an accidental release from the pipeline-a risk Longhorn has significantly minimized through various pipeline mitigation measures. Many of these pipeline mitigation measures were developed directly as a result of consultation with the Service, in order to significantly minimize the risk of a spill near listed species, such as the pipe replacement in Buescher State Park and the replacement of 19 miles of pipe over the Edwards Aquifer recharge and contributing zones. The occurrence of a pipeline release is so unlikely as to be improbable; see APR report, Project Mitigation Appendix at Tab 10. Recognized pipeline experts have concluded that the implementation of the LMP will enable the Longhorn Pipeline to operate at the highest reasonable level of safety attainable by current technology; see APR report at Tab 10 of the Phase Two Project Documentation Appendix. Kiefner & Associates, Inc. (Kiefner) performed an audit of the Longhorn pipeline segment between Houston and Crane (Tab 23 in the Phase Two Project Documentation Appendix). Keifner concluded that the pipeline was safe to operate, even prior to the EA, so long as certain recommendations were followed. Longhorn has committed in the LMP to implement all of Kiefner's recommendations. Kiefner further reported on the safety of the pipeline system as it will stand after implementation of all EA pipeline mitigation measures. Among Kiefner's conclusions: Hydrostatic testing is the most important and positive way of proving that a pipeline is fit for service; the 2000 hydrostatic and proof testing will remove any doubts about the remote possibility that defects may have arisen since the 1995 hydrostatic test • After the pipeline is placed into service, better technology than hydrostatic testing will be used to assure that no defect develops or grows in service to the point where a service failure results • "Smart-Pig" technology will be utilized by Longhorn to locate and characterize anomalies that may represent... time-dependent developing defects Longhorn has taken the unprecedented step of committing to limit surge pressures to no more than the maximum allowable operating pressure (MAOP) in sensitive and hypersensitive areas... providing an extra margin of safety in the critical areas Longhorn's pipeline surveillance programs will "go a long way" to preventing excavation or construction activities from encroaching on the pipeline and possibly damaging it The new pipe in the Edwards Aquifer recharge zone "reduces the already low risk of failure from corrosion and excavation damage," providing an extra margin of safety • "The proposed operation of the pipeline does not create in my opinion, an 99144ba2.v8 67 <<>> unreasonable risk" See Kiefner & Associates, Inc., January 13, 2000, Phase Two Project Documentation Appendix at Tab 23. Further, APR Companies, a company that specializes in pipeline accident investigation, has concluded that the Longhorn Pipeline will benefit from a significant reduction in release probability; see Phase Two Project Documentation Appendix at Tab 10. APR (reference Tab 10 in the Phase Two Project Documentation Appendix) has determined that the average probability of a release (1 in 1000 years per mile) is significantly improved for the pipeline in general through implementation of the LMP with a resulting 2 to 5 times reduction in spill probability. For the Edwards Aquifer recharge zone, the likelihood of a release is reduced 5 to 10 times with implementation of extensive LMCs for that area. A resulting probability for a release then becomes 1 in 5,000 to 10,000 years per mile. APR further estimates the potential worst-case spill scenario for the Edwards Aquifer recharge zone. An earlier estimate approximated 5000 barrels of product released in a major incident. Placement of a single check valve at or near mile post 171 within the recharge zone limits the maximum line fill volume that could spill to 2088 barrels. However, APR's analysis also takes into consideration other factors that influence line drain down such as intervening topographic lows that will hold pipeline contents. Based on detailed analysis of the topography along the line through the recharge zone, and average per unit line drain downs from independent statistics, the probable worst-case spill volume would be only about 1147 barrels in 90% of the potential spill scenarios and 841 barrels in 75% of potential spill scenarios. Longhorn nonetheless has designed the replacement pipeline and emergency response capability on the basis of unqualified worst case release volumes. LBG-Guyton (reference Tab 16 in the Phase Two Project Documentation Appendix) has developed a risk analysis for the Barton Springs Salamander based on the probable worst- case spill volume combined with the measures to be implemented to prevent or minimize released product entry to the aquifer, such as sealing voids in the pipeline trench and grading surface drainage within the ROW to direct any surface flow away from identified point recharge features. Bermed areas at lower elevations will serve to capture product that reaches the surface in those low areas. Their analysis concludes that product concentrations that might reach the aquifer, and ultimately Barton Springs, would be on the order of 0.2 to 0.002 ppb. Concentrations in the water column would be even less (in the absence of MTBE; see Kreitler at Tab 16 and LMC 35). These levels are at nearly an order of magnitude lower than measured levels of petroleum hydrocarbons found in the aquifer and at Sunken Gardens Spring in the past (see Tab 22 in the Phase Two Project Documentation Appendix). Biotoxicological information assembled from existing literature and agency file sources for salamanders (and other aquatic vertebrates), and their prey base (aquatic invertebrates), indicate that concentrations of toxic product constituents (BTEX) in the water column in the ppb range are generally below the "no effect" levels for most organisms (Horizon, 2000). From the above analysis, levels of benzene reaching the springs would be in the 0.010 ppb 99144ba2.v8 68 <<>> (ug/l) range, while toluene would be in the 0.014 ppb range. Horizon reports that EPA data indicate acute toxicity to freshwater aquatic life, for benzene, occurs at about 5,300 ug/l (ppb), while for toluene, the acute toxicity level is about 17,500 ug/ (ppb). The EPA information notes that more sensitive species would have lower acute toxicity levels. However, from the available information, concentrations reaching the springs under the above scenarios would conservatively be several orders of magnitude lower than toxic concentrations. The LBG-Guyton analysis assumes that all or most of the probable worst-case spill volume would reach the aquifer. From prior spill experience with the Longhorn (under previous ownership) and Shell pipelines over the aquifer (1986 and 1987 incidents), 91 to 97 percent of the spilled product (west Texas crude with a similar viscosity to some refined products) was recovered at the surface. Those recovery volumes were in the absence of the void sealing and surface contouring Longhorn will implement to further enhance product recovery. Furthermore, modeling analyses by Rose (1986) and Ross (2000) indicate that soil retention capacity of spilled petroleum product over the Edwards Aquifer recharge zone would be in the range of 350 to 1600 barrels if spread over a 1 to 2 acre area with average soil depth of 0.33 to 1.5 feet. This absorption capacity, combined with high evaporation rates for refined products, and the potential for high levels of product recovery would significantly, if not totally, reduce or eliminate the quantity of product that might reach the aquifer, and ultimately Barton Springs. The 1986 and 1987 incidents resulted in spills of 2245 barrels and 1139 barrels, respectively (in the absence of a block valve). The 1986 spill resulted in hydrocarbon fumes in caves in the vicinity, but no documented adverse effects to the salamander or the aquifer. Under the above-described scenario of a probable worst-case spill for the Longhorn Pipeline (with extremely low probability of occurrence), it is unlikely that adverse effects to the salamander would result as a result of the enhanced Longhorn mitigation measures. In addition to those facets of system operation that limit potential consequences by minimizing release volumes and ensuring a rapid and effective response to a release, Longhorn's emergency response capability will be increased significantly through the LMP. Longhorn will ensure a maximum response time (a) of 1 hour in the recharge zone and Slaughter Creek watershed in the contributing zone; (b) in the Barton Creek watershed in the contributing zone and in other EA designated sensitive and hypersensitive areas of 1 hour to 2 hours; Longhorn will provide for the establishment of a response center in Central Texas, to be located in South Austin, to make certain that manpower and equipment is always at the ready. Prior experience has demonstrated an average response time of 58 minutes (see Tab 24 in the Phase Two Project Documentation Appendix). Once on-scene, the response crews will have the advantage of thorough and detailed information relating to any area along the pipeline. Longhorn has commissioned the preparation of detailed studies of numerous facets of the pipeline ROW, and surrounding areas, to prepare its response crews in advance, if ever necessary. The information developed and advantages gained as a result of the studies includes the following: Species habitat: Response personnel will have the information necessary to avoid 99144ba2.v8 69 <<>> species habitat areas during response and prioritize protective activities in the event of a release in or near a habitat area • Topography: Advance knowledge of area topography allows advance planning for both release drainage potential and control and capture locations • Rivers and streams: Detailed planning has identified waterways at risk and advantageous protective and control locations • Water wells: Both public and private wells are mapped so that responders may prioritize drinking water supplies for protection • Known karst features: Particularly within the Edwards Aquifer recharge zone, advance knowledge of karst features provides information that allows responders to prioritize protection of the aquifer and thus the Barton Springs Salamander • Surface drainage potential: Flow modeling provides knowledge of the potential for released product to flow overland, enabling responders to identify likely scenarios relating both to habitat areas and to human health and safety issues; responders will also have the ability to identify preemptive control and capture locations; surface containment systems are designed to capture any release that reaches the ground surface Longhorn has synthesized this information into stand-alone maps (See Project Documentation Appendix) and in its FRP; further, responders will be trained to use such information during training and during table-top and live drills. Where a potential release might affect listed species or habitat, the precise level of impact cannot be predetermined due to the large number of variables at any given location. As a result, any such attempt at prediction is likely to result in an inaccurate estimate. Accordingly, Longhorn proposes to adopt a contingent methodology for calculating any such effects. This methodology should be useful in the event there is a release from the Longhorn pipeline but neither the Clean Water Act nor the Oil Pollution Act applies to the incident. In such a case, and if Longhorn is liable for the damage, Longhorn will use the Habitat Equivalency Analysis methodology to determine the amount of compensation for which Longhorn is responsible. Longhorn proposes using a methodology that is capable of assessing natural resource damages, preferably the Habitat Equivalency Analysis (HEA) methodology developed by the National Oceanic and Atmospheric Administration (NOAA). HEA is briefly described below. A more detailed description of the HEA methodology is provided in Phase Two Project Documentation Appendix at Tab 25). Pursuant to the HEA methodology: • The duration and extent of injury are documented and estimated from the time of injury until the resource recovers to baseline. 99144ba2.v8 70 <<>> • The services provided by a compensatory project are documented and estimated over the full lite of the project. • The size of a compensatory project is calculated such that the total increase in services provided by the compensatory project equals the total interim loss of services due to the injury. • The cost of the compensatory project is calculated. Other methods exist for assessing natural resource damages under NOAA's regulations governing Natural Resources Damages Assessments for oil spills pursuant to the Oil Pollution Act of 1990 (OPA). 33 U.S.C. § § 2701 et seq. These methodologies may prove more cost-effective than the HEA method and should be considered as well. In the event of an accidental release from the pipeline in or near habitat for listed species, an adverse effect could occur. The level of potential take is impossible to predict in advance. Long-term Maintenance In general, most long-term maintenance is unlikely to result in any adverse effects to listed species beyond those addressed in the Phase One consultation. The majority of long-term maintenance involves ROW maintenance, above-ground facility upkeep, and periodic pipeline testing. These activities were addressed in the Phase One consultation and compensated accordingly. Certain maintenance activities may, however, require construction or land disturbance beyond the existing ROW. Such events are not presently determinable. In the event any such maintenance should necessitate access or construction within listed species habitat, the previously utilized Phase One BA maintenance construction procedures (see •Phase One BA in the Phase Two Project Documentation Appendix at Tab 1) will be followed under the direction of FER qualified environmental inspectors. To the extent feasible, all construction activity will be restricted to the existing ROW within habitat areas, which was fully compensated during Phase One of this consultation. If construction must exceed the ROW in an area of potential habitat, the Service will be notified in advance and additional compensation, as required, will be calculated and provided pursuant to the conditions set forth in the Phase One BA for the given species, to the extent a specific location has not previously been compensated for off-ROW impacts. An additional area of potential Houston toad habitat has been identified in Austin County since the Phase One consultation was completed. This habitat area is within the geologic formation known to support two small Houston toad populations in Austin County approximately 8 miles south of the pipeline corridor and other small populations in Colorado and Lavaca counties further to the south. This area is characterized as patchy woodlands approximately 3000 acres in extent surrounded and interspersed by improved grazing pastures, and with marginally suitable soils (loamy fine sands less than 24 inches deep) (SCS, 1984). The known populations of toads occur in the Catilla-Tremona soil association which is comprised predominantly of sandy soils (SCS, 1984). The potential habitat area 99144ba2.v8 71 <<>> occurs in the Tabor-Tremona-Chazos association which is comprised of loamy and sandy which are not favorable for Houston toads (SCS, 1984). Surveys of this area for the soils. The two associations are separated by several miles of clayey and clayey loam soils Houston toad are not known to have been conducted in the past. A breeding season survey is planned for spring of 2001. The pipeline ROW through this area traverses approximately 12,000 linear feet (2.3 miles). The existing 50 ft wide ROW, therefore, occupies 13.8 acres. This area could be adversely affected by maintenance of the ROW and is being addressed through the Phase One consultation. Emergency Response Potential impacts from an emergency response action could be highly variable depending on location, season, site characteristics, spill characteristics, and type of equipment needed to respond to a particular situation. Training of emergency response personnel will be conducted to make them aware of species related issues, designated potential habitat areas, and avoidance procedures. Avoidance of impacts will be achieved to the greatest extent possible under any given emergency situation. However, control and containment of a product release or fire will constitute a priority, and some level of impacts to designated potential habitats could occur. Impacts could occur from clearing or grading to gain access for emergency response equipment, building temporary containment structures outside of the established ROW, or to remove contaminated soil and vegetation. If fire containment is necessary, fire breaks may need to be dozed in advance of a fire. These activities could result in direct or indirect impacts to potential habitat Such impacts would be assessed and mitigated in the same manner as described previously under the Pipeline Operation section above. Construction Buescher State Park (Houston Toad): Construction of the replacement and lowering projects within Buescher State Park will be contained within the existing 50 ft ROW, and/or within the previously cleared ROWs of the other two adjacent pipelines. No clearing beyond the limits of the existing ROWs will be conducted. Compensation based on the extent of existing Longhorn ROW through Houston toad habitat was provided in the Phase One consultation. Therefore, no additional impacts or compensation are required for this construction. A breeding season survey for toads in the vicinity of the pipeline has been completed, and no toad breeding activity was identified. However, special procedures will be implemented for avoidance prior to and during construction to ensure no adverse effects occur to the toad. Prior to any land disturbance, the construction zone will carefully be inspected by qualified biologists to ascertain the possible presence of Houston toads. The construction zone will then be completely encircled with silt fence (set into the ground) to preclude Houston toads from entering the work space. The construction zone will be inspected periodically by the biologists to ensure Houston toads have not entered the area. Therefore, this construction is unlikely to result in adverse effects to the Houston toad or designated critical habitat beyond those addressed and compensated for in the Phase One consultation. Edwards Aquifer Recharge Zone (Barton Springs Salamander): As described in Section 3.5, a 3-mile segment across the aquifer recharge zone will be replaced with 99144ba2.v8 72 <<>> heavier wall pipe for enhanced safety and integrity. Approximately one-half mile will be replaced immediately east of the recharge zone. The new pipe will also be lowered for greater depth of cover to minimize the potential for third-party strikes. Further, a concrete barrier will be installed over the pipeline to protect the pipeline from third party intrusion; the barrier will be constructed with colored reinforced concrete to increase its deterrent effect. A number of other safety and integrity enhancement measures will also be installed, including a sensor-based leak detection system and additional check valves. All these enhancements will significantly reduce the potential for releases and potential release volumes in the unlikely event of a pipeline release. Longhorn hereby provides to the Service mill certificates for the pipe that will be installed, along with Construction Specification CS4, the specifications that identify methods and procedures for pipeline construction; see the accompanying Phase Two Project Documentation Appendix at Tabs 26 and 27. The construction to accomplish these enhancements will involve deepening the existing trench. Construction will occupy an average work space of 60 feet wide along the 3-mile route. This construction space has been investigated for karst features and other sensitive environmental resources. A detailed Edwards Aquifer Protection Plan has been developed for the project that includes the implementation of all required best management practices (BMPs) using as guidelines the City of Austin Land Development Code specifications and the TNRCC Edwards Aquifer Rules for construction over the recharge zone (Phase Two Project Documentation Appendix at Tab 28). Detailed construction plans will be developed to identify both the design and location of water quality control structures, as well as non- structural BMPs; those plans, which are currently under development, will be made available to the Service upon preparation of reasonably complete draft documents. The environmental protection plan also provides for FERC qualified environmental inspectors to be onsite during the construction process to continuously review and evaluate the efficiency of the recommended BMPs and to make changes as needed for maximum environmental protection. The environmental inspectors will also react to any encounter of subsurface voids by immediately notifying project geological and biological experts for evaluation of the situation and to make recommendations for remedial actions. Remedial actions will, at a minimum, comply with TRCC guidelines for closure of subsurface voids. All encountered limestone voids, regardless of size, will be appropriately sealed within the construction trench. This will prevent potential siltation into the aquifer via such voids during construction, as well as provide additional protection from aquifer contamination in the unlikely event of a product release during operation of the pipeline. In the event a large void is encountered, geotechnical engineers will also be involved in evaluating and recommending remedial actions. The City of Austin, TRCC, Barton Springs/Edwards Aquifer Conservation District, and the Service will also be notified and informed of recommended remedial actions. The trench has been designed with high porosity containment capacity and bermed areas at locations where product could reach the surface. With the implementation of the Edwards Aquifer Environmental Protection Plan, the construction across the Edwards Aquifer recharge zone is not expected to result in any significant adverse impacts to the aquifer or the Barton Springs Salamander. Edwards Aquifer Contributing Zone (Barton Springs Salamander): As described in 99144ba2.v8 73 <<>> Section 3.5, approximately 15 miles of pipe in the contributing zone will be lowered and replaced, and a check valve will be installed immediately downstream of the existing block valve over the contributing zone (MP 175.5), even though the replacement is not necessary (See "Edwards Aquifer Contributing Zone Protections" in The Project Documentation Appendix). The replacements will be installed using heavier wall pipe than exists at this time and will be lowered at least 5 feet below the ground surface. Construction over the contributing zone will be conducted pursuant to the methods and procedures outlined in the Phase One BA. The heavier, deeper pipe will reduce the risk of a release across the contributing zone. The trench has been designed with high porosity containment capacity and bermed areas at locations where product could reach the surface. The check valve will reduce potential release volumes by immediately stopping flow upstream, in the event of a release east of the block valve; as a result, the potential for drainage from higher-elevation segments to the west of the check valve is eliminated during the time required for the block valve to close. Moreover, at the Cedar Valley pump station, which is located in the contributing zone upgradient of the pipeline crossing of Barton Creek, Longhorn has committed to install secondary containment (LMC 27) and a remote monitoring camera (LMC 21) before project startup. The secondary containment will provide protection to Barton Creek, and remote cameras allow monitoring by the pipeline controllers. Furthermore, the host of pipeline mitigation measures directed to Tier Il and III areas will apply over much of the contributing zone, including hydrostatic pressure and proof testing, enhanced leak detection, frequent patrols, cathodic protection system testing, in-line inspection shortly after startup, surge pressure protection, and the establishment of a response center in South Austin. See Section 3.4, Emergency Response. 4.4 Planned, But Unscheduled Construction As described in Section 3.0, several additional improvements to the pipeline are planned to take place, but have not been specifically designed or scheduled at this time. While many of these improvements are located at existing above-ground facilities (valves, pump stations, etc), the exact location and construction details are not yet known. It is believed that the majority of these additional improvements will not occur in potential habitat areas, but if so will not adversely affect listed species habitat, or can be designed to avoid habitat areas. In the event any such improvements should necessitate access or construction within listed species habitat, the previously utilized Phase One BA maintenance construction procedures (see Phase Two Project Documentation Appendix at Tab 1) will be followed under the direction of FERC qualified environmental inspectors. To the extent feasible, all construction activity will be restricted to the existing ROW within habitat areas, which has been fully compensated. If construction must exceed the ROW in an area of potential habitat, the Service will be notified in advance, and additional compensation, as required, will be calculated and provided according to the procedures set forth in the Phase One BA for the given species, to the extent a specific location has not previously been compensated for off-ROW impacts. 4.5 Future Additional, But Currently Unforseen Construction As described in Section 3.0, at various, but unpredictable, times and places in the future, certain construction activities may be required for maintenance, repair, or testing of the 99144ba2.v8 74 <<>> pipeline or attendant facilities. The majority of these future construction activities can be designed to avoid any adverse effect to listed species to the extent the activities occur within potential habitat areas. In the event any such construction should necessitate access or disturbance within listed species habitat, the previously utilized Phase One BA maintenance construction procedures (see Phase Two Project Documentation Appendix at Tab 1) will be followed under the direction of FERC qualified environmental inspectors. To the extent feasible, all construction activity will be restricted to the existing ROW within habitat areas, which has been fully compensated. If construction must exceed the ROW in an area of potential habitat, the Service will be notified in advance, and additional compensation, as required, will be calculated and provided pursuant to the conditions set forth in the Phase One BA for the given species, to the extent a specific location has not previously been compensated for off-ROW impacts. 4.6 Bays and Estuaries The Longhorn Pipeline is in proximity to the Galveston/Trinity Bay system where it passes through Houston. All surface drainage in the Houston area crossed by the Longhorn Pipeline drains to the Galveston/Trinity Bay system ultimately through Buffalo Bayou and the Houston Ship Channel. Bay systems along the Texas coast, including the Galveston/Trinity Bay system, are documented to support a number of listed threatened or endangered sea turtles and marine mammals. Possible concern could exist in the event of a catastrophic release event that product could reach the bay system in sufficient quantities to be toxic or detrimental to those listed species. Several factors are to be considered in this situation that result in an extremely low probability for significant quantities of product to be released in a tributary or waterway that would have direct inflow to Galveston and Trinity Bays. First, the Longhorn Pipeline is buried very deep at the various waterway crossings in north Houston, such as Greens Bayou (24 feet), Hunting Bayou (25.2 feet), ditch north of Hunting Bayou (33.1 feet), ditch south of Hunting Bayou (28 feet), and others (See depths of cover in Project Documentation Appendix). This significant depth greatly reduces the potential for third party strike. Second, most of the area through east and north Houston is ranked as Tier 2 or 3 zones, thus being subject to the enhanced LMP provisions for Sensitive Areas, and Hypersentitive areas. Additionally, all the tributaries drain to Buffalo Bayou and the Houston Ship Channel. Due to the large number of chemical, refining, and industrial facilities situated along the Houston Ship Channel, there exists in place a comprehensive spill response system and equipment to respond quickly to spills of any nature that occur in the channel. It is unlikely that a significant spill from the Longhorn Pipeline would occur in a sensitive drainage area, or would escape the Houston Ship Channel containment into the bays. 4.7 Summary of Conservation Measures 99144ba2.v8 75 <<>> The following provides a summary of the avoidance and conservation measures that Longhorn commits to provide. These measures are assured by the mandates of this consultation and the overall NEPA process simultaneously ongoing with this consultation. The implementation of these conservation measures for listed species assure that the project will be unlikely to result in jeopardy or adverse modification of critical habitat for any listed species and is not likely to adversely effect species or habitat. Many of the mitigation measures of the Longhorn Mitigation Plan which were designed prior to the Phase One or Phase Two consultation processes were intended to provide protections for listed species, either directly or intrinsically. While all LMP features provide significant safety and integrity enhancements for the pipeline as a whole that ultimately benefit species protection, those described below provide specific enhancements which will avoid potential impacts to listed species. Most of these features were incorporated into the LMP prior to finalization of either of the consultation processes. • LMCs 3, 5, 34 - Pipe replacement and lowering over the Edwards Aquifer recharge and contributing zones, with trench and surface containment areas (Barton Springs Salamander), Buescher State Park (Houston toad), Pedernales Falls State Park (golden-cheeked warbler), and other locations in species habitat areas; • LMC 22 - Analysis of, and if necessary, installation of additional valves to limit potential release volumes (all species); • LMC 13 - Addition of an enhanced pipeline leak detection system with additional sensor-based leak detection over the recharge zone and slaughter creek watershed in the contributing zone (all species); • LMC 20 - Increased pipeline surveillance in EA designated sensitive and hypersensitive areas and daily pipeline surveillance across the recharge zone (at least once per week on-ground) (all species); • LMC 23 - Establishment of a fully equipped Emergency Response Center in South Austin (Barton Springs Salamander and Houston toad): • LMC 28 - Revised Facility Response Plan to incorporate features of the City of Austin Barton Springs Oil Spill Contingency Plan and the U.S. Fish and Wildlife Service's Barton Springs Salamander Recovery Plan as well as detailed response planning based upon analysys of stream flow potential in the Edwards Aquifer recharge and contributing zones. (Barton Springs Salamander); • LMC 33 - Establish a refugium for the Barton Springs Salamander and performance of other conservation measures for listed species as may be determined appropriate through consultation with the U.S. Fish and Wildlife Service (all species); • LMC 27 - Provide secondary containment around the Cedar Valley pump station which lies within the Barton Springs/Edwards Aquifer contributing zone. 99144ba2.v8 76 <<>> • LMC 35 - Longhorn has committed that it will not transport products containing MTBE or similar aliphatic ether fuel additives in greater than trace amounts; Though not a specific mitigation commitment, Longhorn has identified all potential areas of concern for listed species along the pipeline corridor from Houston to El Paso for purposes of assessment and avoidance. An additional intrinsic benefit of increased patrol frequencies (LMC 20) is the result that increased inspection and surveillance of the Longhorn Pipeline will enable inspection personnel to coincidentally observe the adjacent pipelines that parallel the Longhorn pipeline. This will provide the opportunity for identification of pipeline emergency situations and threats to the integrity of those pipelines with greater frequency than currently is the case. In fulfillment of LMC 33, Longhorn has committed to a significant number of additional mitigation features specific to listed species developed during the Phase One and Phase Two consultation processes. These commitments become binding as a result of the conclusion of the consultation processes and issuance of the Service's Biological Opinion, and as incorporated into the LMP as it evolves during the EA process. These measures have been developed during the two phases of consultation through discussions between Longhorn, EPA, DOT, and the Service. These commitments are listed below by consultation phase. Phase One • Provision of conservation funding for potentially affected species in the approximate amount of $992,448 (all species). • Monitoring studies of listed species within or adjacent to the ROW (all species). • Minimization of maintenance construction work space in potential species habitat areas (all species). • Seasonal timing of maintenance activities to avoid critical breeding, nesting, or blooming periods for listed species (all species). • Use of special mowing/clearing processes and equipment in potential species habitat areas to minimize ground disturbance (all species). • Provision of FERC qualified environmental inspectors during maintenance activities within potential species habitat areas (all species). • Use of native grasses for restoration of disturbed areas during maintenance activities (all species). • Minimization of the use of herbicides for maintenance purposes (all species). 99144ba2.v8 77 <<>> Phase Two Detailed topographic and surface flow modeling to enhance spill response planning efforts (all species). Special investigative, preparation, and construction practices and techniques for pipe replacement over the Edwards Aquifer Recharge Zone (Barton Springs Salamander) including: Intensive geological and biological field studies of the pipeline corridor to Identity sensitive teatures and areas, including ground penetrating radar, geotechnical coring, karst identification, geological and biological investigations of identified features, and detailed geologic assessment for recharge potential. - Use of enhanced best management practices for erosion and sedimentation control during and after construction of new pipe. - Sealing of subsurface voids encountered during trench excavation. - Provision of a colored, reinforced concrete barrier over the new pipe for enhanced protection from third party damage. Grading of the surface over the new pipe installation to direct surface drainage (potential surface release away from identified sensitive areas/features. • Lowering and replacement of 15 miles of pipe across the Edwards Aquifer Contributing Zone. Training for first responders and other spill response personnel for highest efficiency and care in species areas (all species) . Cumulative Effects Cumulative effects of future State, local or private actions that are reasonably certain to occur in the action area are considered in this BA. Future Federal actions that are unrelated to the proposed action are not considered in this section because they require separate consultation pursuant to Section 7 of the Act. Because of the linear nature of the pipeline and the long history of clearing and operations (about 50 years), no cumulative effects from the activities proposed are anticipated. The majority of the counties involved in the project are predominantly rural (see draft Environmental Assessment of the Proposed Longhorn Pipeline System at Section 4.1.1.2), and imminent future actions identified are not likely to result in jeopardy to the species and are not likely to adversely affect any listed species or habitat. The various mitigation measures required for the Longhorn Pipeline as a result of the environmental review being conducted by the Lead Agencies or as a consequence of this 99144ba2.v8 78 <<>> consultation can be expected to have net beneficial effects on the environment, including listed species and their habitats. First, the Longhorn Pipeline itself will be improved, providing a higher level of environmental protection than previously was the case for the pipeline. Second, the Barton Springs Salamander refugium and captive breeding program will help mitigate for risks posed not only by the Longhorn pipeline, but by the many other existing sources of potential harm to the salamander, outlined above in the discussion of the environmental baseline for the salamander. In addition, some Longhorn-related mitigation measures will have the indirect or cumulative effect of reducing environmental and species-related risks associated with the two other petroleum pipelines in the area, especially over the Edwards Aquifer. For example, the Longhorn Mitigation Plan requires increased surveillance along the pipeline route. While most pipelines have weekly surveillance, Longhorn has committed to a patrol frequency of once every 2.5 days for sensitive and hypersensitive areas. In the three-mile crossing of the Barton Springs recharge zone, Longhorn will have daily patrols. This increased frequency of patrol will facilitate early detection of leaks and third party activity in the are of all three pipelines crossing the recharge zone. Similarly, Longhorn's commitment to aggressive public education and awareness programs will help reduce risks for all three pipelines crossing the Barton Springs recharge zone. ublic awareness should deter individuals from acts that might risk catastrophic spills o other accidents potentially affecting the environment and listed species 99144ba2.v8 79 <<>> 5.0 REFERENCES Arft, A. and T. Ranker. 1995. Demography of the rare orchid Spiranthes diluvialis: implications for conservation. Program and Abstracts, g'h annual meeting of the Society for conservation Biology, June 7-11, Fort Collins, Colorado. Abstract, notes from presentation attended. U.S. Fish and Wildlife Service, Austin, Texas. Brune, G. 1981. Springs of Texas: Volume 1. Branch-Smith Inc. Fort Worth, Texas. Chippindale, P., D. Hillis, and A. Price. 1990. Central Texas Salamander Studies. Section 6 report submitted by Texas Parks and Wildlife Department to U.S. Fish and Wildlife Service. Federal Aid Project No: E-1-2, Job No. 3.4. Austin, Texas. Horizon Environmental Services, Inc. 1991. Threatened or Endangered Species Investigations - EZ Pipeline Project. Horizon Environmental Service, Inc. Austin, Texas. Horizon Environmental Services, Inc. 2000. Biotoxicological Analysis a Potential Longhorn Pipeline Product Release Over The Edwards Aquifer Recharge Zone, Barton Springs Segment. Horizon Environmental Services, Inc. Austin, Texas. Poole, J.M,. and D.H. Riskind. 1987. Endangered, Threatened, or Protected Native Plants of Texas. Austin, Texas: Texas Parks and Wildlife Department, State of Texas. U.S. Fish and Wildlife Service (USFWS). 1984a. Houston toad recovery plan. U.S. Fish and Wildlife Service. Albuquerque, New Mexico. 73pp. U.S. Fish and Wildlife Service (USFWS). 1984b. Navasota ladies'-tresses recovery plan. U.S. Fish and Wildlife Service. Albuquerque, New Mexico. U.S. Fish and Wildlife Service (USFWS). 1994a. Minimum Procedures for Determining the Presence/Absence of Golden-Checked Warblers and Black-Capped Vireos. March 7, 1994 Memorandum, Austin Field Office. U.S. Fish and Wildlife Service (USFWS). 1994b. Population and habitat viability assessment: Houston toad (Bufo houstonensis). Workshop conducted by IUCN/SSC Conservation Breeding Specialist Group in partial fulfillment of USFWS contract #94-172. Apple Valley, Minnesota. U.S. Fish and Wildlife Service (USFWS). 1995. Threatened and Endangered Species of Texas. Austin, Texas: US Fish and Wildlife Service, Revised June, 1995. U.S. Fish and Wildlife Service (USFWS). Houston Toad Recovery Team. 1999. March 31- April 1, 1999 Meeting Minutes. U.S. Fish and Wildlife Service, Austin, Texas. U.S. Fish and Wildlife Service (USFWS). Final Rule to List the Barton Springs Salamander as Endangered. 62 FR 23377. Apr. 30, 1997. Texas Parks and Wildlife. 1993. Endangered species information for Hilltop Lakes. Texas Parks and Wildlife Resource Protection Division, Austin, Texas. 99144ba2.v8 80 <<>> Wilson, H. 1993. Contractors partial draft of recovery plan revision for Navasota ladies'- tresses (unfinished contract). U.S. Fish and Wildlife Service, Austin, Texas. (SCS) Soil Conservation Service. 1984. Soil Survey of Austin and Waller Counties, Texas. United States Department of Agriculture. 99144ba2.v8 81 <<>> Appendix 4B Phase I and II Biological Assessments, Phase I Biological Opinion, and Concurrence Letter <<>> Phase 1 Biological Assessment February 14, 2000 <<>> HJN 990144 BIOLOGICAL ASSESSMENT LONGHORN PIPELINE PROJECT MAINTENANCE ACTIVITIES AND MINOR CONSTRUCTION HOUSTON TO CRANE, TEXAS Prepared For: Longhorn Partners Pipeline, L.P. US Environmental Protection Agency Region 6 US Department of Transportation Office of Pipeline Safety Prepared By: Horizon Environmental Services, Inc. Austin - Beaumont - Houston - Shreveport February 14, 2000 990144BA.v-6 - 2/14/2000 <<>> TABLE OF CONTENTS Section Page 1.0 INTRODUCTION. .1 2.0 PROJECT OVERVIEW. .7 3.0 EXISTING ENVIRONMENT... ...9 3.1 GENERAL... .9 3.2 VEGETATION........ ..9 3.2.1 Gulf Prairies and Marshes Vegetational Area. ...9 3.2.2 Post Oak Savannah Vegetational Area... 12 3.2.3 Blackland Prairies Vegetational Area ... .12 3.2.4 Edwards Plateau Vegetational Area....... ..13 3.2.5 The Trans-Pecos, Mountains and Basins Vegetational Area... ..13 3.3 WILDLIFE.............. ..14 3.3.1 Austroriparian Biotic Province ..14 3.3.2 Texan Biotic Province. ..14 3.3.3 Balconian Biotic Province ..16 3.3.4 Kansan Biotic Province.. 16 3.3.5 Chihuahuan Biotic Province ..16 3.4 THREATENED AND ENDANGERED SPECIES 17 4.0 PROJECT DESCRIPTION... .37 4.1 RIGHT-OF-WAY CLEARING AND MARKING. .37 4.2 PIPELINE MAINTENANCE-CONSTRUCTION PLANNING. 39 4.3 PROJECT ENVIRONMENTAL INSPECTORS 45 4.4 SITE PREPARATION......... 45 4.5 SITE ENTRY....... ..46 4.6 PIPELINE LOWERING AND/OR REPLACEMENT - OPEN TERRAIN 47 4.7 PIPELINE LOWERING AND/OR REPLACEMENT - CREEK CROSSINGS 51 990144BA.v-6 - 2/14/2000 <<>> 4.8 TRENCHING... .51 4.9 BORING.. 4.10 HYDROSTATIC TESTING - OVERVIEW OF ACTIVITIES 4.11 HYDROSTATIC TESTING - POTENTIAL FAILURE OF PIPELINE. 4.12 CATHODIC PROTECTION ENHANCEMENTS 4.13 SURGE PRESSURE PROTECTION 4.14 INVESTIGATIONS........ 59 5.0 POTENTIAL IMPACTS (TAKE) AND COMPENSATION. 60 5.1 SPECIES-BY-SPECIES IMPACT ANALYSIS 64 5.2 AVOIDANCE AND MINIMIZATION 69 5.3 PROPOSED COMPENSATION FOR POTENTIAL TAKE 71 6.0 REFERENCES................... ............77 990144BA.v-6 2/14/2000 <<>> LIST OF FIGURES Figure Page 1 LOCATION MAP ...... 10 2 VEGETATIONAL AREAS OF TEXAS TRAVERSED BY THE LONGHORN PIPELINE 11 3 BIOTIC PROVINCES OF TEXAS TRAVERSED BY THE LONGHORN PIPELINE 15 4 - 12 AREAS OF FEDERALLY LISTED, THREATENED, OR ENDANGERED SPECIES TRAVERSED BY THE LONGHORN PIPELINE - HOUSTON TO CRANE . ..22-30 LIST OF TABLES Table Page 1 FEDERALLY LISTED THREATENED OR ENDANGERED SPECIES WHICH OCCUR IN COUNTIES TRAVERSED BY THE LONGHORN PIPELINE -HOUSTON TO CRANE 18 2 2000 MAINTENANCE CONSTRUCTION, TESTING AND CLEARING, LONGHORN PIPELINE .. 40 3 ROW CLEARING AND ADDITIONAL MAINTENANCE CONSTRUCTION IMPACTS - LONGHORN PIPELINE - HOUSTON TO CRANE. 62 4 LONGHORN PIPELINE TAKE COMPENSATION |.........75 APPENDIX PROJECT DOCUMENTATION APPENDIX ACCOMPANYING DOCUMENT 990144BA.v-6 2/14/2000 <<>> 1.0 INTRODUCTION This Biological Assessment (BA) is prepared in connection with the draft Environmental Assessment of the Longhorn Pipeline owned by Longhorn Partners Pipeline, L.P. (Longhorn). That Environmental Assessment was the product of a settlement reached in the matter of Spiller, et al v. Walker, et al pending in the United States District Court in Austin, Texas. The plaintiffs in that lawsuit alleged failure on the part of numerous federal agencies to adequately analyze the potential environmental impacts of the Longhorn Pipeline. Though the federal defendants and Longhorn denied the plaintiffs' allegations, the parties reached a negotiated settlement that was approved by the Court on March 5, 1999. Parties to that settlement included Longhorn, the US Environmental Protection Agency (EPA), the US Department of Transportation (DOT), the US Department of Justice, the City of Austin, the Lower Colorado River Authority, and the remaining plaintiffs. As part of that Court ordered settlement, the agencies involved in the original litigation were required to conduct an Environmental Assessment, including specific consideration of species protected under the Endangered Species Act (ESA). The Court ordered EPA and DOT, acting as Lead Agencies, to be responsible for the Environmental Assessment, and ordered the Department of Army to act as a cooperating agency. A draft Environmental Assessment, with a preliminary Finding of No Significant Impact (FONSI), was prepared by Radian International LLP at the direction of and pursuant to a work plan approved by the Lead Agencies. As a result of the Environmental Assessment, and with the support of the Lead Agencies, Longhorn has committed to implement a slate of 34 pipeline mitigation measures. (The pipeline mitigation measures are identified and described in the Longhorn Mitigation Plan included in the accompanying Project Documentation Appendix at Tab 2). The pipeline mitigation measures focus on two general areas: first, the enhancement of pipeline integrity to reduce the probability of a pipeline release and to reduce risks to pipeline integrity, and second, enhancement of emergency response capability and development of plans for corrective action in the unlikely event of a pipeline release. Both categories of pipeline mitigation measures are discussed below in greater detail in Section 4.0, Project Description. 990144BA.v-6 - 2/14/2000 <<>> Pursuant to Section 7 of the ESA, the Lead Agencies have requested consultation with the US Fish and Wildlife Service (the Service) regarding the Draft Environmental Assessment and the package of pipeline mitigation measures upon which the Lead Agencies' preliminary FONSI is predicated. In connection with the inter-agency consultation, Longhorn prepared and submitted to the Service a draft BA on the entire pipeline project on September 27, 1999. The Service responded to the September draft BA with comments and requests for additional information in the form of a letter to Horizon Environmental Services, Inc., dated December 15, 1999 (the Comment Letter - see accompanying Project Documentation Appendix at Tab 12). On February 3, 2000, the Lead Agencies designated Longhorn has a non- federal representative for the purpose of consultation with the Service and preparation of a BA on the Longhorn project. The Spiller Court's order provides that issuance of any FONSI with regard to the Longhorn project "shall be conditioned upon implementation" of measures to protect public safety and the environment. Settlement Stipulation at 6. The order also prohibits the DOT from authorizing Longhorn to commence operations until Longhorn has implemented those mitigation measures upon which the FONSI is conditioned. Settlement Stipulation at 7. The order contemplates that Longhorn will apply for, and accept, such ESA permits as may be required in connection with the implementation of any mitigation measures upon which a FONSI may be conditioned. Id. The results of this consultation by the Lead Agencies with the Service are expected to be incorporated in the Record of Decision issued by the Lead Agencies. If the Lead Agencies issue an EA/FONSI, the terms and conditions, mitigatory measures and protections incorporated herein for the benefit of species will be adopted and incorporated by Longhorn in its operating and maintenance manuals submitted to, and enforceable by, DOT pursuant to the Pipeline Safety Act (49 U.S.C. §60101, et seq.) or the Longhorn mitigation commitments. The Office of Pipeline Safety (OPS) administers DOT's regulatory program to ensure the safe transportation of various hazardous liquids by pipeline under 990144BA.v-6 2 - 2/14/2000 <<>> the Pipeline Safety Act. OPS is responsible for inspecting pipelines before they are placed in service to ensure that they are in accordance with DOT's regulations and are being operated safely. The OPS's published statement of its authority is set out below: The Department of Transportation's (DOI) Research and Special Programs Administration (RSPA), acting through the Office of Pipeline Safety (OPS), administers the Department's national regulatory program assure the safe other transportation of natural gas, petroleum, and hazardous materials by pipeline. OPS develops regulations and other approaches to risk management assure safety in design, construction, testing, operation, maintenance, emergency response of pipeline facilities. Although the Service and the Lead Agencies are in consultation with respect to the entire proposed Longhorn Project, this consultation is being approached in two distinct, yet related phases'. The first phase of the consultation (Phase I) relates to pipeline maintenance, pipeline testing and the first category of measures that Longhorn will take to fulfill its commitment to ensure pipeline safety and integrity. These measures focus on pipeline integrity enhancements such as a number of pipe replacements, lowering of some sections of pipe, investigation of possible pipe flaws, hydrostatic pressure testing, and similar actions. The second phase of the consultation (Phase I) will be more directly related to the actual operation of the pipeline, specifically the operation and maintenance of the pipeline system and the potential effects of the unlikely event of a pipeline release. Additional mitigation measures, such as internal pipeline inspections and construction in two particular areas, also will be addressed in Phase II. Those areas are (a) Houston toad habitat and (b) areas of potential effect to the Barton Springs Salamander over the Edwards Aquifer Recharge Zone. A two-stage consultation offers the most protection to the species, because the second phase will benefit from and build upon species information gathered in the first stage of review, while allowing the most efficient route to 402.14(k) provides a mechanism for the Service to review a project, and provide biological opinions on each U.S. Fish and Wildlife regulations allow for a staged consultation. 50 C.F.R § 402.14(k). Section incremental step. 990144BA.v-6 - 2/14/2000 <<>> startup of the pipeline. The Spiller settlement specifically contemplates that Longhorn will undertake certain construction and maintenance activities prior to issuance of a final agency decision in this matter. Settlement Stipulation at 8-11. The parties to the settlement specifically agreed that any such investments by Longhorn in Kimble, Menard, Hays, Travis, Caldwell, Bastrop and any counties within the jurisdiction of the LCRA after August 25, 1998 would not be considered "for the purposes of determining the reasonableness of alternatives" (Settlement Stipulation at 11), meaning that these investments would not constitute irretrievable commitments of resources for the purposes of the National Environmental Policy Act or Section 7(d) of the ESA. Phase I of the consultation focuses on near-term discrete tasks that are requisite preliminary activities-tasks that Longhorn must complete before it can place the pipeline into operation, such as right-of-way clearing and pipeline safety mitigation measures. They will be implemented in a manner that avoids and minimizes potential effects upon species and habitat. Phase II of the consultation will focus on long-term programmatic activities, operation and maintenance of the pipeline, and the possibility of an emergency response. These activities are either (a) not necessarily discrete or (b) not precisely estimable before the fact. Phase II activities carry different risks from Phase I activities. For example, the operation and maintenance activities are ongoing and long-term. Further, though the probability of a pipeline release will be minimized as a result of the Longhorn Mitigation Plan, should a release occur, it has the potential to result in adverse effects to species and habitat at locations and of magnitudes that are difficult to predict with precision. Nevertheless, because of the low risk of such a release and the comprehensive nature of the Longhorn Mitigation Plan, Longhorn and the Lead Agencies believe that it is appropriate to conclude that there is a reasonable likelihood that the entire project is not likely to jeopardize the continued existence of any endangered or threatened species or result in the destruction or adverse modification of critical habitat. This is because the Phase I review is being conducted against the backdrop of a larger mitigation package, which the Service has had an opportunity to review. The Service had an opportunity to review and 990144BA.v-6 4 - 2/14/2000 <<>> comment on the entire project based upon the September draft BA. The two phases thus can be logically separated. Phase I of the Service's review (this BA) will focus on those actions that are designed to make the pipeline safer. The Service can complete this stage of review without pre-judging whether or not the pipeline will be used. Phase II of the Service's review will focus on whether and how the pipeline will be used. The Phase I procedures are routine in the US pipeline industry, during operation, for periodic maintenance, testing and repair of hazardous liquids and gas pipelines. However, to ensure that the pipeline is safe, the Longhorn Mitigation Plan specifies that these activities shall be conducted prior to startup of the Longhorn Pipeline under its proposed use. This BA encompasses Phase I of the consultation. Included in this phase are maintenance of the pipeline right-of-way; maintenance construction to replace and/or lower certain segments of the pipeline, along with investigation and repair of possible flaws in the pipe at an identified number of locations; enhancements to the pipeline cathodic protection system; and hydrostatic pressure testing of the pipeline to ensure the integrity of the pipe for its intended service. None of these activities constitutes an irreversible or irretrievable commitment of resources, natural or monetary, which have the effect of foreclosing the formulation or implementation of any reasonable and prudent alternative measures. This BA is provided to facilitate a formal Section 7 consultation between the EPA, the DOT, and the Service to evaluate the potential for adverse effects to listed species resulting from activities related to the implementation of pipeline mitigation measures to improve pipeline integrity and thereby enhance pipeline safety. Those pipeline mitigation measures are referred to hereafter in this BA as projects. The specific maintenance and testing projects to be implemented are described in detail in Section 4.0 of this BA. Where appropriate, this BA generally comports with EPA Guidelines for Ecological Risk Assessment. See Guidelines for Ecological Risk Assessment, 63 Fed. Reg. 26,846 (1998). For example, EPA guidelines suggest that a suitable 990144BA.v-6 5 - 2/14/2000 <<>> assessment approach will identify the explicit, ecologically relevant expressions of environmental value that are to be protected. See 63 Fed. Reg. at 26,858. To that end, the BA guides project development, in part, by identifying particular species of concern within the project area, and suggesting mitigation efforts which will minimize exposure and impact to those species. Where uncertainty has been encountered, doubt has been resolved in favor of the species, and in this regard, the results of a precise application of EPA Guidelines have likely been exceeded. Precise application of the Guidelines would likely reveal far fewer areas of ecological sensitivity than have been assumed. 990144BA.v-6 6 • 2/14/2000| <<>> 2.0 PROJECT OVERVIEW Longhorn proposes to operate a 723-mile refined petroleum products pipeline system from the GATX Terminal in Galena Park, Texas, to a refined petroleum products terminal in El Paso, Texas. The pipeline also has a 28-mile intermediate connection from a station in Crane County to a planned meter station in Odessa, Texas. The pipeline consists of a combination of 20-inch and 18-inch diameter pipe from Galena Park Station to El Paso Terminal and an 8- inch diameter pipeline from a station in Crane County to a meter station in Odessa, Texas. Finally, three as yet to be built pipelines will connect the El Paso terminal to interstate common carrier pipelines west of El Paso. The pipeline's initial capacity of 72,000 barrels per day (bpd) will be supplied by a new pump station at Galena Park and five newly constructed booster pump stations at the following locations: Satsuma (Harris County), Cedar Valley (Hays County), Kimble County (Kimble County), Crane (Crane County), and El Paso (El Paso County). Two new pipeline construction projects remain to be completed. An 8-inch diameter, 2500-foot lateral that originates at the terminus of the existing Odessa lateral will connect to a terminal facility in Odessa, Texas, owned by Equilon. Three 8.3-mile lateral pipelines, which originate at the El Paso Terminal, will connect with Kinder Morgan (formerly the Santa Fe Pacific pipeline) and Chevron pipelines in the El Paso area. The connection to Kinder Morgan will consist of one 8-inch diameter pipeline and one 12-inch diameter pipeline. The Chevron connection will consist of an 8-inch diameter pipeline. The purpose of the lateral pipelines is to connect into Kinder Morgan and Chevron pipelines to distribute product into the Phoenix, Tucson, and Albuquerque (New Mexico) markets. Chevron operates an 8-inch pipeline that delivers product to the Albuquerque market; Kinder Morgan operates one 12-inch pipeline and one 8-inch pipeline serving the Tucson market. Other Kinder Morgan pipelines connect Tucson to the Phoenix market. The proposed project includes both new construction and refurbishment of 990144BA.v-6 7 - 2/14/2000 <<>> an existing pipeline that has been converted from its former use of transporting crude oil from West Texas to the Gulf Coast area, the majority of which is complete. As described in this chapter, the existing pipeline has been modified to transport refined petroleum products, with flow going from east to west. Williams Pipeline Company (later to become part of Williams Energy Services) will be the contract operator of the Longhorn Pipeline System. Longhorn intends to transport multiple grades of gasoline and distillates, which will include special reformulated grades of gasoline needed to control air emissions in certain areas of the Southwest. The Longhorn Pipeline System is designed for service in excess of 50 years and is made up of four main pipeline segments, several stations, and one terminal, as listed below: • New and refurbished 20-inch diameter pipeline from Galena Park Station to Satsuma Station • Refurbished 18-inch diameter pipeline from Satsuma Station to Crane Station New 18-inch diameter pipeline from Crane Station to El Paso Terminal New lateral pipeline connections to Odessa and to other pipelines at El Paso • New Pump Stations • El Paso Terminal • Odessa Meter Station A detailed description of the Longhorn Pipeline System is included in the Longhorn Pipeline Project Description section of the accompanying Project Documentation Appendix at Tab 1. More detailed descriptions of the project components that are subject to this BA are included in Section 4.0. Future pipeline upgrades, repairs, and maintenance beyond that identified in this document will be addressed in Phase II of the consultation. 990144BA.v-6 8 - 2/14/2000 <<>> 3.0 SEXISTING ENVIRONMENT 3.1 GENERAL The Longhorn Pipeline traverses the State of Texas from east to west originating in east Houston, Harris County and extending westward to Crane Station, Crane County (Figure 1). Auxiliary lines extend from Crane Station northward to Odessa and westward to El Paso in far west Texas. The area traversed by the pipeline varies physiographically from flat or rolling coastal prairie in the Houston region to hilly woodlands of the Edwards Plateau in central Texas to the xeric Permian Basin region of west Texas. 3.2 VEGETATION From east to west, the Longhorn Pipeline traverses the Gulf Prairies and Marshes, Post Oak Savannah, Blackland Prairies, Edwards Plateau, and Trans- Pecos, Mountains and Basins Vegetational Areas (Gould, 1975; Figure 2). The following provides a summary description of each ecological region. 3.2.1 Gulf Prairies and Marshes Vegetational Area This ecological region, approximately 9.5 million acres in extent, is divided into the Coastal Prairie and Gulf Coast Marshlands. The Coastal Prairie is a nearly level plain less than 150 feet above mean sea level (MSL) and dissected by streams and rivers flowing into the Gulf of Mexico while the Gulf Coast Marshlands are limited to narrow belts of low wet marsh immediately adjacent to the coast and along waterways. Surface soils are acid sands, sandy loams, and clays with low permeability and droughty in nature. Annual precipitation averages from 20 inches in the west to 50 inches in the east (Gould, 1975). The climax vegetation is largely grassland or post oak savannah (Gould, 1975). Ranches and rangelands are interspersed by farms. Most of the marsh areas are grazed by cattle within large land holdings. 990144BA.v-6 9 - 2/14/2000 <<>> MARILO Coo Oklahoma Mexico New LuBBOCK • Т корт орт райм Louisiana ODESSA MIDLAND SAN ANGELO Mexico Mexico DEL RIO LAREDO Mexico Gulf of - Longhor Refined Products Pipeline for far: 2003 • 7i21 No. FIGURE I NOT TO SCALE LONGHORN PIPELINE LOCATION MAP MAP SOURCES: TEXAS NATURAL RESOURCE INFORMATION SYSTEM LONGHORN PIPELINE <<>> Longhorn Refined Products Pipeline 10 MEXICO GULF VEGETATIONAL AREAS OF TEXAS 1. . 2. Gulf Prairies and Marshes Pineywoods 3. 4. Post Oak Savannah 5. Blackland Prairies 6. South Texas Plains Cross Timbers and Prairies :50 8. Rolling Plains 7. Edwards Plateau Mile 100 10. Trans-Pecos, Mountains and Basins High Plains Horizon ENVIRONMENTAL SERVICES, INC. FIGURE 2 LONGHORN PIPELINE IN RELATION TO THE Source: Gould, 1975. VEGETATIONAL AREAS OF TEXAS <<>> 3.2.2 Post Oak Savannah Vegetational Area This ecological region, approximately 8.5 million acres in extent, is bordered by the Pineywoods region to the east and the Blackland Prairie region to the west. The topography is gently rolling to hilly, and elevations range from 300 to 800 feet above mean sea level (MSL). Generally, surface soils of higher elevations are light-colored, acidic sandy loams or sands while those of lower elevations are darker, acidic sandy loams or clays. Annual precipitation averages from 35 to 45 inches, and May or June is generally the high rainfall month (Gould, 1975). The Post Oak Savannah was historically dominated by prairie climax grasses and scattered trees. The most prevalent trees were oaks and cedar elm. The deterioration of the climax plant communities in the region is evidenced by an increase of certain grass species, forb species, and woody species (Gould, 1975). Moderate to dense post oak dominated woodlands have developed in many areas as a result of man's suppression of fire. The bottomland woodland remains the most diverse vegetation type of this ecological area. 3.2.3 Blackland Prairies Vegetational Area This ecological region, approximately 11.5 million acres in extent, includes the San Antonio and Fayette Prairies. Land surface ranges in elevation from 300 to 800 feet, gently rolling to nearly level, and well dissected and rapidly drained. Surface soils are fairly uniform, dark-colored calcareous clays interspersed with gray acid sandy loams. Annual precipitation averages from 30 inches in the west to 40 inches in the east (Gould, 1975). The climax native vegetation is true prairie (Gould, 1975). The majority of this ecological area has been brought under cultivation. Farms are interspersed among ranches and rangelands. 990144BA.v-6 12 - 2/14/2000 <<>> 3.2.4 Edwards Plateau Vegetational Area This ecological region encompasses approximately 24 million acres in west-central Texas. Land surface ranges in elevation from 100 to 3000 feet above MSL, rough and well drained, and dissected by several river systems. Surface soils are usually shallow and underlain by material ranging from limestone or caliche to granite. Annual precipitation averages from 15 inches in the west to over 33 inches in the east, and droughts are not uncommon (Gould, 1975). The Edwards Plateau Vegetational Area is predominantly rangeland (Gould, 1975). Bottomland areas of this ecological area having deeper soils have been brought under cultivation. Small farms are interspersed among ranches and rangelands. 3.2.5 Trans-Pecos, Mountains and Basins Vegetational Area This ecological region encompasses approximately 19 million acres of mountains and arid valleys in extreme west Texas. Land surface ranges in elevation from 2500 to over 8500 feet, rough and well drained, and dissected by several river systems. Surface soils have developed from out-wash materials from mountains, varied in texture, calcareous, and some areas are alkaline due to poor drainage. Surface conditions include stony hills, clay flats, sands, salty-saline soils, gypsum flats, deep upland, rough stony mountains, gravelly outwash, and badlands (Gould, 1975). The average annual precipitation for the area is less than 12 inches while higher elevations can range from 16 to 20 inches (Gould, 1975). Cultivated areas are confined largely to irrigable valleys. The majority of land is in large holdings as native range. Ranch operations include cattle, sheep, and goats. 3.3 WILDLIFE 990144BA.v-6 13 - 2/14/2000 <<>> From east to west, the Longhorn Pipeline traverses the Austroriparian, Texan, Balconian, Kansan, and Chihuahuan Biotic Provinces described by Blair (1950; Figure 3). The following provides a summary description of each biotic province. 3.3.1 Austroriparian Biotic Province This province includes the Gulf coast plain from the Atlantic to eastern Texas. The western boundary of this province in Texas is along a line running approximately north from western Harris County to western Red River County. The pine and hardwood forest of the Austroriparian is limited to the west by available moisture. The vertebrate fauna of the Austroriparian Province in Texas is typical of the species in the province to the east. At least 47 species of mammals occur in this province in Texas. Some 29 species of snakes, 10 lizards, 2 land turtles, 17 anurans, and 18 urodels are known to occur in the Texas part of this province (Blair, 1950). 3.3.2 Texan Biotic Province This province is a transitional area and is recognized as a broad ecotone between the forests of the Austroriparian and Carolinian provinces of eastern Texas and Oklahoma, and the grasslands of the western parts of these states. The integration of woodlands and grasslands within the region results in a mixture of wildlife species typical of the 2 general habitats. The vertebrate fauna of the Texan Biotic Province consists of at least 49 species of mammals, 16 lizards, 2 land turtles, 39 snakes, 18 anurans (frogs and toads), and 5 urodeles (salamanders, newts, etc.) (Blair, 1950). No endemic vertebrates are known from the Texan Province. 990144BA.v-6 14 - 2/14/2000 <<>> Kansan Navahonian Texan Balconian Chihuahuan MEXICO Tamaulipan of GULF Longhorn Refined Products Pipeline we 3 070€ 50 100 Miles Horizon ENVIRONMENTAL SERVICES, INC FIGURE 3 LONGHORN PIPELINE IN RELATION TO THE BIOTIC PROVINCES OF TEXAS <<>> 3.3.3 Balconian Biotic Province This province is synonymous with the Edwards Plateau and is a physiographically discrete unit. The name Balconian is derived from the Balcones Fault Zone which forms the southern and eastern boundaries of this province. The vertebrate fauna of the Balconian Biotic Province is a mixture of species characteristic of surrounding major provinces, even though its characteristic vegetation is distinctly different. The vertebrate fauna consists of 57 species of mammals, 16 lizards, 1 land turtle, 36 snakes, 15 anurans (frogs and toads), and 7 urodeles (salamanders, newts, etc.) (Blair, 1950). There are several endemic vertebrates known from the Balconian Biotic Province. 3.3.4 Kansan Biotic Province This province is divided into 3 distinct biotic districts: the Mixed-grass District, Mesquite Plains District, and Short-grass Plains District. All of these biotic districts have areas of dune sand. Moisture is deficient throughout the Kansan Biotic Province, and there is a decrease in available moisture from east to west. The Short-grass Plains District occurs in the area of Crane, Texas. The vertebrate fauna of the Kansan Biotic Province is a mixture of species from each of its biotic provinces. The vertebrate fauna consists of 59 species of mammals, 14 lizards, 1 land turtle, 31 snakes, 9 anurans (frogs and toads), and 14 urodeles (salamanders, newts, etc.) (Blair, 1950). There are 6 endemic vertebrates known from the Balconian Biotic Province. 3.3.5 Chihuahuan Biotic Province Within Texas, the Chihuahuan Biotic Province includes all of the Trans- Pecos Texas except the Guadalupe Mountains in Culberson County. The physiography of the province includes desert basins, mountains, and major waterways and drainages. Even though the climate of most of the province in Texas is arid and seriously deficient of moisture for plant growth, vegetational communities are very diverse. 990144BA.v-6 16 - 2/14/2000 <<>> The vertebrate fauna of the Chihuahuan Biotic Province is extremely diverse and many of the same species can be found in both desert basin and mountain areas. The vertebrate fauna consists of 83 species of mammals, 22 lizards, 1 land turtle, 38 snakes, 13 anurans (frogs and toads), and 1 urodele (salamanders, newts, etc.) (Blair, 1950). There are 6 endemic vertebrates known from the Balconian Biotic Province. 3.4 THREATENED AND ENDANGERED SPECIES Horizon Environmental Services, Inc. (Horizon) has performed investigations along the existing Longhorn Pipeline right-of-way (ROW) and vicinity from Houston to Crane for the possible occurrence of all federally-listed, threatened, or endangered species which are known to exist in all counties of Texas traversed by the Longhorn Pipeline (Table 1). Following investigation of the species which potentially occur in these counties, several species were identified for which there was a possibility of occurrence within the area of potential effect for pipeline maintenance construction, routine ROW maintenance, hydrostatic pressure testing, and the remaining integrity related activities. The area of potential direct effects for the Phase I activities includes the immediate, existing 50-foot wide ROW, and those additional construction specific adjacent areas up to 100 feet either side of the ROW, and other areas that could reasonably and foreseeably be affected by the subject pipeline maintenance, construction, and testing activities (ie., hydrotest releases). No areas of indirect effect are anticipated due to avoidance and minimization procedures. A biological investigation was conducted along the pipeline ROW and immediately adjacent lands to determine if these species and/or suitable habitat were present within the area of concern. Horizon conducted habitat assessments and survey efforts throughout April, May, and June 1999 from 990144BA.v-6 17 - 2/14/2000 <<>> Kimble 18ULS1 Hays x3321 0 0o ste even are mercies 192282623002 Harris 30-92 САлЕрих ИЗ оласТЕЯ Gillespie 3003 Henbanensi Fayette densitem sida Ector 2ovi 2233 Table 1: Federally-listed Threatened or Endangered Species which occur in counties traversed by Longhorn Pipeline Crockett epot linen Crane 00г) soys boons state br 2005100228/008 nucol Sne Blanco Sub be sha X - Known or Suspected to Occur Within Area of Potential Effect TSA - Listed Threatened Due to Similarity of Appearance O - Not Likely to Occur Within Area of Potential Effect xx 20000000 254 волар и 1610р Source of Species: US Fish and Wildlife Service Bastrop PDL - Proposed to be De-listed E - Listed Endangered Austin * T - Listed Threatened Species - Federal Classification American alligator - TSA Attwater's prairie-chicken - E Barton Springs salamander - E Bee Creek Cave harvestman - E Bald eagle - T(PDL) Black-capped vireo - E Bone Cave harvestman - E Clear Creek gambusia - E Comal Springs dryopid beetle - E Comal Springs riffle beetle - E Devil's River Minnow - PE Golden-cheeked warbler - E Kretschmar Cave mold beetle - E Navasota Ladies-tresses - E Fountain darter - E Houston toad - E Interior least tem - E San Marcos gambusia - E San Marcos salamander - T Texas blind salamander - E Texas prairie dawn-flower - E Tobusch fishhook cactus - E Tooth Cave ground beetle - E Tooth Cave pseudoscorpion - E Texas snowbells - E Texas wild-rice - E Tooth Cave spider - E Whooping crane - E <<>> Downstream Waller 0 x Upton Travis 0 0 0= Schleicher Table 1: Federally-listed Threatened or Endangered Species which occur in counties traversed by Longhorn Pipeline Reagan Menard Mason X - Known or Suspected to Occur Within Area of Potential Effect TSA - Listed Threatened Due to Similarity of Appearance O - Not Likely to Occur Within Area of Potential Effect Source of Species: US Fish and Wildlife Service Llano PDL - Proposed to be De-listed E - Listed Endangered T - Listed Threatened Lee Species - Federal Classification American alligator - TSA Attwater's prairie-chicken - E Barton Springs salamander - E Bee Creek Cave harvestman - E Bald eagle - T(PDL) Black-capped vireo - E Bone Cave harvestman - E Comal Springs dryopid beetle - E Clear Creek gambusia - E Comal Springs riffle beetle - E Kretschmarr Cave mold beetle - E Devil's River Minnow - PE Golden-cheeked warbler. - E Navasota Ladies-tresses - E Fountain darter- E Houston toad - E Interior least tem - E San Marcos gambusia - E San Marcos salamander - T Texas blind salamander - E Texas prairie dawn-flower - E Tobusch fishhook cactus - E Tooth Cave ground beetle - E Tooth Cave pseudoscorpion - E Texas snowbells - E Texas wild-rice - E Tooth Cave spider - E Whooping crane - E <<>> Crane Station, Crane County, Texas to Highway 6 in Houston, Harris County, Texas. The portion of the pipeline extending from Crane to El Paso is not subject to this BA since none of the subject activities will apply to that pipeline segment area. Species which potentially occur in or near waterways downstream of the pipeline were assessed based on literature and agency file information. In 1998, the Service concurred with Longhorn's conclusion that the project was not likely to adversely affect species and habitat along the pipeline segment between Crane and El Paso (a copy of the Service's concurrence is included in the accompanying Project Documentation Appendix at Tab 13). As indicated in Table 1, many species have been excluded from further consideration due to Horizon=s determination that the activities are not likely to adversely affect these species. S Horizon's determination was based on information regarding distribution of the various species obtained from various published, agency file, or personal communication sources such as the Texas Parks and Wildlife Department, the US Fish and Wildlife Service, recognized experts for certain species, published species documentation, and published reference books. Those species indicated by an AO@ in Table 1 have been determined not likely to occur within the area of potential effect. Those additional species indicated by an AM@ are migrants that would not likely be affected. Species indicated by an AX@ are those determined by Horizon-s studies to occur or possibly occur in the area of potential effect for present purposes. Those species are addressed in more detail below and on attached maps. Texas Prairie Dawn-flower (Hymenoxys texana) Small, delicate annual to 6 inches tall with single or branching stems. Small yellow flowers blooming in late March to early April. Occurs in sparsely vegetated areas of fine-sandy compacted soil. Specifically, the species occurs in the northern part of the Gulf Coastal Prairie, where it is found in poorly drained depressions or saline swales around the periphery of low, natural mounds (mima mounds) in open grasslands. These mostly barren areas are sparsely vegetated, and the soil is often covered with a blue-green alga (Nostoc sp.). It can also occur on disturbed soils such as rice fields, vacant lots, and pastures if the soil structure remains relatively intact. 990144BA.v-6 20 - 2/14/2000 <<>> An assessment of potentially suitable habitat for the prairie dawn was conducted by Horizon in early June 1999 along the Longhorn pipeline ROW in western Harris and eastern Waller counties from the Satsuma Station on the west edge of Houston to near Monaville in Waller County. Three areas along the ROW, one in Waller County and two in Harris County, exhibited native range conditions with suitable soils that could be considered potentially suitable habitat areas for the prairie dawn (Figures 4 to 12). All other areas along the pipeline within the area investigated had been converted to row crop (corn), monoculture, hay or grazing pasture, or disturbed for land development. A survey for the prairie dawn has not been conducted within the potentially suitable habitat areas to confirm its presence or absence. Longhorn will conduct a survey of the ROW within the potential habitat areas in March of 2000 to determine if the prairie dawn is present, and if so, its distribution and abundance. Navasota Ladies-tresses (Spiranthes parksil) The Navasota Ladies-Tresses (NLT) occurs primarily in moist, sandy soils in small openings amongst Post Oak Savannah vegetation associated with the Navasota, Brazos, and Trinity River drainages. The plant has previously been found in Brazos, Burleson, Freestone, Grimes, Fayette, Leon, Madison, Jasper, Robertson, and Washington counties. NLT are typically found on erosional remnants between rills in slightly to moderately eroded areas along minor intermittent tributaries of the Navasota, Brazos, and Trinity Rivers. NLT grows on sandy loam soils and is often associated with post oak, blackjack oak, yaupon, slender bigelowia (Bigelowia nuttallii), and Spiranthes cernua. The species has also been recorded in open savannahs and shrublands that have experienced little or no grazing pressure, and in hillside seepages. 990144BA.v-6 21 _ 2/14/2000 <<>> Louisiana FIGURE 4 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT SHEET LOCATION MAP LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT LONGHORN PIPELINE Gulf of Mexico FIGURE 5 HOUSTON HARRIS WALLER FIGURE 6 AUSTIN FIGURE 8 FAYETTE FIGURE 7 RAVIST AUSTIN BASTROP HAYS FIGURE 10 LLANO BLANCO GILLESPIE MASON FIGURE 9 MENARD KIMBLE FIGURE 11 SCHLEICHER 12° NOT TO SCALE FIGURE REAGAN CROCKETT LONGHORN REFINED PRODUCTS APPROXIMATE CITY LOCATIONS FOR Mexico 2: TEXAS NATURAL SUE 10197) (http://www.tnris.state.tx.us/data__az.html),1998 UPTON PIPELINE REFERENCE ECTOR ODESSA CRANE CRANE EXPLANATION CRANE <<>> FIGURE 5 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE DT-20a(K) DAWN-FLOWE! HARRIS CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION HOUSTON TOAD - DESIGNATED HABITAT Bufo houstonenses GOLDEN-CHEEKED WARBLER (Dendracia chrysoporio) BAD CADAD MIRED (SPOTA POES -TRESSES EDWARDS RECHARGE ZONE CONTRIBUTING ZONE ROSTER OTT TEXAS PRAIRIE -10 - CR-/ - SURGE 4 PIPELINE/ COUNTY BOUNDARY 199 HIGHMAY OR MAJOR ROADS CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES HERBON AGAIN LOCATIONS LONGHORN PIPELINE ROADS BRIDGES CEMETERY —I1P-2516 MANTENICE CONSTRUCTION TEXAS PRAIRIE DAWN-FLOWER WALLER EXPLANATION ##### RAILWAYS - -50756-3 1.5 MILES PINE ISLAND 4. TROT: HOREON SNORIN SE IS 1909AE 8. HORIZON MPONMONTAL SERMICES, INC, SITE BMESTIGATION (JIME 1990) 5 PER TO PASS ME PAL BED MIS PUNTS OF 159 2. RESOURCES ORATION SET 1700 2. TS NEH MOD BIA SONG 10D, OF TEAS 529 SON SAMS <<>> USTIN, WASHINGTON FIGURE 6 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE NAVASOTA LADIES-TRESSES CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION Condo CO MARGUER BAD CAPPED VIREO EDWARDS RECHARGE ZONE CONTRIBUTING ZONE 257 OLDENBURI - CR-1 - SURGE 4 EE HONY OR MANOR ROMOS CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY — LIP-2546 MICATONICE CONSTRUCTION EXPLANATION - SITE 6-3 NAVASOTA LADIES-TRES: FAYETTE MILES 6. HORIZON EIMIRONMENTAL SERNCES, INC, SITE IMMESTGATION (JUNE 1999) * PONTES TREAD ELBERT MATE PUNTS OF 2. RESOURCES TORTON SISTEN 37/ 2. TAS ABA MO BE SERE 1OED, OF TOUS. LEE SOURCES <<>> FIGURE 7 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE SES-TEAS COLORADO HOUSTON TOAD (POTENTIAL HABITAT) PIPE REPLACEMENT CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION HOUSTON TOAD - POTENTIAL HOUSTON TOAD - DESIGNATED CRITICAL HABITAT HABITA (Bufo houstonemsis) BAD CARD VIRED MAMOTAY POTS-TRESSES EDWARDS RECHARGE ZONE CONTRIBUTING ZONE -67-1 - SURGE 4 - HIGHWAY OR MAJOR ROADS BASTROP® — COUNTY BOUNDARY CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —4P-2516 LOCATTMNICE CONSTRUCTON EXPLANATION - SITE 6-3 INC, SITE INSTIGATION (JUNE 1999) DED MATE PUNTS OF BUT SERE TOES OF TOAS 1. TOAS NATURAL DE 3. DETERMATION OF CRITICAL 8. HORIZON EMIROMMENTAL SERMICES, 2. Tot COUNTY 4. THREATE P <<>> FIGURE 8 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE EDWARDS HAYS TRAVİS CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION Tomotocette tok CTUs SANSON POTS -TRESSES EDWARDS RECHARGE ZONE CONTRIBUTING ZONE ONTRIBUTING ZONE -CR-/ - SURGE 4 DRIPPING SPRINGS HIGHWAY OR MAJOR ROADS • COUNTY BOUNDARY CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES HENDER ANG PETON LOCATIONS LONGHORN PIPEUNE GOLDEN CHEEKED MA RONDS RAILWAYS BRIDGES CEMETERY —LLP-2516 MANTEMANCE CONSTRUCTION EXPLANATION -- ###### — SITE 6-8 SITE 6- PEDES MESTICATIONS, F REGUME PONCORD SPORES, OF TEUS 6. HORIZON DRONENTAL SERMCES, INC, SITE ESTIGATON (UNE 1999) * POTES PRES LA SEPT ME FURTS OF BLANÇO ME SAMOS <<>> FIGURE 9 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE BLACK-CAPPED VIREO BLANCO • GOLDEN-CHEEKED WARBLER CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION Taco Deto TobacTS EDWARDS RECHARGE ZONE CONTRIBUTING ZONE - CR-/ - SURGE 4 HIGHWAY OR MAJOR ROADS WARBLER - COUNTY BOUNDARY CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES MEMBER AS RATIN COCATIONS LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —LP-2516 MANTENNCE CONSTRUCTION EXPLANATION — SITE 6-3 Cool PIPELINE DIGORED SPECIES NESTIOMONS, EPPELME ÇILLESPIE 3. OCTEPMATO, OE CEMEM, HA PS AR HT SIR RT &. HORIZON EMIROMMENTAL SERVICES, MC, SITE INVESTIGATION (JUNE 1999) SPORTED PRESSED FLOURE DET MIME PUNTS OF 2 TS TO ME BUT SAME TOE OF TENS LLANO SAT MATRA SEA MAP SANCES 4. THREATEN HORROR <<>> ELINE LIANO FIGURE 10 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE E BLACK-CAPPED VIREO y GOLDEN-CHÉEKED WARBLER CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION HOTTA TO NOLOTOROMENTAL GILLESPIE NAVASOTA LADIES-TRESSES (Spironthes portsil) EDWARDS RECHARGE ZONE CONTRIBUTING ZONE LOVEY CHERRY 2242 GOLDEN-CHEEKED WARBLER - CR-/ - SURGE 4 COUNTY BOUNDARY • HIGHWAY OR MAJOR ROADS CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —11P-2516 MANTERAMCE CONSTRUCTION EXPLANATION ! - S175 6-8 SITE MASON MC, SITE IMESTONOM (AME 1990) DES OF TENS: MILES 5 PRETE PASS ME UP DEPT ME RUNTS OF ENTAL SERVES PIPELINE QURASS MAR SOUPOSS 4. THREATENED OR DID &. HORIZON <<>> -GILLESPIE BLACK-CAPPED VIREO FIGURE 11 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE PIPELINE MASON 0т-90 (K) CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION HOUSTON TOAD - DESIGNATED HABITAT (Buto houstonensis) MASOTA PORS-TRESSES EDWARDS RECHARGE ZONE CONTRIBUTING ZONE - CR-/ - SURGE 4 - COUNTY BOUNDARY → I HIGHNAY OR MOR ROADS CITY STREETS - RIVERS AND STREAMS NTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY — LLP-2546 MOCATIMANCE CONSTRUCTION 1-8 ALIS SURGE 4. 871 EXPLANATION иннинин KIMBLE - SITE 6-3 LONDON TOBUSCH FISHHOOK CACTUS 3480 YATES EACUP POUNCERED SORDES oF TEMS. 6. HORIZON ENMRONMENTAL SERVICES, IMC., SITE IMVESTIGATION (JUME 1999) SO PARCE PROTEST MADE PLANTS OF MENARD HAS SOURCES I BEATENED OR EHDAN 2. THREATPNED AND <<>> BLACK-CAPPED VIREO FIGURE 12 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE CACTÚS LOCATION SITE 8-3 CPGB-s : KIMBLE CATHODIC PROTECTION ENHANCEMENTS SURGE PRESSURE PROTECTION HOUSTON TOAD - DESIGNATED HABITAT (Bufo houstonents COLDEN-CHEEKED WARBLER Dendrocio chrysaparna LAVASOTA LADIES-TRESSES TOBUSCH FISHHOOK CACTUS Spiranthes pantsi EDWARDS RECHARGE ZONE CONTRIBUTING ZONE - CR-1 - SURGE 4 MENARD HEADER ANSARI LOCATIONS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES CITY STREETS LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —11P-2516 MANTELANCE CONSTRUCTION EXPLANATION — SITE 6-2 B-8 JUIS ANGERED SPECES, MISTATORS, EZ PROLAE 6. HORIZON EMRONMENTAL SERMCES, INC, SITE MESTONTOM (JUNE 1990) 5 PEAS TEE PRESIDE ST MINE PUNTS OF 2 RESOURCES TORMATION SITE 15P ORVETT SUTTON SCHLEICHER " Copperas MAR SORCES A THREATE <<>> In Fayette County, the species is known from one small population approximately 6 miles south of the pipeline and 2 miles north of the town of Fayette. Based on analysis of soil distribution, vegetative cover, physiographic setting, and field assessment by Horizon in November of 1999, two small areas of potential habitat for NLT are present along the pipeline corridor (Figures 4 to 12). No surveys for the species have been conducted along the pipeline. Longhorn will conduct a Fall survey (15 October to 15 November, 2000) for this species within the ROW if suitable climatic conditions occur to determine the presence or absence of this species, and if present, its distribution and abundance. Tobusch Fishhook Cactus (Ancistrocactus tobuschii) Rounded, biscuit-shaped cacti usually 2 to 3 inches tall and up to 3.5 inches in diameter. There are 3 to 5 central spines with the upper 2 to 3 erect and straight and the lower central spines hooked at the tip and spreading. Occurs on limestone gravels of stream terraces, limestone ledges, ridges, and openings on the rocky hills of live oak - juniper woodlands. The Tobusch fishhook cactus has been documented in Kimble County. An assessment of potentially suitable habitat and pedestrian survey for the cacti was conducted by Horizon in April 1999 along portions of the Longhorn pipeline ROW in Kimble County, and no specimens were observed within the ROW. However, one Tobusch fishhook cactus was observed approximately 50 feet north of the cleared ROW (Figures 4 to 12). Longhorn will conduct a blooming period survey (March to April 2000) within the ROW throughout Kimble County to determine the species' distribution and abundance. Houston Toad (Bufo houstonensis) The Houston toad is 2.0 to 3.5 inches long with general coloration varying from light brown to gray or purplish gray, sometimes with green patches. The pale ventral (underneath) surfaces often have small dark spots. The toad is a terrestrial amphibian associated with deep sandy soils within the Post Oak Savannah vegetational area of east central Texas. The vegetation type of currently known Houston toad sites can typically be described as pine or oak 990144BA.v-6 31 - 2/14/2000 <<>> woodland or savannah, with native bunchgrasses and forbs (flowering plants) present in open areas. For breeding, including egg and tadpole development, Houston toads also require still or slow-flowing bodies of water that persist for at least 30 days. The source of ephemeral or permanent water should be located within one-half to three-quarters miles of the toad=s hibernation/foraging habitat (deep sands supporting woodland or savannah). Critical habitat was designated for the Houston toad 31 January 1978, of which a portion of Longhorn pipeline traverses through in Bastrop County (Figures 4 to 12). The Longhorn Pipeline ROW within the Houston toad Critical Habitat area is immediately adjacent to the Phillips EZ Pipeline ROW which Horizon studied in 1991 for endangered species. As part of Horizon's studies, a Houston toad survey was conducted along the EZ Pipeline corridor in 1991 by Dr. James R. Dixon of Texas A&M University with negative results, although minor potential habitat areas were noted (Horizon, 1991). Horizon conducted a reevaluation of suitable habitat along the Longhorn Pipeline ROW within Bastrop County. The field reconnaissance was conducted on 2 June 1999 from the Colorado River, southeast of Bastrop, to FM 2104. Within the designated Critical Habitat, portions of the area along the pipeline had been cleared and planted in improved grasses. These areas were determined to be unsuitable for Houston toad occupation. Based on field observations, and confirmation by the Service, it was determined that two areas of potentially suitable habitat existed along and adjacent to the pipeline ROW. One area included Buescher State Park from approximately 1/2 of a mile to the east of the eastern boundary of the park westward to near Highway 71. The majority of this area contained a moderately thick understory with all drainages flowing south toward the Colorado River. The second area began approximately 500 feet to the west of FM 2104 and extended westward approximately 3/4 of a mile. This area contained two stock tanks with the majority of the surrounding area exhibiting a moderately 990144BA.v-6 32 - 2/14/2000 <<>> thick understory and pine re-growth. The drainages in this area also flowed to the south toward the Colorado River. One or more additional spring surveys (as acceptable to the Service) for the toad will be conducted along and downstream of the pipeline to determine the presence or absence of toads and their overall distribution and abundance. Golden-cheeked Warbler (Dendroica chrysoparia) The golden-cheeked warbler (GCW) is a small, migratory songbird, 4.5 to 5 inches long, with a wingspan of about 8 inches. The male has a black back, throat, and cap, and yellow cheeks with a black stripe through the eye. Females are similar, but less colorful. The lower breast and belly of both sexes are white with black streaks on the flanks. Typical nesting habitat is found in tall, dense, mature stands of Ashe juniper (cedar) mixed with trees such as Texas (Spanish) oak, Lacey oak, shin (scalybark) oak, live oak, post oak, Texas ash, cedar elm, hackberry, bigtooth maple, sycamore, Arizona walnut, escarpment cherry, and pecan. This type of woodland generally grows in relatively moist areas such as steep-sided canyons and slopes. A mix of juniper and deciduous trees on the slopes, along drainage bottoms, and in creeks and draws provide an ideal mix of vegetation for birds. Warblers are also occasionally found in drier, upland juniper-oak (i.e. live oak, post oak, blackjack oak) woodlands over flat topography. An assessment of potentially suitable habitat and surveys for the GCW was conducted by Horizon in April and May 1999 along the Longhorn pipeline ROW from Austin, Texas, to the Mason/Kimble County line. Although no potentially suitable habitat areas were observed within the Longhorn ROW, several areas were located adjacent to the previously cleared permanent ROW. All areas were surveyed by Horizon a minimum of 5 times during April and May on days with favorable weather conditions for bird activity, per US Fish and Wildlife Service guidelines (FWS, 1994). Surveys were conducted on 8, 9, 12, 27,28 April, and 3, 11, 19 May. An equivalent of 4 person-hours per 100 acres were spent at each site, based on habitat size. No GCWs were found to be utilizing any of the potentially suitable habitat areas on or immediately adjacent to the ROW. One to two additional spring breeding season surveys (as acceptable 990144BA.v-6 33 - 2/14/2000 <<>> to the Service) will be conduced for the GCW along and adjacent to the ROW within the potential habitat areas to determine habitat utilization and overall distribution and abundance. Black-capped Vireo (Vireo atricapillus) The black-capped vireo (BCV) is a 4.5 inch long, insect-eating songbird. Mature males are olive green above and white below with faint greenish-yellow flanks. The crown and upper half of the head is black with a partial white eye- ring. The iris is brownish-red and the bill black. The plumage of the female is duller than the male. Females have a dark slate gray head. In Texas, vireo habitat is found on rocky limestone soils of the Edwards Plateau, Cross Timbers and Prairies, eastern Trans-Pecos, and, to a limited extent, on igneous soils in the Chisos Mountains. BCVs require shrub vegetation reaching to ground level for nesting cover. They typically nest in shrublands. An assessment of potentially suitable habitat and surveys for the BCV was conducted by Horizon in April and May 1999 along the Longhorn pipeline ROW from Austin, Texas to Crane County. Potentially suitable habitat areas were observed within the Longhorn ROW as well as several areas located immediately adjacent to the previously cleared permanent ROW. All areas were surveyed by Horizon a minimum of 5 times during April and May on days with favorable weather conditions for bird activity, per US Fish and Wildlife Service guidelines (FWS, 1994). Surveys were conducted on 8, 9, 12, 27, 28 April, and 3, 11, 19 May. An equivalent of 4 person-hours per 100 acres were spent at each site, based on size. No BCVs were found to be utilizing any of the potentially suitable habitat areas on or immediately adjacent to the ROW. One to two additional spring breeding season surveys (as acceptable to the Service) will be conduced for the BCV along and adjacent to the ROW within the potential habitat areas to determine habitat utilization and overall distribution and abundance. Bald Eagle (Haliaeetus leucocephalus) The bald eagle is a migrant and winter resident in Texas. The bald eagle was recently down-listed from endangered to threatened due to successful conservation efforts and is now proposed for de-listing. Migrating and wintering 990144BA.v-6 34 - 2/14/2000 <<>> bald eagles typically arrive in Texas in November and depart sometime in February. They are found primarily in association with reservoirs, rivers or other large bodies of water where they feed on fish, carrion, and waterfowl. Nesting bald eagles in Texas are found in the eastern portion of the state and along the coastal plain as far south as Calhoun and Refugio counties. No bald eagle nests have been identified near the pipeline ROW, however, bald eagles may occur along major waterways (Brazos and Colorado rivers, or major tributaries with impoundments) downstream of the pipeline corridor. The Federal Register, Volume 64 No. 128 (Tuesday, July 6, 1999; Page 36454) puts forth a proposed rule to remove the bald eagle from the List of Threatened and Endangered Wildlife In the Lower 48 States of the United States and de-listing is expected in the near future. The action is proposed because available data indicates that the species has recovered. Interior Least Tern (Sterna antillarum athalassos) Premier nesting sites for the interior least tern are salt flats, broad sandbars, and barren shores along wide, shallow rivers. Important breeding habitat characteristics include: (1) presence of bare or nearly bare ground and alluvial islands or sandbars for nesting; (2) availability of food (primarily small fish); and (3) favorable water levels during the nesting season (so nests remain above water). They usually nest on sites devoid of vegetation, but have been found in areas with an average of 11 to 30% vegetative cover, composed of grasses, shrubs, and trees and ranging from 1 to 3 feet in height. Vegetation, if present, is usually located well away from the colony, with the exception of bugseed, eastern cottonwood, and sandbar willow. As natural nesting sites have become sparse, birds have used sand and gravel pits, ash disposal areas of power plants, reservoir shorelines, gravel levee roads, and other manmade sites. The typical nesting period for the least tern in Texas is mid-April to mid-August. While the interior least tern has not been documented along the pipeline corridor, potential habitat for the tern is present downstream of the pipeline along several major waterways including the Brazos, Colorado, Llano, and James Rivers, and Squaw, Beaver, and Sandy Creeks. The seasonal occurrence 990144BA.v-6 35 - 2/14/2000 <<>> (spring and summer) and potential nesting of least terns is possible in these areas. Conclusions In conclusion, of the 29 federally listed species of potential occurrence in counties traversed by the Longhorn Pipeline between Houston and Crane, only 8 of those species are documented or estimated to occur within the area of potential effect for the pipeline safety projects due to the presence of potentially suitable habitat. None of the species have been documented to occur within the existing ROW of the pipeline, but several have been documented within proximity, either by suitable habitat, or by sightings of individuals. Additional surveys for the Texas prairie dawn-flower, Navasota ladies-tresses, Tobusch fishhook cactus, Houston toad golden-cheeked warbler, and black-capped vireo will be conducted to further document their presence or absence and population densities in the vicinity of the pipeline. These surveys must be conducted during certain narrow seasons, and therefore, can only be conducted once per year. The survey season for the prairie dawn, fishhook cactus, and Houston toad is February to April. The season for the GCW and BCV are late March to late May. The season for the ladies-tresses is October to November. 990144BA.v-6 36 • 2/14/2000 <<>> 4.0 PROJECT DESCRIPTION Longhorn will implement various pipeline safety and integrity enhancements for the pipeline that include various methods of pipeline testing, anomaly investigations, ROW maintenance, section replacements, cathodic protection enhancements, and pipeline lowerings. Table 2 contains a summary of the proposed projects relating to clearing, maintenance construction, hydrostatic testing, and other integrity-related projects that are addressed in this BA (ref. Project Documentation Appendix at Tab 2). Following is a general description of these safety enhancement projects and the methods by which they will be implemented for the Longhorn Pipeline System. Additional detail may be found in Construction Specification CS4 contained in the accompanying Project Documentation Appendix at Tab 4. 4.1 RIGHT-OF-WAY CLEARING AND MARKING Longhorn has committed to bring the surface of the ground within the ROW into "excellent condition" in order to facilitate surveillance prior to startup of the pipeline (ref. Project Documentation Appendix at Tab 2). Excellent condition is that condition which provides a clear line of sight for aerial and ground surveillance patrols in order to effectively monitor and inspect the ground surface along the ROW. A clean and clearly marked ROW provides a distinctive line of demarcation, indicating a change in land use, where surrounding terrain is natural or heavily developed. ROW maintenance will include mowing, brush-hogging, back-dragging, or hand trimming of tall grass or woody re-growth, trimming of tree canopies overhanging the ROW, setting signs, marking points of intersection (horizontal bends) in the pipeline with PVC posts, and painting cross-fence posts. ROW mowing is performed by a twin-blade mower or a brush-hog drawn by a tractor, to a height between two and four inches. Back-dragging is a method of clearing in rocky terrain; back-dragging involves pulling a dozer blade backwards across the ground surface which has the effect of bending vegetation over at the ground surface. Back-dragging typically does not result in the 990144BA.v-6 37 - 2/14/2000 <<>> uprooting of vegetation. Rather, the vegetation is bent or broken just above the ground surface. Back-dragging is used only in areas where rocks on the surface pose a risk of damage to a mower or brush-hog. Weedy vegetation around surface facilities such as valve settings is at times treated with herbicides such as Roundup and Rodeo. Hand trimming involves line trimmers, chain saws, and similar hand-held equipment. Tree canopies are trimmed by workers, using chain saws, that are raised within reach of the canopies by a man-lift. Steel sign posts are typically set by driving the posts directly into the ground. PVC posts are set into shallow holes dug by post-hole digger. In limited circumstances such as when vandals repeatedly remove pipeline markers, sign- posts are dug by post-hole digger to allow the posts to be set into concrete. Clearing within areas identified as endangered species habitat will not result in any ground disturbance because only mechanical or hand cutting will be employed. The term ground disturbance is intended to mean soil disturbance that would result from grubbing brush and tree stumps; rather, they will be cut at ground level. In limited circumstances, stumps directly over the pipeline, which could have adverse effects on the pipe, will be hand-treated with minimal amounts of non-aromatic and non-persistent herbicide to retard re-growth. Herbicides will be applied in accordance with EPA-approved label directions. These activities are routine and are conducted periodically by pipeline operators in the United States. All areas of the ROW are subject to periodic clearing form time to time. ROW clearing occurs at intervals that depend upon the rate of vegetation growth, typically averaging once per year in arid and semi-arid territory (generally, from Austin to Crane) and typically averaging twice per year in territory with greater rainfall (generally, Houston to Austin). Further, metropolitan areas may be mowed as frequently as monthly to meet municipal ordinance requirements and in response to landowner requests. ROW clearing will be conducted on a schedule that avoids impacts to species; for example, Houston toad habitat will be avoided during the warmer seasons (February through November) when 990144BA.v-6 38 - 2/14/2000 <<>> toads are typically active and potentially upon the surface of the ROW, and plant habitat areas are avoided during the respective blooming seasons. 4.2 PIPELINE MAINTENANCE - CONSTRUCTION PLANNING Prior to project engineering and scheduling, each site is surveyed by qualified personnel to determine whether or not the activity (a) may affect threatened or endangered species and habitat, (b) may cause disturbance of cultural resources, (c) may be subject to Clean Water Act Section 404 (U.S. Army Corps of Engineers jurisdiction over dredge and fill materials in waters of the United States), or (d) may be subject to other federal, state or local laws, regulations or ordinances. Appropriate authorizations are obtained (such as this consultation), and necessary requirements are identified and incorporated into project planning and engineering documentation. Project engineers and technicians perform site inspections to identify site- specific conditions and features that require consideration in project planning, such as site ingress/egress routes, workspace requirements, spoil management, equipment storage, servicing and parking needs, and the like (ref. Tab 5, Environmental Protection Plan, and Tab 6, Storm Water Pollution Prevention Plan in the accompanying Project Documentation Appendix). Such considerations are incorporated into project planning and engineering activities. Unless required by the particular project or by site conditions, workspace is limited to the established ROW. Where workspace is required beyond the limits of the established ROW, those areas have been incorporated into project documentation. 990144BA.v-6 39 - 2/14/2000 <<>> Comments Avoid February through April Avoid February through April Avoid February through April Avoid October through November Avoid October through November Avoid February through October Avoid February through October Avoid March 15 through September 1: Avold March 15 through September 1. Avoid March 15 through September 1 Avoid March 15 through September 1 Avoid March 15 through September 1 Avoid March 15 through September 1 Avold March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Avold March through July Avold March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Avoid March through July Species Texas Prairie Dawni Texas Prairie Dawn Texas Prairie Dawn Navasota Ladies-Tresses Navasota Ladies-Tresses Houston Toad Houston Toad :: EA Contributing Zone Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Black-Capped Vireo Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Black-Capped Vireo Golden-Cheeked Warbler Black-Capped Vireo Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Black-Capped Vireo Black-Capped Vireo Black-Capped Vireo Tobusch Fishhook Cactus TABLE 2 2000 MAINTENANCE ACTIVITIES TESTING AND CLEARING LONGHORN PIPELINE County Harris Harris Waller Fayette Fayette Bastrop Bastrop Travis/Hays Hays Hays Hays Hays Hays/Blanco Blanco Blanco Blanco Blanco Gillespie Gillespie Gillespie Gillespie Gillespie i Gillespie Mason Mason Mason Mason Mason Mason Kimble End Station 2279+20 2411+20 2831+84 5128+64 5948+80 6638+72 6864+00 9961+60 9674+72 9762+72 9926+40 10036+40 10199+20 10461+44 11036+96 11105+60 11441+76 11751+52 11821+92 12149+28 12606+88 12631+52 12728+32 12953+60 13110+24 13217+60 13305+60 13437+60 13578+40 16329+28 Right-of-Way Clearing (Maintenance) - See Comments for Avoidance Timing Begin Station 2013+44 2310+88 2684+00 5095+20 5936+48 6600+00 6723+20 9152+00 9657+12 9724+00 9850+72 9945+76 10164+00 10266+08 11008+80 11080+96 11295+68 11691+68 11791+28 12114+08. 12513+60 12596+32 12633+28 12921+92 13043+36 13203+52 13277+44 13381+28 13513+28 14476+00 Site Right-of-Way (50) Right-of-Way (50) Right-of-Way 50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-or-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50*) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) Right-of-Way (50) <<>> Comments Avoid March 15 through September 1 nvestigation of possible dent; access from improved road to ROW, then 1000 feet down nvestigation of possible anomaly: access from improved road to ROW, then 3000 feet Site entry only, via 5936+48-5948+80 Lowering / Replacement; access. under mproved road to ROW, then 1000 feet down Lowering / Replacement; access from Lowering / Replacement: access from improved road to ROW, then 1000 feet down improved road to field road, then via field road Lowering / Replacement: access from Lowering / Replacement; access from improved road to ROW, then 600 feet down Lowering / Replacement; access 800 feet down ROW from Site LPP-2751 Lowering / Replacement; access from improved road to ROW, then 2500 feet down Investigation of possible dent; access from improved road and dirt road to ROW, then nvestigation of possible dent; access from improved road to ROW, then 1000 feet down nvestigation of possible dent; access from Improved road, 3700 feet of unimproved road to ROW. then 7000 feet to project site ROW down ROW development ROW to project site. ROW to project site 1300 feet down ROW ROW ROW Species Black-Capped Vireo Texas Prairie-Dawn Texas Prairie Dawn Navasota Ladies-Tresses Barton Springs Salamander (EA Contributing Zone) Barton Springs Salamander (EA Contributing Zone) Barton Springs Salamander (EA Contributing Zone) Barton Springs Salamander (EA Contributing Zone) Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Black-Capped Vireo Black-Capped Vireo Black-Capped Vireo EA Contributing Zone County Kimble Harris Harris Fayette Travis Travis Travis Hays Blanco Blanco Gillespie Gillespie Gillespie Mason Travis End Station 15234+56 2073+52 2737+37 5931+12 9197+24 9222+24 9488+24 9807+42 10373+24 10381+24 11725+71 12659+39 12682+16 14012+73 Begin Station 15153+60 2073+52 2737+37 5926+74 9195+80 9220+80 9483+31 9807+10 10369+55 10380+60 11725+22 12659+39 12682+16. 14012+73 Hydrostatic Pressure Test - Header Installation Locations 9338+50 Site Maintenance Construction Right-of-Way (50") DT-20a (K) Crossing (K) 2008 (K) Ph. 1 LPP-2467 LPP.2471 LPP-2546 LPP-2627 LPP-2751 LPP-2753 2016 DT-12a (K) DT-11 DT-9a (K). Site 5-5 <<>> Comments CP Ground Bed - Kimble County Station Coating Reconditioning Coating Reconditioning Coating Reconditioning Species Near Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Black-Capped Vireo Tobusch Fishhook Cactus Tobusch Fishhook Cactus Tobusch Fishhook Cactus Tobusch Fishhook Cactus Texas Prairie Dawn Texas Prairie Dawn Navasota Ladies-Tresses Barton Springs Salamander (EA Contributing Zone) and Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler and Black-Capped Vireo Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler Golden-Cheeked Warbler and Black-Capped Vireo Golden-Cheeked Warbler and Black-Capped Vireo Black-Capped Vireo Tobusch Fishhook Cactus and Black-Capped Vireo Tobusch Fishhook Cactus and Black Capped Vireo Texas Prairie Dawn Houston Toad Houston Toad Tobusch Fishhook Cactus County Blanco Blanco Blanco Mason Kimble Kimble Kimble Kimble Harris-Waller Waller Fayette Travis-Hays Hays-Blanco Blanco Blanco Blanco Blanco-Gillespie Gillespie Gillespie-Mason Mason Mason Kimble Kimble Harris Bastrop Bastrop Kimble 2128+97 6612+99 7085+24 End Station 2415+50 3385+00 5966+47 10163+00 10265+00 10504+50 11188+00 11385+50 12033+73 12360+00 13040+00 13435+00 13910+00 14606+00 16992+40 15592+90 10163+00 10265+00 10742+50 11188+00 11385+50 12033+73 12360+00 13040+00. 13435+00 14373+00 2127+97 14606+00 6609+49 7084+74 Begin Station: 10163+00 10280+00 11385+50 13435+00 14606+00 15143+00 15586+00 16167+00 1802+63 2415+50 5039+00 9647+00 15592+90 Hydrostatic Pressure Test - Test Segments Cathodic Protection Enhancements Site Site 6-1 Site 6-2 Site 6-6 Site 7-3 Site 8-1 Site 8-2 Site 8-3 Site 8-4 Segment 2 ›Section 1 ›Section 2 Segment 3 Section 2 ›Section 6 Surge Pressure Protection Segment 5. Segment 6 > Section 1 > Section 2 ›Section 4 > Section 5. ›Section 6 ›Section 7 Segment7 ›Section 1 ›Section 2 ›Section 3. ›Section 6 Segment 8 (all) CR-1 CRA CR-5 CPGB-5 <<>> P 42 (aloiasua pota o, pus berapie is0 2: :2 AN25 CACOODCE DuNG. шо д : w Й becseegepe extnogou of Aru0o20. DA caco sabuo anioos Osgow S s 0020 .. i. god me bbonte noucu po erockhon Bypass Valve - Liano River East Bank; Same Location as Hydrostatic Test Header Location, s0 monic no s000sa0 at a 8 ¡ oise to omel oi obreco biba. mos miepentee sust uecoeism sit.et 600. r gognno tuondu bicly sompue i homo grin bioleg ais coucy pes ga. piar exebueur co.coon .23- .3CS0 32 ir moa pA 700 i 0u0 Species Tobusch Fishhook Cactus O4 2! •.txcile sucotubaer : a00 0 00l00ne) touecs Colp piespo Biotect pear wansdos trciecr bpumuo msi •A . :3G County Kimble 280 s.::00.sm1bou e bebstey o spo bucioct aLoDü: 3 LeME0 A O3DeOU: End Station 14606+51 amoura ne sioleci 7 ue pipee eug ynoigee Begin Station 14606+51 W500 wedmustene iiK:W0N S.00ORDU Site 2 JGane Surge 4. nosge sednpen its pudneuce o exeup) S слома higig roosgon sisb. <<>> Workspace beyond the limits of the established ROW may be required for a number of reasons. First, avoidance of habitat or the natural terrain along one side of the ROW may necessitate expansion of workspace along the opposite side of the ROW. Second, a sloping surface gradient at a project site may require that spoil removed from the pipeline trench be stockpiled with a wider base, extending off of the ROW, than would be required at a project site with a level surface. Further, a project to lower or replace pipe at a creek crossing may require water diversion measures that necessitate a workspace wider than the established ROW. In addition, though project equipment is typically aligned along the existing pipeline ROW, project site conditions such as size, shape and/or slope may require that equipment be centralized in an equipment marshalling area (typically 25 ft. wide by 100 ft. long). for temporary storage, security and/or service. Biological surveys encompass both areas of potential surface disturbance and areas within the zone of potential indirect construction impacts, such as noise. In addition, applicable project best management practices (BMPs) are identified at this stage of project planning and incorporated into planning documentation. A Project Construction Plan is prepared for each individual project location to document project planning. The Project Construction Plan contains the following sections of detailed information: a. Description of Work for the Project b. Responsibilities and Authorities Safety Requirements d. Job Contacts and Notification Requirements Matrix e. Pre-Job Training Requirements a. Environmental Protection b. Project Schedule C. Forms / Documents Required a. Chronological Sequence of Events b. Appendices as follows: i. Appendix 1 - Location Map ii. Appendix 2 - Drawings, Calculations, and 990144BA.v-6 43 - 2/14/2000 <<>> ili. Specifications iV. Appendix 3 - Environmental Protection Plan V. Appendix 4 - Storm Water Pollution Vi. Prevention Plan vii. Appendix 5 - Safety Procedures Document vili. Appendix 6 - Sample Forms An example Project Construction Plan (Site LPP-2627, pipeline lowering/replacement in Hays County, Texas) is included in the accompanying Project Documentation Appendix, at Tab 3, for reference. A Project Construction Plan relating to each project identified in Table 2 is presently under development; Longhorn will provide to the Service a copy of each Project Construction Plan as it is completed. Project BMPs are defined as procedures and specifications by which environmental controls will be implemented and include such items as sedimentation and erosion controls, reclamation procedures, minimization and avoidance procedures, inspection and reporting procedures, spill containment and cleanup procedures, procedures for addressing unforeseen circumstances, procedures for addressing foreseen, but unpredictable circumstances, and others. Project BMPs are identified and adapted from technical guidance manuals generally accepted as providing the appropriate environmental protection measures, such as the Texas Natural Resource Conservation Commission (TNRCC) technical guidance manual, Federal Energy Regulatory Commission (FERC) Environmental Guidance Manuals, and the City of Austin Environmental Criteria Manual. BMPs are incorporated within the Longhorn Storm Water Pollution Prevention Plan (SWPPP); an example of an SWPPP is included the accompanying Project Documentation Appendix at Tab 6. 990144BA.v-6 44 2/14/2000 <<>> 4.3 PROJECT ENVIRONMENTAL INSPECTORS Longhorn and Williams shall employ the services of environmental inspectors (such as Horizon and 3D/International) at every project site with associated species-related constraints. These environmental inspectors are qualified under FERC guidelines. The environmental inspector will remain at each project site during the period of activity to ensure compliance with all project constraints and project BMPs. The inspector is authorized to dictate any additional project BMPs that may become necessary during the activity and to modify work activities and progress to the extent necessary to ensure compliance with project environmental constraints. However, in the event of a conflict between project constraints and sound engineering practices, the inspector shall consult with project engineers and the Service, as appropriate, to achieve project goals while minimizing any impacts to the environment. The environmental inspector retains oversight of site closure and performs, or supervises the performance of, post-activity inspections of project BMPs until site stabilization is achieved. The environmental inspector will produce appropriate documentation for each construction location to include BMP compliance logs, photographs, as- built dimensions of disturbance, and any encounters with listed species during the construction process. The reports will be provided to the Service after completion. 4.4 SITE PREPARATION Prior to site entry, at locations where avoidance and/or minimization of species effects has been recommended, a qualified biologist will clearly identify areas for avoidance and will stake and/or flag such areas. The project environmental inspector also surveys the site to ensure that all such avoidance areas are clearly identified in accordance with conditions approved in the consultation process and confirms other site-specific areas in which disturbances may occur such as routes of ingress/egress, spoil management areas, equipment marshalling areas, workspace areas, and the like. Project BMPs are reviewed prior to site entry, and the locations of any necessary physical control measures to be employed are identified. A survey crew will precede the project equipment and mark the project 990144BA.v-6 45 - 2/14/2000 <<>> boundaries. In addition, the pipeline centerline is marked at 100 foot to 200 foot intervals. 4.5 SITE ENTRY Upon site entry, the necessary project equipment is transported to the site via the designated route for ingress/egress. Site access is achieved via improved roadways and the established ROW, using the shortest available route between improved roadways and the project site. Routes of ingress/egress take into account any potential for effects to threatened and endangered species and habitat that may exist along the ROW between the improved roadway and the project site, as well as accounting for other potential impacts to the environment. At times, equipment will remain on-site only during the time that it is in active use to allow it to be shared between project sites in close proximity. Prior to any excavation, site vegetation is removed, and project BMPs are installed. Site vegetation is cleared to the extent necessary for project completion, so long as the vegetation is not located in areas identified for avoidance. Clearing is accomplished by the methods described in Section 4.1, Right-of-Way Clearing, though vegetation within the workspace may require removal. Project BMPs are installed in accordance with project planning documentation and in accordance with the site-specific SWPPP. The following task descriptions identify process steps that occur once all authorizations are obtained and regulatory requirements are identified and incorporated into project planning and engineering documentation. Detailed procedures for each of the activities summarized below are available in Pipeline Construction Specification CS4, which is included in the accompanying Project Documentation Appendix at Tab 4. In the event of a conflict between Construction Specification CS4 and the site-specific components of the Project Construction Plan, the Project Construction Plan controls. 4.6 PIPELINE LOWERING AND/OR REPLACEMENT - OPEN TERRAIN Once the project site has been prepared and equipment brought onto the location, the following major activities take place: 990144BA.v-6 46 - 2/14/2000 <<>> • Isolate pipeline segment to be replaced by cutting and plugging at boundaries. Williams operating personnel will establish that the line is unpressurized and properly isolated such that the contractor may cut the pipeline at the project limit boundaries. Mechanical plug devices will be utilized to prevent residual product leakage from the pipeline segments or entry of foreign materials into the pipeline. These devices shall be secured to prevent their loss or tampering. • Remove large rocks, if any, from ROW work area to appropriate disposal/storage area. Trackhoes with buckets are used, unless larger rocks require grapple capable (clam) buckets. • Remove and set aside topsoil spoil (double ditch practices). Double-ditching will be required in areas where native plant communities need to be re-established, or there are topsoil improvements, such as sodded lawn areas and cultivated fields. Double-ditching allows topsoil management by making two passes to remove and segregate spoil; one to remove and set aside topsoil and one to remove and set aside subsoils. • Remove overburden and expose pipe. Utilizing track hoes, remove and set aside overburden from the pipeline and load and remove excess amounts from the work site for disposal. Unsuitable overburden (i.e., large rocks) will be disposed of in approved sites. • Cut pipe into subsections at road and water crossings. Expose and cut the pipeline at road crossing boundaries to isolate the removal section into subsections. Utilize drain pans to recover any remaining liquids as the cut is made. Install mechanical plugs in all exposed pipe ends. • Raise and crib pipe on side of trench. Properly manage any coating which comes loose from the pipe. 990144BA.v-6 47 - 2/14/2000 <<>> Prepare and wrap pipe for disposal. Double wrap the pipe sections with 6-mil thickness plastic wrap, taping and sealing each wrapping separately. Ensure that the ends are sealed to prevent any release of coating. • Remove pipe from ROW. Load and remove the wrapped pipe sections by truck. Care will be taken to preserve the plastic wrapping on the pipe. Secure the pipe to the trailer and haul to the disposal site for final disposition. • Cleanup and grade ROW for survey and trenching operations • Capture, contain, and remove any remaining coating materials/scraps using project-prescribed methods for asbestos containing materials. Prepare the grade on either side of the ditch to accommodate the trenching machinery, removing any large rocks. Survey crew should mark and stake the centerline offsets as required by the trenching crew. • Deepen trench to new depth. Depending upon the length of the desired lowering and/or replacement, and depending upon whether the trench is in soil or rock, a track-hoe or wheel trencher (rock saw") deepens the trench to the new depth. A wheel trencher is typically used for longer trenches and trenches in consolidated rock. Dust generation is monitored during trenching, and a water fog of the trenching mechanism may be employed to minimize airborne dust in non-rural areas. • String new pipe along trench. As the ditch is prepared, the pipe may be strung along the workpad in anticipation of measuring and marking for bending, welding, and lowering operations. The survey crew will note the pipe heat and identification numbers sequence for the individual pieces as they are placed. The survey crew will survey the new ditch profile and mark the pipe for calculated field bends. 90144BA.v- 48 2/14/200 <<>> • Make field bends. The field bending crew will proceed ahead of the welding crew to make any required field bends. The contractor may also elect to set up field bending in one of the equipment marshalling areas and perform bending there rather than on the ROW. Weld and Radiograph new pipeline. The welding crew will proceed to weld the pipeline. Inspectors and survey will note the weld numbers and identification of the welders for this activity. The radiography crew will follow the welding crew. Inspection will be per standard specification API 1104 and include 100% radiography of all girth welds. • Apply weld joint coating and inspect pipeline coating for "holidays"; a holiday is a point where the coating fails to electrically insulate the pipe. Weld joint coating will be applied as specified in the Project Construction Plan. This will be by field-applied FBE (fusion bond ероху). Following weld joint coating, the entire coating system will be inspected for holidays and repaired as required. • Pad and lower pipe. Pad the ditch and lower the pipeline as specified in Construction Specification CS4. Install ditch plugs as required to stabilize pipeline during hydrotest and backfilling. The pipeline coating will receive a final "jeeping" as the pipe is lowered to ensure its integrity. Jeeping is the process of electrically inspecting the pipeline coating to ensure that no "holidays" exist in the coating, so named due to the "jeeping" sound the inspection device emits when a holiday is identified. • Complete as-built survey. Complete as-built survey activities, noting weld locations, pipe identification codes, and location and stationing of bends, fittings and other such features for inclusion in alignment sheet drawings. • Backfill and compact trench. Backfill and compact the ditch according to Construction Specification CS4, maintaining sufficient 990144BA.v-6 49 - 2/14/2000 <<>> cover to allow for settling. Install ditch breakers and silt fencing as appropriate for surface erosion control until the site is stabilized. • Perform hydrostatic pressure test on new pipeline segment. Obtain fresh water for pressure test and begin line fill behind a pig. The test pressure and test duration will be established and specified in the Project Construction Plan or in separate hydrostatic testing plans. Drain and dispose of hydrostatic test water. Upon completion of the hydrostatic test, the test water is either pushed with nitrogen to a subsequent test site or removed into mobile tanks for hauling to a disposal facility. Test water is controlled to ensure that it is fully contained in order to prevent discharge to the environment. • Perform Final Tie-Ins. Remove the test headers and make the final tie-ins of the new pipe segment to the existing pipeline. The tie-in welds will be 100% radiographed to ensure their integrity. Coat the tie-in welds with an appropriate joint coating system compatible with both FBE and coal tar coatings. The coating is inspected, or "jeeped," and any holidays are repaired. The tie-in locations are backfilled and compacted. • Clean, Grade, and Seed Right-of-Way. Following installation of erosion control measures, re-seed the right-of-way with native grass seed and/or sod as prescribed for the location. Re-install pipeline markers and any traffic control devices to limit or restrict ROW access by motor vehicles. • Perform Site Cleanup and Restoration. Clean up equipment marshalling and material storage sites, ensure that the worksite access roads are restored to prime condition, and that any road access ways are cleaned and restored. 4.7 PIPELINE LOWERING AND/OR REPLACEMENT - CREEK CROSSING 50 <<>> Pipeline lowering and/or replacement at creek crossings follows generally the same sequence of activities described above for open terrain; however, the additional activities described below apply to the actual creek crossing area. In addition, creeks may be crossed by either trenching or boring. Each crossing method is summarized separately below. 4.8 TRENCHING A trenched crossing is lowered and replaced in much the same manner as an open terrain project; however, incremental measures are employed to ensure both that erosion and sedimentation are minimized and that no potentially harmful materials are discharged to the waterway. Pipeline Construction Specification CS4 provides additional details. Cut Pipe at Creek Crossings. Expose and cut the pipeline at the creek crossing boundaries to isolate the removal section into subsections. Utilize drain pans to recover any remaining liquids as the cut is made. Install mechanical plugs in all exposed pipe ends. • Implement Water Quality Protection Measures. Staging areas, spoil storage areas, and additional workspace areas are located in upland areas above the creek bed. Hazardous materials such as chemicals, fuels, lubricating oils and any other potentially harmful materials are maintained at least 100 feet from the water body. BMPs are installed to prevent sedimentation. Flumes, dams, equipment bridges and other diversion devices are installed as necessary to perform "dry ditch" excavation. • Erosion control measures are employed after project completion to ensure that stream flows do not cause erosion of disturbed areas and subsequent sedimentation. Erosion controls protect against sedimentation and prevent stream flow from removing pipeline cover which could expose the pipe to steam bed forces. Erosion control measures are site-specific, depending upon site conditions, and include berms, dikes, water bars (perpendicular to the pipeline 990144BA.v-6 51 - 2/14/2000 <<>> alignment), silt fences, staked hay bales, seeding, mulching, hydromulching, riprap, and trench plugs. 4.9 BORING Stream crossings may be installed by boring rather than trenching, depending upon hydrologic and engineering considerations and soil types. The existing pipeline may be abandoned in place after obtaining approvals from the landowner and, if necessary, state and federal authorities, and after (a) filling the pipe with an inert material such as grout or concrete, or (b) sealing the ends of the pipe. The pipe may not be abandoned in place if its presence could interfere with stream flows or interfere with future uses of the waterway. Boring a stream crossing requires the use of a work space for installation of bore pits in which the boring equipment operates. The boring operations typically require a workspace approximately 100 to 250 feet wide by 150 feet long. The workspaces are located above the high water mark unless topography or other factors dictate otherwise. Typically, no instream soil disturbance occurs, and BMPs are employed to ensure that spoil storage and other project activities do not cause erosion or sedimentation. From within the bore pits, the boring equipment creates a parabolic pathway to the pit on the other side of the stream bed. Bored material is circulated out of the bore and retained at the upland spoil storage area. The bore is sealed with grout or bentonite to fill fissures along the course and to ensure bore stability. The new pipe is then pulled through the bore using equipment designed for that purpose. Once the pipe is welded, inspected, surveyed, coated and tested, the excavations are filled and compacted, and the site is restored. Site restoration and stabilization is achieved in the same manner as described in Section 4.6, Pipeline Lowering and/or Replacement - Open Terrain. Any necessary erosion and sedimentation controls are employed, and the site is inspected and maintained until final stabilization is reached. 990144BA.v-6 52 - 2/14/2000 <<>> 4.10 HYDROSTATIC TESTING - OVERVIEW OF ACTIVITIES A hydrostatic pressure test is scheduled to be performed to ensure the integrity of the system. This test is scheduled to commence in February 2000 and conclude in May 2000. Hydrostatic testing will start at the Longhorn GATX pump station in Galena Park (Houston) and proceed westward to Crane Station. The test medium will be potable water from a local municipal supply source. In the event some water is lost due to pipe failure, or if water is needed to fill longer test sections, fresh make-up water will be acquired, by permit, from sources crossed by the pipeline (i.e., from rivers or streams). The hydrostatic testing occurs in segments, which are subdivided into test sections of varying lengths. Factors that contribute to test section length include (a) target test pressures; (b) pipe size and grade; (c) the presence or absence of species and habitat; (d) the location of valves and pump stations; and (e) elevation changes along the pipeline. Due to additional factors, two test sections will not be tested during the Houston to Crane hydrostatic testing project. Those two sections are (a) Segment 4, Section 1, which encompasses habitat for the endangered Houston toad and (b) Segment 5, Section 4, which encompasses the recharge zone of the Edwards Aquifer and part of the adjacent contributing zone, areas of potential effect to the endangered Barton Springs Salamander. Rather, those sections will be tested after Phase II consultation relating to pipeline operation, maintenance and emergency response, and after maintenance construction to replace pipeline segments in those areas is completed. The current hydrostatic testing schedule is as follows: TEST SEGMENT START DATE - END DATE Segment 1 February 11 - February 13 Segment 2 February 14 - February 20 Segment 3 February 21 - February 27 53 221420 <<>> Segment 4 February 28 - March 5 (Section 1 after completion of maintenance construction (May)) Segment 5 After completion of maintenance construction (May) Segment 6 March 6 - March 15 Segment 7 March 16 - March 26 Segment 8 March 27 - April 2 Segment 9 April 3 - April 9 Segment 10 April 10 - April 16 Segment 11 April 17 - April 23 As noted above, the test sections traversing Houston toad habitat and the Edwards Aquifer Recharge Zone will not be tested until after the completion of maintenance construction in those areas, which will not commence until after completion of Phase II of this consultation. The start date for Segment 1 identifies the date that actual testing is scheduled to begin; however, for the remaining test segments, the start date identifies the date on which test water is scheduled to be introduced into that segment from the preceding segment. In addition, any delay encountered during testing, such as to replace a failed segment of pipe, will result in equivalent delays in the remainder of the test schedule. To facilitate hydrostatic testing of the pipeline, headers will be installed on the pipeline at intervals along its length which divide the pipeline into segments for discrete testing. There are forty (40) header sites involved in the test. A general description of the installation of the test headers follows. Additional information is provided in the accompanying Project Documentation Appendix at Tab 8, including a graphic depiction of a typical header site. Headers vary in configuration; however, all function similarly to allow the introduction of test water, the pressurization of the test segment and the displacement, after testing, of the test water to the following test section. Prior to any work, the sites will be subject to an environmental, endangered species, and archeological survey conducted by qualified third-party biologists and archeologists. The headers will be installed by excavating an area approximately 20 ft. wide x 80 ft. long × 4 ft. deep around and under the pipeline. The spoil will be 990144BA.v-6 54 - 2/14/2000 <<>> stored on the temporary work easement. The topsoil will be segregated from the sub-grade for restoration of the site following the hydrostatic test. Storm water management during construction and testing will be by methods prescribed in the SWPPP, an example of which is included in the Project Documentation Appendix at Tab 6. • The exposed pipe will be cut and spread apart horizontally, and pre-fabricated headers will be welded to each section. The downstream header shall have a wire brush pig and displacement pig inserted in it before it is welded on the pipeline. A 6-inch temporary crossover pipe with valve will be installed between the upstream and downstream header. Upon completion of the test, the hydrostatic test water will be displaced into the next test segment by nitrogen. The test section will be vented to atmosphere and the temporary piping and headers will be removed. The pipeline will be tied back together with a joint of new pre-tested pipe and the joints will then be coated and wrapped to provide corrosion protection. Coating is inspected for holidays, and repairs are made if holidays are identified. The excavated area will be backfilled and compacted with the subgrade material in the spoil pile followed by the topsoil to finished grade to match the surrounding terrain. The disturbed area is seeded with native grasses or sod, and BMPs are inspected and maintained until the site is stabilized. Total surface workspace requirements for test header installations are about 100 feet wide by 150 feet long along the pipeline. 4.11 HYDROSTATIC TESTING - POTENTIAL FAILURE OF PIPE Hydrostatic testing of the existing Longhorn Pipeline between Houston and Crane is expected to result in a number of failures. Some of those failures, and actions taken to locate failure locations, could have effects upon both species and habitat. However, the calculation of the effects of such failures is difficult to estimate since the location of any such failure cannot be predicted and since the volume of test water that may be discharged is difficult to predict. 990144BA.v-6 55 - 2/14/2000 <<>> Calculations by a pipeline integrity consulting firm estimate that approximately 18 to 20 failures will occur at the high test pressures planned. Since the most likely failure location is at pipeline flaws, the location of the expected failure cannot be predicted with any accuracy; at most, a minimal number of recently replaced sections of pipe may be eliminated from consideration. Therefore, the expected failures will approximate a random distribution over the Houston to Crane segment. A finite number of failures could be assigned to the habitat areas based upon the proportional share of pipeline mileage in habitat areas; however, that methodology would probably result in either overestimation or underestimation of the number of failures in habitat areas. In addition, the potential volume of test water discharged in the event of failure is difficult to estimate. First, if a failure results in rapid depressurization of the test segment, the volume of test water discharged will be the sum of (a) water expelled as the pipe returns to atmospheric pressure, which depends upon test pressure and test segment length, and (b) drainage from any adjacent segments at elevations higher than the failure location. Second, if a failure results in a slow depressurization of the test segment, it may be readily identifiable and quickly contained. If a slow leak is difficult to locate, one or more investigative excavations could be required to either search for the failure or plug a portion of the segment so that lengths of pipe may be eliminated from the search. Therefore, given that failure location and size cannot be predicted, potential effects on species and/or habitat cannot be reasonably estimated in advance. Another factor that makes such estimates difficult is the existence of residual amounts of diesel fuel that remain in the pipeline from cleaning during 1998. As the hydrostatic testing proceeds from east to west, the test water may be expected to reflect relatively higher levels of hydrocarbon content; however, those concentrations cannot be predicted. Spill response equipment such as booms, sorbant pads, and other containment and cleanup equipment will be maintained in the vicinity of the test sites during the procedure. In summary, the locations of hydrostatic test failures cannot be predicted, the volume of test water discharged may not be calculated, and the number of investigative excavations cannot be predicted. 990144BA.v-6 56 - 2/14/2000 <<>> 4.12 CATHODIC PROTECTION ENHANCEMENTS Enhancements of the pipeline cathodic protection system consist of (a) installation of anode beds and (b) re-coating of sections of existing pipe. The cathodic protection system protects the pipe from corrosion. These enhancements are identified and described in the accompanying Project Documentation Appendix at Tab 2, and the locations where activities may affect species and habitat are identified in Table 2. Project planning is performed in a manner similar to that described in Sections 4.3 through 4.5 above. Installation of deep anode ground beds requires a series of vertical bores within which sacrificial anodes are placed; the anodes within each bore and among the series of bores are connected by subsurface wiring that is then connected to the pipeline. The bores and wiring trenches are installed within the existing ROW. During boring, a circulating pit is dug to contain cuttings removed from the bore. After project completion, the pit is filled, excess cuttings are removed for disposal, and the site is closed in the manner described in previous discussions of construction site closure. An example project work plan and related diagrams that provide additional detail about deep ground-bed installation are included in the accompanying Project Documentation Appendix at Tab 11. Pipeline coating reconditioning involves the same activities required for a pipeline lowering or replacement, with the exception of the process steps to remove existing pipe and install new pipe. A coating replacement site undergoes the project planning, site preparation, site entry, and site closure steps much as described above in Sections 4.2 through 4.6. Since the pipe is not cut, any residual liquids within the pipe do not present contamination potential. Asbestos containing pipe coating is managed in accordance with the provisions of the Environmental Protection Plan and the Project Construction Plan (ref. the accompanying Project Documentation Appendix at Tabs 5 and 3, respectively). All coating reconditioning is inspected, or "jeeped," and any holidays are repaired. 4.13 SURGE PRESSURE PROTECTION 990144BA.v-6 57 - 2/14/2000 <<>> To reduce the risk of over-pressurization of the pipeline, Longhorn will implement system changes and operating practices to limit surge pressures to no more than maximum operating pressure in sensitive and hypersensitive areas identified by the Lead Agencies (ref. Project Documentation Appendix at Tab 2). One system change involves the installation of over-pressure activated by- pass systems that will allow a pressure spike to be relieved around certain gate valves. The installation of a by-pass system involves the same process steps as the installation and removal of a hydrostatic test header; see Section 4.10. The by-pass system to be installed at the east bank of the Llano River will use the same work location as the hydrostatic test header to be installed at that valve site. 4.14 INVESTIGATIONS Projects to investigate possible pipe dents and corrosion anomalies follow the same planning and preparation procedures for a pipeline lowering/replacement, but on a lesser scale. Table 2 identifies relevant information for, and the locations of, projects to investigate possible pipe dents and corrosion anomalies. Typical investigation sites require a trench approximately 20 feet in length. If a dent or anomaly cannot be field repaired, a segment of pipe will be removed and replaced, with the length replaced at least twice the pipe diameter. Coating and coating inspection and repair, as well as site closure, follow the procedures described in Section 4.0. 990144BA.v-6 58 - 2/14/2000 <<>> 5.0 POTENTIAL IMPACTS (TAKE) AND COMPENSATION ATake@ of listed species is defined in the ESA and implementing regulations as the act or attempted act of pursuing, hunting, shooting, wounding, killing, trapping, capturing, collecting, harming, or harassing. Harm and harass are defined as the act of disturbing individuals or modifying habitat to the extent that wildlife are actually killed or injured by impairment of essential behavioral patterns such as breeding, feeding, or sheltering. Potential take of certain listed species could occur from a number of actions or events associated with the implementation of the subject project activities described in Section 4.0, including maintenance construction, hydrostatic testing, ROW maintenance, and cathodic protection enhancements. No individuals of any listed species have thus far been documented within the existing pipeline ROW; however, the potential for incidental take cannot be eliminated. Surveys and detailed habitat assessments have been conducted for a number of species of concern, and additional surveys are scheduled for the near future; however, the Service has recommended in the December 15, 1999 Comment Letter that additional surveys be conducted for several years into the future to confirm the presence or absence of species within areas of potential habitat. Furthermore, the hydrostatic testing project could affect habitat areas, but no reasonable means exists to predict or to quantify the potential for take. Alternatively, take may be assumed without reference to the presence or absence of species. Assumed take will very likely result in overcompensation; that is, since surveys have not identified individuals in the pipeline ROW, assumed take will result in compensation for areas of potential habitat where species utilization has, to date, not been confirmed. That overcompensation will provide a net benefit to the species for several reasons. First, surveys to date have not identified individuals in the area of impact for the subject maintenance construction activities; thus, compensation occurs even though there is no documented take. Second, Longhorn will implement numerous controls to ensure that the project activities are conducted first to avoid, and otherwise to minimize, potential effects to species and habitat. Examples include identifying and marking habitat areas for avoidance; planning project implementation to minimize the potential for any effects; use of FERC- 990144BA.v-6 59 - 2/14/2000 <<>> qualified inspectors with authority to alter a project in areas with species related concerns; adjusting project timing to avoid periods of activity and blooming seasons; and implementing storm water pollution control BMPs even when not required by permit. Thus, any potential adverse effects will be avoided or minimized. Third, potential habitat has been assumed over broad areas when, in fact, detailed surveys could reveal that occupied habitat is either absent or of doubtful viability to a species. The end result is that the potentially affected species benefit by conservation efforts on a scale greater than any likely incidental take. Longhorn proposes, therefore, to assume an incidental take for the entire width of the pipeline ROW traverse of broad areas of potential habitat. This conservative assumption will result in overcompensation to the benefit of the potentially affected species and habitats. Take is calculated based on the extent of potentially suitable habitat within the established ROW (50-foot width x length) and within temporary workspaces that exceed the ROW (i.e., equipment staging areas, spoil management areas, and stream diversion areas, the size of which varies by location). On that basis, the take for each species is calculated as indicated in Table 3. As discussed in Section 4.11, Hydrostatic Testing - Potential Failure of Pipe, the locations of potential hydrostatic test failures cannot be accurately predicted, the volume of test water discharged cannot be accurately predicted or calculated, and the number of investigative excavations cannot be predicted. The inability to accurately predict the potential impacts of hydrostatic test failures precludes any pre-activity attempt to predict and/or estimate the potential effects of test failures. Any such attempt would be likely to result in inaccurate estimates. Therefore, Longhorn proposes to provide for a contingent methodology for calculating any such effects. 990144BA.v-6 60 _ 2/14/2000| <<>> Table 3: ROW Clearing/Maintenance and Additional Construction Impacts* Within Listed Species Habitat - Longhorn Pipeline ROW Clearing/Maintenance Area: Texas Prairie Dawn 53,392 linear feet × 50 feet 61.3 acres Navasota Ladies-tresses 4,576 linear feet x 50 feet 5.2 acres Houston Toad 17,952 linear feet x 50 feet 20.6 acres Golden-cheeked Warbler 90,096 linear feet x 50 feet 103.4 acres Black-capped Vireo 36,256 linear feet x 50 feet 41.6 acres Tobusch Fishhook Cactus 185,328 linear feet × 50 feet 212.7 acres TOTAL ROW IMPACTS = 444.8 acres Additional Maintenance Construction Area Construction Dimensions** Species Impact Site Stationing Acres LPP-2753 LPP-2751 10369+55 - 10373+24 200 × 1033 200 × 1000 GCW 4.7 2016 10380+60 - 10381+24 200 × 806 GCW GCW 4.6 Hydrostatic Header 3.7 And Test Sites Site 6-6 Site 6-2 10280+00 50 × 100 GCW 50 × 100 GCW 0.1 0.1 11385+50 Site 8-2 Site 7-3 13435+00 15143+00 50 × 100 50 × 100 TFC BCV 0.1 Site 8-3 15586+00 16167+00 50 × 100 TFC 0.1 Hydrostatic Transfer Site 8-4 0.1 50 x 100 TFC 0.1 Sites Site 6-1 Site 8-1 10163+00 50 x 150 GCW 0.2 And Surge-4 14606+00 50 × 150 TFC 0.2 TOTAL MAINTENANCE CONSTRUCTION IMPACTS 14.0 TOTAL IMPACTS 458.8. Of the methodologies available for calculating the effects of activities upon 2214200 G <<>> species and habitat, the most applicable is the Habitat Equivalency Analysis (HEA) methodology developed by the National Oceanic and Atmospheric Administration for Natural Resources Damages Assessments (NRDAs). The HEA methodology is briefly described by the following steps: The duration and extent of injury are documented and estimated from the time of injury until the resource recovers to baseline; • The services provided by a compensatory project are documented and estimated over the full life of the project; • The size of a compensatory project is calculated such that the total increase in services provided by the compensatory project equals the total interim loss of services due to the injury; and • The cost of the compensatory project is calculated. A more detailed description of the HEA methodology is provided in accompanying Project Documentation Appendix at Tab 10. Longhorn's proposal, then, is to execute the following sequence of measures in the event a hydrostatic test discharge occurs in areas of concern for species and/or habitat: • In the event of a test failure, immediately notify a qualified biologist, who will be maintained on standby along the test segment, and direct the biologist to the failure site; • If a discharge occurs, the biologist will assist the identification of response actions to minimize potential impacts to the environment; and, • The biologist will perform a field survey to document the loss of, destruction of, or injury to natural resources (a) at the location of any excavation, whether the excavation is for location of a failure or for repair of pipe; (b) within the area of impact of the test water; and (c) in any other areas affected by the response to the test failure, as at any other construction site. The effects, if any, of the hydrostatic test failure upon species and/or habitat will then be calculated pursuant to the HEA methodology. Longhorn shall 990144BA.v-6 62 • 2/14/2000| <<>> compensate for the value of any such adverse effects by paying the monetary value of an appropriate compensation project to conservation efforts directed at the preservation and recovery of the affected species and habitat in the region where the impact occurred. For example, if a hydrostatic test resulted in a take of golden-cheeked warbler or black-capped vireo habitat, Longhorn would contribute the requisite monies to appropriate conservation entities acceptable to the Service, such as Balcones Canyonlands Conservation Plan, The Texas Nature Conservancy, or similar initiatives. 5.1 SPECIES BY SPECIES IMPACT ANALYSIS Texas Prairie Dawn (Hymenoxys texana) Potential impacts to the Texas prairie dawn may result from a number of activities. Right-of-way maintenance will occur with the periodic (typically twice per year) use of tractor drawn mowers. Tractors will be rubber-tired, but crushing of plants could occur from time to time, particularly during blooming periods. Mowing height will typically be 3 to 4 inches. Since only the blooming shoot is usually that high, impacts from mowing are deemed to be minimal, except during blooming. Impacts, while not believed to be significant, are quantified as the total ROW (50') through the entire area of identified potential habitat. As indicated in Table 3, this area constitutes approximately 61.3 acres. As an avoidance and minimization measure, mowing will be scheduled to avoid the February through April blooming season. A blooming season survey of the ROW and adjacent areas is recommended to identify any plant locations for specific avoidance, if present. Three construction sites have been identified for completion in the near- term, two dent investigations, and one anomaly investigation (ref. to Table 2). Impact for these three construction areas will be contained within the existing 50' ROW for relatively short distances along the pipeline (see Table 3). Within these areas, excavation, temporary spoil storage, equipment movement, and grading will likely result in elimination of any prairie dawn plants that may occur within the ROW in the construction areas. The area of these impacts is already included in the total ROW impact mentioned above. 990144BA.v-6 63 - 2/14/2000 <<>> Navasota Ladies-tresses (Spiranthes parksil) As in the case of the prairie dawn, periodic (twice per year) mowing with rubber-tired tractor mowers may result in sporadic crushing of plants under tractor tires or mower wheels, or cutting of bloom stalks. Impacts from periodic mowing are again not expected to be significant, but in the absence of detailed plant inventory information for the ROW, an assumed total impact for the ROW through the identified potential habitat areas constitutes 5.2 acres (Table 3). As an avoidance and minimization measure, mowing will be scheduled to avoid the October and November blooming season. A blooming season survey of the ROW and adjacent areas is recommended to identify any plant locations for specific avoidance, if present. No areas of construction are identified in the two potential habitat areas. However, construction will occur just east of the most westerly potential habitat area. The ROW is to be used for access to the construction zone (see Table 3). It is presumed that heavy equipment movement along this portion of the ROW will result in destruction of any plants growing at that locality. Access will be kept within the existing 50' ROW; therefore, potential impacts have already been calculated in the ROW maintenance value above. Houston Toad (Bufo houstonensis) Right-of-way maintenance will again include periodic mowing with rubber- tired tractors. Mowing could generally reduce grass thickness and height, thereby improving mobility for Houston toads. However, since Houston toads are mobile, the possibility exists for run-overs by tractor tires or jumping into the mower blades by toads. Toads are predominantly active during a few months of the year; therefore, the possibilities of encounter are fairly remote. As a means of providing additional avoidance procedures, pipeline ROW maintenance will be timed to occur in the late fall through early spring (November to January) when the toads are generally inactive to limit the possibility of direct impact. In addition to these avoidance procedures and the low likelihood of encounters, Longhorn will assume that all areas of potential habitat traversed by the pipeline ROW are suitable and will commit to compensate for the entire ROW width. From Table 3, this amount is approximately 20.6 acres. Horizon has recommended a spring 990144BA.v-6 64 - 2/14/2000 <<>> breeding season survey for the toad in the vicinity of, and downstream of the pipeline to determine possible toad presence, population, and breeding areas that could be affected. No construction impacts to Houston toads are contemplated in this consultation. Pipe replacements within the toad habitat area will be addressed in the second phase consultation. Edwards Aquifer Contributing Zone - Barton Springs Salamander Right-of-way maintenance and four construction locations are presently contemplated to occur within the contributing zone of the Edwards Aquifer in Travis and Hays counties. The principal concern for impacts to listed species in this area is by siltation from disturbed areas being transported by storm runoff to streams that eventually run onto the Edwards Aquifer Recharge Zone, potentially entering the aquifer, and lowering the quality of water utilized by the Barton Springs salamander. While single projects are not likely to have any demonstrable effects on the salamander, the cumulative effects of many development projects throughout the recharge zone and contributing zone may collectively cause negative impacts. Right-of-way maintenance, consisting of mowing and trimming, is not likely to result in any level of sedimentation or impacts since the activity will not result in ground disturbance. Enhanced Best Management Practices (BMPs) will be utilized throughout construction in disturbed areas to prevent sediment loads from reaching the aquifer or significantly reduce such loads. BMPs are identified in the Project Documentation Appendix, Stormwater Pollution Prevention Plan (Tab 6). The BMPs will also include reclamation of disturbed areas immediately following construction for rapid growth and stabilization of grasses and annuals. As a result of these enhanced BMPs, no significant impacts to the aquifer or Barton Springs salamander are contemplated. Golden-cheeked Warbler - (Dendroica chrysoparia) Golden-cheeked warbler habitat does not exist in the established ROW, 990144BA.v-6 65 - 2/14/2000 <<>> but is presently adjacent to the ROW in a number of locations from Hays County westward to Mason County. Right-of-way maintenance will not directly affect warbler habitat, except for hand pruning of canopies which overhang the ROW. Indirect effects may result from mowing noise or activity if birds are present in the vicinity during maintenance activities. As a minimization procedure, Longhorn will schedule maintenance activities to occur during the non-nesting season (September 1 to March 1) within or near warbler habitat areas to avoid indirect impacts. While no significant impacts are anticipated to occur, Longhorn will mitigate for the full ROW width (50') through potential warbler habitat areas. The area of potential effect is determined to be 103.4 acres (Table 3). Six areas of pipeline maintenance construction or investigation are anticipated to occur along the pipeline within areas identified as potential warbler habitat (Table 2). Each of those areas are estimated to require additional construction space in excess of the existing ROW by variable widths (Table 3). The total additional impact to warbler habitat resulting from construction clearing is 13.4 acres. The additional areas of temporary work space are needed in these areas to facilitate temporary spoil storage, machinery access, pipe stacking, and miscellaneous construction related activities. As avoidance and minimization procedures, Longhorn will to the extent possible, schedule construction activities, particularly clearing, to occur during the non-nesting period (September 1 to March 1). As with the immediately impending construction schedule, clearing will commence prior to March 1st and construction activities will continue continuously until completion. Total estimated impacts to potential warbler habitat are 116.8 acres. Black-capped Vireo - (Vireo atricapillus) Seven areas of potential black-capped vireo habitat exist along the ROW between Blanco and Kimble counties. Black-capped vireo habitat, being an early successional stage of brushy regrowth, does exist within the existing ROW in locations where previous maintenance activities have not occurred in several years. In this case, ROW maintenance will directly impact potential habitat within the existing ROW. The area of direct impact for the full 50' width of the ROW through the various habitat areas constitutes approximately 41.6 acres. Indirect 990144BA.v-6 66 - 2/14/2000 <<>> impacts from ROW maintenance are not likely since maintenance activities will be conducted during the non-nesting season (September 1 to March 15) for vireos. Four maintenance construction locations have been proposed within the areas identified as potential vireo habitat (Table 2). Only one of those construction sites will require clearing beyond the 50' ROW width. An additional 50' of temporary work space will be needed to facilitate temporary spoils storage, equipment access, pipe layout and construction room. The additional acreage of disturbance for this construction site is 0.1 acre. The total area of impact to potential black-capped vireo habitat is 41.7 acres. Tobusch Fishhook Cactus - (Ancistrocactus tobuschit) Potential habitat for the fishhook cactus is very generally estimated from general soils and plant distribution information to include the entire reach of the pipeline's traverse of Kimble County. Without specific survey information for the cactus, it is assumed that the entire ROW across Kimble County is potential cactus habitat. As with the Texas prairie dawn and Navasota ladies-tresses, the Tobusch fishhook cactus is low growing and not likely to be directly affected by mowing, except for possible crushing by tractor tires. However, due to the significant extent of large rocks within the ROW, mowing is not always feasible in this region. A preferred method in rocky terrain is to back drag a bulldozer blade across the ground which knocks down undesirable woody vegetation. This activity can disrupt the ground surface and possibly injure or destroy cactus plants. Therefore, direct impacts to fishhook cactus habitat may occur from time to time. The total area occupied by the ROW across Kimble County is 212.7 acres. Four test header installation locations are planned within the potential fishhook cactus habitat. Each site will disturb an additional 50' width beyond the ROW for the construction of the headers. The additional space is required to facilitate temporary spoils storage, equipment access, pipe construction, and testing equipment. The additional area of impact per site is between 0.1 and 0.2 990144BA.v-6 67 - 2/14/2000 <<>> acre. The total additional impact to cactus habitat is 0.5 acre. The total impact acreage for Tobusch fishhook cactus is 213.2 acres. Other Species Listed species that may occur away from or downstream of the pipeline corridor (ie., bald eagle, interior least tern, American alligator, Barton Springs salamander) are not likely to be adversely affected by the proposed maintenance and minor construction activities. Any discharges of hydrotest waters are not expected to contain levels of hydrocarbons or other toxic materials sufficient to result in adverse impacts. 5.2 AVOIDANCE AND MINIMIZATION Longhorn will, to the extent reasonably possible, conduct the maintenance construction, testing, and other subject activities in a manner that avoids potential effects to species and habitat. If avoidance is reasonably and practically unachievable, Longhorn will conduct the activities in a manner that minimizes any potential effects. Controls and other measures designed to achieve that goal are described in the foregoing descriptions of the various activities. A number of those controls and measures are summarized as follows: 1. Identifying and marking habitat areas for avoidance; 2. Planning project implementation to minimize the potential for any effects; 3. Use of FERC-qualified environmental inspectors with authority to alter project implementation procedures in sensitive areas; Adjusting project timing to avoid breeding populations; for example, projects in Houston toad habitat will avoid the months of February through November, and projects in GCW and BCV habitat areas will avoid March through August and April through September, respectively; Implementing storm water pollution control BMPs even when not required by permit; 6. Maintaining qualified biologists in hydrostatic test project areas for 990144BA.v-6 68 - 2/14/2000 <<>> immediate response in the event of a test water release in a habitat area; Avoiding, until project planning is accomplished, hydrostatic testing over the Edwards Aquifer recharge zone, portions of the contributing zone, and in Houston Toad habitat areas; and Conducting additional species surveys along the pipeline ROW to determine actual presence or absence of species and populations where present. Additionally, work in areas of noise-sensitive species (i.e., GCW, BCV) will be avoided during the breeding/nesting season. If work must occur in habitat areas during a noise-sensitive seasons, the Service will immediately be notified. Biological surveys of the habitat areas will be conducted prior to construction to determine the presence or absence of species and specific locations if present. Avoidance and minimization procedures, as appropriate to protect the species, will be implemented based on these surveys. 5.3 PROPOSED COMPENSATION FOR POTENTIAL TAKE Longhorn proposes the following steps for calculating compensation, for funding that compensation, for implementing the process by which the compensation is valued initially and in the future, and for assuring the Service, the public and interested parties that the total compensation will be funded in full. Longhorn has applied a formula recommended by the Service to determine appropriate compensation. The formula is: Impact acreage × 1.2 x fair market value of land in the area. This formula is modified for Houston toad habitat to use a 3x multiplier instead of 1.2 due to the more critically imperiled nature of the toad population in general. The Service also recommends the application of a one-time 10% inflation factor to anticipate increases in land values over time. Longhorn has calculated compensation for purposes of this BA on the basis of this formula and best estimates of land values in the area of each respective species. Longhorn proposes that actual land values be determined for purposes of calculating compensation on the basis of land appraisals according to the following process. 990144BA.v-6 69 - 2/14/2000 <<>> Within 60 days following the Biological Opinion, Longhorn will engage two licensed appraisers to determine the average value of land in the vicinity of the impact areas for each species along the pipeline. If the two appraisals differ by greater than 5%, then a third appraisal shall be engaged to reach a determination. All appraisals shall take into account land uses and conditions in such vicinity. The current calculation of compensation, set out below, will then be revised based upon the average of the two or three, as the case may be, appraisals. Longhorn proposes a series of payments over time to fund the necessary compensation, with such payments being made in a manner which will maximize benefits to the potentially affected species. For example, maximum benefit to the species may be achieved through Service concurrence that the initial payment go toward conservation efforts directed to the Houston toad and the Tobusch fishhook cactus; since those species face a relatively greater prospect of decline than the remaining species. Longhorn proposes to provide this compensation amount to one or more conservation funds devoted to conservation of the affected species, on an annual basis over a six year period. Future land values shall be determined on the basis of appraisals performed every second year following the initial appraisals and determined employing the same methodology as described above. The remaining compensation due from Longhorn shall then be recalculated based upon the compensation acreage remaining to be funded and the most recent land appraisals for such acreage. Longhorn has solicited the participation of the Service in the identification of conservation funds that provide the greatest benefit to the affected species as a whole. In particular, Longhorn's intent is for the funds to support conservation efforts that employ preservation and recovery actions at least as comprehensive as the actions recommended in the Service's December 15, 1999 Comment Letter and in the relevant species recovery plans. Potential recipients may include the National Fish and Wildlife Foundation, the Texas Parks and Wildlife Department (TPWD), Texas Nature Conservancy, Texas Land Trust, Trust For Public Lands, and similar comprehensive conservation initiatives. Longhorn 990144BA.v-6 70 - 2/14/2000 <<>> prefers that the payments be directed to the National Fish and Wildlife Foundation and TPWD. This amortized payment scale will provide a reliable funding stream for the subject species for an extended period to purchase and manage habitat areas, enhance habitats, fund artificial propagation, and conduct other recovery efforts identified by the various species' recovery plans. The amortized payment schedule encourages an adaptive approach to managing these species by allowing the Service to redirect the funds over time to their highest and best use. As scientific research on the needs of these species continues, the Service may find that resources for the protection of the species should be redirected-perhaps to management and recovery practices of which the scientific community is not yet aware. Rather than committing all the conservation funds to one particular endeavor now, the amortized payment schedule allows the Service to apply the funds strategically over time as conservation priorities change and the understanding of the species grows. An amortized payment schedule also allows the regulated community, such as Longhorn, to commit a greater amount of funds than might otherwise be available. A payment schedule such as this one may establish a useful precedent that will provide an incentive for other private entities, including pipelines, to enter into conservation agreements that otherwise may seem financially prohibitive. This encourages voluntary compliance which ultimately benefits the species. The implementation of the Longhorn proposal will require that appraisals be obtained for calculation of present-day compensation. Longhorn proposes to accomplish the foregoing over the 60 day period following issuance of the Service's biological opinion. Longhorn may at its discretion, at any point in time, (a) pay all outstanding compensation on the basis of the most recent appraised values; or (b) purchase required acreage acceptable to the Service for any given species. Exercise of the foregoing discretion shall reduce remaining obligations and security requirements. 990144BA.v-6 71 - 2/14/2000 <<>> Given the timing matters identified above, Longhorn will provide assurance to the Service that the calculated compensation (refined on the basis of actual land appraisals) will be funded on time and in full. Such assurance will take the form of security that assures the Service that the compensation will be funded. Longhorn proposes such methods as a bond, a letter of credit, an escrow, or similar such mechanism reasonably acceptable to the Service. The security will cover compensation not proposed for immediate funding and the one-time 10% escalation value applied to same. Longhorn makes this proposal conditioned upon the requirement that, as payments are made or in-kind compensation is provided, a corresponding reduction be made in the compensation acreage outstanding and thus in the amount of security required. At issuance of the Biological Opinion, Longhorn shall provide to the Service reasonable evidence that the security is in place. The proposed payments, as secured, will assure that the compensation acreage is in fact acquired to benefit the species. Based upon the Service's recommended formula, the impacts described in Section 5.1, and best estimates of present land values, the present calculation of compensation would be as follows: Texas Prairie Dawn 61.3 acres × 1.2 = 73.56 acres x $3,000/ac + 10% = $242,748 Navasota Ladies-Tresses 5.2 acres × 1.2 = 6.24 acres x $1,000/ac + 10% = $ 6,864 Houston Toad 20.6 acres × 3.0 = 61.80 acres x $2,000/ac = $123,600 Golden-Cheeked Warbler 116.8 acres × 1.2 = 140.16 acres x $2,000/ac + 10% = $308,352 Black-Capped Vireo 990144BA.v-6 72 - 2/14/2000 <<>> 41.7 acres × 1.2 = 50.04 acres × $1,000/ac + 10% = $ 55,044 Tobusch Fishhook Cactus 213.2 acres × 1.2 = 255.84 acres x $1,000/ac = $255,840 Total Compensation $992,448 The total compensation figure stated above is to be funded according to the schedule in Table 4. 990144BA.v-6 73 2/14/2000 <<>> Table 4 Longhorn Pipeline Take Compensation Bonded Amounts Year HT TFC TPD/NLT/GCW/BCV TOTAL• 2000 123,600 255,840 379,440 2001 102,168 102,168 2002 102,168 102,168 2003 102,168 102,168 2004 102,168 102,168 2005 102,168 102,168 2006 102,168 102,168 TOTAL 123,600 255,840 613,008 992,448 Prepay Option Longhorn may elect to prepay amounts earlier than scheduled with corresponding drop in security and compensation requirements. In-Kind Option Longhorn may purchase required acreage acceptable to the Service with corresponding drop in security and compensation requirements. Subject to adjustment based upon appraisals to be obtained by Longhorn. 990144BA.v-6 74 - 2/14/2000 <<>> Thus, the Longhorn proposal, which is tabulated in Table 4, may be summarized as follows: At issuance of Biological Opinion: Provide security for total estimated compensation of $992,448; During 60 days following Biological Opinion: Obtain land appraisals to determine current value of total compensation; 3. Within 30 days of Appraisals: Fund acreage attributable to Houston Toad and Tobusch fishhook cactus based upon initial appraisals; Adjust security requirement to reflect appraised values and initial payment; Annually following Biological Opinion: a. Scheduled payments are made; and b. A corresponding reduction is made in the compensation acreage outstanding, and the required security is reduced to an amount necessary to secure the then outstanding compensation acreage; and 6. Bi-Annually following Biological Opinion: Obtain appraisals to determine average land values, and adjust security requirement to reflect changes in land uses. This commitment is being made without regard to whether or not the pipeline is eventually placed into service; rather, this commitment is based upon the level of take that occurs as described above. 990144BA.v-6 75 2/14/2000 <<>> 6.0 REFERENCES Arroyo, Bryan. Threatened and Endangered Species of Texas. Austin, Texas: US Fish and Wildlife Service, Revised June 1995. Blair, W.F., The Biotic Provinces of Texas. Texas Journal of Science. 2:93-117, 1950. Campbell, Linda. Endangered and Threatened Animals of Texas. Austin, Texas: Texas Parks and Wildlife Department; Resource Protection Division, Davis, W.D. & Schmidly, D.J.. The Mammals of Texas. Texas Parks and Wildlife Department. Austin, Texas, 1994. Gould, F.W.. Texas Plants: A Checklist and Ecological Summary. Texas A&M University Agricultural Experiment Station. MP-585/Revised. College Station, Texas, 1975. Horizon Environmental Services, Inc. Threatened or Endangered Species Investigations - EZ Pipeline Project. 1991. Poole, Jackie M. and David H. Riskind. Endangered, Threatened, or Protected Native Plants of Texas. Austin, Texas: Texas Parks and Wildlife Department, 1987. United States Fish and Wildlife Service. Determination of Critical Habitat for the Houston toad. Federal Register 43(21):4022-4026. 1978. United States Fish and Wildlife Service. Minimum Procedures for Determining the Presence/Absence of Golden-Checked Warblers and Black-Capped Vireos. March 7, 1994 Memorandum, Austin Field Office. 1994. 990144ba.v-6 - 2/14/2000 76 <<>> Phase I FWS Biological Opinion February 17, 2000 <<>> ted States aND mere see the Inter gre Ecological Services Field Office FISH AND WILDLIFE SERVICE 10711 Burnet Road, Suite 200 (512) 490-0057 / 490-0974 Austin, Texas 78758 (iax) MARCH 18A9 February 17, 2000 Consultation Number 2-15-00-F-413 Gregg Cooke Regional Administrator, Region 6 U.S. Environmental Protection Agency 1445 Ross Avenue, Suite 1200 Dallas, Texas 75202-2733 Rodrick Seeley Regional Director, Southwest Region U.S. Department of Transportation, Office of Pipeline Safety 2320 LaBranch Road, Room Number 2116 Houston, Texas 77004 Dear Mr. Cooke and Mr. Seeley: The U.S. Environmental Protection Agency, Region 6 (EPA) (February 10, 2000) and the U.S. Department of Transportation, Office of Pipeline Safety, Southwest Region (OPS) (February 17, 2000) submitted letters requesting consultation with a Biological Assessment for the proposed Longhorn Pipeline Project, Maintenance Activities and Minor Construction, Houston to Crane, Texas. This letter acknowledges the U.S. Fish and Wildlife Service's (Service) receipt of your requests for the initiation of formal consultation under the Endangered Species Act of 1973 as amended (U.S.C. 1531 et seq.) (ESA). The Longhorn Pipeline Partners L.P., is the applicant and designated "non-federal Representative" for this project, and Horizon Environmental Services, Incorporated, prepared the Biological Assessment for EPA, OPS, and Longhorn. All information required of you to initiate consultation was either included with your letters or is otherwise accessible for our consideration and reference. We have assigned this consultation the number 2-15- 00-F-413 and this number should be included in all future correspondence. This letter also transmits the Service's biological opinion on the Longhorn Pipeline Project Maintenance Activities and Minor Construction, Houston to Crane, Texas, proposed for authorization by EPA and OPS. The Service is able to complete this consultation in the short time frame because of the extensive coordination that occurred during informal consultation. This Biological Opinion is only related to the activities proposed in this Phase One of the overall consultation. The phased approach to this consultation is explained in further detail below. 1 <<>> BIOLOGICAL OPINION Longhorn Pipeline - Phase One INTRODUCTION This document represents the Service's biological opinion on the effects of the proposed actions on the species listed in Texas. The Service has reviewed the proposed plans for the Longhorn Pipeline Project Maintenance Activities and Minor Construction from Houston to Crane, Texas, as outlined in the Biological Assessment provided by EPA and OPS. The first phase of the consultation (Phase One) relates to pipeline right-of-way (ROW) maintenance (clearing and marking, selected pipeline maintenance construction activities (pipe replacements and lowering), and pipeline testing (investigation of possible flaws and hydrostatic pressure testing). The Biological Assessment is hereby incorporated into this Biological Opinion by reference. The Service will not duplicate all maps, tables, and figures but will instead refer to the Biological Assessment. There are no species proposed for listing that would be impacted by the proposed action, therefore, no conference opinion will be issued. The draft Environmental Assessment on Longhorn Pipeline, and the associated Biological Assessment are the product of a settlement reached in the matter of Spiller et al. v. Walker et al. pending in the United States District Court in Austin, Texas (Appendix One). As part of the Court ordered settlement, the agencies involved in the original litigation were required to conduct an Environmental Assessment, including specifically, consideration of species listed under the ESA. The Court ordered EPA and OPS, acting as Lead Agencies, to be responsible for the Environmental Assessment. The Court order provides that issuance of any finding of no significant impact (FONSI) with regard to the proposed Longhorn Pipeline project "shall be conditioned upon implementation" of measures to protect public safety and the environment (Settlement Stipulation at 6). The order also prohibits the OPS from authorizing Longhorn to commence operations until Longhorn has implemented those mitigation measures upon which any FONSI is conditioned (Settlement Stipulation at 7). The order contemplates that Longhorn will apply for such ESA permits as may be required in connection with the implementation of any mitigation measures upon which a FONSI may be conditioned. (Settlement Stipulation at 7). The results of this consultation by the Lead Agencies with the Service are expected to be incorporated in the Record of Decision issued by the Lead Agencies. The terms and conditions, mitigatory measures and protections incorporated herein for the benefit of species are expected to be adopted and incorporated by Longhorn in its enforceable mitigation commitments or in its operating and maintenance manuals subject to inspection by, and enforceable by OPS, pursuant to the Pipeline Safety Act (49 USC 60101 et seq.). The Court settlement specifies that Longhorn will undertake certain construction and maintenance activities prior to issuance of a final agency decision in this matter (Settlement Stipulation at 8-11). The parties to the settlement specifically agreed that any such investments by Longhorn in Kimble, Menard, Hays, Travis, Caldwell, Bastrop and any counties within the jurisdiction of the Lower Colorado River Authority after August 25, 1998 would not be considered "for the purposes of determining the reasonableness of alternatives" (Settlement Stipulation at 11). 2 <<>> Although the Service and the Lead Agencies are in consultation with respect to the entire proposed Longhorn project, this consultation is being approached in two distinct, yet related phases. Service regulations allow for a staged consultation (50 CFR 402.14(k)) where the Service reviews a project, and provides biological opinions on each incremental step provided that no irreversible or irretrievable commitments of resources are made. The first phase of the consultation (Phase One) relates to pipeline ROW maintenance (clearing and marking), selected pipeline maintenance construction activities (pipe replacements and lowering), and pipeline testing (investigation of possible flaws and hydrostatic pressure testing). The proposed actions for Phase One are focused on activities that Longhorn wishes to perform before the final decision on the environmental review process is made by EPA and OPS. The Service believes that, by submitting the proposed action, EPA and OPS have made a determination that these activities can proceed before the final environmental decision is made because these activities are consistent with the current operational approvals for this pipeline and the settlement agreement. The Longhorn Pipeline Partners wish to conduct these activities before a final decision is made because of the potential delay in accomplishing this work due to seasonal constraints placed on the activities by the presence of endangered or threatened species. The golden-cheeked warbler and black-capped vireo are migratory birds that would be impacted less if this work were to commence before the birds return to Central Texas from their wintering habitat in Mexico. Because the pipeline is existing, routine maintenance is supposed to be occurring, and the construction impacts proposed are prudent for whatever liquid would flow through the pipeline, the Service believes that none of these activities constitute an irreversible or irretrievable commitment of resources, natural or monetary, which have the effect of foreclosing the formulation or implementation of any reasonable and prudent alternatives or measures. The Service believes that these investments would not constitute irretrievable commitments of resources for the purposes of Section 7(d) of the ESA. The Service has evaluated the proposed activities only with regard to the potential impacts to listed species and compliance with the ESA. This Biological Opinion does not indicate Service support for any alternatives, including routing, in the EPA and OPS environmental review process and in no way should be viewed as a factor in deciding the outcome of that process. Alternative routes may have less potential impact to listed species. In the opinion of the Service, implementing the proposed projects before completion of the environmental review process is a business decision made by the Longhorn Pipeline Partners. The second phase of the consultation (Phase Two) will be more directly related to the actual operation of the pipeline, specifically the operation and maintenance of the pipeline system and the potential effects of a pipeline release. The two phases can be logically separated. Phase One of the Service's review will focus on those actions that are designed to make the pipeline safer. The Service can complete this stage of review without pre-judging whether or not the pipeline will be used. Phase Two of the Service's review will focus on whether and how the pipeline will be used. It is anticipated that the consultation for the Longhorn Pipeline will also include a Phase Two Biological Assessment and Biological Opinion that will address issues directly related to the actual long-term operation and maintenance of the pipeline, specifically the operation and maintenance of the pipeline system and the potential effects of emergency response activities in the event of a pipeline release. Both EPA and OPS, within the Biological 3 <<>> Assessment, have committed to continuing the next phase (Phase Two) of consultation. Based on information available on the proposed project, the Service determines that there is a reasonable likelihood that the entire project is not likely to jeopardize the continued existence of any endangered or threatened species or result in the destruction or adverse modification of critical habitat. During the Phase Two consultation, the Service may change this determination, based on further review of the existing information or new information gathered during the Environmental Assessment process or the Phase Two consultation. This biological opinion is based on: (1) the information that EPA and OPS provided with a request for formal consultation including the Biological Assessment, (2) the information previously provided as part of the informal consultation (including the draft Environmental Assessment), (3) information in our office (including information provided by the public and the plaintiffs in the lawsuit on the Longhorn Pipeline), (4) field investigations, and (5) other sources of information. In the request for formal consultation, EPA and OPS attached the Biological Assessment and copies of all consultation documents for the activities proposed to be addressed by this Biological Opinion on Phase One activities associated with the Longhorn Pipeline. CONSULTATION HISTORY Informal consultation between the Service, Longhorn, and the EPA has been in process since February 1999. Longhorn was formally designated as the Non-federal Representative for conducting informal consultation on behalf of the EPA and OPS on February 3, 2000. The history of consultation (both informal and formal) actions follows in Table One. Table One. CONSULTATION HISTORY DATE HISTORY 10 February, 1999 Meeting Between Service and Longhorn Representatives 25 February, 1999 Meeting Between Service and Longhorn Representatives 9 March, 1999 Meeting of Service and Radian (consultants writing EA for EPA and OPS) 22 March, 1999 Meeting Between Service and Longhorn Representatives 30 April, 1999 Meeting Between Service and Longhorn Representatives 11 May, 1999 Meeting Between Service and Longhorn Representatives 12 May, 1999 Meeting with the Plaintiffs to discuss the Settlement Agreement 1 June, 1999 Meeting with Barton Springs/Edwards Aquifer Conservation District 8 June, 1999 Meeting Between Service and Longhorn Representatives 11 June, 1999 Multi-Agency Field Tour of Longhorn Pipeline in and near Austin, Texas 29 June, 1999 Meeting Between Service and Longhorn Representatives 4 <<>> Table One. CONSULTATION HISTORY 30 June, 1999 Telephone Conference Between Service and Department of Justice 19 July, 1999 Meeting Between Service and Longhorn Representatives 27 August, 1999 Meeting Between Service and Longhorn Representatives 10 September, 1999 Meeting Between Service and Longhorn Representative Meeting Between Service and EP/ 13 September, 1999 Meeting Between Service, Austin and Regional Director 27 September, 1999 leeting between Service Austin Office and Washington Offic Original Draft Biological Assessment Submitted to Servic 30 September, 1999 Meeting Between Service and Longhorn Representatives 4 November, 1999 Meeting Between Service and Longhorn Representatives 9 November, 1999 Meeting Between Service and Longhorn Representatives 16 November, 1999 EPA and OPS Longhorn Public Meeting, Austin 22 November, 1999 Meeting Between Service and Longhorn Representatives 7 December, 1999 Meeting Between Service and Longhorn Representatives 8 December, 1999 Meeting Between Service and EPA 15 December, 1999 Meeting Between Service and Longhorn Representatives Service Issues Comments on Original Draft Biological Assessment "Not Likely to Adversely Affect" Determination. Service Issues Response to EPA Regarding EPA's initial Request for Concurrence on a 17 December, 1999 Meeting Between Service and Longhorn Representatives 6 January, 2000 Meeting Between Service and Longhorn Representatives Maintenance and Construction Activities in Non-habitat Areas for Listed Species. Longhorn Requests Concurrence from Service for "Not Likely to Adversely Affect" for 10 January, 2000 EPA and OPS Longhorn Public Meeting, Austin 11 January, 2000 Meeting Between Service, EPA and OPS 17 January, 2000 Meeting Between Service and Longhorn Representatives 18 January, 2000 Meeting Between Service and Longhorn Representative 28 January, 2000 Draft First Phase Biological Assessment received for review 7 February, 2000 Meeting Between Service and Longhorn Representatives 1 February, 2000 Telephone Conference Between Service and Congressman Doggett's Staff 3 February, 2000 consultation EPA and OPS designate Longhorn the "non-federal repersentative" for purposes of 10 February, 2000 Received EPA Request for Formal Consultation 5 <<>> Table One. CONSULTATION HISTORY 17 February, 2000 Received Revised Phase One Biological Assessment 17 February, 2000 Received OPS Request for Formal Consultation DESCRIPTION OF THE PROPOSED ACTION Project Overview - (Both Phase One and Phase Two) The following is an overview of the project as proposed by Longhorn Pipeline and is provided to give an overall context of the proposed project. The specific activities proposed for this Biological Opinion are detailed in the next section. Longhorn proposes to operate a 723-mile refined petroleum products (gasoline and jet fuel) pipeline system from the GATX Terminal in Galena Park, Texas, (near Houston, Texas) to a refined petroleum products terminal in El Paso, Texas. The pipeline also has a 28-mile intermediate connection from a station in Crane County to a planned meter station in Odessa, Texas. The pipeline consists of a combination of 20-inch and 18-inch diameter pipe from Galena Park Station to El Paso Terminal and an 8-inch diameter pipeline from a station in Crane County to a meter station in Odessa, Texas. Finally, three as yet to be built pipelines will connect the El Paso terminal to interstate common carrier pipelines west of El Paso. The pipeline's initial capacity of 72,000 barrels per day (bpd) will be supplied by a new pump station at Galena Park and five newly constructed booster pump stations at the following locations: Satsuma (Harris County), Cedar Valley (Hays County), Kimble County (Kimble County), Crane (Crane County), and El Paso (El Paso County). Two new pipeline construction projects remain to be completed. An 8-inch diameter, 2500-foot lateral that originates at the terminus of the existing Odessa lateral will connect to a terminal facility in Odessa, Texas, owned by Equilon. Three 8.3-mile lateral pipelines, which originate at the El Paso Terminal, will connect with Kinder Morgan (formerly the Santa Fe Pacific pipeline) and Chevron pipelines in the El Paso area. The connection to Kinder Morgan will consist of one 8-inch diameter pipeline and one 12-inch diameter pipeline. The Chevron connection will consist of an 8-inch diameter pipeline. The purpose of the lateral pipelines is to connect into Kinder Morgan and Chevron pipelines to distribute product into the Phoenix, Tucson, and Albuquerque markets. Chevron operates an 8-inch pipeline that delivers product to the Albuquerque market; Kinder Morgan operates one 12-inch pipeline and one 8-inch pipeline serving the Tucson market. Other Kinder Morgan pipelines connect Tucson to the Phoenix market. The proposed project includes both new construction and refurbishment of an existing pipeline that has been converted from its former use of transporting crude oil from West Texas to the Gulf Coast area, the majority of which has been completed. As described in this chapter, the existing pipeline has been modified to transport refined petroleum products, with flow going from east to west. Williams Pipeline Company will be the contract operator of the Longhorn 6 <<>> Pipeline System. Longhorn intends to transport multiple grades of gasoline and distillates, which will include special reformulated grades of gasoline needed to control air emissions in certain areas of the Southwest. The Longhorn Pipeline System is designed for service in excess of 50 years and is made up of four main pipeline segments, several stations, and one terminal, as listed below: 1. New and refurbished 20-inch diameter pipeline from Galena Park to Satsuma; 2. Refurbished 18-inch diameter pipeline from Satsuma Station to Crane Station; 3. New 18-inch diameter pipeline from Crane Station to El Paso Terminal; 4. New lateral pipeline connections to Odessa and to other pipelines at El Paso; New Pump Stations; 6. El Paso Terminal; and 7. Odessa Meter Station. A detailed description of the Longhorn Pipeline System is included in the Biological Assessment (Project Documentation Appendix at Tab One). Future pipeline upgrades, repairs, and maintenance beyond that identified in the Biological Assessment will be addressed in Phase Two of the consultation. Project Description (Actions addressed under this Biological Opinion) This Biological Opinion only covers those portions of the overall project that have been specifically identified in the Phase One - Biological Assessment. Appendix Two contains a list of all of the activities covered in this Phase One consultation including ROW clearing and maintenance, pipeline maintenance and construction, pipeline testing, and other integrity-related projects. Following is a description of each of these procedures and the methods by which they will be implemented for the Longhorn Pipeline System. Additional detail may be found in Construction Specification CS4 contained in the Biological Assessment (Project Documentation Appendix at Tab Four. Right-of-way (ROW) Clearing, Marking, and Maintenance The existing pipeline ROW is about 50 feet wide and 723 miles long and most of it has been routinely maintained and cleared for over 50 years. Longhorn has committed to bring the surface of the ground within the ROW into "excellent condition" in order to facilitate surveillance prior to startup of the pipeline (Biological Assessment - Project Documentation Appendix at Tab 2). Excellent condition is that condition which provides a clear line of sight for aerial and ground surveillance patrols in order to effectively monitor and inspect the ground surface along the ROW. A clean and clearly marked ROW provides a distinctive line of demarcation, indicating a change in land use, where surrounding terrain is natural or heavily developed. These activities are routine and are conducted periodically by pipeline operators in the United States. 7 <<>> ROW maintenance will include mowing, brush-hogging, back-dragging, and/or hand trimming of tall grass or woody re-growth, trimming of tree canopies overhanging the ROW, setting signs, marking points of intersection (horizontal bends) in the pipeline with PVC posts, and painting cross-fence posts. ROW mowing is performed by a twin-blade mower or a brush-hog drawn by a tractor, to a height between two and four inches. Back-dragging is a method of clearing in rocky terrain; back-dragging involves pulling a dozer blade backwards across the ground surface which has the effect of bending vegetation over at the ground surface. Back-dragging typically does not result in the uprooting of vegetation. Rather, the vegetation is bent or broken just above the ground surface. Back-dragging is used only in areas where rocks on the surface pose a risk of damage to a mower or brush-hog. Vegetation around surface facilities such as valve settings is at times spot-treated, by hand application, with herbicides such as Roundup and Rodeo. Hand trimming involves line trimmers, chain saws, and similar hand-held equipment. Tree canopies are trimmed by workers, using chain saws, that are raised within reach of the canopies by a man-lift. Steel sign posts are typically set by driving the posts directly into the ground. PVC posts are set into shallow holes dug by post-hole digger. In limited circumstances such as when vandals repeatedly remove pipeline markers, sign-posts are dug by post-hole digger to allow the posts to be set into concrete. Clearing within areas identified as endangered species habitat will not result in any substantial ground disturbance because only mechanical or hand cutting will be employed. The term ground disturbance is intended to mean soil disturbance that would result from grubbing brush and tree stumps. Back-dragging will result in some minor disturbance of the soil surface similar to grubbing. In limited circumstances, stumps directly over the pipeline, which could have adverse effects on the pipe, will be spot-treated by hand application, with minimal amounts of non- aromatic and non-persistent herbicide to retard re-growth. Herbicides will be applied in accordance with EPA-approved label directions. All areas of the ROW are subject to periodic clearing from time to time. ROW clearing occurs at intervals that depend upon the rate of vegetation growth, typically averaging once per year in arid and semi-arid territory (generally, from Austin to Crane) and typically averaging twice per year in territory with greater rainfall (generally, Houston to Austin). Further, metropolitan areas may be mowed as frequently as monthly to meet municipal ordinance requirements and in response to landowner requests. ROW clearing will be conducted on a schedule that avoids impacts to species. 8 <<>> Pipeline Maintenance - Construction Planning Prior to project engineering and scheduling, each site is surveyed by qualified personnel to determine whether or not the activity (a) may affect threatened or endangered species and habitat, (b) may cause disturbance of cultural resources, (c) may be subject to Clean Water Act Section 404 (U.S. Army Corps of Engineers jurisdiction over dredge and fill materials in waters of the United States), or (d) may be subject to other federal, state or local laws, regulations or ordinances. Appropriate authorizations are obtained (such as this consultation), and necessary requirements are identified and incorporated into project planning and engineering documentation. Project engineers and technicians perform site inspections to identify site-specific conditions and features that require consideration in project planning, such as site ingress/egress routes, workspace requirements, spoil management, equipment storage, servicing and parking needs, and the like (Biological Assessment - Project Documentation Appendix at Tab 5 and Tab 6). Such considerations are incorporated into project planning and engineering activities. Unless required by the particular project or by site conditions, workspace is limited to the established ROW. Where workspace is required beyond the limits of the established ROW, those areas have been incorporated into project documentation. Workspace beyond the limits of the established ROW may be required for a number of reasons. First, avoidance of habitat or the natural terrain along one side of the ROW may necessitate expansion of workspace along the opposite side of the ROW. Second, a sloping surface gradient at a project site may require that spoil removed from the pipeline trench be stockpiled with a wider base, extending off of the ROW, than would be required at a project site with a level surface. Further, a project to lower or replace pipe at a creek crossing may require water diversion measures that necessitate a workspace wider than the established ROW. In addition, though project equipment is typically aligned along the existing pipeline ROW, project site conditions such as size, shape and/or slope may require that equipment be centralized in an equipment marshaling area (typically 25 ft. wide by 100 ft. long) for temporary storage, security and/or service. Biological surveys encompass both areas of potential surface disturbance and areas within the zone of potential indirect construction impacts, such as noise. In addition, applicable project best management practices (BMPs) are identified at this stage of project planning and incorporated into planning documentation. A Project Construction Plan is prepared for each individual project location to document project planning. The Project Construction Plan contains the following sections of detailed information: Description of Work for the Project; Responsibilities and Authorities; Safety Requirements; Job Contacts and Notification Requirements Matrix; Pre-Job Training Requirements; Environmental Protection; Project Schedule; Forms / Documents Required; 9 <<>> Chronological Sequence of Events; and Appendices as follows: Appendix 1 - Location Map Appendix 2 - Drawings, Calculations, and Specifications Appendix 3 - Environmental Protection Plan Appendix 4 - Storm Water Pollution Prevention Plan Appendix 5 - Safety Procedures Document Appendix 6 - Sample Forms Project BMPs are defined as procedures and specifications by which environmental controls will be implemented and include such items as sedimentation and erosion controls, reclamation procedures, minimization and avoidance procedures, inspection and reporting procedures, spill containment and cleanup procedures, procedures for addressing unforeseen circumstances, procedures for addressing foreseen, but unpredictable circumstances, and others. Project BMPs are identified and adapted from technical guidance manuals generally accepted as providing the appropriate environmental protection measures, such as the Texas Natural Resource Conservation Commission (TNRCC) technical guidance manual, Federal Energy Regulatory Commission (FERC) Environmental Guidance Manuals, and the City of Austin Environmental Criteria Manual. BMPs are incorporated within the Longhorn Storm Water Pollution Prevention Plan (SWPPP); an example of an SWPPP is included the Biological Assessment (Project Documentation Appendix at Tab 6). Project Environmental Inspectors Longhorn and Williams shall employ the services of environmental inspectors (such as Horizon Environmental Service Inc. and 3D/International) at every project site with associated species- related constraints. These environmental inspectors are qualified under FERC guidelines. The environmental inspector will remain at each project site during the period of activity to ensure compliance with all project constraints and project BMPs. The inspector is authorized to dictate any additional project BMPs that may become necessary during the activity and to modify work activities and progress to the extent necessary to ensure compliance with project environmental constraints. However, in the event of a conflict between project constraints and sound engineering practices, the inspector shall consult with project engineers and the Service, as appropriate, to achieve project goals while minimizing any impacts to listed species or the environment. The environmental inspector retains oversight of site closure and performs, or supervises the performance of, post-activity inspections of project BMPs until site stabilization is achieved. The environmental inspector will produce appropriate documentation for each construction location to include BMP compliance logs, photographs, as-built dimensions of disturbance, and any encounters with listed species during the construction process. The completion reports for projects listed in Appendix Two, will be provided to the EPA, OPS, and the Service, annually. Site Preparation Prior to site entry, at locations where avoidance and/or minimization of species effects has been recommended, a qualified biologist will clearly identify areas for avoidance and will stake and/or flag such areas. The project environmental inspector also surveys the site to ensure that all such avoidance areas are clearly identified in accordance with conditions approved in the consultation process and confirms other site-specific areas in which disturbances may occur such as routes of 10 <<>> ingress/egress, spoil management areas, equipment marshaling areas, workspace areas, and similar areas needed for construction. Project BMPs are reviewed prior to site entry, and the locations of any necessary physical control measures to be employed are identified. A survey crew will precede the project equipment and mark the project boundaries. In addition, the pipeline centerline will be marked at 100-foot to 200-foot intervals. Site Entry Upon site entry, the necessary project equipment is transported to the site via the designated route for ingress/egress. Site access is achieved via improved roadways and the established ROW, using the shortest available route between improved roadways and the project site. Routes of ingress/egress account for any potential for effects to threatened and endangered species and habitat that may exist along the ROW between the improved roadway and the project site, as well as accounting for other potential impacts to the environment. At times, equipment will remain on-site only during the time that it is in active use to allow it to be shared between nearby project sites. However, impacts to potential habitat for listed species from site ingress/egress will be minimized to the maximum extent practicable. Prior to any excavation, site vegetation is removed, and project BMPs are implemented. Site vegetation is cleared to the extent necessary for project completion, so long as the vegetation is not located in areas identified for avoidance. Clearing is accomplished by the methods described in above (ROW Clearing), though vegetation within the workspace may require removal. Project BMPs are installed in accordance with project planning documentation and in accordance with the site-specific SWPPP. Task Descriptions - (Process Once All Authorizations Are Obtained) The following task descriptions identify process steps that occur once all authorizations are obtained and regulatory requirements are identified and incorporated into project planning and engineering documentation. Detailed procedures for each of the activities summarized below are available in Pipeline Construction Specification CS4, which is included in the Biological Assessment (Project Documentation Appendix at Tab 4). In the event of a conflict between Construction Specification CS4 and the site-specific components of the Project Construction Plan, the Project Construction Plan will be followed. Pipeline Lowering and/or Replacement - Open Terrain Once the project site has been prepared and equipment brought onto the location, the following major activities take place. • The pipeline segment to be replaced is isolated by cutting and plugging at boundaries. Williams operating personnel will establish that the line is not pressurized and is properly isolated such that the contractor may cut the pipeline at the project limit boundaries. Mechanical plug devices will be utilized to prevent residual product leakage from the pipeline segments or entry of foreign materials into the pipeline. These devices shall be secured to prevent their loss or tampering. 11 <<>> Remove large rocks, if any, from ROW work area to appropriate disposal/storage area. Track hoes with buckets are used, unless larger rocks require grapple capable (clam) buckets. Remove and set aside topsoil spoil (double ditch practices). Double-ditching will be required in areas where native plant communities need to be re-established, or there are topsoil improvements, such as sodded lawn areas and cultivated fields. Double-ditching allows topsoil management by making two passes to remove and segregate spoil; one to remove and set aside topsoil and one to remove and set aside subsoils. Remove overburden and expose pipe. Utilizing track hoes, remove and set aside overburden from the pipeline and load and remove excess amounts from the work site for disposal. Unsuitable overburden (i.e., large rocks) will be disposed of in approved sites. Cut pipe into subsections at road and water crossings. Expose and cut the pipeline at road crossing boundaries to isolate the removal section into subsections. Utilize drain pans to recover any remaining liquids as the cut is made. Install mechanical plugs in all exposed pipe ends. Raise and crib pipe alongside the trench. Properly manage any coating which comes loose from the pipe. • Prepare and wrap pipe for disposal. Double wrap the pipe sections with 6-mil thickness plastic wrap, taping and sealing each wrapping separately. Ensure that the ends are sealed to prevent any release of coating. • Remove pipe from ROW. Load and remove the wrapped pipe sections by truck. Care will be taken to preserve the plastic wrapping on the pipe. Secure the pipe to the trailer and haul to the disposal site for final disposition. • Cleanup and grade ROW for survey and trenching operations. • Capture, contain, and remove any remaining coating materials/scraps using project-prescribed methods for asbestos containing materials. Prepare the grade on either side of the ditch to accommodate the trenching machinery, removing any large rocks. Survey crew should mark and stake the centerline offsets as required by the trenching crew. • Deepen trench to new depth. Depending upon the length of the desired lowering and/or replacement, and depending upon whether the trench is in soil or rock, a track-hoe or wheel trencher (rock saw") deepens the trench to the new depth. A wheel trencher is typically used for longer trenches and trenches in consolidated rock. Dust generation is monitored during trenching, and a water fog of the trenching mechanism may be employed to minimize airborne dust in non-rural areas. 12 <<>> • String new pipe along trench. As the ditch is prepared, the pipe may be strung along the workpad in anticipation of measuring and marking for bending, welding, and lowering operations. The survey crew will note the pipe heat and identification numbers sequence for the individual pieces as they are placed. The survey crew will survey the new ditch profile and mark the pipe for calculated field bends. Make field bends. The field bending crew will proceed ahead of the welding crew to make any required field bends. The contractor may also elect to set up field bending in one of the equipment marshaling areas and perform bending there rather than on the ROW. Weld and Radiograph new pipeline. The welding crew will proceed to weld the pipeline. Inspectors will survey and note the weld numbers and identification of the welders for this activity. The radiography crew will follow the welding crew. Inspection will be per standard specification API 1104 and include 100% radiography of all girth welds. • Apply weld joint coating and inspect pipeline coating for "holidays". A holiday is a point where the coating fails to electrically insulate the pipe. Weld joint coating will be applied as specified in the Project Construction Plan. This will be by field-applied FBE (fusion bond epoxy). Following weld joint coating, the entire coating system will be inspected for holidays and repaired as required. Pad and lower pipe. Pad the ditch and lower the pipeline as specified in Construction Specification CS4. Install ditch plugs as required to stabilize pipeline during hydrotest and backfilling. The pipeline coating will receive a final "jeeping" as the pipe is lowered to ensure its integrity. Jeeping is the process of electrically inspecting the pipeline coating to ensure that no holidays exist in the coating, so named due to the "jeeping" sound the inspection device emits when a holiday is identified. • Complete as-built survey. Complete as-built survey activities, noting weld locations, pipe identification codes, and location and stationing of bends, fittings and other such features for inclusion in alignment sheet drawings. Backfill and compact trench. Backfill and compact the ditch according to Construction Specification CS4, maintaining sufficient cover to allow for settling. Install ditch breakers and silt fencing as appropriate for surface erosion control until the site is stabilized. Perform hydrostatic pressure test on new pipeline segment. Obtain fresh water for pressure test and begin line fill behind a pig. The test pressure and test duration will be established and specified in the Project Construction Plan or in separate hydrostatic testing plans. • Drain and dispose of hydrostatic test water. Upon completion of the hydrostatic test, the test water is either pushed with nitrogen to a subsequent test site or 13 <<>> removed into mobile tanks for hauling to a disposal facility. Test water is controlled to ensure that it is fully contained in order to prevent discharge to the environment. • Perform final tie-ins. Remove the test headers and make the final tie-ins of the new pipe segment to the existing pipeline. The tie-in welds will be 100% radiographed to ensure their integrity. Coat the tie-in welds with an appropriate joint coating system compatible with both FBE and coal tar coatings. The coating is inspected, or jeeped, and any holidays are repaired. The tie-in locations are backfilled and compacted. • Clean, grade, and seed ROW. Following installation of erosion control measures, re-seed the ROW with native grass seed and/or sod as prescribed for the location. Re-install pipeline markers and any traffic control devices to limit or restrict ROW access by motor vehicles. • Perform site cleanup and restoration. Clean up equipment marshaling and material storage sites, ensure that the worksite access roads are restored to prime condition, and that any road access ways are cleaned and restored. Pipeline Lowering and/or Replacement - Creek Crossing Pipeline lowering and/or replacement at creek crossings follows generally the same sequence of activities described above for open terrain; however, the additional activities described below apply to the actual creek crossing area. In addition, creeks may be crossed by either trenching or boring. Each crossing method is summarized separately below. Trenching A trenched crossing is lowered and replaced in much the same manner as an open terrain project; however, incremental measures are employed to ensure both that erosion and sedimentation are minimized and that no potentially harmful materials are discharged to the waterway. Pipeline Construction Specification CS4 in the Biological Assessment (Project Documentation Appendix at Tab 4) provides additional details. • Cut pipe at creek crossings. Expose and cut the pipeline at the creek crossing boundaries to isolate the removal section into subsections. Utilize drain pans to recover any remaining liquids as the cut is made. Install mechanical plugs in all exposed pipe ends. • Implement water quality protection measures. Staging areas, spoil storage areas, and additional workspace areas are located in upland areas above the creek bed. Hazardous materials such as chemicals, fuels, lubricating oils and any other potentially harmful materials are maintained at least 100 feet from the water body. BMPs are implemented to prevent sedimentation. Flumes, dams, equipment bridges and other diversion devices are installed as necessary to perform "dry ditch" excavation. 14 <<>> • Erosion control measures are employed after project completion to ensure that stream flows do not cause erosion of disturbed areas and subsequent sedimentation. Erosion controls protect against sedimentation and prevent stream flow from removing pipeline cover which could expose the pipe to stream bed forces. Erosion control measures are site-specific, depending upon site conditions, and include berms, dikes, water bars (perpendicular to the pipeline alignment), silt fences, staked hay bales, seeding, mulching, hydro-mulching, rip- rap, and trench plugs. Boring Stream crossings may be installed by boring rather than trenching, depending upon hydrologic setting, engineering considerations, and soil types. The existing pipeline may be abandoned in place after obtaining approvals from the landowner and, if necessary, state and federal authorities, and after (a) filling the pipe with an inert material such as grout or concrete, or (b) sealing the ends of the pipe. The pipe may not be abandoned in place if its presence could interfere with stream flows or interfere with future uses of the waterway. Boring a stream crossing requires the use of a work space for installation of bore pits in which the boring equipment operates. The boring operations typically require a workspace approximately 100 to 250 feet wide by 150 feet long. The work spaces are located above the high water mark unless topography or other factors dictate otherwise. Typically, no instream soil disturbance occurs, and BMPs are employed to ensure that spoil storage and other project activities do not cause erosion or sedimentation. From within the bore pits, the boring equipment creates a parabolic pathway to the pit on the other side of the stream bed. Bored material is circulated out of the bore and retained at the upland spoil storage area. The bore is sealed with grout or bentonite to fill fissures along the course and to ensure bore stability. The new pipe is then pulled through the bore using equipment designed for that purpose. Once the pipe is welded, inspected, surveyed, coated and tested, the excavations are filled and compacted, and the site is restored. Site restoration and stabilization is achieved in the same manner as described in above (Pipeline Lowering and/or Replacement - Open Terrain). Any necessary erosion and sedimentation controls are employed, and the site is inspected and maintained until final stabilization is reached. Hydrostatic Testing - Overview of Activities A hydrostatic pressure test is scheduled to be performed to ensure the integrity of the system. This test is scheduled to commence in February 2000 and conclude in May 2000. Hydrostatic testing will start at the Longhorn GATX pump station in Galena Park (Houston) and proceed westward to Crane Station. The test medium will be potable water from a local municipal supply source. In the event some water is lost due to pipe failure, or if water is needed to fill longer test sections, fresh make-up water will be acquired, by permit, from sources crossed by the pipeline (i.e., from rivers or streams) or other sources of fresh water. The hydrostatic testing occurs in segments, which are subdivided into test sections of varying lengths. Factors that contribute to test section length include: 15 <<>> (a) target test pressures; (b) pipe size and grade; (c) the presence or absence of species and habitat; (d) the location of valves and pump stations; and (e) elevation changes along the pipeline. Due to additional factors, two test sections will not be tested during the Houston to Crane hydrostatic testing project. Those two sections are areas that encompass habitat for the Houston toad and areas of potential effect to the Barton Springs Salamander (including the recharge zone and part of the adjacent contributing zone (on each side) of the Edwards Aquifer). Rather, those sections will be tested after Phase Two consultation relating to pipeline operation, maintenance and emergency response, and after maintenance construction to replace pipeline segments in those areas is completed. To facilitate hydrostatic testing of the pipeline, headers will be installed on the pipeline at intervals along its length which divide the pipeline into segments for discrete testing. There are forty (40) header sites involved in the test. A general description of the installation of the test headers follows. Additional information is provided in the Biological Assessment (Project Documentation Appendix at Tab 8). Headers vary in configuration; however, all function similarly to allow the introduction of test water, the pressurization of the test segment and the displacement, after testing, of the test water to the following test section. • Prior to any work, the sites will be subject to an environmental, endangered species, and archeological survey conducted by qualified third-party biologists and archeologists. The headers will be installed by excavating an area approximately 20 ft. wide x 80 ft. long x 4 ft. deep around and under the pipeline. The spoil will be stored on the temporary work easement. The topsoil will be segregated from the sub-grade for restoration of the site following the hydrostatic test. Storm water management during construction and testing will be by methods prescribed in the SWPPP, an example of which is included in the Biological Assessment (Project Documentation Appendix at Tab 6). • The exposed pipe will be cut and spread apart horizontally, and pre-fabricated headers will be welded to each section. The downstream header shall have a wire brush pig and displacement pig inserted in it before it is welded on the pipeline. A 6-inch temporary crossover pipe with valve will be installed between the upstream and downstream header. Upon completion of the test, the hydrostatic test water will be displaced into the next test segment by nitrogen. The test section will be vented to atmosphere and the temporary piping and headers will be removed. The pipeline will be tied back together with a joint of new pre-tested pipe and the joints will then be coated and wrapped to provide corrosion protection. Coating is inspected for holidays, and repairs are made if holidays are identified. The excavated area will be backfilled and compacted with the sub- grade material in the spoil pile followed by the topsoil to finished grade to match the surrounding terrain. The disturbed area is seeded with native grasses or sod, and BMPs are inspected and maintained until the site is stabilized. Total surface 16 <<>> workspace requirements for test header installations are about 100 feet wide by 150 feet long along the pipeline. Hydrostatic Testing - Potential Failure of Pipe The locations of potential hydrostatic test failures cannot be accurately predicted, the volume of test water discharged cannot be accurately predicted or calculated, and the number of investigative excavations cannot be predicted. The inability to accurately predict the potential impacts of hydrostatic test failures precludes any pre-activity attempt to predict and/or estimate the potential effects of test failures. Any such attempt would be likely to result in inaccurate estimates. Therefore, Longhorn proposes to provide for a contingent methodology for calculating any such effects. Of the methodologies available for calculating the effects of activities upon species and habitat, the most applicable is the Habitat Equivalency Analysis (HEA) methodology developed by the National Oceanic and Atmospheric Administration for Natural Resources Damages Assessments (NRDAs). The HEA methodology is briefly described by the following steps. • The duration and extent of injury are documented and estimated from the time of injury until the resource recovers to baseline. The services provided by a compensatory project are documented and estimated over the full life of the project. • The size of a compensatory project is calculated such that the total increase in services provided by the compensatory project equals the total interim loss of services due to the injury. • The cost of the compensatory project is calculated. A more detailed description of the HEA methodology is provided in Biological Assessment Project Documentation Appendix at Tab 10. Longhorn's will execute the following sequence of measures in the event a hydrostatic test discharge occurs in areas of concern for species and/or habitat: In the event of a test failure, immediately notify a qualified biologist, who will be maintained on standby along the test segment, and direct the biologist to the failure site; • If a discharge occurs, the biologist will assist the identification of response actions to minimize potential impacts to the environment; and, • The biologist will perform a field survey to document the loss of, destruction of, or injury to natural resources (a) at the location of any excavation, whether the excavation is for location of a failure or for repair of pipe; (b) within the area of 17 <<>> impact of the test water; and (c) in any other areas affected by the response to the test failure, as at any other construction site. The effects, if any, of the hydrostatic test failure upon species and/or habitat will then be calculated pursuant to the HEA methodology. Longhorn shall compensate for the value of any such adverse effects by paying the monetary value of an appropriate compensation project to conservation efforts directed at the preservation and recovery of the affected species and habitat in the region where the impact occurred. For example, if a hydrostatic test resulted in a take of golden-cheeked warbler or black-capped vireo habitat, Longhorn would contribute the requisite monies to appropriate conservation entities acceptable to the Service, such as Balcones Canyonlands Conservation Plan, The Texas Nature Conservancy, or similar initiatives. Cathodic Protection Enhancements Enhancements of the pipeline cathodic protection system consist of (a) installation of anode beds and (b) re-coating of sections of existing pipe. The cathodic protection system protects the pipe from corrosion. These enhancements are identified and described in the Biological Assessment (Project Documentation Appendix at Tab 2), and the locations where activities may affect species and habitat are identified in Appendix Two. Project planning is performed in a manner similar to that described above. Installation of deep anode ground beds requires a series of vertical bores within which sacrificial anodes are placed; the anodes within each bore and among the series of bores are connected by subsurface wiring that is then connected to the pipeline. The bores and wiring trenches are installed within the existing ROW. During boring, a circulating pit is dug to contain cuttings removed from the bore. After project completion, the pit is filled, excess cuttings are removed for disposal, and the site is closed in the manner described in previous discussions of construction site closure. An example project work plan and related diagrams that provide additional detail about deep ground-bed installation are included in the Biological Assessment (Project Documentation Appendix at Tab 11). Pipeline coating reconditioning involves the same activities required for a pipeline lowering or replacement, with the exception of the process steps to remove existing pipe and install new pipe. A coating replacement site undergoes the project planning, site preparation, site entry, and site closure steps much as described above. Since the pipe is not cut, any residual liquids within the pipe do not present contamination potential. Asbestos containing pipe coating is managed in accordance with the provisions of the Environmental Protection Plan and the Project Construction Plan (Biological Assessment - Project Documentation Appendix at Tabs 5 and 3, respectively). All coating reconditioning is inspected, or "jeeped," and any holidays are repaired. Surge Pressure Protection To reduce the risk of over-pressurization of the pipeline, Longhorn will implement system changes and operating practices to limit surge pressures to no more than maximum operating pressure in sensitive and hypersensitive areas identified by the EPA and OPS. (Biological Assessment - Project Documentation Appendix at Tab 2). One system change involves the installation of over-pressure activated by-pass systems that will allow a pressure spike to be relieved around certain gate valves. The installation of a by-pass system involves the same 18 <<>> process steps as the installation and removal of a hydrostatic test header; see above (Hydrostatic Testing - Overview of Activities). The by-pass system to be installed at the east bank of the Llano River will use the same work location as the hydrostatic test header to be installed at that valve site. Investigations Projects to investigate possible pipe dents and corrosion anomalies follow the same planning and preparation procedures for a pipeline lowering/replacement, but on a lesser scale. Table 2 identifies relevant information for, and the locations of, projects to investigate possible pipe dents and corrosion anomalies. Typical investigation sites require a trench approximately 20 feet in length. If a dent or anomaly cannot be field repaired, a segment of pipe will be removed and replaced, with the length replaced at least twice the pipe diameter. Coating and coating inspection and repair, as well as site closure, follow the procedures described in Section 4.0 of the Biological Assessment. Avoidance and Minimization Longhorn will, to the extent reasonably possible, conduct the maintenance construction, testing, and other subject activities in a manner that avoids potential effects to species and habitat. If avoidance is reasonably and practically not achievable, Longhorn will conduct the activities in a manner that minimizes any potential effects. Controls and other measures designed to achieve that goal are described in the foregoing descriptions of the various activities. A number of those controls and measures are summarized as follows: • Identifying and marking habitat areas for avoidance; • Planning project implementation to minimize the potential for any effects; Using FERC qualified environmental inspectors with authority to alter project implementation procedures in sensitive areas; Adjusting project timing to avoid breeding populations; for example, projects in Houston toad habitat will avoid the months of January through June and projects in golden-cheeked warbler and black-capped vireo habitat areas will be avoided March 1 through August 1 and March15 through September 1, respectively; • Implementing storm water pollution control BMPs even when not required by permit; • Maintaining qualified biologists in hydrostatic test project areas for immediate response in the event of a test water release in a habitat area; • Avoiding, until project planning is accomplished, hydrostatic testing over the Toad habitat areas; and Edwards Aquifer recharge zone, portions of the contributing zone, and in Houston 19 <<>> • Conducting additional species surveys along the pipeline ROW to determine actual presence or absence of species and populations where present. Additionally, work in areas of noise-sensitive species (i.e., golden-cheeked warbler and black- capped vireo) will be avoided during the breeding/nesting season. If work must occur in habitat areas during noise-sensitive seasons, the Service will immediately be notified. Proposed Minimization to Offset Impacts to Listed Species Land Conservation Funding The extent of the project and timetable for implementation prevent Longhorn from completing detailed surveys for threatened and endangered species in all potential habitat where disturbance or destruction may occur, due to the variable survey times for each species and extensive amounts of habitat areas involved. Exact quantification of impacts to all listed species from scheduled activities is not possible if the project is to be completed on a timely basis. Therefore, Longhorn has requested that the Service prepare a biological opinion based on an evaluation of impacts to potential habitat, rather than impacts to individuals or identified occupied habitat. Longhorn proposes to provide benefits to the species based on potential habitat impacts as if it were occupied. This will insure that all possible impacts are considered and provide maximum species benefits. Longhorn will apply a standard formula to potential impacts to determine appropriate minimization. The formula is: impact acreage × 1.2 x fair market value of land in the area. This formula is modified for Houston toad habitat to use a 3x multiplier instead of 1.2 due to the more critically imperiled nature of the toad population in general. Longhorn will also apply a one-time 10% inflation factor to anticipate increases in land values over time. Within 60 days following the Biological Opinion, Longhorn will engage two licensed appraisers to determine the average value of land in the vicinity of the impact areas for each species along the pipeline. If the two appraisals differ more than 5%, then a third appraisal shall be obtained to reach a determination. All appraisals shall take into account land uses and conditions in the vicinity. The current calculation of compensation, set out below, will then be revised based upon the average of the two or three appraisals. Longhorn proposes a series of payments over time to fund the habitat acquisition, with such payments being made in a manner which will maximize benefits to the potentially affected species. The initial payment will go toward conservation efforts directed to the Houston toad and the Tobusch fishhook cactus because those species face a relatively greater prospect of decline than the remaining species. Longhorn will provide the land conservation funding amount to one or more conservation organizations with funds devoted to conservation of the affected species. Payments will be made on an annual basis over a six-year period. Future land values shall be determined on the basis of appraisals performed every second year following the initial appraisals and determined employing the same methodology as described above. The remaining compensation due from Longhorn shall then be recalculated based upon the compensation acreage remaining to be funded and the most recent land appraisals for such acreage. 20 <<>> Longhorn and the Service will identify conservation organizations that provide the greatest benefit to the affected species as a whole. Potential recipients may include the National Fish and Wildlife Foundation, the Texas Parks and Wildlife Department (TPWD), Texas Nature Conservancy, Texas Land Trust, Trust For Public Lands, the Hill Country Conservancy and similar comprehensive conservation initiatives. The Service will also work with TPWD and other partners to accomplish the greatest benefit for listed species. Longhorn may at its discretion, at any point in time, (a) pay all outstanding compensation on the basis of the most recent appraised values; or (b) purchase required acreage acceptable to the Service for any given species. Given the timing matters identified above, Longhorn will provide assurance to the Service that the calculated compensation (refined on the basis of actual land appraisals) will be funded on time and in full. Such assurance will take the form of security that assures the Service that the compensation will be funded. Longhorn proposes such methods as a bond, a letter of credit, an escrow, or similar such mechanism reasonably acceptable to the Service. The security will cover compensation not proposed for immediate funding and the one-time 10% escalation value applied to same. Longhorn makes this proposal conditioned upon the requirement that, as payments are made or in-kind compensation is provided, a corresponding reduction be made in the compensation acreage outstanding and thus in the amount of security required. Before issuance of the Biological Opinion, Longhorn shall provide to the Service reasonable evidence that the security is in place. Based upon the formula, and the impacts described above, and assumed land values, the present calculation of land conservation funds for minimizing adverse affects would be as follows in Table Two. Table Two. Proposed Minimization to Offset Impacts to Listed Species Price Inflation Species Acres Multiplier Acres per acre factor Total ($) Texas prairie 61.3 1.2 73.56 $3000 10% 242,748 dawn Navasota 5.2 1.2 6.24 $ 1000 10% 6,864 ladies'-tresses Houston toad 20.6 3.0 61.80 $2000 pay now 123,600 Golden- 116.8 12 140.16 $2000 10% 308,352 cheeked warbler Black-capped 41.7 1.2 50.04 $ 1000 10% 55,044 vireo Tobusch 213.2 1.2 255.84 $1000 pay now 255,840 fishhook cactus 21 <<>> Total 992,448 Longhorn's Monitoring Commitment In addition to Longhorn's land conservation funding, they have also committed to survey the existing ROW to determine the presence/absence of listed species. The following summarizes the Longhorn Monitoring Commitment for each potentially affected species. Longhorn will survey for the Texas prairie dawn within the potentially suitable habitat areas to confirm its presence or absence. The survey will be conducted within the ROW in areas identified as potential habitat in March of 2000 to determine if the Texas prairie dawn is present, and if so, its distribution and abundance. Longhorn will conduct a Fall survey (15 October to 15 November, 2000) for the Navasota ladies'- tresses within the ROW if suitable climatic conditions occur to determine the presence or absence of this species, and if present, its distribution and abundance. • For the Tobusch fishook cactus, Longhorn will conduct a blooming period survey (March to April 2000) within the ROW throughout Kimble County to determine the species' distribution and abundance. One or more additional Spring surveys (as acceptable to the Service) for the Houston toad will be conducted along and downstream of the pipeline to determine the presence or absence of toads and their overall distribution and abundance. • One to two additional Spring breeding season surveys (as acceptable to the Service) will be conduced for the golden-cheeked warbler along and adjacent to the ROW within the potential habitat areas to determine habitat utilization and overall distribution and abundance. • One to two additional spring breeding season surveys (as acceptable to the Service) will be conduced for the black-capped vireo along and adjacent to the ROW within the potential habitat areas to determine habitat utilization and overall distribution and abundance. STATUS OF THE SPECIES/ENVIRONMENTAL BASELINE Status of the Species and Distribution The following is a review of the status of each species being considered in this biological opinion that may be adversely affected by the proposed action. The Service has reviewed the list of threatened and endangered species and identified potential impacts to the following species. Texas prairie dawn (Hymenoxys texana) - The Texas prairie dawn is a small, delicate annual to 6 inches tall with single or branching stems. It has small yellow flowers blooming in late March 22 <<>> to early April. It occurs in sparsely vegetated areas of fine-sandy compacted soil. Specifically, the species occurs in the northern part of the Gulf Coastal Prairie in Harris and Fort Bend counties, where it is found in poorly drained depressions or saline swales around the periphery of low, natural mounds (mima mounds) in open grasslands. These mostly barren areas are sparsely vegetated, and the soil is often covered with a blue-green alga (Nostoc sp.). It can also occur on disturbed soils such as rice fields, vacant lots, pastures, and possibly pipeline ROW if the soil structure remains relatively intact. There are fewer than 35 known sites recorded for the species, and several have been lost in recent years to urbanization in the Houston area. Most populations remaining are small, and are on private land. Very few sites currently have any form of protection. The primary threat to the species is habitat destruction as a result of urbanization, roadway construction, and conversion of habitat for agricultural purposes. An assessment of potentially suitable habitat for the Texas prairie dawn was conducted by Horizon in early June 1999 along the Longhorn pipeline ROW in western Harris and eastern Waller counties from the Satsuma Station on the west edge of Houston to near Monaville in Waller County. Three areas along the ROW, one in Waller County and two in Harris County, exhibited native range conditions with suitable soils that could be considered potentially suitable habitat areas for the prairie dawn. All other areas along the pipeline within the area investigated had been converted to row crop (corn), monoculture, hay or grazing pasture, or disturbed for land development. A survey for the prairie dawn has not been conducted within the potentially suitable habitat areas to confirm its presence or absence. Navasota ladies'-tresses (Spiranthes parksii) - The Navasota ladies' tresses was listed as endangered on May 6, 1982, without critical habitat. This member of the orchid family occurs primarily in moist, sandy soils in small openings in post oak savanna vegetation. The species is known to occur in Brazos, Burleson, Fayette, Freestone, Grimes, Jasper, Leon, Madison, Robertson, and Washington counties (USFWS 1984b). Currently, approximately 149 sites have been recorded, representing perhaps 75-80 distinct population areas, predominantly concentrated around two centers of distribution, one in southern Brazos County and one in central Grimes County. Some of these recorded sites have been damaged or destroyed since they were reported. Together these population centers contain the majority of known sites and individuals (Wilson 1993). However, the majority of sites contain fewer than 25 recorded plants. It is known that for this species not all individuals in a population are visible above ground in a given year, and most of these sites have been visited only once, so demographic data on populations is very limited. Nevertheless there is great concern among botanists that most of these sites may not represent viable populations. Navasota ladies'-tresses occur in a variety of moist sandy soils near drainages, in the Post Oak Savannah vegetation associated with the Navasota, Brazos, and Trinity River watersheds. Navasota ladies'-tresses are typically found on erosional remnants between rills in slightly to moderately eroded areas along minor intermittent tributaries, from the upper drainage head, extending along the edges of temporary streams to the flood plain of permanent streams. Navasota ladies-tresses grow on sandy loam soils and are often associated with post oak, blackjack oak, yaupon, slender bigelowia (Bigelowia nuttallii), and Spiranthes cernua.. Typical 23 <<>> habitat consists of natural openings in upland Post Oak Savanna vegetation (Poole and Riskind 1987, USFWS 1984b, Wilson 1993). Plants are believed to be situated where subsurface flow or seepage of water occurs seasonally, a common feature in other species of the genus (Arft and Ranker 1995, Kathy Parker, pers. comm.). While Navasota ladies'-tresses is found in small naturally created openings in the post oak woodlands, it cannot be regarded as a disturbance species, as it usually occurs in well developed woodland and is not a colonizer of extensively disturbed areas. There are few records in flood plain forests, open savannahs and shrublands that have experienced little or no grazing pressure, and in hillside seepages. Navasota ladies'-tresses is extremely slow-growing and long-lived. Rosette leaves support the formation of a storage tuber between November and March that sequesters resources in preparation for sending up a leafless bloom stalk at some future time. It is believed that often plants require more than one year of photosynthate storage to successfully send up a bloom stalk. If local conditions have not been favorable for forming sufficient below ground reserves, the plant may not bloom (Wilson 1993). Navasota ladies'-tresses apparently does not transplant well. In a mining project in Grimes county by Texas Municipal Power Association (TMPA), plants in the impact area were removed and transplanted into an adjacent habitat area. Plant survival has been low in most sites (TMPA 1996). Similarly, in an experiment in Lick Creek Park near College Station, Dr. Hugh Wilson planted some seedlings which survived into their second season, but died prior to the third growing season (Wilson 1993). Because of the low numbers of individuals reported from populations, the slow growing nature of the plants, its unusual habitat requirements of openings in mature vegetation, and its sensitivity to disturbance and transplanting attempts, the species is not regarded as being very resilient, and recovery following any damage to a population is expected to be slow. The primary threat to Navasota ladies'-tresses is destruction or modification of habitat due to urbanization, clearing for agricultural production, or mining (47 FR 19539, USFWS 1995, 1984b). Destruction of understory by feral pigs is also a problem in some areas. More than 40 known sites have been lost in the last ten years to mining or urbanization. Post oak savannah in many of these counties continues to be converted to bermuda grass pasture. Subsequently, habitat loss continues, particularly in the areas of Brazos and Grimes counties where most sites are located. The City of College Station in Brazos County is growing rapidly, particularly in the southern and southeastern fringes where most known populations are located. Mining in Grimes County disturbs more than 7,000 acres every 5 years (Wilson 1993). In Fayette County, the species is known from one small population approximately 6 miles south of the pipeline and 2 miles north of the town of Fayette. Based on analysis of soil distribution, vegetative cover, physiographic setting, and field assessment by Horizon in November of 1999, two small areas of potential habitat for Navasota ladies'-tresses are present along the pipeline corridor. No surveys for the species have been conducted along the pipeline. Tobusch Fishhook Cactus (Ancistrocactus tobuschii) - Tobusch fishhook cactus is a rounded, biscuit-shaped cacti usually 2 to 3 inches tall and up to 3.5 inches in diameter. There are 3 to 5 central spines with the upper 2 to 3 erect and straight and the lower central spines hooked at the tip and spreading. The plants are very inconspicuous, and produce cream to yellow flowers from February through early April. These cacti have been demonstrated to be obligate outcrossers 24 <<>> pollinated by native bees with a foraging distance of about 1/4 mile, and seeds are dispersed by native ants. The species occurs on limestone gravels of stream terraces, limestone ledges, ridges, and openings on the rocky hills of live oak - juniper woodlands in Bandera, Edwards, Kerr, Kimble, Kinney, Real, Uvalde, and Val Verde counties. A significant number of populations have been documented in Kimble County. Currently about 50 sites are recorded for the species, following a recent range - wide representative survey. Most of the populations are extremely small (5-20 plants), with individuals widely scattered. Known sites are separated by large distances. Most existing populations are on private land, and there are very few protected sites. Demographic data collected in monitoring studies over the last five years or so show that only one of the known populations is even marginally viable. The species is extremely slow growing and does not appear to reproduce until 10-17 years of age. It takes four successful flowers/fruits to produce one seedling (Jackie Poole, Texas Parks and Wildlife, pers. comm.). It is estimated that very few viable populations (10-15) remain over the 8 county range of the species. The survival and recovery of the species will require restoration and careful management, to provide sufficient numbers of populations and individuals in effective proximity to each other for successful pollination (and gene flow) to ensure the continuity of the species. Studies examining the probable reasons for population declines are underway. Threats to the species are believed to include inappropriate timing of range management practices (such as fire and clearing practices that disturb the soil), extensive predation by beetle grubs, loss of habitat to real estate development, and some collection by cactus enthusiasts. An assessment of potentially suitable habitat and pedestrian survey for the cacti was conducted by Horizon in April 1999 along portions of the Longhorn pipeline ROW in Kimble County, and no specimens were observed within the ROW. However, one Tobusch fishhook cactus was observed about 50 feet north of the cleared ROW. All of the ROW within Kimble County has been identified as potentially suitable habitat. Golden-cheeked Warbler (Dendroica chrysoparia) - The golden-cheeked warbler is a small, migratory songbird, 4.5 to 5 inches long, with a wingspan of about 8 inches. The male has a black back, throat, and cap, and yellow cheeks with a black stripe through the eye. Females are similar, but less colorful. The lower breast and belly of both sexes are white with black streaks on the flanks. Typical nesting habitat is found in tall, dense, mature stands of Ashe juniper (cedar) mixed with trees such as Texas (Spanish) oak, Lacey oak, shin (scalybark) oak, live oak, post oak, Texas ash, cedar elm, hackberry, bigtooth maple, sycamore, Arizona walnut, escarpment cherry, and pecan. This type of woodland generally grows in relatively moist areas such as steep-sided canyons and slopes. A mix of juniper and deciduous trees on the slopes, along drainage bottoms, and in creeks and draws provides ideal vegetation for birds. Warblers are also occasionally found in drier, upland juniper-oak (i.e., live oak, post oak, blackjack oak) woodlands over flat topography. An assessment of potentially suitable habitat and surveys for the golden-cheeked warbler was conducted by Horizon in April and May 1999 along the Longhorn pipeline ROW from Austin, Texas, to the Mason/Kimble County line. Although no potentially suitable habitat areas were 25 <<>> observed within the Longhorn ROW, several areas were located adjacent to the previously cleared permanent ROW. All areas were surveyed by Horizon a minimum of 5 times during April and May on days with favorable weather conditions for bird activity, per U.S. Fish and Wildlife Service guidelines (USFWS, 1994a). Surveys were conducted on 8, 9, 12, 27, 28 April, and 3, 11, 19 May. An equivalent of 4 person-hours per 100 acres were spent at each site, based on habitat size. No golden-cheeked warblers were found to be utilizing any of the potentially suitable habitat areas on or immediately adjacent to the ROW. However, three years of survey are necessary to confirm presence/absence under Service guidelines (USFWS 1994a). Black-capped Vireo (Vireo atricapillus) -The black-capped vireo is a 4.5 inch long, insect- eating songbird. Mature males are olive green above and white below with faint greenish-yellow flanks. The crown and upper half of the head is black with a partial white eye-ring. The iris is brownish-red and the bill black. The plumage of the female is duller than the male. Females have a dark slate gray head. In Texas, vireo habitat is found on rocky limestone soils of the Edwards Plateau, Cross Timbers and Prairies, eastern Trans-Pecos, and, to a limited extent, on igneous soils in the Chisos Mountains. Black-capped vireos require shrub vegetation reaching to ground level for nesting cover. They typically nest in shrublands. An assessment of potentially suitable habitat and surveys for the black-capped vireo was conducted by Horizon in April and May 1999 along the Longhorn pipeline ROW from Austin, Texas to Crane County. Potentially suitable habitat areas were observed within the Longhorn ROW as well as several areas located immediately adjacent to the previously cleared permanent ROW. All areas were surveyed by Horizon a minimum of 5 times during April and May on days with favorable weather conditions for bird activity, per Service guidelines (USFWS, 1994a). Surveys were conducted on April 8, 9, 12, 27, 28, and May 3, 11, and 19. An equivalent of 4 person-hours per 100 acres were spent at each site, based on size. No black-capped vireos were found to be utilizing any of the potentially suitable habitat areas on or immediately adjacent to the ROW. However, three years of survey are necessary to confirm presence/absence under Service guidelines (USFWS 1994a). Bald Eagle (Haliaeetus leucocephalus) - The bald eagle is a migrant and winter resident in Texas. The bald eagle was recently down-listed from endangered to threatened due to successful conservation efforts and is now proposed for de-listing. Migrating and wintering bald eagles typically arrive in Texas in November and depart around February. They are found primarily in association with reservoirs, rivers or other large bodies of water where they feed on fish, carrion, and waterfowl. Nesting bald eagles in Texas are found in the eastern portion of the state and along the coastal plain as far south as Calhoun and Refugio counties. No bald eagle nests have been identified near the pipeline ROW, however, bald eagles may occur along major waterways (Brazos and Colorado rivers, or major tributaries with impoundments) downstream of the pipeline corridor. The Federal Register, (Volume 64 No. 128, Tuesday, July 6, 1999; Page 36454) contains a proposed rule to remove the bald eagle from the List of Threatened and Endangered Wildlife in the Lower 48 States of the United States. Interior Least Tern (Sterna antillarum athalassos) - Premier nesting sites for the interior least tern are salt flats, broad sandbars, and barren shores along wide, shallow rivers. Important breeding habitat characteristics include: (1) presence of bare or nearly bare ground and alluvial islands or sandbars for nesting; (2) availability of food (primarily small fish); and (3) favorable 26 <<>> water levels during the nesting season (so nests remain above water). They usually nest on sites devoid of vegetation, but have been found in areas with an average of 11 to 30% vegetative cover, composed of grasses, shrubs, and trees and ranging from 1 to 3 feet in height. Vegetation, if present, is usually located well away from the colony, with the exception of bugseed, eastern cottonwood, and sandbar willow. As natural nesting sites have become sparse, birds have used sand and gravel pits, ash disposal areas of power plants, reservoir shorelines, gravel levee roads, and other manmade sites. The typical nesting period for the least tern in Texas is mid-April to mid-August. While the interior least tern has not been documented along the pipeline corridor, potential habitat for the tern is present downstream of the pipeline along several major waterways including the Brazos, Colorado, Llano, and James Rivers, and Squaw, Beaver, and Sandy Creeks. The seasonal occurrence (Spring and Summer) and potential nesting of least terns is possible in these areas. Barton Springs Salamander (Eurycea sosorum)- The Barton Spring salamander was listed as endangered in 1997, without critical habitat. The Barton Springs salamander belongs to a group of related salamanders that are endemic to the Edwards Plateau region of central Texas. All members of this group are obligately aquatic because the adults retain the larval, gill-breathing morphology throughout their lives. The Barton Springs salamander, formally described in 1993, was first collected from Barton Springs in 1946 and has been found only at the four hydrologically connected outlets of Barton Springs in Zilker Park within the City of Austin (Brune, 1981; Chippindale et. al., 1993). This salamander is a small species, adults reaching 2.5 inches (about 68 mm) in total length with reduced eyes and elongate, spindly limbs indicative of a semi-subterranean lifestyle. Barton Springs salamanders are found in the flowing, thermally constant water issuing from the spring outlets in association with aquatic macrophytes, leaves and organic debris, and gravel and rock substrates having little silt and sediment deposition. Water from the contributing and recharge zones of the Barton Springs segment of the Edwards Aquifer influences the conditions at Barton Springs. The main threat to the species has been identified as degradation of water quality from future growth and development on the Barton Springs segment of the Edwards Aquifer (Federal Register 62:23385). Houston Toad (Bufo houstonensis) - The Houston toad was listed as endangered in 1970 (Federal Register, October 13, 1970) and Critical Habitat was designated in Bastrop and Burleson counties in 1978 (Federal Register, January 31, 1978). Houston toads are generally brown and speckled, although individual toad coloration can vary considerably. Some may appear light brown, others almost black and they may also have a slightly reddish, yellowish, or greyish hue. Two dark bands extend down from each eye to the mouth. Their legs are also banded with darker pigment. A variable white stripe streaks along the sides of the toad's body. Their undersides are usually pale with small, dark spots. Males have a dark throat which appears bluish when distended. Adult Houston toads are 2 to 3.5 inches long and like all toads, are covered with raised skin patches that contain chemicals that make the toad distasteful and sometimes poisonous to predators. The toad was eliminated from three counties (Harris, Fort Bend, Liberty) prior to the 1970s due to habitat loss resulting from urban expansion. Although Houston toad populations have been found in nine other counties (Austin, Bastrop, Burleson, Colorado, Lavaca, Lee, Leon, Milam, 27 <<>> Robertson), the Service is concerned about the long-term viability of these populations. The small population in Lavaca County has not been seen since its discovery in 199l; the population at the critical habitat site (Woodrow Lake) in Burleson County has not been seen since 1983; and the population in Leon County lies within an expanding residential area. The largest known population of Houston toads occurs within the pine/oak woodland region of Bastrop County. This area also contains federally designated critical habitat. All known Houston toad populations occur along bands of geologic formations that support deep sands. Six populations occur on a band running through Bastrop County northeast to Freestone County. Three other populations occur on another band through Lavaca, Austin, and Colorado counties (USFWS, 1994b). Houston toad habitat consists of rolling uplands characterized by pine and/or oak woodlands (loblolly pine, post oak, blackjack or sandjack oak) underlain by pockets of deep, sandy soils. Because their skin is semi-permeable to water, Houston toads become dormant to escape harsh weather conditions, such as winter cold (hibernation) and drought (estivation). They seek protection during this time by burrowing into sand or hiding under rocks, leaf litter, logs or in abandoned animal burrows (TPWD, 1993). Although Houston toads are typically associated with woodland habitat, they also breed in and migrate across sparsely wooded and cleared areas near woodlands. They may also breed in and traverse areas that do not support deep sandy soils, including clay and gravel substrates, provided these areas are near woodlands underlain by pockets of deep sandy soils. Houston toads breed from January to June, with a peak in February and March. During the breeding season, toads appear to move randomly from one breeding site to another, achieving genetic transfer between populations that may appear isolated, thus creating a metapopulation, an aggregation of smaller populations linked genetically and demographically and functioning almost as a single population. Presently, the most reliable breeding sites are stock ponds and similar impoundments, though in wet years breeding may occur wherever sufficient standing water is present. For successful breeding, water must persist for at least 30-60 days to allow egg hatching, tadpole maturation, and emergence of toadlets. Mortality in young is high, due to predation and drying of breeding sites, with significantly less than one percent of eggs laid believed to survive to adulthood (USFWS, 1984a, 1994b, 1995). The Houston toad is vulnerable to extinction primarily due to habitat loss, degradation, and fragmentation. Over the last 50 years, the historic range of Houston toads has contracted and several populations have been lost. Threats include expanding urbanization and conversion of woodlands to agricultural production areas, such as coastal bermuda pastures, use of fertilizers and pesticides that impact the toad directly or its food supply, and loss of suitable breeding habitat because of alterations in watershed drainages and wetland alterations or destruction (such as degraded water quality, draining/filling of wetlands, stocking with predatory fish, etc.). Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the Houston toad, the Service believes this phase of the project will provide a net conservation benefit for this species. According to the Houston Toad Recovery Plan (USFWS 1984a), Houston toad breeding sights have been recorded in Buescher State Park south of Longhorn Pipeline. Houston toads have also been heard chorusing on the adjacent property owned by the University of Texas to the north of Buescher State Park and Longhorn Pipeline (USFWS, unpublished data). Dr. James R. Dixon of 28 <<>> Texas A&M University conducted a survey along the Longhorn Pipeline ROW and adjacent Phillips EZ Pipeline ROW in 1991 with negative results, although areas of potential habitat were noted (Horizon 1991). Horizon Environmental Services, Inc. conducted a reevaluation of suitable habitat along the Longhorn Pipeline ROW within Bastrop County. The field reconnaissance was conducted on 2 June 1999 from the Colorado River, southeast of Bastrop, to FM 2104. Portions of the area along the pipeline had recently been cleared and planted in improved grasses. Based on field observations and discussions with the Service, two areas of suitable habitat were identified along and adjacent to the pipeline ROW. One area includes Buescher State Park from approximately 0.5 mile east of the eastern boundary of the park westward to near Highway 71. The second area begins about 500 feet to the west of FM 2104 and extends westward approximately 0.75 mile. The drainages in both of these areas flow south toward the Colorado River. EFFECTS OF THE ACTIONS Direct and Indirect Effects Texas Prairie Dawn - Potential impacts to the Texas prairie dawn may result from a number of activities. ROW maintenance will occur with the periodic (typically twice per year) use of tractor drawn mowers. Tractors will be rubber-tired, and crushing of plants could occur from time to time, particularly during blooming periods. Mowing height will typically be 3 to 4 inches. Since only the blooming shoot is usually that high, impacts from mowing are deemed to be minimal, except during blooming. Longhorn has chosen to quantify impacts as the total ROW (50 feet) through the entire area of identified potential habitat. This area constitutes approximately 61.3 acres. As an avoidance and minimization measure, mowing will be scheduled to avoid the February through April blooming season. Three construction sites have been identified for completion in the near-term, two pipeline dent investigations, and one anomaly investigation (Appendix Two). Impact for these three construction areas will be contained within the existing 50 foot ROW for relatively short distances along the pipeline. Within these areas, excavation, temporary spoil storage, equipment movement, and grading will likely result in elimination of any prairie dawn plants that may occur within the ROW in the construction areas. The area of these impacts is already included in the total ROW impact mentioned above (61.3 acres). Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the Texas prairie dawn, the Service believes this phase of the project will provide a net conservation benefit for this species. Navasota Ladies'-tresses - As in the case of the prairie dawn, periodic (twice per year) mowing with rubber-tired tractor mowers may result in sporadic crushing of plants under tractor tires or mower wheels, or cutting of bloom stalks. Impacts from periodic mowing, in the absence of detailed plant inventory information for the ROW, are quantified as of total impact for the ROW through the identified potential habitat areas constitutes 5.2 acres. As an avoidance and minimization measure, mowing will be scheduled to avoid the October and November blooming 29 <<>> season. A blooming season survey of the ROW and adjacent areas will be conducted to identify any plant locations for specific avoidance, if present. No areas of construction are identified in the two potential habitat areas. However, construction will occur just east of the most westerly potential habitat area. The ROW is to be used for access to the construction zone. It is presumed that heavy equipment movement along this portion of the ROW will result in destruction of any plants growing at that locality. Access will be kept within the existing 50 foot ROW; therefore, potential impacts have already been calculated in the ROW maintenance value above (5.2 acres). Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the Navasota Ladies-tresses, the Service believes this phase of the project will provide a net conservation benefit for this species. Tobusch Fishhook Cactus - Potential habitat for the fishhook cactus is very generally estimated from general soils and plant distribution information to include the entire reach of the pipeline's traverse of Kimble County. Without specific survey information for the cactus, it is assumed that the entire ROW across Kimble County is potential cactus habitat. As with the Texas prairie dawn and Navasota ladies'-tresses, the Tobusch fishhook cactus is low growing and not likely to be directly affected by mowing, except for possible crushing by tractor tires. However, due to the significant extent of large rocks within the ROW, mowing is not always feasible in this region. A preferred method in rocky terrain is to back drag a bulldozer blade across the ground which knocks down undesirable woody vegetation. This activity can disrupt the ground surface and possibly injure or destroy cactus plants. Therefore, direct impacts to fishhook cactus habitat may occur. The total area occupied by the ROW across Kimble County is 212.7 acres. Four test header installation locations are planned within the potential fishhook cactus habitat. Each site will disturb an additional 50-foot width beyond the ROW for the construction of the headers. The additional space is required to facilitate temporary spoils storage, equipment access, pipe construction, and testing equipment. The additional area of impact per site is between 0.1 and 0.2 acre. The total additional impact to cactus habitat is 0.5 acre. The total impact acreage for Tobusch fishhook cactus is 213.2 acres. Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the Tobusch fishhook cactus, the Service believes this phase of the project will provide a net conservation benefit for this species. Golden-cheeked Warbler - Golden-cheeked warbler habitat does not exist in the established ROW, but is presently adjacent to the ROW in a number of locations from Hays County westward to Mason County. ROW maintenance will not directly affect warbler habitat, except for hand pruning of canopies which overhang the ROW. Indirect effects may result from mowing noise or activity if birds are present in the vicinity during maintenance activities. As a minimization procedure, Longhorn will schedule maintenance activities to occur during the non- 30 <<>> nesting season (September 1 to March 1) within or near warbler habitat areas to avoid indirect impacts. The area of potential effect is determined to be 103.4 acres. Six areas of pipeline maintenance, construction, or investigation are anticipated to occur along the pipeline within potential warbler habitat (Appendix Two). Each of those areas are estimated to require additional construction space in excess of the existing ROW by variable widths. The total additional impact to warbler habitat resulting from construction clearing is 13.4 acres. The additional areas of temporary work space are needed in these areas to facilitate temporary spoil storage, machinery access, pipe stacking, and miscellaneous construction related activities. As avoidance and minimization of project impacts, Longhorn will schedule clearing, to occur during the non-nesting period (September 1 to March 1). As with the immediately impending construction schedule, clearing will commence prior to March 1 and construction activities will be continuous until completion. Total estimated impacts to potential warbler habitat are 116.8 acres. Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the golden-cheeked warbler, the Service believes this phase of the project will provide a net conservation benefit for this species. Black-capped Vireo - Seven areas of potential black-capped vireo habitat exist along the ROW between Blanco and Kimble counties. Black-capped vireo habitat, being an early successional stage of brushy regrowth, does exist within the existing ROW in places where previous maintenance activities have not occurred in several years. In this case, ROW maintenance will directly impact potential habitat within the existing ROW. The area of direct impact for the full 50 foot width of the ROW through the various habitat areas constitutes approximately 41.6 acres. Indirect impacts from ROW maintenance are not likely since maintenance activities will be conducted during the non-nesting season (September 1 to March 15) for vireos. Four maintenance construction locations have been proposed within the areas identified as potential vireo habitat (Table 2). Only one of those construction sites will require clearing beyond the 50 foot ROW width. An additional 50 feet of temporary work space will be needed to facilitate temporary spoils storage, equipment access, pipe layout and construction room. The additional acreage of disturbance for this construction site is 0.1 acre. The total area of impact to potential black-capped vireo habitat is 41.7 acres. Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the black-capped vireo, the Service believes this phase of the project will provide a net conservation benefit for this species. Houston Toad - ROW maintenance will include periodic mowing with rubber-tired tractors. To avoid mortality of toads that may occur within the ROW during mowing, maintenance activities will be timed to occur in the late summer through fall (July through December) when the toads tend to be less active and are not breeding. In addition to these avoidance procedures and the low likelihood of encounters, Longhorn will assume that all areas of potential habitat traversed 31 <<>> by the pipeline ROW are suitable habitat. This area (ROW width of 50 feet times length) is about 20.6 acres. To minimize edge effects, the ROW will be maintained in native bunchgrasses to facilitate dispersal and provide cover from predators. No construction impacts to Houston toads are contemplated in this consultation. Pipe replacements within the toad habitat area will be addressed in the second phase of consultation. 32 <<>> Because of the toad's vulnerability to development activities, the Service believes that the combined impact of the existing and anticipated habitat fragmentation and destruction in Bastrop County could jeopardize its continued existence and adversely modify its critical habitat at some point in the future, unless immediate efforts are implemented to protect enough remaining habitat to support viable, self-sustaining populations. Several large, high quality, interconnected habitat blocks are needed to promote population viability (USFWS 1994b, Houston Toad Recovery Team 1999). The Houston Toad Recovery Team believes that 20,000-30,000 acres of suitable (undeveloped) habitat in blocks of 5,000 acres or greater are needed to support a viable, self-sustaining population of toads with low risk of extinction, with an absolute minimum of 15,000 acres provided this 15,000 acres is in large, interconnected blocks of the best habitat remaining. The Service intends to ensure the toad's long-term survival and recovery by ensuring that any activities authorized under the Endangered Species Act provide long-term protection for the Houston toad. Thus, any actions authorized by the Service must permit the persistence of at least 20,000-30,000 acres in large, unfragmented habitat blocks in Bastrop County. Toads must be able to disperse between the habitat blocks through direct connections and/or through migration corridors that allow dispersal to occur (i.e., multiple smaller upland habitat patches and riparian corridors). Currently, the habitat blocks north of Highway 21 and in and around Bastrop State Park are most likely to continue to support toad populations, provided no additional habitat destruction occurs that significantly disrupts normal feeding, breeding, and sheltering behavior. Since much of the area south of Highway 71 has already been extensively fragmented by development, the Service believes that this area is less likely to continue to support toads over the long-term. The area in and around the University of Texas Science Park and Buescher State Park has potential to support a population, provided enough habitat remains contiguous and undisturbed. Until sufficient high quality habitat has been secured and managed to provide population viability in perpetuity, the Service believes that any further development that would impact the integrity of the remaining habitat blocks or their connections would jeopardize the toad and adversely modify its critical habitat. Without permanent habitat protection to ensure the persistence of the largest known population of toads in Bastrop County, the Houston toad faces an imminent risk of extinction. Thus, it is imperative that the impacts from any activity authorized by the Service provide habitat protection and maintain migration corridors. By ensuring that all clearing and development activities implement sufficient measures to minimize impacts, the Service believes many projects in toad habitat can move forward without reducing the likelihood of survival and recovery of the species. The Service will continue to assess the impacts of existing and proposed projects and evaluate whether or not this goal is being achieved. Since Phase One of the Longhorn Pipeline project involves the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities will include long-term habitat protection for the Houston toad, the Service believes this phase of the project will provide a net conservation benefit for this species. 33 <<>> Other Species - Listed species that may occur away from or downstream of the pipeline corridor (bald eagle, interior least tern, Barton Springs salamander) are not likely to be adversely affected by the proposed maintenance and minor construction activities. Any discharges of hydrotest waters are not expected to contain levels of hydrocarbons or other toxic materials sufficient to result in adverse impacts. Effects of Hydrostatic Testing - Potential Failure of Pipe Hydrostatic testing of the existing Longhorn Pipeline between Houston and Crane is expected to result in a number of failures. Some of those failures, and actions taken to locate failure locations, could have effects upon both species and habitat. However, the calculation of the effects of such failures is difficult to estimate since the location of any such failure cannot be predicted and since the volume of test water that may be discharged is difficult to predict. Calculations by a pipeline integrity consulting firm estimate that approximately 18 to 20 failures will occur at the high test pressures planned. Since the most likely failure location is at pipeline flaws, the location of the expected failure cannot be predicted with any accuracy; at most, a minimal number of recently replaced sections of pipe may be eliminated from consideration. Therefore, the expected failures will approximate a random distribution over the Houston to Crane segment. A finite number of failures could be assigned to the habitat areas based upon the proportional share of pipeline mileage in habitat areas; however, that methodology would probably result in either overestimation or underestimation of the number of failures in habitat areas. In addition, the potential volume of test water discharged in the event of failure is difficult to estimate. First, if a failure results in rapid depressurization of the test segment, the volume of test water discharged will be the sum of (a) water expelled as the pipe returns to atmospheric pressure, which depends upon test pressure and test segment length, and (b) drainage from any adjacent segments at elevations higher than the failure location. Second, if a failure results in a slow depressurization of the test segment, it may be readily identifiable and quickly contained. If a slow leak is difficult to locate, one or more investigative excavations could be required to either search for the failure or plug a portion of the segment so that lengths of pipe may be eliminated from the search. Therefore, given that failure location and size cannot be predicted, potential effects on species and/or habitat cannot be reasonably estimated in advance. Another factor that makes such estimates difficult is the existence of residual amounts of diesel fuel that remain in the pipeline from cleaning during 1998. As the hydrostatic testing proceeds from east to west, the test water may be expected to reflect relatively higher levels of hydrocarbon content. Those concentrations cannot be predicted but are not expected to contain levels of hydrocarbons or other toxic materials sufficient to result in adverse impacts. Spill response equipment such as booms, absorbent pads, and other containment and cleanup equipment will be maintained in the vicinity of the test sites during the procedure. In summary, the locations of hydrostatic test failures cannot be predicted, the volume of test water discharged can not be calculated, and the number of investigative excavations cannot be predicted. In the event of a pipeline failure in or near habitat for listed species, incidental take may occur. The level of potential take is impossible to predict. Basically, take from failure of the pipeline during this testing would require reinitiation of this consultation. 34 <<>> Cumulative Effects Cumulative effects of future State, local or private actions that are reasonably certain to occur in the action area are considered in this biological opinion. Future Federal actions that are unrelated to the proposed action are not considered in this section because they require separate consultation pursuant to Section 7 of the Act. Because of the linear nature of the pipeline and the long history of clearing (about 50 years) the Service anticipates no cumulative effects from the activities proposed. The majority of the counties involved in the project are predominantly rural, and imminent future actions identified that may affect each of the listed species are either not considered to be of sufficient magnitude to result in jeopardy to the species or will include minimization necessary to avoid jeopardy. Conclusion The Service in developing its biological opinion has thoroughly reviewed the proposed action submitted by EPA, OPS, and Longhorn Pipeline Partners. This Biological Opinion is predicated on the compliance and the full and complete adherence by EPA, OPS and the Longhorn Pipeline Partners to the Description of the Proposed Action provided earlier in this document. In consideration of the above and after reviewing the current status of the potentially affected species, the environmental baseline for the action area, the effects of the proposed action including direct, and indirect and cumulative effects, it is the Service's biological opinion that the action as proposed by EPA, OPS, and the Longhorn Pipeline Partners for Longhorn Pipeline Project Maintenance Activities and Minor Construction from Houston to Crane, Texas, is not likely to jeopardize the continued existence of any Federally listed species. In addition the proposed action is not likely to destroy or adversely modify the designated critical habitat of the Houston toad. In addition, the Service concurs with the not likely to adversely affect determination, made by EPA and OPS for areas that are not habitat for threatened or endangered species. INCIDENTAL TAKE STATEMENT Section 9 of the ESA and Federal regulations pursuant to section 4(d) of the ESA prohibit the take of endangered and threatened species, respectively, without special exemption. Take is defined as to harass, harm, pursue, hunt, shoot, wound, kill, trap, capture or collect, or to attempt to engage in any such conduct. Harm is further defined by the Service to include significant habitat modification or degradation that results in death or injury to listed species by significantly impairing essential behavioral patterns, including breeding, feeding, or sheltering. Harass is defined by the Service as intentional or negligent actions that create the likelihood of injury to listed species to such an extent as to significantly disrupt normal behavior patterns which include, but are not limited to, breeding, feeding or sheltering. Incidental take is defined as take that is incidental to, and not the purpose of, the carrying out of an otherwise lawful activity. Under the terms of section 7(b)(4) and section 7(o)(2), taking that is incidental to and not intended as part of the agency action is not considered to be prohibited taking under the Act provided that such taking is in compliance with the terms and conditions of this Incidental Take Statement. The term take in the Endangered Species Act is not defined for plants and therefore plants are not included in the incidental take statement of biological opinions. However, Federal agencies 35 <<>> are required under section 7 (a)(1) of the Act to consult with the Service on actions that may affect listed plants, and to insure that any agency action is not likely to jeopardize the continued existence of the species or result in the destruction or adverse modification of critical habitat. Further, section 7(a)(2) of the Act applies equally to plants and animals. Amount or Extent of Take The Service anticipates that the level of incidental take from the proposed activities will be low. The seasonal restrictions placed on these activities, and alternative techniques planned for sensitive habitat areas (land conservation funding), and other conservation actions planned should avoid and minimize the potential for incidental take to the maximum extent practicable. The amount or extent of incidental take resulting from the proposed action on listed species is difficult to assess since comprehensive survey information is not available for all species that could be affected. The approach taken for most of the potentially affected species is to assume that they are present in the identified potential habitat areas and that take will occur. The proposed action uses the potential habitat to define the possible extent of any take that could occur. Based on the proposed action, the Service will assume incidental take for the entire width of the pipeline ROW (and edge effects from the ROW) as it traverses broad areas of potential habitat for listed species. Take is calculated based on the extent of suitable habitat within the established ROW (50-foot width x length) and within temporary work spaces that exceed the ROW (variable by location). The following summarizes by species the amount of potentially suitable habitat that will be impacted by the proposed action (Table Three). Table Three. Potential Suitable Habitat Species Area Impacted Texas prairie dawn 61.3 acres Navasota ladies'- tresses 5.2 acres Houston toad 20.6 acres Golden-cheeked warbler 116.8 acres Black-capped vireo 41.7 acres Tobusch fishhook cactus 213.2 acres Effect of Take In the accompanying biological opinion, the Service determined that the level of anticipated take identified is not likely to result in jeopardy to the species or destruction or adverse modification of critical habitat. Implementation of this project should result in net benefit to the species listed above in Table Two, to the extent that conservation benefits planned exceed expected impacts to the species. Reasonable and Prudent Measures The Service believes the following reasonable and prudent measures are necessary and appropriate to minimize take associated with the proposed Phase One - Longhorn Pipeline Project Maintenance Activities and Minor Construction Houston to Crane, Texas. 36 <<>> The measures described below are non-discretionary, and must be undertaken by EPA and/or OPS so that they become binding conditions on the Longhorn Pipeline Partners, as appropriate, for the exemption in section 7(o)(2) to apply. EPA and OPS have a continuing duty to regulate the activities addressed by this incidental take statement. If EPA or OPS, (1) fails to assume and implement the terms and conditions or (2) fails to require the Longhorn Pipeline Partners to adhere to the terms and conditions of the incidental take statement through enforceable terms and conditions, the protective coverage of section 7(0)(2) may lapse. In order to monitor the impact of incidental take, EPA, OPS, and/or Longhorn Pipeline Partners must report the progress of the action and its impact on the species to the Service as specified in the incidental take statement (below) [50 CFR §402.14(I)(3)]. Reasonable and Prudent Measure 1: The proposed actions, as described in the above "PROJECT DESCRIPTION (Actions addressed under this Biological Opinion)" and the accompanying Biological Assessment must be followed. In areas where the Biological Assessment and the Biological Opinion are not in agreement, the Biological Opinion will be followed. The Service will be available to clarify any questions that may arise during implementation. Reasonable and Prudent Measure 2: EPA and/or OPS must ensure that the activities are carried out by the Longhorn Pipeline Partners as they are proposed. Monitoring of these activities must be accomplished to ensure compliance. The level of monitoring must include onsite review of activities with a relatively intense focus on the first year when construction will occur. EPA and/or OPS must submit a monitoring plan detailing the level of monitoring that will occur. Service concurrence with the level and type of monitoring proposed is a requirement. Terms and Conditions In order to be exempt from the prohibitions of section 9 of the Act, EPA and OPS must comply with the following terms and conditions, which implement the reasonable and prudent measures conditions are non-discretionary. described above and outline required reporting/monitoring requirements. These terms and Terms and Conditions to Implement Reasonable and Prudent Measure 1 This term and condition is effective immediately. Terms and Conditions to Implement Reasonable and Prudent Measure 2 This term and condition is effective immediately. Given that the proposed work is scheduled to begin with the issuance of this opinion, EPA and/or OPS must submit a monitoring plan detailing the level of monitoring within two weeks of the receipt of the Biological Opinion. On site review of the projects should begin before March 1, 2000. Conservation Recommendations Section 7(a)(1) of the Act directs Federal agencies to utilize their authorities to further the purposes of the Act by carrying out conservation programs for the benefit of endangered and threatened species. Conservation recommendations are discretionary agency activities to 37 <<>> minimize or avoid adverse effects of a proposed action on listed species or critical habitat, to help implement recovery plans, or to develop information. It is recommended that in areas where surveys are completed ahead of destructive project actions, any plants in the action area be protected and avoided wherever possible. Where Tobusch fishook cactus plants are found that cannot be avoided and will be destroyed by the project activities, the Service recommends these plants be removed and transferred to the conservation collection of the Desert Botanical Garden in Phoenix, Arizona, where they can be cultivated for seed production and cryopreservation for use in future restoration work for the species. Contact Desert Botanical Garden prior to removals to arrange transfer and obtain any special instruction. In general, plants should be removed by digging at least a one foot diameter area around the plant, carefully rinsing to bare root, thoroughly drying the entire subsoil area and any wounds before transport (by placing on newspapers in a cool shaded location) and then (when dry) carefully packing in newspaper in a box, and then packing in a second box surrounded by protective packing materials before express shipping. • It is recommended that maintenance practices be implemented that will help minimize impacts to the vegetation community, fragmentation of Houston toad habitat, and edge effects. To facilitate dispersal for Houston toads that cross the ROW, Longhorn Pipeline has agreed to maintain the ROW in native bunchgrasses rather than sod-forming grasses, which inhibit movement. The height of native bunchgrass communities shall be maintained several inches (i.e., ≥ 4 inches) above ground level to provide adequate cover for toads. • Avoid using herbicides and pesticides in Houston toad areas. If herbicide use cannot be avoided, direct application techniques shall be used to minimize amount of application and areas of the habitat impacted. Avoiding the use of herbicides and pesticides is particularly critical near any wetland areas and during the breeding season (January through June). Avoiding the use of chemicals in habitat minimizes the risk of harm through toxic effects to the toads and tadpoles themselves or their food base. • To protect the Houston toad from predation by red imported fire ants (Solenopsis invicta), periodically inspect the ROW for fire ant activity. Inspections should occur when fire ants are most active. If fire ants are found, individually treat fire ant mounds using commercial fire ant bait in accordance with label instructions. Bait should be placed only near fire ant mounds and not near the mounds of native ant species. To avoid affects on non-target species, apply bait when ants are actively foraging and prevent accumulations of excess bait. Reinitiation Notice This concludes formal consultation for Phase One - Longhorn Pipeline Project Maintenance Activities and Minor Construction Houston to Crane, Texas. As provided in 50 CFR $402.16, 38 <<>> reinitiation of formal consultation is required where discretionary Federal agency involvement or control over the action has been retained (or is authorized by law) and if: (1) the amount or extent of incidental take is exceeded; (2) new information reveals effects of the agency action that may affect listed species or critical habitat in a manner or to an extent not considered in this opinion; (3) the agency action is subsequently modified in a manner that causes an effect to the listed species or critical habitat not considered in this opinion; or (4) a new species is listed or critical habitat designated that may be affected by the action. In instances where the amount or extent of incidental take is exceeded, any operations causing such take must cease pending reinitiation. In closing we wish to thank EPA, OPS, and the Longhorn Pipeline Partners for the cooperation and patience shown during this consultation. Thank you for your interest in protecting our federal trust resources. If you have any questions, please contact Matthew Lechner (512) 490- 0057, extension 234. Sincerely, /s/ William M. Seawell (for) David C. Frederick Supervisor 39 <<>> Appendix One Confidential Settlement Agreement UNITED STATES DISTRICT COURT WESTERN DISTRICT OF TEXAS AUSTIN DIVISION Ethel Spiller, et al., Plaintiffs versus Robert M. Walker, et al. Defendants CIVIL NO. A-98-CA-255-SS Settlement Stipulation 40 <<>> Appendix Three Literature Cited Arft, A. and T. Ranker. 1995. Demography of the rare orchid Spiranthes diluvialis: implications for conservation. Program and Abstracts, 9*h annual meeting of the Society for Conservation Biology, June 7-11, Fort Collins, Colorado. Abstract, notes from presentation attended. U.S. Fish and Wildlife Service, Austin, Texas. Brune, G. 1981. Springs of Texas: Volume 1. Branch-Smith Inc. Fort Worth, Texas. Chippindale, P., D. Hillis, and A. Price. 1990. Central Texas Salamander Studies. Section 6 report submitted by Texas Parks and Wildlife Department to U.S. Fish and Wildlife Service. Federal Aid Project No: E-1-2, Job No. 3.4. Austin, Texas. Horizon Environmental Services, Inc. 1991. Threatened or Endangered Species Investigations - EZ Pipeline Project. Horizon Environmental Service, Inc. Austin, Texas. Poole, J.M,. and D.H. Riskind. 1987. Endangered, Threatened, or Protected Native Plants of Texas. Austin, Texas: Texas Parks and Wildlife Department, State of Texas. U.S. Fish and Wildlife Service (USFWS). 1984a. Houston toad recovery plan. U.S. Fish and Wildlife Service. Albuquerque, New Mexico. 73pp. U.S. Fish and Wildlife Service (USFWS). 1984b. Navasota ladies'-tresses recovery plan. U.S. Fish and Wildlife Service. Albuquerque, New Mexico. U.S. Fish and Wildlife Service (USFWS). 1994a. Minimum Procedures for Determining the Presence/Absence of Golden-Checked Warblers and Black-Capped Vireos. March 7, 1994 Memorandum, Austin Field Office. U.S. Fish and Wildlife Service (USFWS). 1994b. Population and habitat viability assessment: Houston toad (Bufo houstonensis). Workshop conducted by IUCN/SSC Conservation Breeding Specialist Group in partial fulfillment of USFWS contract #94-172. Apple Valley, Minnesota. U.S. Fish and Wildlife Service (USFWS). 1995. Threatened and endangered species of Texas (revised). U.S. Fish and Wildlife Service. Austin, Texas. U.S. Fish and Wildlife Service (USFWS). 1995. Threatened and Endangered Species of Texas. Austin, Texas: US Fish and Wildlife Service, Revised June, 1995. U.S. Fish and Wildlife Service (USFWS). Houston Toad Recovery Team. 1999. March 31-April 1, 1999 Meeting Minutes. U.S. Fish and Wildlife Service, Austin, Texas. Texas Parks and Wildlife. 1993. Endangered species information for Hilltop Lakes. Texas Parks and Wildlife Resource Protection Division, Austin, Texas. Wilson, H. 1993. Contractors partial draft of recovery plan revision for Navasota ladies'-tresses (unfinished contract). U.S. Fish and Wildlife Service, Austin, Texas. 41 <<>> Phase Il Biological Assessment April 10, 2000 Addendum September 14, 2000 42 <<>> Horizon Job No. 990144 PHASE TWO BIOLOGICAL ASSESSMENT OPERATION, LONG-TERM MAINTENANCE, AND EMERGENCY RESPONSE, LONGHORN PIPELINE PROJECT HOUSTON TO EL PASO, TEXAS PREPARED FOR: LONGHORN PARTNERS PIPELINE U.S. DEPARTMENT OF TRANSPORTATION AND U.S. ENVIRONMENTAL PROTECTION AGENCY REGION 6 PREPARED BY: HORIZON ENVIRONMENTAL SERVICES, INC. AUSTIN - BEAUMONT - HOUSTON - SHREVEPORT APRIL 10, 2000 Addendum September 14, 2000 99144ba2.v8 <<>> TABLE OF CONTENTS Section Page 1.0 INTRODUCTION 1 2.0 CONSULTATION HISTORY .4 3.0 DESCRIPTION OF THE PROPOSED ACTIONS. 7 3.1 Project Overview.... .7 3.2 Pipeline Operation 22 3.3 Long-Term Maintenance.. .22 3.4 Emergency Response..... 29 3.5 Edwards Aquifer Protections.. 43 3.6 Pipeline Maintenance Construction. 46 3.6.1 Buescher State Park 46 3.6.2 Edwards Aquifer Protections. 47 3.7 Hydrostatic Pressure Testing And Proof Testing 51 3.8 Right-of-Way Maintenance 52 3.9 Corrosion Inhibitor .. 52 4.0 AVOIDANCE AND CONSERVATION MEASURES 55 Avoidance 55 4.2 Status of the Species/Environmental Baseline 57 4.3 Effects of the Actions.... 68 4.4 Planned, But Unscheduled Construction .. 75 4.5 Future Additional, But Currently Unforseen Construction 76 4.6 Bays and Estuaries Issues. 76 4.7 Summary of Conservation Measures 77 5.0 REFERENCES ...81 99144ba2.v8 <<>> LIST OF TABLES Table Page 1 Consultation History - Phases One And Two. ..4 2 Chronology of Longhorn Pipeline Actions.. 10 3 List of Endangered Species Habitat Areas along the Longhorn Pipeline... ..12 4 Federally Listed Threatened or Endangered Species Which Occur In Counties Traversed By The Longhorn Pipeline Houston to El Paso........ .. 58 - 59 LIST OF FIGURES Figure Page 1 Location Map................ ...8 2 - 10 Areas of Potential Threatened or Endangered Species Habitat Along the Longhorn Pipeline - Houston to El Paso. .. 13 - 21 APPENDIX Phase Two Project Documentation Appendix Accompanying Document Longhorn Facility Response Plan Accompanying Document 99144ba2.v8 <<>> 1.0 INTRODUCTION This document is the Biological Assessment (BA) of the potential for effects, arising out of the activities proposed by Longhorn Partners Pipeline, L.P. (Longhorn), on federally-listed species in Texas. This BA presents data and information describing the proposed plans for the second phase of consultation for the Longhorn Pipeline Project -- Operation, Maintenance, and Response Activities, Houston to El Paso, Texas. The first phase of the consultation (Phase One), which has already been completed, related to pipeline right-of- way maintenance, clearing and marking, selected pipeline maintenance construction activities (pipe replacements and lowering), and pipeline testing (investigation of possible flaws and hydrostatic pressure testing). The Service found that Longhorn's Phase One activities were not likely to jeopardize the continued existence of any federally listed species, nor was it likely to destroy or adversely modify the designated critical habitat of the Houston toad. The Phase One BA, dated February 14, 2000, and the Phase One Biological Opinion (BO), dated February 17, 2000, are hereby incorporated into this Phase Two BA by reference (see Phase Two Project Documentation Appendix at Tabs 1 and 2). The draft Environmental Assessment (EA) of the proposed Longhorn Pipeline System and these BAs are the product of a settlement reached in the matter of Spiller et al. v. Walker et al. pending in the United States District Court in Austin, Texas (See Phase Two Project Documentation Appendix at Tab 3; the Settlement Stipulation). As part of the Court approved settlement, two agencies involved in the original litigation were required to conduct an EA including, specifically, consideration of species listed under the Endangered Species Act (ESA). The Court ordered the U.S. Environmental Protection Agency (EPA) and the U.S. Department of Transportation (DOT), to be responsible for the EA. EPA and the DOT Office of Pipeline Safety (OPS) act as Lead Agencies in the EA process. Radian International LLC (Radian) is a contract preparer of the EA and works at the direction of the Lead Agencies. The Court order provides that issuance of any finding of no significant impact (FONSI) with regard to the proposed Longhorn Pipeline project "shall be conditioned upon implementation" of measures to protect public safety and the environment (Settlement Stipulation at 6). The order also prohibits OPS from authorizing Longhorn to commence operations until Longhorn has implemented those mitigation measures upon which any FONSI is conditioned (Settlement Stipulation at 7). The order contemplates that Longhorn will apply for such ESA permits as may be required in connection with the implementation of any mitigation measures upon which a FONSI may be conditioned. (Settlement Stipulation at 7). The results of this consultation by the Lead Agencies with the Service are expected to be incorporated in the Record of Decision issued by the Lead Agencies. The terms and conditions, mitigatory measures and protections incorporated herein for the benefit of species are expected to be adopted and incorporated by Longhorn in its enforceable mitigation commitments or in its operating and maintenance manuals subject to inspection by, and enforceable by, OPS pursuant to the Pipeline Safety Act (49 U.S.C. 60101 et seq.). Although the Service and the Lead Agencies are in consultation with respect to the entire proposed Longhorn pipeline project, this consultation is being approached in two distinct, yet related phases. Service regulations allow for a staged consultation (50 CFR 402.14(k)) where the Service reviews a project and provides biological opinions on each 99144ba2.v8 1 <<>> incremental step, provided that no irreversible or irretrievable commitments of resources are made. This second phase of the consultation will be directly related to the actual operation of the pipeline, specifically the operation and maintenance of the pipeline system and the potential effects of a pipeline release and related emergency response. Like Phase One, Phase Two activities also include implementation of some mitigation measures, specifically the replacement of pipe in Buescher State Park (see Longhorn Mitigation Commitment 34 (LMC 34) of the Longhorn Mitigation Plan (LMP) dated September 1, 2000; see Phase Two Project Documentation Appendix at Tab 4) and the replacement of some 19 miles of pipe over the Edwards Aquifer recharge and contributing zones with thick-walled pipe. On its own initiative, Longhorn will lower two other sections of pipe in Buescher Park where the pipe crosses streams. Phase Two also includes (a) hydrostatic pressure testing of pipeline segments not tested pursuant to Phase One, specifically, Houston toad habitat areas and areas of potential effect to the Barton Springs Salamander, (b) treatment of the pipeline internally with corrosion inhibitor, and (c) right-of-way clearing in areas of potential effect to the Barton Springs Salamander. Since none of the Phase Two work will be undertaken by Longhorn until this consultation is complete, neither the federal agencies nor Longhorn will engage in any irreversible or irretrievable commitment of resources during the course of the consultation. The two phases have been logically separated. Phase One of the Service's review focused on those actions that were designed to make the pipeline safer. That review did not pre- judge whether or not the pipeline would be used. This second phase of the consultation will focus on whether and how the pipeline will be used. New construction of pipe between Crane and El Paso was reviewed by the Service in 1997 and resulted in a not likely to adversely affect determination (See Tab 5 of the Phase Two Project Documentation Appendix). The Service can logically conclude that operation and maintenance of the Longhorn Pipeline will not jeopardize the continued existence of any federally listed species, and that it is not likely to destroy or adversely modify the designated critical habitat of the Houston toad. This project, as designed, is not likely to adversely affect threatened or endangered species or habitat. There is little risk from operation of the pipeline. The risks that do exist arise in the unlikely event of an accidental release of product from the pipeline. response to this risk, and pursuant to the Settlement Stipulation, Longhorn will implement numerous mitigation measures designed to avoid a release entirely or reduce the magnitude and the impact of a release. Longhorn developed these mitigation measures in response to risks identified by the Lead Agencies. Mitigation measures such as pipe replacement and pipe lowering, in-line inspections, daily surveillance patrols over the Edwards Aquifer recharge zone, enhanced damage prevention and public education programs, and hydrostatic pressure testing greatly minimize the risk of an accidental release from the pipeline in the first place. These efforts minimize the risk a release will occur. In addition, Longhorn will install an enhanced leak detection system which will allow pipeline operators to rapidly detect even a very small release over the Edwards Aquifer recharge zone and portions of the contributing zone and respond quickly, thereby limiting the amount of product released into the environment. Longhorn will also fund a refugium for the Barton Springs Salamander. 99144ba2.v8 2 <<>> Taken together, the Service can conclude that these measures are sufficient to ensure operation of the pipeline will neither jeopardize the continued existence of any federally listed species, nor adversely affect their habitat, and is not likely to adversely affect threatened or endangered species or habitat along the pipeline route. This BA is based upon: (1) the information that Longhorn (as designated non-federal representative), provided as part of the informal consultation including the Draft Environmental Assessment and the Phase One BA), (2) information in the Service's office (including information provided by the public and the plaintiffs in the lawsuit relating to the Longhorn Pipeline), (3) field investigations, and (4) other sources of information. 99144ba2.v8 3 <<>> 2.0 CONSULTATION HISTORY Informal and formal consultation between the Service, Longhorn, EPA, and OPS has been Table 1: CONSULTATION HISTORY - PHASES ONE AND TWO DATE HISTORY 10 February, 1999 Meeting Between Service and Longhorn Representatives 25 February, 1999 Meeting Between Service and Longhorn Representatives 9 March, 1999 Meeting of Service and Radian (consultants writing EA for EPA and OPS) 22 March, 1999 Meeting Between Service and Longhorn Representatives 30 April, 1999 Meeting Between Service and Longhorn Representatives 11 May, 1999 Meeting Between Service and Longhorn Representatives 12 May, 1999 Meeting with the Plaintiffs to discuss the Settlement Agreement 1 June, 1999 Meeting with Barton Springs/Edwards Aquifer Conservation District 8 June, 1999 Meeting Between Service and Longhorn Representatives 11 June, 1999 Multi-Agency Field Tour of Longhorn Pipeline in and near Austin, Texas 29 June, 1999 Meeting Between Service and Longhorn Representatives 30 June, 1999 Telephone Conference Between Service and Department of Justice 19 July, 1999 Meeting Between Service and Longhorn Representatives 27 August, 1999 Meeting Between Service and Longhorn Representatives 10 September, 1999 Meeting Between Service and EPA Meeting Between Service and Longhorn Representatives 13 September, 1999 Meeting Between Service, Austin and Regional Director 27 September, 1999 Meeting between Service Austin Office and Washington Office Original Draft Biological Assessment Submitted to Service 30 September, 1999 Meeting Between Service and Longhorn Representatives 99144ba2.v8 4 <<>> Table 1: CONSULTATION HISTORY - PHASES ONE AND TWO DATE HISTORY 4 November, 1999 Meeting Between Service and Longhorn Representatives 9 November, 1999 Meeting Between Service and Longhorn Representatives 16 November, 1999 EPA and OPS Longhorn Public Meeting, Austin 22 November, 1999 Meeting Between Service and Longhorn Representatives 7 December, 1999 Meeting Between Service and Longhorn Representatives 8 December, 1999 Meeting Between Service and EPA 15 December, 1999 Meeting Between Service and Longhorn Representatives Service Issues Comments on Original Draft Biological Assessment Service Issues Response to EPA Regarding EPA's initial Request for Concurrence on a "Not Likely to Adversely Affect" Determination. 17 December, 1999 Meeting Between Service and Longhorn Representatives 6 January, 2000 Longhorn Requests Concurrence from Service for "Not Likely to Adversely Affect" Meeting Between Service and Longhorn Representatives for Maintenance and Construction Activities in Non-habitat Areas for Listed Species. 10 January, 2000 EPA and OPS Longhorn Public Meeting, Austin 11 January, 2000 Meeting Between Service, EPA and OPS 17 January, 2000 Meeting Between Service and Longhorn Representatives 18 January, 2000 Meeting Between Service and Longhorn Representative 28 January, 2000 Initial Draft First Phase Biological Assessment received for review 7 February, 2000 Meeting Between Service and Longhorn Representatives 1 February, 2000 Telephone Conference Between Service and Congressman Doggett's Staff 3 February, 2000 of consultation EPA and OPS designate Longhorn the "non-federal representative" for purposes 10 February, 2000 Received EPA Request for Formal Consultation 14 February, 2000 Received Second Draft of Phase One Biological Assessment For Review 17 February, 2000 Received Revised Final Phase One Biological Assessment 17 February, 2000 Received OPS Request for Formal Consultation 17 February, 2000 Service issued Phase One Biological Opinion 9 March, 2000 Il consultation with submission of initial draft of Phase Two Biological Assessment Meeting between Service and Longhorn Representatives to initiate informal Phase 12 April 2000 Received Revised Draft Phase I! Biological Assessment 26 April 2000 Meeting Between Service and Longhorn Representatives 99144ba2.v8 5 <<>> Table 1: CONSULTATION HISTORY - PHASES ONE AND TWO DATE HISTORY 6 June 2000 Meeting Between Service and Longhorn Representatives 23 June 2000 Meeting Between Service and Longhorn Representatives 30 June 2000 Meeting Between Service and Longhorn Representatives 21to 31 July 2000 Received supplemental information for the Phase II Biological Assessment 3 August 2000 Meeting Between Service and Longhorn Representatives 5 August 2000 Meeting Between Service and Longhorn Representatives 9 August 2000 Meeting Between Service and Longhorn Representatives 23 August 2000 Meeting Between Service and Longhorn Representatives 6 September 2000 Meeting Between Service, Lead Agency, and Longhorn Representatives 11 to 13 Sept. 2000 Received supplemental information for the Phase II Biological Assessment 99144ba2.v8 <<>> 3.0 DESCRIPTION OF THE PROPOSED ACTIONS The following is an overview of the project as proposed by Longhorn and is provided to give an overall context of the proposed project. The specific activities proposed for this Phase Two BA are detailed in the following sections. This project overview differs slightly from the project overview contained within the Phase One BA; specifically, this project overview describes four connecting pipelines as opposed to the three previously described. However, the differences implicate no change to the potential effects of the overall project upon species, given that no potential habitat areas have been identified along the planned route of the connecting pipelines. 3.1 Project Overview Due to the expanding demand for refined products in El Paso and other markets in the southwestern United States, the proposed Longhorn Pipeline will transport up to 225,000 barrels per day (bpd) of refined products to the El Paso Terminal and to the Equilon Terminal in Odessa. From these terminals, products will be distributed by truck transport in the El Paso and Odessa markets. Tanker trucks could transport refined products to Juarez in Mexico. The Longhorn Pipeline will connect to the Kinder Morgan and Chevron pipelines at El Paso, enabling shippers to transport products to Phoenix, Tucson, Albuquerque, and other southwestern markets. Market conditions and shipper requirements will determine the actual pattern of distribution of products to El Paso and to the Phoenix, Tucson, Albuquerque, and other southwestern markets. The Longhorn Pipeline System is designed for service in excess of fifty years from startup and is made up of four main pipeline segments, several stations, and one terminal, as listed below: 1. New and refurbished 20-inch diameter pipeline from Galena Park Station to Satsuma Station 2. Refurbished 18-inch diameter pipeline from Satsuma Station to Crane Station 3 New 18-inch diameter pipeline from Crane Station to El Paso Terminal 4. New lateral pipeline connections to Odessa and to other pipelines at El Paso 5. New Pump Stations: GATX, Satsuma, Cedar Valley, Kimble County, Crane, and El Paso 6. El Paso Terminal 7. Odessa Meter Station Longhorn has constructed and will operate a 723-mile refined petroleum products pipeline system from the GATX Terminal in Galena Park, Texas, to a refined petroleum products terminal at El Paso, Texas (Figure 1). The pipeline also has a 28-mile intermediate connection from a station in Crane County to a planned meter station in Odessa, Texas. The pipeline consists of a combination of 20-inch and 18-inch diameter pipe from Galena Park Station to El Paso Terminal and an 8-inch diameter pipeline from a station in Crane County to a meter station in Odessa, Texas. The pipeline's initial capacity of 72,000 bpd will be supplied by a new origin pump station at Galena Park and five new booster pump stations, Satsuma, Cedar Valley, Kimble County, Crane, and El Paso. 99144ba2.v8 7 <<>> 98S00 M rene ta 01 erie 493 0-r 01307o0/g pero bac ле vol ago покоо. 07501 кото AMARILLO eno 2820ag0 nsm 30270 Oklahoma Mexico es i-lo-ing New ron. Louisiana COULDNE T WORTH DALLA ODESSA TO COLOTINE TACO Mexico cApu KIMBLE COUNTY ON SaN/ ANTONIC REDO CHRISTI Mexico Gulf of EXPLANATION LONGHORN REFINED PRODUCTS PIPELINE LONGHORN PIPELINE PUMP STATION: RAD 39067 PUMP STATIONS N LONGHORN PIPELINE 1.05- STATE OF TEXAS NOT. TO SCALE MAP SQURCES: (htto:// www.tnns.state.tx.us/dota__oz.ntml), 1998 TEXAS NATURAL RESOURCE INFORMATION SYSTEM LONGHORN PIPELINE <<>> An 8-inch diameter, 2,500-toot lateral that originates at the terminus of the existing Odessa lateral will connect to a terminal facility in Odessa, Texas, owned by Equilon. Three 8.3-mile lateral pipelines, which originate at the El Paso Terminal, will connect with Kinder Morgan (formerly the Santa Fe Pacific pipeline) and Chevron pipelines in the El Paso area. The connection to Kinder Morgan will consist of one 8-inch diameter pipeline and one 12-inch diameter pipeline. The Chevron connection will consist of an 8-inch diameter pipeline. The purpose of the lateral pipelines is to connect into Kinder Morgan and Chevron pipelines to distribute product into the Phoenix, Tucson, and Albuquerque markets. Chevron operates an 8-inch pipeline that delivers product to the Albuquerque market; Kinder Morgan operates one 12-inch pipeline and one 8-inch pipeline serving the Tucson market. Other Kinder Morgan pipelines connect Tucson to the Phoenix market. One additional eight-inch pipeline, to be installed in the same right-of-way as the El Paso laterals, will create a return system between the El Paso Terminal and the point of the lateral pipeline connections to Kinder Morgan and Chevron. The return system will be used to displace product from within the lateral pipelines back to the El Paso Terminal. The return system will allow product of one type to be removed from a lateral pipeline, prior to initiating delivery of a different product into one of the Kinder Morgan or Chevron pipelines, thus facilitating quality control of products delivered to those pipelines. The return system will be accomplished by installation of a manifold at the point where the lateral pipelines connect to the Kinder Morgan and Chevron pipelines. After startup, Longhorn plans to periodically increase capacity to reach an ultimate capacity of 225,000 bpd. To reach this capacity, Longhorn will, in the future, build ten new booster pump stations and will refurbish or reconstruct three existing stations at the following locations: Approximate Location Station (milepost to milepost) Buckhorn MP 67.5 - MP 77.5 Warda Existing site Bastrop Existing site Orotaga MP 203.8 - MP 213.8 Eckert Existing site Llano MP 265.0 - MP 275.0 Cartman MP 334.0 - MP 344.0 Olson MP 410.0 - MP 420.0 Big Lake Approximately MP 373.4 Pecos MP 516.2 - MP 526.2 Utica MP 543.6 - MP 553.6 Cottonwood Approximately MP 576.3 Harris MP 642.6 - MP 652.6 The Longhorn project includes both new construction and refurbishment of an existing 99144ba2.v8 9 <<>> pipeline that has been converted from its former use of transporting crude oil from West Texas to the Gulf Coast area. The existing pipeline has been modified to transport refined petroleum products, with flow going from east to west. Williams Pipe Line Company (Williams) will be the contract operator of the Longhorn Pipeline System. Longhorn intends to transport multiple grades of gasoline and distillates (i.e., various grades of diesel fuel and jet tuel). The GATX to El Paso segment of the Longhorn Pipeline will function as an interstate common carrier pipeline for those product volumes that will be transported across state lines through the Longhorn Pipeline connections with the Kinder Morgan and Chevron pipelines that extend across the Texas border into New Mexico and Arizona. Product volumes moved from GATX to El Paso for delivery at El Paso will be intrastate movements. The Crane to Odessa segment of the Longhorn Pipeline is an intrastate common carrier pipeline since it transports products solely within the State of Texas. Table 2 lists a chronology of overall pipeline actions leading up to the present. Table 2 - Chronology of Longhorn Pipeline Actions 1949-1950 Exxon constructed the original 18"/20" pipeline, Crane to Baytown, to transport crude oil. 1950-1990 Operation and Periodic maintenance/refurbishment. 1990 An internal inspection (smart pig) of the 20" pipeline was performed. 1995 An internal inspection of the 18" pipeline was performed. 1995-1996 The 18" and 20" pipelines were subjected to a hydrostatic pressure test and purged with nitrogen. Oct 21, 1997 Longhorn acquired the existing pipeline from Exxon. 1s Qtr. 98 Longhorn cleaned the existing pipeline to remove crude oil from the inner walls, so to prepare the existing pipeline for use in petroleum products service. Construction of new pump stations, terminals, and new pipeline sections began. 1998/1999 New Construction completion dates (dates shown are dates of substantial completion): Galena Park Origin Station - August 1998 Satsuma Pump Station - August 1998 Cedar Valley Pump Station - July 1999 Crane Pump Station- March 1999 Kimble County Pump Station - July 1999 El Paso Terminal and Pump Station - August 1999 20" Pipeline, GATX to Tie-In to Existing 20" Pipeline, Houston - October 1998 8" Pipeline, Crane to Odessa - November 1998 18" Pipeline, Crane to El Paso - November 1998 (0.5 mile remains to be constructed to Odessa Meter Station) Odessa Meter Station - In design Equipment installation remaining at a few sites Cleaning and refurbishment of the existing pipeline 18"/20"- March to November 1998 Pipeline Laterals - In design (from El Paso terminal to tie-in point with three interstate 1999 Longhorn commenced implementation of Environmental Assessment mitigation measures, pipelines) 2000 including maintenance construction and investigation of potential pipeline flaws. Longhorn continued implementation of Environmental Assessment related pipeline mitigation testing of the Houston to Crane segment of the pipeline, investigation of potential pipeline measures, including ROW maintenance and marking, maintenance construction, hydrostatic flaws, and cathodic protection system improvements. Additional details about the pipeline system, and its operation and maintenance, are contained in Section 7.0 of the Longhorn Pipeline Project Description prepared in 99144ba2.v8 10 <<>> connection with the EA; a copy of the Project Description is provided in the accompanying Phase Two Project Documentation Appendix at Tab 6. For purposes of this Phase Two BA, Longhorn has identified the areas along the pipeline where operating and maintenance activities "may affect" species and habitat. Areas of potential effect include areas of potential species habitat along the pipeline route. Those areas are identified in two documents: (a) Table 3, which lists pipeline stationing numbers for potential habitat areas along the course of the pipeline; and (b) Figures 2 through 10 which graphically depict those same potential habitat areas. This BA addresses those portions of the overall project that were not specifically identified in the Phase One BA. Those items include pipeline operation, long-term maintenance, planned additional construction and future unforeseen construction, potential pipeline release and related emergency response, construction on the Edwards Aquifer recharge zone and at Buescher State Park, hydrostatic pressure testing of approximately 60 miles of pipeline that was not tested pursuant to the Phase One BA, internal treatment of the pipeline with corrosion inhibitor, and right-of-way clearing over the Edwards Aquifer recharge zone. Details of general construction procedures and environmental protection guidelines for implementation of maintenance construction and pipeline testing activities are contained in the Phase One BA and are not repeated herein. Specific construction procedures and environmental protection guidelines for the construction sites at Buescher State Park (Houston toad habitat) and the Edwards Aquifer recharge zone are provided below. Additional procedures and guidelines, as referenced in the following, are contained in various parts of the Phase Two Project Documentation Appendix. The EA assigned tier rankings to individual segments of the entire pipeline that identify environmentally sensitive areas along the pipeline route. "Areas were identified as sensitive based upon proximity and density of population, ground water (with an emphasis on drinking water supplies), surface water, presence of threatened and endangered species habitats, and proximity to recreational areas." See Draft Longhorn EA at Section 9.2.3. Sensitive areas were divided into two categories, Tier | (sensitive) and Tier I!! (hypersensitive); areas not designated as Tier II or Tier III are designated as Tier I. A description of the methodology employed by the Lead Agencies to designate such sensitive and hypersensitive areas is set forth in Appendix 9C of the EA, along with maps of those areas. This Phase Two BA refers to such sensitive and hypersensitive areas. 99144ba2.v8 11 <<>> Horizon ENVIRONMENTAL SERVICES, INC. Table 3: List of Endangered Species Habitat Areas Along The Longhorn Pipeline Houston to El Paso Begin Station 2310+88 2013+44 End Station 2411+20 2279+20 County Waller Harris Harris Texas Prairie Dawn Species 2684+00 4662+00 2831+84 Texas Prairie Dawn 5936+48 5095+20 4782+00 Fayette Austin Texas Prairie Dawn 5128+64 Navasota Ladies-Tresses Navasota Ladies-Tresses - Houston Toad 6723+20 6600+00 6638+72 5948+80 Bastrop Fayette 9152+00 9011+20 9152+00 6864+00 Bastrop Houston Toad Travis/Hays Travis EA Recharge Zone Houston Toad 9724+00 9657+12 9674+72 9961+60 Hays Hays Golden-Cheeked Warbler EA Contributing Zone 9850+72 9762+72 10164+00 9945+76 10036+40 9926+40 Hays Golden-Cheeked Warbler Hays/Blanco. Hays Golden-Cheeked Warbler 10266+08 10461+44 10199+20 Golden-Cheeked Warbler Blanco Golden-Cheeked Warbler 11008+80 11080+96 11036+96 Blanco Golden-Cheeked Warbler Golden-Cheeked Warbler 11691÷68 11295+68 11441+76 11105+60 Blanco: Blanco Golden-Cheeked Warbler Black-Capped Vireo 12114+08 11791+28 11751+52 12149+28 11821+92 Gillespie Gillespie Golden-Cheeked Warbler Golden-Cheeked Warbler 12513+60 12633÷28 12596+32 12606+88 Gillespie Gillespie Golden-Cheeked Warbler 12631+52 Gillespie Golden-Cheeked Warbier Black-Capped Vireo 12921+92 12728+32 13043+36 13110+24 12953+60 Gillespie Mason Mason Golden-Cheeked Warbler Black-Capped Vireo 13203+52 13381+28 13277+44 13305+60 13217÷60 Mason Golden-Cheeked Warbler Golden-Cheeked Warbler 13513+28 13437+60 Mason Mason Black-Capped Vireo Black-Capped Vireo 15153+60 14476+00 16329+28 13578+40 Mason Kimble Tobusch Fishhook Cactus Black-Capped Vireo 15234+56 Kimble Black-Capped Vireo 4/5/00 11 29 PM indengered species hatreat ist RAD 3907 <<>> Louisiana FIGURE 2 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT SHEET LOCATION MAP LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT LONGHORN PIPELINE FIGURE 3 HOUSTON HARRIS FIGURE 4 AUSTIN FIGURE 6 FAYETTE FIGURE 5 RAVIS AUSTIN BASTROP HAYS FIGURE 8 LLANO 3 BLANCO GILLESPIE MASON FIGURE 7 MENARD KIMBLE FIGURE 9 SCHLEICHER FIGURE 1ó NOT TO SCALE RF AGAN! CROCKETT LONGHORN REFINED PRODUCTS APPROXIMATE CITY LOCATIONS FOR AS SUCE IN ATON (10/97 state.tx.ua/dato._oz.html), 1998 Mexico UPTON PIPELINE REFERENCE ODESSA CRANE CRANE EXPLANATION CRANE SOURCES: RAD 39072 <<>> FIGURE 3 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE TEXAS PRAIRIE DAWN-FLOWER HARRIS EXAS PRAIRIE DAWN-FLOWEI Hmenarys ferono VAVASOTA LADIES -TRESSES Saronthes ports" EDWARDS RECHARGE ZONE CONTRIBUTING ZONE On DAT PIPELINE • COUNTY BOUNDARY - HIGHWAY OR MAJOR ROADS CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE RAILWAYS BRIDGES CEMETERY - LLP-2546 MAINTENANCE CONSTRUCTION LOCATION TEXAS PRAIRIE DAWN-FLOWER WALLER EXPLANATION MC. SITE MMESTIOMON (RUNE 1999) =: MILES PINE iSLAND 5 PEAS TOTA TREAD LURE DE: MATE PANTS OF NAVILLE 359 2 RESOURCES TORTOR T 579/9 2 HIS TEN MOO BUT SINGE (197D, OF TOUS 5. HORIZON ENMRONMENTAL SERVICES. * SURCES <<>> ~ un HOUSTON TOAD I (POTENTIAL HABITAT) AUSTIN, FIGURE 4 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELIN WASHINGTON ~ NAVASOTA LADIES-TRESSES TOMS PRAT DON-TOWER AMONTA PIES -TRESSES EDWARDS RECHARGE ZONE CONTRIBUTING ZONE OLDENBURE CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —12P-2516 MUCITONMCE CONSTRUCTION EXPLANATION RAD 39074 MC. SITE DMESTIGITOM (UNE 1990) NAVASOTA LADIES-TRESSES FAYETTE + ROTECTED MATHE PLANTS OF VILES 00 5 50 0/9/90 2 TO TO NO BON SONE TIES OF TOUS. OURCES NO SOURCE <<>> Hono FIGURE 5 THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE RTLEY. HOUSTON TO CRANE SEGMENT COUNTIES OF: TEXAS LONGHORN PIPELINE HOUSTON O HoL ESOTE AREAS OF POTENTIAL FEDERALLY-LISTED COLORADO HOUSTON TOAD (POTENTIAL HABITAT) REPLACEMENT. PIPE HOUSTON TO ALSTOM HOUSTON TOAD Countaco ChO OMELER AANO AAD VREO TORsto coti PoK aCTUS MAISOTA S PONt-TRESSES EDWARDS RECHARGE ZONE CONTRIBUTING ZONE LE DESIGNATED CRITICAL HABITA — COUNTY BOUNDARY → J ACHMAY OR ANOR RONOS CITY STREETS RIVERS AND STREAMS NTERMTTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE BASTROP ROADS RAILWAYS BRIDGES CEMETERY - LLP-2516 MAINTENANCE CONSTRUCTION LOCATION EXPLANATION WATTERSON OCKNE & HORIZON DIMRONMDYTAL SERMCES, INC, SITTE IMMESTIGMOM (RUNE 1999) 2. TeSORCES TORSTON S13T3 (3/87 2 TIS FSH MOO DUF SONOS 19ES, OF TOUS. S. PON TEDA PASSED MATE DER ME PRATS. OF <<>> "ZONE'T UKAWINU 990144-A29 NUMBER FIGURE 6 AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE EDWARDS RECHARCE KŁVISED BY 3/8/00 HAYS DKAr 1 TRAVIS MASON POTS-TRESSES EDMARDS RECHARGE ZONE CONTRIBUTING ZONE CONTRIBUTING ZONE ORIPPING GOLDEN-CHEEKED WARBLER — COUNTY BOUNDARY 332 HIGHMAY OR MAVOR ROADS CRY STREETS RIVERS AND STREAMS INTERMITTENT STREANS COMMUNITY BOUNDARIES LONGHORN PIPELINE RAILWAYS BRIDGES CEMETERY —11P-2516 MAATRANCE CONSTRUCTON EXPLANATION RAD 39076 DOES OF TOUS: CE BE MATE PLAITS OF ACHMENTAL SERMCES, NC. STE BMESTIEATION (INE 1990) MILES 5763/9/94 Do Not Scole This Drawing BLANÇO <<>> AREAS OF POTENTIAL FEDERALLY-LISTED THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE BLACK-CAPPED VIREO BLANCO MAMOTA POTS TRESSES EDMARDS RECHARGE ZONE CONTRIBUTING ZONE → CACHTY OR MANOR RONOS — COUNTY BOUNDARY CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —LLP-2516 MUNTIONICE COMSTRUCTION cORO EXPLANATION GOLDEN-CHEEKED WARBLER man 20n77 PIPELINE MILES ÇILEŚPIE DA SON (TO), OF TONS LLANO MPSOURCES 5 POET TOE <<>> ABAPPLE PIPELINE LLANÓ FIGURE 8 THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE | GOLDEN-CHEEKED WARBLER > I BLACK-CAPPED VREO HOUSTON TOND - DESIGNATED AREAS OF POTENTIAL FEDERALLY-LISTED con HILLTOR 7 GILLESPIE HABITA Buto houstone) ADO CARDO VARCO EDMARDS RECHARGE ZONE CONTRIBUTING ZONE 2242 GOLDEN-CHEEKED WARBLER COUNTY BOUNDARY CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY -IP-2516 LOCATONCE CONSTRUCTION EXPLANATION BLACK-CAPPED VIREO. RAD 39078 MASON 1.5 MILES a HORIZOM DIMRONMENTAL SERMICES, MC, SITE BESTOMOM (LUME 1990) 2 TAS TEN MONO BIA SINCE TOD, OF TOAS PIPELINE DO SOURCES. <<>> rook -GILLESPIE BLACK-CAPPED VIREO 88 FIGURE 9 THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE PIPELINE HOUSTON TOAD - DESIGNATED AREAS OF POTENTIAL FEDERALLY -LISTED MASON HABITAT Buto houstonerais) GOLDEN-CHEEKED WARBLER (Dendracio chrysoporio) Testroots tok carys JAVASOTA LADIES-TRESSES (arranthes port) EDWARDS RECHARGE ZONE CONTRIBUTING ZONE MOUNTAN COUNTY BOUNDARY → Je HIGHMAY OR MUOR RONDS CITY STREETS RIVERS AND STREAMS NTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY — 11-2516 MAUATINANCE CONSTRUCTION EXPLANATION KIMBLE #/** RAn LONDON cook TOBUSCH FISHHOOK CACTUS 3480 YATES & HORIZON EMIRONMENTAL SERVICES, MC, SITE IMESTIGATIOM (SUME 1999) TEACUP ST PASSED OUR UST MONE PLANTS OF 2. THE AN AND DIA SOME TODD OF TOUS. MENARD 377 <<>> NUMOLN - BLACK-CAPPED VIREO CÁCTUS LOCATION FIGURE 10 THREATENED OR ENDANGERED SPECIES HABITAT TRAVERSED BY LONGHORN PIPELINE HOUSTON TO CRANE SEGMENT COUNTIES OF TEXAS LONGHORN PIPELINE PIPELINE HOUSTON TO DEED AREAS OF POTENTIAL FEDERALLY-LISTED DI 310/00 KIMBLE TOAD - POTENTIAL TRA PRAN I DONY FOWER SOOTA POES-TESSES EDWARDS RECHARGE ZONE TOBUSCH FISHHOOK CACTUS CONTRIBUTING ZONE / Pook MENARD → CONNY OR MANOR ROADS • COUNTY BOUNDARY CITY STREETS RIVERS AND STREAMS INTERMITTENT STREAMS COMMUNITY BOUNDARIES LONGHORN PIPELINE ROADS RAILWAYS BRIDGES CEMETERY —11P-2516 MANTEOANCE CONSTRUCTION EXPLANATION RAD 39080 1674 SITE MMESTOKTON (RUME 1990) MILES PIPELINE I SON (1092, OF TOUS SUTTON 2 TrOot COUNTY SCHLEICHER SOURCES: <<>> 3.2 Pipeline Operation Operation of the Longhorn Pipeline essentially involves the pumping of refined petroleum products through the pipeline to terminals at El Paso and Odessa, where the products are stored in above-ground breakout tanks. From either terminal, the products will be loaded into tank trucks for transport to distribution facilities (such as gas stations and fleet servicing facilities). In addition, at the El Paso Terminal the products may be re-introduced into the connecting pipelines, and then to interstate pipelines operated by Kinder Morgan and Chevron, for transport to southwestern markets. The process of pumping refined products involves the following steps. First, products from bulk storage tanks at the GATX terminal in Galena Park are introduced in batches to the pipeline at the Longhorn GATX pump station. As the products proceed through the pipeline, booster pump stations continue to move the product stream; those booster stations include Satsuma Station in northwest Houston, Cedar Valley Station in Hays County, Kimble County Station in Kimble County, and Crane Station in Crane County. Product destined for Odessa is stored in above-ground breakout tanks prior to re- introduction to the 8-inch pipeline between Crane and Odessa. The pipeline system is operated and controlled remotely from the Williams control center in Tulsa, Oklahoma, using the supervisory control and data acquisition (SCADA) system. The SCADA system allows the controller to start and stop pumps, open and close valves, and monitor the functions of the system components. Pump station and valve site operations are managed by programmable logic controllers that interpret and execute commands from the system controller. A multitude of sensors installed in the pipeline and its equipment provide data to the controller and the automated leak detection system. Primary communications are conducted by satellite, with backup provided by land line systems. Section 7.0 of the Longhorn Pipeline Project Description provides additional detail about system operation; see Phase Two Project Documentation Appendix at Tab 6. 3.3 Long-Term Maintenance Maintenance of the Longhorn Pipeline requires activities directed to specific components of the system. For example, pumps and valves receive inspections and maintenance such as lubrication; above-ground tanks receive inspections and maintenance; the right-of-way (ROW) is mowed periodically, and ROW marker signs are erected and replaced as necessary (see Phase One BA); and the pipe is periodically subjected to thorough inspection and analysis that may dictate a variety of maintenance approaches. Additionally, corrosion inhibitor is regularly injected into the product stream to prevent internal corrosion. This Phase Two BA focuses on those maintenance activities that could occur within areas of habitat identified during Phase One. Since the El Paso terminal is not within potential habitat areas, terminal maintenance activities are not treated in this BA. Since Kimble County Station is within a habitat area (Tobusch Fishhook Cactus) and Cedar Valley Station is in an area of potential effect to the Barton Spring Salamander, station maintenance descriptions will focus on activities conducted at those stations. Valve Maintenance 99144ba2.v8 22 <<>> Valve maintenance involves periodic inspections (twice per year, not to exceed 7 ½ months between inspections, per 49 C.F.R. 195.420(a)) to ensure that the valve is not leaking and to confirm that the valve is operable. Leak and overall condition inspection is visual, as described | in the Williams Operating and Maintenance Manuals, Maintenance and Calibration section, Valve Maintenance and Calibration (Phase Two Project Documentation Appendix at Tab 7). If a leak is identified, corrective action is taken to stop the leak and perform cleanup of any product released. All lubricants are managed to prevent any release to the environment; specific procedures are identified in the Williams System of Manuals, Operating Manual, Section 12 (Phase Two Project Documentation Appendix at Tab 7). Pipeline Cleaning Pipeline cleaning is conducted approximately twice per year to remove deposits from the inner walls of the pipe. Pipe cleaning involves the introduction of a spherical or cylindrical scraper (also known as a scraper pig) into the pipeline at a pump station; the scraper travels within the product stream and is removed at a downstream station, along with any debris collected along the way. Launching and receipt of the scrapers is accomplished by way of scraper launchers and scraper receivers (traps, also known as strainers) that are installed at the pump stations. Any debris removed from the pipeline is contained in drums, and drip pans are employed to prevent release to the environment; disposal of the material is conducted in accordance with applicable laws and regulations. Pump Station Maintenance Pump station maintenance protocols depend upon the equipment located at each individual station; however, only two similarly equipped stations lie within habitat or in an area of potential effect to species. Those are Kimble County station which is located in Tobusch Fishhook Cactus habitat in Kimble County and Cedar Valley Station which is located in the Edwards Aquifer contributing zone. Each of those stations contains minimal equipment, the major components of which are pumps and electric motors, scraper launcher/traps, above-ground station piping (to bypass a pump or the station as a whole), intake and outflow (suction and discharge) remote-controlled motor operated block valves, and a station control room. No tanks are located at those two stations. Maintenance of the pump station equipment follows generally the same procedures outlined above for valve maintenance, and below for painting of above-ground components. Pumps require inspection and periodic calibration. Calibration requires that the pump cases be opened for measurement of component tolerances. To do so, the pump is isolated from the pressurized pipeline system, and the case is opened; product remaining within the case is collected in a sump system for re-injection to the product stream. The sump system is sealed and cathodically protected to prevent releases to the subsurface. Drain pans are used if product cannot be drained to the sump; the drain pans are emptied to the sump system for re-injection. Any debris removed from the pump case, along with wipe rags, sorbent pads, and other disposable materials, are collected in a closed top containment drum and stored on a concrete containment skid. The waste materials are classified and then disposed of at an approved disposal facility. 99144ba2.v8 23 <<>> Pipe cleaning debris (see foregoing section) is collected in strainers located at each pump station. The strainers are located upon a concrete skid that contains any liquid from the strainer and drains to the station sump system. Drain pans are used to contain any liquid that will not drain directly to the sump system. Debris removed from the strainer is collected in closed top containment drums and stored on a concrete containment skid. The waste materials are classified and then disposed of at an approved disposal facility. Painting Above-Ground Components Above-ground pipeline components must be protected with coatings (Longhorn uses paint) to prevent atmospheric corrosion (49 C.F.R. § 195.416(i)). Above-ground facilities include pump equipment, valves, meter facilities, and the like. Maintenance of the coatings requires periodic painting, typically on a 5 to 10 year cycle. Any waste materials generated during painting are managed to prevent release to the environment. See the Williams System of Manuals, Operating Manual, Section 12 and the Longhorn Environmental Protection Plan (Phase Two Project Documentation Appendix at Tabs 7 and 8, respectively). Pipe Integrity Maintenance - Introduction Pipe integrity maintenance activities result from inspections and analyses that identify potential threats to pipe integrity; maintenance may then occur to reduce the risk associated with a particular threat. In-Line Inspection In-line inspection is the process of examining the pipe for flaws, corrosion anomalies, dents, cracks, and other flaws using sophisticated electronic inspection devices known as The technology applied is known as high resolution magnetic flux leakage (MFL) and transverse field MFL, and geometry and ultrasonic inspections are performed as well. Smart pigs identify anomalies and record the locations. The smart pig data is then processed and analyzed, both manually and by computer, to determine whether or not the identified anomalies represent pipe flaws that require corrective action. Next, the anomalies are graded and prioritized for inspection; upon inspection, repairs are made, if necessary, to offset the potential adverse effect of the specific flaw. Actions will range from re-coating of a location not requiring repair, to replacement of the flawed pipe with a cylinder of new pipe; typically minor repair such as application of a protective sleeve is all that is necessary. Maintenance construction to investigate and repair flaws identified by the in-line inspection will be conducted in accordance with the procedures set out in the Phase One BA An in-line inspection may produce data that indicates an immediate threat to pipeline integrity, prompting an immediate inspection by excavating the pipe. If an actual threat exists, a repair is made, and otherwise the pipe is coated and buried. In either event, the protection of human health and safety and of the environment is accomplished while efforts are undertaken to avoid all potential adverse effects. See LMP at Sec. 3.5.2. Smart pigs are introduced and extracted from the operating pipeline through the scraper launcher/trap at each pump station; however, some pipeline segments between pump 99144ba2.v8 24 <<>> stations are long enough that the smart pig cannot complete the entire run. In such cases, a temporary launcher/trap assembly is installed on the pipeline to allow removal of the smart pig so that data may be downloaded, batteries recharged, and the smart pig re- launched. Construction to install and remove the temporary launcher/trap assembly is similar to construction to install a hydrostatic pressure test header as described in the Phase One BA. Electronic tracking devices that monitor and record smart pig travel are set on top of the ground during the tests. The initial in-line inspections to be performed pursuant to Longhorn Mitigation Commitment 11 shall consist of a high resolution MFL inspection within three (3) months of system startup. The timing of subsequent in-line inspections of all types will be determined by the Longhorn Pipeline System Integrity Plan and associated Operational Reliability Assessment processes.; the LMP sets maximum intervals for certain tools See Longhorn Mitigation Plan, Items 10, 11, 12, and 12A, and at Section 4.0. No more than three years shall pass without at least one in-line inspection. Temporary launcher/trap assemblies, if any are necessary, will be installed outside of areas of species habitat; thus, no effect upon species is foreseen as a result of in-line inspections. Hydrostatic Pressure Testing Integrity maintenance of the pipeline could require periodic hydrostatic pressure testing, if prompted by the Longhorn Operational Reliability Assessment (see LMP at Sec. 3.3 and 4.0). Hydrostatic pressure testing as prompted by the ORA could encompass different segments of or all of the pipeline. The Phase One BA describes in detail the processes and activities involved in hydrostatic testing, and future testing will be conducted in conformance with the Phase One BA in all respects to avoid potential adverse effects. Corrosion Inhibitor Treatment Shortly after the conclusion of this consultation, Longhorn will treat the pipeline to prevent potential internal corrosion. As a matter of course, potential internal pipe corrosion is managed through several means including the injection of corrosion inhibitors to the product stream. Due to the delays encountered during the Environmental Assessment of the Longhorn pipeline, however, product has not been transported and no corrosion inhibitor has been applied. At the urging of the Service, Longhorn elected not to inject corrosion inhibitor during the hydrostatic and proof tests commenced in February. Due to the project delays associated with the Environmental Assessment, Longhorn intends to treat the pipeline at its next opportunity to reduce the potential for internal corrosion prior to project startup. This process may be repeated from time to time as deemed necessary to maintain internal pipeline integrity; however, Longhorn's present expectation is that only one such treatment will be necessary. The treatment process involves the introduction of a water and corrosion inhibitor mixture into the pipeline at the GATX Terminal in Houston and the mixture pushed through the pipeline with injected nitrogen gas pressure. This will not constitute a pressure test or alteration of operating pressures. Maximum pressures involved in the procedure would not reach normal operating pressures. These pressures are significantly below the 1,100 to 99144ba2.v8 25 <<>> 1,500 psig pressures experienced during periodic hydrostatic testing of the pipeline. At seven intervals along the pipeline (existing valve settings), surface equipment would be needed to facilitate the handling of the water slug and pigs if the procedure is conducted independent of product flow in the line. Those points typically would be: MP 34.09 (Satsuma Station) MP 134.67 (west side of Colorado River) MP 151 (eastern Travis County) MP 182 (Cedar Valley Station) MP 227.9 (Eckert Station) MP 358.7 (west of El Dorado) MP 457.5 (Crane Station) At these points, trucks and equipment would be employed to facilitate the launching and recovery of pigs and nitrogen injection. The water mixture would be recovered into vacuum trucks at Crane Station for proper disposal. The corrosion inhibitor agent to be utilized is manufactured by Baker-Petrolite and goes by the commercial name "Magnacide 575." Material Safety Data Sheets for this product are included in the Phase Two Project Documentation Appendix. Cathodic Protection Maintenance of the cathodic protection system requires periodic inspection and testing and potential system enhancements. Testing and inspection involves pipe-to-soil surveys, close interval surveys, rectifier inspections, casing tests, and interference testing. Pipe-to-soil potential surveys require that pipe-to-soil readings, measured in volts, be taken at pre-existing test stations that are spaced along the pipeline. Survey personnel typically travel along the pipeline in a pickup truck. Pipe-to-soil surveys will occur semi-annually in EA-designated sensitive and hypersensitive areas and annually in other areas. Close interval surveys require that pipe-to-soil potential readings be taken approximately every three feet along the pipeline; thus, testing personnel walk the pipeline, typically in a group of two to five, carrying testing equipment and data loggers. Close interval surveys will be conducted annually in EA-designated hypersensitive areas and on the balance of the pipeline as dictated by the Longhorn Pipeline System Integrity Plan and associated Operational Reliability Assessment (see LMP at Sections 3 and 4, Tab 4). Rectifier inspections include monthly visual inspection and recording of voltage and amperage readings to ensure normal operation; bi-monthly inspections are required by the pipeline safety regulations (49 C.F.R. § 195.416(c)). Casing testing may involve pipe-to- soil potential readings and/or electrical current and resistance readings to determine if the 99144ba2.v8 26 <<>> casing is in direct contact or electrolytically shorted to the carrier pipe. Interterence testing involves pipe-to-soil readings and/or line current measurements to determine whether or cathodic protection system is interfering with the cathodic protection current that protects not a nearby metal object (such as a crossing or parallel pipeline) or the associated the Longhorn pipeline. Pipe-to-soil surveys, close interval surveys, casing testing, and foreign interference testing may identify sections of pipe that require additional cathodic protection or other measures, such as coating re-conditioning, shorted casing remediation, or installation of a bond between the Longhorn pipeline and a source of foreign structure cathodic protection interterence. The addition of cathodic protection current most likely will occur through the installation of sacrificial anode or impressed current ground beds. The procedure for installation of a ground bed is contained in the Phase One BA, as is the procedure for coating reconditioning. Shorted casing remediation involves removal of a direct metallic short (i.e., a spacer bolt or a short segment of the casing end in contact with the carrier pipe), or draining electrolyte (water/mud) from the casing. Some casing remediations may require installation of new pipe, often concrete coated, through the casing or the installation of heavy wall thickness pipe, also with an abrasion resistant overcoat (i.e., concrete), bored under the road/railroad crossing. Any such work in habitat areas will follow the maintenance construction procedure outlined in the Phase One BA. Installation of a bond (a cable) to a foreign source of cathodic protection interference would involve a small excavation between the Longhorn Pipeline and the foreign structure, which are by definition in close proximity. A cable is installed between the facilities and secured to the pipe, usually by thermite welding. Typically, an interference bond installation will occur at or very near a crossing of the pipelines. A bell-hole excavation of approximately ten feet by ten feet, or one-hundred square feet, is sufficient. A depth to that of the deepest line, normally six to eight feet, is needed for the installation. Note that only the top side of the deeper line, not the entire circumference, needs to be exposed to accommodate lead attachment. The cables are brought into an aboveground test station for current flow and pipe-to-soil potential monitoring. The test station will generally be set directly over the pipelines' intersection. However, in some cases, if a fence line is nearby, the leads will be extended to that fence and the test station installed at that location. The trench for leads from the pipelines' intersection to the fence could range from ten to usually not more than fifty feet and from 8 inches to three feet wide and approximately 30 inches deep or below plow depth. Typically, not more than one-hundred-fifty square feet of surface area is disturbed for this trench and it typically remains within the pipeline rights-of-way. Coating disturbed during cable installation is repaired. Any such work in habitat areas will follow the maintenance construction procedure outlined in the Phase One BA. Cathodic protection system maintenance construction is typically conducted completely within the existing ROW. Though unexpected, the possibility exists that future construction could require work to occur outside the existing ROW, since a particular site could be attended with work space constraints (see procedure in the Phase One BA). Depth of Cover 99144ba2.v8 27 <<>> In 1998 Longhorn performed a depth of cover survey to determine the burial depth of the pipeline. In response to the findings of that depth of cover survey, Longhorn has identified a number of locations where the pipeline will be lowered or replaced. Examples of such locations are represented by LMCs 5 and 18; those locations were identified through the depth of cover survey and assigned priority either by Radian in the case of sensitive and hypersensitive areas (LMC 5) or by Longhorn in the case of other lowerings (LMC 18). In the coming years, the Longhorn Pipeline System Integrity Plan, Depth of Cover element, will determine, on a risk-assessed basis, the order and timing of future pipeline lowerings. The locations are prioritized by evaluating the potential for damage to the pipe. As those locations are addressed, the activity will follow the maintenance construction procedures described in the Phase One BA. Maintenance construction is typically conducted completely within the existing ROW. Though unexpected, the possibility exists that future construction could require work to occur outside the existing ROW, since a particular site could be attended with work space constraints (see procedure in the Phase One BA). Removal of Encroachments Longhorn has identified a number of encroachments that will be removed from the pipeline ROW within one year of system startup, in accordance with the commitments of the LMP (See LMC 16). The Service has requested Longhorn's assistance to increase landowner awareness of species and habitat concerns in connection with encroachment removal. Longhorn thus hereby commits to seek to include in any agreement with an encroaching landowner the following acknowledgment: Landowner is hereby informed that threatened or endangered species and/or habitat may exist upon or in proximity to the Property [defined term to identify the Longhorn ROW], and Landowner may have responsibilities to consult with the U.S. Fish and Wildlife Service pursuant to the Endangered Species Act. Longhorn acknowledges that the foregoing does not specifically prohibit by contract Landowner activity that could cause adverse effects to species and habitat. Since any agreement for encroachment removal would be voluntary, Longhorn cannot force landowners to agree that adverse effects will be avoided. Landowners would simply refuse to agree to such prohibitions, leaving Longhorn's power of eminent domain as the remedy. The power of eminent domain does not include within its scope the authority to require landowners to contractually agree to comply with applicable statutory requirements. In summary, Longhorn agrees to raise awareness as much as it legally may. Section 7.0 of the Longhorn Pipeline Project Description provides additional detail about system operation and maintenance; see Phase Two Project Documentation Appendix at Tab 6. 3.4 Emergency Response Risk Based Approach - Longhorn Mitigation Plan 99144ba2.v8 28 <<>> The EA process included the identification of pipeline mitigation measures that Longhorn has committed to implement. Many of the pipeline mitigation measures were identified in response to potential risks identified in the EA. The pipeline mitigation measures are designed to reduce those risks by prioritizing the deployment of resources toward the following goals: Prevention: Reduce the risk of a release by focusing on the four primary categories of risk: outside force damage, corrosion, material defects, and improper operation. Detection: Rapid identification of a pipeline release through use of the best available leak detection technology system-wide, and sensor-based technology in the Edwards Aquifer recharge zone. • Release Volume Minimization: Optimal use of block valves, coupled with the installation of additional check valves, will serve to reduce potential spill volumes, including in areas of potential effect to species. Control: Enhanced emergency response capability that employs thorough, detailed pre-planning, resource identification, and resource retention. A description of the manner in which those pipeline mitigation measures reduce risk is presented in Longhorn's Risk Reduction Benefits Summary, Phase Two Project Documentation Appendix at Tab 9. Prevention - Reduce the Risk of a Release Numerous pipeline mitigation measures are focused on reducing the risk of a pipeline release; many pipeline mitigation measures reduce more than one risk category. For example, hydrostatic pressure testing of the pipeline addresses outside force damage, corrosion, and material defects by testing the pipeline to pressures that create a margin of safety above operating pressures. Flaws that would create a potential for release during operation are eliminated by raising and maintaining internal pipe pressure to at least 125% of its operating pressure over an eight hour period. The pipeline mitigation measures that reduce the risk of a release include the following: : Hydrostatic pressure testing (LMCs 1 and 2) Replacement of an 19-mile segment over the Edwards Aquifer recharge and contributing zones, with the additional protection of a concrete barrier over the pipe (LMC 3) •. Cathodic protection system enhancements (LMC 4) Lowering, replacing and/or reconditioning if necessary at least 38 locations (LMCs 5 and 18) Removal of stopple fittings (LMC 6) Investigation and repair if necessary of 7 potential pipeline flaws (LMCs 7 and 8) Replacement of the crossing of Rabbs Creek (LMC 8) Surge pressure in EA designated sensitive and hypersensitive areas will not exceed maximum operating pressure (LMC 9) 99144ba2.v8 29 <<>> • In-line inspection within 3 months of system startup and additional in-line inspections according to the LMP, the Longhorn Pipeline System Integrity Plan and associated Operational Reliability Assessment (LMCs 10, 11, and 12) Increased frequency of cathodic protection system performance testing (LMCs 14 and 32) • Documentation of adequate pipeline span support and secondary containment at tank facilities (LMCs 15 and 27) • Removal of encroachments to the pipeline ROW (LMC 16) • Clearing the ROW to excellent condition (LMC 17) Analysis and remediation if necessary of stress corrosion cracking and earth movement risks (such as water crossings and seismic activity) (LMC 19) • Increased frequency of pipeline surveillance patrols (LMC 20) • Increased frequency of pump station inspections and installation of remote cameras at all pump stations (LMC 21) Performance of a water crossing valve study, with DOT review and concurrence, of additional check valves (LMC 22) • Development of an enhanced public education program, with performance monitoring (LMC 25) The effect of the above mitigation measures is to significantly reduce risk far below pre- mitigation levels. Detect - Best Available Leak Detection Technology Longhorn has committed to employ the best available, proven leak detection technology in the pipeline industry. Pipeline mitigation measures that improve leak detection, thus reducing the risk of an undetected leak, include the following: • Enhanced, computational-based leak detection system-wide, and sensor-based leak detection over the Edwards Aquifer recharge zone and the Slaughter Creek watershed in the contributing zone (LMC 13) Removal of encroachments to the pipeline ROW (LMC 16) • Clearing the ROW to excellent condition (LMC 17; see Phase One BA and the Service's February 17, 2000 Biological Opinion) • Increased frequency of pipeline surveillance patrols (LMC 20) • Increased frequency of pump station inspections and installation of remote cameras at all pump stations (LMC 21) Development of an enhanced public education program, with performance monitoring (LMC 25) Minimize - Reduce Potential Release Volumes Pipeline mitigation measures also focus on reduction of potential leak volumes: • Enhanced, computational-based leak detection system-wide, and sensor-based leak detection over the Edwards Aquifer recharge zone and the Slaughter Creek watershed in the contributing zone (LMC 13) 99144ba2.v8 30 <<>> • Performance of a water crossing valve study, with DOT review and concurrence of additional valves (LMC 22) Install additional check valves, one over the Edwards Aquifer recharge zone and one over the Edwards Aquifer contributing zone (this Phase Two BA; see section entitled Edwards Aquifer Protections) Control --Maximize Emergency Response Capability Finally, Longhorn has committed to bolster its emergency response planning and preparedness capability to reduce response times and to be prepared, in advance, with a full response effort: Ensure maximum 2-hour full response to EA designated sensitive areas, maximum 1 to 2 hours in hypersensitive areas, and maximum 1-hour response in the Edwards Aquifer recharge zone and the Slaughter Creek watershed in the contributing zone (LMC 23) Establish a response center in South Austin (LMC 23) Enhanced facility response plan will: Address firefighting in areas without Hazardous Materials response units (LMC 24) - Provide detailed planning for areas with high populations of potentially sensitive receptors (LMC 26) Establish consistency with the City of Austin Barton Springs Oil Spill Response Plan and the Service's Barton Springs Salamander Recovery Plan (LMC 28) - Identify and provide detailed planning for multiple response locations within the Edwards Aquifer recharge and contributing zones selected on the basis of calculations of worst case times of transport to the recharge zone In addition, Longhorn has included potential habitat areas on response plan maps and included protection of such habitat areas in response planning and preparedness training, in response to the Comment Letter (see Oil Pollution Act of 1990 Facility Response Plan). Probability of Release and Risk Reduction Longhorn has calculated the pre-mitigation probability of a pipeline release for the potential habitat areas along the pipeline. Those figures are presented in the APR report at Tab 10 of the Phase Two Project Documentation Appendix. The basis for the probabilities calculated is pre-mitigation data compiled by Radian for the Environmental Assessment. Thus, the probabilities do not take into account the numerous risk-reducing pipeline mitigation measures that Longhorn has committed to implement and is in the process of implementing; see above section Prevention - Reduce the Risk of a Release, and Table 2, Chronology of Longhorn Pipeline Actions. The result, then, is that the possibility of a release in the potential habitat areas will be further reduced from those shown in APR report. System-Wide Software-Based Leak Detection 99144ba2.v8 31 <<>> The Longhorn Pipeline will employ the best available, technologically proven pipeline leak detection system. The leak detection system is described in the following excerpt from Item 13 of the LMP submitted in connection with the EA: "Objective: The objective of this program is to identify the Longhorn Release identification time and the shutdown time required to minimize the size and Detection Systems that will be employed to minimize both the leak impact of a potential leak on the Longhorn Pipeline System. Leak Detection Systems: Leak detection for the unintended escape or potential loss of product from Longhorn Pipeline incorporates the use of a combination of visual, mechanical, and analytical processes, equipment, and models. Collectively, Longhorn's Leak Detection System capabilities, which provide for several areas of overlap, are designed to significantly reduce the likelihood of a protracted period of undetected pipeline system breaches and continued that would adversely contribute to human or environmental exposure to hydrocarbon products. Heightened awareness of the designated sensitive and hypersensitive areas along the Longhorn pipeline has resulted in the employment of enhanced leak detection technology and processes. Longhorn's Leak Detection System is comprised of two primary components: External Patrols; and Technology Based systems. By design, these two areas of leak detection provide redundancy and assurance that a release will be detected within the shortest time possible using current best available technology. External Patrols: External Patrol of the Longhorn Pipeline System is primarily accomplished through the targeted activities of Longhorn Operations and directed third party surveillance contract personnel. Some of these activities include aerial patrol, inspection of water crossings, ground based right-of-way patrol, tank dike inspection, scheduled inspections of valve locations, surface facilities, buried road crossings, and DOT regulatory based activities. External Patrol is also enhanced through the incorporation of data obtained through normal pipeline maintenance activities, such as those accomplished via cathodic protection inspections, One-Call line spotting, and physical pipeline examination during pipeline exposures. Another important source of input under the category of External Patrol results from the involvement of the general public, emergency response organizations, contractors, and other third party sources. These groups are specifically targeted via • Longhorn's Damage Prevention Program (see 99144ba2.v8 32 <<>> Longhorn Pipeline System Integrity Plan) and other activities which are designed to instill awareness of the location of the pipeline corridor. Further, active public education programs are designed to result in an increase in public knowledge by which to primarily avoid, but to secondarily recognize, any activities that could reasonably lead to adverse effects to the pipeline system. With pipeline location awareness, product characteristic information, and emergency response phone numbers and points of contact, the general public, emergency responders, contractors, and other third party groups serve as further insurance that system leaks can be minimized from third party damage, may be recognized if one occurs, and in that case be communicated to Longhorn Operations personnel. External Patrol leak detection is dependent upon the physical identification of some abnormality or change from the characteristics of the surrounding area of the pipeline corridor. Physical evidence can include a hydrocarbon odor, a sheen on a water surface, spraying product, bubbles along the ground, discoloration of soil, areas of vegetation "browning," and fires in near proximity to the pipeline assets. Similar to many other methods of leak detection, External Patrol leak detection can readily identify a moderate to major product release. Smaller leaks, be they from pinhole leaks or leaking pipeline components, often require more time to trigger the physical indicators such as defoliation or odor which indicate a potential product leak. Technology Based: Longhorn will employ a leak detection software system to monitor the operation of its pipeline system. This system represents the current best available, proven technology in the industry. The leak detection software is a transient model that is designed to analyze and compare the actual pipeline operations of pressures and flow rates against theoretical values during both steady state and changing conditions. Deviations between actual and theoretical values result in alarm indications and notification to the Operations Control Center for subsequent review, analysis, investigation, and if appropriate shutdown of the pipeline system. Longhorn approached the selection of a computational based leak detection software system through the employment of a highly respected third party consultant who has demonstrated experience in the field of pipeline SCADA systems and leak detection, along with a current understanding of leak detection technologies and performance capabilities. Leak detection performance requirements, based upon demonstrated industry achievable levels and best available transient model technology, were developed by Longhorn's consultant and approved by Longhorn's management. Computational based Leak Detection "Requests For Proposals" were sent to several prospective vendors, and responses were returned to Longhorn's consultant for detailed review and evaluation. The review/analysis process included clarifying discussions with the vendors, technical presentations, and detailed reference checks with provided customer lists. This process yielded two vendors who were judged to be capable of meeting the leak detection 99144ba2.v8 33 <<>> performance requirements established by Longhorn. Further discussions with the two "finalists" resulted in the selection of the computational based leak detection software system that was determined to have the higher degree of leak detection performance. The software based leak detection system is fundamentally a volume (mass) balance system that employs a fully transient model. The flow balance calculated from flow measurements is corrected by the packing rate, which is calculated by the "real-time" model. The resulting volume balance allows calculation of potential leak indicators. A leak would be identified by comparing the node flow balances at measurement points. The model dynamically tracks changes in the pipeline's flow rate. Variation between modeled and measured flow shows up in the volume balance calculation. The rate of change of all boundary measurements affects the leak detection by affecting the model directly, as well as the dynamic thresholds. Leak alarm thresholds are provided for each volume balance section and averaging interval. The SCADA system used for the Longhorn pipeline system operates on Neles (formerly Valmet Automation) Oasys software version 5.2. Longhorn operator Williams subscribes to the Neles maintenance program which provides software program updates. Williams maintains the most a communeason and contin at the pie se components. For example, in 1999 the SCADA system experienced 99.954% reliability (after deduction for Y2K testing). The 0.046% down time for that year is attributable to a single four-hour service outage. Thus, it is very unlikely that the SCADA system would be out of service for any appreciable amount of time. A SCADA system outage could result in a loss of leak detection system sensitivity. An outage which does not affect the entire SCADA system can occur, for example, with the loss of data from a remote terminal unit (RTU) at a pump station for more than three minutes, in which case an alarm sounds in the Control Center to alert the controller. Under such circumstances, the system uses backup land line communications links to reestablish communications. However, the leak detection system is able to maintain its detection capability by modeling across the point of data loss. A loss of SCADA communications that affected the entire system, for example because of a computer malfunction, would immediately be known to the controller. If the SCADA system experiences any outage that results in a total loss of leak detection capability for all or any portion of the pipeline for a period in excess of 5 minutes, then the controller will take action to achieve system shutdown within 30 minutes. In the event that the SCADA system experiences an outage that does not result in a loss of leak detection capability, but instead results in a diminished capability of the system to detect a leak, then the controller will take action to achieve system shutdown within 30 minutes if the capability of the system to detect leaks is diminished 99144ba2.v8 34 <<>> to a level that would prevent Longhorn from meeting its "Leak Detection Performance Commitment" set out below. Further Enhancement: In addition to the computational based leak detection system, Longhorn has committed to employ additional technology to provide for more Stringent leak detection across the environmentally sensitive Edwards Aquifer Recharge Zone and the Slaughter Creek watershed in the Edwards Aquifer Contributing Zone (the "Enhanced Leak Detection System"). In order to achieve this capability, Longhorn plans to employ a hydrocarbon sensing leak detection cable system that has clearly demonstrated the leak detection capability to satisfy Longhorn's commitment contained within Mitigation Commitment 13. This system is designed to detect a leak as small as 0.0030467 barrel per hour in twelve (12) to one hundred twenty (120) minutes from contact with the leak detection cable, depending upon the product sensed by the system. Several factors will make it probable that any released product will come into contact with the leak detection cable within a minimum amount of time, including the following: (a) the construction methods that Longhorn will employ over the recharge and contributing zones during replacement of this segment of pipe, including protection of all identified subsurface voids; and (b) backfill materials used within the trench (primarily fine materials to provide padding to the pipe and otherwise relatively porous media), coupled with the primarily limestone geology of the Edwards outcrop and the fact of the in- trench materials having been disturbed will cause any released product to accumulate within the trench where the leak detection cable will be located. Longhorn has committed to having this system in place prior to start-up of the pipeline. The hydrocarbon sensing leak detection system is based upon the TraceTek hydrocarbon sensing cable manufactured by Raychem HTS. Longhorn's ultimate choice of the TraceTek cable was made after Longhorn, Williams and UTSI International Corporation performed exhaustive research of leak detection technology potentially feasible for this particular application. After detailed analysis of potentially feasible leak detection technologies, and consultation with the Office of Pipeline Safety, the TraceTek cable was identified as the current best available, proven technology in the industry. The table below identifies the sensing capabilities of the TraceTek system. Leak Detection Response: With notification typically originating through the utilization of its External Patrol and Technology Based components of its Leak Detection System Capabilities, Longhorn Pipeline will facilitate the orderly and controlled shutdown of its system within five (5) minutes of a probable leak indication. 99144ba2.v8 35 <<>> Longhorn maintains 24-hour surveillance of its pump stations, motorized valve locations (MOV), terminals (pipe, pumps, valves, meters, and tanks), and meter stations through its SCADA system. (Truck loading operations at the El Paso Terminal are monitored locally.) Twenty-four-hour surveillance will also be maintained with respect to Longhorn's Enhanced Leak Detection System. Pipeline operational data from these locations is transmitted directly to the Tulsa Operations Control Center, where trained and qualified Operations Control personnel monitor and provide equipment control commands to the Longhorn system. Operations Control personnel utilize the following methods for the determination or suspicion of a probable leak indication: • Deviation outside normal operational thresholds from the computational based transient leak detection software system in a direction that is indicative of a leak; • Receipt of an alarm by the sensor cable system over the Edwards Aquifer Recharge Zone; Unexpected deviation outside minimum or maximum alarm thresholds for system pressures and flow rates; Rate of Change alarms that compare pressure or flow value change versus time; Operations Control personnel independent analysis of flowing conditions; • Third party call of suspected or confirmed product leak; • Input from Field Operations Personnel; Automatic closure of MOV's or stoppage of pipeline pumps; and • Terminal high level alarms. Analysis of a suspected pipeline leak is accompanied by an identification of the location of the suspected leak. Upon the detection, notification, and determination of a probable leak indication, Operations Control personnel are trained to immediately shut down the pump station(s) upstream to the leak location. The pump station downstream to the leak location is either kept running or is started to assist with the orderly movement of product away from the leak location. Following the shut down of the upstream pump(s), the Operations Control personnel will close the upstream MOV's from the leak location to prevent the introduction of new product to the segment. Through the use of the SCADA system, upstream pump stoppage and MOV closure are accomplished within five (5) minutes from the identification of a probable leak indication. The Longhorn Pipeline was designed to be shut down immediately following a probable leak indication. Communication with field operations, product origination or destination points and terminals are not required to shut down the pipeline in an orderly or safe fashion. Operations Control personnel are trained to notify the appropriate supply, destination, field operations, and 99144ba2.v8 36 <<>> emergency responder personnel as soon as practical following the shut down and isolation of the pipeline. The above emergency shut down procedures will be documented and tested for Operations Control personnel training certification prior to start-up of the Longhorn Pipeline system. The Longhorn pump stations utilize a Programmable Logic Controller (PLC) to handle the start-up, sequencing, data transmittal, and shut down of the equipment within the station. The Tulsa Operations Control Center sends command signals to and receives operational data from the PLC's at each pump station. The PLC's, coupled with the instrumentation contained at each pump station, serve to protect the pump equipment from mechanical disturbances such as vibration, abnormal motor winding or pump bearing temperatures, loss of product through seal leaks, and fire sources. Internally, the pump equipment is protected from conditions of high product flow, low product flow, low system pressure, high system pressure, and excessive or low motor amperage. The PLC is programmed to provide both early indication alarm and automatic pump shutdown in the event that designated parameters are operated outside their intended range. Pressure, flow, and tank level readings from across the pipeline system are transmitted to the Tulsa Control Center via the SCADA system for computational transient modeling analysis and Operations Controller interpretation of the physical data, as is the data generated by the Enhanced Leak Detection System. The status of the sensor cable system over the Edwards Aquifer Recharge Zone also is transmitted to the Tulsa Control Center. Outside of the automatic shut down of pump units that are controlled by the local pump station PLC's, shut down of equipment and isolation of MOV's are originated by the Operations Controller. Leak Detection Performance Commitment: Longhorn is committed to implementing the best available leak detection systems with the following design specifications: SYSTEM DESIGN LOCATION SPECIFICATIONS Tier I 1% of flow detected within one-half hour. Tier lI 1% or more of flow detected within one-half hour. Tier III 0.5% - 1% of flow detected within one hour. Same as Tier II, except Edwards Aquifer recharge zone an ontributing zone (Slaughter Creek watershed Edwards Aquifer barrel/hour from contact for the following products Same as Tier Il, and sensor-based detection of 0.0030467 • Gasoline - 12 minutes watershed) : Diesel Fuel - 60 to 120 minutes Jet Fuel - 50 to 70 minutes 99144ba2.v8 37 <<>> The leak detection equipment will be installed prior to startup. The computational based system will be adjusted to become operational over approximately the first two weeks of pipeline operation and be further optimized within 6 months of startup. The sensor-based system will be fully operational, at full sensitivity, immediately upon startup. Leak detection capabilities will be demonstrated and periodically tested." UTSI International is Longhorn's third party leak detection consulting firm. Correspondence describing leak detection system development and design is included in the Phase Two Project Documentation Appendix at Tab 11, as are qualifications of the UTSI personnel directly involved in system development and design. System shutdown is achievable without field communications due to the fact that the SCADA system gives remote control of all relevant system components to the pipeline control center in Tulsa. The leak detection system software will not be inoperable during the fine-tuning period; rather, it will be adjusted to its operating status over approximately the first two weeks, and further optimized over as much as six months from startup. The sensor-based system over the Edwards Aquifer recharge zone and Slaughter Creek watershed in the contributing zone will be fully operational, at its full sensitivity, immediately upon system startup. Emergency Response Preparation - Emergency Response Plan The Williams System of Manuals contains an Emergency Response Plan volume, a copy of which is included in the Phase Two Project Documentation Appendix at Tab 12. The Emergency Response Plan provides direction to the employee first aware of an emergency situation, including emergencies that involve a release of a transported commodity. The priority for protection in the event of an emergency is appropriate: (1) human health and safety; (2) the environment; and (3) property. Among the first duties of the first aware/first responder role is to activate the applicable facility response plan (FRP; aka OPA '90 Plan). A copy of the most recent draft of the Longhorn FRP (March 24, 2000) is hereby provided as a separate Appendix; as development is completed, the final FRP will be provided to the Service. Oil Pollution Act of 1990 Facility Response Plan Longhorn developed and distributed an FRP in 1998 and submitted same to DOT for review and comment. The Settlement Stipulation that arose out of the NEPA lawsuit, however, contained DOT's agreement that it would not approve, or allow Longhorn to commence operations under, the FRP until the conclusion of the EA process. The FRP was scrutinized during the EA, and Longhorn committed to develop numerous enhancements to the FRP as listed in this Phase Two BA at Section 3.4. The Service also provided comments to enhance response capability over the EARZ/EACZ. The FRP enhancements will serve to protect the environment as a whole, and listed species and habitat in particular, as well as human health and safety. The LMP contains a number of commitments to enhance the FRP, and those enhancements have been developed and implemented to the extent possible: 99144ba2.v8 38 <<>> • Ensure maximum 2-hour full response to EA designated sensitive areas and maximum 1 to 2 hours in hypersensitive areas (LMC 23) Establish a response center in South Austin (LMC 23) • Enhanced facility response plan will: - Address firefighting in areas without Hazardous Materials response units (LMC 24) - Provide detailed planning for areas with high populations of potentially sensitive receptors (LMC 26) - Establish consistency with the City of Austin Barton Springs Oil Spill Response Plan and the Service's Barton Springs Salamander Recovery Plan (LMC 28; these enhancements depend upon promulgation by the City of Austin and the Service of their respective plans, neither of which has occurred at this writing) The EA took into account listed species and potential habitat when identifying areas to designate as sensitive and hypersensitive (see Section 3.1, above). Thus, the FRP benefits that are directed to sensitive and hypersensitive areas also are directed at species and habitat; see EA at Section 9.2.3 and Appendix 9C. The development of a new response center, to be located in south Austin, will limit the elapsed time between notification of response personnel and implementation of a full response at any release site. Longhorn will stage personnel and equipment to achieve a full response in sensitive areas in less than two hours, and in one to two hours in hypersensitive areas. A response time of 1 hour will prevail for the Edwards Aquifer recharge zone and Slaughter Creek watershed in the contributing zone. A maximum 1 to 2 hour response time will apply in the Barton Creek watershed in the contributing zone. More detailed, site-specific planning and preparation will enable more rapid and more effective deployment on-site. Sensitive and hypersensitive areas are interspersed along the pipeline route, with non-designated areas between; therefore, segments between sensitive and hypersensitive areas benefit from much the same treatment by virtue of proximity (See Longhorn FRP at Volumes II and III, Sections 4 and 5). Stated another way, a Tier I area located near a Tier II or Tier III area, or located between two areas of either Tier Il or Tier Ill status, will by definition be within the reach of response crews within the same time periods stated above for sensitive (Tier II) and hypersensitive (Tier III) areas. Emergency Response Activities The following paragraphs describe generally the sequence and character of activities that occur at a pipeline release location. Each potential release would likely involve unique circumstances, and, among other factors (see APR Companies, Phase Two Project Documentation Appendix at Tab 10), the on-site response will vary with location, terrain, weather conditions, product released, and release volume. The area of disturbance caused by a response action varies depending upon the character of the response and by nature of the release. The following description identifies the majority of typical response activities. The first responder(s) will immediately notify Longhorn Operations Control and the Area Manager. They will take appropriate action to protect life and ensure safety of personnel. They will additionally request Operations Control to notify the appropriate emergency responders. Operations Control will coordinate company response activities until company 99144ba2.v8 39 <<>> personnel arrive on scene. When a leak is detected, Operations Control will shut down the pipeline following procedures in the Operations Control Manual. Remote operated valves upstream of the release will be closed and downstream valves may be closed or left open to allow drainup, depending on conditions. The Longhorn First Responder assumes the role of Longhorn Incident Commander (IC) until relieved. The Longhorn IC will work in cooperation with the local emergency responders (reference Longhorn Emergency Response Plan from the System of Operating Manuals). Responders will conduct a preliminary assessment of the situation including potential health and safety hazards. If someone is injured or if there is the potential for a fire or explosion, emergency services will be called out. Assistance from public agencies for site control and evacuations will be requested if necessary. Proper monitoring will be conducted to ensure public and personnel safety, and that the necessary spill response contractors have been mobilized to assist in containment and cleanup operations. Response contractors are currently identified in the FRP Volume I, Section 8 and within each county-level response zone plan (Volumes II and III). All or a portion of additional resources will be activated, as necessary. For a major release, all resources may be activated. Appropriate regulatory agencies will be notified. Potentially affected sensitive areas will be identified. The designated Tier II and Tier I! areas are identified on the strip maps in FRP Volumes || & III, Section 4. Additional information on the Wildlife Sensitive Areas is located in Section 5 of Volumes || & III. The topographic maps also locate sensitive features along and down gradient from the pipeline. Any response activities will involve measures to protect the sensitive areas. If there is the potential to affect the Wildlife Sensitive Areas, the biological contractor will be included as part of the response team. A request for assistance to have potential ignition sources in the vicinity of the spill, including motors, electrical pumps, electrical power, etc. shut down will be made. Local fire departments and/or Boots & Coots, Eagle Environmental, or other release response contractors will be notified if the use of fire suppressants is required. Longhorn responders will shut down and control the source of the spill. This may include closing additional valves, collection of pooled product at the pipeline location, digging out the pipeline, collection of product from the pipeline and the pipeline ditch, and repair of the pipeline. Longhorn responders will stabilize and contain the situation in coordination with appropriate agencies. This may include berming, the deployment of containment and/or sorbent booms, construction of dams, or trenching in a manner that limits the spread of the product. The tactic used is dependent upon many factors including the location, the volume, type of sensitive areas, weather, and similar factors. General response tactics are discussed in the FRP at Volume I, Section 3. Site-specific tactical plans for selected sensitive areas are located in Section 4 of Volumes II and III. Access points and possible response strategies are identified in the tactical plans. The pre-identified access points were chosen on the basis of calculations of worst case transport times, proximity to existing roads and other access, and suitability for use. Within the Edwards Aquifer recharge and contributing zones, multiple response locations with associated tactical plans have been identified along the Barton, Slaughter and Williamson Creek watersheds in the event a release were to 99144ba2.v8 40 <<>> reach a stream or tributary and potentially be transported toward the recharge zone. (see LBG-Guyton, "Travel Times for Hypothetical Releases from Longhorn Pipeline within the Pipeline Replacement Corridor in Austin, Texas," 2000 in the Project Documentation Appendix). Additional access points may be utilized during an actual response. If indicated, wildlife protection measures will be initiated. Product recovery and removal operations will be initiated. This may include recovery of free product from ground surface, water or trenches using vacuum trucks, skimmers or sorbents. Excavation of contaminated soil may be utilized. In situ methods such as biological treatment or controlled burns may be considered. Any technique used will attempt to minimize disturbance to the environment. Additional information on recovery techniques is located in Volume I, Section 3 of the FRP. All necessary approvals must be obtained from applicable resource trustees. Documentation procedures will be initiated. Documentation of all response actions taken, including notifications, agency and media meetings, equipment and personnel mobilization and deployment, and area impacted will be made. Spill tracking and surveillance operations will be initiated. The extent of pollution may be determined via surveillance aircraft. In the event of subsurface impacts, cave monitoring or water well monitoring may be utilized. Photographers and/or videographers will be utilized. The equipment and personnel required for a response are dependent on the specific release situations. The volume, location, and the unique site characteristics will affect the necessary resources. Some of the equipment such as transport vehicles, temporary storage or tank trucks may be located at a staging area rather than at an active work site. Site-specific resources are identified in the tactical plans within the FRP. In general the major resources that may be utilized at the pipeline release response location may include: Vacuum Trucks (one or more at each recovery site depending on leak volume); : Trackhoe or backhoe for pipeline dig out; Dirt moving equipment may include an additional backhoe or bulldozer and dump trucks for containment and recovery operations; Spill response trailer; Sorbent Material; • Tanker Trucks and/or temporary storage; • Welder's Truck (for pipeline repair); • Boom Truck (for pipeline repair); Miscellaneous transport vehicles; Roll offs or drums for contaminated debris; and • Fire suppressant material if necessary. Species Habitat Areas Longhorn has implemented additional levels of planning and preparedness in the FRP 99144ba2.v8 41 <<>> since September 1999. Human health and safety must take precedence during the execution of an emergency response. If a release occurs within habitat, or at any location where the release could adversely affect species or habitat, Longhorn will employ additional measures to avoid any potential adverse effects to species or habitat. To do so, Longhorn has incorporated into the FRP maps depicting areas of potential habitat both adjacent to the pipeline and along pipeline sections from which a release could adversely affect species or habitat. Longhorn also has identified numerous pre-planned containment and recovery locations throughout the Edwards Aquifer recharge zone and the contributing zone. Further, Longhorn has included in its FRP training regimen for emergency response personnel the information necessary to identify such areas and prioritize response activities toward such areas. Habitat areas along the pipeline have been mapped, and the maps have been incorporated into the FRP along with descriptions of response actions that apply in those areas (See Longhorn FRP at Volumes Il and III, Sections 4 and 5). In addition, Longhorn will immediately engage a qualified biologist on-site to provide direction to response personnel if a release location is near an area of potential habitat. Personnel will be directed to avoid indirect effects such as traversing habitat areas to gain site access. They also will employ site and circumstance-specific measures to protect species and habitat threatened by a release and thereby avoid adverse effects; for example, were a release to ignite in Bastrop County, fire-fighting efforts would identify and give heightened protection to habitat areas near the fire (see Buescher State Park Fire Response Resources, in the Project Documentation Appendix). Longhorn acknowledges the value of Service expertise in protecting species and habitat. As such, Longhorn solicits Service participation in emergency response planning and preparedness training with respect to species and habitat protection. Longhorn invites Service participation in response training at response drills and table-top exercises. Longhorn shall notify the Service of such training exercises, provide the Service an opportunity to review and comment upon preparation for the training, and invite Service participation during such training. 3.5 Edwards Aquifer Protections The Edwards Aquifer in Travis and Hays Counties is a valued resource. In addition, the Barton Springs Salamander, which resides in several spring outlets of the Edwards Aquifer, is an endangered species that must be protected. Longhorn will implement a multitude of measures both to ensure that the quality and integrity of the aquifer is preserved, and to ensure the continued survival of the salamander. See document entitled Edwards Aquifer_ Protections, in the Project Documentation Appendix, which summarizes the various protections. Longhorn will implement conservation measures to avoid the possibility of impacts to the aquifer that could result from a pipeline release over the recharge zone or upon the contributing zone, should ever one occur. However, the Service has requested an analysis of the potential effects if released product were to enter the aquifer. Longhorn will implement a number of pipeline enhancements, including (a) replacement of the pipe over the recharge zone and the contributing zone with new thicker-walled pipe; (b) additionally protecting the new pipe with a reinforced concrete barrier; (c) installation of an 99144ba2.v8 42 <<>> enhanced, sensor-based leak detection system through the recharge zone and the Slaughter Creek watershed in the contributing zone; (d) installation of additional check valves; and (e) daily inspections of the ROW (See Section 3.5.2). An extremely sensitive, sensor-based leak detection system will complement a computational-based leak detection system; jointly the systems will be capable of rapidly identifying potential small and large leaks. Daily patrols will identify potential threats to the pipeline, and enhanced emergency response capability will provide for rapid and effective release response. Longhorn has commissioned thorough analyses of the Edwards Aquifer recharge zone and contributing zone by experienced hydrogeologists, geologists, and biologists (See resumes of Sherrod, Kreitler, Russo, Stein, Miller, Dorsey and Gasch, Phase Two Project Documentation Appendix at Tab 13). The subsurface along the pipeline traverse of the recharge zone has been studied by ground-penetrating radar, and subsequent investigations demonstrated the absence of significant voids along the pipeline (See LBG- Guyton letter to Vince Murchison dated 10 December, 1999, Phase Two Project Documentation Appendix at Tab 14). The related topography has been mapped, and surface drainage tendencies have been modeled. Local infrastructure has been surveyed and analyzed to determine the potential implications to infrastructure components in the unlikely event of a pipeline release; for example, roadways would interrupt the flow of a hypothetical release that resulted in surface flow. Storm water detention ponds in and around Austin receive detailed response planning. Analysis of areas along the pipeline traverse of the recharge and contributing zones has identified locations where the capacity of the pipeline trench to retain fluid could be exceeded. Longhorn first will backfill the trench with fill that has been sized to result in high porosity, which will have the effect of increasing the capacity of the trench to retain fluid if any is released from the pipeline. At an estimated 18 locations at lower elevations, however, the capacity of the trench could be exceeded if worst case discharge volumes are used with the assumption of complete pipe drainage. At those locations, Longhorn will install a berm containment system that has been designed both to contain any product that may reach the surface and to prevent storm water accumulations that could compromise the capacity of the containment systems. Those containment systems are described in the analysis entitled "EARZ/EACZ Pipeline Replacement Trench and Berm Product Containment Conceptual Design," "Response to Lead Agency Review of Conceptual Design for Trench and Berm Product Containment for the EARZ/EACZ Longhorn Pipeline Replacement," and "Response to USFWS' draft letter of 8/26/00," all of which are included in the Project Documentation Appendix. Included with the conceptual design are diagrams of the containment systems. The containment systems will be constructed with hydrocarbon-sensing valves that allow the passage of storm water but automatically close, without human intervention, if hydrocarbons contact the valve. Another preventive conservation measure Longhorn will employ is the installation of check valves over the Edwards Aquifer recharge zone and over the contributing zone. The check valves will be located in a manner that reduces potential volumes that could drain from the pipeline in the event of a breach. Check valves are one-way valves that allow product within the pipeline to flow in the intended direction, i.e., downstream in the pipeline. However, check valves prevent flow in 99144ba2.v8 43 <<>> the opposite direction, upstream, such that if for any reason product attempts to flow backward, the valve closes to preclude flow in the upstream direction. A hypothetical example illustrates the function of a check valve. If one assumes a pipeline breach on an incline such that the pipeline flow is uphill, the contents of the pipeline could drain out of the breach due to the forces of gravity. If one then assumes that a check valve was installed along that incline (downstream on the pipeline), then the check valve would stop the backward, downhill flow of the product from the pipeline, effectively reducing the volume of product that could drain from the breach (gravity is not the only force to be factored into the potential for draindown, as discussed below). The check valves that Longhorn will install will be located to achieve just such effect. The valve over the recharge zone will be placed at approximately milepost 171.5, near the pipeline intersection with Whiteworth Loop in the Sendera Glen subdivision, which is downhill of a gradual rise in the land surtace to the west. By being located near a low point of the pipeline traverse of the recharge zone, the check valve will prevent the potential for draindown of product from the check valve to a point approximating the western edge of the recharge zone. The valve over the contributing zone will be located at the existing Edwards Aquifer West Valve, approximately milepost 175.5, about 2.1 miles east of U.S. 290 and about 1.8 miles west of the boundary of the recharge zone. Again, this valve is located below a moderate incline to the west and will reduce the potential draindown volume of a release between the two check valves. See APR report, Phase Two Project Documentation Appendix at Tab 10. Concerns have been raised by various parties, Longhorn opponents included, to the effect that a breach in a pipeline allows all product in the pipeline between adjacent block valves to drain out, but such is not the case. The California State Fire Marshall's office has analyzed pipeline release volumes to determine the extent to which various components of release volume contribute to total release volume (see Phase Two Project Documentation Appendix at Tab 15). The analysis determined that draindown contributes only marginal volumes to a release. Of the releases studied, in only 25% of the cases did the total release volume exceed 4.5% of the potential draindown of the pipeline, while in just 10% of the cases did the total release volume exceed 28% of the potential draindown. Among the reasons for low draindown volumes is that for product to flow out of the pipeline, it must first be displaced by air, similar to the manner in which water flows from a bottle that is turned upside down. See APR Companies, Phase Two Project Documentation Appendix at Tab 10. Longhorn has calculated full line draindown for hypothetical releases to the east of the recharge zone check valve described above; that volume is 3,875 barrels (162,750 gallons). However, if one applies the lessons of the California State Fire Marshall risk assessment that volume is more realistically calculated as 1,147 barrels (48,174 gallons) at 28% draindown and 841 barrels (35,322 gallons) at 4.5% draindown. Despite the findings of the California State Fire Marshall risk assessment, Longhorn has designed the bermed areas described above using the assumption that all product escapes from the pipeline segment affected by a release. Using those more realistic assumptions, the potential threat to the Barton Springs Salamander from a pipeline release in such areas is lower than previously understood. Calculations of the effect of a release over the aquifer recharge zone performed by LBG- Guyton (see Phase Two Project Documentation Appendix at Tab 16) demonstrate that the potential for adverse effects to the salamander is greatly reduced. See Section 4.4 of this 99144ba2.v8 44 <<>> BA and LBG-Guyton, Phase Two Project Documentation Appendix at Tab 16. Nonetheless, Longhorn's conservation and mitigation measures will make it unlikely that adverse effects to the aquifer will occur. 3.6 Pipeline Maintenance Construction This section identifies and describes incremental pipeline maintenance construction activities, in addition to those that were the subject of the Phase One BA, that will be implemented in two specific areas: (a) within Houston toad habitat in Bastrop County; and (b) across and adjacent to the Edwards Aquifer recharge zone within Austin. Additional maintenance construction will include planned, but unscheduled construction and future additional, but currently unforeseen construction. Maintenance construction that occurs outside the two presently identified areas will be subject to the maintenance construction procedures described in the Phase One BA, as will maintenance construction in Houston toad habitat and the Edwards Aquifer recharge zone; however, this BA contains descriptions of additional conservation measures that Longhorn will implement during the maintenance construction activities over the Edwards Aquifer recharge zone. The maintenance construction procedures referred to herein, and presented in detail in the Phase One BA, are identified below: 1. Pipeline Maintenance -- Construction Planning 2 Project Environmental Inspectors 3. Site Preparation 4. Site Entry 5. Pipeline Lowering and/or Replacement - Open Terrain 6. Pipeline Lowering and/or Replacement - Creek Crossing 3.6.1 Buescher State Park Maintenance construction activities planned within Buescher State Park (containing Houston toad habitat) result both from the EA process and from Longhorn commitments to reduce risks to species and habitat. The EA related project is the replacement of 671 feet of pipe at mile post 127.94 (Hunt Branch) within Buescher State Park in Bastrop County, Texas. Longhorn committed in the LMP (LMC 34) to replace the pipe since data on file at the time indicated that the segment contains several shorter sections of Grade B pipe. Longhorn has since identified file documentation that demonstrates that the existing pipe is adequate for the design pressure; however, Longhorn remains willing to replace the pipe to limit the potential for surge pressure-related damage and thus lower the risk of a release in this habitat area. Two additional tasks have been identified to reduce the risk of a release in Houston toad habitat: (a) lowering and replacement of the pipeline crossing of Dry Branch in Buescher State Park (pipeline mile post 128.33); and (b) lowering and replacement of the pipeline crossing of an unnamed creek approximately 1360 feet east of the 671-foot replacement (pipeline mile post 127.72). See additional engineering information at Tab 17 of the Phase Two Project Documentation Appendix. The three projects significantly reduce the potential for damage to the pipe in and near the three creeks. Since land development does not occur within the state park, and taking into 99144ba2.v8 45 <<>> account the pervasiveness and effect of the EA mitigation measures that focus on identifying and preventing corrosion, on eliminating material defects, and on preventing adverse consequences resulting from operator error, the greatest threat to the pipeline is outside force damage within the creek beds. For a complete discussion of the risk reduction realized by the creek crossing replacements, see APR Report (Phase Two Project Documentation Appendix at Tab 10). Further, the replacements will limit the potential volume of a release, should one occur, since the thicker and higher-grade new pipe will be least likely to suffer a breach, by serving as low-point catchments for product within the pipe that could escape if a release occurred at lower elevations. The new creek crossing replacement pipe will have 0.375" wall thickness and be of American Petroleum Institute Grade X56 or better. The burial depth of the pipe will be determined on the basis of regulatory requirements (49 C.F.R. § 195.248) and site conditions such as type of stream bed material and basin and channel configuration; the pipe will be buried below a depth that would allow in-stream forces to pose a threat to pipeline integrity. 3.6.2 Edwards Aquifer Protections During informal consultation on the Longhorn Pipeline Project, the Service voiced concerns about the pipeline crossing of the Edwards Aquifer recharge zone and the potential for adverse effects to the Barton Springs Salamander. Adverse effects to the salamander may be associated with water quality degradation within the aquifer (See Barton Springs salamander listing final rule at Tab 18 of the Phase Two Project Documentation Appendix). Typically, water quality degradation originates at the aquifer recharge and contributing zones and is largely associated with residential and commercial development and the creation of impervious cover. In addition, commercial and industrial operations and vehicular roadway traffic create the potential both for chronic water quality degradation as a result of ongoing activities and for acute water quality degradation in the event of a release of deleterious materials to the watershed. System operation and ongoing, long-term maintenance of the pipeline are not likely to result in adverse effects to the salamander, for which critical habitat has not been designated. ROW maintenance, pipeline inspection, valve maintenance, and similar such activities are unlikely to result in adverse effects to the salamander inasmuch as the activities are implemented in a manner that does not affect aquifer water quality. Longhorn responded to the Service's concerns about water quality by identifying measures that will not only reduce the potential for a pipeline release, but will protect water quality and promote public efforts to ensure the survival of the species in the unlikely event of a release that threatened the Barton Springs segment of the Edwards Aquifer. Longhorn committed to implement the following measures and included the measures in its Environmental Assessment mitigation commitments: Replacement of over 3 miles of pipe over (and east of) the recharge zone and 15 miles of pipe over the full extent of the contributing zone with new, thicker walled pipe (LMC 3). • 99144ba2.v8 Installation of an enhanced, sensor-based leak detection system across the aquifer 46 <<>> recharge zone and the Slaughter Creek watershed in the contributing zone to complement the pipeline-system-wide computational-based leak detection system (LMC 13). Installation of check valves (one in the recharge zone and one in the contributing zone) to minimize the volume of a potential release should one occur (see Section 3.3, Edwards Aquifer Protection). Performance of daily pipeline surveillance patrols over the recharge zone (LMC 20). Establishment of a refugium and captive breeding program for the Barton Springs Salamander as a conservation measure to ensure the survival of the species in the event of any perturbation to the extant population (LMC 33). Further in response to concerns voiced by the Service, and concerns voiced also by the Barton Springs/Edward Aquifer Conservation District, Longhorn will implement an additional measure to reduce the risk of a release that could adversely affect water quality. Longhorn commits to install a protective concrete barrier over the 5-foot-deep replacement pipe. The barrier will be engineered with reinforced concrete to provide a protective covering over the pipeline that will alert an errant excavator to the presence of the pipeline. The concrete will be colored red to ensure ready notice of the presence of a protected structure. The protection offered by the concrete barrier will provide further reduction of a threat to the pipeline, third party damage, in the developing areas of south Austin, southwestern Travis County, and northeastern Hays County (See additional information at Tab 19 of the Phase Two Project Documentation Appendix). Analysis of the pipeline traverse of the recharge and contributing zones has identified areas where surface flow modeling indicates a tendency for surface flow toward known karst features or toward Slaughter Creek, Barton Creek or Williamson Creek (see LBG-Guyton, Phase Two Project Documentation Appendix at Tab 16 and associated figure). Those areas include (a) from the fire station west of Brodie Lane to Deer Lane, toward the Karst Preserve; (b) from the pipeline crossing of Deer Lane to a point just east of the Sendera Creek. LBG-Guyton has recommended that measures be employed to divert surface flow from those features, with the result that in the event of a release that results in surface flow, the features and thus the Edwards Aquifer will not be subject to the potential for rapid infiltration to the aquifer; see LBG-Guyton, Phase Two Project Documentation Appendix at Tab 16. Longhorn commits to employ such measures. Given the relatively low slope of surface topography across the recharge zone, slight modifications during final surface grading will accomplish the goal of protecting the sensitive features. Thus, planning for construction of the replacement pipe will include the requirement that, during final grading, a low swale or berm be created to protect those features. The precise location and design of these surface flow control features are not easily predictable in advance of construction; thus, Longhorn's geological, biological, and engineering consultants (LBG-Guyton, Horizon ESI, Paragon Engineering, Bury + Partners) will make field recommendations to the contractor as reclamation begins. These recommendations will be carried out by the Contractor at the 47 <<>> direction of the on-site Environmental Inspector. Since the Longhorn Pipeline primarily traverses the surface divide between the Williamson and Slaughter Creek drainage areas, little if any surface flow of storm water will be affected, and no adverse effect to aquifer recharge water quantity will occur. Additional analysis has been performed with respect to the recharge and contributing zones. Surface flow modeling has identified surface flow tendencies along the pipeline, and the calculations have been made of time of travel, to the recharge zone or recharge features, of a hypothetical release under worst case stream flow conditions. See Drawing 199044-C2 and LBG-Guyton, "Travel Times for Hypothetical Releases from Longhorn Pipeline within the pipeline Replacement Corridor in Austin, Texas," 2000 in the Project Documentation Appendix. Longhorn has based its emergency response planning on the results of those analyses, resulting in the multiple pre-planned response locations identified in the Travis County and Hays/Blanco sections of the FRP. Multiple pre-planned response locations enable response personnel to identify the optimum response locations for a release along any segment of the recharge and contributing zones. Longhorn also has identified locations across the recharge and contributing zones at which a release of product could fill the trench and reach the surface. At those locations, Longhorn will construct a bermed area that achieves two competing goals: (1) providing containment in the unlikely event of a release that reaches the surface; and (2) preventing the infiltration of storm water to the areas (which could otherwise compromise containment capacity). The areas will be constructed of berms and swales along and/or across the pipeline right-of-way. Storm water will be prevented from entering the bermed areas by the placement of diversion berms. The presently identified locations of potential surface presence of product, and the conceptual design of the bermed areas, is set forth in the "Longhorn Pipeline EARZ/EACZ Pipeline Replacement Trench and Berm Product Containment Conceptual Design" in the Project Documentation Appendix (note that locations #1 and #20 are outside the applicable replacement segment). Longhorn will execute replacement of the pipe section that crosses the recharge zone pursuant to a maintenance construction plan that does not include the segment across the contributing zone (See Tabs 20 and 44 of the Phase Two Project Documentation Appendix). Pipe replacement across the contributing zone shall be executed pursuant to typical project construction plans developed during the Phase One consultation (but including the sealing of identified karst features in the limestone trench; see additional details in the following paragraphs). Longhorn also has committed to replace an additional one-half mile (approximately) of pipe east of the recharge zone. That area has been identified through surface flow modeling as susceptible to seeing surface flows toward the recharge zone and Williamson Creek. All new pipe will be buried to a depth of 5 feet to top of pipe and will be protected by a red concrete barrier. This segment of the project will be executed pursuant to project construction plans containing the same protections as those developed pursuant to Phase One of this consultation. 99144ba2.v8 48 <<>> The maintenance project will employ numerous measures in excess of the maintenance construction procedures described in the Phase One BA, identified specifically and by qualified individuals and entities (See Phase Two Project Documentation Appendix at Tab 13 for resumes of Kreitler, Stein, Sherrod, Bury, and Miller) as protective of the Edwards Aquifer and thus the salamander. The procedures build upon a solid base of construction storm water best management practices (BMPs) that are implemented at every construction site; moreover, Longhorn will implement procedures at least as stringent as locally prescribed construction BMPs. Longhorn will design its construction project to employ the construction BMPs promulgated by the Texas Natural Resource Conservation Commission (TNRCC) for application during construction over the recharge zone. During pipeline replacement, Longhorn will seal any identified karst features in the limestone trench or exposed in the ROW following guidelines established by TRCC. Upon encountering any karst feature during construction, the Contractor and on-site Environmental Inspector will be required to immediately notify Longhorn's geological, biological, and engineering consultants (Sherrod, Miller, Kreitler, Stein, Bose, Bury - see resumes in Phase Two Project Documentation Appendix at Tab 13) who will promptly inspect the field situation and prescribe proper sealing methods to the contractor. _In addition, immediate notice will be made to appropriate representatives of the City of Austin and the Barton Springs/Edwards Aquifer Conservation District who may also provide additional recommendations to Longhorn's specialists on proper sealing procedures. If exceptionally large or deep voids or caverns are encountered, structural engineering specialists will provide engineered recommendations for supporting the pipeline over the void closure (example engineered recommendations encountered 20 and 44 of the Phase Two Project Documentation Appendix ). All void closure recommendations will minimize potential adverse effects to the function of the void (ie., recharge capability or faunal habitat) while providing the maximum seal from the pipeline and any potential releases. Not only does this address potential issues of impacts to species during construction, but also provides significant aquifer protection and product recovery benefits in the event of a release during operation. Pipeline releases should stay within the pipeline trench and at land surface within the ROW where they can be more easily contained and controlled. First, the volume of a spill will be limited by the installation of check valves that reduce spill volume to a probable maximum of 2100 barrels in the recharge zone. Additionally, the APR report (Tab 10 of the Phase Two Project Documentation Appendix) concludes that only about 28% of the line fill capacity between block valves might be released in 90% of the release scenarios. Third, the topography across the recharge zone is relatively flat, and rapid runoff away from the ROW will not likely occur; see LBG-Guyton Addendum Phase Two Project Documentation Appendix at Tab 16. It is anticipated that with the flat terrain and limited spill volume, potential product spills will remain on the ROW of the pipeline where any caves and other karst features will have already been identified and been sealed or protected during pipeline replacement. Longhorn has, however, committed to implement a number of bermed containment areas at locations where it is possible that product could reach the ground surface, and accumulate, in the event of a release (see Sec. 3.5). The bermed areas are designed so that any released product is captured within the trench and is captured if it rises to the 99144ba2.v8 49 <<>> surface. The bermed areas also are designed to prevent storm water infiltration by run-on and to shed storm water through outlets; however, the systems will collect product in the event of a release by means of automatic, hydrocarbon sensing valves. These systems will be designed and built of low-porosity materials but with the integrity to withstand major storm events. The capacity of the bermed areas will be calculated to contain both a worst case release (assuming complete pipe segment drainage) and precipitation generated by a 100-year storm event. Periodic inspection of the locations will be performed in conjunction with regularly scheduled pipeline surveillance patrols. Longhorn commits to perform a field test of both the trench sealing procedure and the berm construction methods in conjunction with the maintenance construction project over the recharge and contributing zones. If the field test identifies design or construction flaws, adjustments to design or construction techniques will be employed to achieve the desired effect. See "Proposal to Perform Field Tests to Verify the Design and Construction of the Pipeline Trench and Berms for the Longhorn Partners Pipeline over the Edwards Aquifer Recharge Zone in Austin, Texas," in the Project Documentation Appendix. As a result of the foregoing measures, the following defenses protect the Edwards Aquifer: 1. New, thicker pipe; 2. Five foot burial depth; 3. Concrete barrier; 4. Enhanced leak detection; 5. Sealing of all voids, fissures, vugs, and other potential recharge features in the limestone trench; 6. Trench backfill absorption enhancement; Surface containment systems and berms; and Enhanced response planning. As described in Section 4.3 below, that risk will be further reduced by implementation of the Edwards Aquifer Protection Plan during construction. 3.7 Hydrostatic Pressure Testing And Proof Testing Longhorn committed to perform hydrostatic pressure tests and proof tests of the pipeline, and those tests have proceeded during 2000. (See Phase One BA at Sec. 4.10 and LMP Items 1 and 2.) Hydrostatic and proof testing of the pipeline has been ongoing, beginning at the Longhorn GATX pump station in Galena Park (Houston) and proceeding westward to Crane Station, but skipping the segments through Houston toad habitat in Bastrop County and the Edwards Aquifer Recharge Zone in Travis County (refer to Phase One BA in the Phase Two Project Documentation Appendix at Tab 1). The hydrostatic and proof testing has occurred in segments, which were subdivided into test sections of varying lengths. Due to sensitive aquatic species concerns, the Houston toad and the Barton Springs Salamander, two test sections were not tested during the overall Houston to Crane testing project. Those two sections are (a) Segment 4, Section 1, which encompasses habitat for the endangered Houston toad and (b) all of Segment 5, which encompasses eastern Travis County, the recharge zone of the Edwards Aquifer and part of the adjacent contributing zone, areas of concern to the endangered Barton Springs 99144ba2.v8 50 <<>> Salamander. Those sections will be hydrostatic pressure tested, after completion of Phase Two consultation and after pipe replacement takes place, to complete the system integrity testing. Procedures for testing will follow those described in the Phase One BA. However, due to the heightened sensitivity of these two locations, project environmental inspectors and spill response equipment will be onsite and in constant ready status for immediate response during the testing. Makeup water for the tests will originate from the Colorado River or from local sources, and other than the potential for small amounts of residual diesel no contaminants are foreseen in the test water. Since most of the tested line sections will be newly installed pipe and since the prior hydrostatic testing will have flushed the pipe that is not slated for replacement, significant contaminants are not expected to be present in the test water. New pipe is expected to contain minimal manufacturing residue. 3.8 Right-of-Way Maintenance ROW maintenance was considered by the Service in Phase One of this consultation with the exception of one area, the Edwards Aquifer recharge zone; see Phase Two Project Documentation Appendix at Tabs 1 and 2. ROW maintenance in the recharge zone will be conducted in the same manner as described in the Phase One BA. In summary, the conservation measures described in the Phase One BA are designed to prevent disturbance of the earth, to preclude sedimentation, and to prevent the release or distribution of herbicides to the environment. 3.9 Corrosion Inhibitor The LC-50 concentrations of Magnacide 575 in the water column for freshwater fish and aquatic invertebrates ranges from 19.4 ppm (ml/I) (Daphnia- 48 hr) to 119 ppm (mg/l) (trout - 96 hr). Reproductive capacity diminution in Daphnia was demonstrated to have an EC-50 of 0.154 ppm (ml/l). No-effect concentrations for this product on fish and aquatic invertebrates was not available. LC-50 concentrations for dermal exposure to terrestrial mammals (rabbit) is 2000 ppm (mg/kg). Surface disturbance for the application of the corrosion inhibitor would be restricted to the seven valve setting sites previously noted. Access to those sites would be from public roads. The mixture ratio for the proposed inhibitor in the pipeline is approximately 3500 to 4000 ppm. These concentrations exceed the LC-50 for aquatic organisms, and are also above the lethal levels for terrestrial organisms. A release of this product in a surface tributary stream could be toxic until such time as dilution in the water body reduces the toxicity below limits. 99144ba2.v8 51 <<>> For listed species, the risk is believed to be very minimal. Terrestrial plants such as the Texas prairie dawn, Navasota ladies-tresses, and Tobusch fishhook cactus have very minimal exposure risk as spilled product on the ground would either be confined very quickly to topographically low areas or absorbed into the soil in a short distance from the pipeline. Surveys conducted for these plant species along the Longhorn ROW (Report of investigations - in progress) by Horizon in response to the requirements of the LMP did not reveal the presence of any individuals of these species within or near the ROW. The Houston toad would also be unlikely to be exposed to a spill if one occurs in Houston toad habitat areas. During the late summer period when the activity is proposed to occur, Houston toads are generally in estivation in deep sand burrows in uplands. Exposure to spilled product would be extremely low probability. Additionally, Houston toad surveys were conducted along portions of the line passing through the designated critical habitat for the Houston toad. No toads where found to occur within or adjacent to the ROW, or downstream (report in preparation). The only exposure avenue for the Barton Springs salamander would be entry of a large volume of the corrosion inhibitor directly into the Edwards Aquifer through a point recharge feature; however, the risk of a release of the corrosion inhibitor is demonstrably nominal as discussed in the following paragraphs. That the risk of a release of the inhibitor is low is based upon the fact that the inhibitor treatment water will be moved through the pipeline at pressures significantly lower than the pressure reached during the recently completed hydrostatic tests. The inhibitor will be propelled by nitrogen injected at a maximum pressure of 285 pounds per square inch gauge ("psig"). At the point of the inhibitor water batches, the pressure will range from approximately 65 psig to 140 psig. In comparison, the hydrostatic tests induced pressures ranging from approximately 1,100 psig to over 1,500 psig. Further, though some segments were not tested (22 miles across Buscher State Park in Bastrop County and 40 miles across the Edwards Aquifer recharge and contributing zones in Travis and Hays Counties), the hydrostatic test water was moved through those segments, and none was lost. The following table compares the minimum hydrostatic test pressures to the maximum treatment pressure. Corrosion Ratio Hydrostatic Inhibitor Hydrostatic Segment/Section' Minimum(psig)? Test Maximum(psig)3 Treatment Inhibitor Test to 2(1802+63 - 4024+50) 1265.0 285 4.4 3 (4024+50 - 5964+47) 1113.0 285 3.9 4-1 (5964+47 - 7110+81) 6504 285 2.3 4-2 (7112+16 - 8004+00) 1113.0 285 3.9 99144ba2.v8 52 <<>> Hydrostatic Corrosion Inhibitor Ratio Segment/Section' Minimum(psig)? Test Treatment Hydrostatic Maximum(psig) Inhibitor Test to 5 (8004+00 - 10163+00) 500° 285 1.8 6 (10163+00 - 12039+37) 1235.0 285 4.3 7 (12360+00 - 14597+72) 1265.0 285 4.4 8 (14606+00 - 16992+40) 1113.0 285 3.9 1 Segments shown are those with threatened or endangered species or habitat in proximity to the pipeline. The pressures shown are test target pressures for segments actually tested; all target pressures were met during the test. Nitrogen will be injected at 285 psig and therefore is used as the maximum; the pressures at the inhibitor batches will be lower, on the order of 65 to 140 psig; This section was not hydrostatic tested, but experience pressures as high as 650 psig (nitrogen) while adjacent sections were tested. This segment was not hydrostatic tested, but experienced pressures as high as 500 psig (nitrogen) while adjacent segments were tested. The above data demonstrate that treatment pressures will be significantly lower than were the hydrostatic test pressures. Since the hydrostatic test pressures were of such higher magnitude, and since the pipeline has been repaired at the few locations of hydrostatic test failures, the risk of a release is extremely low. In addition, regular, ongoing pipeline surveillance is monitoring activity near the pipeline to protect from third party damage that could threaten pipeline integrity. Furthermore, Longhorn will take measures to prevent a release of the inhibitor to the environment. Piping and materials management protocols that will be implemented serve to ensure that the inhibitor is controlled at all times. Nonetheless, spill equipment and supplies necessary to contain and immediately remove a release will be maintained along the pipeline segments as the treatment procedure progresses westward. Finally, a biologist will be maintained on stand-by during treatment across Bastrop, Travis and Hays Counties, in the event of a release that could affect the Houston toad or the Barton Springs salamander, to immediately advise response crews in release response and mitigation. Therefore, no adverse affects to the Barton Springs salamander would be expected. Exposure possibilities for the golden-cheeked warbler or black-capped vireo would be Studies for the presence of the warbler and vireo in the springs of 1999 and 2000 along the ROW did not reveal the presence of either bird species within or in close proximity to the ROW (report in progress). All ground activity associated with this process would be at previously disturbed valve setting locations, none of which are within or near listed species habitat. 99144ba2.v8 53 <<>> The recently completed hydrostatic testing has proven the Longhorn Pipeline to be sound. The corrosion inhibitor solution would be pumped through the pipeline at significantly lower pressures than the hydrotest. Little handling of material is required for the procedure. The risk of a significant spill or release of the inhibitor material in the environment is extremely low. Even if released, exposure or toxicity of the solution would not be significant for any of the listed species. 99144ba2.v8 54 <<>> 4.0 AVOIDANCE AND CONSERVATION MEASURES 4.1 Avoidance Longhorn will conduct pipeline operation, maintenance, construction, testing, and other subject activities in a manner that avoids potential effects to species and habitat. Controls and other measures designed to achieve that goal are described in the foregoing descriptions of the various activities. A number of those controls and measures are summarized as follows: • Full implementation of the Longhorn Mitigation Plan; • Identifying and marking habitat areas for avoidance; • Planning project implementation to avoid the potential for any effects; • Using FERC qualified environmental inspectors with authority to alter project implementation procedures in areas of potential concern to species, including application of incremental BMPs as a result of site-specific conditions; Adjusting project timing to avoid breeding populations; for example, maintenance or construction projects in Houston toad habitat will avoid the months of January through June and projects in golden-cheeked warbler and black-capped vireo habitat areas will be avoided from March 1 through August 1 and March 15 through September 1, respectively; Implementing storm water pollution control BMPs even when not required by permit; Maintaining qualified biologists in hydrostatic test project areas for immediate response in the event of a test water release in a habitat area; Avoiding work in areas of noise-sensitive species (i.e., golden-cheeked warbler and black-capped vireo) during the breeding/nesting season. If work must occur in habitat areas during noise-sensitive seasons, the Service will immediately be notified for additional avoidance procedures. Longhorn's Monitoring Commitment Longhorn has committed to survey the existing ROW to determine the presence/absence of listed species. The following summarizes the Longhorn Monitoring Commitment for each potentially affected species. • Longhorn has completed surveys for the Texas prairie dawn within the potentially suitable habitat areas to confirm its presence or absence. The surveys were conducted within the ROW in areas identified as potential habitat in early April of 2000 to determine if the Texas prairie dawn was present, and if so, its distribution and abundance. No prairie dawn were found, nor was any highly suitable habitat 99144ba2.v8 55 <<>> identified. Longhorn will conduct a fall survey (15 October to 15 November, 2000) for the Navasota ladies'- tresses within the ROW if suitable climatic conditions occur to determine the presence or absence of this species, and if present, its distribution and abundance. For the Tobusch fishhook cactus, Longhorn has conducted a blooming period survey (late February 2000) within the ROW throughout Kimble County to determine the species' distribution and abundance. No cacti were observed. • A spring survey for the Houston toad in Buescher Park was conducted along and downstream of the pipeline to determine the presence or absence of toads and their overall distribution and abundance. No toads were detected in the park. • One to two additional Spring breeding season surveys (as acceptable to the Service) will be conduced for the golden-cheeked warbler along and adjacent to the ROW within the potential habitat areas to determine habitat utilization and overall distribution and abundance. A survey for 2000 was conducted with no golden- cheeked warblers being found in or near the ROW. • One to two additional spring breeding season surveys (as acceptable to the Service) will be conduced for the black-capped vireo along and adjacent to the ROW within the potential habitat areas to determine habitat utilization and overall distribution and abundance. A survey for 2000 was conducted with no black-capped vireos being found in or near the ROW. 4.2 Status of the Species/Environmental Baseline The following is a review of the status of each species being considered in this biological opinion that may be adversely affected by the proposed action. The Service has reviewed the list of threatened and endangered species and identified potential impacts to the following species. Texas prairie dawn (Hymenoxys texana) - The Texas prairie dawn is a small, delicate annual to 6 inches tall with single or branching stems. It has small yellow flowers blooming in late March to early April. It occurs in sparsely vegetated areas of fine-sandy compacted soil. Specifically, the species occurs in the northern part of the Gulf Coastal Prairie in Harris and Fort Bend counties, where it is found in poorly drained depressions or saline swales around the periphery of low, natural mounds (mima mounds) in open grasslands. These mostly barren areas are sparsely vegetated, and the soil is often covered with a blue-green alga (Nostoc sp.). It can also occur on disturbed soils such as rice fields, vacant lots, pastures, and possibly pipeline ROW if the soil structure remains relatively intact. 99144ba2.v8 56 <<>> Kimble Hudspeth Hays • Gillespie ich occur. in counties traversed by Longhorn Pipeline Fayette Ector Page 1 of 2 Cootert Federally-listed Threatened or Endangered Species Blanco: RAD 39117 Species - Federal Classification American alligator: TSA Atwater's prairie-chicken - E Bald eagle - T(PDL?: Barton Springs salamander « Ei Ber Creek Cave harvestman E Bik-cooped vireo E Bone Cave harvestman E Clear Creek sambusia - E Comal Springs dryopid beetle - E Somal Springs diffle beetle - E Comanche Springs pupfish • E ild-buckwheat-T Devil's River Minnow. T rican spotted owe Te Footh Gave <<>> Known or Suspected to Occur Within Area of Potential Effect TSA - Listed Threatened Due to Similarity of Appearance O - Not Likely to Occur Within Area of Potential Effect M - Migrant Not Likely to be Adversely Affected ce of Species: US Fish and Wildlife Service PE - Proposed to be Listed as Endangered FEDERAL CLASSIFICATION PDL - Proposed to be De-listed E - Listed Endangered. T - Listed Threatened Ward Waller TABLE 4 Federally-listed Threatened or Endangered Species which occur in counties traversed by Longliorn Pipeline Upton Page 2 of 2 000z Schleicher Reeves: zOoO Reagan Menard Mason RAD 39118 Speciei - Federal Classificacion low flycatcher - E Smerkan Filigator - TSA Atwater's prairie-chicken • E bald eagle - T(PDL): Barton Springs salamander • E Bee Creek Cave harvestman: E Black capped vireo •E Bone Cave harvestman - E Clear Creek gambusia: E Comal Springs dryopid beetle • E Coral Springs riffle beetle • E Comanche Springs puplish • E Devil's River Minnow - T Fountan darter: E Solden-cheeked warbler - E m wild-buckwheat. T eschmar Cave mold beetle - E: Tooth Cave pseudose ooth Cive spider - E: a crane -E <<>> There are fewer than 35 known sites recorded for the species, and several have been lost in recent years to urbanization in the Houston area. Most populations remaining are small, and are on private land. Very few sites currently have any form of protection. The primary threat to the species is habitat destruction as a result of urbanization, roadway construction, and conversion of habitat for agricultural purposes. An assessment of potentially suitable habitat for the Texas prairie dawn was conducted by Horizon in early June 1999 along the Longhorn pipeline ROW in western Harris and eastern Waller counties from the Satsuma Station on the west edge of Houston to near Monaville in Waller County. Three areas along the ROW, one in Waller County and two in Harris County, exhibited native range conditions with suitable soils that could be considered potentially suitable habitat areas for the prairie dawn. All other areas along the pipeline within the area investigated had been converted to row crop (corn), monoculture hay or grazing pasture, or disturbed for land development. A survey for the prairie dawn has been conducted within the potentially suitable habitat areas during early April 2000 with negative results. Navasota ladies'-tresses (Spiranthes parksii) - The Navasota ladies' tresses was listed as endangered on May 6, 1982, without critical habitat. This member of the orchid family occurs primarily in moist, sandy soils in small openings in post oak savanna vegetation. The species is known to occur in Brazos, Burleson, Fayette, Freestone, Grimes, Jasper, Leon, Madison, Robertson, and Washington counties (USFWS 1984b). Currently, approximately 149 sites have been recorded, representing perhaps 75-80 distinct population areas, predominantly concentrated around two centers of distribution, one in southern Brazos County and one in central Grimes County. Some of these recorded sites have been damaged or destroyed since they were reported. Together these population centers contain the majority of known sites and individuals (Wilson 1993). However, the majority of sites contain fewer than 25 recorded plants. It is known that for this species not all individuals in a population are visible above ground in a given year, and most of these sites have been visited only once, so demographic data on populations is very limited. Nevertheless there is great concern among botanists that most of these sites may not represent viable populations. Navasota ladies'-tresses occur in a variety of moist sandy soils near drainages, in the Post Oak Savannah vegetation associated with the Navasota, Brazos, and Trinity River watersheds. Navasota ladies'-tresses are typically found on erosional remnants between rills in slightly to moderately eroded areas along minor intermittent tributaries, from the upper drainage head, extending along the edges of temporary streams to the flood plain of permanent streams. Navasota ladies-tresses grow on sandy loam soils and are often associated with post oak, blackjack oak, yaupon, slender bigelowia (Bigelowia nuttalli), and Spiranthes cernua. Typical habitat consists of natural openings in upland Post Oak Savanna vegetation (Poole and Riskind 1987, USFWS 1984b, Wilson 1993). Plants are believed to be situated where subsurface flow or seepage of water occurs seasonally, a common feature in other species of the genus (Arft and Ranker 1995, Kathy Parker, pers. comm.). While Navasota ladies'-tresses is found in small naturally created openings in the post oak woodlands, it cannot be regarded as a disturbance species, as it usually occurs in 99144ba2.v8 59 <<>> well developed woodland and is not a colonizer of extensively disturbed areas. There are few records in flood plain forests, open savannahs and shrublands that have experienced little or no grazing pressure, and in hillside seepages. Navasota ladies'-tresses is extremely slow-growing and long-lived. Rosette leaves support the formation of a storage tuber between November and March that sequesters resources in preparation for sending up a leafless bloom stalk at some future time. It is believed that often plants require more than one year of photosynthate storage to successfully send up a bloom stalk. If local conditions have not been favorable for forming sufficient below ground reserves, the plant may not bloom (Wilson 1993). Navasota ladies'-tresses apparently does not transplant well. In a mining project in Grimes county by Texas Municipal Power Association (TMPA), plants in the impact area were removed and transplanted into an adjacent habitat area. Plant survival has been low in most sites (TMPA 1996). Similarly, in an experiment in Lick Creek Park near College Station, Dr. Hugh Wilson planted some seedlings which survived into their second season, but died prior to the third growing season (Wilson 1993). Because of the low numbers of individuals reported from populations, the slow growing nature of the plants, its unusual habitat requirements of openings in mature vegetation, and its sensitivity to disturbance and transplanting attempts, the species is not regarded as being very resilient, and recovery following any damage to a population is expected to be slow. The primary threat to Navasota ladies'-tresses is destruction or modification of habitat due to urbanization, clearing for agricultural production, or mining (47 FR 19539, USFWS 1995, 1984b). Destruction of understory by feral pigs is also a problem in some areas. More than 40 known sites have been lost in the last ten years to mining or urbanization. Post oak savannah in many of these counties continues to be converted to bermuda grass pasture. Subsequently, habitat loss continues, particularly in the areas of Brazos and Grimes counties where most sites are located. The City of College Station in Brazos County is growing rapidly, particularly in the southern and southeastern fringes where most known populations are located. Mining in Grimes County disturbs more than 7,000 acres every 5 years (Wilson 1993). In Fayette County, the species is known from one small population approximately 6 miles south of the pipeline and 2 miles north of the town of Fayette. Based on analysis of soil distribution, vegetative cover, physiographic setting, and field assessment by Horizon in November of 1999, two small areas of potential habitat for Navasota ladies'-tresses are present along the pipeline corridor. Surveys for the species are scheduled to be conducted along the pipeline in October 2000 if suitable climactic conditions occur. Tobusch Fishhook Cactus (Ancistrocactus tobuschii) - Tobusch fishhook cactus is a rounded, biscuit-shaped cacti usually 2 to 3 inches tall and up to 3.5 inches in diameter. There are 3 to 5 central spines with the upper 2 to 3 erect and straight and the lower central spines hooked at the tip and spreading. The plants are very inconspicuous, and produce cream to yellow flowers from February through early April. These cacti have been demonstrated to be obligate outcrossers pollinated by native bees with a foraging distance of about 1/4 mile, and seeds are dispersed by native ants. 99144ba2.v8 60 <<>> Currently about 50 sites are recorded for the species, following a recent range-wide representative survey. Most of the populations are extremely small (5-20 plants), with individuals widely scattered. Known sites are separated by large distances. Most existing populations are on private land, and there are very few protected sites. Demographic data collected in monitoring studies over the last five years or so show that only one of the known populations is even marginally viable. The species is extremely slow growing and does not appear to reproduce until 10-17 years of age. It takes four successful flowers/fruits to produce one seedling (Jackie Poole, Texas Parks and Wildlife, pers. comm.). It is estimated that very few viable populations (10-15) remain over the 8 county range of the species. The survival and recovery of the species will require restoration and careful management, to provide sufficient numbers of populations and individuals in effective proximity to each other for successful pollination (and gene flow) to ensure the continuity of the species. Studies examining the probable reasons for population declines are underway. Threats to the species are believed to include inappropriate timing of range management practices (such as fire and clearing practices that disturb the soil), extensive predation by beetle grubs, loss of habitat to real estate development, and some collection by cactus enthusiasts. An assessment of potentially suitable habitat and pedestrian survey for the cacti was conducted by Horizon in April 1999 along portions of the Longhorn pipeline ROW in Kimble County, and no specimens were observed within the ROW. However, one Tobusch fishhook cactus was observed about 50 feet north of the cleared ROW. An additional survey of the entirety of the ROW through Kimble County was conducted by Horizon in late February 2000 with negative findings for the cactus. However, as a conclusion of the Phase One consultation, in the absence of complete surveys at that time, all of the ROW within Kimble County was considered as potentially suitable habitat and fully compensated. Golden-cheeked Warbler (Dendroica chrysoparia) -The golden-cheeked warbler is a small, migratory songbird, 4.5 to 5 inches long, with a wingspan of about 8 inches. The male has a black back, throat, and cap, and yellow cheeks with a black stripe through the eye. Females are similar, but less colorful. The lower breast and belly of both sexes are white with black streaks on the flanks. Typical nesting habitat is found in tall, dense, mature stands of Ashe juniper (cedar) mixed with trees such as Texas (Spanish) oak, Lacey oak, shin (scalybark) oak, live oak, post oak, Texas ash, cedar elm, hackberry, bigtooth maple, sycamore, Arizona walnut, escarpment cherry, and pecan. This type of woodland generally grows in relatively moist areas such as steep-sided canyons and slopes. A mix of juniper and deciduous trees on the slopes, along drainage bottoms, and in creeks and draws provides ideal vegetation for birds. Warblers are also occasionally found in drier, upland juniper-oak (i.e., live oak, post oak, blackjack oak) woodlands over flat topography. 99144ba2.v8 61 <<>> An assessment of potentially suitable habitat and surveys for the golden-cheeked warbler was conducted by Horizon in April and May 1999 along the Longhorn pipeline ROW from Austin, Texas, to the Mason/Kimble County line. Although no potentially suitable habitat areas were observed within the Longhorn ROW, several areas were located adjacent to the previously cleared permanent ROW. All areas were surveyed by Horizon a minimum of 5 times during April and May on days with favorable weather conditions for bird activity, per U.S. Fish and Wildlife Service guidelines (USFWS, 1994a). Surveys were conducted on 8, 9, 12, 27, 28 April, and 3, 11, 19 May. An equivalent of 4 person-hours per 100 acres were spent at each site, based on habitat size. No golden-cheeked warblers were found to be utilizing any of the potentially suitable habitat areas on or immediately adjacent to the ROW. However, three years of survey are necessary to confirm presence/absence under Service guidelines (USFWS 1994a). Additional surveys for the warbler are under way for the Spring of 2000. Black-capped Vireo (Vireo atricapillus) -The black-capped vireo is a 4.5 inch long, insect-eating songbird. Mature males are olive green above and white below with faint greenish-yellow flanks. The crown and upper half of the head is black with a partial white eye-ring. The iris is brownish-red and the bill black. The plumage of the female is duller than the male. Females have a dark slate gray head. In Texas, vireo habitat is found on rocky limestone soils of the Edwards Plateau, Cross Timbers and Prairies, eastern Trans- Pecos, and, to a limited extent, on igneous soils in the Chisos Mountains. Black-capped vireos require shrub vegetation reaching to ground level for nesting cover. They typically nest in shrublands. An assessment of potentially suitable habitat and surveys for the black-capped vireo was conducted by Horizon in April and May 1999 along the Longhorn pipeline ROW from Austin, Texas to Crane County. Potentially suitable habitat areas were observed within the Longhorn ROW as well as several areas located immediately adjacent to the previously cleared permanent ROW. All areas were surveyed by Horizon a minimum of 5 times during April and May on days with favorable weather conditions for bird activity, per Service guidelines (USFWS, 1994a). Surveys were conducted on April 8, 9, 12, 27, 28, and May 3, 11, and 19. An equivalent of 4 person-hours per 100 acres were spent at each site, based on size. No black-capped vireos were found to be utilizing any of the potentially suitable habitat areas on or immediately adjacent to the ROW. However, three years of survey are necessary to confirm presence/absence under Service guidelines (USFWS 1994a). Additional surveys for the vireos are under way for the Spring 2000. Bald Eagle (Haliaeetus leucocephalus) -The bald eagle is a migrant and winter resident in Texas. The bald eagle was recently down-listed from endangered to threatened due to successful conservation efforts and is now proposed for de-listing. Migrating and wintering bald eagles typically arrive in Texas in November and depart around February. They are found primarily in association with reservoirs, rivers or other large bodies of water where they feed on fish, carrion, and waterfowl. Nesting bald eagles in Texas are found in the eastern portion of the state and along the coastal plain as far south as Calhoun and Refugio counties. No bald eagle nests have been identified near the pipeline ROW, however, bald eagles may occur along major waterways (Brazos and Colorado rivers, or major tributaries with impoundments) downstream of the pipeline corridor. The Federal Register, (Volume 64 No. 128, Tuesday, July 6, 1999; Page 36454) contains a proposed rule to remove the bald eagle from the List of Threatened and Endangered Wildlife in the 99144ba2.v8 62 <<>> Lower 48 States of the United States. Formal delisting is now anticipated to occur in July 2000. Interior Least Tern (Sterna antillarum athalassos) - Premier nesting sites for the interior least tern are salt flats, broad sandbars, and barren shores along wide, shallow rivers. Important breeding habitat characteristics include: (1) presence of bare or nearly bare ground and alluvial islands or sandbars for nesting; (2) availability of food (primarily small fish); and (3) favorable water levels during the nesting season (so nests remain above water). They usually nest on sites devoid of vegetation, but have been found in areas with an average of 11 to 30% vegetative cover, composed of grasses, shrubs, and trees and ranging from 1 to 3 feet in height. Vegetation, if present, is usually located well away from the colony, with the exception of bugseed, eastern cottonwood, and sandbar willow. As natural nesting sites have become sparse, birds have used sand and gravel pits, ash disposal areas of power plants, reservoir shorelines, gravel levee roads, and other manmade sites. The typical nesting period for the least tern in Texas is mid-April to mid- August. While the interior least tern has not been documented along the pipeline corridor, potential habitat for the tern is present downstream of the pipeline along several major waterways including the Brazos, Colorado, Llano, and James Rivers, and Squaw, Beaver, and Sandy Creeks. The seasonal occurrence (Spring and Summer) and potential nesting of least terns is possible in these areas. Barton Springs Salamander (Eurycea sosorum)- The Barton Spring Salamander was listed as endangered in 1997, without critical habitat. The Barton Springs Salamander belongs to a group of related salamanders that are endemic to the Edwards Plateau region of central Texas. All members of this group are obligately aquatic because the adults retain the larval, gill-breathing morphology throughout their lives. The Barton Springs Salamander, formally described in 1993, was first collected from Barton Springs in 1946 and has been found only at the four hydrologically connected outlets of Barton Springs in Zilker Park within the City of Austin (Brune, 1981; Chippindale et. al., 1993). This salamander is a small species, adults reaching 2.5 inches (about 68 mm) in total length with reduced eyes and elongate, spindly limbs indicative of a semi-subterranean lifestyle. Barton Springs Salamanders are found in the flowing, thermally constant water issuing from the spring outlets in association with aquatic macrophytes, leaves and organic debris, and gravel and rock substrates having little silt and sediment deposition. Water from the contributing and recharge zones of the Barton Springs segment of the Edwards Aquifer influences the conditions at Barton Springs. The main threat to the species has been identified as degradation of water quality from future growth and development on the Barton Springs segment of the Edwards Aquifer (Federal Register 62:23385). An expanded discussion of the environmental baseline for the salamander is provided in the Project Documentation Appendix at Tab 22. Houston Toad (Bufo houstonensis) - The Houston toad was listed as endangered in 1970 (Federal Register, October 13, 1970) and Critical Habitat was designated in Bastrop and Burleson counties in 1978 (Federal Register, January 31, 1978). Houston toads are generally brown and speckled, although individual toad coloration can vary considerably. Some may appear light brown, others almost black and they may also have a slightly reddish, yellowish, or greyish hue. Two dark bands extend down from each eye to the 99144ba2.v8 63 <<>> mouth. Their legs are also banded with darker pigment. A variable white stripe streaks along the sides of the toad's body. Their undersides are usually pale with small, dark spots. Males have a dark throat which appears bluish when distended. Adult Houston toads are 2 to 3.5 inches long and like all toads, are covered with raised skin patches that contain chemicals that make the toad distasteful and sometimes poisonous to predators. The toad was eliminated from three counties (Harris, Fort Bend, Liberty) prior to the 1970s due to habitat loss resulting from urban expansion. Although Houston toad populations have been found in nine other counties (Austin, Bastrop, Burleson, Colorado, Lavaca, Lee, Leon, Milam, Robertson), the Service is concerned about the long-term viability of these populations. The small population in Lavaca County has not been seen since its discovery in 1991; the population at the critical habitat site (Woodrow Lake) in Burleson County has not been seen since 1983; and the population in Leon County lies within an expanding residential area. The largest known population of Houston toads occurs within the pine/oak woodland region of Bastrop County. This area also contains federally designated critical habitat. All known Houston toad populations occur along bands of geologic formations that support deep sands. Six populations occur on a band running through Bastrop County northeast to Freestone County. Three other populations occur on another band through Lavaca, Austin, and Colorado counties (USFWS, 1994b). Houston toad habitat consists of rolling uplands characterized by pine and/or oak woodlands (loblolly pine, post oak, blackjack or sandjack oak) underlain by pockets of deep, sandy soils. Because their skin is semi-permeable to water, Houston toads become dormant to escape harsh weather conditions, such as winter cold (hibernation) and drought (estivation). They seek protection during this time by burrowing into sand or hiding under rocks, leaf litter, logs or in abandoned animal burrows (TPWD, 1993). Although Houston toads are typically associated with woodland habitat, they also breed in and migrate across sparsely wooded and cleared areas near woodlands. They may also breed in and traverse areas that do not support deep sandy soils, including clay and gravel substrates, provided these areas are near woodlands underlain by pockets of deep sandy soils. Houston toads breed from January to June, with a peak in February and March. During the breeding season, toads appear to move randomly from one breeding site to another, achieving genetic transfer between populations that may appear isolated, thus creating a metapopulation, an aggregation of smaller populations linked genetically demographically and functioning almost as a single population. Presently, the most reliable breeding sites are stock ponds and similar impoundments, though in wet years breeding may occur wherever sufficient standing water is present. For successful breeding, water must persist for at least 30-60 days to allow egg hatching, tadpole maturation, and emergence of toadlets. Mortality in young is high, due to predation and drying of breeding sites, with significantly less than one percent of eggs laid believed to survive to adulthood (USFWS, 1984a, 1994b, 1995). The Houston toad is vulnerable to extinction primarily due to habitat loss, degradation, and fragmentation. Over the last 50 years, the historic range of Houston toads has contracted and several populations have been lost. Threats include expanding urbanization and conversion of woodlands to agricultural production areas, such as coastal bermuda pastures, use of fertilizers and pesticides that impact the toad directly or its food supply, 99144ba2.v8 64 <<>> and loss of suitable breeding habitat because of alterations in watershed drainages and wetland alterations or destruction (such as degraded water quality, draining/filling of wetlands, stocking with predatory fish, etc.). Since Phase One of the Longhorn Pipeline project involved the continuation of maintenance activities rather than new clearing or development, and minimization of these continuing maintenance activities included long-term habitat protection for the Houston toad, the • Service concluded that Phase One of the project would provide a net conservation benefit for this species. According to the Houston Toad Recovery Plan (USFWS 1984a), Houston toad breeding sights have been recorded in Buescher State Park south of Longhorn Pipeline. Houston toads have also been heard chorusing on the adjacent property owned by the University of Texas to the north of Buescher State Park and Longhorn Pipeline (USFWS, unpublished data). Dr. James R. Dixon of Texas A&M University conducted a survey along the Longhorn Pipeline ROW and adjacent Phillips EZ Pipeline ROW in 1991 with negative results, although areas of potential habitat were noted (Horizon 1991). Horizon Environmental Services, Inc. conducted a reevaluation of suitable habitat along the Longhorn Pipeline ROW within Bastrop County. The field reconnaissance was conducted on 2 June 1999 from the Colorado River, southeast of Bastrop, to FM 2104. Portions of the area along the pipeline had recently been cleared and planted in improved grasses. Based on field observations and discussions with the Service, two areas of suitable habitat were identified along and adjacent to the pipeline ROW. One area includes Buescher State Park from approximately 0.5 mile east of the eastern boundary of the park westward to near Highway 71. The second area begins about 500 feet to the west of FM 2104 and extends westward approximately 0.75 mile. The drainages in both of these areas flow south toward the Colorado River. A breeding season survey of the habitat areas in Buescher State Park has been conducted by Horizon during February and March of 2000 with negative results. Comanche Springs Pupfish (Cyprinodon elegans) - The Comanche Springs pupfish seldom exceeds 2 inches in total length. It is gray-green above and pale yellow to white below, with clear to light orange fins. The sides are silvery white with blue-black blotches forming a "stripe" along the side (often faint on the male). Males have black speckling on the side and a black edge on the caudal (tail) fin. Historically, this pupfish occurred in 2 separate spring systems of the Pecos River drainage. One was Comanche Springs, with headwaters (now almost always dry) within the city limits of Fort Stockton, Texas, and the other was a group of springs near Balmorhea. The pupfish population at Comanche Springs were extirpated (lost) when the springs first went dry in 1955. At present, the species occurs primarily in aquatic habitat fed by springflow from Phantom Lake, Griffin, and San Solomon Springs near Balmorhea, Texas. The Longhorn Pipeline is not within the sub-watersheds of these springs where the pupfish occur and groundwater contamination from product releases that would affect the springs is extremely unlikely (Dr. Charles Kreitler, personal communication). Therefore, this species is not likely to be adversely affected, but is addressed herein for information purposes only. Pecos Gambusia (Gambusia nobilis) - The Pecos Gambusia is a small (2-inches long), live-bearing fish with a dark lateral stripe and a metallic gray-blue color. Females have a 99144ba2.v8 65 <<>> black area on the abdomen that surrounds the anal fin and anus. The anal fin of males is modified into a gonopodium, a tube-like structure used in fertilization of the female. Historically, the Pecos Gambusia was restricted to the Pecos River basin in southeastern New Mexico and western Texas. The species occurred from as far south as Fort Stockton, Texas to as far north as Fort Sumner, New Mexico. The populations of Pecos Gambusia that once existed at Leon Spring and Comanche Springs were lost when these springs went dry during the mid-1950s. Presently in Texas, populations of the Pecos Gambusia occur near Balmorhea in aquatic habitat supported by springflow from Phantom Lake, Griffin, San Solomon, and East Sandia Springs. A substantial population also occurs in Leon Creek and in Diamond-Y Spring outflow north of Fort Stockton. The species also occurs in a limited number of locations in New Mexico. The Longhorn Pipeline is not within the sub-watersheds that support the Pecos Gambusia and groundwater contamination that would affect any of the spring habitats is extremely unlikely (Dr. Charles Kreitler, personal communication). Therefore, this species is not likely to be adversely affected, but is addressed herein for information purposes only. Devils River Minnow (Dionda diaboli) - The Devils River minnow is a small fish, with adults reaching sizes of 1.0 to 2.1 inches standard length. The fish has a wedge-shaped caudal spot and pronounced lateral stripe with double dashes extending through the eye to the snout but not reaching the lower lip. The species has a narrow head with prominent dark markings on scale pockets above the lateral line that produce a crosshatched appearance when viewed from the top. General habitat associations for Devils River minnow have been described as channels of fast-flowing, spring-fed waters over gravel substrates. Although the species is closely associated with the stream, rather than in the spring outflow itself. The known historic range of the species includes the Devils River from Beaver Lake downstream to near its confluence with the Rio Grande and four other tributaries of the Rio Grande River not associated with the Devils River. The current distribution of Devils River minnow is at 2 sites on the Devils River, 2 sites on San Felipe Creek, and 1 site on Sycamore Creek (US Fish and Wildlife Service, 1998). The Longhorn Pipeline ROW crosses the northern most extent of the Devils River watershed, in excess of 100 river miles upstream from known populations of the minnow. At this distance, it is unlikely that released product would reach the population areas of the minnow in quantities to be toxic (James Miertschin, personal communication). This species is also unlikely to be adversely affected, but is included herein for informational purposes. Southwest Willow Flycatcher (Empidonax trailii extimus) - The southwest willow flycatcher occurs in riparian woodlands along streams and rivers in Hudspeth, Culberson, and El Paso counties. Specific localities of this species in the vicinity of the pipeline are not known. It is possible this species could occur along the Pecos and Devil's rivers downstream of the pipeline. This species would not likely be directly affected by any activitiy associated with the pipeline. However, this species utilizes riparian woodlands that could be affected by a major release of product in a waterway. The methods for assessment of such a potential, but unlikely, event are addressed in section 3.4. 99144ba2.v8 66 <<>> 4.3 Effects of the Actions Pipeline Operation Normal operation of the pipeline is not expected to result in any adverse effects to listed species. There is a risk of an accidental release from the pipeline-a risk Longhorn has significantly minimized through various pipeline mitigation measures. Many of these pipeline mitigation measures were developed directly as a result of consultation with the Service, in order to significantly minimize the risk of a spill near listed species, such as the pipe replacement in Buescher State Park and the replacement of 19 miles of pipe over the Edwards Aquifer recharge and contributing zones. The occurrence of a pipeline release is so unlikely as to be improbable; see APR report, Project Mitigation Appendix at Tab 10. Recognized pipeline experts have concluded that the implementation of the LMP will enable the Longhorn Pipeline to operate at the highest reasonable level of safety attainable by current technology; see APR report at Tab 10 of the Phase Two Project Documentation Appendix. Kiefner & Associates, Inc. (Kiefner) performed an audit of the Longhorn pipeline segment between Houston and Crane (Tab 23 in the Phase Two Project Documentation Appendix). Keifner concluded that the pipeline was safe to operate, even prior to the EA, so long as certain recommendations were followed. Longhorn has committed in the LMP to implement all of Kiefner's recommendations. Kiefner further reported on the safety of the pipeline system as it will stand after implementation of all EA pipeline mitigation measures. Among Kiefner's conclusions: Hydrostatic testing is the most important and positive way of proving that a pipeline is fit for service; the 2000 hydrostatic and proof testing will remove any doubts about the remote possibility that defects may have arisen since the 1995 hydrostatic test • After the pipeline is placed into service, better technology than hydrostatic testing will be used to assure that no defect develops or grows in service to the point where a service failure results • "Smart-Pig" technology will be utilized by Longhorn to locate and characterize anomalies that may represent... time-dependent developing defects Longhorn has taken the unprecedented step of committing to limit surge pressures to no more than the maximum allowable operating pressure (MAOP) in sensitive and hypersensitive areas... providing an extra margin of safety in the critical areas Longhorn's pipeline surveillance programs will "go a long way" to preventing excavation or construction activities from encroaching on the pipeline and possibly damaging it The new pipe in the Edwards Aquifer recharge zone "reduces the already low risk of failure from corrosion and excavation damage," providing an extra margin of safety • "The proposed operation of the pipeline does not create in my opinion, an 99144ba2.v8 67 <<>> unreasonable risk" See Kiefner & Associates, Inc., January 13, 2000, Phase Two Project Documentation Appendix at Tab 23. Further, APR Companies, a company that specializes in pipeline accident investigation, has concluded that the Longhorn Pipeline will benefit from a significant reduction in release probability; see Phase Two Project Documentation Appendix at Tab 10. APR (reference Tab 10 in the Phase Two Project Documentation Appendix) has determined that the average probability of a release (1 in 1000 years per mile) is significantly improved for the pipeline in general through implementation of the LMP with a resulting 2 to 5 times reduction in spill probability. For the Edwards Aquifer recharge zone, the likelihood of a release is reduced 5 to 10 times with implementation of extensive LMCs for that area. A resulting probability for a release then becomes 1 in 5,000 to 10,000 years per mile. APR further estimates the potential worst-case spill scenario for the Edwards Aquifer recharge zone. An earlier estimate approximated 5000 barrels of product released in a major incident. Placement of a single check valve at or near mile post 171 within the recharge zone limits the maximum line fill volume that could spill to 2088 barrels. However, APR's analysis also takes into consideration other factors that influence line drain down such as intervening topographic lows that will hold pipeline contents. Based on detailed analysis of the topography along the line through the recharge zone, and average per unit line drain downs from independent statistics, the probable worst-case spill volume would be only about 1147 barrels in 90% of the potential spill scenarios and 841 barrels in 75% of potential spill scenarios. Longhorn nonetheless has designed the replacement pipeline and emergency response capability on the basis of unqualified worst case release volumes. LBG-Guyton (reference Tab 16 in the Phase Two Project Documentation Appendix) has developed a risk analysis for the Barton Springs Salamander based on the probable worst- case spill volume combined with the measures to be implemented to prevent or minimize released product entry to the aquifer, such as sealing voids in the pipeline trench and grading surface drainage within the ROW to direct any surface flow away from identified point recharge features. Bermed areas at lower elevations will serve to capture product that reaches the surface in those low areas. Their analysis concludes that product concentrations that might reach the aquifer, and ultimately Barton Springs, would be on the order of 0.2 to 0.002 ppb. Concentrations in the water column would be even less (in the absence of MTBE; see Kreitler at Tab 16 and LMC 35). These levels are at nearly an order of magnitude lower than measured levels of petroleum hydrocarbons found in the aquifer and at Sunken Gardens Spring in the past (see Tab 22 in the Phase Two Project Documentation Appendix). Biotoxicological information assembled from existing literature and agency file sources for salamanders (and other aquatic vertebrates), and their prey base (aquatic invertebrates), indicate that concentrations of toxic product constituents (BTEX) in the water column in the ppb range are generally below the "no effect" levels for most organisms (Horizon, 2000). From the above analysis, levels of benzene reaching the springs would be in the 0.010 ppb 99144ba2.v8 68 <<>> (ug/l) range, while toluene would be in the 0.014 ppb range. Horizon reports that EPA data indicate acute toxicity to freshwater aquatic life, for benzene, occurs at about 5,300 ug/l (ppb), while for toluene, the acute toxicity level is about 17,500 ug/ (ppb). The EPA information notes that more sensitive species would have lower acute toxicity levels. However, from the available information, concentrations reaching the springs under the above scenarios would conservatively be several orders of magnitude lower than toxic concentrations. The LBG-Guyton analysis assumes that all or most of the probable worst-case spill volume would reach the aquifer. From prior spill experience with the Longhorn (under previous ownership) and Shell pipelines over the aquifer (1986 and 1987 incidents), 91 to 97 percent of the spilled product (west Texas crude with a similar viscosity to some refined products) was recovered at the surface. Those recovery volumes were in the absence of the void sealing and surface contouring Longhorn will implement to further enhance product recovery. Furthermore, modeling analyses by Rose (1986) and Ross (2000) indicate that soil retention capacity of spilled petroleum product over the Edwards Aquifer recharge zone would be in the range of 350 to 1600 barrels if spread over a 1 to 2 acre area with average soil depth of 0.33 to 1.5 feet. This absorption capacity, combined with high evaporation rates for refined products, and the potential for high levels of product recovery would significantly, if not totally, reduce or eliminate the quantity of product that might reach the aquifer, and ultimately Barton Springs. The 1986 and 1987 incidents resulted in spills of 2245 barrels and 1139 barrels, respectively (in the absence of a block valve). The 1986 spill resulted in hydrocarbon fumes in caves in the vicinity, but no documented adverse effects to the salamander or the aquifer. Under the above-described scenario of a probable worst-case spill for the Longhorn Pipeline (with extremely low probability of occurrence), it is unlikely that adverse effects to the salamander would result as a result of the enhanced Longhorn mitigation measures. In addition to those facets of system operation that limit potential consequences by minimizing release volumes and ensuring a rapid and effective response to a release, Longhorn's emergency response capability will be increased significantly through the LMP. Longhorn will ensure a maximum response time (a) of 1 hour in the recharge zone and Slaughter Creek watershed in the contributing zone; (b) in the Barton Creek watershed in the contributing zone and in other EA designated sensitive and hypersensitive areas of 1 hour to 2 hours; Longhorn will provide for the establishment of a response center in Central Texas, to be located in South Austin, to make certain that manpower and equipment is always at the ready. Prior experience has demonstrated an average response time of 58 minutes (see Tab 24 in the Phase Two Project Documentation Appendix). Once on-scene, the response crews will have the advantage of thorough and detailed information relating to any area along the pipeline. Longhorn has commissioned the preparation of detailed studies of numerous facets of the pipeline ROW, and surrounding areas, to prepare its response crews in advance, if ever necessary. The information developed and advantages gained as a result of the studies includes the following: Species habitat: Response personnel will have the information necessary to avoid 99144ba2.v8 69 <<>> species habitat areas during response and prioritize protective activities in the event of a release in or near a habitat area • Topography: Advance knowledge of area topography allows advance planning for both release drainage potential and control and capture locations • Rivers and streams: Detailed planning has identified waterways at risk and advantageous protective and control locations • Water wells: Both public and private wells are mapped so that responders may prioritize drinking water supplies for protection • Known karst features: Particularly within the Edwards Aquifer recharge zone, advance knowledge of karst features provides information that allows responders to prioritize protection of the aquifer and thus the Barton Springs Salamander • Surface drainage potential: Flow modeling provides knowledge of the potential for released product to flow overland, enabling responders to identify likely scenarios relating both to habitat areas and to human health and safety issues; responders will also have the ability to identify preemptive control and capture locations; surface containment systems are designed to capture any release that reaches the ground surface Longhorn has synthesized this information into stand-alone maps (See Project Documentation Appendix) and in its FRP; further, responders will be trained to use such information during training and during table-top and live drills. Where a potential release might affect listed species or habitat, the precise level of impact cannot be predetermined due to the large number of variables at any given location. As a result, any such attempt at prediction is likely to result in an inaccurate estimate. Accordingly, Longhorn proposes to adopt a contingent methodology for calculating any such effects. This methodology should be useful in the event there is a release from the Longhorn pipeline but neither the Clean Water Act nor the Oil Pollution Act applies to the incident. In such a case, and if Longhorn is liable for the damage, Longhorn will use the Habitat Equivalency Analysis methodology to determine the amount of compensation for which Longhorn is responsible. Longhorn proposes using a methodology that is capable of assessing natural resource damages, preferably the Habitat Equivalency Analysis (HEA) methodology developed by the National Oceanic and Atmospheric Administration (NOAA). HEA is briefly described below. A more detailed description of the HEA methodology is provided in Phase Two Project Documentation Appendix at Tab 25). Pursuant to the HEA methodology: • The duration and extent of injury are documented and estimated from the time of injury until the resource recovers to baseline. 99144ba2.v8 70 <<>> • The services provided by a compensatory project are documented and estimated over the full lite of the project. • The size of a compensatory project is calculated such that the total increase in services provided by the compensatory project equals the total interim loss of services due to the injury. • The cost of the compensatory project is calculated. Other methods exist for assessing natural resource damages under NOAA's regulations governing Natural Resources Damages Assessments for oil spills pursuant to the Oil Pollution Act of 1990 (OPA). 33 U.S.C. § § 2701 et seq. These methodologies may prove more cost-effective than the HEA method and should be considered as well. In the event of an accidental release from the pipeline in or near habitat for listed species, an adverse effect could occur. The level of potential take is impossible to predict in advance. Long-term Maintenance In general, most long-term maintenance is unlikely to result in any adverse effects to listed species beyond those addressed in the Phase One consultation. The majority of long-term maintenance involves ROW maintenance, above-ground facility upkeep, and periodic pipeline testing. These activities were addressed in the Phase One consultation and compensated accordingly. Certain maintenance activities may, however, require construction or land disturbance beyond the existing ROW. Such events are not presently determinable. In the event any such maintenance should necessitate access or construction within listed species habitat, the previously utilized Phase One BA maintenance construction procedures (see •Phase One BA in the Phase Two Project Documentation Appendix at Tab 1) will be followed under the direction of FER qualified environmental inspectors. To the extent feasible, all construction activity will be restricted to the existing ROW within habitat areas, which was fully compensated during Phase One of this consultation. If construction must exceed the ROW in an area of potential habitat, the Service will be notified in advance and additional compensation, as required, will be calculated and provided pursuant to the conditions set forth in the Phase One BA for the given species, to the extent a specific location has not previously been compensated for off-ROW impacts. An additional area of potential Houston toad habitat has been identified in Austin County since the Phase One consultation was completed. This habitat area is within the geologic formation known to support two small Houston toad populations in Austin County approximately 8 miles south of the pipeline corridor and other small populations in Colorado and Lavaca counties further to the south. This area is characterized as patchy woodlands approximately 3000 acres in extent surrounded and interspersed by improved grazing pastures, and with marginally suitable soils (loamy fine sands less than 24 inches deep) (SCS, 1984). The known populations of toads occur in the Catilla-Tremona soil association which is comprised predominantly of sandy soils (SCS, 1984). The potential habitat area 99144ba2.v8 71 <<>> occurs in the Tabor-Tremona-Chazos association which is comprised of loamy and sandy which are not favorable for Houston toads (SCS, 1984). Surveys of this area for the soils. The two associations are separated by several miles of clayey and clayey loam soils Houston toad are not known to have been conducted in the past. A breeding season survey is planned for spring of 2001. The pipeline ROW through this area traverses approximately 12,000 linear feet (2.3 miles). The existing 50 ft wide ROW, therefore, occupies 13.8 acres. This area could be adversely affected by maintenance of the ROW and is being addressed through the Phase One consultation. Emergency Response Potential impacts from an emergency response action could be highly variable depending on location, season, site characteristics, spill characteristics, and type of equipment needed to respond to a particular situation. Training of emergency response personnel will be conducted to make them aware of species related issues, designated potential habitat areas, and avoidance procedures. Avoidance of impacts will be achieved to the greatest extent possible under any given emergency situation. However, control and containment of a product release or fire will constitute a priority, and some level of impacts to designated potential habitats could occur. Impacts could occur from clearing or grading to gain access for emergency response equipment, building temporary containment structures outside of the established ROW, or to remove contaminated soil and vegetation. If fire containment is necessary, fire breaks may need to be dozed in advance of a fire. These activities could result in direct or indirect impacts to potential habitat Such impacts would be assessed and mitigated in the same manner as described previously under the Pipeline Operation section above. Construction Buescher State Park (Houston Toad): Construction of the replacement and lowering projects within Buescher State Park will be contained within the existing 50 ft ROW, and/or within the previously cleared ROWs of the other two adjacent pipelines. No clearing beyond the limits of the existing ROWs will be conducted. Compensation based on the extent of existing Longhorn ROW through Houston toad habitat was provided in the Phase One consultation. Therefore, no additional impacts or compensation are required for this construction. A breeding season survey for toads in the vicinity of the pipeline has been completed, and no toad breeding activity was identified. However, special procedures will be implemented for avoidance prior to and during construction to ensure no adverse effects occur to the toad. Prior to any land disturbance, the construction zone will carefully be inspected by qualified biologists to ascertain the possible presence of Houston toads. The construction zone will then be completely encircled with silt fence (set into the ground) to preclude Houston toads from entering the work space. The construction zone will be inspected periodically by the biologists to ensure Houston toads have not entered the area. Therefore, this construction is unlikely to result in adverse effects to the Houston toad or designated critical habitat beyond those addressed and compensated for in the Phase One consultation. Edwards Aquifer Recharge Zone (Barton Springs Salamander): As described in Section 3.5, a 3-mile segment across the aquifer recharge zone will be replaced with 99144ba2.v8 72 <<>> heavier wall pipe for enhanced safety and integrity. Approximately one-half mile will be replaced immediately east of the recharge zone. The new pipe will also be lowered for greater depth of cover to minimize the potential for third-party strikes. Further, a concrete barrier will be installed over the pipeline to protect the pipeline from third party intrusion; the barrier will be constructed with colored reinforced concrete to increase its deterrent effect. A number of other safety and integrity enhancement measures will also be installed, including a sensor-based leak detection system and additional check valves. All these enhancements will significantly reduce the potential for releases and potential release volumes in the unlikely event of a pipeline release. Longhorn hereby provides to the Service mill certificates for the pipe that will be installed, along with Construction Specification CS4, the specifications that identify methods and procedures for pipeline construction; see the accompanying Phase Two Project Documentation Appendix at Tabs 26 and 27. The construction to accomplish these enhancements will involve deepening the existing trench. Construction will occupy an average work space of 60 feet wide along the 3-mile route. This construction space has been investigated for karst features and other sensitive environmental resources. A detailed Edwards Aquifer Protection Plan has been developed for the project that includes the implementation of all required best management practices (BMPs) using as guidelines the City of Austin Land Development Code specifications and the TNRCC Edwards Aquifer Rules for construction over the recharge zone (Phase Two Project Documentation Appendix at Tab 28). Detailed construction plans will be developed to identify both the design and location of water quality control structures, as well as non- structural BMPs; those plans, which are currently under development, will be made available to the Service upon preparation of reasonably complete draft documents. The environmental protection plan also provides for FERC qualified environmental inspectors to be onsite during the construction process to continuously review and evaluate the efficiency of the recommended BMPs and to make changes as needed for maximum environmental protection. The environmental inspectors will also react to any encounter of subsurface voids by immediately notifying project geological and biological experts for evaluation of the situation and to make recommendations for remedial actions. Remedial actions will, at a minimum, comply with TRCC guidelines for closure of subsurface voids. All encountered limestone voids, regardless of size, will be appropriately sealed within the construction trench. This will prevent potential siltation into the aquifer via such voids during construction, as well as provide additional protection from aquifer contamination in the unlikely event of a product release during operation of the pipeline. In the event a large void is encountered, geotechnical engineers will also be involved in evaluating and recommending remedial actions. The City of Austin, TRCC, Barton Springs/Edwards Aquifer Conservation District, and the Service will also be notified and informed of recommended remedial actions. The trench has been designed with high porosity containment capacity and bermed areas at locations where product could reach the surface. With the implementation of the Edwards Aquifer Environmental Protection Plan, the construction across the Edwards Aquifer recharge zone is not expected to result in any significant adverse impacts to the aquifer or the Barton Springs Salamander. Edwards Aquifer Contributing Zone (Barton Springs Salamander): As described in 99144ba2.v8 73 <<>> Section 3.5, approximately 15 miles of pipe in the contributing zone will be lowered and replaced, and a check valve will be installed immediately downstream of the existing block valve over the contributing zone (MP 175.5), even though the replacement is not necessary (See "Edwards Aquifer Contributing Zone Protections" in The Project Documentation Appendix). The replacements will be installed using heavier wall pipe than exists at this time and will be lowered at least 5 feet below the ground surface. Construction over the contributing zone will be conducted pursuant to the methods and procedures outlined in the Phase One BA. The heavier, deeper pipe will reduce the risk of a release across the contributing zone. The trench has been designed with high porosity containment capacity and bermed areas at locations where product could reach the surface. The check valve will reduce potential release volumes by immediately stopping flow upstream, in the event of a release east of the block valve; as a result, the potential for drainage from higher-elevation segments to the west of the check valve is eliminated during the time required for the block valve to close. Moreover, at the Cedar Valley pump station, which is located in the contributing zone upgradient of the pipeline crossing of Barton Creek, Longhorn has committed to install secondary containment (LMC 27) and a remote monitoring camera (LMC 21) before project startup. The secondary containment will provide protection to Barton Creek, and remote cameras allow monitoring by the pipeline controllers. Furthermore, the host of pipeline mitigation measures directed to Tier Il and III areas will apply over much of the contributing zone, including hydrostatic pressure and proof testing, enhanced leak detection, frequent patrols, cathodic protection system testing, in-line inspection shortly after startup, surge pressure protection, and the establishment of a response center in South Austin. See Section 3.4, Emergency Response. 4.4 Planned, But Unscheduled Construction As described in Section 3.0, several additional improvements to the pipeline are planned to take place, but have not been specifically designed or scheduled at this time. While many of these improvements are located at existing above-ground facilities (valves, pump stations, etc), the exact location and construction details are not yet known. It is believed that the majority of these additional improvements will not occur in potential habitat areas, but if so will not adversely affect listed species habitat, or can be designed to avoid habitat areas. In the event any such improvements should necessitate access or construction within listed species habitat, the previously utilized Phase One BA maintenance construction procedures (see Phase Two Project Documentation Appendix at Tab 1) will be followed under the direction of FERC qualified environmental inspectors. To the extent feasible, all construction activity will be restricted to the existing ROW within habitat areas, which has been fully compensated. If construction must exceed the ROW in an area of potential habitat, the Service will be notified in advance, and additional compensation, as required, will be calculated and provided according to the procedures set forth in the Phase One BA for the given species, to the extent a specific location has not previously been compensated for off-ROW impacts. 4.5 Future Additional, But Currently Unforseen Construction As described in Section 3.0, at various, but unpredictable, times and places in the future, certain construction activities may be required for maintenance, repair, or testing of the 99144ba2.v8 74 <<>> pipeline or attendant facilities. The majority of these future construction activities can be designed to avoid any adverse effect to listed species to the extent the activities occur within potential habitat areas. In the event any such construction should necessitate access or disturbance within listed species habitat, the previously utilized Phase One BA maintenance construction procedures (see Phase Two Project Documentation Appendix at Tab 1) will be followed under the direction of FERC qualified environmental inspectors. To the extent feasible, all construction activity will be restricted to the existing ROW within habitat areas, which has been fully compensated. If construction must exceed the ROW in an area of potential habitat, the Service will be notified in advance, and additional compensation, as required, will be calculated and provided pursuant to the conditions set forth in the Phase One BA for the given species, to the extent a specific location has not previously been compensated for off-ROW impacts. 4.6 Bays and Estuaries The Longhorn Pipeline is in proximity to the Galveston/Trinity Bay system where it passes through Houston. All surface drainage in the Houston area crossed by the Longhorn Pipeline drains to the Galveston/Trinity Bay system ultimately through Buffalo Bayou and the Houston Ship Channel. Bay systems along the Texas coast, including the Galveston/Trinity Bay system, are documented to support a number of listed threatened or endangered sea turtles and marine mammals. Possible concern could exist in the event of a catastrophic release event that product could reach the bay system in sufficient quantities to be toxic or detrimental to those listed species. Several factors are to be considered in this situation that result in an extremely low probability for significant quantities of product to be released in a tributary or waterway that would have direct inflow to Galveston and Trinity Bays. First, the Longhorn Pipeline is buried very deep at the various waterway crossings in north Houston, such as Greens Bayou (24 feet), Hunting Bayou (25.2 feet), ditch north of Hunting Bayou (33.1 feet), ditch south of Hunting Bayou (28 feet), and others (See depths of cover in Project Documentation Appendix). This significant depth greatly reduces the potential for third party strike. Second, most of the area through east and north Houston is ranked as Tier 2 or 3 zones, thus being subject to the enhanced LMP provisions for Sensitive Areas, and Hypersentitive areas. Additionally, all the tributaries drain to Buffalo Bayou and the Houston Ship Channel. Due to the large number of chemical, refining, and industrial facilities situated along the Houston Ship Channel, there exists in place a comprehensive spill response system and equipment to respond quickly to spills of any nature that occur in the channel. It is unlikely that a significant spill from the Longhorn Pipeline would occur in a sensitive drainage area, or would escape the Houston Ship Channel containment into the bays. 4.7 Summary of Conservation Measures 99144ba2.v8 75 <<>> The following provides a summary of the avoidance and conservation measures that Longhorn commits to provide. These measures are assured by the mandates of this consultation and the overall NEPA process simultaneously ongoing with this consultation. The implementation of these conservation measures for listed species assure that the project will be unlikely to result in jeopardy or adverse modification of critical habitat for any listed species and is not likely to adversely effect species or habitat. Many of the mitigation measures of the Longhorn Mitigation Plan which were designed prior to the Phase One or Phase Two consultation processes were intended to provide protections for listed species, either directly or intrinsically. While all LMP features provide significant safety and integrity enhancements for the pipeline as a whole that ultimately benefit species protection, those described below provide specific enhancements which will avoid potential impacts to listed species. Most of these features were incorporated into the LMP prior to finalization of either of the consultation processes. • LMCs 3, 5, 34 - Pipe replacement and lowering over the Edwards Aquifer recharge and contributing zones, with trench and surface containment areas (Barton Springs Salamander), Buescher State Park (Houston toad), Pedernales Falls State Park (golden-cheeked warbler), and other locations in species habitat areas; • LMC 22 - Analysis of, and if necessary, installation of additional valves to limit potential release volumes (all species); • LMC 13 - Addition of an enhanced pipeline leak detection system with additional sensor-based leak detection over the recharge zone and slaughter creek watershed in the contributing zone (all species); • LMC 20 - Increased pipeline surveillance in EA designated sensitive and hypersensitive areas and daily pipeline surveillance across the recharge zone (at least once per week on-ground) (all species); • LMC 23 - Establishment of a fully equipped Emergency Response Center in South Austin (Barton Springs Salamander and Houston toad): • LMC 28 - Revised Facility Response Plan to incorporate features of the City of Austin Barton Springs Oil Spill Contingency Plan and the U.S. Fish and Wildlife Service's Barton Springs Salamander Recovery Plan as well as detailed response planning based upon analysys of stream flow potential in the Edwards Aquifer recharge and contributing zones. (Barton Springs Salamander); • LMC 33 - Establish a refugium for the Barton Springs Salamander and performance of other conservation measures for listed species as may be determined appropriate through consultation with the U.S. Fish and Wildlife Service (all species); • LMC 27 - Provide secondary containment around the Cedar Valley pump station which lies within the Barton Springs/Edwards Aquifer contributing zone. 99144ba2.v8 76 <<>> • LMC 35 - Longhorn has committed that it will not transport products containing MTBE or similar aliphatic ether fuel additives in greater than trace amounts; Though not a specific mitigation commitment, Longhorn has identified all potential areas of concern for listed species along the pipeline corridor from Houston to El Paso for purposes of assessment and avoidance. An additional intrinsic benefit of increased patrol frequencies (LMC 20) is the result that increased inspection and surveillance of the Longhorn Pipeline will enable inspection personnel to coincidentally observe the adjacent pipelines that parallel the Longhorn pipeline. This will provide the opportunity for identification of pipeline emergency situations and threats to the integrity of those pipelines with greater frequency than currently is the case. In fulfillment of LMC 33, Longhorn has committed to a significant number of additional mitigation features specific to listed species developed during the Phase One and Phase Two consultation processes. These commitments become binding as a result of the conclusion of the consultation processes and issuance of the Service's Biological Opinion, and as incorporated into the LMP as it evolves during the EA process. These measures have been developed during the two phases of consultation through discussions between Longhorn, EPA, DOT, and the Service. These commitments are listed below by consultation phase. Phase One • Provision of conservation funding for potentially affected species in the approximate amount of $992,448 (all species). • Monitoring studies of listed species within or adjacent to the ROW (all species). • Minimization of maintenance construction work space in potential species habitat areas (all species). • Seasonal timing of maintenance activities to avoid critical breeding, nesting, or blooming periods for listed species (all species). • Use of special mowing/clearing processes and equipment in potential species habitat areas to minimize ground disturbance (all species). • Provision of FERC qualified environmental inspectors during maintenance activities within potential species habitat areas (all species). • Use of native grasses for restoration of disturbed areas during maintenance activities (all species). • Minimization of the use of herbicides for maintenance purposes (all species). 99144ba2.v8 77 <<>> Phase Two Detailed topographic and surface flow modeling to enhance spill response planning efforts (all species). Special investigative, preparation, and construction practices and techniques for pipe replacement over the Edwards Aquifer Recharge Zone (Barton Springs Salamander) including: Intensive geological and biological field studies of the pipeline corridor to Identity sensitive teatures and areas, including ground penetrating radar, geotechnical coring, karst identification, geological and biological investigations of identified features, and detailed geologic assessment for recharge potential. - Use of enhanced best management practices for erosion and sedimentation control during and after construction of new pipe. - Sealing of subsurface voids encountered during trench excavation. - Provision of a colored, reinforced concrete barrier over the new pipe for enhanced protection from third party damage. Grading of the surface over the new pipe installation to direct surface drainage (potential surface release away from identified sensitive areas/features. • Lowering and replacement of 15 miles of pipe across the Edwards Aquifer Contributing Zone. Training for first responders and other spill response personnel for highest efficiency and care in species areas (all species) . Cumulative Effects Cumulative effects of future State, local or private actions that are reasonably certain to occur in the action area are considered in this BA. Future Federal actions that are unrelated to the proposed action are not considered in this section because they require separate consultation pursuant to Section 7 of the Act. Because of the linear nature of the pipeline and the long history of clearing and operations (about 50 years), no cumulative effects from the activities proposed are anticipated. The majority of the counties involved in the project are predominantly rural (see draft Environmental Assessment of the Proposed Longhorn Pipeline System at Section 4.1.1.2), and imminent future actions identified are not likely to result in jeopardy to the species and are not likely to adversely affect any listed species or habitat. The various mitigation measures required for the Longhorn Pipeline as a result of the environmental review being conducted by the Lead Agencies or as a consequence of this 99144ba2.v8 78 <<>> consultation can be expected to have net beneficial effects on the environment, including listed species and their habitats. First, the Longhorn Pipeline itself will be improved, providing a higher level of environmental protection than previously was the case for the pipeline. Second, the Barton Springs Salamander refugium and captive breeding program will help mitigate for risks posed not only by the Longhorn pipeline, but by the many other existing sources of potential harm to the salamander, outlined above in the discussion of the environmental baseline for the salamander. In addition, some Longhorn-related mitigation measures will have the indirect or cumulative effect of reducing environmental and species-related risks associated with the two other petroleum pipelines in the area, especially over the Edwards Aquifer. For example, the Longhorn Mitigation Plan requires increased surveillance along the pipeline route. While most pipelines have weekly surveillance, Longhorn has committed to a patrol frequency of once every 2.5 days for sensitive and hypersensitive areas. In the three-mile crossing of the Barton Springs recharge zone, Longhorn will have daily patrols. This increased frequency of patrol will facilitate early detection of leaks and third party activity in the are of all three pipelines crossing the recharge zone. Similarly, Longhorn's commitment to aggressive public education and awareness programs will help reduce risks for all three pipelines crossing the Barton Springs recharge zone. ublic awareness should deter individuals from acts that might risk catastrophic spills o other accidents potentially affecting the environment and listed species 99144ba2.v8 79 <<>> 5.0 REFERENCES Arft, A. and T. Ranker. 1995. Demography of the rare orchid Spiranthes diluvialis: implications for conservation. Program and Abstracts, g'h annual meeting of the Society for conservation Biology, June 7-11, Fort Collins, Colorado. Abstract, notes from presentation attended. U.S. Fish and Wildlife Service, Austin, Texas. Brune, G. 1981. Springs of Texas: Volume 1. Branch-Smith Inc. Fort Worth, Texas. Chippindale, P., D. Hillis, and A. Price. 1990. Central Texas Salamander Studies. Section 6 report submitted by Texas Parks and Wildlife Department to U.S. Fish and Wildlife Service. Federal Aid Project No: E-1-2, Job No. 3.4. Austin, Texas. Horizon Environmental Services, Inc. 1991. Threatened or Endangered Species Investigations - EZ Pipeline Project. Horizon Environmental Service, Inc. Austin, Texas. Horizon Environmental Services, Inc. 2000. Biotoxicological Analysis a Potential Longhorn Pipeline Product Release Over The Edwards Aquifer Recharge Zone, Barton Springs Segment. Horizon Environmental Services, Inc. Austin, Texas. Poole, J.M,. and D.H. Riskind. 1987. Endangered, Threatened, or Protected Native Plants of Texas. Austin, Texas: Texas Parks and Wildlife Department, State of Texas. U.S. Fish and Wildlife Service (USFWS). 1984a. Houston toad recovery plan. U.S. Fish and Wildlife Service. Albuquerque, New Mexico. 73pp. U.S. Fish and Wildlife Service (USFWS). 1984b. Navasota ladies'-tresses recovery plan. U.S. Fish and Wildlife Service. Albuquerque, New Mexico. U.S. Fish and Wildlife Service (USFWS). 1994a. Minimum Procedures for Determining the Presence/Absence of Golden-Checked Warblers and Black-Capped Vireos. March 7, 1994 Memorandum, Austin Field Office. U.S. Fish and Wildlife Service (USFWS). 1994b. Population and habitat viability assessment: Houston toad (Bufo houstonensis). Workshop conducted by IUCN/SSC Conservation Breeding Specialist Group in partial fulfillment of USFWS contract #94-172. Apple Valley, Minnesota. U.S. Fish and Wildlife Service (USFWS). 1995. Threatened and Endangered Species of Texas. Austin, Texas: US Fish and Wildlife Service, Revised June, 1995. U.S. Fish and Wildlife Service (USFWS). Houston Toad Recovery Team. 1999. March 31- April 1, 1999 Meeting Minutes. U.S. Fish and Wildlife Service, Austin, Texas. U.S. Fish and Wildlife Service (USFWS). Final Rule to List the Barton Springs Salamander as Endangered. 62 FR 23377. Apr. 30, 1997. Texas Parks and Wildlife. 1993. Endangered species information for Hilltop Lakes. Texas Parks and Wildlife Resource Protection Division, Austin, Texas. 99144ba2.v8 80 <<>> Wilson, H. 1993. Contractors partial draft of recovery plan revision for Navasota ladies'- tresses (unfinished contract). U.S. Fish and Wildlife Service, Austin, Texas. (SCS) Soil Conservation Service. 1984. Soil Survey of Austin and Waller Counties, Texas. United States Department of Agriculture. 99144ba2.v8 81 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 4C PROGRAMMATIC AGREEMENT <<>> Programmatic Agreement among the U.S. Environmental Protection Agency, U.S. Department of Transportation, Texas State Historic Preservation Officer, Tribal Historic Preservation Officer(s) (or other Tribal official) and the Advisory Council on Historic Preservation regarding the Longhor Pipeline Project in Texas WHEREAS, the U.S. Environmental Protection Agency (EPA), and the U.S. Department of Transportation (DOT) have agreed to prepare an Environmental Assessment (EA) on the Longhorn Partners Pipeline Project in Texas (hereinafter referred to as the Undertaking); and WHEREAS, the EPA and DOT have determined that the Undertaking may have an effect on "historic properties" (i.e., properties included in or eligible for inciusion in the National Register of Historic Places), and have consulted with the State Historic Preservation Officer (SHPO), applicable Tribal Historic Preservation Officers (THPO) and where there is no THPO other appropriate Tribal officials, and the Advisory Council on Historic Preservation (ACHP), pursuant to Subpart B of the ACHP's regulations (36 CFR Part 800) implementing Section 106 of the National Historic Preservation Act (NHPA); and WHEREAS, the EPA and DOT will, as a part of the EA process, elicit the views of interested federal and state agencies, environmental groups and the public with regard to the Undertaking and its effect on historic properties; and WHEREAS, the effects on historic properties cannot be fully determined prior to approval of the Undertaking, and this PA addresses all phases of facilities construction for those areas; NOW, THEREFORE, the EPA, DOT, SHPO/THPO and ACHP agree that this PA is consistent in theorince vior se following stipulations in order to saisy al aspects or EPA'S and DOT's Section 106 responsibilities. 1 <<>> the Secretary of the Interior for Histonic Preservation (48 CFR 44734-37). Survey and testing at pa guidelnes of work shall provide sufficient documentation to assess the eligibility, in consultation with the SHPO/THPO, of the properties for inclusion in the National Register of Historic Places. Any unresolved eligibility issue(s) between LPP and the SHPO/THPO will be forwarded to EPA and DOT for submittal to the Keeper of the Register for final determination. LP shall submit a draft report of survey investigations to the SHPO/THPO for review and comment, prior to initiating : test excavations designed to evaluate National Register eligibility, in order to allow the ! SHPO/THPO to comment regarding sites requiring testing. Unless the SHPO/THPO notifies LPP within 30 working days after receipt, the survey investigations shall be considered adequate for Section 106 purposes. LPP shall provide a draft report of test excavations to the SHPO/THPO, with a copy to ERA and DOT, to allow SHPO/THPO's review and recommendation(s) on the National Register eligibility of tested sites. Unless the SHPO/THPO objects to it within 30 working days after receipt, the draft testing report shall be considered adequate for Section 106 purposes. If the SHPO/THPO objects or requests additional testing information, the matter will be resolved between LPP and the SHPO/THPO. If the adequacy of stipulation 7, below. testing cannot be resolved between LPP and the SHPO/THPO, it shall be resolved according to 2. For historical and archeological properties determined by the SHPO/THPO, or the for purposes of Section 106. Keeper of the Register, to be ineligible for the National Register, no protection need be afforded Bit lactims 3. For affected arseniagical properties determined eligible for inclusion to the National elgile? Register, and where it is not possible to avoid the potential adverse effects of the Undertaking, LPP shall: (a). Develop, in consultation with the SHPO/THPO, and implement a Data Recovery Plan and Research Design (hereinafter referred to as the Plan). The Plan shall be consistent with the Secretary of the Interior's Standards and Guidelines for Archeological Documentation (48 CFR 44734-37) and take into account the ACHP's publication, Treatment of Archeological Properties. (b). The Plan shall include, as appropriate, research, design, controlled earth work, report schedules, monitoring, relocation, preservation, reburial, recordation, and curation of artifacts. It shall specify, at a minimum: i) the property or properties where data recovery is to be carried out; ii) any property or properties that will be destroyed, altered or transferred without data recovery; ili) research investigations that will be conducted under the approved data recovery plans and, as appropriate, will take into account any previous work conducted or other research in the area, and 2 .... .. <<>> and DOT. (c). LPP shall submit the Plan to the SHPO/THPO, for review and approval, prior to initiating any action that would adversely affect an eligible property. Unless the SHPO/THPO objects within 30 calendar days after receipt, the Plan shall be implemented by LPP. If the SHPO/THPO objects, and/or requests additional information or revisions to the Plan, the matter will be resolved between LPP and the SHPO/THPO. If the matter cannot be resolved, it shall be resolved according to stipulation 7, below. 4. For affected historie properties, other than archeological sites, determined eligible for the National Register, and where it is not possible to avoid the adverse effects of the Undertaking, LPP shall, in consultation with the SHPO/THPO and any identified interested parties, including Indian tribes and other Native Americans identified by EPA or DOT, develop a proposal to mitigate the adverse effects of the Undertaking on those properties. Then, LPP shall: (a). Provide the SHPO/THPO, for review and approval, the mitigation proposal to ensure the recordation, relocation, marketing and/or preservation of the property, taking into account the Secretary of the Interior's Standards for Treatment of Historic Properties (36 CFR 68). In determining what level of documentation to propose, LPP shall first contact the SHPO/THPO and/or the National Park Service (NPS), Intermountain Field Office, 1220 South St. Francis Dr., Santa Fe, New Mexico 87504. (b). Unless the SHPO/THPO objects within 30 calendar days after receipt, the mitigation proposal shall be implemented by LPP. If the SHPO/THPO objects, or requests additional information or revisions to the proposal, the matter shall be resolved between LPP and the SHPO/THPO. If the proposal cannot be revolved, it shall be resolved according to stipulation 9, below. 5. LPP, in coordination with the SHPO/THPO, shall ensure that all survey, evaluation, data recovery, mitigation, and monitoring are conducted under the direct supervision of a person(s) meeting, at a minimum, the qualifications set forth in the professional qualifications standards in the Secretary of the Interior's Standards and Guidelines for Archeology and Historic Preservation. If any cultural properties are discovered during construction or related ground disturbing activities, LPP shall ensure that all activities are halted that may adversely effect an cultural property, and immediately notify the SHPO/THPO, EPA and DOT. LPP shall allow the SHPO/THPO a minimum of two working days to inspect the property. Based on the SHPO/THPO's findings, determine with EPA and DOT, appropriate course of action based on PA process beginning at Stipulation 1. 3 <<>> 7. Should LPP or the SHPO/THPO object within 30 calendar days to any plan, proposal, requirement or specification pursuant to this PA, EPA and DOT shall consult with the objecting party to resolve the objection. If EPA and DOT determine that the objection cannot be resolved, EPA and DOT shall forward all pertinent documentation on the dispute to the ACHP. Within 30 days after receipt of all pertinent documentation, the ACHP will: a) provide the EPA and DOT with its recommendation, which EPA and DOT shall take into account in reaching a final decision; or b) notify EPA and DOT that it will comment pursuant to 36 CFR 800.7, and proceed to comment. Any ACHP comment provided in response to such a request shall be taken into account by EPA in accordance with 36 CFR 800.7(c)(2). Any recommendation or comment provided by the ACHP shall be understood to pertain only to the subject of the dispute. 8. Should a member of the public, Indian tribe or other Native American, or other interested person object at any time during implementation of the measures stipulated in this PA, EPA and DOT shall take the objection into account and consult, as appropriate, with the objecting party, the SHPO/THPO, the ACHP, and/or LPP. If EPA and DOT determine the objection cannot be resolved, it shall follow stipulation 7, above. 9. Nothing herein shall preclude LPP from exercising any rights it may have to seek appropriate review of any findings, determination or ruling which may be made by any regulatory authority under this PA. 10. Upon written notice from the SHPO/THPO or the ACHP that any of the conditions of this PA are being violated, the EPA and DOT shall consult with the SHPO/THPO and ACHP to determine how the concern should be resolved. 11. If the EPA, DOT, SHPO/THPO or ACHP finds that the terms of this PA cannot be met, or considers a change or revision to be appropriate, it shall request the other signatory parties to consider an amendment of the PA. All amendments shall be executed in the same manner as the original PA. 12. Any party to this PA may terminate it by providing 30 working days written notice to the other parties, provided that the parties will consult during the period prior to termination to seek amendments or other actions that would avoid termination. In the event of termination, the EPA will comply with 36 CFR 800.3 through 800.6 for this Undertaking. 4 <<>> (date) the State Historic Prevervation Officer of Texas the U.S. Department of Transportation (dato the Advisory Couracil oa Historic Preservation the Vi. Jole 9/2/000 пате) (date) Concurrion Party. Longhora Pipelis Parters, LP. Carto (Danse) (date) Tribal Siguanory (will Ill in Tribe names if any want to participare) Dear Matader 4/2/0 Tribal Fistric Preseration Oicel Mescaluo Apuche Tribe TOTAL P. 11 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 4D SHPO CONCURRENCE LETTER <<>> Horizon... Environmental Services, Inc. 26 April 2007 RECEIVED Mr. Bill Martin APR 2 6 2007 Texas Historical Commission P.O. Box 12276 TEXASHISTORICALCOMMISSION Austin, Texas 78711-2276 RE: Longhorn Partners Pipeline, L.P, CONCUR High Probability Maps Waller through Crane Counties, Texas by Welln 1. Mak Section 106 for F. Lawerence Oaks HJN 050175 AR State Historic Preservation Officer Date 5/23/67 Dear Mr. Martin: Track# Please find enclosed a CD containing files of the delineated archeological high probability areas along the Longhorn Partners Pipeline (LP) right-of-way (ROW) from Waller County through Crane County, Texas. The CD contains 21 PDF's of strip maps depicting: 1) the ROW alignment on topographic quadrangles; 2) the delineated archeological high probability areas; and 3) areas in the vicinity of the archeological high probabilities areas that have been previously surveyed for cultural resources. In addition, the CD contains an Excel file depicting the beginning and end mileposts of each high probability area as well as the counties in which they are located. As you will recall, Jeff Blackmore and I met with you a few months ago and went over the delineated high probability areas. The files on the CD reflect the identical areas that we reviewed together with the exception of areas that have been recently surveyed with negative results. These negative survey areas have been clipped from the stretches of high probability areas, leaving only unsurveyed areas. As previously discussed, it is Horizon's opinion that areas of the ROW beyond those of the delineated high probability areas constitute low probability areas for significant cultural deposits where formal cultural resources investigations are unwarranted.. As such, Horizon recommends that cultural resources clearance be granted for all low probability areas along the ROW and that all future maintenance and construction activities within these low probability areas along the existing ROW be allowed to proceed without further consultation with your office. Only those areas within the existing ROW delineated as high probability areas will be assessed for cultural resources by a qualified archeologist prior to any impacts. On behalf of Magellan Pipeline Company, L.P. (Magellan) and Longhorn Partners Pipeline, L.P. (Longhorn), Horizon Environmental Services, Inc. (Horizon) is seeking documented consultation with your office in regard to compliance with Section 106 of the National Historic Preservation Act (NHPA) of 1966, as amended. Should you concur with Horizon's delineated high probability hesitate to call me at (512) 328-2430. areas and recommendations, please sign below. If you have any questions, please do not 1507 South IH 35 * Austin, Texas 78741 * 512.328.2430 * Fax 512.328.1804 * www.horizon-esi.com CORPORATE HEADQUARTERS WBE/DBE/HUB Certified <<>> Howzon. Environmental Services, Inc. Sincerely, Tuss Browntow Russ Brownlow, MA, RPA Principal / Cultural Resources Director Horizon Environmental Services, Inc. Concurrence Date Enclosures: 1 CD Cc: Jeff Blackmore Project File <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.0 PIPELINE INTEGRITY ANALYSIS 5.1 INTRODUCTION Chapter 5 focuses on the current operation, maintenance, and safety controls of the pipeline in its current state. The focus of Chapter 6 is the potential changes in risk as a result of the Proposed Project. Many aspects of risk and integrity will remain unchanged under the Proposed Project. This analysis relies on the documentation provided by the pipeline operator, including the Longhorn Pipeline relative risk database, the PHMSA Audits, Operational Reliability Analysis (ORAs), and the self-audits. The Longhorn Pipeline System (System) initially transported crude liquids from Crane in West Texas eastward to markets near Baytown, Texas until 1995. “Longhorn Partners Pipeline, L.P. (“Longhorn”) was formed in 1995 with the goal of delivering refined petroleum products (gasoline and other motor fuels) to markets in El Paso, with connections through other pipelines to New Mexico and Arizona”. Beginning in 1998, physical conversion began that included construction of pipeline segments from Crane to El Paso, Crane to Odessa, and other ancillary pipelines and facilities. An Environmental Assessment of the Proposed Longhorn Pipeline (1999 EA) was published in 2000, with a Finding of No Significant Impact (FONSI) issued by the Environmental Protection Agency and PHMSA later that year. Further activities and system enhancements designed to improve pipeline integrity began in accordance with commitments found in the Longhorn Mitigation Plan (LMP). Operations of the re-structured pipeline system began in January of 2005. It is useful to understand the history of mitigation and inspection of the Longhorn Pipeline from November 2000 (FONSI issued) to current. The following is a high-level summary of the mitigation and inspection of the Longhorn Pipeline. • March 1999 - Settlement Agreement requires Environmental Assessment, which ultimately leads to the Longhorn Mitigation Plan • November 2000 - FONSI issued and LMP published • 2001 – 2004 Pre-Startup Mitigation Commitment Activities Performed • January, 2005 - Official startup date for the Longhorn Pipeline System • February 2007 - High Resolution Magnetic Flux Leakage (HRMFL) in-line inspections completed for Galena Park to Crane. Electronic Geometry Pig (EGP) inspection completed in conjunction with HRMFL. • January 2008 - Transverse Field MFL Inspection (TFI) in-line inspections completed on Galena Park to Crane. Electronic Geometry Pig (EGP) inspection completed in conjunction with TFI tool. • November 2008 - HRMFL in-line inspections completed for Crane to El Paso 5-1 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • July, 2010 – Ultrasonic Wall Measurement Tool (UT) in-line inspections completed for Galena Park to Crane. Electronic Geometry Pig (EGP) inspection completed in conjunction with UT tool. • November, 2011 – Replacement of approximately six miles of existing pipeline in the Pedernales River watershed. Presented herein is an overall summary of the pipeline’s general condition and attributes, as reviewed in past inspections and tests and review of data associated with inspections and tests done since 1999. This data is used for determining the structural integrity of the pipeline as well as the system’s ability to withstand specified operating conditions. This chapter also examines the pipeline’s leak history, including a review of leak incidents, frequencies, volumes, and causes. Design, maintenance, and operation of this system are regulated by PHMSA under 49 CFR Part 195 and the Texas Railroad Commission (RRC) (Tex. Admin Code 16 Part 1 Chapter 8 Subchapter D). Magellan’s System Integrity Plan (SIP) procedures specify the details of all O&M activities. The procedures found in the Longhorn Pipeline System Integrity Plan (LPSIP) have been integrated into Magellan’s SIP. LMP Commitments are identified in the SIP as “Assets covered by the Mitigation Plan”, or the “Mitigation Plan.” There are 39 Longhorn Mitigation Commitments in the LMP that require Magellan to conduct inspections and testing that were either in addition to, or more frequent than, those required in 49 CFR Part 195 in the year 2000. These additional measures were expected to result in increased detection of threats and an improved level of mitigation resulting in increased assurance of integrity and associated reductions in risk. Although pipeline regulations have increased significantly since the 1999 EA, some of the LMP provisions are still imposing requirements that exceed current regulations. 5.1.1 Applicable Regulations Magellan, as operator of the System, is subject to compliance with 49 CFR Parts 40, 190, 194, 195 and 199 as well as specific requirements within the LMP. Per the requirements of the LMP and SIP-ADM-14.01 (Appendix 5A), a self-audit is conducted annually for the purpose of ensuring that the LMP stated plan goals, objective, and commitments are being met. The recent self-audit reports are available to the public via posting on Magellan’s website. Longhorn Pipeline is subject to PHMSA and the Texas RRC inspections. Findings from these inspections are tabulated in Table 5.1.1-1 cover inspections from April 2005 through Sept 2009. As an interstate pipeline, the Longhorn Pipeline is regulated by PHMSA. Applicable federal regulations and other requirements, and guidance are listed and described below. 5-2 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.1.1.1 Pipeline Safety Regulations Under Federal regulations, 49 CFR Parts 40, 190, 194, 195 and 199 are applicable to hazardous liquid pipelines. Part 190 prescribes procedures used by PHMSA for regulating pipeline safety. The PHMSA enforcement authority and civil and criminal penalties for violating the Pipeline Safety Act are detailed in this regulation. Part 194 contains requirements for oil spill response plans to reduce the environmental impact of onshore pipeline oil spills. Part 195 prescribes safety standards and reporting requirements for pipeline facilities used in the transportation of hazardous liquids. Included in Part 195 are the IMP regulations (49 CFR Part 195.452), established in 2001 after establishment of the LMP. The IMP for liquid pipeline operators specifies how pipeline operators must identify, prioritize, assess, evaluate, repair and validate the integrity of hazardous liquid pipelines that could, in the event of a leak or failure, affect HCAs within the United States. HCAs include population areas; areas containing drinking water and ecological resources that are unusually sensitive to environmental damage; and commercially navigable waterways. The rule requires a comprehensive plan to identify HCA’s, and to assess risk and manage integrity in those areas. A formal and well documented approach is required in order to effectively meet these newer regulations. Part 199 addresses the requirements for drug and alcohol testing and references the procedures of Part 40. 5.1.1.2 Longhorn Mitigation Plan (LMP) An Environmental Assessment (EA) of the Longhorn Pipeline was published in 2000. Following the assessment, a FONSI was issued by the EPA and PHMSA after execution of the settlement agreement which resulted in the Longhorn Mitigation Commitments (LMCs) outlined in the LMP. These mitigation commitments consist of activities and system enhancements designed to improve pipeline integrity generally over and above regulatory requirements. The LMP is composed of 40 mitigation commitments and these are summarized in Appendix 9B. Magellan submits annual reports to PHMSA (per LMC 38) that include information about the status of mitigation commitments, implementation, the character of interim developments, and results of any mitigation-related studies and analyses. The reports also summarize developments related to its Operation Reliability Assessment (ORA). These reports are made available to the public via Magellan’s internet website. Per LMC 39, any changes or modifications proposed by Magellan to the LMP for the purpose of adapting to changing technology and circumstances are made available to the public (and the mayors of Houston, Austin, and El Paso, and the General Manager of the LCRA) at the time it is submitted to PHMSA for approval and written concurrence. 5.1.1.3 National Oil and Hazardous Substance Pollution Contingency Plan EPA regulations in 40 CFR Part 300 provide an organizational framework and procedures for preparing to respond to discharges of oil and accidental releases of hazardous substances into locations which present danger to public health or welfare. The document specifies responsibilities among federal, state, and local regulatory agencies during an emergency response. It establishes requirements for federal, regional, and area emergency response plans 5-3 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL and addresses procedures for the response of other persons as well. This document also provides response plans per Comprehensive Environmental Response, Compensation, and Liability Act requirements. 5.1.1.4 Spill Prevention, Control, and Countermeasures Plan (SPCC) EPA regulations in 40 CFR 112 and Texas Commission on Environmental Quality (TCEQ) Spill Prevention and Control (Chapter 327) include requirements for oil spill prevention, preparedness, and response to prevent oil discharges to navigable waters and adjoining shorelines. The rule requires specific facilities to prepare, amend, and implement SPCC Plans. The SPCC rule is part of the Oil Pollution Prevention Regulation, which also includes the Facility Response Plan (FRP) Rule. 5.1.1.5 Hazardous Waste Operations and Emergency Response (HAZWOPER) OSHA regulations found in 29 CFR Part 1910.120 cover HAZWOPER activities. Hazardous waste activities include clean-up operations required by a governmental body involving hazardous substances at uncontrolled hazardous waste sites, corrective actions involving clean- up operations at Resource Conservation and Recovery Act sites, voluntary clean-up operations at sites recognized by governmental bodies as uncontrolled waste sites, and operations involving hazardous wastes at treatment, storage, and disposal facilities. Emergency response operations for releases of hazardous materials comply with requirements of paragraph (q) of this regulation. 5.1.1.6 Transportation Security Administration (TSA) Pipeline Security In April 2011, TSA Pipeline Security Division updated the TSA Pipeline Security Guidelines which provide recommendations for pipeline industry security practices. These updated guidelines incorporate changes to the DHS threat advisory system and supersede the 2002 DOT Pipeline Security Information Circular and the related Pipeline Security Contingency Planning Guidance. Magellan participates in the TSA Corporate Security Review (CSR) Program conducted by the Pipeline Security Division. The CSR Program is an on-site security review with a pipeline company. CSRs help establish working relationships with key security representatives in the pipeline industry as well as provide TSA with a general understanding of a pipeline operator's security planning and implementation. Data obtained from CSRs aid in establishing a baseline against which to evaluate minimum security standards in the pipeline industry and identify coverage gaps. CSRs help to identify and share best practices observed throughout the industry. 5.1.2 Information Analyzed Magellan provided data for the operational years since the 1999 EA. These documents include results from the recent In-Line Inspection (ILI), cathodic protection (CP) surveys, self-audit reports, ORAs, regulatory audit reports, leak history, and other documents. 5-4 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL In assessing the pipeline integrity for the current FEA, additional inspections and audits were not necessary for several reasons: • Use of well-documented, recent inspections, even if conducted by the company being audited, is a well-established protocol in regulatory auditing. • Specialized, independent, and often “certified” third-party pipeline service companies often prepared inspections and reports. • The PHMSA audits can be relied upon as indications as to whether regulatory and LMCs are being carried out since these audits are thorough, non-biased, and performed by trained auditors. • The ORAs and Self Audits can be relied upon as accurate data since they are performed by reputable, independent pipeline experts with standing credentials. 5.1.2.1 Key Documents Key documents that form the basis of the data presented here include: • System Integrity Plan (SIP) (2011) • Longhorn Pipeline System Integrity Plan (LPSIP) • Longhorn Mitigation Plan (LMP) • Final Longhorn Environmental Assessment (1999 EA) • Longhorn Mitigation Plan progress reports • Operational Reliability Analyses (ORA) from 2005 to 2009 • Proposed hydraulic profiles • In-Line Inspection (ILI) anomaly lists • Longhorn self-audits • Facility Response Plans (FRPs) • Det Norske Veritas (DNV) reports on ILI • Process Hazard Analysis (PHA) reports from facilities • Surge analyses • Hydraulic profile graphics • Scenario Based Risk Mitigation Analysis (SBRMA) - qualitative review with action plan generation, used as continuation of Relative Risk Assessment (RRA) (per Section 3.5.10 of the LMP) • Facility Risk Assessment - RRA for facilities • Relative Risk Assessment (RRA) Manual These documents include hundreds of pages of materials. Experienced subject matter experts (SMEs) have reviewed all documents listed as part of regular ongoing integrity management activities. 5-5 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.1.2.2 Databases Recent inspection, survey, and test data is critical in assessing current pipeline conditions. Key databases provided by Magellan include: • Linefill – General pipe specification information including pipe diameter, wall thickness, and grade • Maximum Operation Pressure (MOP) Calculations • Documentation of Repairs, (i.e. Pipeline Maintenance Reports and Correlation Reports) • ILI vendor reports • Potential spill volume calculations • Pipeline depth of cover (DOC) survey reports • Pipeline Relative Risk Assessments (RRA) Results from integrity assessments, ILI and pressure tests, are used to characterize the pipe wall with regards to past damages and certain feature types. Results also provide insights into aggressiveness of exposure and effectiveness of mitigation, although the relative role of each independently is often not discernible. Magellan has procedures in place to integrate ILI information and to determine appropriate responses. 5.2 CONSTRUCTION/EXISTING SYSTEM The present and future condition of the Longhorn Pipeline is influenced by the original construction and present O&M. This section examines the attributes and conditions of the system based on available data and information. These attributes and conditions are relevant for assessing risks in Chapter 6 and potential impacts analyzed in Chapter 7. Attributes such as age, type of pipe, results of inspections and tests, in combination with O&M procedures and mitigation measures (see Chapter 9), influence the integrity of the system. 5.2.1 General Attributes The Longhorn Pipeline consists of various segments installed at different times, as described in Chapter 3 of the 1999 EA. Most of the pipeline between Galena Park and Crane was built between 1947 and 1953. Short sections were replaced as needed over the years. The 18-inch pipeline connecting Crane to the El Paso Terminal was built in 1998, as was the 8-inch lateral from Crane to Odessa. A new 9.1-mile section of 20-inch pipeline between the Galena Park Station and the existing pipeline was installed in 1998. The age and basic pipe characteristics of major sections of the pipeline, between the Galena Park and El Paso are summarized in Table 5.2.1-1. The age of the pipeline is a factor in the integrity evaluation because of the potential for deterioration if the pipeline was not adequately maintained, and because of the potential issues associated with era of manufacturing and 5-6 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL construction practices. The direct effects of age on physical condition and pipe properties are discussed later. An overview of construction specifications utilized during original construction is provided in Table 5.2.1-2. The table also provides specifications utilized by Williams as part of the construction to convert the line to refined product service. In general, the specifications for installation in recent years are more stringent and more detailed than the 1949 specifications. This is relevant since some older features still exist in the current pipeline or influence the probability of integrity issues. Some key differences are: • The level of detail of the pipeline material specifications has increased. • Minimum depth of cover and vertical clearance requirements have increased and new requirements have been added (for example, at road crossings). • Coating type has changed from coal tar enamel to fusion-bonded epoxy for new construction. • Field-applied coating at girth welds has changed. • Welding requirements and techniques have changed. • Hydrostatic testing pressure requirements have increased 55%, and test duration has doubled. • No CP was required in 1949; but now exists across the System. Integrity Management activities and programs specified within the SIP that incorporate LMP and 49 CFR Part 195 requirements are designed to manage any integrity threats associated with previous construction practices and material utilized. 5.2.2 Effects of Age Age alone is not a reliable indicator of pipeline integrity as some pipelines have been in good operating condition for more than 80 years. Possible threats to pipeline integrity are not necessarily strongly correlated with the passage of time, although the “area of opportunity” for something to go wrong obviously does increase with the passage of time. Experts believe that there is no effect of age on the microcrystalline structure of steel such that the strength and ductility properties of the pipe are adversely affected. The primary time-dependent phenomena are the potential for corrosion and for crack growth. Therefore, the ways that the age of a pipeline can influence the potential for failures are through corrosion, fatigue, environmental atmospheric corrosion (EAC), and possibly through vulnerabilities introduced by older manufacturing and construction methods. These age effects are well understood and once identified, mitigation can be applied that counteract these threats with a degree of confidence. Magellan’s Operational Reliability Analysis (ORA) program is designed to specifically address fatigue and other age related concerns. 5-7 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.2.3 Manufacturing and Construction Methods Steelmaking technology, pipe manufacturing technology, coating technology, and construction technology have all made significant advancements over the years. Table 5.2.1-1 shows pipe specifications as provided in Magellan’s database. Manufacturing longitudinal weld seam defects can lead to preferential corrosion or cracking of the seam. Any manufacturing defects are evaluated through existing SIP inspection and mitigation procedures. The older portions of this Longhorn Pipeline appear to have been manufactured and constructed with the best practices of the time. A higher susceptibility to certain failure mechanisms has been identified in older electric resistance welding (ERW) and electric flash welded (EFW) pipe. This applies to pipe manufactured with a low-frequency ERW process, typically seen in pipe which was manufactured prior to 1970, or in an electric flash weld pipe made by A.O. Smith between the years of 1930 and 1969 (History of Line Pipe Manufacturing in North America, J.F. Kiefner, 1996). On the Longhorn Pipeline, over 50% of the pipe was manufactured by either this low- frequency ERW process or the EFW process. ERW/EFW manufacturing creates a longitudinal weld seam in the pipe wall. Flaws that may threaten the integrity of these weld seams have been identified as: • Lack of fusion; • Hook cracks; • Nonmetallic inclusions; • Misalignment; • Excessive trim; • Fatigue/corrosion fatigue; • Selective corrosion (crevice corrosion); • Hard spots; and • Fatigue at lamination3/seam interface. These mechanisms, failure databases, and supporting metallurgical investigations are more fully described in technical literature references (DOT, 1989; Fields, 1989). Since 1970, the conversion by pipe manufacturer to high-frequency ERW techniques along with improvements in quality control has resulted in a more reliable weld seam. The integrity of low-frequency ERW seams is evaluated through in-line inspection techniques that orient magnets to allow detection of longitudinally oriented metal loss and cracks in the seam weld. These tools commonly referred to as TFI tools were utilized on the Longhorn Pipeline system from Galena Park to Crane in areas where older low-frequency ERW seams exist. These inspections and subsequent remediation techniques are discussed further in later sections. 3 Laminations are metal separations occurring in the wall of the pipe, produced during the pipe manufacturing process. 5-8 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Construction techniques have advanced. Newer pipelines benefit from better bending practices, welding technologies (sometimes mechanically automated), inspection technologies, better quality control practices, boring and drilling techniques, and typically deeper burials. Therefore, with respect to advancements in technologies, it is not the passage of time that causes a threat, but the recognition that older pipelines could have issues associated with the manufacturing and coating processes based on the pipe vintage and the construction techniques employed. Construction specifications are shown in Table 5.2.1-1. Pipeline defects or weaknesses that may be inherent in older pipeline are detected through a combination of in-line inspections or cathodic protection surveys. In-line inspection techniques can detect areas of metal loss caused by poor coating quality or pre-mature deterioration. Depth of Cover Surveys can identify areas that were initially laid to depths that could present an integrity issue today. Similar to the discussion on pipe manufacturing techniques, the methods for welding pipe joints have improved over the years. Girth welds today must pass a more stringent inspection than welds from the original construction of the pipeline. Standards of acceptability of girth weld imperfections have changed. Welding standards such as API 1104 (incorporated by reference into 49 CFR Part 195) specify additional and different potential weld defects to be repaired than the standards from 1950. However, some welding specifications and options for welder tests were a part of the original Humble Oil Company construction specifications for the subject pipeline. Pressure testing conducted as part of the pre-startup mitigation activities from 2000 – 2004 was designed to detect any injurious defects such as girth weld defects that could lead to future integrity issues. Arc burns, created during welding, are of concern due to the possibility of small cracks forming around the “hard spot” which might be created from the arc burn. Identified arc burns are to be repaired as required by the SIP. The TFI tool inspections were designed to detect cracks. All cracks and crack-like indications were repaired following completion of the inspection. A concern investigated in 1999 EA was the potential existence of non-steel components in the older portions of the pipeline. Specifically, the possible use of cast-iron type materials, which are weaker than steel, was investigated. Valves and pumps were refurbished prior to startup by a national contractor specializing in such activities for the pipeline industry. No non-steel components were identified. 5.2.4 Countering Age Effects Potential effects of age are countered through a formal integrity management program, which exists in the form of the SIP (which includes the LMP). This program includes practices for identifying weaknesses in materials, flaws in damage prevention programs, and specifying appropriate responses. Future inspection and testing is driven by the ORA. If the potential age- related effects are properly controlled, the design life of pipeline steel is considered indefinite. 5-9 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.2.5 Maintenance Repairs and Rehabilitation The major maintenance activities conducted on the System consist of repairs or replacement of the following: • CP system rectifiers and electrical circuitry; • Test leads attached to the pipe; • Casings and casing/pipe electrical isolation for road and railroad crossings; • Pipe protective coatings, including paint on aboveground pipe and components; • Pipe segments; • Block and check valves; • Pressure and temperature sensors; • Pipe bridge supports for elevated stream crossings; and • Pump station equipment, including pumps, valves, pipe and fittings, instrumentation, controls, and tanks. Magellan, as directed by the LMP, conducted numerous mitigation and rehabilitation projects along the Longhorn Pipeline. These projects, known as Longhorn Mitigation Commitments (LMCs), are summarized in Appendix 9B. LMC 3 required the replacement of approximately 19 miles of the existing pipeline over the Edwards Aquifer Recharge and Contributing zones in the Austin area with thick walled pipe; the pipe was buried to a minimum depth of 5 feet and protected by a concrete barrier cap. The pipe replacement included a segment over a three-mile reach of the Edwards Aquifer Recharge Zone, a segment east of the Edwards Aquifer Recharge Zone, and across the Edwards Aquifer Contributing Zone (approximately from MP 185.6 to MP 188.8) to the boundary of the Barton Creek Watershed. This measure was completed prior to startup of the System (2005). Per LMC 5, shallow or exposed pipe at 12 locations (including Marble Creek) was mitigated. Certain sites listed in the LMP occurred within the Edwards Aquifer Recharge and Contributing Zones (see above). The Marble Creek crossing was refurbished and replaced with new pipe. This measure was completed prior to startup (2005). As detailed in Appendix 9B, per LMC 6, various stopple fittings were removed prior to startup. Per LMC 7, pipe at two locations, near Satsuma Station and in Waller County were replaced as indicated by the 1995 ILI. This measure was completed prior to startup. Per LMC 8, pipe at the Rabb’s Creek crossing was replaced and appropriate repairs were made at five dent locations identified by the 1995 ILI. This was completed prior to startup. Per the LCRA Settlement Agreement, and LMC 3, Magellan replaced approximately six miles of existing pipeline in the Pedernales watershed that is characterized as having a time of travel for a spill from Lake Travis of eight hours or less. The pipeline segment replacement crossing the Pedernales River was completed prior to startup. Horizontal directional drill construction methods were used to install the section of pipe under the Pedernales River. 5-10 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.2.6 Facilities 5.2.6.1 Tanks All tanks and related equipment are required to be constructed in accordance with industry standard American Petroleum Institute 650—Welded Steel Tanks for Oil Storage; American Petroleum Institute 651 – CP of Aboveground Petroleum Storage Tanks; American Petroleum Institute 2000 – Venting Atmospheric and Low Pressure Storage Tanks; American Petroleum Institute 2003 – Protection Against Ignitions Arising Out of Static, Lightning, and Stray Currents; American Petroleum Institute 2350 – Overfill Protection for Storage Tanks in Petroleum Facilities; and National Fire Protection Association (NFPA) 30 – Flammable and Combustible Liquids Code. The main purpose of the Tank Maintenance Inspection Program is to inspect all tanks in accordance with American Petroleum Institute 653 inspection requirements and make recommendations on necessary repairs to ensure the integrity of the tanks. Under PHMSA tank rules, an annual inspection is required. PHMSA (as part of its responsibilities under 49 CFR Part 195) periodically audits the performance of Magellan’s tank maintenance program. PHMSA previously identified deficiencies were corrected in a timely manner. No unresolved issues remain from past audits. 5.2.6.1.1 External or In-Service Inspections All tanks are given a visual external inspection by an inspector certified in American Petroleum Institute 653. This inspection is conducted at least every five years or at the quarter corrosion rate life of the shell, whichever is less. The inspection includes a survey of the tank for settlement activity, measurement of the shell thickness for corrosion, inspection of vents, inspection for tank shell damage, floating roof inspection, fixed roof inspection, etc. The inspection is performed by an American Petroleum Institute 653 certified inspector and documented on an In-Service Inspection Form. The forms are retained in the records of the Tank Maintenance Department. 5.2.6.1.2 Internal or Out-of-Service Inspection All tanks are given a formal internal inspection to ensure the integrity of the tank bottom. This inspection is initially conducted after ten years of operation. Subsequent inspections are established in accordance with American Petroleum Institute 653. The inspection is performed by inspectors certified pursuant to API 653 and documented on an Out-of-Service Inspection Form. A copy of the documentation is retained in the Tank Maintenance Department’s records. 5.2.6.2 Pump Stations Pump stations and valves are part of the System and significant to System integrity. The factors affecting the integrity of the existing pump stations and mainline valves on the pipeline from Galena Park to Crane are discussed and described in this section. Pump stations and valves 5-11 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL are discussed separately from the pipe portions of the pipeline. They consist of equipment items and configurations that can be examined individually to evaluate their integrity and potential risk. The purpose of pump stations along the pipeline is to provide the driving force to maintain liquid product flow at a desired flow rate through the pipeline. Pump stations are located along the pipeline at distances that are primarily determined by the pipeline elevation profile, the product characteristics, and the desired product flow rate. The liquid product enters each station at a relatively low pressure, and the pressure is increased through the station pumps. Currently there exist four pump stations from Galena Park to Crane. In a pump station, the product enters from the upstream side of the station and passes through a strainer to remove any entrained particulate matter. The product then passes successively through the two pumps in series where the pressure is increased to the level needed to maintain the desired flow rate to the next downstream pump station. The pressure at the outlet of the second pump is regulated by a pressure control valve to prevent excessively high pressure in the pipeline. The outlet pressure is regulated at or below the MOP. Check valves in each pump bypass line and in the mainline bypass line prevent recirculation or reverse flow of the product back through the pipeline in the event of a pump shutdown or valve closure. These check valves also permit the product to bypass either or both of the pumps. Other major equipment present at some or all of the pump stations include relief and storage tanks, booster pumps, scraper (pig) launchers and receivers, meter provers, pressure relief tanks, and sump tanks. Scraper launchers and/or receivers are installed at eight sites. These launchers and receivers are used for pigging. All of the pumps are centrifugal models equipped with single mechanical seals. The pumps are all driven by weather-protected Type II electric motors. The electrical systems and circuits are designed to meet or exceed National Electric Code and Underwriters Laboratory specifications to protect against ignition in hazardous atmospheres. Most of the valves of interest to System integrity are large block or control valves in the size range of 10 to 20 inches. There are also a number of small valves, usually one inch or less in size, associated with instrumentation, and particularly, with thermal safety valves (TSVs). TSVs are installed on any segment of pipe in liquid service that could be blocked in under any circumstance. A blocked-in segment of line could be heated by the sun, ambient air, or other sources. The liquid within the pipe segment could expand and, without the TSVs, could cause the pipe or associated valves to rupture. Pressure due to liquid expansion causes a TSV to open and drain liquid to the sump tank, thus preventing damage and a possible release of product. 5.2.6.3 Mainline Block Valves There are both block and check valves located on the Longhorn Pipeline. Block valves are located at pump stations and other strategic points along the pipeline. Block valves are placed to minimize draindown during maintenance and to minimize potential spill volumes. Check 5-12 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL valves prevent back flow and draindown in the event of an upstream failure or a flow reversal. The characteristics and locations of these valves are described and discussed in this section. Also presented are estimated maximum leak/spill volumes for selected sensitive locations. The location and types of mainline valves on the existing Longhorn Pipeline are listed in Table 5.2.6-1 and illustrated on the valve schematic contained in Appendix 5B. The valves on the section of the pipeline between the Galena Park and Satsuma stations are 20 inches in diameter. The mainline valves located west of Satsuma Station are 18 inches in diameter. All valves are constructed of steel and have an ANSI rating of 600. The valves are manufactured by companies such as Daniels, Cooper, WKM, US Steel, and Kerotest. Closure time for the remotely controlled block valves ranges from 90 seconds to 3.2 minutes depending on supplier and model (Willbros, 1998). Closure rates have implications for surge potential. Risk and evaluation of future surge potential is discussed in Section 6.2.1.3. The mainline valves are installed in locations that can isolate the pumping stations, protect certain environmentally sensitive areas, or isolate sections in long segments of the pipeline unbroken by pumping stations. There are remote-controlled valves on the eastern (currently upstream) side of several environmentally sensitive area crossings. In the current configuration, these valves were often paired with a check valve and a manually operated valve on the downstream side of the crossings. In the event of a pipeline leak in the sensitive areas, valves can prevent additional drainage from upstream and downstream sections of the pipeline into the sensitive areas, when such valves are closed in a timely manner. Prior to start-up and per LMC 22, a study was conducted to quantify the benefits of additional check valves. The Valve Study was performed by APR Companies and included recommendations for the installation of seven (7) additional check valves. Additionally per the LCRA Settlement agreement, nine additional check valves and two valves were relocated at locations through the Colorado, Pedernales, Llano, and San Saba River Basins to limit maximum drain down volumes. Table 5.2.6-2 illustrates valves installed per LMC 22 and the LCRA Settlement agreement. These valves were installed to minimize drain down and the potential consequences of a leak. Table 5.2.6-3 illustrates potential maximum release volumes under the Proposed Project. 5.3 NORMAL OPERATIONS PHMSA regulations require that liquid pipeline companies prepare and follow a manual of written procedures for conducting normal operations and maintenance activities and for managing abnormal operations and emergency situations. Operation and maintenance of the System follows the guidelines set forth in the SIP. The SIP incorporates PHMSA, OSHA, EPA, and company requirements. The procedures found in the Longhorn System Integrity Plan (LPSIP), which are documented in the LMP has been integrated into the SIP Procedures. Surveys and studies that were performed in advance of the 1999 EA include: 5-13 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • Depth-of-Cover Survey • Exposed Pipe Survey • CP/CIS • Seismic activity • Scour, erosion, flood potential at selected stream and river crossings • Span evaluations • Landslide potential • Root cause analyses These analyses provided data for Longhorn’s Risk Assessment and Integrity Management Programs. They also provide Magellan with data to design and implement corrective actions and to identify and resolve potential issues. Updates to these investigations are on-going as is evidenced in relevant procedures in the SIP and their inclusion in the annual ORAs. The procedures processes, programs within the SIP are designed to mitigate threats associated with the following: • Commodity Characteristics • Internal Corrosion • Hydrogen Blistering • Surge and Hydraulic Profile • Cracking • Stress Corrosion Cracking • Incorrect Operations • Security • Atmospheric Corrosion • External Corrosion • Third Party Damage • External Forces 5.3.1 Threats 5.3.1.1 Commodity Characteristics The pipeline system currently transports refined petroleum products (e.g. gasoline and distillates) which the following programs are designed to address. 5.3.1.2 Internal Corrosion Magellan’s Corrosion Control Program (SIP-ADM 7.04–001) in Element 7 of the SIP (Appendix 5A) contains procedures for addressing internal corrosion and for compliance with 49 CFR Part 195.579. Mitigation includes running cleaning pigs twice a year or more often as needed in refined product service to remove corrosive components and free water. Corrosion inhibitors are 5-14 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL injected at product origins to mitigate any corrosive effects of the product. Corrosion coupons or other types of monitoring are used to determine the effectiveness of the inhibitor and the potential extent of any corrosion. At least three times each calendar year, and not exceeding intervals of 4.5 months, corrosion coupons are removed from the test locations and forwarded to an appropriate laboratory for corrosion analysis. Coupon corrosion rates over 1 mpy of general corrosion or pitting (including MIC) trigger a detailed analysis directed by NACE certified corrosion control personnel. This analysis includes a review of incoming product quality sample data, inhibitor injection rates, bacteria testing and, if necessary, inhibitor performance testing. Deficiencies are required to be resolved within six (6) months of discovery, except those that present a more urgent threat to pipeline integrity are corrected immediately. As discussed in Section 5.3.5, Magellan has conducted inspections utilizing three different types of intelligent in-line inspection tools (ILI) to detect and subsequently mitigate any affects of past damages caused by internal corrosion. Table 5.3.1-1 provides details of the inspections conducted and Table 5.3.1-2 provides details of the findings and subsequent repairs made to each segment of the system. Results from a 2007 in-line inspection of the Crane to El Paso segment revealed internal corrosion damages along portions of an 84-mile portion of the line. Forty-two miles of that segment had damages severe enough to warrant immediate pressure reduction and eventual pipe replacement. This finding was unexpected based upon the fact that the pipe was relatively new having been installed in 1998. There was no evidence that this internal metal loss damage occurred during operation of the pipeline since startup in 2005. Magellan engaged expert consultants to evaluate the corrosion. Potential for MIC, an often accelerated corrosion rate mechanism, was identified. The investigation revealed that the corrosion damage most likely occurred due to initial hydrostatic test water that was allowed to remain in the pipe in low lying areas. Bacteria grew in this water and ultimately caused MIC. Since the pipeline was not commissioned until years later severe internal corrosion occurred. Proper drying and conditioning of the pipe would have most likely prevented this damage. Magellan modified pressure testing procedures to heighten awareness that extensive corrosion can occur following hydrostatic testing. UT inspections were conducted on a quarterly basis from 2007 to 2011 at two locations along the 42-mile segment. No measurable corrosion growth was detected in this process. 5.3.1.3 Hydrogen Blistering A hydrogen blister is defined as a bulging of the internal or external pipe wall from the accumulation of hydrogen pressure within a lamination or inclusion in the pipe wall. This pressure is sufficient to deform the pipe wall locally. Cracking can occur if the pressure-induced stresses are high enough. A lamination is defined as a plane of non-fusion within the steel plate that occurs during the manufacturing process. The lamination can be parallel to the inner and outer surfaces of the 5-15 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL pipe, inclined or sloping with respect to the inner and outer pipe surfaces. A lamination can also be surface breaking or can occur in a stepwise manner through the wall thickness. If pipe wall bulging is present at a lamination, it is considered a hydrogen blister. The history of the 20 inch and 18 inch pipe previously in crude oil service prior to 1995 (valve J- 1 at MP 9.1 to Crane) indicates that no pipe lamination or hydrogen blister failures occurred during service. However, hydrostatic testing prior to start-up in 2005 indicated the presence of pipe laminations and hydrogen blistering at pipe laminations in the 18 inch segment from Satsuma to Crane. The possibility of existing blisters represents a potential anomaly for the Longhorn Pipeline system that could be adversely affected by pressure cycle induced fatigue discussed further in Section 5.3.1.5. To mitigate the threat of existing blister growing in service due to pressure cycle fatigue cracking, LMC 12 required an in-line inspection of the existing pipeline from Galena Park to Crane with an ultrasonic (UT) wall measurement tool. The results of this inspection are further discussed in Section 5.3.5.2. The re-introduction of sour crude oil to the pipeline present a new threat of laminations growing into hydrogen blisters. This new threat as a result of the Proposed Project is further discussed in Section 6.3.1.2. 5.3.1.4 Surge and Hydraulic Profile The pressures generated by pumping (including flow resistance) and the pressures created by topography (elevation) effects combine to form a hydraulic profile. Pressures are controlled to a level at or below MOP under normal operations. Surge pressures are created when a moving fluid is suddenly brought to a halt. The kinetic (moving) energy is converted to potential energy, resulting in an increase in pressure and the creation of a pressure wave. In a fluid-filled pipeline, a positive pressure wave is propagated upstream of the point where the fluid flow is interrupted. Flow interruptions in a pipeline are usually due to valve closures or pump shutdowns. A negative pressure wave travels downstream from the point of interruption. The pressure can decrease below the vapor pressure of the liquid, and some of the liquid can vaporize, forming vapor cavities. Each cavity may be large enough to separate the liquid into two segments. When the pressure in the system equalizes, the vapor cavity will collapse. The velocities of the liquid can be very high during these collapses, producing a significant pressure wave. Applicable sections of 49 CFR Part 195 prohibit operating pressures from exceeding 110% of MOP during surge or abnormal operating conditions. The LMP specifies that the normally allowable temporary exceedance of MOP under surge conditions not be allowed to occur in Tier 3 (hypersensitive) areas. This means that in those areas, surge pressures are controlled to a level lower than in other segments of the System and also below common industry practice. Per LMC 31, Magellan performs a surge pressure analysis prior to any change in the system that has the capacity to cause surge pressure to occur on the system. Magellan is required to submit mitigation measures acceptable to PHMSA prior to any such change in the system. 5-16 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Submitted mitigation measures must adequately address any maximum allowable surge pressures on the system identified by the surge pressure analysis. Magellan follows 49 CFR Part 195 in determining MOP as the minimum of the following: • The maximum internal pressure that does not generate stresses in excess of 72% of pipe yield • 80% of the minimum test pressure • Component pressure rating OR 80% of the factory test pressure or prototype test pressure of a component Magellan’s processes related to safe pressures are designed to ensure that pressure containing capabilities for all pipe conditions as identified by ILI tools or integrity tests are documented and compared to safe allowable operating pressure to ensure that such features are not over pressured. Discharge pressure of operating pump stations are set to ensure that 100% of MOP is not exceeded during normal operating conditions for any portion of the line. Surge pressure analyses are completed to ensure that for worst-case operating conditions, surge pressure can’t exceed the limits as defined within the LMP. This calculation is completed on 07-FORM-0746. Upon completion of an integrity assessment, an analysis is completed for all metal loss anomalies with Rupture Pressure Ratio (RPR) less than 1.00 to identify the discrete point pressures of the anomaly (DPP, PDPP) per 7.03-ADM-007, ILI Analysis Guidelines (Appendix 5A). An RPR equal to 1.0 corresponds to a predicted burst stress equal to the Specified Minimum Yield Strength of the pipe. This analysis takes into account discharge pump station set points, elevation differences, and surge conditions to determine the maximum pressure achievable at each specific defect location. For each feature location the design pressure for the line and the upstream pump’s maximum discharge set point is determined. The maximum elevation difference between the pressure source and the feature location combined with the specific gravity of heaviest product is utilized to determine the static head pressure due to elevation change. The calculated static head pressure is then added to the pump set point to get maximum pressure at the feature location due to static head. A surge analysis is then conducted for the feature location to determine maximum pressure due to surge. The static head and surge maximum pressures at each feature location are then compared. The engineer will then select the greater value to determine the maximum pressure at each location. This value is used as PDPP for the anomaly location. Any feature with a calculated remaining strength or burst pressure (PBURST) less than PDPP is repaired as an immediate condition. Additionally any feature with a PBURST multiplied by 72% (PSAFE) less than PDPP is repaired as a 180-day condition. This procedure is repeated for any unrepaired features when an operating pressure increase is considered in accordance with 7.07-ADM-002 (Appendix 5A). Any features that require repair are mitigated prior to the pressure increase. 5-17 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.3.1.5 Cracking/Fatigue Monitoring Fatigue, caused by cycles of applied stress, can result in crack initiation, activation, and propagation. Internal pressure fluctuations during pipeline operation over long periods of time are the main source of fatigue for most pipelines. Non-service-related fatigue loadings (such as traffic over roadway crossings) are normally of minor magnitude and are not typically thought to contribute significantly to fatigue stresses except in special circumstances. Fatigue effects can be predicted and, therefore, controlled to a large extent. Material selection, pressure testing, load cycle monitoring, and ILI with crack detection tools are the primary means by which fatigue failures are prevented. Manufacturing defects in or immediately adjacent to the longitudinal ERW or EFW seams of the 1950 line-pipe material are a source of seam cracks. These defects that may be initially too small to fail at the operating or test pressures will grow through fatigue cracking driven by pressure cycling and become large enough to cause a failure if exposed to sufficient numbers of large pressure fluctuations. The ORA Process Manual requires monitoring of pressure cycles during the operation of the pipeline, calculating the worst-case crack growth in response to the pressure cycles, and reassessing the integrity of the pipeline at appropriate intervals to find and eliminate growing cracks before they become large enough to cause a failure of the pipeline. Table 5.3.1-3 shows results of calculations from the 2010 ORA which identified the shortest time to failure of 92.1 years for Case 7 for the section of pipe from MP 295.2 to 405.1. Cases 4 and 6 are the only two other sections which show reassessment intervals less than 100 years. In accordance with LMC 10, Longhorn conducted an ILI and subsequent remediation with a TFI tool designed to detect cracks and other manufacturing defects in the longitudinal seam weld. These inspections were completed by January 2008. In accordance with LMC 12, Magellan conducted an ILI and subsequent remediation of the existing pipeline from Galena Park to Crane with an ultrasonic (UT) measurement tool. These inspections were completed by July 2010. The UT tool is designed to detect laminations and blistering of laminations which can lead to cracking. 5.3.1.6 Stress Corrosion Cracking (SCC) Modification to pressure cycle frequencies and intensities affects the threat of SCC. It is prudent to retain SCC as a possible threat. Magellan conducts Non-Destructive Examination (NDE) to examine for the presence of SCC through magnetic particle inspections. Magellan has not detected any indications of SCC. 5-18 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.3.1.7 Incorrect Operations As part of LMC 3.5, the incorrect operations mitigation program focuses on design, construction, maintenance and operations to reduce the likelihood of human error. Incidents are tracked and discussed to identify opportunities for improvement. 5.3.1.8 Security Magellan’s existing procedures include provisions to address appropriate security measures as defined in SIP-ADM-8.01 (Appendix 5A). This initiative provides a framework that complies with the security regulations to protect the assets, employees, the environment, stakeholders, and the community from security threats. 5.3.1.9 Atmospheric Corrosion A relatively slow rate of metal loss is normally associated with atmospheric corrosion. The ability to inspect most exposures reduces threats to integrity from this failure mechanism. Experience, however, indicates that certain areas require special inspections to monitor corrosion. These areas include casings, splash zones, insulation, below-grade chambers, and supports. Preventative measures most often employed are the application and maintenance of a protective paint coating. Magellan’s corrosion procedures are provided in SIP-ADM-7.04 (Appendix 5A), and contain special procedures to address these areas. The atmospheric corrosion procedures require Magellan to: • Identify all above grade and above water line structures/facilities or parts of structures/facilities as subject for atmospheric corrosion inspection. • Evaluate all facility above ground structures every year or more often as needed. This is 3 times the frequency required by regulation. Evaluate utilizing the SSPC-VIS-2; Standard Method for Evaluating Degree of Rusting on Painted Steel Surfaces, General Rusting Standard. Particular attention is given to pipe and soil to air interface areas, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water. • Maintain a listing of all subject areas, including GPS coordinates, and updated as needed in the CP Data Manager. • Some structures/facilities with corresponding inspection requirements are: - Pump stations, measuring stations, storage vessels and tankage, and miscellaneous facilities (building, structure, piping and equipment); - Initially buried pipe or related facilities now exposed to the atmosphere due to intentional or unintentional reasons (i.e., erosion, subsidence, etc.); - Pipe spans (supported and unsupported); - Suspension bridges (piping and structure); - Above-grade pipeline valves, expansion loops, and associated piping; 5-19 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL - Below-grade facilities in casings, vaults, or ‘cans’ (corrugated metal valve chambers, etc.); and - Some valves on the System are located in below ground chambers which can have higher corrosion potential due to alternately wet-dry conditions. 5.3.1.10 External Corrosion The corrosion control program, as further detailed in the System Integrity Plan (SIP), provides for ongoing maintenance and evaluation of corrosion. The program addresses the monitoring and mitigation of special forms of corrosion such as microbiological induced corrosion (MIC), alternating current (AC) induced, stray current, selective seam corrosion, stress corrosion cracking (SCC), internal corrosion. Corrosion is time dependent and strongly influenced by the environmental conditions near the pipe. It is reasonable to assume that without proper mitigation, that with increasing passage of time the opportunity for corrosion damage increases. Corrosion prevention measures can also be time-sensitive. In external corrosion control, the degree to which a coating system is susceptible to age-related deterioration varies according to the type of coating and its environment. Coating advancements have led to many improvements in the coating products and applications both in the mill and in the field during construction. Some coatings are more susceptible to disbondment, mechanical abrasion, and chemical reaction. The CP system can also diminish in effectiveness as anode materials are consumed. SIP–ADM 7.04 (Appendix 5A) provides processes to evaluate the effectiveness of CP systems. Additionally, pipeline inspection and rehabilitation procedures are able to detect any areas of metal loss caused by coating damage. Any deficiencies are mitigated in a timely manner in accordance with regulatory and SIP requirements. Prior to startup, CP systems were assessed and mitigated by the installation of ground beds, performance of interference testing, coating replacement and mitigation of casings as identified by CP surveys. Additionally, close interval pipeline surveys were completed for hypersensitive areas and any pipeline segments not previously surveyed. Any corrosion-related conditions were remediated prior to startup. The potential for external corrosion for buried steel pipe depends on numerous factors including: • Corrosivity of the soil • Presence of bacteria promoting MIC • Potential for AC induction • Potential for selective seam corrosion • Condition of the coating, evidenced by: - Coating age and type; - Quality of application and care during installation - Damage potential (i.e., soil movements, lightning strikes, etc.) 5-20 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL - CP current density requirements; and - Visual inspections. • Effectiveness of CP system, evidenced by: - Annual CP survey pipe-to-soil potentials; - CIS pipe-to-soil potentials; - Coating disbondment potential; - Coating shielding potential; and - ILI findings. • Interference potential, depending on: - Nearby utilities; - Presence of casings; and - Other nearby buried structures. Corrosion induced metal loss damages to the exterior pipe wall occur when both the coating and CP fail in the presence of a corrosive environment. These damages are detected by ILI and repairs to both coating and CP are made as required. Occurrences of external metal loss damages, presumably from external corrosion are identified in each of the three ILI’s (MFL, TFI, and UT). The frequency and dimensions of damage detected are noted by the ILI’s. These ILI findings are discussed in Section 5.3.5.2.1. For each metal loss feature excavated, pipe to soil potential are measured to determine whether or not CP is adequate for the location. If deficiencies are identified, remedial measures are completed to ensure protection levels are obtained and to insure further metal loss damage does not occur. Corrosion pits were detected and subsequently repaired during year 2000 pressure test. High resolution MFL tools and Ultrasonic Wall Measurement Tools (UT) can detect pitting corrosion anomalies with good accuracy and these inspections are routinely conducted. Pinhole corrosion pitting represents a more specialized manifestation of corrosion, characterized as having short length and width (less than 0.4 inch). Pinholes can be difficult to detect if not in the presence of larger areas of pitting corrosion. It is rare to encounter pinhole corrosion without the presence of other highly detectable corrosion features. Longhorn has not experienced any pinhole corrosion of this kind. Pinhole corrosion is most often associated with larger areas of pitting corrosion that are easily detectable by common ILI tools. 5.3.1.10.1 Pipe Coating. Coatings prevent an electrolyte such as water and/or soil from making direct contact with the pipe steel, thus eliminating the electrolytic path necessary for corrosion to occur. Coating for the newer constructed sections of pipe consists of fusion-bonded epoxy (14 to 16 mils). Lilly 2040 Topcoat was used where additional coating protection was necessary, such as crossings. Coatings on the refurbished 18-inch and 20-inch diameter pipeline consist of hot coal tar, asbestos felt, and glass fiber. According to construction specifications, precautions were taken in handling, bending, and backfilling the pipe to maintain the integrity of the coating. 5-21 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL The fusion-bonded epoxy coating is applied to newer portions of the line. The original coal tar coating, applied on the older portions of the line, was a widely used design and has proven to have a long life span in many cases. Coatings are susceptible to age-related deterioration from mechanical abrasion and chemical reaction from absorption of gases and liquids. Existing corrosion control and integrity management procedures are designed to mitigate the effects of any deterioration. Evidence of the current coating condition is found through visual inspection reports, pipe-to-soil potential surveys, and detection of previous corrosion damages through in- line inspection. 5.3.1.10.2 Cathodic Protection CP provides an additional method of protection from corrosion. CP is the application of direct- current electricity from an external source to oppose the discharge of corrosion current from anodic areas. When a CP system is properly installed, all portions of the protected structure (pipeline) collect current from the surrounding electrolyte (soil), and the entire exposed surface becomes cathodic. Protective currents are provided from electrically connected anodes or from an alternating current/direct current rectifier in conjunction with anodes. Anode beds have a design life, become depleted over time, and must be replaced. Depleted anode beds are detected by changes in CP and rectifier readings. The original number and location of these systems is based on calculated demand for CP current. Additional systems are added as necessary to maintain adequate CP on the pipeline and associated facilities. CP on interstate hazardous liquid pipelines has been mandated by DOT since 1973. A CP system is in place for the refurbished 18-inch and 20-inch diameter pipeline. Impressed current CP systems are detailed in SIP-ADM-7.04 (Appendix 5A) and include the design and installation of various configurations of CP systems. Part of the maintenance of the System requires periodic replacement of inadequate anode beds. The effectiveness of the CP system depends on the sufficiency of the voltage and current provided along the pipeline. Periodic measurements of the voltage between the pipe and the soil are required to verify the adequacy of the CP. Test leads or stations, installed at fixed locations along the pipeline, are used for annual or semi-annual measurements of pipe-to-soil voltages. These test stations consist of electrical wire connected to the pipe and brought to the top of the ground over the pipe. Magellan conducts pipe-to-soil potential surveys at test lead locations semi-annually over sensitive and hypersensitive areas which is twice the frequency required by 49 CFR Part 195.416 (LMP Section 3.5.1.). Rectifiers, installed to provide the CP current, are inspected monthly which is also twice the frequency required by regulation. Detailed procedures for execution of corrosion monitoring and testing are in the SIP-ADM-7.04 (Appendix 5A). An ‘exception’ is a voltage potential reading below an established criteria of -0.85 volts. Table 5.3.1-4 summarizes test point exceptions for the 2011 calendar year inspections. Magellan manages exceptions in accordance with the LMP and Part 195.452. Magellan’s Corrosion Control Program limits CP to a negative 1.2 volts to prevent excessive voltages. A voltage level 5-22 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL that is too high electrolyzes water, resulting in hydrogen (H2) liberation on any exposed pipeline metal. Close Interval Surveys record voltage readings at intervals shorter than test lead intervals and are conducted periodically in hypersensitive (Tier 3) areas per the LMP. The CIS interval is usually from 3 to 15 feet along the pipeline. Since corrosion problems can be localized, CIS increases the opportunity for detecting potential problems compared with test lead station readings. This is especially important in the ability to detect interferences. Protocol dictating when and where CIS is conducted is found in LMP for Tier 3 areas and in SIP-ADM-7.04 (Appendix 5A) for all other areas. The following lengths of System were inspected on the dates shown. Longhorn Pipeline CIS 2006-2011 Survey Year Survey Date Range Tier 3 Miles Surveyed Total Miles Surveyed Comment 2006 February 21.98 112 2007 March to May 21.98 22.79 2008 February & March 21.98 30 2009 April & May 21.98 35 2010 June & July 21.98 37 2011 July & August 29.17 46 East Houston tie-in changes Prior to 2011, there was a total of 21.98 miles of Tier 3 and 100% of this was inspected each year per LMP requirements. In 2011, with the addition of pipe connecting to the East Houston Terminal, additional Tier 3 mileage was added to the system and 100% of this was inspected resulting in a total of 29.17 miles surveyed. CIS is not specifically mandated by regulations. In addition to pipe-to-soil surveys, ILI also provides evidence of corrosion control effectiveness. For each metal loss feature excavated, pipe to soil potential are measured to determine whether or not CP is adequate for the location. If deficiencies are identified, remedial measures are completed to ensure protection levels are obtained. Some ILI tools can infer potential interferences from nearby metal pipelines or structures. The presence of nearby buried metal can be detected by the magnetic flux leakage ILI tool. 5.3.1.10.3 IR Drop (CP Voltage Measurement Criteria) A generally accepted criterion for CP pipe-to-soil voltage readings, as measured by a copper- copper sulfate reference electrode, is at least -0.85 volts at the pipe-to-electrolyte boundary. A more positive reading indicates decreased protection. The actual practice of ensuring adequate levels of CP is often more complex than this simple criterion. Readings must be carefully interpreted in light of the measurement system used. The reading of interest is the pipe-to-soil potential directly at the pipe-soil interface. Since this reading cannot practically be taken directly, 5-23 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL a reading at the surface is taken and adjusted to reflect the reading at the pipe-soil interface. The adjustment from readings taken to reading of interest is often termed “IR compensation,” with the implication that "IR" or "IR drop" is the part of the voltage reading that should not be considered in assessing the adequacy of CP. The surface readings can be taken with the impressed electric current supply to the System turned either “on” or “instant off.” The IR drop subtracts the voltage drop through the soil from the reading to yield the “true value” of the pipe- to-reference electrode potential. The -0.85 volt is usually considered a conservative criterion since a safety margin is already included for most soil conditions. Magellan’s corrosion control program (SIP-ADM 7.04-001, Appendix 5A) in Element 7 of the SIP contains procedures for addressing CP criteria including consideration for IR drop. Corrosion Control Program in part provides the following (SIP-ADM 7.04-006, Appendix 5A): 2.4.1 IR drop is considered by taking potential readings directly over or as near as practical to the structure surface. The effect on the potential measuring circuit is kept to a minimum by using a high resistance volt meter and being mindful of lead lengths and the condition, contact to structure and contact to electrolyte. Furthermore, CP levels are to be evaluated utilizing CP criteria (SIP-ADM 7.04-006, Appendix 5A). Within the procedure are defined methods for considering the effects of IRF drop including the use of: • High resistance voltmeter • Historical operating information • Reference cell placement • Calculation • Current interruption • Buried coupons In addition to deficient CP voltage, excess voltage can also be a concern. In order to avoid excess voltage, Magellan uses negative 1.2 volts as a limit on pipe-to-soil potentials as an informal guideline. Episodes of more negative voltage potential are individually evaluated and mitigated. 5.3.1.10.4 Casings Casings were originally installed as a means to reduce the effects of vehicle loadings on the buried pipe, to provide a path for leaks to be routed and detected without damaging the road or railroad structure, and to facilitate less intrusive pipe replacements. Casings have the potential to: 1) act as a shield so that protective CP currents cannot reach the carrier pipe, 2) create an environment for unobservable atmospheric corrosion, 3) create an opportunity for a “short circuit” in which the carrier pipe becomes anodic to the casing pipe and accelerated corrosion occurs on the carrier pipe. In much of today’s construction practices, the use of casings is avoided. 5-24 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Casings are checked annually in Tier 1 areas and semi-annually in Tier 2 and 3 areas to ensure that they are not interfering with CP by being in an electrically shorted condition. If a short is verified, an action plan is developed to clear the short within timeframes specified within the LMP. There is one-half mile of pipe encased in plastic casing through the Edwards Aquifer (Ref SBRMA 2006) that was identified in early reviews (2006) as needing specific corrosion control procedures. Magellan has developed and implemented SIP procedure 7.05-ADM-037, HDPE Inspection and Dewatering Procedure, for this purpose. The procedure ensures that the casing remains free of water through inspections at weekly intervals not to exceed 10 days and following any rainfall event in excess of 0.1 inches, for the presence of water and hydrocarbon vapors. Any water discovered is removed and analyzed. 5.3.1.10.5 Microbiologically Influenced Corrosion (MIC) As defined within the Corrosion Control Program, 7.04-ADM-001 (Appendix 5A), in the event that the pipeline system experiences one or more confirmed discoveries of injurious MIC, or where accelerated corrosion from MIC is anticipated, a Bacteria Testing Protocol will be established to evaluate future integrity threats from MIC. The line specific protocol will be utilized until such time that the threat from MIC has been assessed and appropriate mitigation actions have been taken. Testing for MIC shall be conducted in accordance with Bacteria Testing – Serial Dilution Method. External MIC has not been identified on the Longhorn Pipeline. 5.3.1.10.6 AC Induced Corrosion. Where pipelines are parallel to high voltage overhead lines for some distance high AC voltage can be induced into the pipeline. Under certain conditions the AC current, as it diverts from the steel into the soil, can lead to AC induced corrosion. AC induced corrosion has occurred along isolated portions of a nine-mile segment in the Houston area. The potential for AC induced corrosion is a function of proximity to sources of AC, source strength, configuration relative to pipeline, soil characteristics, pipe coating, and other factors. Newer coatings tend to make pipe more susceptible to AC induced corrosion. A study was completed to determine where AC induced currents exceeded criteria. As a result of the study, mitigation measures were employed through the installation of zinc anode beds. The CP Database was updated to include any locations for the entire Longhorn system where potential for AC induced corrosion occurs due to proximity of High Voltage Alternating Current Systems. SIP-7.04-ADM-023 procedure (Appendix 5A) was developed and implemented to identify and mitigate areas of induced AC. AC voltage readings are taken at over 30 points along the System, as part of this procedure. Magellan continues to monitor these locations annually as a part of ongoing CP system maintenance. 5-25 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.3.1.10.7 Stray Currents Magellan manages the threat of metal in close proximity to a buried pipeline through foreign line crossing surveys. One potential effect of nearby buried metallic structures or especially those with their own CP systems is to divert electric current from the pipeline that is being protected. Such impacts on CP systems from other buried metals or foreign CP systems are referred to as “interferences.” Stray current corrosion can occur when nearby CP systems interfere and cause one of the protected metallic structures to become anodic to the other. This can cause localized and rapid metal loss. Owners of pipelines, whose CP systems have been found to be interfering, normally cooperate by installing bonds between the systems. Some of these are termed 'critical bonds' indicating that serious CP system malfunction is possible upon damage to the bond. Magellan inspects critical bonds at least six times each calendar year, but with intervals not exceeding 2 ½ months. DC stray current was suspected as the cause of corrosion for two leaks that were detected near MP 351. The first leak was identified during the hydrotesting before start-up, and the second was detected during a repair when a corrosion anomaly started leaking after the area was grit blasted. Although neither anomaly was reportable to PHMSA because they did not fail in- service, they did highlight the potential for stray currents in the area. The Longhorn Pipeline is paralleled for a good portion of its length between Crane and East Houston by two other pipelines. A stray current survey study in the vicinity of MP 351 showed interference by one pipeline where the Longhorn Pipeline acted as a ground bed. A total of 4,000 feet of affected pipe was replaced. The remaining affected pipe was remediated with metal repair sleeves. A second stray current survey after the replacement and repairs showed stray current was reduced but still required remediation through changes to the CP system to prevent further stray currents. Results were utilized to implement the changes to CP system to fully remediate stray currents. The CP system is monitored in accordance with SIP-ADM-7.04 inspection procedures and frequencies (Appendix 5A). 5.3.1.10.8 Selective Seam Corrosion Some low frequency ERW pipe has an increased susceptibility to a special form of corrosion— “selective seam corrosion (SSC)” or “crevice corrosion.” While CP is thought to be effective in preventing formation of initiators of this type of corrosion, its effectiveness in stopping on-going corrosion in an existing crevice depends on the current density and the electrolyte in the crevice. Magellan conducted inspections (2007/2008) utilizing transverse flux (TFI) MFL which is ideally suited to identify potential areas of selective seam corrosion. The In-Line Inspection Analysis Guideline, 7.03-ADM-007, provides criteria for determining areas of SSC to investigate. These inspections did not reveal any confirmed metallurgical indications of SSC. Any identified areas of possible SSC were remediated in accordance with the Pipeline Defect Evaluation and Repair Procedure, 7.01-ADM-001. 5-26 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.3.1.11 Third Party Damage The purpose of damage prevention is to protect the pipeline from third-party damage. Magellan’s Damage Prevention Program for the Longhorn Pipeline includes public outreach and damage prevention protocols such as: permanent pipeline markers, ground and aerial surveillance, One Calls, blasting monitoring, depth-of-cover surveys, ROW maintenance, navigable water crossings inspections, and line spotting activities. These protocols and procedures are detailed in SIP-ADM-7.05 (Appendix 5A) and incorporate processes to proactively identify and manage risks to outside forces damage and achieve public safety. Several aspects of Magellan’s overall damage prevention program as it applies to the Longhorn Pipeline exceed regulatory requirements. Examples include: • Definitive, quantifiable criteria for additional inspection related to anecdotal evidence of third party activities; • Extraordinary measurements of specific parameters such as near-misses, encroachments, etc.; • Special agreements with agricultural excavators; and • Increased pipeline surveillance frequencies by aerial and/or ground patrol that are at a minimum double the frequency required by regulation. Additionally, per LMC 12a, Electronic Geometry Pig inspections are conducted every three years to identify any potential damage to the pipeline caused by third parties. 5.3.1.11.1 One Call Magellan has established a standardized One Call program to protect Company Assets from damage due to excavation, encroachments, and other third party activities. Magellan has established and maintains a One Call membership with respective state agencies and follows industry standards to receive, record, respond and document One Call Locate Notifications. 5.3.1.11.2 Public Education SIP-ADM-10.01, Public Awareness, as detailed in Appendix 5A ensures promotion of public awareness of underground utilities, damage prevention and emergency preparedness. Collectively, this initiative enhances public safety and minimizes damage to property, the environment and the Longhorn Pipeline. Magellan’s Public Awareness Program was developed to comply with the standards established in American Petroleum Institute’s Recommended Practice (RP) 1162. Per LMC 25, enhanced public education/damage prevention programs were developed to: (a) ensure awareness among contractors and potentially affected public, (b) promote cooperation in protecting the pipeline and (c) to provide information to affected communities with regard to detection of and responses to well water contamination. 5-27 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL The Public Awareness Program utilizes mailings, flyers, public meetings, emergency responder meetings, periodic radio public service announcements, and newspaper ads to educate the local public. Annual mailing to groups such as schools, residences, hospitals, churches, retirement homes and other businesses include the following information: • One-Call information • Product identification information • How to identify and report a suspected leak • Personal safety guidelines in the event of a leak • "Dig Safely" or Call 811 program information Annual (not to exceed 15 months) mailings target a one-quarter (1/4) mile radius of the pipeline in metropolitan areas and a one (1) mile radius in rural areas. Mailings include items such as phone stickers, refrigerator magnets, and rulers to ensure that emergency contact information and "Call 811" information will be readily available. Door-to-door visits with the public in areas adjacent to the pipeline are performed in Tier II and III areas every two years (not to exceed 30 months). Damage prevention flyers and “Call 811” literature is distributed to the public at county fairs, trade shows, agricultural shows, feed stores, home and garden shows, and equipment rental companies. Non-emergency response government agencies that are exempt from one-call mandates, such as city and county planning, zoning and building permit offices, and agricultural agencies are contacted annually (not to exceed 15 months) with mailings and a personal visit to distribute maps of the pipeline route and inform developers of the presence of the pipeline. Reply cards and records of personal visits, along with third party damage incident scorecards, are used to measure the effectiveness of the program. Emergency response agencies within each county that the pipeline passes through are contacted at intervals not to exceed 15 months, but at least once each calendar year, in person and provided with maps of the system. Specific emergency response requirements and plans are reviewed on an annual basis with applicable LEPC and emergency responders. Annual emergency response drills are conducted. 5.3.1.11.3 Excavator Education Excavator education is an important element of damage prevention in order to reduce the likelihood of unintended third party damage caused from excavation activity. The program as defined within the SIP-ADM-10.01, Public Awareness Initiative, focuses on promoting cooperation and awareness throughout the following groups (Appendix 5A): • General contractors (i.e., irrigation, dirt, fencing, plumbing, landscaping) • Land owners 5-28 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • Real estate developers • Utility companies • Mining and quarry operations The identified excavators are provided with the following: • Information on the "Dig Safely" program initiated by DAMQAT (Damage Prevention Quality Action Team - a joint industry and government effort to educate the public on the prevention of damages to all underground and submerged facilities). • Information on the Texas One-Call system. • Information about the location of the pipeline and products in the line. • What to do in the event that unintentional damage of the pipeline occurs. • Instructions on how to recognize and report a leak. Direct mail flyers, written in English and Spanish, include items such as dashboard calendars and stickers so that emergency contact information and "Dig Safely" information will be readily available. Reply cards will be included to measure the damage prevention program effectiveness. Advertisements are placed in various trade journals and/or community publications along the Longhorn right of way to reinforce the "Dig Safely" program and to instruct the excavators to use the One-Call system. 5.3.1.11.4 Depth of Cover and Exposed Pipe For pipelines under 49 CFR Part 195.248, requirements are that new pipe in industrial, commercial, and residential areas should be buried to a depth of 36 inches for normal excavation and 30 inches for rocky excavation. The depth of cover is 30 inches in other normal areas of construction and there are special situations such as water bodies and ports requiring depths ranging from 18 to 48 inches for newly constructed pipelines. Excepting the Gulf of Mexico and its inlets, there is no explicit regulation requiring the maintenance of depth of cover. Unintended exposures can occur from forces such as ground erosion and stream scouring. Construction specifications of 1949 called for a minimum 24 inches of cover in soft terrain and 12 inches in rocky terrain. The current construction specifications call for a minimum depth of cover of 30 inches or deeper in normal conditions as shown in Table 5.2.1-2. There is no regulatory requirement to increase cover over an existing pipeline; however, as part of the LMC 18, 26 shallow or exposed areas were identified and remediated prior to startup by adding cover to a depth of five feet or a concrete cap. In 2007, Magellan conducted a depth of cover survey between Galena Park and Crane and as a result mitigated nine additional shallow cover areas. For segments re-configured to aboveground, protection offered by cover is removed and the pipeline is more vulnerable to damage from external threats. Damage from these external threats is mitigated by installation of security fencing or appropriate physical barriers. Moving a pipe segment aboveground also changes the potential for external corrosion. Atmospheric 5-29 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL corrosion is generally less severe and inspection ability is increased. Careful attention is placed upon the coatings notably at ground-air interfaces and beneath supports due to higher susceptibility at these locations. Special coatings and inspections, as required by the SIP, are placed on piping and valves located in below ground chambers due to potential for alternating wet-dry conditions. See Section 5.3.1.9 for more discussion on atmospheric corrosion. 5.3.1.11.5 Pipeline Markers Permanent pipeline markers are used to notify the public of the general location of the Longhorn Pipeline. Pipeline markers are installed and maintained in accordance with SIP procedure 7.05- ADM-002 (Appendix 5A). Permanent pipeline markers are maintained in Tier I (general), Tier II (Sensitive), and Tier III (Hypersensitive) areas as follows: • Pipeline markers meet or exceed all requirements of 49 C.F.R. §195.410. • Marker spacing for Tier I areas are placed within line-of-sight of each other. Exceptions may be necessary for land use (i.e., cultivation), and landowner and tenant issues. Discussions explaining the importance of line markers, as identified in our Public Education program are held with landowners or tenants. • Marker spacing for Tier II and III areas are placed such that if any one marker is removed, the location of the pipeline can still be identified from either direction from any point in between. • All line markers are written in English and Spanish. • Marker placement and density is evaluated routinely through aerial and ground surveillance. • Missing or damaged markers are replaced within 7 days of discovery. • Markers are located at all aboveground facilities to identify the operator of the system. • Markers are located on each side of each public road crossing, water crossing, and railroad crossings. 5.3.1.11.6 Pipeline Surveillance Most pipeline rights-of-way corridors are accessible through aerial surveillance, which is the primary method of right-of-way inspection and damage prevention. Periodic conditions such as weather, however, may render certain segments of the right-of-way inaccessible via fixed wing aircraft or helicopter and thus ground surveillance can supplement air surveillance. In addition, ground surveillance is utilized when vegetation temporarily obstructs aerial surveillance. Pipeline surveillance is conducted in accordance with the SIP procedure 7.05-ADM-031 (Appendix 5A) and LMC 20. Surveillance intervals are conducted as follows: • Tier II and III areas: Every 2.5 days, not to exceed 72 hours • Tier I areas: Once a week, not to exceed 12 days, but at least 52 times per year • Edwards Aquifer Recharge Zone: Daily (one day per week shall be a ground-level patrol) 5-30 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Aerial and ground surveillance frequency is increased across Tier II (sensitive) and Tier III (hypersensitive) areas when the threat of flooding and/or severe erosion is identified near the pipeline right-of-way. Emergency situations identified during aerial or ground surveillance are immediately reported to the Pipeline Control Center located in Tulsa, OK. All surveillance personnel and line spotters are trained and certified in OSHA HAZWOPER to the first responder level. Every consideration is given to endangered species when conducting ground surveillance in and around the pipeline right-of-way. Maps depicting the location and habitat of endangered species are utilized for this purpose. 5.3.1.11.7 Encroachments and ROW Maintenance Per LMC 16, encroachments along the pipeline ROW were removed that could reasonably obstruct prompt access to the pipeline for routine or emergency repair activities or that could reasonably be expected to hinder leak detection or other problems. Potential encroachments are evaluated using the guidelines found in the SIP. Per LMC 17, ROW was cleared prior to startup, and is now continuously maintained. 5.3.1.12 External Forces As a result of LMC 19, studies evaluating each of the following matters along the pipeline were conducted and recommendations were implemented: a. Scour, erosion, and flood potential b. Seismic activity c. Ground movement, subsidence, and aseismic faulting d. Landslide potential e. Soil stress The predominant conclusion was that earth movements (Geohazards) present a low risk. In any case, Magellan continues to manage external force threats as recommended by these studies and as required by the SIP. Examples of activities to manage external force threats include: 1. Scheduled inspections occur at various water crossings at six-month and five-year intervals. Inspections also occur after certain flood events to evaluate for scouring, erosion and flood potential. 2. Studies are performed every six months to evaluate for ground movement, subsidence and aseismic faulting. 3. Surveys are conducted every five years to evaluate landslide potential. These studies and their conclusions remain valid for the System, and as such, the discussion as found in the 1999 EA is still relevant. The Proposed Project may change failure potential from these threats at certain locations where valves are re-configured and possibly at station 5-31 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL modifications. Threats are very location-dependent. An assessment of their frequency and magnitude is part of the design process. Industry accepted design and construction practices will ensure that integrity is not compromised by such threats. 5.3.1.12.1 Flooding Scheduled inspections occur at various water crossings at six-month and five-year intervals. Inspections also occur after certain flood events to evaluate for scouring, erosion and flood potential. As a result of PHMSA Advisory ADB-11-04, Magellan implemented the Flooding Conditions Procedure, 7.05-ADM-039 (Appendix 5A) to provide standards for recognition, surveillance, and responses to flooding conditions near mainline pipelines. 5.3.1.12.2 Geohazards Studies are performed every six months to evaluate for ground movement, subsidence and aseismic faulting. Surveys are conducted every five years to evaluate landslide potential. Additionally, the Earth Movement Inspection Procedure, 7.05-ADM-020 (Appendix 5A), provides methods for the investigation and monitoring of areas of the pipeline identified as having high susceptibility to earth movement or where earth movement has been identified. Pipeline surveillance activities pay particular attention, within the target area, to signs or indicators of earth movement or subsidence such as ground cracks, sink holes, erosion, heaving, or buckling. ORAs since 2005 have updated geohazard threat analysis, especially aseismic faulting threat. No new issues have been identified and some previously identified issues have been recognized as being less severe than was initially (and conservatively) deemed plausible. 5.3.1.12.3 Crossings The Longhorn Pipeline crosses creeks and rivers as well as man-made linear features such as roads, railroads, or other pipelines. Rivers and creeks are subject to erosion that can dislodge the pipeline. Vehicle traffic on roads and railroads can cause recurring stresses and vibrations in the subsurface. For these reasons, pipelines are often fortified at crossings and protective measures are specified depending on the circumstances. These can include thicker wall pipe and increasing depth of burial and casings at road and railroad crossings. No new crossings or modifications to existing crossings have been specified as part of the Proposed Project. Magellan manages the integrity of overhead pipeline crossings with the Overhead Pipeline Crossing Integrity Procedure, 7.05-ADM-030 (Appendix 5A). This procedure manages integrity through a comprehensive risk-based program which identifies risk reduction projects to improve structural component integrity. Magellan manages the integrity of navigable buried river crossings with the Navigable Crossings Inspection Procedure, 7.05-ADM-014 (Appendix 5A). This procedure requires inspection to determine pipeline depths at these crossing at least once every five years per regulatory requirements. 5-32 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Per LMC 15, an engineering analysis was conducted to verify that all pipeline spans were adequately supported and protected from external loading. Subsequent remediation was completed prior to startup in 2005. 5.3.2 Staffing and Training Magellan employs field staff to cover the route of the Longhorn Pipeline. The System has defined geographical support areas consisting of: field technicians, corrosion technicians, maintenance coordinators, area supervisors, operators and operation managers. These teams are supported by a centralized technical services team that includes engineering, environmental, health and safety, regulatory compliance, training, corrosion and risk mitigation, operations control, design, and real estate services. Magellan has an established training program to instruct employees in safety, security, environmental and operational compliance. Training is reviewed regularly to assure effectiveness. Magellan’s training program consists of the following major components: new employee orientation; annual training OJT; computer-based training (KnowledgeWire); web- based training; vendor-led training schools/seminars; technical training; SIP/safety meetings and supervisory training. New Employee Orientation (NEO) is required for all field-based personnel to provide basic training on the fundamentals of safety and operations. Emphasis is placed on employee safety. The NEO class is three weeks in length. Week 1 and week 3 are spent in Tulsa at Magellan’s headquarters and week 2 is spent at the employee’s home location. Additional computer-based training (CBT) and site specific training at their home location are covered once the employee has completed the NEO classes. New employees have 180 days to complete the majority of their training requirements. Annually, employees are required to attend mandatory training on a variety of safety and compliance topics. Magellan employees utilize the Compliance Management System (CMS) for training records. Key resource documents are available through Magellan’s intranet site, Compass. Employees are also provided the opportunity to evaluate training. The evaluations are collected, combined, reviewed and analyzed for improvement efforts. Employees and supervisors may request additional training on special topics or topics that need deeper study or development. The training department schedules additional classes based upon those requests. 5.3.3 Risk Assessment Processes Magellan’s risk management practices are relevant to this analysis since they provide some evidence into future risk management potential. An examination of those practices is presented here. 5-33 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Risk assessment and risk management performed by Magellan are detailed in the LMP and SIP. Integrity Management Plan (IMP) regulations now mandate formal risk assessment and can be found in 49 CFR Part 195.452. . The risk assessment defined in the 1999 EA and LMP were designed prior to the Integrity Management regulations. An operator, whose system can impact a pre-defined HCA, is required to place certain portions of the system under a formal integrity management program which includes formal risk assessment. Magellan’s current risk assessment tools being applied to the System include: • ORA - annual evaluation of integrity issues; conducted by independent third party • Data Management - physical data, collected by and contributed from an integrated team of operational and technical subject matter experts, is the cornerstone of the “Risk Management” process. • Pipeline Risk Assessment or Relative Risk Assessment (RRA) - central element of LMP and IMP compliance; follows 1999 EA risk assessment. • Facility Risk Assessment (FRA) - special IMP process used in stations. • PHA’s - SME-based techniques to identify hazards related to facilities. • Preventive and Mitigative Measures Analysis (Section 6) and Scenario Based Risk Mitigation Analysis (SBRMA) - qualitative review with action plan generation, used as continuation of RRA (per Section 3.5.10 of the LMP). These tools and processes are discussed below. 5.3.3.1 Operational Reliability Assessment (ORA) An ORA is performed by an independent third party approved by PHMSA and results and recommendations are reported to PHMSA and publicly posted via Magellan’s internet website. Recommendations must be implemented as written by third party. The ORA is an ongoing process completed annually. The ORA Process Manual prescribes the scope, schedule, technical approach and procedures for performing the ORA functions. As stated in the ORA manual: “…the ORA will provide Longhorn with a technical evaluation of the integrity of its pipeline assets and will provide specific recommendations that are intended to either preserve long-term integrity or to mitigate areas of concern before they can result in a threat of failure. An Office of Pipeline Safety (OPS) approved third party consultant (ORA contractor) will perform the ORAs. The ORA contractor’s recommendations will be related to integrity intervention methods and scheduled for incorporation into the LPSIP. The ORA can be viewed as the second line of defense (supporting the LPSIP) in maintaining the long-term integrity of the pipeline system. The primary focus of the ORA is upon line pipe, while the LPSIP covers a much broader set of operating and maintenance processes.” 5-34 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL The ORA is a central element in managing integrity threats on the Longhorn Pipeline. Guidance in determining appropriate response to new findings is a key aspect of each annual report. Intervention, via inspection to detect and remove damages, is a central aspect of Magellan’s integrity management program. The ORA provides the basis for intervention types and timing. A probability of exceedance (PoE) methodology is used in the establishment of integrity assessment intervals for corrosion. The PoE estimates are generated for both internal and external corrosion in each annual ORA, according to the ORA manual. The PoE process is discussed in Section 5.3.5.2.2. The ORA also incorporates a process to determine crack remaining life and associated reassessment intervals. A crack estimation of remaining life (in lieu of a PoE analysis for metal loss) is conducted by determining frequency and amplitude of pressure cycles and subsequently estimating the crack growth rates. The estimated remaining lives are then multiplied by a factor of 0.45 as an added safety factor. The ORA also provides a qualitative evaluation of programs and processes intended to control certain other failure mechanisms. 5.3.3.2 Data Management Similar to other pipeline systems, Magellan assets have specific physical attributes that are characterized by their construction materials, as well as, their installation and maintenance methods. The products transported, operating parameters, and routing through population density, land uses, and environmentally sensitive areas, further characterize the Magellan pipeline system. Taken collectively, physical assets, products transported and operating systems are factors that characterize the relative risks to the surrounding environment and population. Physical data, collected by and contributed from an integrated team of operational and technical subject matter experts, is the cornerstone of the “Risk Management” process. Magellan uses ESRI (vendor) products for its Geographic Information System (GIS) and currently employs an in-house developed pipeline data model known as the Technical Information Exchange System (TIES) for some pipeline and facility data. Other data of record is documented in a variety of different formats, such as: • Pipeline Data (TIES - Oracle 11) • Facility Data (TIES - Oracle 11) • Depth of Cover Data (MS Access, MS Excel) • In-line Inspection Data (MS Excel) • Corrosion Data (American Innovations - CPDM) • Close Interval Survey (MS Excel) • Release Data (MS Access) • High Consequence Area Data (MS Access) • Risk Model (American Innovations - SQL Server 2005) • Real Estate Data (LandROW - Oracle 11) • Damage Prevention / One Call Data (MS Access, MS Excel) • Operational Data Store (ODS - Oracle 11) 5-35 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • Environmental Data (GIS, MS Excel) • Emergency Response Data (GIS, MS Excel) • Hydrostatic Test Data (MS Excel) 5.3.3.3 Pipeline Risk Assessment Risk Management is the process of evaluating integrity related issues and allocating resources in a manner that minimizes risk. Risk assessment is a core function within risk management. Relative risk assessment (RRA) allows Magellan to target and focus on those assets posing the highest risk to population and/or environment, so to facilitate the development of risk mitigation programs. This enables the implementation of controls and measures with which to reduce the likelihood of adverse events or to mitigate the potential consequences. The inherent value in Magellan’s risk management approach is that it ensures that its resources (time, talent, and money) are effectively employed in those areas of highest risk. A RRA was included as a part of the 1999 EA to help identify or confirm high-risk areas along the pipeline route. It was also used as a means to account for changes in absolute probabilities likely to be achieved with changes in design and operational practices. The RRA model is one of the risk assessment tools used by Magellan on the System. Magellan has maintained the original segmentation and re-calculates RRA scores on a periodic basis. The Magellan RA Index Sum is an overall measure of failure potential. The Index sum is divided into four sub- categories. These correspond to possible failure modes, which are Third-Party Damage Index, Corrosion Index, Design Index, and Incorrect Operations Index. The Pipeline RRA process consists of the following process steps: 1. Gather Data needed for Assessment 2. Populate Relative Risk Model 3. Conduct Pipeline Risk Assessment 4. Populate Segments based on Risk Results 5. Conduct Assessment Planning 6. Conduct Integrity Assessments 7. Evaluate Assessment Results 8. Execute Mitigation 9. Conduct Preventive Mitigative Measures Analysis 10. Implement Additional Mitigation Measures 11. Update Pipeline Risk Model. The LMP identified potential future benefits from an effective risk management program including: “…a sharper focus on continuously identifying and reducing real risk issues, reduction in accidents, prioritization of inspection programs, prioritization of maintenance plans, and assistance in project design.” 5-36 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.3.3.4 Facility Risk Assessment Similar to the Pipeline RRA, the facility risk assessment integrates the components that influence facility integrity and combines them into an overall facility risk assessment score. This risk assessment allows Magellan to target facility risk management activities and resources to the highest priority areas. A scoring type assessment questionnaire is utilized to produce a relative probability score and a relative consequence score. The major components of the risk assessment include: 1. Facility Age 2. Complexity 3. Overfill Protection Evaluation 4. Over/Short Monitoring Evaluation 5. Mechanical Integrity 6. Corrosion Control 7. Incident History 8. Consequence Potential The Facility Relative Risk Assessment Process is conducted via the following process steps: 1. Identification and grouping of facilities for risk scoring 2. Collection of data for assessment 3. Input information into risk assessment database. 4. Calculation of the relative risk score. 5. Prioritization of facilities 6. Utilization of risk ranking to prioritize projects within the various facility integrity programs. 5.3.3.5 Process Hazard Analysis PHAs are formal risk assessment/management tools used to assess the potential hazards associated with station facilities of a pipeline system. There are a variety of methodologies that can be used to conduct a PHA; however, Magellan has adopted the What if/Checklist and the Hazard and Operability Study (HAZOP) methodologies. A HAZOP is a structured and systematic analysis of a process that utilizes parameters and guide words to establish the cause and effect of any potential hazard or deviation from the design intent. Each hazard/deviation is evaluated by the HAZOP team to determine if the cause is credible, to establish the safeguards in place to prevent the deviation and whether any additional recommendations are required to meet an acceptable risk threshold. Each credible deviation is risk ranked according to severity and likelihood using a subjective criterion by the HAZOP team. The severity score assigned for each identified hazard is ranked without consideration of the safeguards currently in place. The likelihood score assigned for each identified hazard is ranked based on the safeguards currently in place to prevent the deviation. The likelihood score does not include the impact of any recommendations. The impact of the recommendations on the likelihood score will be considered during the subsequent PHA revalidations. A PHA has been conducted at each 5-37 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL facility per the requirements of the LMP with recommendations implemented. These PHAs are required to be revalidated every five years. 5.3.3.6 Preventive and Mitigative Measures Analysis Following the relative risk assessment of the various pipeline segments, the Scenario Based Risk Mitigation Analysis (SBRMA) Program is executed. This program is designed to identify preventive measures and/or modifications that can be recommended that would reduce the risks to the environment and the population in the event of a product release. The relative risk ranking results are used to allocate resources to reduce the overall operational risk. As part of the SBRMA, a review is conducted of the risk model Index Sum and contributing index scores to determine areas along the pipeline and within the facilities with the highest risk. A meeting is then scheduled with the Longhorn Risk Analyst to discuss low scores and identify target areas where scores could be raised by conducting mitigation measures. Any low risk scores corresponding to high risk areas more than two standard deviations from the mean are identified and a spreadsheet is prepared detailing the risk factors that are contributing to the low risk scores for each high risk area identified. A roundtable meeting is held with appropriate Subject Matter Experts (SME’s) and stakeholders to include: Field Operations, Pipeline Control, Corrosion, Pipeline Integrity, One-Call, and Engineering to discuss areas of identified low risk scores and determine any additional preventive or mitigative measure needed to reduce pipeline and/or facility risk. Additionally, following a mainline integrity assessment of HCA’s and Tier 2 and 3 areas, Magellan initiates a Risk Analysis Process to determine if additional preventive or mitigation measures are necessary. Additionally, following integrity related events such as an in-service externally reportable release; a risk analysis will be conducted. For facilities releases or releases from mainline components such as valves, flanges, and fittings, the Company Incident Investigation Process will be followed. For facilities a risk analysis process to determine if additional preventive or mitigative measures are necessary will be conducted on a prioritized systematic basis. Each analysis is lead from the centralized Asset Integrity group by the Asset Integrity Engineer / Analyst and is designed to be a systematic approach to gathering data, conducting analyses, formulating recommendations and implementing risk reduction measures. Following documentation of the analysis, a roundtable discussion is held with appropriate stakeholders in Operations Control, Field Operations, Corrosion, Pipeline Integrity, One Call, Damage Prevention, and Engineering to discuss the results and finalize recommendations for additional preventive and mitigative measures. 5.3.4 Control Systems (SCADA) The operation of each pump station is controlled by a combination of local control systems and remote monitoring via a centralized Supervisory Control and Data Acquisition (SCADA) system located at the Magellan Operations Control Center. Each data source, transmitting information 5-38 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL to the SCADA system, communicates approximately every three seconds. The signals are electronically transmitted by satellite communications. Telephone modems are in place as a backup to the satellite system. The modem system can be used if there is an isolated failure in satellite communications from individual stations or if there is a failure of the entire satellite system. When all locations are being accessed with the backup modem system, the initial connection can take up to three and one-half minutes to establish communication, then the systems responds every three seconds. Local control systems provide much of the protection against abnormal operation at each of the pump stations. Table 5.3.4-1 lists emergency shutdown alarms and devices located at pump stations. These local control systems are designed to provide an orderly shutdown of the pump station if an alarm condition occurs or if certain operating parameters are violated. At the same time that the shutdown sequence has been initiated, a shutdown alarm is transmitted to the Magellan Operations Control Center. Examples of local control systems are: • A low suction pressure (typically less than 50 pounds per square inch gauge [psig] at several stations) will cause the pump to automatically shut down. • A pump discharge pressure above a specific pressure setting will also produce an automatic pump shutdown. Other sensors and controllers act in a similar manner. The primary objective of these local controls is to prevent abnormal conditions from damaging the pipeline and pump station equipment and potentially causing or contributing to a leak. The capability to detect smaller leaks and to respond with appropriate action resides primarily with the controllers in the Magellan Operations Control Center via the SCADA system. Per LMC 13, the leak detection system is computational based and can detect 1% or less loss of flow within one-half hour over the entire pipeline system. The system capability is periodically demonstrated through testing. 5.3.4.1 Leak Detection Specialized leak detection was required as part of the LMP. LMC 13 required an enhanced leak detection and control system to be installed to include a transient model based leak detection system utilizing 9 meter stations (6 clamp on meters and 3 turbine meters). Longhorn met LMC 13 in 2000 by installing a pipeline leak detection system (PLDS), a software package designed and provided by Energy Solutions International, Ltd. A routine analysis is continuous and ongoing to verify that PLDS meets the accuracy parameters of the LMP. PLDS is based on the real time simulation of the flow in the pipeline and is comprised of a rigorous transient computer model driven by SCADA data. PLDS verifies the pipeline instrumentation integrates hydraulically and alarms when it detects drifts in calibration, wrong measurements, or missing product from the pipeline. Leak detection is performed by viewing sections of pipe bounded by meters. On the Longhorn Pipeline, both turbine meters and ultrasonic devices (strap on meters) are used to monitor and analyze the hydraulics in smaller segments. PLDS detects leaks in pipelines by performing accurate transient compensated volume (mass) balance calculations for 5-39 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL defined sections of the pipeline each SCADA scan. SCADA scans and model calculations are performed every three seconds. PLDS complies with the American Petroleum Institute RP 1130 1st edition, of September 2007. This system also adheres to the sensitivity guidelines set forth in LMC 13 shown in the table below. Location System Design Specifications Tier 1 1% of flow detected within one-half hour Tier 2 and 3 1% or more of flow detected within one-half hour 0.5% - 1% of flow detected within one hour PLDS alarms are passed back to SCADA. Upon receiving the probable leak indication, the controller proceeds with the line shutdown. The line shutdown is achieved within five minutes or less. Table 5.3.4-1a details the PLDS alarms and required responses. Per Magellan procedure, 9.02-ADM-082, Magellan is required to demonstrate and test the leak detection system on a periodic basis to ensure the sensitivities meet the requirements outlined in Longhorn Mitigation Plan Commitment 13. As example, on November 19th, 2011 at 15:28, with the pipeline flowing at 2800 BPH, the leak detection system alarmed in the 10 minute window when product was diverted into a pig trap, which holds a maximum of 20 BBLs. The volume of 20 BBLs at the noted flow rate results in 0.7% sensitivity. Leak detection sensitivities are calculated and reviewed monthly by the Magellan Leak Detection analyst. Larger leaks are signaled by an alarm in the Magellan Operation Control Center indicating that the pressure and/or flow rate has deviated outside of preset parameter limits. These limits are 20% for pressure and 12% for flow rates and may be periodically reviewed and changed based on analysis of historical data. Thus, a decrease in flow greater than 12% from the target rate would cause an alarm at the Control Center within six seconds of the time the sensor detected the low flow rate. When a pressure or flow parameter alarm occurs, the controller reviews the pipeline operation and checks the pipeline. If no cause is apparent, controller proceeds with the line shutdown. The line shutdown is achieved within five minutes or less. Mainline isolation valves will be closed, and the pipeline will be kept under pressure to determine its integrity and to identify the location of any leak. Additionally, as part of LMC 13, a leak detection system was installed over the Edwards Aquifer Recharge Zone and the Slaughter Creek watershed in the Edwards Aquifer Contributing Zone that will detect a leak of extremely minute volume in twelve (12) to one hundred twenty (120) minutes from contact, depending upon the product sensed by the system. The leak detection system consists of a buried hydrocarbon sensing cable system designed to meet the leak detection performance specifications. The pipeline system is designed to achieve emergency shut down within five minutes of a probable leak indication. 5-40 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.3.4.2 Control Room Procedures For the purposes of monitoring and control from the Magellan Operations Control Center in Tulsa, Oklahoma, the Magellan Pipeline System is divided into eight consoles. The Longhorn Pipeline is assigned to Console One. Each console is under the control of a Pipeline Controller who continually monitors the pipeline operations. Each of these controllers works a 12-hour shift. A supervisor is generally present in the control center on weekdays and is on call at other times. Controllers can start and stop flow of product into the pipeline from supply points, start and stop pumps, operate valves, and monitor pipeline pressures, flow rates, product densities, and temperatures. The control room is therefore an important component of the leak detection system since potential leak indications are diagnosed and responded to from there. Detailed procedures for all control room operations are contained in the SIP. Recent PHMSA regulation CFR 195.446 requires robust Control Room practices in the areas of controller fatigue mitigation, alarm management, change management, lessons learned from operating experience, training and compliance validation. Several American Petroleum Institute standards are incorporated by reference in CFR 195.446 such as American Petroleum Institute RP 1165 and American Petroleum Institute RP 1168 (section 5/7). CFR 195.446 must be fully implemented by August 2012 and will be audited by PHMSA. 5.3.5 Pipeline Inspection and Testing Pipeline integrity is ensured by two main efforts: (1) the detection and removal of any integrity threatening anomalies to ensure the current pipe integrity; and (2) the avoidance of future threats to the integrity. A defect is considered to be any undesirable pipe anomaly such as a crack, gouge, dent, or metal loss, which could lead to a leak or spill during operations. Possible defects include seam weaknesses associated with low-frequency ERW and electric flash welded pipe, dents or gouges from past excavation damage or other external forces, external corrosion wall loss, internal corrosion wall loss, lamination defects, pipe body cracks, circumferential weld defects, and hard spots. The purpose of inspection and testing is to validate the structural integrity of the pipeline and its ability to sustain the operating pressures and other anticipated loads. The protocol is to test and/or inspect the pipeline system at frequent enough intervals to ensure pipeline integrity despite the possible advancement of time-dependent failure mechanisms. Inspections and testing methods consist of those mandated by regulations as well as those that are independently initiated by the operator. Some methods of inspection and testing are listed in Table 5.3.5-1. The results of testing and inspection are critical inputs into the risk assessment. Risk factors that are strongly influenced by these results include: • Knowledge of active failure mechanisms such as corrosion, cracking, and external forces 5-41 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • Knowledge of effectiveness of mitigation of all threats • Knowledge of pipe’s ability to resist future failure mechanisms • Analysis of ability to successfully intervene in a failure scenario, thus preventing that failure. Current integrity management regulations recognize three methods by which integrity can be assessed: pressure testing, ILI, and direct assessment. Magellan uses the first two methods. Within the liquid pipeline industry, direct assessment is only utilized when pressure testing or ILI is not an option. Information on pressure testing and ILI is discussed in this section. 5.3.5.1 Pressure Testing A pressure test is used to confirm the ability of the pipeline to sustain its specified operating pressure and establish a safety margin relative to MOP. Hydrostatic pressure testing, often called ‘hydrotesting,’ is the most common form of pressure testing. In this document, phrases such as pressure test and hydrostatic test are used interchangeably with the former being the more general descriptor. Pressure testing is beneficial in countering integrity concerns by removing critical defects. Pressure testing to a level significantly higher than operating pressure (usually 1.25 times MOP or more) adds a margin of safety since any defects of a size and configuration that would cause the pipe to fail operating pressures, would have been detected during such pressure tests. Remaining flaws that did not fail at test pressure should not fail at the lower pressure associated with MOP unless further flaw growth occurs. The safety margin provided by the pressure test will normally decrease over time because the test only verifies the pipe integrity at the time of the test. The probability of defect growth and addition since the test date must be considered. Since a new defect could be introduced at any time or defect growth could accelerate in a localized region, the test usefulness is tied to other operational aspects of the pipeline. Introduction of new defects could come from a variety of sources, such as third-party activities or corrosion. For this reason, pressure test data have a finite lifetime as a measure of pipeline integrity without other supporting evidence such as documentation of continuing CP, monitoring of internal corrosion, ILI, a strong damage prevention program, and fatigue analysis. All of these are aspects of Magellan’s SIP. Prior to startup (2005), Longhorn hydrostatically tested the pipeline for a minimum of 8 hours in accordance with 49 CFR Part 195 Subpart E requirements from East Houston to Crane including all hypersensitive (Tier 3) and sensitive (Tier 2) areas. A summary of pressure tests performed on the System from 1995 through 2004 is shown in Table 5.3.5-2. The more recent tests performed between 2005 and 2011 are shown in Table 5.3.5-3. 5-42 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.3.5.2 In-Line Inspection (ILI) For a pressurized pipeline, the pipe wall thickness is designed to safely accommodate the expected operating stresses, including normal operating pressure, surge pressure, external forces (e.g., traffic loadings), the weight of the pipe itself, and other factors. Loss of wall thickness reduces the pipe’s ability to withstand such loads. In addition, any abrupt changes in wall thickness or shape can amplify the stress level in the pipe wall, potentially contributing to failure. Therefore, the detection of anomalies, which reduce the wall thickness or which have the potential to amplify the stress level in the wall, is an important preventative measure. ILI, also called “smart pigging” or “intelligent pigging,” is the use of an electronically instrumented device, travelling inside the pipeline that measures characteristics of a pipe wall. The industry began to use these tools in the 1980s. The pipe conditions found which may require further inspection are referred to as anomalies. General and detailed discussions of these tools are available in the technical literature. PHMSA regulations require that all new pipe installations be designed to accommodate ILI devices. The pipeline diameter, fittings, valves, and other parts of the pipeline must therefore be able to accommodate the passage of these devices. The PHMSA Integrity Management Plan (IMP) regulations recognize ILI as a valid technology for integrity assessment in an IMP. The state-of- the-art for ILI has advanced to the point that many pipeline companies are basing integrity management programs primarily around such inspections. Many pipe anomalies that are of a size that would not be detectable under a normal pressure test can be detected through ILI. However, anomaly detection is not 100% accurate even with the most advanced techniques. Many factors affect the number and size of undetected flaws. These include conditions under which the inspection is made such as speed of travel, fluid properties, and distance traveled; tool type; tool accuracy; calibration; and interpretation of data among others. Uncertainties regarding true system strength will remain even after inspection, and similar to the pressure test, ILI test results are valid for a finite time period. General types of anomalies that can be detected and characterized to varying degrees by ILI include: • Geometric anomalies (dents, wrinkles, out-of-round pipe); • Metal loss (gouging and general, pitting, and channeling corrosion); and • Laminations, cracks, or crack-like features. More significant features (i.e., those that have larger dimensions) are more reliably detected. Some examples of available ILI devices are: geometry tools, magnetic flux leakage tools, and ultrasonic tools. These can be further categorized based on their configurations for increased sensitivity to certain flaw types. For example, a circumferential Magnetic Flux Leakage (MFL) tool uses the MFL detection technology in a specialized way to increase sensitivity to crack detection and sizing Each of these tools has specific applications. Most tools can detect previous third-party damage or impacts from other outside forces. Geometry tools are used to locate pipe deformations such 5-43 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL as dents or out-of-round areas. Magnetic flux leakage tools identify areas of metal loss. Ultrasonic wall thickness tools detect general wall thinning and laminations. So called “crack tools” are specifically designed to detect cracks, especially those whose orientation is difficult to detect by other means. Currently, no single tool is superior in detecting all types of anomalies. Depending on vendor specifications and ILI tool type, detection thresholds can vary. The degree of resolution (the ability to characterize an anomaly) also depends on anomaly size, shape, and orientation in the pipe. The probability of detecting an anomaly using ILI increases with increasing anomaly size. Smaller anomalies as well as certain anomaly shapes and orientations have lower detection thresholds than others. Vendors report detection thresholds for various anomaly types and orientations with probabilistic detection capabilities. Higher confidence detection thresholds for general corrosion are commonly stated as a depth sizing accuracy of ±10 to 15% of wall thickness, for MFL type ILI. Severity of an anomaly is a function of not only depth but also other dimensions and orientation. Several industry-accepted methods exist for determining severity of certain anomaly types and for evaluating the remaining strength in corroded pipe. ASME B31G, ASME B31G Modified, and RSTRENG are examples. These calculation routines require measurements of the dimensions and configuration of corroded areas. Depending upon the depths and proximity to one another, some areas will have sufficient remaining strength despite the corrosion damage. The calculation determines whether the area must be repaired. Metal loss is characterized as “significant” based upon the depth or the ratio between the predicted failure pressure and the operating pressure. This generally accepted method is a valid approach for addressing corrosion integrity concerns. Magellan was required to run three separate types of ILI tools as part of the commitments under the LMP. These three tools included: 1) Magnetic Flux Leak (MFL), 2) Transverse Flux Inspection (TFI), and 3) Ultrasonic Wall Measurement (UT). ILI tool run dates are shown in Table 5.3.1-1. 5.3.5.2.1 ILI Findings MFL Inspection (December 2005 - November 2008) LMC 11 required conducting a high- resolution MFL inspection in the pipeline between Galena Park (Valve J-1) and Crane within three months of startup (2005). Although delayed by unforeseen circumstances (low throughput of product and the presence of debris in the pipeline), the inspections were completed on all required segments by February 2007. Inspections for the Crane to El Paso segment were completed by November 2008. Electronic Geometry Pig (EGP) inspections were conducted in conjunction with the MFL inspections (as per LMC 12a) to evaluate for pipeline deformation resulting from dents and mechanical damage. TFI Inspection (March 2007 – January 2008) LMC 10 required that a ILI crack detection tool run be performed no more than three years after system startup. These tool run inspections were completed by January 2008 and associated rehabilitation was completed. Electronic Geometry Pig (EGP) inspections were conducted in conjunction with the TFI inspections (as per LMC 12a) to evaluate for pipeline deformation resulting from dents and mechanical damage. 5-44 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL UT Inspection (September 2009 – July 2010) Per LMC 12, Longhorn conducted an ILI of the existing pipeline (Valve J1 to Crane) with an UT wall measurement tool to verify wall thickness as described by the SIP (Section 3.5.2 and the associated ORA (Section 4.0). This inspection was completed in 2010 and subsequent remediation was completed following the inspections. Electronic Geometry Pig (EGP) inspections were conducted in conjunction with the UT tool inspections (as per LMC 12a) to evaluate for pipeline deformation resulting from dents and mechanical damage. The presence of laminations as detected by the UT wall measurement tool becomes more important under the Proposed Project due to the potential for hydrogen blistering in Crude Oil Service. This was discussed in more detail in section 5.3.1.3. A total of 8183 laminations were identified by the UT tool. These are summarized as follows: • Galena Park to Satsuma – 1695 (1689 planar, 6 variable depth) • Satsuma to Warda – 1082 (290 planar, 777 intermittent, 6 bulging, 2 sloping, 7 variable depth) • Warda to Cedar Valley – 541 (140 planar, 392 intermittent, 3 bulging, 2 sloping, 4 variable depth) • Cedar Valley to Eckert – 594 (134 planar, 446 intermittent, 14 variable depth) • Eckert to Ft. McKavett – 1907 (612 planar, 1255 intermittent, 2 bulging, 12 sloping, 26 variable depth) • Ft. McKavett to Crane – 2364 (600 planar, 1743 intermittent, 10 bulging, 8 sloping, 3 variable depth) Magellan’s In-Line Analysis Technical Specification, 7.03-ADM-003, requires the vendor to identify lamination indications detected in the pipeline. Based upon criteria determined by third party consultants and Magellan, the following features are designated as meeting criteria for investigation: • Sloping • Bulging • Surface Breaking • Hydrogen Blisters • Laminations interacting with other features are evaluated to determine if investigation and repair is warranted. The features are then added to the dig list for excavation and repair per 7.03-ADM-007, Section 15.1; 7.03-ADM-003, Section 5.4. Repairs are conducted in accordance with 7.01-ADM-001, Pipeline Defect Evaluation and Repair Procedure. All injurious laminations were repaired. Table 5.3.1-2 provides a summary of anomalies detected by ILI tool type for all three ILI’s conducted since the pressure test. 5-45 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.3.5.2.2 Follow-up Excavations After receiving an ILI indication of a potentially injurious anomaly, an excavation is required to more accurately inspect the pipe and make repairs. Excavating to inspect the pipe is also used to validate the ILI results and determine the actual sizing inaccuracies associated with a specific ILI. Certain anomalies identified by ILI are investigated and repaired according to pre-established criteria. Some criteria are mandated by regulation. For example, certain anomalies on pipe segments within High Consequence Areas (HCAs) require investigation and repair within specified time constraints. Other criteria are voluntarily adopted by an operator or specified by the LMP. The criteria in use by Magellan are specified in SIP-ADM-7.03 (Appendix 5A) and are in accordance with the requirements of the 49 CFR Part 195 and the LMP. A summary of the criteria is contained in Table 5.3.5-4. In addition to the established criteria, a Probability of Exceedance (PoE) analysis is also performed on all detected metal loss anomalies. This process is outlined in the LMP and is used to calculate the probability for every anomaly that its tool-predicted dimensions are actually larger than predicted dimensions by an amount sufficient to reach depth or pressure based repair criteria. The analysis further utilizes established estimated corrosion rates to predict when each anomaly would reach repair criteria. Response plans are then formulated to investigate all anomalies well in advance of their predicted time to failure. Following the initial MFL inspection, anomalies with calculated probabilities greater than 1 in 10 million (1E-7) were addressed. This equates to any metal loss anomaly with a depth greater than 34% of the pipe wall thickness or calculated safe pressure less than the maximum operating pressure at the location of the feature. This ensures that each feature has a safety factor of 1.39 times maximum operating pressure. Additionally, following the UT, MFL, and future metal loss inspections a corrosion growth rate is applied to all metal loss anomalies to determine when the feature might grow to a POE level of 1E-5 or depth of 44%. The time interval for unaddressed metal loss to grow to a POE level of 1E-5 is then determined to be the re-assessment interval. As a result of these repair criteria, any metal loss features with a remaining strength less than 1.39 times the maximum operating pressure at the location of the feature or with indicated depths greater than 44% have been repaired. In some instances, anomalies will be investigated by Magellan even when not mandated by the pre-established criteria or POE process. Regarding the criteria for repair and the way in which such repairs and replacements were undertaken, there are no findings of inadequacies in the ORAs, self-audits, or PHMSA audits. Table 5.3.1-2 provides a summary of anomalies repaired by ILI tool type for all three ILI’s conducted since the pressure test. 5-46 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 5.3.5.3 Visual and NDE Inspections This section is restricted to a discussion of coating inspection and inspection of pipe that is exposed. Visual inspections are required by regulations whenever a buried pipe is exposed and, as a matter of course, for other parts of the System that are normally observable. Routine inspections of the System as a whole are covered in the section on Third Party Damage (5.3.1.11). Magellan’s SIP Element 7.04–ADM–005 (Appendix 5A) details specific steps to take and documentation for all pipe that is unearthed that includes coating condition, soil conditions, evidence of corrosion, and other useful information. Spreadsheets of results of ILI-prompted excavations were provided for this FEA. Comments by inspectors provide valuable insight into conditions found, accuracy of ILI reports, and possibilities for future damages. The data is evaluated and written comments are considered by Magellan’s subject matter experts. 5.4 ACCIDENTAL RELEASES 5.4.1 Leak Analysis This section analyzes the spill history of the System. The purpose is to analyze the historical frequency, causes, and consequences of past leaks and spills, as an indicator of possible future performance. Data on releases provided by Magellan has been summarized in Table 5.4.1-1 - Pipeline and Facility Spill Data Since 2002; Table 5.4.1-2 - Summary of Cause of Release for Facilities; and Table 5.4.1-3 - Summary of Cause of Release for Pipeline. There have been 42 documented leaks since 2002. Of these, 38 have occurred in facilities and 4 on the pipeline. All have impacted soil and none have impacted water bodies. One release was of water used for hydrotesting, 2 were water/product mixes, one was IVD additive, one was corrosion inhibitor, and one was hydraulic fluid and the remaining 36 were hydrocarbon products (diesel, gasoline, oil, etc.). The largest release, 119 barrels, was of hydrotest water prior to start of operations. Slightly over 7.5 barrels of additive/hydrocarbons were released between July 2002 and January 2005 in 14 incidents prior to start of operations related to various commissioning activities. Since operations began, there have been 28 documented releases amounting to 44 barrels. There were four incidents over 5 barrels accounting for 29 of the 44 barrels. Eight of the 28 releases were of a nature to be classified as reportable under PHMSA definitions. One of the eight was classified as a pipeline release and the remaining were classified as facility releases. 5.4.1.1 Leak Causes As noted above, the primary locations of leaks were in facilities. These include rotating equipment mechanical failures (e.g., pump seal failures), tank corrosion, or operating errors (e.g., not taking action to stop a relief tank overflow caused by equipment malfunction). Table 5.4.1-2 shows the causes for the 38 facility leaks. The leading cause was equipment failure 5-47 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL (21), followed by human error (16). Table 5.4.1-3 shows the causes for the four pipeline leaks. The leading cause was equipment failure. Three of the four incidents resulted from small valves of 2 inch or lesser size malfunctioning. The fourth was a leak that initiated during a repair operation. In compliance with SIP-ADM 13.02 (Appendix 5A), Magellan conducts incident investigations and incorrect operations mitigation review for the Longhorn assets on a quarterly basis to assess data and reduce the potential for human error in the design, construction, maintenance, and operational activities that could impact the mechanical integrity of the assets, 5.4.1.2 Comparisons with Other Pipeline Leak Data Magellan contracted with Allegro Energy Consulting to extract mainline pipe only incident data for the years 2010-2011 as a benchmark comparision for the risk threshold of 1E-4 mainline incidents/year. This equates to 0.1 incidents/1000mile-year. This compares to the onshore pipeline PHMSA reportable incident rate for mainline pipe only of 0.830 incidents/1000mile-year for crude oil pipelines or 0.695 incidents/1000mile-year for crude and refined product pipelines combined. The Texas reportable incident rate for mainline pipe only was reported to be 1.057 incidents/1000mile-year for crude oil pipelines and 0.838 incidents/1000mile-year for crude and refined product pipelines combined. Tables 5.4.1-4 and 5.4.1-5 show the overall pipeline and facilities incident rate for Texas and US reportable incidents for the decade 2001 to 2010. This data is compared in Table 5.4.1-6 to Longhorn Reportable incidents for the period since commissioning activities began in 2002 and the period since operations began in January 2005. This table shows that leak volumes and incident frequencies for the Longhorn pipeline are below the averages for other Texas and US pipeline populations since the start of operations and commissioning. 5.4.2 Spill and Emergency Response Plan This section deals with the response of the operator, contractors, and public agencies to a pipeline spill. Compliance with regulations, adequacy of planning/preparations to protect sensitive areas, response time, and coordination between various response entities are considered in effective emergency response planning. 5.4.2.1 Compliance with Regulations Planning and responding to spills from pipeline operations is regulated under several different federal and state programs, including: • 49 CFR Part 194; • 49 CFR Part 195; • Oil Pollution Act of 1990; • OSHA HAZWOPER; and 5-48 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • TCEQ Spill Prevention and Control (Texas Administrative Code Chapter 327). In addition, there are various industry guidelines that suggest the format and content of an appropriate emergency-planning program. The ANSI B31.4 and American Petroleum Institute Recommended Practice 1129 are examples of such guidelines that were used for comparison to the Longhorn emergency response planning. Present operations are formalized under the following: Longhorn Pipeline Oil Spill FRP; Magellan SIP. The FRP is specific to the Longhorn Pipeline and was developed primarily to comply with the requirements of OPA ‘90 and 49 CFR Part 194. The plan was originally submitted to PHMSA on November 2, 1998 for review and approval, then updated on March 24, 2000. The FRP is reviewed annually and modified as needed. The most recent PHMSA submittal was October 8, 2012 and reflects the pipeline reversal and change in product. The FRP contains information on spill response planning, training, resources and procedures. The plan includes: • Notification procedures for initiating a response and for regulatory reporting; • Release detection procedures and release mitigation procedures; • Description of initial response actions, including immediate response steps, securing the source of the spill, safety and health considerations, storage/disposal of waste materials, endangered species and wildlife rehabilitation, and documentation of the response; • Description of response teams and their responsibilities (all operations and maintenance personnel have the authority to act as the Incident Commander/ Qualified Individual); • Communication equipment; • Personnel and resources available for responding to a spill, including the operator and oil spill response contractors (Employees are generally located within a one-hour response time along the pipeline. The operator has response agreements with emergency response contractors that have equipment and personnel located in Houston, San Antonio, Austin, Eastland, Midland/Odessa, and El Paso. The contractors are required to meet or exceed the requirements of 49 CFR Part 194); and • Containment and diversion booming strategies to protect human life and sensitive resources. The pipeline is mapped on 1:100,000 US Geological Survey (USGS) topographic maps that indicate any lakes, rivers, and streams within five miles of the pipeline. The topographic maps also indicate the potential down gradient flow direction from the pipeline locations. Environmentally sensitive areas are mapped within a radius of one mile of the pipeline per 49 CFR 194.103. Beyond 49 CFR Part 194 requirements, detailed mapping on USGS 7.5-minute topographic maps is included for at least 15-miles downstream on river crossings and in the Houston and Austin areas. Mapping also includes aerial photos of the Houston and Austin areas. The spill training program for field employees includes spill response training, incident command training, and OSHA’s HAZWOPER training. Tabletop exercises or Mock Drills are conducted annually for the Longhorn system and included as part of the spill training. Magellan encourages 5-49 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL and invites local response agencies to participate in periodic tabletop and spill response exercises. An Austin Sub-area Plan was prepared to provide more detailed response information beyond the scope of OPA Plan requirements. This plan includes map locations for known caves and detailed response strategies for the creek crossings in the Austin area. Magellan meets yearly with Local Emergency Planning Committees to work towards appropriate emergency response awareness. Volume I of the FRP presents emergency planning information that is general in nature and common to all portions of the pipeline. Volume II of the FRP addresses specific response zones and sensitive along the pipeline system. Within each of these two response zones, a number of sensitive areas have been identified for a higher degree of specific planning: • Initial Response Actions (IRAs); and • Tactical Response Plans (TRPs). The Longhorn FRP complies with the requirements for emergency planning and preparedness in the applicable regulations. 5.4.2.2 Sensitive Areas Response This subsection addresses how the Longhorn FRP has identified and planned response for sensitive areas along the pipeline. As discussed in the previous subsection, Volumes I and II of the FRP includes IRAs and TRPs in Section 4 to address specific response issues. The IRAs are multi-page tabular checklists of emergency planning information that include: • Initial responder actions; • Area Supervisor/Qualified Individual actions; • Estimated response times for Magellan and contractor personnel; • Local emergency management agencies; • Listing of environmentally sensitive areas near the pipeline section; • Contractor resources that would be used in the response; • Fire and public safety cautions; and • Information about threatened and endangered species. One IRA is typically done for each county that the pipeline crosses. The TRPs are on a folded 11x17-inch page presented in a color page layout format. The TRPs include: • Color map showing the route to access the site 5-50 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • Tabular driving directions to access the site • Text box containing the response strategy • Tables estimating the personnel and equipment required to implement the response • Photos and/or drawings illustrating the implementation of the strategy (such as where booms or dams would be installed, where the vacuum truck would park and similar considerations); and • Series of photos assembled into a panoramic view of the site with annotations added for directions of flow of any water bodies. There are typically several TRPs per county. The TRPs are primarily associated with water crossings and sites down gradient from water crossings where spilled oil can be contained and collected. The FRP also includes a detailed set of pipeline routing maps that show highways, population centers, schools, hospitals, parks/recreation areas, aquifers, water intakes, and waterways. These maps have been further annotated to show areas of known karst formations (caves), potential work sites near the pipeline, road and creek crossings, and details on the Edwards Aquifer. A complete listing of sensitive areas is provided along with a reference to the map or maps on which they are shown, as well as contact information for the sensitive areas. Volume 3 of the FRP contains detailed information as to public and private groundwater sources along the pipeline. The volume also contains engineering drawings for water filtration systems for a series of public water systems along the pipeline. In the event of a release, the water filtration systems can be quickly constructed and attached to public water systems. The LMP has specific requirements related to spill and emergency response within sensitive areas. The following summarizes those mitigation commitments. Per LMC 23, a response center was established in South Austin which includes available response equipment and personnel such that under normal conditions, a maximum two hour, full response can be assured. Response resources have been developed at several locations to assure attainment of the proposed response times. Response personnel and equipment are in place. Per LMC 24, Facilities Response Plans were revised to better address firefighting outside of metropolitan areas (Houston, Austin, and El Paso) where HAZMAT units do not exist. Training of selected volunteer Fire Department personnel that are staging emergency response equipment trailers and enhanced Facility Response plans have been completed and ongoing training is conducted. Per LMC 26, Facility Response Plans were revised prior to startup to include more detailed response planning for areas adjacent to the pipeline ROW which have high populations of potentially sensitive receptors. Per LMC 27, secondary containment was installed at the Cedar Valley pump station in Hays County. 5-51 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Per LMC 28, Facility Response Plans were revised as necessary, to make them consistent to the extent practicable, with the City of Austin’s Barton Springs Oil Spill Contingency Plan and the U.S. Fish and Wildlife Service’s Barton Springs Salamander Recovery Plan. Per LMC 30, provisions were made prior to startup to provide alternate water supplies to certain municipalities and private well users as detailed in Longhorn’s contingency plans. Per LMC 40, the river gauge at the Pedernales River is monitored to anticipate the possibility of a flood event. When the river stage reaches 100,000 cfs at the gauge, Longhorn will immediately shut down the pipeline until the river has receded below the action level (100,000 cfs) at the gauge. Magellan personnel will inspect the pipeline to determine whether it is safe before resuming pipeline operations. This measure will be implemented for the operational life of the pipeline system. 5.4.2.3 Recent Emergency Response Experience There have been no releases requiring emergency response from area Hazmat Response Teams since the start of operations. However, as part of the response plans, annual mock response drills are conducted to test emergency response capabilities. 5.4.2.4 Trench Integrity Assessment – Edwards Aquifer Recharge Zone The pipeline crosses the Edwards Aquifer Recharge Zone south of Austin in Travis County. This 3-mile segment of pipeline has undergone several enhancements designed to mitigate the impacts to the environment from a pipeline release. These enhancements include thicker- walled pipe; enhanced leak detection consisting of a hydrocarbon sensing cable; a control system designed to achieve emergency shutdown with 5-minutes; and a sealed trench with associated mitigation structures. The stated purpose of the pipeline trench design and sealing protocol used along this 3-mile segment of pipeline was to ensure that no material volume of the pipeline product would exit the trench and infiltrate into the underlying aquifer in the unlikely event of a pipeline leak. Two separate reports assessing the condition of the trench have been prepared by companies and individuals who were directly involved in the original trench design, construction, and proof of concept preparation. The first report, entitled, “Trench Integrity and Construction Methodology of the Magellan Longhorn Pipeline from Mile Post 169.88 to 188.8” (October 2012), was prepared by LBG-Guyton Associates and Hatch Mott MacDonald. The purpose of this assessment was to evaluate the integrity of the trench design and to assess material deterioration (Appendix 5C). According to the report, there are several factors controlling the service life of the concrete and gunite used to seal the trench. The primary risk factors affecting service life were determined to be: leaching; delayed ettringite formation; sulfate attack; acid and base attack; salt crystallization; freezing and thawing; abrasion, erosion and cavitation; thermal damage; and seismic and structural loads. The findings of the investigation indicate that the service life for the gunite/concrete trench is expected to last 50 or more years. This 5-52 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL prediction is made with a high level of confidence considering the engineering safeguards utilized during construction, lack of seismic and structural loads, and lack of physical and chemical deterioration. The second report, entitled “Trench Integrity Inspection Report of the Magellan Longhorn Pipeline from Mile Post 169.88 to 173.38” (November 2012), was prepared by LBG-Guyton Associates (Appendix 5D). This report summarizes a visual inspection of the sealed trench at two separate locations within the recharge zone. Extraordinary precautions were taken during excavation to minimize potential impact to the existing trench structure. A vacuum truck was used which allows efficient excavation with air into hard soils without harming underground utilities. The inspection revealed that the gunite and trench were in excellent condition at both locations. The trench floor and walls were dry and the various components of the trench (fill material, hydrocarbon sensing cable conduit, gunite liner and cap) appeared to be in original condition after ten years. The poly coat spot treatment sealant was the only material observed that exhibited any signs of deterioration (peel cracks and divots). This hand application of sealant was used sporadically on blemeshes, surface anamolies, or lateral discontinuities to ensure the underlying gunite provided a water-tight seal. It is possible that some of this deterioration may have occurred during excavation activities. Based on these observations, it was concluded that the pipeline trench design and sealing protocol used within the Edwards Aquifer Recharge Zone will continue to prevent a material volume of fluid from exiting the trench and infiltrating into the underlying aquifer. The conclusions of these two investigations suggest that the trench, road bore pits, diversion berms, and trench sealing materials are performing as originally designed and would be effective in containing a product release along the length of the trench. A detailed discussion of the trench design is provided in the report entitled, “Results of Proof of Concept Tests to Verify the Design and Construction Methods for the Longhorn Partners Pipeline Trench Over the Edwards Aquifer Recharge Zone in Austin, Texas” prepared by LBG-Guyton Associates, December 2001. This document has been uploaded to the docket and is available for review. 5.4.3 Consequence Potential (CoF) This FEA uses a fixed distance buffer, 1,250 feet either side of the centerline, combined with an overland flow spill analysis to evaluate receptor damage potential at distances from the pipeline. This is called the “Zone of Potential Impact” and is used to determine potential impacts described in Chapter 7. For the overland flow analysis, product drain down volume is calculated for selected points along the pipeline. The potential drain down volume is then combined with 5 minutes of maximum flow volume to arrive at a total maximum estimated release volume for a selected point on the pipeline. Maximum estimated release volumes for selected points along the pipeline are shown in Table 5.2.6-3. These volumes are calculated based upon proposed locations of Remotely Controlled Valves (RCVs) for the Proposed Project. 5-53 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL The estimated maximum release volumes are overlaid onto a USGS Digital Elevation Model (DEM) 30-meter grid. A “Least Resistance Path” algorithm is used to determine topological flow direction across the DEM grid. Flow distance is determined by “filling” each DEM grid with a one-half inch of product volume and continuing with the flow direction until the total product volume for the selected point is exhausted. Although 100-ft grids were ‘filled’ in this process, a flow path line was generated. To produce a polygon from the flow paths, a 400-ft buffer (200 feet either side of the line) was added. This allowed a safety factor of at least one grid (on a diagonal (171 feet for a 100-ft square grid)). Thermal effects, surface flow resistance, soil penetration, inclusion of local flow-enabling features smaller than the DEM resolution, and other process details have not been provided. The rigorous calculations performed in the 1999 EA offer confirmation of currently used hazard zones. 5.5 CONCLUSIONS The existing processes, programs and procedures as detailed within the SIP form the cornerstone of integrity for the pipeline and facilities assets that make up the System. The procedures within the SIP are influenced and shaped by applicable regulations including the LMP and industry standards. The execution of the LMCs and associated procedures within the LMP have resulted in an operating pipeline system with a low incident rate as envisioned and stipulated in the 1999 EA. 5.6 REFERENCES Allegro Energy Group, Data provided to Radian International, 1999. Deaver, R.L., Memorandum, “Longhorn Project – Analysis of DOT Accident Reports on Exxon Pipeline Company,” 1998. Department of Transportation Office of Pipeline Safety, dot.ops.gov. Fields, R.J., E.N. Pugh, D.T. Read, J.H. Smith, “As Assessment of the Performance and Reliability of Older ERW Pipelines,” US Department of Commerce, NISTIR 89-4136, July 1989. Fluor Daniel Williams Brothers (FDWBC), Longhorn Partners Pipeline, Phase 1 Environmental Site Assessment, Volume 1, September 1995, pp. 1-116 Harris, O.B., Telephone Contact Report, May 18, 1999. IT Corporation. “Study of Aseismic Faults and Regional Subsidence Along Longhorn Partners Pipeline,” June 14, 2000. Johnston, D.C. and J.F. Kiefner, “Audit of Existing Portions of Longhorn Pipeline,” Kiefner & Associates, February 24, 1999. Johnston, D.C., and Kiefner, J.F., “Audit of Existing Portions of Longhorn Pipeline”, February 24, 1999, Final Report to Jenkins and Gilchrist. Kiefner & Associates, Mock ORA, RAD 41578-41656, October 2000. 5-54 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Kiefner, J.F. and Vieth, P.H., “When Does a Pipeline Need Revalidation? The Influence of Defect Growth Rates and Inspection Criteria on an Operator’s Maintenance Program” in Pipeline Rules of Thumb Handbook. E.W. McAllister (Ed.), Gulf Publishing Co., Houston, Texas, 1998. Kiefner, J.F., Johnston, D.C., “Root Cause Analysis of Accidental Releases on the Former Exxon 18-inch Kemper-to-Satsuma Crude Oil Pipeline (Longhorn Mitigation Commitment 19C, Longhorn Mitigation Plan)”, April, 2004, Final Report to Longhorn Pipeline Partners King, F., “Hydrogen Effects on Carbon Steel Used Fuel Containers”, December 2009, Nuclear Waste Management Organization Report TR-2009-29 Lees, F.P., “Loss Prevention in the Process Industries,” Vol. 3, Butterworth’s, 1996. Longhorn Partners Pipeline, Longhorn PDEA, Longhorn Project Description, March 1, 1999. Longhorn Mitigation Plan, Introduction, revised September 11, 2000. Longhorn Partners Pipeline, “Integrity Management System - Expectations and Guidelines,” URS Radian No. 1049. Longhorn Pipeline Final Draft Environmental Assessment, 2000. URS Radian. Longhorn Pipeline Partners, “OPA Plan (DOT),” URS Radian No. 206. LUFT (1988) “Leaking Underground Fuel Tank Manual: Guidelines for Site Assessment, Cleanup, and Underground Storage Tank Closure,” State of California Leaking Underground Fuel Tank Task Force, May 1988. M. Beller, K. Reber, U. Schneider, “Tools, Vendors, Services - A Review Of Current In-Line Inspection Technologies”, 2002 Conference Proceedings: “The Pipeline Pigging Conference,” Pipe and Pipeline International, Kuala Lumper, June 30-July 2, 1998. McDaniel, Mary (Railroad Commission of Texas), Letter and Enclosed “Evaluation Report of a Liquid Pipeline Carrier,” to Mr. James C. Thomas, Office of Pipeline Safety, DOT, Houston, Texas, April 30, 1996. Muhlbauer, W.K., “Pipeline Risk Management Manual, 2nd Edition,” Gulf Publishing Co., 1996. National Association of Corrosion Engineers (NACE), 2003, “Review of Published Literature on Wet H2S Cracking of Steels through 1989”, September 2003, Item No. 24185, NACE International. National Association of Corrosion Engineers (NACE), Standard Recommended Practice, Control of External Corrosion on Underground or Submerged Metallic Piping Systems, RP 0169-96, Item No. 21001, NACE International, Houston, Texas, 1996 (ISBN 1- 57590-035-1). Pearson, M., Meeting contact with Mike Pearson, Williams Energy Services, April 28, 1999. Pennwell Maps, http://www.mapsearch.com/ines.html Proceedings of the 1996 Pipeline Reliability Conference. “Designing a Cost-Effective and Reliable Pipeline Leak-Detection System,” Houston, Gulf Publishing Company and Scientific Surveys Ltd., 1996. Railroad Commission, Letter, Safety Evaluation of EPC pipeline from Crane to Satsuma, April 30, 1996, URS Radian No. 148. Title 49, Code of Federal Regulations, Part 192, “Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards. 5-55 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL URS Radian, Compilation of Data Summaries and Other Supporting Information to Longhorn Environmental Assessment, August 1999. 5-56 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL CHAPTER 5 TABLES <<>> Audit Date 4/1/2004 4/1/2004 4/11/2005 4/11/2005 4/11/2005 4/11/2005 4/22/2005 10/14/2005 10/14/2005 10/14/2005 10/14/2005 8/8/2006 8/8/2006 8/8/2006 8/8/2006 Table 5.1.1-1 Compliance Audit Findings Summary of Finding Remediation 1A. failure to ensure through evaluations that individuals performing covered tasks are qualified not contested 1B. Respondent failed to provide records to demonstrate that three hundred and fifteen (3 15) of its employees were properly qualified to perform the covered task under Respondent's operator qualification (OQ) program 1. On December 29, 2005, Respondent submitted additional records. Item 1 - IMP failed to include a technically justifiable method for identifying segments that could affect an HCA. Overland Spread analysis criticized; drain- down criticized Modified overland spread calculation method. Adjusted HCAs and conducted additional digs Item 2A - Failure to follow procedure for assessing Highest risk first Withdrawn By PHMSA Item 2B - Relative risk scores did not adequately reflect PoF. Modified risk algorithms Item 3 - Inadequate procedures for placement of EFRD's Modified procedures LMC Inadequacies in addressing low flow conditions identified by PHMSA Respond to PHMSA recommendations for procedural changes Procedures did not reference American Petroleum Institute 1104 19th Ed Procedures corrected 1A. Did not inspect rectifiers monthly 1B. Did not inspect critical bonds monthly Caused by failure of employee, duties transferred to a NACE certified employee. 2C. Many valves not protected from vandalism LH formally disagrees with "fencing" interpretation but installs fencing in spirit of cooperation (420065032 PHMSA LH Fencing Response 06-20-08.doc) Procedures did not reference American Petroleum Institute 1104 19th Ed Procedures corrected 1. insufficient line marking Completed 2. Exceeding valve maint interval 3.Some valves not protected from vandalism Completed 4. Failure to adequately inspect breakout tanks according to Sec 4 American Petroleum Institute 653 Completed 5. Failure to adequately inspect CP on B/O tank according to American Petroleum Institute 651 Completed <<>> Table 5.1.1-1 Compliance Audit Findings (continued) Audit Date Summary of Finding Remediation 8/8/2006 6. Failure to follow LMP for Leak Detect sensitivities and response time, video monitoring of PS, ROW maint, encroachments Completed 5/14/2007 Procedures do not adequately address the following: 1. Procedures to be located where activities are performed 2.A. Welding procedure and qualification records, and record retainage. 2.B. Piping Matrix Table to require visual examination 2.C. American Petroleum Institute 1104 ref (9 instead of 6) in procedures 2.D. Pressure tests without leakage. 2.E. Emergency Training cycle 2.F. Placement of line markers 2.G. movement of HVL PL under pressure 2H. Fire extinguisher inspection 2.I. Excavator notification for temp marker 2. J. MOP reduction resulting from corrosion pitting 3. Immediate response areas 4. 110% of MOP limit in start or SD 5. PL Inspection after Abnormal Ops 6. Reviews for effectiveness of Abnormal Ops 7. Minimizing volume of spill 8. Handling of RR traffic during Emergency Revision of procedures 8/20/2007 Exceeding 15-mo interval for Emergency Training Revise from instructions 12/17/2009 1. Failure to follow LMP, LMC 39 Modified procedures <<>> Table 5.2.1-1a Pipe Characteristics Segment Segment Length (mi) Diameter Manufacturer Seam Type Year Built Type ERW- HF American Petroleum Institute 5L X-52 Galena Park to East Houston 9.55 20" U.S. Steel American Steel 1998 ERW- HF 2010 American Petroleum Institute 5L X-52 East Houston to Crane 457 18"/20" A.O. Smith EFW- LF and ERW- LF 1947, 1950, 1953 American Petroleum Institute 5L X-45, X- 52, GR B U.S. Steel ERW- HF 1998 American Petroleum Institute 5L X-65 Crane to El Paso 235 18" Procarsa ERW- HF 2008 American Petroleum Institute 5L X-52, X- 65 Crane to Odessa 29.27 8.625" California Steel ERW- HF 1998 American Petroleum Institute 5L X-60 Note: Predominant pipe information shown for each segment Wall Thickness (in) 0.312, 0.344, 0.375 0.25, 0.344, 0.375 0.250, 0.281, 0.312, 0.375 0.281, 0.375, 0.5 0.281, 0.375, 0.5 0.188, 0.25 Coating Fusion Bond Epoxy Fusion Bond Epoxy Coal Tar Fusion Bond Epoxy Fusion Bond Epoxy Fusion Bond Epoxy <<>> LINE 6643 6643 6643 6643 6643 6643 6643 6643 6643 6643 6643 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 6645 Table 5.2.1-1b Pipe Characteristics Detail by Manufacturer MANUFACTURER SEAM_TYPE YEAR_BUILT FEET MILES AMERICAN STEEL ERW-HF 2010 13525.60 2.56 HALL LONGMORE ERW-HF 2011 24.00 0.00 HUSTEEL ERW-HF 2010 3594.80 0.68 HUSTEEL ERW-HF 2011 333.25 0.06 HYSCO ERW-HF 2010 1465.50 0.28 HYSCO ERW-HF 2011 126.00 0.02 STUPP STEEL ERW-HF 2010 17.60 0.00 U.S. STEEL ERW-HF 1998 31093.15 5.89 U.S. STEEL SMLS 1998 21.00 0.00 U.S. STEEL ERW-HF 2010 176.80 0.03 U.S. STEEL SMLS 2011 34.50 0.01 A.O. SMITH EFW 1947 134.75 0.03 A.O. SMITH EFW 1950 1743291.52 330.17 A.O. SMITH EFW 1953 264398.10 50.08 A.O. SMITH EFW 1967 24981.20 4.73 AMERICAN STEEL ERW-HF 1984 5291.00 1.00 AMERICAN STEEL ERW-HF 1995 47.00 0.01 AMERICAN STEEL ERW-HF 2000 5523.53 1.05 AMERICAN STEEL ERW-HF 2002 2433.00 0.46 AMERICAN STEEL ERW-HF 2004 1648.00 0.31 AMERICAN STEEL SMLS 2004 98.00 0.02 AMERICAN STEEL ERW-HF 2005 988.00 0.19 AMERICAN STEEL ERW-HF 2006 24.50 0.00 AMERICAN STEEL SMLS 2006 49.50 0.01 AMERICAN STEEL ERW-HF 2007 4018.00 0.76 AMERICAN STEEL ERW-HF 2008 68.00 0.01 AMERICAN STEEL ERW-HF 2010 4695.60 0.89 AMERICAN STEEL ERW-HF 2011 22001.00 4.17 APA PIPE CORP. ERW-HF 2010 212.00 0.04 CORUS ERW-HF 2006 17.00 0.00 CORUS SMLS 2006 16.00 0.00 HUSTEEL ERW-HF 2008 4856.00 0.92 HUSTEEL ERW-HF 2010 16103.70 3.05 KAWASAKI STEEL ERW-HF 1999 128.00 0.02 KAWASAKI STEEL ERW-HF 2000 108.50 0.02 KAWASAKI STEEL ERW-HF 2001 18.00 0.00 KAWASAKI STEEL ERW-HF 2002 465.75 0.09 KAWASAKI STEEL ERW-HF 2004 59.50 0.01 KAWASAKI STEEL ERW-HF 2010 47.00 0.01 KAWASHO ERW-HF 2007 45.00 0.01 MANNESMANN ERW-HF 2010 2154.00 0.41 <<>> Table 5.2.1-1b Pipe Characteristics Detail by Manufacturer (continued) LINE MANUFACTURER SEAM_TYPE YEAR_BUILT FEET MILES 6645 NAPA (FORMERLY KAISER) DSAW 2000 1534.00 0.29 6645 NAPA (FORMERLY KAISER) DSAW 2001 1904.50 0.36 6645 NAPA (FORMERLY KAISER) DSAW 2002 3695.00 0.70 6645 NAPA (FORMERLY KAISER) DSAW 2004 22.00 0.00 6645 NAPA (FORMERLY KAISER) DSAW 2010 9.00 0.00 6645 NIPPON STEEL ERW-HF 1998 2.00 0.00 6645 NIPPON STEEL ERW-HF 1999 229.00 0.04 6645 NIPPON STEEL ERW-HF 2000 361.75 0.07 6645 NIPPON STEEL ERW-HF 2002 2153.75 0.41 6645 NIPPON STEEL ERW-HF 2004 154.75 0.03 6645 PROCARSA ERW-HF 2008 212657.80 40.28 6645 STUPP STEEL ERW-HF 1998 5.00 0.00 6645 STUPP STEEL ERW-HF 2002 4794.50 0.91 6645 STUPP STEEL ERW-HF 2010 17.70 0.00 6645 SUMITOMO STEEL ERW-HF 1998 189.50 0.04 6645 SUMITOMO STEEL ERW-HF 2004 376.00 0.07 6645 TULSA TUBE SMLS 2004 11.00 0.00 6645 U.S. STEEL ERW-HF 1984 201.10 0.04 6645 U.S. STEEL ERW-HF 1998 1064683.30 201.64 6645 U.S. STEEL SMLS 1998 29.00 0.01 6645 U.S. STEEL ERW-HF 1999 85.30 0.02 6645 U.S. STEEL ERW-HF 2000 10693.10 2.03 6645 U.S. STEEL ERW-HF 2001 3011.00 0.57 6645 U.S. STEEL ERW-HF 2002 111576.00 21.13 6645 U.S. STEEL ERW-HF 2004 130.45 0.02 6645 U.S. STEEL SMLS 2004 59.00 0.01 6645 U.S. STEEL ERW-HF 2006 190.50 0.04 6645 U.S. STEEL ERW-HF 2008 48.75 0.01 6645 U.S. STEEL ERW-HF 2010 141.40 0.03 6645 UNITED ERW-HF 1998 124.00 0.02 6645 UNKNOWN ERW-LF 1947 124378.45 23.56 6645 UNKNOWN ERW-LF 1950 202.00 0.04 6645 UNKNOWN ERW-LF 1953 2515.00 0.48 6645 UNKNOWN ERW-HF 1979 346.00 0.07 6645 UNKNOWN ERW-HF 1982 598.00 0.11 6645 UNKNOWN ERW-HF 1987 84.00 0.02 6645 UNKNOWN ERW-HF 1988 677.50 0.13 6645 UNKNOWN ERW-HF 1995 654.00 0.12 6645 UNKNOWN ERW-HF 1998 1244.80 0.24 6645 UNKNOWN SMLS 1998 38.00 0.01 6645 UNKNOWN ERW-HF 2002 11.00 0.00 6648 AMERICAN STEEL ERW-HF 1998 134.00 0.03 <<>> Table 5.2.1-1b Pipe Characteristics Detail by Manufacturer (continued) LINE MANUFACTURER SEAM_TYPE YEAR_BUILT FEET 6648 AMERICAN STEEL SMLS 1998 19.50 6648 CALIFORNIA STEEL INDUSTRIES ERW-HF 1998 148237.00 6648 CALIFORNIA STEEL INDUSTRIES ERW-HF 2004 1296.66 6648 TEX-TUBE STEEL ERW-HF 2004 348.00 6648 U.S. STEEL ERW-HF 2004 4350.88 6648 U.S. STEEL SMLS 2004 135.91 MILES 0.00 28.08 0.25 0.07 0.82 0.03 <<>> Table 5.2.1-1c Pipe Characteristics Detail by Coating Type Segment Name Year Built Grades Segment Length (mi) Diameter (in) Wall Thickness (in) Coating Seam Type 6643: Galena Park to East Houston 1998 5LX-52 0.0250 20 0.312 EPOXY PAINT ERW-HF 6643: Galena Park to East Houston 1998 5LX-52 5.8596 20 0.312,0.344,0 .375 FUSION BOND EPOXY ERW-HF 6643: Galena Park to East Houston 1998 5LX- 52,GR. B 0.0043 20 0.375 PAINT ERW-HF 6643: Galena Park to East Houston 1998 GR. B 0.0040 20 0.375 PLASTIC TAPE/PAINT SMLS 6643: Galena Park to East Houston 2010 5LX-52 0.0018 20 0.375 FBE/PAINT ERW-HF 6643: Galena Park to East Houston 2010 5LX-52 2.5617 20 0.25,0.375 FUSION BOND EPOXY ERW-HF 6643: Galena Park to East Houston 2010 5LX-52 0.6806 20 0.375 FUSION BOND EPOXY ERW-HF 6643: Galena Park to East Houston 2010 5LX-52 0.2776 20 0.25,0.344 FUSION BOND EPOXY ERW-HF 6643: Galena Park to East Houston 2010 5LX-52 0.0015 20 0.375 FUSION BOND EPOXY ERW-HF 6643: Galena Park to East Houston 2010 5LX-52 0.0335 20 0.375 FUSION BOND EPOXY ERW-HF 6643: Galena Park to East Houston 2010 5LX-52 0.0002 20 0.375 PAINT ERW-HF 6643: Galena Park to East Houston 2011 5LX-60 0.0011 16 0.375 PAINT ERW-HF 6643: Galena Park to East Houston 2011 5LX-60 0.0017 20 0.375 FBE/PAINT ERW-HF 6643: Galena Park to East Houston 2011 5LX-42 0.0042 20 0.5 FBE/PAINT ERW-HF 6643: Galena Park to East Houston 2011 5LX-42 0.0030 20 0.5 FUSION BOND EPOXY ERW-HF 6643: Galena Park to East Houston 2011 5LX-60 0.0599 20 0.375 FUSION BOND EPOXY ERW-HF 6643: Galena Park to East Houston 2011 5LX-42 0.0158 20 0.5 FUSION BOND EPOXY ERW-HF 6643: Galena Park to East Houston 2011 5LX-52 0.0043 20 0.375 FUSION BOND EPOXY SMLS 6643: Galena Park to East Houston 2011 5LX-42 0.0015 20 0.5 PAINT ERW-HF 6643: Galena Park to East Houston 2011 5LX-60 0.0004 20 0.375 PAINT ERW-HF 6643: Galena Park to East Houston 2011 5LX-42 0.0039 20 0.5 PAINT ERW-HF 6643: Galena Park to East Houston 2011 5LX-52 0.0023 20 0.375 PAINT SMLS 6645: East Houston to El Paso 1947 5LX-45 0.0255 18 0.281 COAL TAR EFW 6645: East Houston to El Paso 1947 GR. B 1.4363 20 0.312,0.375 COAL TAR ERW-LF 6645: East Houston to El Paso 1947 GR. B 0.0009 20 0.312 EPOXY PAINT ERW-LF 6645: East Houston to El Paso 1947 GR. B 0.0993 20 0.312,0.375 PLASTIC TAPE ERW-LF 6645: East Houston to El Paso 1947 5LX- 22.0200 20 0.312,0.375 UNKNOWN ERW-LF Manufacturer U.S. STEEL U.S. STEEL U.S. STEEL U.S. STEEL STUPP STEEL AMERICAN STEEL HUSTEEL HYSCO STUPP STEEL U.S. STEEL HUSTEEL HUSTEEL HUSTEEL HYSCO HALL LONGMORE HUSTEEL HYSCO U.S. STEEL HALL LONGMORE HUSTEEL HYSCO U.S. STEEL A.O. SMITH UNKNOWN UNKNOWN UNKNOWN UNKNOWN <<>> Table 5.2.1-1c Pipe Characteristics Detail by Coating Type (continued) Segment Name Year Built Grades Segment Length (mi) Diameter (in) Wall Thickness (in) 42,GR. B 6645: East Houston to El Paso 1950 5LX-45 326.3091 18 0.281,0.287,0 .312,0.375 6645: East Houston to El Paso 1950 5LX-46 0.0038 18 0.281 6645: East Houston to El Paso 1950 5LX-45 0.0502 18 0.281 6645: East Houston to El Paso 1950 5LX-45 0.1602 18 0.281,0.312 6645: East Houston to El Paso 1950 5LX-45 0.3121 18 0.281,0.312 6645: East Houston to El Paso 1950 5LX-45 0.0280 18 0.281 6645: East Houston to El Paso 1950 5LX- 45,5LX- 46 2.8237 18 0.281,0.287,0 .312,0.375 6645: East Houston to El Paso 1950 GR. B 0.0254 18 0.375 6645: East Houston to El Paso 1950 5LX-45 0.0076 18 0.281 6645: East Houston to El Paso 1950 5LX- 45,GR. B 0.4778 18 0.312,0.375 6645: East Houston to El Paso 1950 5LX- 42,5LX- 46 0.0091 18 0.312,0.375 6645: East Houston to El Paso 1953 5LX-52 50.0127 18 0.25,0.375 6645: East Houston to El Paso 1953 5LX-52 0.4763 18 0.25 6645: East Houston to El Paso 1953 5LX-52 0.0186 18 0.25 6645: East Houston to El Paso 1953 5LX-52 0.0441 18 0.25 6645: East Houston to El Paso 1967 5LX-65 4.7142 18 0.281,0.312 6645: East Houston to El Paso 1967 5LX-65 0.0045 18 0.281 6645: East Houston to El Paso 1967 5LX-65 0.0125 18 0.281 6645: East Houston to El Paso 1979 GR. B 0.0655 20 0.375 6645: East Houston to El Paso 1982 GR. B 0.0106 20 0.312 Coating COAL TAR COAL TAR EPOXY PAINT EPOXY/PE NON-SHIELDING TAPE (RD-6) PAINT PLASTIC TAPE PLASTIC TAPE TAR SET UNKNOWN UNKNOWN COAL TAR COAL TAR NON-SHIELDING TAPE (RD-6) PLASTIC TAPE COAL TAR NON-SHIELDING TAPE (RD-6) PLASTIC TAPE COAL TAR EPOXY/PE Seam Type EFW ERW-LF EFW EFW EFW EFW EFW ERW-LF EFW EFW ERW-LF EFW ERW-LF EFW EFW EFW EFW EFW ERW-HF ERW-HF Manufacturer A.O. SMITH UNKNOWN A.O. SMITH A.O. SMITH A.O. SMITH A.O. SMITH A.O. SMITH UNKNOWN A.O. SMITH A.O. SMITH UNKNOWN A.O. SMITH UNKNOWN A.O. SMITH A.O. SMITH A.O. SMITH A.O. SMITH A.O. SMITH UNKNOWN UNKNOWN <<>> Table 5.2.1-1c Pipe Characteristics Detail by Coating Type (continued) Segment Name Year Built Grades Segment Length (mi) Diameter (in) Wall Thickness (in) 6645: East Houston to El Paso 1982 GR. B 0.1027 20 0.312 6645: East Houston to El Paso 1984 5LX- 42,5LX- 52,GR. B 1.0015 18 0.281,0.375 6645: East Houston to El Paso 1984 GR. B 0.0006 18 0.375 6645: East Houston to El Paso 1984 GR. B 0.0381 18 0.375 6645: East Houston to El Paso 1987 GR. B 0.0159 20 0.312 6645: East Houston to El Paso 1988 GR. B 0.0867 20 0.375 6645: East Houston to El Paso 1988 5LX-42 0.0416 20 0.375 6645: East Houston to El Paso 1995 5LX-45 0.0089 18 0.281 6645: East Houston to El Paso 1995 5LX-46 0.0284 18 0.281 6645: East Houston to El Paso 1995 5LX-42 0.0028 18 0.375 6645: East Houston to El Paso 1995 5LX-42 0.0068 18 0.5 6645: East Houston to El Paso 1995 5LX-52 0.0715 18 0.375 6645: East Houston to El Paso 1995 5LX- 42,5LX- 52 0.0144 18 0.375 6645: East Houston to El Paso 1998 5LX-52 0.0359 18 0.375 6645: East Houston to El Paso 1998 5LX- 52,5LX- 65 197.7403 18 0.281,0.375 6645: East Houston to El Paso 1998 5LX-42 0.2335 18 0.5 6645: East Houston to El Paso 1998 5LX-65 0.0030 18 0.281 6645: East Houston to El Paso 1998 5LX- 52,5LX- 65 0.0448 18 0.281,0.375 6645: East Houston to El Paso 1998 5LX-65 0.0009 18 0.375 6645: East Houston to El Paso 1998 5LX-65 0.2788 18 0.281,0.375 Coating PLASTIC TAPE COAL TAR PLASTIC TAPE PLASTIC TAPE PLASTIC TAPE COAL TAR ENAMEL EXTRUDED POLYETHYLENE COAL TAR COAL TAR EPOXY/PLASTIC TAPE FUSION BOND EPOXY PLASTIC TAPE UNKNOWN FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY NON-SHIELDING TAPE (RD-6) PAINT PLASTIC TAPE PLASTIC TAPE Seam Type ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF Manufacturer UNKNOWN AMERICAN STEEL AMERICAN STEEL U.S. STEEL UNKNOWN UNKNOWN UNKNOWN AMERICAN STEEL UNKNOWN UNKNOWN UNKNOWN UNKNOWN UNKNOWN SUMITOMO STEEL U.S. STEEL UNKNOWN U.S. STEEL U.S. STEEL STUPP STEEL U.S. STEEL <<>> Table 5.2.1-1c Pipe Characteristics Detail by Coating Type (continued) Segment Name Year Built Grades Segment Length (mi) Diameter (in) Wall Thickness (in) 6645: East Houston to El Paso 1998 5LX-65 0.0235 18 0.281 6645: East Houston to El Paso 1998 5LX-52 0.0060 18 0.375 6645: East Houston to El Paso 1998 5LX-52 0.0023 18 0.375 6645: East Houston to El Paso 1998 GR. B 0.0072 18 0.281 6645: East Houston to El Paso 1998 5LX-52 3.5689 20 0.312,0.344,0 .375 6645: East Houston to El Paso 1998 5LX-52 0.0004 20 0.375 6645: East Houston to El Paso 1998 5LX-52 0.0029 20 0.375 6645: East Houston to El Paso 1998 GR. B 0.0055 20 0.375 6645: East Houston to El Paso 1999 5LX-52 0.0242 18 0.375 6645: East Houston to El Paso 1999 5LX-52 0.0434 18 0.375 6645: East Houston to El Paso 1999 5LX-65 0.0152 18 0.281 6645: East Houston to El Paso 1999 5LX-65 0.0009 20 0.312 6645: East Houston to El Paso 2000 5LX-65 0.2894 18 0.375,0.385,0 .406 6645: East Houston to El Paso 2000 5LX- 52,5LX- 60,5LX- 65 1.0461 18 0.281,0.312,0 .375,0.385 6645: East Houston to El Paso 2000 5LX-52 0.0205 18 0.375 6645: East Houston to El Paso 2000 5LX- 52,5LX- 65 0.0080 18 0.375 6645: East Houston to El Paso 2000 5LX- 52,5LX- 65 2.0051 18 0.281,0.312,0 .375 6645: East Houston to El Paso 2000 5LX-52 0.0040 18 0.375 6645: East Houston to El Paso 2000 5LX-52 0.0049 18 0.375 6645: East Houston to El Paso 2000 5LX-65 0.0011 18 0.385 Coating PLASTIC TAPE PLASTIC TAPE/PAINT PLASTIC TAPE/PAINT PLASTIC TAPE/PAINT FUSION BOND EPOXY PAINT PAINT PLASTIC TAPE/PAINT FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY PAINT PAINT PLASTIC TAPE Seam Type ERW-HF ERW-HF ERW-HF SMLS ERW-HF ERW-HF ERW-HF SMLS ERW-HF ERW-HF ERW-HF ERW-HF DSAW ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF DSAW Manufacturer UNITED U.S. STEEL UNKNOWN UNKNOWN U.S. STEEL NIPPON STEEL U.S. STEEL U.S. STEEL KAWASAKI STEEL NIPPON STEEL U.S. STEEL U.S. STEEL NAPA (FORMERLY KAISER) AMERICAN STEEL KAWASAKI STEEL NIPPON STEEL U.S. STEEL NIPPON STEEL U.S. STEEL NAPA (FORMERLY KAISER) <<>> Table 5.2.1-1c Pipe Characteristics Detail by Coating Type (continued) Segment Name Year Built Grades Segment Length (mi) Diameter (in) Wall Thickness (in) 6645: East Houston to El Paso 2000 5LX-65 0.0152 18 0.281 6645: East Houston to El Paso 2000 5LX- 56,5LX- 60 0.0513 20 0.375 6645: East Houston to El Paso 2000 5LX-52 0.0053 20 0.375 6645: East Houston to El Paso 2001 5LX-65 0.3607 18 0.375,0.385 6645: East Houston to El Paso 2001 5LX-65 0.0034 18 0.375 6645: East Houston to El Paso 2001 5LX-65 0.5694 18 0.281,0.375 6645: East Houston to El Paso 2001 5LX-65 0.0009 18 0.375 6645: East Houston to El Paso 2002 5LX-65 0.4114 18 0.375 6645: East Houston to El Paso 2002 5LX-65 0.6998 18 0.38,0.385 6645: East Houston to El Paso 2002 5LX-65 0.4608 18 0.281 6645: East Houston to El Paso 2002 5LX- 52,5LX- 65 0.0812 18 0.375 6645: East Houston to El Paso 2002 5LX- 52,5LX- 60,5LX- 65 0.0563 18 0.375 6645: East Houston to El Paso 2002 5LX-65 0.9080 18 0.375,0.385 6645: East Houston to El Paso 2002 5LX- 65,5LX- 70 20.7193 18 0.281,0.375,0 .385 6645: East Houston to El Paso 2002 5LX-65 0.0011 18 0.375 6645: East Houston to El Paso 2002 5LX-52 0.0071 18 0.375 6645: East Houston to El Paso 2002 5LX-52 0.0018 18 0.375 6645: East Houston to El Paso 2002 5LX-52 0.0021 18 0.375 Coating UNKNOWN FUSION BOND EPOXY PAINT FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY PAINT COAL TAR/EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY NON-SHIELDING TAPE (RD-6) PAINT PAINT UNKNOWN Seam Type ERW-HF ERW-HF ERW-HF DSAW ERW-HF ERW-HF ERW-HF ERW-HF DSAW ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF Manufacturer U.S. STEEL NIPPON STEEL NIPPON STEEL NAPA (FORMERLY KAISER) KAWASAKI STEEL U.S. STEEL U.S. STEEL U.S. STEEL NAPA (FORMERLY KAISER) AMERICAN STEEL KAWASAKI STEEL NIPPON STEEL STUPP STEEL U.S. STEEL U.S. STEEL KAWASAKI STEEL NIPPON STEEL UNKNOWN <<>> Table 5.2.1-1c Pipe Characteristics Detail by Coating Type (continued) Segment Name Year Built Grades Segment Length (mi) Diameter (in) Wall Thickness (in) 6645: East Houston to El Paso 2002 5LX- 56,5LX- 60,5LX- 65 0.3498 20 0.375 6645: East Houston to El Paso 2004 5LX-52 0.0018 18 0.375 6645: East Houston to El Paso 2004 5LX-65 0.0090 18 0.375 6645: East Houston to El Paso 2004 5LX-65 0.0042 18 0.385 6645: East Houston to El Paso 2004 5LX-65 0.0472 18 0.281,0.375 6645: East Houston to El Paso 2004 5LX-65 0.0095 18 0.375 6645: East Houston to El Paso 2004 5LX-52 0.0009 18 0.375 6645: East Houston to El Paso 2004 5LX-52 0.0712 18 0.375 6645: East Houston to El Paso 2004 5LX-65 0.0119 18 0.375 6645: East Houston to El Paso 2004 5LX-52 0.0010 18 0.375 6645: East Houston to El Paso 2004 5LX- 52,GR. B 0.0126 18 0.375 6645: East Houston to El Paso 2004 5LX- 65,GR. B 0.0036 18 0.375 6645: East Houston to El Paso 2004 5LX-52 0.0011 18 0.375 6645: East Houston to El Paso 2004 5LX-65 0.0002 18 0.281 6645: East Houston to El Paso 2004 5LX-52 0.0112 18 0.375 6645: East Houston to El Paso 2004 5LX- 52,5LX- 60 0.2566 20 0.375 6645: East Houston to El Paso 2004 5LX-60 0.0134 20 0.375 6645: East Houston to El Paso 2004 5LX-52 0.0186 20 0.375 6645: East Houston to El Paso 2004 5LX-52 0.0038 20 0.375 6645: East Houston to El Paso 2004 5LX-60 0.0008 20 0.375 6645: East Houston to El Paso 2004 5LX-60 0.0015 20 0.375 6645: East Houston to El Paso 2004 5LX-52 0.0045 20 0.375 Coating FUSION BOND EPOXY COAL TAR COAL TAR FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY PAINT PAINT PAINT PLASTIC TAPE PLASTIC TAPE/PAINT FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY PAINT PAINT PLASTIC TAPE PLASTIC TAPE/PAINT Seam Type ERW-HF ERW-HF ERW-HF DSAW ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF SMLS ERW-HF ERW-HF SMLS ERW-HF SMLS ERW-HF ERW-HF SMLS ERW-HF ERW-HF ERW-HF ERW-HF Manufacturer NIPPON STEEL KAWASAKI STEEL U.S. STEEL NAPA (FORMERLY KAISER) AMERICAN STEEL KAWASAKI STEEL NIPPON STEEL SUMITOMO STEEL U.S. STEEL TULSA TUBE NIPPON STEEL U.S. STEEL TULSA TUBE U.S. STEEL U.S. STEEL AMERICAN STEEL NIPPON STEEL AMERICAN STEEL AMERICAN STEEL NIPPON STEEL NIPPON STEEL AMERICAN STEEL <<>> Table 5.2.1-1c Pipe Characteristics Detail by Coating Type (continued) Segment Name Year Built Grades Segment Length (mi) Diameter (in) Wall Thickness (in) 6645: East Houston to El Paso 2005 5LX-65 0.1871 18 0.375 6645: East Houston to El Paso 2006 5LX- 52,5LX- 65 0.0084 18 0.375 6645: East Houston to El Paso 2006 5LX-65 0.0010 18 0.375 6645: East Houston to El Paso 2006 5LX-52 0.0032 18 0.375 6645: East Houston to El Paso 2006 5LX- 52,5LX- 65 0.0277 18 0.375 6645: East Houston to El Paso 2006 5LX-65 0.0060 18 0.375 6645: East Houston to El Paso 2006 5LX-65 0.0036 18 0.375 6645: East Houston to El Paso 2006 5LX-65 0.0034 18 0.375 6645: East Houston to El Paso 2006 5LX-52 0.0030 18 0.375 6645: East Houston to El Paso 2007 5LX-65 0.7610 18 0.281 6645: East Houston to El Paso 2007 5LX-52 0.0085 18 0.375 6645: East Houston to El Paso 2008 5LX-52 0.9197 18 0.375,0.5 6645: East Houston to El Paso 2008 5LX-65 40.2555 18 0.281,0.375 6645: East Houston to El Paso 2008 5LX-52 0.0129 18 0.375 6645: East Houston to El Paso 2008 5LX-65 0.0206 18 0.375 6645: East Houston to El Paso 2008 5LX-65 0.0075 18 0.375,0.5 6645: East Houston to El Paso 2008 5LX-65 0.0017 18 0.281 6645: East Houston to El Paso 2010 5LX-52 0.0068 18 0.375 6645: East Houston to El Paso 2010 5LX-65 0.0017 18 0.385 6645: East Houston to El Paso 2010 5LX- 52,5LX- 65 0.4127 18 0.281,0.375 6645: East Houston to El Paso 2010 5LX-65 0.0402 18 0.375 6645: East Houston to El Paso 2010 5LX-52 0.0021 18 0.375 6645: East Houston to El Paso 2010 5LX- 0.4080 18 0.375 Coating FUSION BOND EPOXY FUSION BOND EPOXY PAINT PAINT PAINT PAINT PLASTIC TAPE PLASTIC TAPE PLASTIC TAPE/PAINT FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY PAINT PAINT PAINT PLASTIC TAPE FBE/PAINT FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY Seam Type ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF SMLS ERW-HF SMLS SMLS ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF DSAW ERW-HF ERW-HF ERW-HF ERW-HF Manufacturer AMERICAN STEEL U.S. STEEL AMERICAN STEEL CORUS U.S. STEEL AMERICAN STEEL AMERICAN STEEL AMERICAN STEEL CORUS AMERICAN STEEL KAWASHO HUSTEEL PROCARSA AMERICAN STEEL PROCARSA U.S. STEEL U.S. STEEL KAWASAKI STEEL NAPA (FORMERLY KAISER) AMERICAN STEEL APA PIPE CORP. KAWASAKI STEEL MANNESMANN <<>> Table 5.2.1-1c Pipe Characteristics Detail by Coating Type (continued) Segment Name Year Built Grades Segment Length (mi) Diameter (in) Wall Thickness (in) 52,5LX- 65 6645: East Houston to El Paso 2010 5LX-65 0.0011 18 0.281 6645: East Houston to El Paso 2010 5LX-52 0.0018 20 0.375 6645: East Houston to El Paso 2010 5LX-52 0.4755 20 0.375 6645: East Houston to El Paso 2010 5LX-52 3.0492 20 0.375 6645: East Houston to El Paso 2010 5LX-52 0.0016 20 0.375 6645: East Houston to El Paso 2010 5LX-52 0.0268 20 0.375 6645: East Houston to El Paso 2010 5LX-52 0.0007 20 0.375 6645: East Houston to El Paso 2011 5LX-65 4.1669 18 0.281,0.375 6648: Crane to Odessa 1998 GR. B 0.0037 8.625 0.322 6648: Crane to Odessa 1998 5LX-46 0.0227 8.625 0.25 6648: Crane to Odessa 1998 5LX- 42,5LX- 60 28.0741 8.625 0.188,0.25 6648: Crane to Odessa 1998 5LX-46 0.0027 8.625 0.25 6648: Crane to Odessa 1998 5LX-42 0.0011 8.625 0.25 6648: Crane to Odessa 2004 5LX- 52,5LX- 60 0.0781 8.625 0.25,0.322 6648: Crane to Odessa 2004 5LX- 52,5LX- 60,GR. B 0.8110 8.625 0.188,0.277,0 .322 6648: Crane to Odessa 2004 GR. B 0.0109 8.625 0.322 6648: Crane to Odessa 2004 5LX-52 0.0014 8.625 0.322 6648: Crane to Odessa 2004 5LX-60 0.0009 8.625 0.277 6648: Crane to Odessa 2004 GR. B 0.0006 8.625 0.322 6648: Crane to Odessa 2004 5LX-60 0.0020 8.625 0.188 Coating PAINT FBE/PAINT FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY FUSION BOND EPOXY PAINT FUSION BOND EPOXY FBE/PAINT FUSION BOND EPOXY FUSION BOND EPOXY PAINT PAINT EPOXY/PE EPOXY/PE EPOXY/PE EPOXY/PLASTIC TAPE EPOXY/PLASTIC TAPE FBE/PAINT FUSION BOND EPOXY Seam Type ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF SMLS ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF ERW-HF SMLS ERW-HF ERW-HF SMLS ERW-HF Manufacturer AMERICAN STEEL STUPP STEEL AMERICAN STEEL HUSTEEL STUPP STEEL U.S. STEEL HUSTEEL AMERICAN STEEL AMERICAN STEEL AMERICAN STEEL CALIFORNIA STEEL INDUSTRIES AMERICAN STEEL CALIFORNIA STEEL INDUSTRIES CALIFORNIA STEEL INDUSTRIES U.S. STEEL U.S. STEEL CALIFORNIA STEEL INDUSTRIES U.S. STEEL U.S. STEEL U.S. STEEL <<>> Table 5.2.1-1c Pipe Characteristics Detail by Coating Type (continued) Segment Name Year Built Grades Segment Length (mi) Diameter (in) Wall Thickness (in) 6648: Crane to Odessa 2004 5LX- 52,5LX- 60 0.1660 8.625 0.25,0.322 6648: Crane to Odessa 2004 5LX-42 0.0659 8.625 0.322 6648: Crane to Odessa 2004 5LX- 60,GR. B 0.0101 8.625 0.277 6648: Crane to Odessa 2004 GR. B 0.0143 8.625 0.322 PAINT PAINT PAINT PAINT Coating Seam Type ERW-HF ERW-HF ERW-HF SMLS Manufacturer CALIFORNIA STEEL INDUSTRIES TEX-TUBE STEEL U.S. STEEL U.S. STEEL <<>> Table 5.2.1-2 Overview of Pipeline Construction Specifications Discussions with Magellan reveal that their construction specifications are the same as the Williams CS4 specifications shown in the table below. Section 1949, Humble Oil Kemper (Crane) – Satsuma 1998, Williams CS4 Galena Park Station - Satsuma, Station (9.1 miles) Refurbishing Satsuma Station-Kemper Station, Odessa Lateral, Crane Station - El Paso Terminal 49 CFR Part 195* see note below Minimum Depth of Cover (inches) Normal Excavation Industrial, Commercial, Residential 24 36 36 Water body > 100 ft (high water marks) 24 48 48 Drainage Ditches 24 36 36 Other 24 30 30 Rock Excavation Industrial, Commercial, Residential 12 30 30 Water body > 100 ft (high water marks) 4 (concrete) 18 18 Drainage Ditches 12 36 36 Other 12 18 18 Crossings Hard-surfaced road (cased) Vented casing, Kapco rock shield in addition to coating, seal bushings Vented casing, 1.25 inch reinforced concrete jacket, seal bushings; 4 ft clearance to road foundation, 3 ft to bottom of drainage ditch. Installation must withstand traffic loads. Railroad Same as hard-surfaced road Cased: 5 ft 6 inch clearance to top of RR ties, 3 ft to bottom of drainage ditch; Uncased: 10 ft to top of ties, 6 ft to bottom of drainage ditch. Installation must withstand traffic loads. River Weighted so it will not float when empty (2-inch concrete sheaths), split offset weld sleeves over welds, Kapco Rock shield over ends. With riprap: rock plugs (typ. 50 ft to each side, 3 ft clearance from top of pipe to base of rock plug, 8 ft to river bottom; w/o riprap min 4 ft to river bottom; concrete weights as required. Cover specified as 48 inches for normal excavation and 18 inches for rock excavation. Irrigation canal Open cut, 5 ft of cover Covered under general depth of cover or drainage ditches. <<>> Table 5.2.1-2 Overview of Pipeline Construction Specifications (continued) Section 1949, Humble Oil Kemper (Crane) – Satsuma 1998, Williams CS4 Galena Park Station - Satsuma, Station (9.1 miles) Refurbishing Satsuma Station-Kemper Station, Odessa Lateral, Crane Station - El Paso Terminal 49 CFR Part 195* see note below Bar ditch 30-inch clearance, including 6- inch concrete slab Covered under general depth of cover or drainage ditches. Other Pipe 12-inch clearance, pass below 24 inch normal, 12 inch in rock Clearance of 12 inches from other underground structures. Coating and Wrapping Regular Weld, clean, prime (coal tar base), dry, coal tar enamel & asbestos PL felt machine-applied to 94 mils, cool. GATX-Crane: Fusion bond epoxy; Crane-El Paso: weld, clean, hot enamel (94 mil min. yard applied, 18 mil glass mat wrapped and embedded, poured molten enamel, coal tar PL felt wrapped. Specified in general terms River Crossings Weld, clean, prime (coal tar base), dry, double coat coal tar enamel, glass mat wrapper, coat coal tar enamel, asbestos PL felt and Kraft paper, yard- applied in Houston. Same as regular Specified in general terms Welds AWS Class E-6010 electrodes or similar American Petroleum Institute Standard 1104 (17th Ed. Sep 88), Sect. IX of ASME Boiler and Pressure Vessel Code American Petroleum Institute Standard 1104 and Section IX of ASME Boiler and Pressure Vessel Code Hydrostatic Testing 1000 psi, 4 hours 1525-1575 psi, 8 hours §195.303 CP Not mentioned Specified in detail §195.414 Per 49 CFR Part 195.210 – No pipeline may be located within 50 feet of any private dwelling, or any industrial building or place of public assembly in which persons work, congregate, or assemble, unless it is provided with at least 12 inches of cover in addition to that described above. <<>> Table 5.2.6-1 Valve Locations and Types for the Longhorn Pipeline Longhorn Milepost Valve Type Valve Location 0.00 Motor Operated Block Valve MOV 8 - BOL-Galena Park Station 0.00 Remotely Operated Block Valve GS1 - Galena Park Station 1.86 Motor Operated Block Valve MOV 107 Holland Ave.- Incoming Line “B” 1.77 Motor Operated Block Valve MOV 106 Holland Ave.- Outgoing Line “A” 5.34 Manual Block Valve GS2 (Wallisville Rd.) 9.47 Motor Operated Block Valve MOV 231 - East Houston Term. 9.47 Motor Operated Block Valve MOV 233 - East Houston Term. - Incoming 2.36 Motor Operated Block Valve MOV 237 - East Houston Term. - Outgoing 2.36 Motor Operated Block Valve MOV 235 - East Houston Term. 7.46 Manual Block Valve GS3 (S. SIDE CADDO ST.) 11.98 Remotely Operated Block Valve GS5 (MESA RD./FM 527) 21.20 Remotely Operated Block Valve GS-6 (SWEETWATER LANE) 34.09 Remotely Operated Block Valve GS7 34.09 Motor Operated Block Valve Satsuma Station - Incoming 34.14 Motor Operated Block Valve Satsuma Station - Outgoing 34.14 Remotely Operated Block Valve SE1 63.78 Motor Operated Block Valve SE2 (E. SIDE BRAZOS RIVER) 64.08 CHECK SE3 (W. SIDE BRAZOS RIVER) 64.08 Manual Block Valve SE3 (W. SIDE BRAZOS RIVER) 112.89 Motor Operated Block Valve SE4 112.90 Manual Block Valve G2 Warda Station - INCOMING 112.90 Manual Block Valve G7 Warda Station - OUTGOING 112.96 Manual Block Valve SE5 133.87 Motor Operated Block Valve SE6 (E. SIDE COLORADO RIVER) 134.67 CHECK SE7 (W. SIDE COLORADO RIVER) 134.67 Manual Block Valve SE7 (W. SIDE COLORADO RIVER) 139.34 BURIED CHECK CV8 (SH 304) 149.19 BURIED CHECK CV9 (FM 535) 166.67 Remotely Operated Block Valve SE8 (US HWY. 81) 171.53 BURIED CHECK SENDERA MESA DRIVE (AUSTIN AQUIFER) 172.29 BURIED CHECK BECKETT RD. (AUSTIN AQUIFER) 174.94 BURIED CHECK SILVER MTN. RD. (AUSTIN AQUIFER) 175.51 Remotely Operated Block Valve SE9 RAMBLE 3 ST. (AUSTIN AQUIFER) <<>> Table 5.2.6-1 Valve Locations and Types for the Longhorn Pipeline Longhorn Milepost Valve Type Valve Location 175.51 BURIED CHECK RAMBLE 3 ST. (AUSTIN AQUIFER) 177.13 BURIED CHECK US HWY. 290 (AUSTIN AQUIFER) 181.60 Motor Operated Block Valve Cedar Valley - INCOMING 181.65 Motor Operated Block Valve Cedar Valley - OUTGOING 181.65 Motor Operated Block Valve SE10 185.88 BURIED CHECK FITZHUGH CREEK (AUSTIN AQUIFER) 186.48 BURIED CHECK OAK FOREST DRIVE (AUSTIN AQUIFER) 192.45 Manual Block Valve SE10A (E. SIDE FLAT CREEK) 193.39 CHECK CV3 (W. SIDE FLAT CREEK) 194.38 BURIED CHECK 194.76 BURIED CHECK CV10 ULRICH RD. 198.64 Remotely Operated Block Valve SE11 (E. SIDE PEDERNALES RIVER) 198.97 CHECK SE12 (W. SIDE PEDERNALES RIVER) 198.97 Motor Operated Block Valve SE12 (W. SIDE PEDERNALES RIVER) 199.58 BURIED CHECK CV4 (W. SIDE PEDERNALES RIVER) 203.46 BURIED CHECK CV5 (CYPRESS MILL RD.) 205.50 BURIED CHECK CV11 (US HWY. 281) 211.90 Manual Block Valve SE13 (BETWEEN HICKORY/WHITE OAK CKS.) 211.98 BURIED CHECK CV6 (BETWEEN HICKORY/WHITE OAK CKS.) 214.21 BURIED CHECK CV7 (W. SIDE WHITE OAK CREEK) 227.90 Manual Block Valve SE14 227.93 Remotely Operated Block Valve G2 Eckert - Incoming 227.94 Remotely Operated Block Valve G7 Eckert - Outgoing 228.02 Manual Block Valve SE15 276.46 Remotely Operated Block Valve SE16 (E. SIDE LLANO RIVER, STA. NO. 181) 276.64 CHECK SE17 (W. SIDE LLANO RIVER, STA. NO. 181) 276.64 Manual Block Valve SE17 (W. SIDE LLANO RIVER, STA. NO. 181) 280.95 BURIED CHECK CV12 (US HWY. 377) 284.37 BURIED CHECK CV13 288.91 Manual Block Valve SE18 (CR 370) 295.19 Remotely Operated Block Valve SE 19 KIMBLE STATION 295.19 CHECK CV1 295.21 Manual Block Valve SE20 321.95 Manual Block Valve SE21 <<>> Table 5.2.6-1 Valve Locations and Types for the Longhorn Pipeline Longhorn Milepost Valve Type Valve Location 324.68 BURIED CHECK CV14 (CR 245) 338.75 BURIED CHECK CV15 (W. SIDE ANTELOPE DRAW) 346.58 BURIED CHECK CV16 (FM 190) 358.70 Manual Block Valve SE22 373.44 Motor Operated Block Valve SE23 INCOMING (FORMERLY BIG LAKE, STA. NO. 179) 373.45 Manual Block Valve SE24 OUTGOING (FORMERLY BIG LAKE, STA. NO. 179) 416.63 Manual Block Valve SE25 (SH 1555) 457.54 Remotely Operated Block Valve SE26 Crane Station 457.54 Motor Operated Block Valve Crane Station - INCOMING 457.55 Motor Operated Block Valve Crane Station - OUTGOING 457.55 Remotely Operated Block Valve SE27 492.26 Manual Block Valve SE26A (FM 1219) 523.63 Manual Block Valve SE27A (CR 170) 526.17 Manual Block Valve SE28 (FM1216) 526.17 BURIED CHECK SE28 (FM 1216) 528.06 LEVER LOCK CHECK (W. SIDE US HWY 285) 555.10 Manual Block Valve SE29 (CR 222) 576.32 FIRE GATE SE30 COTTONWOOD STA. 576.33 Manual Block Valve G3 COTTONWOOD STA. INCOMING 576.33 Manual Block Valve G9 COTTONWOOD STA. OUTGOING 576.33 Remotely Operated Block Valve SE31 COTTONWOOD STA. 607.10 Manual Block Valve SE32 (SH 54) 638.86 Manual Block Valve SE33 (FM 1111) 668.37 Manual Block Valve SE34 694.41 Motor Operated Block Valve SE35 - EL PASO TERMINAL 694.41 Remotely Operated Block Valve EOL - EL PASO TERMINAL <<>> Table 5.2.6-2 Locations of Check Valves Installed per LCRA Settlement and Valve Studies River Basin Approximate Current Station Location (Check Valve) Approximate Proposed Station Location (RCV) Location Description Notes 7110+58 7154+40 Near Colorado River Relocated - Colorado River between Austin and Bastrop (maximum drain down volume of 300,000 gallons) 7357+15 7386+72 Near Bastrop, TX Relocated – LCRA 7877+23 7818+62 Close to Jenkins Road Relocated – LCRA 9056+27 9056+27 Sandera Mesa Drive (Edwards Aquifer) No change in location - APR Edwards Aquifer 9266+77 9266+77 Ramble 3 St. (Edwards Aquifer) No change in location - APR 10210+24 10218+91 Near Flat Creek Relocated - APR 10263+24 10263+24 Ulrich Rd and Co Rd 301 No change in location – LCRA 10503+95 10503+95 Near the Pedernales River No change in location - Pedernales River (maximum drain down volume of 200,000 gallons) 10538+00 10538+00 West Side of Pedernales R. No change in location - APR 10742+50 10742+50 Near Cottonwood Creek No change in location – APR 10850+40 10810+80 Near Hwy 281 Relocated – LCRA 11192+24 11192+24 Near FM 1323 and Sandy School Rd No change in location - APR 11310+24 11267+52 Near White Oak Relocated – APR <<>> Table 5.2.6-2 Locations of Check Valves Installed per LCRA Settlement and Valve Studies (continued) River Basin Approximate Current Station Location (Check Valve) Approximate Proposed Station Location (RCV) Location Description Notes Relocated – 14606+59 14616+10 Near the Llano River Llano River (maximum drain down volume of 250,000 gallons) 14834+24 14834+24 Hwy 377 near London, TX No change in location – LCRA 15014+74 14920+70 London, TX Relocated – LCRA 17143+24 17143+24 Co. RD 245 No change in location – LCRA San Saba River (maximum drain down volume of 350,000 gallons) 17886+00 18038+18 Eldorado, TX Relocated - LCRA 18299+24 18303+12 Hwy 190 W. of Eldorado, TX Relocated - LCRA <<>> Table 5.2.6-3 Estimated Maximum Release Volumes Maximum Drain Volume Loss during detection and Pipeline Shutdown Total Maximum Release Location Station, Ft bbl gal bbl gal bbl gal Brazos River 3378+79 502 21,091 781 32,800 1,283 53,891 Colorado River Basin 7000+04 to 7999+04 4,549 191,061 781 32,800 5,330 223,861 Colorado River Crossing 7100+33 1,241 52,108 781 32,800 2,022 84,908 Edwards Aquifer - General 8756+15 to 9146+82 2,645 111,089 781 32,800 3,426 143,889 Pedernales River Basin 10100+04 to 11410+04 3,249 136,472 781 32,800 4,030 169,272 Pedernales River Crossing 1049480 2,570 107,937 781 32,800 3,351 140,737 Llano River Basin 14506+04 to 15554+04 3,486 146,398 781 32,800 4,267 179,198 Llano River Crossing 14601+52 561 23,573 781 32,800 1,342 56,373 San Saba River Basin 17043+04 to 18299+04 5,878 246,891 781 32,800 6,659 279,691 San Saba River Crossing 17140+00 1,950 81,883 781 32,800 2,731 114,683 Note: As an additional measure of conservatism, an additional (2000 – 781) 1219 bbls was added to these volumes for purposes of calculating and determining the zone of potential impact for this FEA. <<>> Galena Park to Satsuma MP 0 to MP 34.1 Satsuma to Warda MP 34.1 to MP 112.9 Warda to Cedar Valley MP 112.9 to MP 181.6 Cedar Valley to Eckert MP 181.6 to MP 227.9 Eckert to Ft McKavett MP 227.9 to MP 321.9 Pipeline Table 5.3.1-1 ILI Tool Runs Threats Addressed Tool Date of Tool Run Corrosion Pressure- Cycle Induced Fatigue Laminations and Hydrogen Blisters Third Party Damage Deformation 10-Jun-04 X HRMFL * 28-Oct-04 X X HRMFL ** 14-Dec-05 X X TFI 6-Jul-07 ‡ X X Deformation 5-Oct-07 X Deformation 11-Sep-09 X UT 22-Sep-09 X X X Next Required Assessment 22-Sep-14 2200 11-Sep-12 11-Sep-12 HRMFL/Deformation 21-May-06 X X Deformation 15-Dec-07 X TFI 20-Dec-07 ‡ X X Deformation 12-Oct-09 X UT 24-Nov-09 X X X Next Required Assessment 24-Nov-14 2057 12-Oct-12 12-Oct-12 HRMFL/Deformation 21-Jul-06 X X TFI 19-Sep-07 ‡ X X Deformation 16-Oct-07 X Deformation 16-Dec-09 X UT 24-Jan-10 X X X Next Required Assessment 24-Jan-15 2162 16-Dec-12 16-Dec-12 HRMFL/Deformation 15-Feb-07 X X TFI 22-Mar-07 ‡ X Deformation 25-Jan-10 X UT 20-Feb-10 X X X Next Required Assessment 20-Feb-15 2066 25-Jan-13 25-Jan-13 HRMFL/Deformation 19-Dec-06 X X TFI 9-Nov-07 ‡ X X Deformation 23-Jan-08 X Deformation 27-Mar-10 X UT 25-Jun-10 X X X Next Required Assessment 25-Jun-15 2048 27-Mar-13 27-Mar-13 Tool Date of Tool Threats Addressed <<>> Table 5.3.1-1 ILI Tool Runs (continued) Segment Run Corrosion Pressure- Cycle Induced Fatigue Laminations and Hydrogen Blisters Third Party Damage HRMFL/Deformation 12-Oct-06 X X Ft.McKavett to Deformation 21-Dec-07 X Crane MP 321.9 to MP 457.5 TFI 8-Jan-08 ‡ X X UT 8-Jul-10 X X X Deformation 5-Aug-10 X Next Required Assessment 8-Jul-15 2049 8-Jul-13 8-Jul-13 Crane to Cottonwood Deformation 2-May-07 X MP 457.5 to MP 576.3 HRMFL/Deformation 21-Nov-08 X X Next Required Assessment 21-Nov-13 Not susceptible 21-Nov-13 21-Nov- 13 Deformation 2-May-07 X Cottonwood to El Paso MP 576.3 to MP 694.4 HRMFL/Deformation 27-Mar-08 X X Next Required Assessment 27-Mar-13 Not susceptible 27-Mar-13 27-Mar- 13 Crane to HRMFL/Deformation 8-Jun-11 X X Odessa Next Required Assessment 8-Jun-16 Not susceptible 8-Jun-16 8-Jun-16 * The MFL tool run in Oct-04 was not a complete run ** The MFL tool run in Dec-05 was used to complete the Oct-04 MFL run ‡ The TFI was used to remediate Phase I and Phase II corrosion anomalies and in some cases was used to remediate POE anomalies, but was not used to set the next corrosion reassessment using the POE process. <<>> Pipeline Segment 20" Galena Park to Satsuma (MP 0 to MP 34.09) 18" Satsuma to Warda (MP 34.09 to 112.89) 18" Warda to Cedar Valley (MP 112.89 to MP 181.6) Table 5.3.1-2 ILI Features Summary Item EGP & MFL EGP & TFI EGP & UTWM ILI Year 2004 & 2005 2007 2009 ILI Dents 23 (including <2%) 2 3 ILI Metal Loss 5,9001 8,8091 3371 ILI Seam Weld Features N/A 17 N/A ILI Girth Weld Anomalies 89 0 0 ILI Laminations N/A N/A 1,695 No. Dents Repaired 3 1 1 No. Metal Loss Repaired 47 14 3 No. Seam Weld Features Repaired N/A 17 N/A No. Girth Weld Anomalies Repaired 9 0 0 No. Laminations Repaired N/A N/A 6 ILI Year 2006 2007 2009 ILI Dents 10 5 4 ILI Metal Loss 2,1391 93,9871 7331 ILI Seam Weld Features N/A 4 N/A ILI Girth Weld Anomalies 18 0 0 ILI Laminations N/A N/A 1,082 No. Dents Repaired 3 0 6 No. Metal Loss Repaired 15 21 14 No. Seam Weld Features Repaired N/A 4 N/A No. Girth Weld Anomalies Repaired 5 0 0 No. Laminations Repaired N/A N/A 12 ILI Year 2006 2007 2009 & 2010 ILI Dents 24 7 10 ILI Metal Loss 3,8271 141,9601 1,5781 ILI Seam Weld Features N/A 6 N/A ILI Girth Weld Anomalies 1 0 2 ILI Laminations N/A N/A 541 No. Dents Repaired 3 0 3 No. Metal Loss Repaired 67 42 22 No. Seam Weld Features Repaired N/A 6 N/A No. Girth Weld Anomalies Repaired 1 0 0 No. Laminations Repaired N/A N/A 6 <<>> Table 5.3.1-2 ILI Features Summary (continued) Pipeline Segment Item EGP & MFL EGP & TFI EGP & UTWM ILI Year 2007 2007 2010 ILI Dents 49 46 16 ILI Metal Loss 13,0111 82,0101 1,0061 ILI Seam Weld Features N/A 3 N/A 18" Cedar Valley to Eckert (MP 181.6 to MP 227.9) ILI Girth Weld Anomalies 2 0 3 ILI Laminations N/A N/A 594 No. Dents Repaired 8 1 7 No. Metal Loss Repaired 52 30 5 No. Seam Weld Features Repaired N/A 3 N/A No. Girth Weld Anomalies Repaired 2 0 0 No. Laminations Repaired N/A N/A 0 ILI Year 2006 2007 & 2008 2010 ILI Dents 86 90 30 ILI Metal Loss 61,1671 82,9741 4861 ILI Seam Weld Features N/A 3 N/A 18" Eckert to Ft. McKavett (MP 227.9 to MP 321.9) ILI Girth Weld Anomalies 56 0 0 ILI Laminations N/A N/A 1,907 No. Dents Repaired 18 9 5 No. Metal Loss Repaired 116 10 11 No. Seam Weld Features Repaired N/A 3 N/A No. Girth Weld Anomalies Repaired 6 0 0 No. Laminations Repaired N/A N/A 14 ILI Year 2006 2007 & 2008 2010 ILI Dents 54 35 14 ILI Metal Loss 3,3701 75,5991 1,4271 ILI Seam Weld Features N/A 42 N/A 18" Ft. McKavett to Crane (MP 321.9 to MP 457.5) ILI Girth Weld Anomalies 0 0 2 ILI Laminations N/A N/A 2,364 No. Dents Repaired 8 0 4 No. Metal Loss Repaired 50 14 24 No. Seam Weld Features Repaired N/A 42 N/A No. Girth Weld Anomalies Repaired 0 0 1 No. Laminations Repaired N/A N/A 18 Note 1: Differences in numbers of metal loss features include: (1) Features under sleeves are not reported in UT inspections, (2) Multiple features in MFL inspection are included in one feature in UT inspection (fewer features per joint and longer lengths), and (3) Low level features in MFL inspections not reported in UT inspection due reporting, detection thresholds. <<>> Table 5.3.1-3 Pressure-Cycle-Induced Fatigue Cracking Analysis from the 2010 ORA for the Current Westward Product Flow Direction Description Station Number, feet MP, miles Diameter, inches Wall Thickness, inches Pipe Grade Time to Failure, years1 Reassessment Interval, years2 Case 1 1998 ERW pipe at Galena Park 0+00 0 20 0.312 X52 > 500 > 225 Case 2 Transition to 1950 ERW pipe at MP9 downstream of Galena Park 480+09 9.1 20 0.312 Grade B 428.6 193.1 Case 3 Transition to heavy wall 1950 EFW pipe 1067+46 20.2 20 0.375 Grade B > 500 > 225 Case 4 1950 EFW pipe at Satsuma 1802+61 34.1 18 0.281 X45 110.9 50.0 Case 5 Transition to heavy wall 1950 EFW pipe 1821+42 34.5 18 0.375 Grade B 344.0 155.0 Case 6 1950 EFW pipe downstream of Cedar Valley 10037+72 190.1 18 0.312 X45 131.9 59.4 Case 7 1950 EFW pipe at Kimble County 15589+07 295.2 18 0.281 X45 92.1 41.5 Case 8 Transition to 1950 ERW pipe at Kemper (former Exxon Station) 21387+88 405.1 18 0.25 X52 > 500 > 225 Case 9 1998 ERW pipe at Crane 24158+39 457.5 18 0.281 X65 > 500 > 225 1 Hypothetical, based on assumptions detailed in ORA 2 Based on 0.45 times the hypothetical time to failure <<>> Table 5.3.1-4 Test Point Exceptions for 2011 Segment Name Milepost Location Description Longhorn Tier Inspection Date Structure P/S Remarks East Houston to Kimble 221.972 Bottom of Canyon E of Creek 1 10/06/2011 -0.592 -1.187 Test station repaired. East Houston to Kimble 147.685 Jenkins Rd 247 ESD 2 05/03/2011 -0.68 East Houston to Kimble 116.847 FM 448 ESD 1 10/26/2011 -0.784 Corrected P/S MP 147.204 rectifier repaired. Warda and Zack Lane rectifiers were adjusted. -1.411 -0.95 East Houston to Kimble 25.8 TP E of MP 26 3 09/28/2011 -0.765 -1.285 Test station repaired. East Houston to Kimble 18.674 ESD Hardy Toll Rd 2 04/28/2011 0 -1.658 Test station repaired. East Houston to Kimble 15.727 Keith Rd 2 09/28/2011 -0.333 -1.359 Test station repaired. Ft. McKavett to Kemper 344.895 -15' 3 05/06/2011 0.038 -1.03 Data reading error [reading 3' away was -1.162] Kemper to Crane 441.715 +15' 1 06/02/2011 -0.821 -2.64 Kemper to Crane 441.714 +12' 1 06/02/2011 -0.812 -2.64 Kemper to Crane 441.713 +9' 1 06/02/2011 -0.833 -2.642 Kemper to Crane 441.712 +6' 1 06/02/2011 -0.812 -2.649 Kemper to Crane 441.71 FGN LINE XING IN PASTURE 1 06/02/2011 -0.819 -2.647 Kemper to Crane 441.709 -3' 1 06/02/2011 -0.817 -2.645 New ground bed was installed at MP440. Kemper to Crane 441.708 -6' 1 06/02/2011 -0.816 -2.654 Kemper to Crane 441.707 -9' 1 06/02/2011 -0.814 -2.651 Kemper to Crane 441.706 -12' 1 06/02/2011 -0.71 -2.655 Kemper to Crane 441.705 -15' 1 06/02/2011 -0.717 -2.662 <<>> Table 5.3.1-4 Segment Name Kemper to Crane Kemper to Crane Kemper to Crane Kemper to Crane Kemper to Crane Kemper to Crane Kemper to Crane Kemper to Crane Kemper to Crane Kemper to Crane Kemper to Crane Test Point Exceptions for 2011 (continued) Milepost Location Description Longhorn Tier Inspection Date 441.235 +15' 1 06/02/2011 441.234 +12' 1 06/02/2011 441.233 +9' 1 06/02/2011 441.232 +6' 1 06/02/2011 441.231 +3' 1 06/02/2011 441.23 441.229 CANYON REEF PL XING -3' 1 06/02/2011 1 06/02/2011 441.228 -6' 1 06/02/2011 441.227 -9' 1 07/28/2011 441.226 -12' 1 06/02/2011 441.225 -15' 1 06/02/2011 Structure P/S -0.464 -0.442 -0.401 -0.378 -0.335 -0.296 -0.312 -0.368 -0.73 -0.437 -0.457 Corrected P/S -2.308 -2.281 -2.272 -2.272 -2.266 -2.2 -2.314 -2.36 -2.413 -2.44 -2.448 Remarks New ground bed was installed. <<>> Table 5.3.4-1 Alarm and Shutdown Devices Device description Device # Time Delay Immediate Lockout Non- Lockout Shutdown Annunciate Pump Case Hi-Temp. 95 X X X Pump Seal Leak 96 X X X Flow Switch 98 X X X Motor Vibration 99M startup only X X Pump Vibration 99P startup only X X Low Suction Pressure 21 X X X High discharge Pressure 25 X X X Thrust Bearing Hi-Temp. 38E X X X Motor Outboard Bearing Hi-Temp. 38A X X X Motor Inboard Bearing Hi-Temp. 38B X X X Pump Inboard Bearing Hi-Temp. 38C X X X Pump Outboard Bearing Hi-Temp. 38D X X X Motor Overload 49A X X X Motor Windings Hi-Temp. 49B X X X Low Pump Lube Oil Pressure 63LOPP startup only X X Low Motor Lube Oil Pressure 63LOPM startup only X X AC Power Failure 97PF X X X Station Alarm 86ST X X X Overcurrent 50-51 X X X Switchgear Phase Failure 47-27 X X X Hazardous Gas Detector 45HA X X X Sump Hi-Level 17 X X Low DC Power 80 X X X Low Station Air 63A X X X Fire Detector 45FA X X X Miscellaneous Lockout (Normally High Case Psi) MLI X X X <<>> Table 5.3.4-1 Alarm and Shutdown Devices (continued) Device description Device # Time Delay Immediate Lockout Non- Lockout Shutdown Annunciate Fire Eye Self Check 45FSC X X Loss of Genius Block (derived) X X X Sequence Failure (derived) X X Start Attempts Failure (derived) X X Lockout - defined as an immediate shutdown that requires a physical reset only allowed on-site. Non-Lockout Shutdown - defined as an immediate shutdown that does not require a reset. A restart can be made with no other action required. Notes: "Local" shutdown devices initiate a pump shutdown and transmit an indicator Unit Lock-Out alarm to the Magellan Operations Control Center. The alarm sent to the Control Center does not normally identify the cause of the shutdown (e.g., motor overload, low suction pressure, etc.), but it alerts the Control Center to the pump shutdown. A technician must go to the pump and correct the problem causing the shutdown before it can be restarted. <<>> Table 5.3.4-1a Leak Detection System Alarm and Response Table Description Condition LEAK DETECTION PLDS EMERG-LO Indicates A system indication of a line integrity anomaly, requiring investigation. Note: The Longhorn Mitigation Plan requires a controlled shutdown and isolation of the Longhorn pipeline within 5 minutes of the indication. Response 1. Perform an Investigation Event Shutdown per the 9.02-ADM-002 Startup and Shutdown. 2. Investigate line integrity via trends and event records. 3. Notify the Supervisor or Leak Detection Analyst (LDA). a. If after shutdown, an abnormal or unexpected pressure drop occurs, then proceed to Emergency Code Red Procedure in Emergency Code Red – Investigation Procedure event. b. If after shutdown and investigation, the Supervisor, LDA, and Controller agree it is a false alarm, then the Supervisor may approve restarting the line. Document in Logmate. Classify the cause as a “Data Failure”, or an “Irregular Operating Condition”, or as a “Possible Commodity Loss” Description Condition PLDS LOW Indicates A system indication of a line integrity anomaly, requiring investigation. Response 1. Monitor all pressures and flow rates throughout the line for deviation and investigate line integrity via trends and event records. • If investigation indicates release, proceed to 9.02-ADM-011 Emergency – Code Red – Investigation Event. • If investigation does not indicate release, notify the Supervisor or Leak Detection Analyst (LDA). <<>> Table 5.3.5-1 Basic Inspection and Test Methods Inspection or Test Type Purpose Attributes Pressure Testing (Hydrotesting) Serves as a pre-service integrity validation of the pipe and components by pressurizing to a level above the maximum operating pressure. Destructively eliminates injurious defects. The time, duration, and elevation above MOP, are primary factors in reducing the probabilities of flaw growth that could result in an in-service failure. Confirms the SMYS of the steel. A regulatory requirement for new pipe sections, to uprate existing pipe sections, and conversion from vapor to liquid service. Done by sectioning line according to terrain elevations. One or more valve sections can be included within test segment. Requirements and procedures defined in regulations and industry standards. The hydrotesting service is often provided by a specialty contractor overseen by operating company staff. CP Inspections and Surveys Determines the adequacy of CP voltages and currents for protecting the pipeline against corrosion and to detect areas of potentially defective coating. Rectifier inspections are done to ensure that the rectifiers are in service and providing the required impressed current for CP. Station tests or surveys are done to measure CP voltages at test station locations. This also includes readings taken at pipe casings under roads and railway crossings. Close-interval surveys are done to measure CP voltages along the length of the pipeline between CP test stations at intervals of a few feet and provide a more complete understanding of the CP voltages. In-Line Inspection (ILI) Detects areas of anomalies, such as metal Automated internal inspection tools or “smart <<>> Table 5.3.5-1 Basic Inspection and Test Methods (continued) Inspection or Test Type Purpose loss, deformations, cracks, etc. Manual Ultrasonic Wall Thickness Measurement Determines wall thickness and identifies areas of possible corrosion by direct measurement of pipe wall. Visual Surveys Identifies any adverse conditions associated with coating or pipe, such as corrosion, dents, scrapes, gouges or deteriorating or damaged coating. Ground Patrols and Aerial Surveys Identifies external conditions that might adversely affect the pipeline, such as third party activity and right-of-way (ROW) encroachments. Also used as a means of detecting leaks. Attributes pigs” vary in anomaly types that can be detected and terms of degree of resolution. Services are provided by a specialty pigging contractor. Results often require expertise in interpreting data. Either part or all of a pipeline is pigged depending on the location of pig launching and receiver equipment and the size and geometry of the pipeline system. Manually held instrument used in conjunction with exposed pipe inspections. Requires coating removal. Done in conjunction with finding exposed pipe or exposing pipe for inspection by digging at various pipe locations. The bare pipe can only be examined when the coating is removed. These apply more to the effects of external factors on the pipeline and the detection of leaks than to factors associated with the conditions of the pipe itself. They complement visual surveys. <<>> Section Name Sec. 1-1 (1 of 3) Sec. 2-1 (2 of 3) Sec. 3-1 (3 of 3) Satsuma Station Sec. 1-1 (1 of 3) Sec. 2-1 (2 of 3) Sec. 3-1 (3 of 3) Sec. 13B Sec. 13A Sec. 4-1 (1 of 2) Sec. 2-1 (2 of 2) Sec. 1-1 (1 of 4) Sec. 2-1 (2 of 4) Sec. 3-1 (3 of 4) Sec. 5-3 (4 of 4) Sec. 1-1 (1 of 7) Sec. 2-1 (2 of 7) Sec. 3-2 (3 of 7) Sec. 4-1 (4 of 7) Sec. 5-1 (5 of 7) Sec. 7 Sec. 6A & B Sec. 7-1 (7 of 7) Sec. 1-1 (1 of 6) Sec. 2-1 (2 of 6) Sec. 3-1 (3 of 6) Sec. 4-1 (4 of 6) Sec. 5-1 (5 of 6) Sec. 6-1 (6 of 6) Sec. 1-1 (1 of 4) Sec. 2-2 (2 of 4) Sec. 6-12 (3 of 4) Sec. 4-2 (4 of 4) Sec. 1-1 (1 of 4) Sec. 2-1 (2 of 4) Sec. 2A & B Table 5.3.5-2 Summary of Hydrostatic Tests Date of Testing Beginning Test Section (ft) End Test Section (ft) Diameter (in) Min Pressure (psig) Pipe Grade 2/11/2000 0 62,018 20 994 B 2/12/2000 62,018 128,628 20 995 B 2/11/2000 128,628 180,013 20 996 B 11/2/1998 180,013 180,263 18/16 1321 X-52 2/24/2000 180,263 241,637 18 1269 X-45 2/26/2000 241,637 338,598 18 1276 X-45 2/26/2000 338,598 402,659 18 1278 X-45 12/4/1995 338,364 462,200 18 1217 X-45 12/4/1995 462,200 596,078 18 1274 X-45 5/24/2002 595,962 711,251 18 1276 X-45 3/27/2000 711,251 800,291 18 1278 X-45 6/12/2002 800,280 852,896 18 1280 X-45 6/12/2002 852,896 896,366 18 1414 X-45 6/25/2002 896,366 997,465 18 2724 X-45 5/13/2002 997,465 1,016,229 18 1419 X-45 4/12/2000 1,016,128 1,026,620 18 1416 X-45 4/12/2000 1,026,620 1,048,852 18 1418 X-45 4/17/2000 1,048,852 1,074,458 18 1418 X-45 4/13/2000 1,074,458 1,118,725 18 1415 X-45 4/14/2000 1,118,725 1,138,673 18 1409 X-45 11/20/1995 1,118,844 1,203,340 18 1243 X-45 11/20/1995 1,203,340 1,460,647 18 1245 X-45 4/15/2000 1,203,733 1,236,231 18 1273 X-45 5/4/2000 1,236,231 1,304,029 18 1265 X-45 5/4/2000 1,304,029 1,343,575 18 1265 X-45 5/5/2000 1,343,575 1,391,175 18 1265 X-45 5/5/2000 1,391,175 1,412,541 18 1265 X-45 5/6/2000 1,412,541 1,436,741 18 1265 X-45 5/6/2000 1,436,741 1,460,755 18 1265 X-45 5/16/2000 1,460,755 1,514,472 18 1123 X-45 4/27/2002 1,514,472 1,559,154 18 1122 X-45 4/30/2002 1,559,154 1,616,691 18 1269 X-45 5/31/2000 1,616,691 1,699,642 18 1414 X-45 6/14/2000 1,699,642 1,758,799 18 1270 X-45 6/14/2000 1,758,799 1,829,913 18 1271 X-45 11/10/1995 1,699,421 1,893,964 18 1261 X-45 <<>> Table 5.3.5-2 Summary of Hydrostatic Tests (continued) Section Name Date of Testing Beginning Test Section (ft) End Test Section (ft) Diameter (in) Min Pressure (psig) Pipe Grade Sec. 4-1 (4 of 4) 6/14/2000 1,879,753 1,926,702 18 1272 X-45 Sec. 1 11/10/1995 1,893,964 2,135,340 18 1232 X-45 Kemper Station 4/26/1998 2,135,318 2,138,788 18 1275 X-65 Sec. 15 (Kemper to Crane) 8/23/1995 2,138,780 2,333,459 18 1260 X-52 Sec. 1-1 (1 of 2) 7/1/2000 2,159,919 2,263,600 18 1307 X-52 Sec. 2-4 (2 of 2) 7/11/2000 2,263,600 2,415,817 18 1301 X-52 Sec. 1-1 10/25/1998 2,409,841 2,647,839 18 1970 X-65 Sec. 2-1 10/25/1998 2,647,839 2,849,320 18 1898 X-65 Sec. 3-1 10/27/1998 2,849,320 2,954,141 18 1833 X-65 Sec. 4-1 11/11/1998 2,954,141 3,000,851 18 1915 X-65 Sec. 5-1 11/12/1998 3,000,851 3,064,837 18 1857 X-65 Sec. 6-1 11/12/1998 3,064,837 3,090,948 18 1839 X-65 Sec. 7-2 11/12/1998 3,090,948 3,110,611 18 1850 X-65 Sec. 8-2 11/12/1998 3,110,611 3,133,500 18 1859 X-65 Sec. 9-1 11/13/1998 3,133,500 3,144,342 18 1858 X-65 Sec. 10-1 11/13/1998 3,144,342 3,166,108 18 1843 X-65 Sec. 11-1 11/14/1998 3,166,108 3,192,195 18 1861 X-65 Sec. 12-1 11/14/1998 3,192,195 3,282,242 18 1832 X-65 Sec. 13-1 11/14/1998 3,282,242 3,403,336 18 1840 X-65 Sec. 14-1 11/22/1998 3,403,336 3,489,788 18 1835 X-65 Sec. 15-1 11/21/1998 3,489,788 3,528,408 18 1831 X-65 Sec. 16-1 (El Paso) 11/21/1998 3,528,408 3,666,344 18 1837 X-65 Sec. 1 (Crane to Odessa) 10/10/1998 0 148,396 8.625 1856 X-60 Sec. 1 (Odessa Lateral Extension) 10/7/2004 148,396 154,482 8.625 1936 B Four leaks were reported during the 1995 hydrostatic testing (From Kemper to Crane): Origin of Leak Station No. (ft) Milepost Repairs Hydrogen blister 2,146,607 406.6 Replaced 43' of 18" pipe Leak in pipe body 2,160,888 409.3 Replaced 45' of 18" pipe Hydrogen blister 2,190,051 414.8 Installed full wrap 18" long ERW seam failure 2,242,311 424.7 Replaced 60' of 18" pipe <<>> Table 5.3.5-3 Summary of Hydrostatic Tests (2005 to 2011) Valve Section Name Date of Testing Diameter (in) Min Pressure (psig) Pipe Grade Crane Station to El Paso 1998 18 1,833 X65 18 2,023 X65 Various MP 77 to MP 404* 1999-2000 18 1,872 X60 18 1,850 X65 20 995 Gr B Galena Park to Crane Station 2000 18 1,122 X45 18 1,279 X45 18 1,280 X45 Multiple Sections MP112.8 to MP 306.2** 2002 18 2,724 X65 Hwy 130 Adjustment MP 158.64 (508 ft.) 2005 18 1,852 X65 Crane – Monahann (42 mile replacement) MP 486.8 – MP 528 2008 18 1838 X65 MP 350.8 – MP 351.5 2007 18 1875 X65 Multiple Test Sections – Tuckerton Road Relocation MP 36 – MP 39.2 2011 18 1825 X52 Ped River Basin Replacements MP 188.4 – MP 196.6 – Various sections 2011 18 1265 X65 East Houston Loop Installation 2010 20 1221 X52 *Hydrostatic tests of various line replacements were conducted between MP 77 and MP 404 from 1999 to 2000 **A total of 82.1 miles of both new and original 1950-pipe. Leaks during testing occurred in 2002. See details in Chapter 5. <<>> Table 5.3.5-4 Summary of ILI Repair Criteria Feature Location Schedule ILI identified condition HCA Immediate1 Metal loss features (including SWFA, SWFB, ASWML and SWML) with predicted depths greater than or equal to 80% of the wall thickness HCA Immediate2 Features with predicted burst pressure, PBURST, less than PDPP requires reduce operating pressure or shutdown pipeline until repair is made. Metal loss calculation using 85% Area RSTRENG criterion or CorLASTM (Flow Stress Criterion, 85% Area) SWFA, SWFB, ASWML, or SWML calculation using CorLASTM (Fracture Mechanics Criterion) HCA Immediate2 Non-HCA 5 day Top-side dents (above the 4 and 8 o’clock positions) predicted to contain associated metal loss, cracking or a stress riser. HCA Immediate2 Top-side dents with a predicted depth greater than 6% of the nominal pipe diameter. Non-HCA 60 day HCA Immediate2 Significant features in the judgment of the person evaluating the inspection and test assessment Non-HCA 5 day results. All 5 day Metal loss greater than 70% wall thickness HCA 60 day Top-side dents with a predicted depth greater than 3% of the pipeline diameter (greater than 0.250” in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12). HCA 60 day Bottom-side dents (below 4 and 8 o’clock positions) predicted to contain any metal loss, cracking, or a stress riser. All 180 day3 Dents with any of the following: Metal loss, corrosion, exceeds 6% of the pipe outside diameter, or located in a longitudinal seam or girth weld. HCA 180 day Top-side dents with a predicted depth greater than 2% of the pipeline’s diameter (0.250” in depth for a pipeline diameter less than NPS 12). All 180 day Features where the calculation of remaining strength of the pipe shows an operating pressure, PSAFE, that is less than PDPP at the location of the anomaly. HCA 180 day Areas of general corrosion with a predicted metal loss greater than 50% of nominal wall. HCA 180 day Features with predicted metal loss greater than 50% of nominal wall that are located at a crossing of another pipeline, or are in an area with widespread circumferential corrosion, or are in an area that could affect a girth weld. HCA 180 day Potential crack indications that when excavated are determined to be a crack. All 180 day3 Cracks located in the pipe body, girth weld, and longitudinal seam that are determined to be injurious to the integrity of the pipeline. 6A-19 <<>> Table 5.3.5-4 Summary of ILI Repair Criteria (continued) Feature Location Schedule ILI identified condition All 180 day Corrosion of or along a longitudinal seam weld (as identified by the ILI service provider as being axially oriented seam weld metal loss). HCA 180 day Gouge or grooves with a predicted depth greater than 12.5% of nominal wall. All 180 day3 Gouges or grooves greater than 50% of nominal wall thickness. All 180 day3 Casing shorts with associated metal loss. All 180 day3 Girth weld anomalies All 180 day3 Corrosion within 3” of either side and/or across girth welds All Based upon judgment Severe Mill related defects such as laminations or hard spots. Injurious laminations are determined to be those that are sloping, surface breaking, bulging or interacting with other features. Any condition identified by ILI that could impair the integrity of the pipeline should be repaired as appropriate. Note 1: Requires shutdown of the pipeline until the repair is made. Note 2: Requires shutdown of the pipeline or reduction of the operating pressure until the repair is made. Note 3: Indications which shall be investigated within 6 months of receipt of vendor report; mitigation action, if necessary, will occur after evaluation by excavation. <<>> Table 5.4.1-1 Pipeline and Facility Spill Data Since 2002 Release Date Location Name Location Type PHMSA Reportable Product Released Released To BBLs Released Total BBLs Recovered 7/19/2002 Warda Facility No Water Soil 119.048 0.000 8/19/2004 El Paso Facility No IVD Additive (Hydrocarbo ns) Concrete Containment 0.071 0.071 8/29/2004 Crane Facility No Hydrocarbon s/Crude Oil Soil 0.714 0.714 9/17/2004 El Paso Facility Yes Diesel Soil 0.298 0.298 9/19/2004 El Paso Facility No Fuel, Diesel - Low Sulfur Soil 0.071 0.071 10/1/2004 Eckert Facility No Gasoline Soil 0.357 0.167 10/22/2004 El Paso Junction Facility Yes Fuel, Diesel - Low Sulfur Soil 0.238 0.238 10/26/2004 El Paso Facility Yes Fuel, Diesel - Low Sulfur Soil 0.238 0.238 11/11/2004 Odessa Facility Yes Gasoline Soil 0.357 0.357 11/29/2004 East Edwards Aquifer Valve Pipeline No Gasoline Soil 0.036 0.024 12/4/2004 El Paso Facility No Gasoline, Regular, Unleaded Soil 10.310 0.310 12/18/2004 Crane Facility Yes Gasoline Soil 4.762 1.191 1/8/2005 Crane Facility No Gasoline, Regular, Unleaded Soil 0.119 0.119 1/12/2005 Mainline Block Valve SE11 Pipeline No Gasoline Soil 0.071 0.048 4/24/2005 Odessa Facility Yes Diesel Soil 7.290 7.200 7/18/2005 Warda to Cedar Valley Pipeline Yes Gasoline Soil 5.000 5.000 <<>> Table 5.4.1-1 Pipeline and Pump Station Spill Data Since 2002 (continued) Release Date Location Name Location Type PHMSA Reportable Product Released Released To BBLs Released Total BBLs Recovered 12/27/2005 Kimble Facility No Gasoline Soil 0.071 0.071 12/29/2005 Crane Facility No Diesel Soil 0.095 0.095 10/19/2006 El Paso Facility No Diesel Concrete Pad 11.310 1.310 11/14/2006 Ft. McKavett to Crane Pipeline No Gasoline Soil 0.548 0.548 4/23/2007 Galena Park Facility Yes Gasoline Soil/ Gravel 5.714 5.500 5/15/2007 El Paso Facility No Gasoline Secondary Containment 13.000 3.000 10/24/2007 El Paso Facility No Transmix Soil 0.048 0.048 12/21/2007 Diamond Junction Facility No Transmix Soil 0.071 0.071 1/23/2008 Galena Park Facility No Corrosion Inhibitor Gravel 10.238 0.238 2/1/2008 El Paso Facility No Gasoline Soil 0.071 0.071 2/13/2008 El Paso Facility No Gasoline Soil 0.071 0.071 2/20/2008 El Paso Facility No Diesel Soil & Containment 13.571 3.571 4/29/2008 Crane Facility Yes Diesel Soil 0.952 0.952 5/8/2008 El Paso* Facility No Diesel Soil 111.300 9.300 9/5/2008 El Paso Facility No Contact Water with Diesel Soil 10.595 0.000 9/18/2008 Galena Park Facility Yes Gasoline Soil and Gravel 0.238 0.238 10/20/2008 Crane Facility Yes Diesel Gravel and Soil 0.119 0.000 3/31/2009 El Paso Facility No Water, with hydrocarbon sheen Soil, Gravel 10.429 0.486 10/30/2009 El Paso FACILITY No Hydraulic Fluid Soil 10.286 0.286 <<>> Table 5.4.1-1 Pipeline and Pump Station Spill Data Since 2002 (continued) Release Date Location Name Location Type PHMSA Reportable Product Released Released To BBLs Released Total BBLs Recovered 1/16/2010 El Paso Facility No Diesel containment pad and soil 0.071 0.071 1/18/2010 El Paso Facility No N Grade Soil 0.024 0.024 5/17/2010 El Paso Facility No Gasoline Soil 0.095 0.095 11/29/2010 Crane Facility Yes Gasoline Soil/Gravel 0.238 0.238 2/3/2011 El Paso Facility No Diesel concrete and soil 10.476 0.476 3/21/2011 Satsuma Facility No Gasoline Soil/Gravel 0.048 0 6/23/2011 Warda Facility Yes Gasoline Soil and Gravel 2.357 1.767 Note 1 - Spill did not occur on PHMSA Regulated asset <<>> Release Date 7/19/2002 8/19/2004 8/29/2004 9/17/2004 9/19/2004 10/1/2004 10/22/2004 10/26/2004 11/11/2004 12/4/2004 12/18/2004 1/8/2005 4/24/2005 12/27/2005 12/29/2005 Table 5.4.1-2 Summary of Cause of Release for Facilities Cause Code Name Incident Summary (Cause of Release) Human Error - Contractor Error While pumping of hydrostatic test water into a storage facility tank manifold system, a valve was left open releasing the material onto soil Human Error - Contractor Error During the first filling, the IVD additive Tank was found to have a small leak at the base. After removing the wax tape to locate the leak, it was found that a temporary plug had been driven into a one-half inch threaded fitting. Equipment Failure Not Specified Human Error - Company Personnel While receiving pipeline pigs during commissioning, the scraper trap was drained to the normal system, to the separator/sump. On the launcher, a plug was left out of the drain, allowing the product to rise and overflow the drain pan. Equipment Failure During commissioning of Tank four, water draw pig tail upper valve was leaking from a weep hole. Equipment Failure A dead-end blind flange was found to be dripping. Human Error - Company Personnel A fitting was left open on the line. Equipment Failure Flange Leak on Scraper Trap. Other Possible Drain Line Equipment Failure Pump Mechanical Seal on Tank Pump #1 failed. Equipment Failure A TSV released from a valve body and filled the sump. The sump high-level alarm failed to operate. The sump overflowed. Human Error - Contractor Error The relief piping going to the relief tank was closed off. All the valves blocked it and we were blowing nitrogen through the piping. Some gasoline still inside piping came out the two inch valve nearest the relief tank side. Human Error - Company Personnel Drain valve opened and overfilled sump. Equipment Failure Both pump seals failed. Seal drain lines clogged. Product spilled from pump skid onto ground. Equipment Failure While draining mainline strainer to the sump. <<>> Table 5.4.1-2 Summary of Cause of Release for Facilities (continued) Release Date Cause Code Name Incident Summary (Cause of Release) 10/19/2006 Equipment Failure Volumetric Prover at the Truck Loading Rack Overflowed while the meter was being calibrated. 4/23/2007 Equipment Failure Tubing Failure on a baring box cooling line. 5/15/2007 Equipment Failure A driver started loading Regular Unleaded Gasoline into his tanker truck when he noticed his fuel tank leaking. 10/24/2007 Human Error - Company Personnel Leak on a flange and spilled approx. two gallons of product on the ground. During tank maintenance technician used a LOTO template. The template did not meet the exact scope of work, closing the valves did not allow for thermal relief. 12/21/2007 Human Error - Contractor Error In a drain down at the pipeline a release of 1.5 - 3 gallons of transmix (primarily diesel) to soil. During a construction project, secondary containment in place during drain-up and was removed. Decision was made to install a skillet in upstream valve, secondary containment was not used and product hit the ground when they opened the flange. 1/23/2008 Human Error - Driver A cam lock fitting on the discharge side of a semi-truck vibrated loose causing product to spill. Driver did not wire-tie or secure fitting to prevent cam-lock from vibrating open per 9.01-ADM-185 (Appendix 5A). 2/1/2008 Equipment Failure 1/2 pipe TSV (terminal relief valve) connection came loose and began to leak. An operator discovered the release and secured the valve. The leak resulted in approximately three gallons spilled onto the top soil. T 2/13/2008 Human Error - Company Personnel There was a thermal relief block valve that was partially closed and not "car sealed" per procedure at tank 12 thus over pressuring the rack manifold causing a spill of material on the ground. Failure to follow LOTO procedures. 2/20/2008 Equipment Failure Diesel fuel leak partially outside containment, inside terminal at Filter F-3. Approximately 25 gallons in containment, 125 gallons outside containment released to soil. Toptech configuration issue, causing tank 15 pump to turn on inadvertently. 4/29/2008 Human Error - Contractor Error While equalizing the levels between Tank 53 and Tank 52 to put T52 into service, product was discovered leaking from the tank inlet valve’s flange. This flange was split to remove a skillet after completion of American Petroleum Institute 653 tank inspection and not properly re-installed. 5/8/2008 Equipment Failure A broken nipple on a pressure release valve on a pump going to the truck rack. <<>> Table 5.4.1-2 Summary of Cause of Release for Facilities (continued) Release Date Cause Code Name Incident Summary (Cause of Release) 9/5/2008 Human Error - Contractor Error A contractor was removing the liquid contents (water and diesel) from the secondary containment for a temporary diesel storage tank and walked away during the transfer. The 55-gallon drum in which the liquid was being pumped overfilled. Magellan/Contract personnel responded to the incident and took immediate steps to contain the release. 9/18/2008 Human Error - Company Personnel A mainline strainer O-ring failed while pumping product from the sump to the mainline. In early Sept. maintenance was performed in GP; valve indicator stems were identified as broken on MOV 3 & 4 but not repaired, O-ring was not replaced when strainer was opened as required and sump pump internal relief (either failure or set at wrong value) did not shut down the pump of which over pressured the reinjection line. 10/20/2008 Human Error - Contractor Error Tank 51 was being re-filled from the mainline pipeline with diesel. The onsite technician was monitoring the tank refilling activities and noticed weeping from under the tank. Upon discovering the weeping, the technician contacted operations control who in turn terminated the tank filling. 3/31/2009 Human Error - Company Personnel A technician was preparing prover for a water draw. The Technician was in the process of flushing the prover with water. In order to do this he had to open the vent valve located on the prover to prevent the prover from air locking. While filling the prover with water, the technician returned to his truck to talk with another technician. The facility engineer arrived on site and noticed water coming from the vent and notified the technicians. 10/30/2009 Equipment Failure Contractor (CTI) transport truck loading tank bottoms for transport broke hydraulic hose on truck and spilled approximately 12 gallons of hydraulic fluid on ground. 1/16/2010 Equipment Failure Leaking flange on filter vessel spilled diesel in containment area and sprayed some on ground. 1/18/2010 Equipment Failure While doing the morning walk down an operator noticed a small leak coming from the Pump on Tank 17. After investigating it was found to be the pump seal. 5/17/2010 Human Error - Company Personnel Found gasoline leaking from a plug hole on the stripper pump 11/29/2010 Equipment Failure The seal on the prover valve stem leaked. The containment under the valve was only partially effective due to high winds in the area. The 4 way prover valve was originally installed upside down, this has been corrected. <<>> Table 5.4.1-2 Summary of Cause of Release for Facilities (continued) Release Date Cause Code Name Incident Summary (Cause of Release) 2/3/2011 Equipment Failure The O-rings on rack diesel filter vessels F7 & F8 started to leak. Impacted area was cleaned up. Reviewed proper torqueing procedure, tagged bolts on vessel flange to assist with sequence, replaced gasket, and placed copy of filter change procedure at vessel site. Did not determine root cause of gasket failure. 3/21/2011 Equipment Failure A nipple cracked on a mainline unit at Satsuma Station released a mist of product. The nipple was connected to drain piping that likely vibrated and caused the failure. The cracked nipple was replaced and the drain piping was removed as it is not necessary. 6/23/2011 Equipment Failure Stem packing on the valve was identified as the leak source and was repaired. <<>> Release Date 11/29/04 01/12/05 07/18/05 11/14/06 Table 5.4.1-3 Summary of Cause of Release for Pipeline (Not Facilities) Cause Code Incident Summary (Cause of Release) Equipment Failure Drip found emanating from valve stem on 1" ball valve upstream of SE8. Equipment Failure - Valve Steam leak from ½-inch ball valve. Equipment Failure - Cracked/Leaking Fitting 2” nipple cracked while injecting product into pig launching barrel. Corrosion - External Crew was prepping anomaly found during ILI tool run for repair. While sandblasting the affected area in preparation for installing a sleeve product started misting from a pinhole in the pipeline. <<>> Table 5.4.1-4 Texas Reportable Incidents and Frequencies Texas All Incidents1 Significant Incidents2 Miles Existing in 2010 50,8343 50,834 Incidents 2001-2010 9943 3333 Gross Barrels Spilled 291,2453 287,8663 Avg Incidents/yr 99.4 33.30 Incidents/1000mi-Yr 1.96 0.66 Avg BBL/Yr 29,125 28,787 Avg BBL/mi-Yr 0.57 0.57 Table 5.4.1-5 US Reportable Incidents and Frequencies US All Incidents1 Significant Incidents2 Miles Existing in 2010 170,961 170,961 Incidents 2001-2010 3,444 1,153 Gross Barrels Spilled 1,052,896 1,042,588 Avg Incidents/yr 344.40 115.30 Incidents/1000mi-Yr 2.01 0.67 Avg BBL/Yr 105,290 104,259 Avg BBL/mi-Yr 0.62 0.61 All data are from PHMSA for 49 CFR Part 195 Jurisdictional Hazardous Liquid Pipelines hazardous liquid pipeline operators 1All Reportable incidents as defined by PHMSA 2Significant Incidents as defined by PHMSA: http://primis.phmsa.dot.gov/comm/reports/safety/SigPSI.html?nocache=5235 3Extracted from: http://primis.phmsa.dot.gov/comm/reports/safety/TX_detail1 42009 mileage from the Natural Gas Transmission, Gas Distribution, and Hazardous Liquid Pipeline Annual Mileage, Nov 30, 2011, as reported from: http://phmsa.dot.gov/portal/site/PHMSA/menuitem. 5Extracted from: http://primis.phmsa.dot.gov/comm/reports/safety/AllPSI.html 6Extracted from: http://primis.phmsa.dot.gov/comm/reports/safety/SigPSI.html Table 5.4.1-6 Longhorn Reportable Incident Frequencies Longhorn 2002 – 2011 (9.5 years)* Longhorn 1/27/05-2011 (6.5 years)* Texas Pipelines 2001 – 2010 US Pipelines 2001 - 2010 Pipe Spill Frequency (spills/year/1,000 miles) 1.89 1.70 1.96 2.01 Pipe Spill Volume (bbl/year/mile) .004 .005 0.57 0.62 *Note: Data gathered through mid-2011. Data based upon 722.5 miles of the Longhorn system. 13 reportable leaks totaling 28 bbls since 2002 and 8 reportable leaks totaling 22 bbls since 2005. <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL CHAPTER 5 APPENDICES <<>> ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 5A REFERENCED PROCEDURES OF THE 2012 MAGELLAN SIP <<>> APPENDIX 5A REFERENCED PROCEDURES OF THE MAGELLAN 2012 SIP SIP-ADM 7.01-001 SIP-ADM 7.03 SIP-ADM 7.03-003 SIP-ADM 7.03-007 SIP-ADM 7.04 SIP-ADM 7.04-001 SIP-ADM 7.04-005 SIP-ADM 7.04-006 SIP-ADM 7.04-023 SIP-ADM 7.05 SIP-ADM 7.05-002 SIP-ADM 7.05-014 SIP-ADM 7.05-020 SIP-ADM 7.05-030 SIP-ADM 7.05-031 SIP-ADM 7.05-037 SIP-ADM 7.05-039 SIP-ADM 7.07-002 SIP-ADM 8.01 SIP-ADM 9.01-185 SIP-ADM 10.01 SIP-ADM 13.02 SIP-ADM 14.01 <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 1 of 16 1.0 PURPOSE 1.1 The purpose of this procedure is to establish a standardized method for identification, analysis and repair of pipeline defects when necessary. 2.0 PROCEDURE 2.1 General 2.1.1 Exceptions—This procedure may not apply to the following conditions: 2.1.1.1 Emergency situations such as a major pipeline release 2.1.1.2 Threaded piping 2.1.2 DEFECT ASSESSMENT, RSTRENG ANALYSIS OF CORROSION OR KAPA, NONDESTRUCTIVE TESTING, MAINTENANCE WELDING, COATING APPLICATION, AND INSTALLATION OF REPAIRS (E.G., CLAMPS, COMPOSITE REPAIRS) ARE COVERED TASKS. 2.1.3 WELDING ON LINES THAT ARE UNDER INTERNAL PRESSURE (LIVE LINE WELDING) SHALL BE DONE IN ACCORDANCE WITH COMPANY WELDING PROCEDURES AND PRACTICES. REFER TO SPECIFICATION 101, MAINTENANCE WELDING (EXCLUDING ETHYLENE PIPELINES). 2.2 PRECAUTIONS 2.2.1 ALL EXPOSED BELL AND SPIGOT GIRTH WELDS SHALL BE REINFORCED BY MEANS OF SLEEVING 2.2.2 IF NEEDED (WHEN PIPE IS NOT RESTING ON THE GROUND) THE PIPE SHOULD BE ADEQUATELY SUPPORTED PRIOR TO BACKFILLING. CONSIDERATION SHOULD BE GIVEN TO USING DIRT PLUGS OR SANDBAGS AT SPACING INTERVALS NOT TO EXCEED 20 FEET PARTICULARLY IN AREAS WHERE ADDITIONAL WEIGHT HAS BEEN APPLIED BY INSTALLATION OF SLEEVING. 2.2.3 ALL EXPOSED GIRTH WELDS (INCLUDING BELL AND SPIGOT JOINTS) SHALL BE SUPPORTED (SUPPORTS TO BE PLACED ON EACH SIDE OF THE GIRTH WELD NOT TO EXCEED 5 FEET) VIA SANDBAGS OR EQUIVALENT SETTLEMENT RESISTANT SUPPORTS PRIOR TO BACKFILLING. 2.2.4 PIPELINE DEFECTS DISCOVERED THROUGH INTEGRITY TESTS SUCH AS IN-LINE INSPECTIONS (ILI), PRESSURE TEST, AND ROUTINE MAINTENANCE SHALL BE ASSESSED AND REPAIRED, IN A TIMELY AND CONSISTENT MANNER UTILIZING AND COMPLYING WITH COMPANY PROCEDURES, INDUSTRY STANDARDS AND APPLICABLE REGULATIONS (DOT 195.452) AND RECOMMENDED PRACTICES. 2.2.5 PIPELINE DEFECTS (INCLUDING GENERAL OR LOCALIZED CORROSION) CONFIRMED THROUGH ACTUAL FIELD FINDINGS (NOT REPORTED BY ILI TOOL) THAT MEET THE CRITERIA OF A PRESSURE REDUCING DEFECT SHALL BE REPAIRED IMMEDIATELY. UPON DISCOVERY, A PRESSURE AND OR RATE REDUCTION, OR LINE SHUTDOWN SHALL BE CONSIDERED. 2.2.6 PIPELINE DEFECTS NOT REPAIRED BY MEANS OF FULL ENCIRCLEMENT SLEEVING AND OR PIPE REPLACEMENT SHOULD BE NON- DESTRUCTIVELY TESTED PRIOR TO RECOATING. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 2 of 16 2.2.7 2.2.8 2.2.9 ALL REPAIRS ARE MADE IN A SAFE MANNER AND ARE MADE SO AS TO PREVENT DAMAGE TO PERSONS OR PROPERTY AND TO COMPLY WITH DOT 195.422. All materials used for repairs or replacement such as sleeves, pipe, fittings, and valves shall meet the minimum design requirements of the asset. ENSURE THAT THE SITE AND/OR BELL HOLE ARE SAFE, PRIOR TO AND DURING PIPELINE EXCAVATION ACTIVITIES. FOR SPECIFIC GUIDELINES TO TRENCHING, REFER TO THE EXCAVATION SAFETY PROCEDURE. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 3 of 16 2.2.10 DETERMINE IF THE COATING CONTAINS ASBESTOS, BEFORE AUTHORIZING OR ALLOWING ANY PIPELINE COATING REMOVAL. TO THE ASBESTOS PERFORMANCE PROCEDURE. REFER 2.2.11 IF THE DEFECT APPEARS TO BE ASSOCIATED WITH PRODUCT LOSS (LEAKING), TAKE APPROPRIATE MEASURES AS INDICATED BY THE EMERGENCY RESPONSE PLANS TO SHUT THE LINE IN OR REDUCE THE 2.3 PRESSURE IN THE PIPELINE TO A SAFE PRESSURE BASED ON THE PRELIMINARY EVALUATION, FEATURE SITE AND PIPELINE OPERATION INFORMATION. 2.2.12 WHEN CLEANING PIPE (I.E. SAND BLASTING OR POWER BRUSHING) FOR PREPARATION OF EVALUATING, REPAIRING, OR COATING PIPELINE DEFECTS EXERCISE EXTREME CARE AS ACTUAL DEPTH OF DEFECT MAY BE GREATER THAN REPORTED OR PREDICTED. TO ENSURE SAFE WORK PRACTICES LIGHTLY CLEAN PIPE UNTIL IT IS EVIDENT THAT SUFFICIENT REMAINING WALL EXIST TO ALLOW THOROUGH CLEANING OF THE DEFECT. REVIEW AND PERFORM THE FOLLOWING GENERAL STEPS FOR EVALUATION OF ALL DEFECTS 2.3.1 2.3.2 2.3.3 2.3.4 UPON COMPLETION OF THE EXCAVATION, PHOTOGRAPH THE REPAIR SITE PRIOR TO REMOVING THE COATING. PREPARE THE SITE AND PIPELINE FOR A DETAILED EVALUATION OF THE DEFECT AFTER IT HAS BEEN DETERMINED IT IS SAFE TO WORK ON OR NEAR THE PIPELINE. THIS INCLUDES REMOVING COVER TO FULLY EXPOSE THE PIPE, COATING REMOVAL AND APPROPRIATELY CLEANING THE FEATURE TO BE EVALUATED IN ORDER TO MAKE DETAILED MEASUREMENTS OF THE FEATURE AND TO DETERMINE THE TYPE OF DEFECT. DOCUMENT ALL DEFECT INFORMATION ON PIPELINE MAINTENANCE REPORT. VISUALLY DETERMINE THE TYPE OF DEFECT THEN USE THE APPROPRIATE PART OF THIS PROCEDURE, LISTED BELOW, TO ASSIST WITH FEATURE EVALUATION AND THE RECOMMENDED REPAIR OPTIONS. REFER TO TABLE 1 FOR A DETAILED LISTING OF REPAIR OPTIONS. UNDER SPECIAL CIRCUMSTANCES, THE MANAGER OF ASSET INTEGRITY CAN APPROVE DEVIATIONS FROM THE APPROVED/PREFERRED REPAIR METHODS LISTED IN TABLE 1. 2.3.4.1 CORROSION—PARAGRAPH 2.4 2.3.4.2 PIPE BODY GOUGES AND/OR MILL DEFECTS—PARAGRAPH 2.5 DENTS AND DENTS WITH ASSOCIATED GOUGES/STRESS RISERS—PARAGRAPH 2.6 2.3.4.4 ARC BURNS—PARAGRAPH 2.7 2.3.4.5 WELD DEFECTS—PARAGRAPH 2.8 2.3.4.6 STRESS CORROSION CRACKING (SCC)—PARAGRAPH 2.9 2.3.4.7 SELECTIVE SEAM CORROSION (SSC)- PARAGRAPH 2.10 2.3.4.8 HARD SPOTS—PARAGRAPH 2.12 2.3.4.3 <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 4 of 16 2.4 2.5 2.6 2.3.4.9 BUCKLING—PARAGRAPH 2.13 2.3.4.10 CRACKS- LONG SEAM AND PIPE BODY- PARAGRAPH 2.13 EVALUATE AND SELECT REPAIR OPTIONS FOR CORROSION 2.4.1 AFTER CAREFULLY REVIEWING THE CORROSION FOOTPRINT OR CHARACTERISTICS, CLEAN THE AREA SUITABLY TO AID IN THE EVALUATION OF THE CORROSION. WHEN CLEANING PIPE (I.E. SAND BLASTING OR POWER BRUSHING) FOR PREPARATION OF EVALUATING, REPAIRING, OR COATING PIPELINE DEFECTS EXERCISE EXTREME CARE AS ACTUAL DEPTH OF DEFECT MAY BE GREATER THAN REPORTED OR PREDICTED. TO ENSURE SAFE WORK PRACTICES LIGHTLY CLEAN PIPE UNTIL IT IS EVIDENT THAT SUFFICIENT REMAINING WALL EXIST TO ALLOW THOROUGH CLEANING OF THE DEFECT. 2.4.2 IF DETERMINED NECESSARY, MEASURE THE LENGTH (IN THE LONGITUDINAL DIRECTION) AND DETERMINE THE DEPTH OF THE DEEPEST PITTING WITHIN A CORRODED AREA OR A SEGMENT OF THAT AREA. THE CORROSION ANALYSIS CRITERION FOR RSTRENG OR KAPA REQUIRES DIVISION OF THE PITTED AREA INTO SEGMENTS OF CONSISTENT PREDETERMINED LENGTHS AND MEASUREMENT OF THE MAXIMUM DEPTHS WITHIN EACH SEGMENT. REFER TO RSTRENG ANALYSIS OF CORROSION PROCEDURE FOR DETAILS. 2.4.3 REFER TO PARAGRAPH 2.16 OF THIS PROCEDURE FOR CORROSION REPAIR METHODS AND OPTIONS. 2.4.4 NOTIFY ASSET INTEGRITY FOR ASSISTANCE WITH REPAIR OPTIONS WHEN INTERNAL CORROSION IS FOUND OR SUSPECTED. EVALUATE AND SELECT REPAIR OPTIONS FOR PIPE BODY GOUGES AND/OR MILL DEFECTS 2.5.1 MEASURE THE DEFECT CIRCUMFERENTIAL WIDTH, LENGTH AND DEPTH AT THE DEEPEST POINT AND SEVERAL OTHER POINTS ALONG ITS LENGTH. MEASURE THE ANGLE, WHEN APPLICABLE, OF THE DEFECT RELATIVE TO THE RUN OF THE PIPELINE. 2.5.2 REFER TO TABLE 1 OF THIS PROCEDURE FOR GOUGES, PIPE BODY AND/OR MILL DEFECTS REPAIR METHODS AND OPTIONS. 2.5.3 IF THE REPAIR IS MADE BY REMOVING THE DEFECT BY MEANS OF SANDING/GRINDING, UPON COMPLETION, THE AREA SHALL BE NONDESTRUCTIVELY INSPECTED TO ENSURE THAT A STRESS RISER, STRESS CONCENTRATION, CRACK OR OTHER INJURIOUS DEFECT DOES NOT EXIST PRIOR RECOATING THE AREA. EVALUATE AND SELECT REPAIR OPTIONS FOR DENTS 2.6.1 MEASURE THE DENT AREA (THE LENGTH, CIRCUMFERENCE AND DEPTH AT THE DEEPEST POINT). EXAMINE THE BOTTOM OF THE DENT FOR SCRATCHES, GOUGES, GROOVES, METAL LOSS OR HEAVILY WORK- HARDENED MATERIAL. MEASURE SCRATCH, GOUGE, GROOVE OR METAL LOSS, IF PRESENT, LENGTH AND DEPTH AT THE DEEPEST POINT ALONG ITS LENGTH. 2.6.2 (REFERENCE SECTION, WHEN REQUIRED FOR USE WITH TABLE 1) ANY DENT THAT EXCEEDS 2% OR 0.250” IN NPS < 12”, WITH OR WITHOUT VISIBLE METAL LOSS, SHALL BE REPAIRED WITH A TYPE B SLEEVE. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 5 of 16 2.7 2.6.3 DENTS 2% OR LESS IN NPS <12” THAT ARE PROVEN BY NONDESTRUCTIVE INSPECTION THAT A STRESS RISER, STRESS CONCENTRATION, CRACK OR OTHER INJURIOUS DEFECT DOES NOT EXIST WITHIN THE DENT MAY BE RECOATED. REFER TO PARAGRAPH 2.16 OF THIS PROCEDURE FOR DENT REPAIR METHODS AND OPTIONS. EVALUATE AND SELECT REPAIR OPTIONS FOR ARC BURNS 2.7.1 NOTE: IF THE ARC BURN IS ON A NEW LINE UNDER CONSTRUCTION, THE ARC BURN SHALL BE REMOVED AS A CYLINDER, PER THE ONSHORE CONSTRUCTION SPECIFICATIONS. 2.8 2.7.2 EXAMINE ARC BURNS FOR CRACKING AND DEPTH. 2.7.3 REFER TO SPECIFICATION 101: MAINTENANCE WELDING (EXCLUDING ETHYLENE PIPELINES) PARAGRAPH 7.0 AND PARAGRAPH 2.16 OF THIS PROCEDURE FOR ARC BURN REPAIR METHODS AND OPTIONS. EVALUATE AND SELECT REPAIR OPTIONS FOR WELD DEFECTS 2.8.1 EXAMINE WELD DEFECTS VISUALLY IN ACCORDANCE WITH SPECIFICATION 100, CONSTRUCTION AND FABRICATION OF PIPELINES AND RELATED PIPING SYSTEMS AND SPECIFICATION 101, MAINTENANCE 2.9 WELDING (EXCLUDING ETHYLENE PIPELINES). EVALUATE WELDS THAT HAVE BEEN X-RAYED IN ACCORDANCE WITH LATEST APPROVED API SPECIFICATION. 2.8.2 REPAIR ALL IN-SERVICE JOINT WELDS IN ACCORDANCE WITH SPECIFICATION 101 – MAINTENANCE WELDING (EXCLUDING ETHYLENE PIPELINES). THIS WILL USUALLY REQUIRE THE USE OF A SMALL TYPE B REPAIR SLEEVE COMMONLY CALLED A “WEDDING BAND”. 2.8.3 THE ONLY REPAIR ALLOWED ON A LONG-SEAM WELD IS GRINDING OR SANDING TO REMOVE SURFACE DEFECTS THAT DO NOT EXCEED 12.5% (REFERENCE 2.5.3) OF THE PARENT METAL WALL THICKNESS. REPAIR ALL OTHER WELD DEFECTS BY INSTALLING A FULL ENCIRCLEMENT TYPE B REPAIR SLEEVE OR CUTTING OUT A CYLINDER OF PIPE AND REPLACING IT WITH NEW PIPE. EVALUATE AND SELECT REPAIR OPTIONS FOR LAMINATION DEFECTS 2.9.1 EXAMINE PIPE FOR LAMINATION BY NON DESTRUCTIVE TESTING OF THE SURFACE IN THE AREA OF CONCERN. 2.9.2 DOCUMENT THE LENGTH, ORIENTATION, PROXIMITY TO SEAM AND GIRTH WELD IF RELEVANT, AND NOTE ADDITIONAL INTERACTIVE FEATURES (METAL LOSS, CRACKS, DENTS, ETC.), IF APPLICABLE NOTE SLOPING, BULGING, SURFACE BREAKING, AND BLISTERING. 2.9.3 REPAIRS WILL BE MADE IN ACCORDANCE WITH SECTION 2.15. 2.9.4 INSPECT THE FULL CIRCUMFERENCE OF THE PIPELINE WHERE THE SLEEVE ENDS ARE TO BE WELDED TO THE PIPELINE USING AN ULTRASONIC THICKNESS INSTRUMENT AND/OR A MAGNETIC PARTICLE INSPECTION TECHNIQUE. ENSURE THERE ARE NO SURFACE CRACKS, LAMINATIONS OR THIN WALL THAT COULD AFFECT THE INTEGRITY OF THE DEFECT, WELD, OR SLEEVE. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 6 of 16 2.10 EVALUATE AND SELECT REPAIR OPTIONS FOR STRESS CORROSION CRACKING (SCC) 2.10.1 2.10.2 2.10.3 EXAMINE PIPE FOR STRESS CORROSION CRACKING (SCC) BY NON DESTRUCTIVE TESTING AND OR MAGNETIC PARTICLE INSPECTION OF THE SURFACE IN THE AREA OF CONCERN. DOCUMENT THE FINDINGS WITH PHOTOGRAPHS WHEN POSSIBLE OR DRAW A SKETCH SHOWING THE AREA AFFECTED BY CRACKING. DOCUMENT THE LENGTH, DENSITY, SPACING AND GENERAL LOCATION OF THE CRACKS RELATIVE TO OTHER SURFACE CONDITIONS SUCH AS LONGITUDINAL AND JOINT WELDS. NOTIFY ASSET INTEGRITY FOR ASSISTANCE WITH REPAIR OPTIONS WHEN SCC IS FOUND OR SUSPECTED. IF SCC IS DISCOVERED ON ASSETS COVERED BY THE MITIGATION PLAN, REFER TO THE ORA PROCESS MANUAL DECISION TREE PRIOR TO EVALUATING AND REPAIRING. DOCUMENT WHETHER OR NOT SCC WAS DISCOVERED ON PIPELINE MAINTENANCE REPORT. 2.11 EVALUATE AND SELECT REPAIR OPTIONS FOR SELECTIVE SEAM CORROSION 2.10.4 (SSC) 2.11.1 2.12 2.11.2 2.11.3 2.12.1 EXAMINE PIPE FOR SELECTIVE SEAM CORROSION (SSC) BY EVALUATING THE LONGITUDINAL SEAM WELD FOR LOCALIZED CORROSION LOCATED ALONG THE BOND LINE OF LOW FREQUENCY ELECTRIC RESISTANCE WELDING (LR-ERW) AND ELECTRIC FLASH WELDING (EFW) PIPING, THAT LEADS TO THE DEVELOPMENT OF A WEDGE SHAPED GROOVE THAT IS OFTEN FILLED WITH CORROSION PRODUCTS. DOCUMENT THE FINDINGS WITH PHOTOGRAPHS WHEN POSSIBLE OR DRAW A SKETCH SHOWING THE AREA AFFECTED BY SELECTIVE SEAM CORROSION. NOTIFY ASSET INTEGRITY FOR ASSISTANCE WITH REPAIR OPTIONS WHEN SSC IS FOUND OR SUSPECTED. DOCUMENT WHETHER OR NOT SSC WAS DISCOVERED ON THE PIPELINE MAINTENANCE REPORT. 2.13 EVALUATE AND SELECT REPAIR OPTIONS FOR HARD SPOTS MEASURE HARD SPOT AREA (THE LENGTH AND CIRCUMFERENCE) AND MAP THE HARDNESS USING CALIBRATED PORTABLE TESTING EQUIPMENT. 2.12.2 MEASURE THE HARDNESS AND MAKE A SKETCH SHOWING THE HARDNESS DISTRIBUTION. USE THE FOLLOWING CRITERIA WHEN EVALUATING HARD SPOTS: REPAIR ALL HARD SPOTS WHEN THE MAXIMUM HARDNESS EXCEEDS ROCKWELL C 35. REFER TO PARAGRAPH 2.16 OF THIS PROCEDURE FOR HARD SPOT REPAIR METHODS AND OPTIONS. EVALUATE AND SELECT REPAIR OPTIONS FOR BUCKLING/RIPPLES/WRINKLES 2.13.1 NOTIFY ASSET INTEGRITY FOR ASSISTANCE WITH REPAIR CRITERIA AND REPAIR METHODS AND OPTIONS. 2.13.2 REFER TO PARAGRAPH 2.13 OF THIS PROCEDURE FOR BUCKLING <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 7 of 16 2.14 2.15 REPAIR METHODS AND OPTIONS. EVALUATE AND SELECT REPAIR OPTIONS FOR LONG SEAM AND PIPE BODY CRACKS 2.14.1 EXAMINE PIPE FOR CRACKING BY NON-DESTRUCTIVE TESTING AND MAGNETIC PARTICLE INSPECTION OF THE SURFACE IN THE AREA OF CONCERN. DOCUMENT THE FINDINGS WITH PHOTOGRAPHS WHEN POSSIBLE OR DRAW A SKETCH SHOWING THE AREA AFFECTED BY CRACKING. DOCUMENT THE LENGTH, DENSITY, SPACING AND GENERAL LOCATION OF THE CRACKS RELATIVE TO OTHER SURFACE CONDITIONS SUCH AS LONGITUDINAL AND JOINT WELDS. 2.14.2 REFER TO TABLE 1 OF THIS PROCEDURE FOR CRACK IN PIPE BODY OR WELD SEAM FOR REPAIR METHODS AND OPTIONS. REPAIR METHODS AND OPTIONS FOR FEATURES OR DEFECTS 2.15.1 REFER TO THE CHART BELOW FOR EVALUATING REPAIR OPTIONS. UNDER SPECIAL CIRCUMSTANCES, THE MANAGER OF ASSET INTEGRITY CAN APPROVE DEVIATIONS FROM THE APPROVED/PREFERRED REPAIR METHODS LISTED IN THE FOLLOWING CHART. Table 1 Repair Method Re-Coat Defect Type Grind /Sand Type “A” Type “B” Bolt On Composite Cut Out HCA Immediate Condition Metal loss >80% (external) Assets Covered by Mitigation Plan >70% N N N X T N O Metal loss >80% (internal) Assets Covered by Mitigation Plan >70% N N N O T N X PBURST < PDPP at location of anomaly (external) N N O X T O O PBURST < PDPP at location of anomaly (internal) N N N X T N O Dents above 4:00 and 8:00 with any indicated metal loss, cracking, or stress riser (See Paragraph 2.6.2) N N N X T N O Dents above 4:00 and 8:00 with a depth >6% of nominal pipe diameter N N N X T O O <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE Asset Integrity 01/01/12 Re-Coat Defect Type Grind /Sand (See Paragraph 2.6.2) HCA 60-Day Condition Dents above 4:00 and 8:00 with a depth>3% of nominal pipe diameter (>0.250” in depth for a pipeline diameter 2% of nominal pipe diameter (>0.250” in depth for a pipeline diameter 2% of pipeline diameter (>0.250” in depth for a pipeline diameter 6% of pipeline diameter (See Paragraph 2.6.2) N N PSAFE>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 9 of 16 Repair Method Re-Coat Defect Type Grind /Sand Type “A” Type “B” Bolt On Composite Cut Out Corrosion of or along a longitudinal seam weld (Selective Seam Corrosion) N N N X T N O Gouges or grooves >12.5% nominal wall thickness N N N X T N O Other Conditions N N N X T N O Leaking defect Metal loss <12.5% nominal wall thickness X N N N N N N Non-Injurious Planar Laminations X N O O T N O Sloping Laminations N N N X T N O Bulging Laminations N N N X T N O Surface Breaking Laminations N N N X T N O Hydrogen Blisters N N N X T N O Laminations interacting with Deformations N N N X T N O Arc burn N X N O N N O Hard spot N N Gouges or grooves <12.5% nominal wall thickness X X Buckling O X N O Repair by cutout, pumpkin, Type B sleeve, or call Asset Integrity for assistance N N N N N N SCC suspected Call Asset Integrity for assistance Leaking mechanical (Dresser) coupling Repair by tightening, using housing (pumpkin), or cutout Mechanical leaks (valves and fittings) Repair in accordance with manufacturer’s guidelines or cutout and replace 2.15.2 2.15.3 THIS TABLE OUTLINES THE APPROVED/PREFERRED METHOD (X), <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 10 of 16 2.16 OPTIONAL (O), AND TEMPORARY ONSHORE OR PERMANENT OFFSHORE (T) METHODS OF REPAIRING IMPERFECTIONS OR DEFECTS. THE METHODS THAT ARE NOT PERMITTED (N) ARE ALSO INDICATED. THE OPTIONAL METHODS LISTED DO NOT REPRESENT ALL OPTIONAL METHODS BUT IDENTIFY NORMALLY ACCEPTED OPTIONS. A TEMPORARY REPAIR MAY BE MADE USING ANY METHOD DEEMED SUITABLE USING SOUND ENGINEERING JUDGMENT. FOR DETAILED INFORMATION ON REPAIR METHODS, REFER TO PARAGRAPH 2.17 OF THIS PROCEDURE. GENERAL NOTES ON REPAIR METHODS 2.16.1 2.16.2 2.16.3 2.16.4 2.16.5 2.16.6 DEFECTS REPAIRED BY GRINDING AND/OR SANDING, INSTALLING A TYPE “A” SLEEVE, TYPE “B” SLEEVE, COMPOSITE REINFORCED SLEEVE OR REPLACING THE AFFECTED PIPE AS A CYLINDER ARE ALL PERMANENT REPAIRS. BOLT-ON OR MECHANICAL REPAIR CLAMPS USED ONSHORE ARE CONSIDERED TEMPORARY REPAIRS THEREFORE; REPLACE OR UPGRADE THEM WITH A PERMANENT REPAIR AS SOON AS FEASIBLE OR WITH APPROVAL OF THE MANAGER, ASSET INTEGRITY, A PROPERLY WELDED MECHANICAL OR BOLT-ON CLAMP IS CONSIDERED A PERMANENT REPAIR FOR ONSHORE APPLICATIONS. WHEN PRACTICAL, REPAIR DEFECTS BY SLEEVING. THERE ARE TWO NORMALLY USED METHODS OF SLEEVING NON-LEAKING DEFECTS: TYPE “A” AND TYPE “B” SLEEVE. BASE THE DECISION TO USE ONE TYPE OVER THE OTHER ON THE SPECIFIC FIELD CIRCUMSTANCES AND TABLE 1 TYPE “A” FULL ENCIRCLEMENT WELDED STEEL SLEEVE CAN BE USED TO REPAIR DEFECTS. THIS SLEEVE CANNOT BE USED ON LEAKING DEFECTS OR TO PROVIDE LONGITUDINAL REINFORCEMENT TO THE PIPELINE. REFER TO PARAGRAPH 2.17.3 FOR DETAILED INFORMATION ABOUT INSTALLING TYPE “A” SLEEVES. REPAIR LEAKING DEFECTS BY SLEEVING WITH A TYPE “B” SLEEVE WHEN PRACTICAL. TYPE “B” SLEEVES REQUIRE WELDING ON THE PRESSURIZED PIPE AND SHOULD NOT BE USED TO REPAIR OTHER DEFECTS EXCEPT UNDER SPECIAL CIRCUMSTANCES. REFER TO PARAGRAPH 2.17.4 FOR DETAILED INFORMATION ABOUT INSTALLING TYPE “B” SLEEVES. REPAIR OF LEAKING DEFECTS CAUSED BY ISOLATED CORROSION MAY BE MADE BY INSTALLING A BOLT-ON LEAK CLAMP (ON-SHORE TEMPORARY) OR A TYPE “B” SLEEVE. USE COMPOSITE REINFORCEMENT SLEEVES TO REPAIR DEFECTS THAT HAVE BEEN GROUND OUT, WERE CAUSED BY CORROSION OR DENTS ON LOW STRESS PIPELINES WITHOUT SCRATCHES. 2.16.7 CAUTION: DO NOT USE COMPOSITE SLEEVES TO REPAIR LEAKING DEFECTS OR CRACKING. REFER TO PARAGRAPH 2.17.5 FOR DETAILS. 2.16.8 REPAIR SUBMERGED PIPELINES IN NAVIGABLE WATERS CONTAINING LEAKING DEFECTS BY MECHANICALLY APPLYING A FULL ENCIRCLEMENT SLEEVE OR BY INSTALLING A NEW SECTION OF PRE- TESTED PIPE. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 11 of 16 2.16.9 REPAIR ANY DEFECT BY REMOVING THE DEFECTIVE COMPONENT (VALVE, FITTING, ETC.) OR A CYLINDER OF PIPE CONTAINING THE DEFECT AND INSTALLING A NEW COMPONENT OR CYLINDER OF PIPE. 2.16.10 PATCHES ARE NOT AN APPROVED REPAIR METHOD. 2.17 REPAIR PROCEDURES 2.17.1 REPAIR DEFECT BY GRINDING AND/OR SANDING, AS FOLLOWS 2.17.2 CAUTION: PRIOR TO PERFORMING ANY GRINDING OR SANDING ON A LIVE LINE, EVALUATE THE DEFECT TO BE REPAIRED. IF IT IS ESTIMATED THAT THE DEFECT IS POTENTIALLY GREATER THAN 10% OF THE NOMINAL WALL THICKNESS, DO NOT PERFORM ANY GRINDING OR SANDING OPERATIONS AND IMMEDIATELY REFER TABLE 1 TO DETERMINE THE APPROPRIATE REPAIR METHOD, SUCH AS INSTALLING A SLEEVE. 2.17.3 2.17.2.1 2.17.2.2 2.17.2.3 2.17.2.4 2.17.2.5 REMOVE THE DEFECT BY GRINDING AND/OR SANDING. AFTER GRINDING OR SANDING, IF THE REMAINING WALL THICKNESS IS LESS THAN 88% OF NOMINAL, REEVALUATE THE INTEGRITY OF THE PIPELINE AND GRIND AREA USING RSTRENG (REFER TO RSTRENG ANALYSIS OF CORROSION) OR KAPA AND INSTALL A REINFORCING SLEEVE IF NECESSARY. THE TRANSITION FROM THE AREA WHERE THE DEFECT WAS REMOVED TO THE SURROUNDING UNDISTURBED MATERIAL SHALL BE SMOOTH. NONDESTRUCTIVELY INSPECT ALL AREAS WHERE DEFECTS HAVE BEEN REMOVED BY GRINDING, USING MAGNETIC PARTICLE OR DYE PENETRANT INSPECTION METHOD TO ENSURE THE ENTIRE DEFECT HAS BEEN REMOVED. DURING NDT, PAY PARTICULAR ATTENTION TO ANY INDICATIONS OF CRACKING. IF THE REMAINING WALL THICKNESS PASSES RSTRENG CALCULATIONS, THE AREA DOES NOT REQUIRE SLEEVING AND MAY BE PROPERLY CLEANED AND RECOATED. IF THE REMAINING WALL THICKNESS IS LESS THAN REQUIRED BY RSTRENG CALCULATION, PERFORM A REPAIR. THE AREA DOES NOT REQUIRE BLEND GRINDING OR SANDING WHEN THE DEFECT REQUIRES TYPE “A” OR TYPE “B” SLEEVING. REPAIR DEFECT USING A TYPE “A” SLEEVE (NON-PRESSURE CONTAINING), AS FOLLOWS 2.17.3.1 PREPARE THE PIPELINE TO INSTALL THE TYPE “A” SLEEVE BY REMOVING ALL OF THE COATING AND THOROUGHLY POWER BRUSH OR BLAST CLEANS THE PIPE SURFACE IN THE AREA THE SLEEVE WILL COVER. 2.17.3.2 FABRICATE OR OBTAIN A SLEEVE WITH THE SAME OR GREATER OVERALL STRENGTH (WALL THICKNESS X YIELD STRENGTH) AS THE PIPELINE BEING REPAIRED. REFER TO SPECIFICATION 101—MAINTENANCE WELDING (EXCLUDING <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 12 of 16 2.17.3.3 ETHYLENE PIPELINES) ATTACHMENT A FOR DETAILS. USE A SLEEVE THAT IS AT LEAST 4 INCHES IN LENGTH. ENSURE THAT THE SLEEVE COVERS THE DEFECT(S) PLUS A MINIMUM OF 2" PAST THE DEFECT(S) ON EACH END. REFER TO SPECIFICATION 101—MAINTENANCE WELDING 2.17.4 2.17.3.4 2.17.3.5 2.17.3.6 2.17.3.7 2.17.3.8 (EXCLUDING ETHYLENE PIPELINES) FOR DESIGN DETAILS. CLEAN THE INSIDE AND OUTSIDE SURFACE OF THE SLEEVE BY THOROUGHLY POWER BRUSHING OR ABRASIVE BLASTING. APPLY A HARDENABLE FILLER MATERIAL SUCH AS AN EPOXY IN DENTS, CORROSION PITS, AND/OR ADJACENT TO THE LONG SEAM OF THE PIPE TO COMPLETELY FILL VOID AREAS BEFORE INSTALLING THE SLEEVE. APPLY SLEEVE WITH BACKING STRIP TO PIPELINE ENSURING IT IS TIGHT. THE EFFECTIVENESS OF THE SLEEVE DEPENDS ON ITS SNUGNESS AROUND THE PIPE. APPLY THE SLEEVE TO PIPELINE ENSURING A SNUG FIT. WELD PER SPECIFICATION 101—MAINTENANCE WELDING (EXCLUDING ETHYLENE PIPELINES) AND THE SPECIFIED WELDING PROCEDURE. SEAL THE ENDS OF THE STEEL SLEEVE WITH A MASTIC BAR, THEN A SHRINK SLEEVE AND COAT THE EXTERIOR OF THE SLEEVE FOLLOWING COATINGS—SELECTION, APPLICATIONS AND MAINTENANCE. REPAIR DEFECT USING A TYPE “B” SLEEVE (PRESSURE CONTAINING), AS FOLLOWS: 2.17.4.1 2.17.4.2 PREPARE THE PIPELINE TO INSTALL THE TYPE “B” SLEEVE BY REMOVING ALL THE COATING AND THOROUGHLY POWER BRUSH OR BLAST CLEAN THE PIPE SURFACE IN THE AREA THE SLEEVE WILL COVER. FABRICATE OR OBTAIN A SLEEVE WITH THE SAME OR GREATER OVERALL STRENGTH (WALL THICKNESS X YIELD STRENGTH) AS THE PIPELINE BEING REPAIRED. REFER TO SPECIFICATION 101—MAINTENANCE WELDING ATTACHMENT 2.17.4.3 A FOR DETAILS. USE A SLEEVE THAT IS AT LEAST FOUR INCHES IN LENGTH. ENSURE THAT THE SLEEVE COVERS THE DEFECT(S) PLUS A MINIMUM OF 2" PAST THE DEFECT ON EACH END. TYPE B SLEEVES MAY BE USED FOR LEAKING OR NON-LEAKING DEFECTS INCLUDING CIRCUMFERENTIALLY ORIENTED DEFECTS. WHEN MULTIPLE SLEEVES ARE USED, A TYPE B SLEEVE SHOULD NOT BE TERMINATED WITHIN ONE-HALF PIPE DIAMETER OR 4 INCHES FROM A GIRTH WELD WHICHEVER IS GREATER. THE DISTANCE BETWEEN SLEEVES SHOULD BE AT LEAST ONE PIPE DIAMETER. SEPARATED SLEEVES MAY BE SPACED LESS THAN ONE PIPE DIAMETER APART IF JOINED BY A WELDED BRIDGING SLEEVE OR MADE CONTINUOUS BY BUTT-WELDING THEM TOGETHER. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 13 of 16 2.17.4.4 2.17.4.5 2.17.4.6 2.17.4.7 2.17.4.8 WHEN INSTALLED AT A NON-LEAKING DEFECT, A TYPE B SLEEVE MAY BE INSTALLED IN A MANNER THAT REDUCES THE HOOP STRESS IN THE CARRIER PIPE. METHODS FOR ACCOMPLISHING THIS INCLUDE LOWERING THE PRESSURE BEFORE THE SLEEVE IS INSTALLED, APPLYING EXTERNAL MECHANICAL FORCE, OR PREHEATING THE SLEEVE TO FACILITATE A “SHRINK-FIT.” INSPECT THE FULL CIRCUMFERENCE OF THE PIPELINE WHERE THE SLEEVE ENDS ARE TO BE WELDED TO THE PIPELINE USING AN ULTRASONIC THICKNESS INSTRUMENT AND/OR A MAGNETIC PARTICLE INSPECTION TECHNIQUE. ENSURE THERE ARE NO SURFACE CRACKS, LAMINATIONS OR THIN WALL THAT COULD AFFECT THE INTEGRITY OF THE WELD OR SLEEVE. CLEAN THE INSIDE AND OUTSIDE SURFACE OF THE SLEEVE BY THOROUGHLY POWER BRUSHING OR ABRASIVE BLASTING. APPLY A HARDENABLE FILLER MATERIAL SUCH AS AN EPOXY IN DENTS, CORROSION PITS, AND/OR ADJACENT TO THE LONG SEAM OF THE PIPE TO COMPLETELY FILL VOID AREAS BEFORE INSTALLING THE SLEEVE. APPLY THE SLEEVE WITH BACKING STRIP TO PIPELINE ENSURING A SNUG FIT. WELD PER SPECIFICATION 101— MAINTENANCE WELDING (EXCLUDING ETHYLENE PIPELINES) AND THE SPECIFIED WELDING PROCEDURE. NONDESTRUCTIVELY TEST THE COMPLETED LONGITUDINAL GROOVE WELD AND CIRCUMFERENTIAL FILLET WELDS IN COMPLIANCE WITH SPECIFICATION 101—MAINTENANCE 2.17.4.9 WELDING (EXCLUDING ETHYLENE PIPELINES). COAT THE EXTERIOR OF THE SLEEVE WITH PRIMER AND RD-6 TAPECOAT FOLLOWING COATINGS—SELECTION, APPLICATIONS AND MAINTENANCE. 2.17.5 REPAIR DEFECT USING AN APPROVED COMPOSITE REINFORCED SLEEVE 2.17.5.1 2.17.5.2 2.17.5.3 2.17.5.4 2.17.5.5 DO NOT USE A COMPOSITE SLEEVE TO REPAIR LEAKS, CRACKS, OR WELD DEFECTS. REFER TO TABLE 1 FOR SPECIFICS. A QUALIFIED PERSON(S) MUST INSTALL COMPOSITE SLEEVES. PREPARE THE PIPELINE TO INSTALL THE COMPOSITE REINFORCED SLEEVE(S) IN ACCORDANCE WITH THE MANUFACTURER'S SPECIFICATIONS. USUALLY ABRASIVE BLASTING IS REQUIRED. INSTALL THE COMPOSITE SLEEVE PER MANUFACTURER’S SPECIFIC REQUIREMENTS AND SPECIFICATIONS. INSTALL METALLIC (CARON STEEL) BANDING AT ONE-FOOT INTERVALS ON THE SLEEVE FOR THE PURPOSE OF ILI TOOL <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 14 of 16 2.17.5.6 IDENTIFICATION. COAT THE EXTERIOR OF THE SLEEVE WITH PRIMER AND RD-6 TAPECOAT FOLLOWING COATINGS—SELECTION, APPLICATIONS AND MAINTENANCE. AS AN ALTERNATIVE, A 2.17.6 “HEAT SHRINK SLEEVE” THAT FULLY ENCOMPASSES THE LENGTH AND CIRCUMFERENCE OF THE COMPOSITE SLEEVE MAY ALSO BE USED, IF THE ENDS OF THE COMPOSITE SLEEVE ARE APPROPRIATELY FILLED IN ORDER TO PREVENT ANY AIR GAPS. THE HEAT SHRINK SLEEVE MUST EXTEND PAST THE ENDS OF THE COMPOSITE SLEEVE BY AT LEAST 4 INCHES FOR PROPER ENCAPSULATION/COATING OF THE COMPOSITE SLEEVE AND COVER ADJACENT BARE STEEL AREAS, WHICH MAY RESULT IN THE USE OF MULTIPLE HEAT SHRINK SLEEVES. REPAIR DEFECTS USING A BOLT-ON MECHANICAL CLAMP 2.17.6.1 INSTALL PROPERLY DESIGNED FULL ENCIRCLEMENT MECHANICAL CLAMP BY COVERING THE DEFECT. 2.17.6.2 FOLLOW ALL MANUFACTURERS’ INSTRUCTIONS WHEN INSTALLING MECHANICAL CLAMP. 2.17.6.3 REPLACE MECHANICAL CLAMPS WITH A PERMANENT REPAIR AS SOON AS FEASIBLE. PROPERLY WELDED MECHANICAL CLAMPS ARE CONSIDERED PERMANENT REPAIRS FOR ONSHORE APPLICATIONS, UPON APPROVAL BY THE MANAGER OF ASSET INTEGRITY. 2.17.6.4 WELD + ENDS OR SIMILAR COMPRESSION TYPE FITTINGS SHALL NOT BE USED TO JOIN PIPE TOGETHER WITHOUT A WRITTEN JOB SPECIFIC INSTALLATION PROCEDURE INCLUDING REVIEWING AND FOLLOWING MANUFACTURES PROCEDURES TO ENSURE CORRECT INSTALLATION AND OTHER NECESSARY SAFETY MEASURES FOR SAFE AND RELIABLE OPERATION OF THE PIPELINE SYSTEM. CALL MANAGER OF ASSET INTEGRITY FOR FURTHER GUIDANCE, IF NECESSARY. 2.17.6.5 COAT THE EXTERIOR OF THE SLEEVE WITH PRIMER AND RD-6 TAPECOAT FOLLOWING COATINGS—SELECTION, APPLICATIONS AND MAINTENANCE. 2.17.7 REPAIR DEFECTS BY CUTTING OUT A CYLINDER OF PIPE AND REPLACING IT WITH NEW PIPE 2.17.7.1 2.17.7.2 2.17.7.3 2.17.7.4 PRIOR TO CUTTING OR WELDING CHECK FOR LEL’S WITH HAZ GAS DETECTOR REMOVE PIPE OR FITTING CONTAINING THE DEFECT AS A CYLINDER. ENSURE ANY REMOVED SECTION HAS HAD ADEQUATE TIME FOR VENTILATION PRIOR TO CUTTING AND TRANSPORTING. WHENEVER POSSIBLE, ENSURE THAT THE REPLACEMENT PIPE HAS A LENGTH OF NOT LESS THAN ONE-HALF THE PIPE DIAMETER OR NOT LESS THAN 3 INCHES WHICHEVER IS <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 15 of 16 2.17.7.5 2.17.7.6 GREATER. THE REPLACEMENT PIPE, FITTING, OR VALVE SHALL HAVE A GREATER THAN OR EQUAL DESIGN PRESSURE AS THE EXISTING PIPE OR FITTING AND SHALL BE PRE-TESTED. PIPE ENDS SHOULD BE CHECKED FOR MAGNETISM PRIOR TO WELDING. IF WELDING QUALITY BECOMES AN ISSUE, STEPS TO REDUCE OR TEMPORARILY ELIMINATE THE MAGNETIC FIELD ON THE PIPE ENDS SHOULD BE TAKEN. 2.17.8 NOTE: PRIOR TO INSTALLING PRETESTED PIPE, ENSURE THE APPROPRIATE RECORDS (I.E., MTRS, HYDROSTATIC TEST RECORDS) HAVE BEEN LOCATED, THOROUGHLY REVIEWED, AND VERIFIED ACCURATE. 2.17.8.1 2.17.8.2 2.17.8.3 ENSURE LEL’S HAVE BEEN REMOVED FROM WORK AREA PRIOR TO INSTALLING NEW PIPE INSTALL THE REPLACEMENT MATERIAL IN ACCORDANCE WITH SPECIFICATION 101, MAINTENANCE WELDING (EXCLUDING ETHYLENE PIPELINES). COAT THE EXTERIOR OF THE NEW AND ADJACENT PIPE (AS NEEDED) WITH PRIMER AND RD-6 TAPECOAT FOLLOWING COATINGS—SELECTION, APPLICATIONS AND MAINTENANCE. 2.17.9 REPAIR DEFECTS BY RECOAT 2.17.9.1 2.17.9.2 PREPARE THE PIPELINE TO INSTALL COATING BY REMOVING ALL OF THE EXISTING COATING AND THOROUGHLY POWER BRUSH OR BLAST CLEAN THE PIPE SURFACE IN THE AREA OF THE RECOAT. COAT THE EXTERIOR OF THE SLEEVE WITH PRIMER AND RD-6 TAPECOAT FOLLOWING COATINGS—SELECTION, APPLICATIONS AND MAINTENANCE. 2.18 2.17.9.3 AFTER APPLICATION OF THE RD-6 COATING, INSTALL METALLIC BANDING (CARBON STEEL) FOUR INCHES FROM EACH END OF THE RECOAT AREA AND COAT THE METALLIC BANDS WITH RD-6 COATING. DOCUMENT ALL REPAIRS ON THE PIPELINE MAINTENANCE REPORT AND ENSURE A COPY IS SENT TO THE RECORDS COORDINATOR IN TULSA. 3.0 DEFINITIONS 3.1 3.2 3.3 3.4 Arc Burn: Localized points of surface melting caused by arcing between electrode or ground and pipe surface. Bolt-On Fitting: Any onshore or offshore attachment to a pipeline that is attached via bolts. Composite Reinforcement Sleeve: A nonmetallic sleeve used to repair some nonleaking pipeline defects. Dent: An area of the pipe where the local curvature is no longer part of a circular arc having the same radius as the pipe. The local indentation shall be considered a dent if <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 16 of 16 the measured distance between the lowest point of the indentation and a prolongation of the original contour of the pipe exceeds the value equivalent to 2% of the pipe’s diameter. 3.5 Hard Spot: Localized spot where the hardness of the material is greater than surrounding material. 3.6 MIC: Microbiologically induced corrosion. 3.7 RSTRENG: A modified corrosion assessment criterion to predict a minimum failure pressure based on detailed corrosion depth and length measurements. 3.8 3.9 Stress Corrosion Cracking (SCC): Cracking which results from stress induced corrosion. Selective Seam Corrosion (SSC): Localized corrosion located along the bond line of low-frequency electric resistance welding (LR-ERW) and electric flash welding (EFW) piping, that leads to the development of a wedge shaped groove that is often filled with corrosion products. 3.10 Type A Sleeve: A band of steel that encircles the pipeline and is not welded to the pipeline. 3.11 Type B Sleeve: A band of steel that encircles the pipeline and is welded to a pipeline at the ends forming a pressure vessel and is normally used for a leaking defect but may be used for non-leaking defects under special circumstances. 3.12 Wedding Band: A short (Usually 6 to 12 inches in length) Type B Sleeve that encompasses a joint weld. 3.13 Weld Defect: A weld imperfection located in a seam or girth weld. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 17 of 16 System Integrity Plan Change Log Date Change Location Change By 2.2 Clyde Clausen Mike Pearson 2.12 Clyde Clausen Mike Pearson 2.3 Clyde Clausen Mike Pearson 07/23/02 Various Clyde Clausen Mike Pearson Various Clyde Clausen Mike Pearson 2.6.3 Clyde Clausen Mike Pearson 08/08/02 2.4.3 & 2.13.1 Clyde Clausen Mike Pearson 11/21/03 All Clyde Clausen Mike Pearson 12/22/03 1.0 Clyde Clausen Mike Pearson 12/22/03 2.1.2 Clyde Clausen Mike Pearson 12/22/03 2.1.3 Clyde Clausen Mike Pearson 12/22/03 2.1.4 Clyde Clausen Mike Pearson 12/22/03 2.1.5 Clyde Clausen Mike Pearson 12/22/03 2.2.3 Clyde Clausen Mike Pearson 12/22/03 2.6 Clyde Clausen Mike Pearson 12/22/03 2.12 Clyde Clausen Mike Pearson 12/22/03 2.14.7 Clyde Clausen Mike Pearson 12/22/03 2.15.4.5 Clyde Clausen Mike Pearson 12/22/03 2.15.6.4 Clyde Clausen Mike Pearson 11/21/04 All Clyde Clausen Mike Pearson 9/9/04 2.7 Clyde Clausen Mike Pearson 9/9/04 2.14.3.2 Clyde Clausen Mike Pearson 9/9/04 2.14.3.3 Clyde Clausen Mike Pearson 9/9/04 2.14.6.2 Clyde Clausen Mike Pearson 9/9/04 2.14.6.3 Clyde Clausen Mike Pearson 9/9/04 2.14.6.4 Clyde Clausen Mike Pearson Brief Description of Change Detailed how to perform a visual assessment. Added a repair method to the table for Natural Gas. Provided details on reference sections. Replaced Paragraph 6.12 reference with 2.13. Paralleled repair language with the Welding manual to alleviate conflicts and inconsistencies. Added section for dent repair clarification. Added repair method deviation approval process. Annual Review Deleted Purpose of this procedure is to establish, inserted analysis and repair of Deleted Pump piping and Tanks Deleted DOT Part 195 governs the repairs Williams utilizes for certain pipeline repairs. These regulatory parts and subparts may be referenced within this document. Added OQ qualification paragraph Added live line welding paragraph Deleted paragraph, and re‐worded Deleted Caution Note Become 2.11. Rewrote repair options for buckling/ripples Become 2.13.7. Deleted offshore pipeline Become 2.14.4.5. Added (Carbon Steel) Become 2.14.6.4. Modified Note to read ensure the appropriate records (i.e. MTRs, Hydrostatic Test Records) have been located, thoroughly reviewed, and verified accurate. Annual Review Modified Paragraph within Note Deleted Ethylene Pipelines Modified Paragraph for changes due to new regulated requirements Modified Paragraph for changes due to new regulated requirements Modified Paragraph Added new Paragraph <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE Asset Integrity 01/01/12 11/20/05 All Clyde Clausen Mike Pearson 01/01/06 4.4 Clyde Clausen Mike Pearson 01/01/06 2.6.2 Clyde Clausen Mike Pearson 01/01/06 2.12.1 Clyde Clausen Mike Pearson 01/01/06 References Mike Pearson 1/26/06 2.14.6.3 Clyde Clausen Mike Pearson 1/26/06 2.14.6.5 Clyde Clausen Mike Pearson 2/15/06 2.1.5 Clyde Clausen Mike Pearson 11/16/06 All Clyde Clausen Mike Pearson 11/16/06 2.3.3.7 Clyde Clausen Mike Pearson 11/16/06 2.9.3 Clyde Clausen Mike Pearson 11/16/06 2.10 Clyde Clausen Mike Pearson 11/16/06 4.9 Clyde Clausen Mike Pearson 1/10/07 2.2.4 Clyde Clausen Mike Pearson 1/10/07 2.4.1 Clyde Clausen Mike Pearson 1/10/07 2.2.3 Clyde Clausen Mike Pearson 5/8/07 2.2.4 Clyde Clausen Mike Pearson 5/8/07 2.1.1 Clyde Clausen Mike Pearson 6/28/07 2.2.1 Clyde Clausen Mike Pearson 6/28/07 2.2.2 Clyde Clausen Mike Pearson 6/28/07 2.5.3 Clyde Clausen Mike Pearson 6/28/07 2.8.3 Clyde Clausen Mike Pearson 11/16/07 All Clyde Clausen Mike Pearson 4/01/08 2.2.1 Dennis Vasicek Clyde Clausen 4/01/08 2.2.2 Dennis Vasicek Clyde Clausen 4/01/08 2.2.3 Dennis Vasicek Clyde Clausen 7.01–ADM–001 Revision: 9 Page 18 of 16 Annual Review Added definition Minor modifications Incorporated HCA Repair Criteria removed Minor Modification to Paragraph‐ (Added Valve) Minor Modification to Paragraph‐ (Change Specification 100 to Specification 101) Removed Pressure reduction requirements from Paragraph. Annual Review Added 2.3.3.7 Added Paragraph Added 2.10 Added Definition Added precaution for cleaning pipe. Added precaution for cleaning pipe to existing paragraph. Added Paragraph to comply with 195.422. Added Paragraph to comply with 195.422. Removed reference to MPC Added Paragraph Added Paragraph for pressure reductions for defects that can’t be repaired in 8 hours. Added Paragraph for non‐destructive testing repairs that have been removed by grinding/sanding. Added reference to paragraph Conducted Annual Review Added: All exposed bell and spigot girth welds shall be reinforced by means of sleeving Added: If needed (when pipe is not resting on the ground) the pipe should be adequately supported prior to backfilling. Consideration should be given to using dirt plugs or sandbags at spacing intervals not to exceed 20 feet particularly in areas where additional weight has been applied by installation of sleeving Added: All exposed girth welds (including bell and spigot joints) shall be supported (supports to be placed on each side of the girth weld) via sandbags or equivalent settlement resistant supports prior to backfilling. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE Asset Integrity 01/01/12 11/14/08 All Dennis Vasicek Clyde Clausen 12/18/08 2.1.3 Dennis Vasicek Clyde Clausen 12/18/08 2.2.5 Dennis Vasicek Clyde Clausen 12/18/08 2.3.1 Dennis Vasicek Clyde Clausen 12/18/08 2.3.4.10 Dennis Vasicek Clyde Clausen 12/18/08 2.13 Dennis Vasicek Clyde Clausen 12/18/08 2.16.3.8 Dennis Vasicek Clyde Clausen 8/21/09 All Clyde Clausen Doug Chabino 8/21/09 2.2.3 Clyde Clausen Doug Chabino 8/21/09 2.2.6 Clyde Clausen Doug Chabino 11/30/09 All Clyde Clausen Doug Chabino 11/30/09 2.16.5.4 Clyde Clausen Doug Chabino 11/30/09 2.16.6.1 Clyde Clausen Doug Chabino 11/30/09 2.16.6.3 Clyde Clausen Doug Chabino 11/30/09 2.16.6.7 Clyde Clausen Doug Chabino 9/3/10 2.1.2, 2.4.2, 2.16.1.1 Clyde Clausen Doug Chabino 9/3/10 2.9.3 Clyde Clausen Doug Chabino 9/3/10 2.14.1 Clyde Clausen Doug Chabino 9/3/10 All Clyde Clausen Doug Chabino 9/1/11 All Clyde Clausen Doug Chabino 9/1/11 2.14.1 Clyde Clausen Doug Chabino 12/31/11 All 6/12/12 2.14 Table Clyde Clausen Doug Chabino 7.01–ADM–001 Revision: 9 Page 19 of 16 Conducted Annual Review Minor modification (installation of repairs, i.e. composite/clamps) to paragraph Minor Modification to paragraph Added paragraph to photograph repair site prior to removing coating Added Section for Cracks Added Section for Cracks Minor Modifications to paragraph Conducted Annual Review, See modifications below Added not to exceed 5’ to paragraph Added requirement to NDE pipeline defects that are not repaired by means of sleeving or pipe replacement Removed reference to contact Pipeline Integrity and added Asset Integrity Added Paragraph Added Paragraph Added Paragraph Added Paragraph Added utilization of KAPA for conducting pressure assessments Added new paragraph to refer to the ORA process manual decision tree if SCC is discovered on assets covered by the mitigation plan Added Immediate repair criteria for Assets covered by the mitigation plan to repair table Conducted Annual Review Conducted Annual Review Added Lamination Repair Options to Table 2012 Annual Review complete Modified Lamination Repair Table <<>> Magellan Midstream Partners, L.P. INTEGRITY TESTING AND REHABILITATION SIP–ADM–7.03 Asset Integrity 01/01/10 Revision: 6 Page 1 of 4 1.0 OBJECTIVE 1.1 The objective of this initiative is to maintain asset integrity by establishing consistent processes for integrity testing. 2.0 DESCRIPTION 2.1 The Company utilizes pressure testing, in‐line inspection (ILI), or a combination thereof, to assess and validate the physical integrity of its pipeline system. In addition to standardized pipeline construction and maintenance practices, the Company adheres to a comprehensive Integrity Management Program that incorporates the use of appropriate integrity testing technologies and rehabilitation practices in order to assist in identifying, understanding and controlling pipeline risk and integrity threats. 2.2 A priority rating system based on relative risk is established to select pipeline segments for integrity testing schedules. The frequency of reassessments will be determined by the processes established within the Integrity Management Plan. 3.0 STANDARDS 3.1 The Project Manager shall: 3.1.1 Consult with the Pipeline or Facility Risk Engineer, as appropriate for type of asset, to ensure review of applicable asset integrity factors is completed prior to testing. 3.1.2 Coordinate the execution of pressure testing projects in accordance with the Pressure Testing Procedure. 3.1.3 Complete the appropriate Hydrostatic Test Documentation (Hydrostatic Test Documentation for Liquids) and remit with the required attachments to the Records 3.1.4 Coordinator within thirty days of the pressure test. Coordinate the execution of ILI projects in accordance with the In‐Line Inspection Procedure. 3.2 The Records Coordinator shall: 3.3 3.4 3.2.1 Review pressure test documentation for thoroughness and adequacy, and retain in Asset Integrity file repository for useful life of the facillity. 3.2.2 Notify the Pipeline Surge Engineer following receipt of pressure test records. 3.2.3 Input the new pressure test data and the new calculated Maximum Operating Pressure (MOP) information into the Hydrostatic Test Database within 60 days following receipt of the pressure test records. The Manager of Asset Integrity Engineering shall: 3.3.1 Coordinate changes to system pressure settings with Operations Control and/or Operations Manager as applicable. The Pipeline Integrity Supervisor shall: 3.4.1 Determine the effect(s) on the MOP of the corresponding asset(s) following notice of receipt of pressure test documentation. 3.4.2 Coordinate the execution and documentation of integrity testing and rehabilitation <<>> Magellan Midstream Partners, L.P. INTEGRITY TESTING AND REHABILITATION SIP–ADM–7.03 Asset Integrity 01/01/10 Revision: 6 Page 2 of 4 3.4.3 3.4.4 plans of existing assets. Notify the Manager of Asset Integrity Engineering of any required adjustments to system operating pressures due to integrity testing results. Maintain and annually review the In‐Line Inspection Procedure and Pressure Testing Procedure for use on Company operated assets. 3.5 The Pipeline Integrity Engineer shall: 3.5.1 Immediately evaluate reports from the ILI vendor and generate a Dig List in accordance with In‐Line Inspection Procedure. 3.5.2 Notify the Pipeline Integrity Coordinator that the Dig List has been developed in order to initiate project execution of feature investigations and rehabilitation, as required. <<>> Magellan Midstream Partners, L.P. INTEGRITY TESTING AND REHABILITATION SIP–ADM–7.03 Asset Integrity 01/01/10 Revision: 6 Page 3 of 4 System Integrity Plan Change Log Date Change Location Change By Approved By Brief Description of Change 10/16/03 All Clyde Clausen Michael Pearson 10/23/03 2.1 & 2.2 Clyde Clausen Michael Pearson 10/23/03 3.2 Clyde Clausen Michael Pearson 10/23/03 3.4.2 Clyde Clausen Michael Pearson 10/23/03 3.5 Clyde Clausen Michael Pearson 10/23/03 3.7.2 Clyde Clausen Michael Pearson 9/29/04 All Mike Pearson Michael Pearson 9/29/04 3.13 Clyde Clausen Michael Pearson 9/29/04 3.3.1 Clyde Clausen Michael Pearson 9/29/04 3.4.3 Clyde Clausen Michael Pearson 10/16/05 All Clyde Clausen Michael Pearson 10/16/06 All Clyde Clausen Michael Pearson 10/16/06 Entire Document Clyde Clausen Michael Pearson 10/16/06 3.1.2 Clyde Clausen Michael Pearson 10/16/06 3.1.4 Clyde Clausen Michael Pearson 10/16/06 3.2.1 Clyde Clausen Michael Pearson 10/16/06 3.2.2 Clyde Clausen Michael Pearson 10/16/06 3.3.1 Clyde Clausen Michael Pearson 10/16/06 3.3.2 Clyde Clausen Michael Pearson 10/16/06 Clyde Clausen Michael Pearson 3.3.2 10/16/06 3.4.4 Clyde Clausen Michael Pearson 10/16/06 Clyde Clausen Michael Pearson 3.5 10/16/06 3.6 Clyde Clausen Michael Pearson 09/11/07 All Clyde Clausen Michael Pearson 9/11/07 3.2.2 Michael Pearson Conducted 2003 Annual Review, (See Change Log) Minor modifications to Paragraph Inserted responsibilities of Pipeline Integrity Coordinator. Added new responsibility to Pipeline Integrity or Facility Supervisor. Added Operations Control Manager responsibilities Added new responsibility to Pipeline Integrity Engineer. Conducted 2004 Annual Review, (See Change Log) Changed 2 weeks to thirty days Added responsibility to Asset Integrity Manager Added new responsibility to Pipeline Integrity or Facility Supervisor. Conducted 2005 Annual Review‐ (No Changes) Conducted 2006 Annual Review‐ (See Change Log) Revised job titles to reflect recent organizational changes. Minor Modification to Paragraph Minor Modification to Paragraph Minor Modification to Paragraph Minor Modification to Paragraph Deleted Paragraph Moves up and becomes 3.3.1 Moved responsibility under Pipeline Integrity/ Risk Engineering Supervisor: Determine the effect(s) on the MOP of the corresponding asset(s) following notice of receipt of pressure test documentation Minor Modification to Paragraph Deleted Operations Control Manager Requirements as it is covered within 7.07 Operating Pressures. Deleted Asset Integrity Analyst Responsibilities Conducted 2007 Annual ,(See Change Log) Deleted Risk Engineer and Inserted Pipeline Surge Engineer. Deleted two weeks. <<>> Magellan Midstream Partners, L.P. INTEGRITY TESTING AND REHABILITATION SIP–ADM–7.03 Asset Integrity 01/01/10 Revision: 6 Page 4 of 4 9/11/07 3.3 Clyde Clausen Michael Pearson 9/11/07 3.4 Clyde Clausen Michael Pearson 9/11.07 3.4.3 Clyde Clausen Michael Pearson 1/1/09 8/21/09 All Clyde Clausen Doug Chabino 8/21/09 3.1.3 Clyde Clausen Doug Chabino 8/21/09 Section 4 Clyde Clausen Doug Chabino 01/01/11 Deleted Director, Inserted Manager Asset Integrity Engineering Deleted Risk Engineering and made sole responsibility of Pipeline Integrity Supervisor Deleted Director and inserted Manager Asset Integrity Engineering 2008 annual review complete – no changes Conducted Annual Reivew Removed Gas Reference Removed Gas Link Reviewed, no changes <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 1 of 13 1.0 OBJECTIVE 1.1 The purpose of this specification defines Company in-line inspection (ILI) requirements for ILI service providers (Vendors). 2.0 SCOPE 2.1 This requirement specification shall be provided to ILI vendors when Company wishes to inspect specific pipeline segments. 2.2 This specification covers: 2.2.1 Company responsibilities 2.2.2 Vendor responsibilities 2.2.3 Technical criteria for assessing metal loss indications using MFL ILI tools; crack-like, metal loss, and seam weld indications using circumferential MLF ILI technology (i.e. TFI, AFD, SWML) and USCD ILI tools; laminations and metal loss using ultrasonic wall measurement (USWM) ILI tools, and geometry indications using EGP ILI tools. 2.3 This procedure incorporates API 1163, ILI Systems Qualification Standard, First Edition, August 2005; NACE Standard PR 0102-2002; and ANSI/ASNT ILI-PQ-2005 where applicable. 3.0 COMPANY RESPONSIBILITIES 3.1 3.2 3.3 3.4 3.5 Company will furnish alignment sheets (strip maps), GPS/Street atlas files, trap revision drawings, pipeline data listing, and information pertaining to flow rates and product physical properties to enable Vendor to match ILI tool capabilities to the provided data. Company will complete and submit the Information Worksheet (Questionnaire) provided by the Vendor. Company will provide sufficient data, such as EGP and/or profile gauge plate l reports, etc., to allow Vendor to determine whether or not line modifications including launching and receiving facilities are required to enable ILI tools to successfully navigate the pipeline. Company may perform modifications, if required, to the pipeline to enable ILI tools to the successfully navigate pipeline. Company will clean the pipeline based on a review of prior cleaning records to ensure optimum ILI results. Cleaning data will be reviewed with the Vendor to determine and agree on the adequacy of the line cleanliness to achieve the performance specification. Company will provide adequate lifting equipment at the launching and receiving traps to facilitate the installation and removal of ILI tools. Company will provide personnel to assist Vendor in inserting ILI tools into the launch trap, removing the ILI tools from the receiving facility, and operating launcher and receiver facilities. 3.6 3.7 3.8 3.9 3.10 Company will provide a suitable area near the job site for equipment preparation, cleaning, refurbishment, and field data processing. Company will provide a suitable area (if available at receive location) to clean the ILI tools and dispose of contaminated pig components, cleaning materials and pipeline debris extracted from the pipeline as a result of the ILI tool run. Company will attempt to operate pipeline facilities to maintain an adequate and steady flow rate through pipeline during ILI run. Company will supply reporting format for providing ILI results to Company. Following field examination of pipeline features, Company will provide collected data of physical measurements of reported features to Vendor. <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 2 of 13 4.0 VENDOR RESPONSIBILITIES 4.1 Performance Specification 4.1.1 Vendor shall provide a written performance specification that includes, but is not limited to the following: 4.1.1.1 Optimum ILI tool travel velocity 4.1.1.2 ILI tool velocity range and description of impact on data resolution if ILI tool is operated at various velocity levels outside of specified velocity range. 4.1.1.3 ILI tool length and weight 4.1.1.4 ILI tool maximum permissible bore restriction 4.1.1.5 ILI tool sensor type 4.1.1.6 Number of sensors 4.1.1.7 Sensor sample rate in terms of longitudinal distance of sensor travel between samples 4.1.1.8 4.1.1.9 Office where data analysis will be performed Method and approach to analysis and reporting of non-corrosion pipeline features and specific pipeline features (mill related defects, ID reductions indications, and pipeline sleeves or patches). 4.1.1.10 Detection and sizing thresholds 4.1.1.11 ILI tool tolerances and sizing accuracy (statement as to percent of time identified tolerances are met) for: 4.1.1.11.1 Odometer in relation to feature location 4.1.1.12 4.1.1.11.2 Feature depth 4.1.1.11.3 Feature length 4.1.1.11.4 Feature orientation (i.e. circumferential position or o’clock position) Performance criterion (Probability of Identification) for the classification of specific features including inside diameter (ID) and outside diameter (OD) discrimination. 4.1.1.13 Acceptance limits on lost data considering axial length of lost data and/or number of sensor(s) affected during the ILI and/or number of adjacent sensors of lost data. 4.1.1.14 AGM placement specifications (maximum depth of line, distance from casing, etc.). 4.1.1.15 ILI tool bend radius and wall thickness specification. <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 3 of 13 4.2 Field Activities 4.2.1 4.2.2 4.2.3 4.2.4 4.2.5 4.2.6 Vendor shall provide fully functioning ILI tools prepared for service and compatible with the pipe specifications, pipeline operational characteristics, and agreed performance specification. 4.2.1.1 4.2.1.2 4.2.1.3 Mainline block valves may have valve seat spaces that must be spanned by ILI tool. Vendor shall confirm that ILI tools can successfully negotiate such spans without incurring damage or impacting the quality of the final results. Mainline check valves may or may not be pinned open during ILI run and the ILI tools are expected to negotiate such check valves without incurring damage or impacting the quality of the final results. Tees may or may not be barred. ILI tools are expected to negotiate such tees and any crosses without incurring damage or impacting the quality of the final results. Vendor shall notify Company of specific ILI tools to be used and shall supply ILI tools that provide adequate battery life and storage capability to minimize number of ILI runs required. Vendor shall identify to Company when flow rate changes may affect the agreed performance specification. Vendor shall account for actual flow rates and make provisions for the ILI tools to effectively inspect each section relative to the ILI tool battery and data storage limitations. Vendor shall supply an above ground marker system (AGM) to facilitate the location of pipe features using Company’s established AGM locations. Vendor shall provide a sufficient number (minimum of eight (8)) of properly functioning AGM devices to provide benchmark reference on the pipeline. Company will provide tracking personnel for the placement (at approximately 1.0 mile intervals) and retrieval of devices. Vendor shall provide above ground reference number and odometer count for each reference site. 4.2.7 Based on the technical drawings and other information provided to Vendor by Company, Vendor shall advise Company if design and dimensions of pipeline, including launching and receiving facilities, are suitable for ILI tool launching and receiving. 4.2.8 If required by Company, Vendor shall provide an EGP and/or a profile/gauge plate ILI tool of such configuration to detect variations in pipeline geometry that may restrict passage of the ILI tools or prevent complete ILI of the pipeline. EGP or profile/gauge plate ILI tool shall be equipped with a detection system for tracking and locating purposes. A minimum of two receivers shall be provided. 4.2.9 Vendor shall provide labor, supervision, inspection, per diem, materials, ILI tools, vehicles, equipment, and equipment transportation as required. Vendor shall supply technical support regarding care and handling of ILI tools during launch and receive activities. Vendor shall provide certifications of supervisor and team members prior to arriving on-site. 4.2.10 If required by Company, Vendor shall provide programming and calibration of the ILI tools prior to ILI runs including checks of onboard computer hardware and software. 4.3 Data Analysis 4.3.1 Vendor shall provide Company with information within 24 hours of the removal of any electronic ILI tool from the receiver trap as to whether the inspection tool functioned correctly (anticipated memory usage/total distance) and logged the appropriate data. If the ILI tool did not function correctly or if upon review the logged data is considered by <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 4 of 13 Company and Vendor to be unsatisfactory, both parties will schedule a rerun as soon as reasonably possible, unless otherwise directed by Company. 4.3.2 Vendor shall make available on a twenty-four (24) hour per day basis and at no additional cost to Company, appropriate home office based personnel certified to level III in analysis to support the Company while the Company prepares for and/or performs any direct examinations of features reported by the preliminary or final report. 4.3.3 4.3.4 Vendor shall provide a phone list of appropriate support personnel. Vendor shall make available to Company, if required by the Company, a fully trained and qualified individual to provide field assistance to the Company during any direct examination of features reported by Vendor. Vendor shall provide unit cost pricing for providing such field support. 4.3.5 Company will be permitted to assign a representative, consultant or otherwise, to audit the data analysis process on a periodic basis, to ensure data analysis process is being performed to Company specifications. 4.3.6 Vendor shall use trained and qualified personnel for data analysis. 4.4 Documentation 4.4.1 Vendor shall issue an AGM integrity report whereby the distances between above ground markers per the odometer of ILI tool is compared to corresponding Company GPS and established AGM locations. 4.4.2 Vendor shall provide an analysis report containing a data summary with measurements in imperial units in hard and electronic copy including the following: 4.4.2.1 Performance specification applicable to the pipeline segment, including the essential variables, the method(s) used to qualify the performance specification, and equipment specifications. 4.4.2.2 Names and certification levels of Vendor representatives who analyzed data, produced the report, and approved the report. 4.4.2.3 Executive summary. 4.4.2.4 Fully described data quality issues 4.4.2.5 Data analysis parameters used to produce the report. 4.4.2.6 Certifications of ILI tool calibration. 4.4.2.7 Designation and location of critical pipeline features including, but not limited to: pipeline valves, welds, sleeve repairs, casings, heavy wall pipe, taps, tees and AGM locations. 4.5 Reporting Timescales and Other Requirements 4.5.1 Prior to any verbal or written report, Vendor shall perform QA/QC that not only satisfies Vendor requirements in API 1163, Section 11, but also ensures that report is thorough, complete, correct, and delivered in accordance with this Specification. 4.5.2 Vendor shall provide verbal report within 5 business days of completing successful EGP ILI run. Report shall specifically address presence of any bore restrictions in excess of 10% of the pipe diameter so that a determination can be made about the ability of the MFL/circumferential MFL/ultrasonic /other ILI tool to safely negotiate the pipeline. 4.5.3 Vendor shall provide an adequate number of reference locations to identify the location of features. Reference locations shall provide distance to nearest upstream and downstream AGM locations, length of joint containing feature, and lengths of five pipe joints immediately upstream and downstream. <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 5 of 13 4.5.4 4.5.5 4.5.6 4.5.7 4.5.8 4.5.9 4.5.10 4.5.11 4.5.12 4.5.13 Vendor shall provide bi-weekly status report that includes status of data analysis and anticipated report delivery date. Vendor shall provide preliminary report (if required) within 21 business days of a successful ILI run. Vendor shall notify Company (in writing) if timing cannot be achieved. Preliminary report is required for the following indications: 4.5.5.1 Metal loss greater than 80% nominal wall thickness 4.5.5.2 ID reductions that might prevent passage of a MFL, circumferential MFL, ultrasonic or other ILI tool 4.5.5.3 Assets Covered Per Mitigation Plan: 4.5.5.3.1 Metal Loss greater than 70% nominal wall thickness 4.5.5.3.2 Top of pipe (above 4 and 8 o’clock) ID reductions with indicated metal loss 4.5.5.3.3 4.5.5.3.4 Significant anomaly that in the judgment of the data evaluator requires immediate action Top of the pipe (above 4 and 8 o’clock) ID reductions without indicated metal loss and greater than 6% of pipe outside diameter 4.5.5.3.5 Cracks to the extent preliminary indications are an established TFI tool reporting procedure Vendor shall provide electronic draft report of the pipeline listing, wall thickness listing, weld comparison (when historical listing is provided by Company), and AGM location information prior to issuing the final report. Company will review and provide comments within 5 business days following receipt. Vendor shall ship a final report within 5 business days of receipt of Company comments to electronic draft report. Unless otherwise indicated, Vendor shall provide two (2) copies of final report as part of the base cost. Hard copy reports shall be provided in a 3 ring binder using 8 ½” x 11” paper. Final report shall be delivered to Company no later than 180 days after the ILI tool is removed from the receive scraper trap and shall include ILI run date, final report issue date and, if appropriate, final report re-issue date. Vendor shall notify Company in writing if this timing cannot be met and shall demonstrate through documentation that it was impracticable to deliver information within 180 days. If Company determines that it was practical to obtain the report within the 180 days, an ILI tool may be re-run. Vendor shall provide software for viewing the raw signal trace data and other data presentations. Vendor shall automatically provide software updates. Vendor will manually review enough features to validate the accuracy of Vendor’s automated sizing system. Vendor will indicate which features were manually reviewed. If a discrepancy is identified in a final report that requires further evaluation, re-grade, and/or re-issue by Vendor, Vendor shall deliver revised final report within two weeks of discrepancy being identified. If data is re-graded, Vendor shall provide written correspondence documenting basis of discrepancies and proposed corrective actions. Upon completion of rehabilitiation activities by Company, Company will provide Vendor with actual field findings. Vendor will review data and provide feedback regarding tool performance and if regrade or rerun is warranted. <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 6 of 13 Vendor will schedule quarterly reviews with Company to discuss tool scheduling and performance, report delivery timelines and other performance standards. 4.5.14 5.0 technical Criteria 5.1 Metal Loss Interaction Criterion 5.1.1 5.1.2 Vendor shall group metal loss indications spaced less than 6 times the wall thickness (6t) apart in either axial or circumferential directions (called interacting) together to form a cluster. A reported metal loss anomaly may consist of an individual metal loss indication or a cluster of two or more interacting metal loss indications. Length and width reported for a cluster is the sum of individual indications plus metal interaction length or width, up to 6t in either direction. Peak depth reported for a cluster is the peak depth of the deepest metal loss indication in the cluster. A graphical presentation is as follows: 5.1.2.1 Expanded pig call boxes that overlap should be considered as interacting. P ig C a ll B o x # 1 P ig C a ll B o x # 2 P ig C a ll B o xe s e xp a n d e d '3 t' in e a ch d ire ctio n 5.2 Metal Loss Assessment Criterion 5.2.1 Vendor shall use RSTRENG 85% Area criterion (RSTRENG85% Area) to evaluate corrosion metal loss indications based upon the reported peak depth and axial length. 5.2.1.1 Predicted Failure Stress  Failure SMYS =  )000,10(      - 1  - 1 85.0    d  t   85.0    d  t   M 1-       where: Failure = Predicted failure stress, psi  = Flow stress, f{SMYS}, psi SMYS = Specified minimum yield strength, psi. d = depth of metal loss, inch t = Nominal wall thickness of pipe, inch <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 7 of 13 Dt d/t = depth-to-wall thickness ratio of the metal loss M = Folias factor, f{L, D, t} L = Axial length of the corrosion, inch D = Nominal outside diameter of the pipe, inch 2 L For  1 = 0.6275 + M50, 2 L 0.003375 - Dt  2 2   L  Dt   For 2 L 0.032 = M50, > Dt 2 L 3.3 + Dt 5.2.1.2 Rupture Pressure Ratio, RPR      - 1  85.0 - 1 85.0  Failure SMYS  )000,10(    d  t   RPR  = SMYS SMYS    d  t   M 1-       5.2.1.3 Predicted Burst Pressure, PBurst - 1 85.0    d  t   P   Burst Failure    2 t  SMYS = D    )000,10(     2 t  D       - 1  85.0    d  t   M 1-       5.2.2 5.2.3 Provide an RPR value and PSafe pressure value for all metal loss features. If instructed by Company, Vendor shall perform RSTRENG Effective Area Assessment of data for metal loss indications and shall produce a projected corrosion profile. Vendor shall evaluate this profile using the iterative calculation procedure in RSTRENG Effective Area analysis. An example profile is shown below: <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 8 of 13 Direction of Flow 30% 30% 10% Cluster 20% 50% Projected Corrosion Profile Wall Thickness 5.3 Crack-like and Longitudinal Seam Weld Assessment Criterion Circumferential MFL (TFI, AFD, SMFL) and ultrasonic crack detection (USCD) 5.3.1 Vendor shall identify ‘crack-like’ indications detected in pipeline, whether in pipe body or in longitudinal seam weld (LSW). 5.3.2 Vendor shall identify each indication of the following detected anomalies associated with LSW. Axial Seam Weld Metal Loss (ASWML) 5.3.2.6 Seam Weld Anomaly (SWA) 5.3.3 5.3.4 5.3.2.1 Seam Weld Features ‘A’ (SWFA 5.3.2.2 Seam Weld Features ‘B’ (SWFB) 5.3.2.3 Seam Weld Dents (SWD) 5.3.2.4 Seam Weld Metal Loss (SWML) 5.3.2.5 Potential pipe body metal loss indications (but not “crack-like” or other indications associated with LSW) reported by Vendor shall be assessed in accordance with Metal Loss Interaction Criterion and Metal Loss Assessment Criterion above). Company or designee will assess SWFA, SWFB, SWML, and ASWML indications using CorLASTM (fracture criterion) or comparable analysis. <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 9 of 13 5.4 Ultrasonic Wall Measurement Assessment Criterion 5.4.1 5.4.2 5.4.3 5.4.4 5.4.5 Pipeline Integrity Engineer or designee will consult with ILI vendor and Magellan’s third party consultant to establish reporting and evaluation criteria guidelines. All laminations as identified by tools reporting capabilities will be included in final report Vendor shall identify each indication of the following detected anomalies: 5.4.3.1 Sloping laminations 5.4.3.2 Bulging laminations 5.4.3.3 Laminations interacting with dents, metal loss, cracks, girth and seam welds and other reported features 5.4.3.4 Surface breaking laminations 5.4.3.5 Hydrogen blisters 5.4.3.6 Planar, intermittent or variable depth laminations 5.4.3.7 Other significant indications within the capability of the tool’s detection Vendor shall evaluate Metal loss as identified in section 5.1 and 5.2 and 5.5 Vendor shall evaluate deformation indications as identified in section 5.6 5.5 Metal Loss in Seamless Pipe 5.5.1 Vendor shall report sections of pipe containing “areas of interest” where seamless pipe noise pattern data is to the extent that the data analyst is challenged to accurately predict metal loss dimensions. 5.6 Geometry Assessment Criterion 5.6.1 Vendor shall report all deformations >2% of pipe diameter. Vendor shall report confirmed correlated deformations and geometric anomalies (regardless of depth) with associated metal loss, deformation >2% of pipe diameter associated with LSW, and deformation >2% of pipe diameter affecting pipe curvature of girth welds. In addition, vendor shall report all deformations and geometric anomalies that interact with laminations. 5.7 5.6.2 Vendor shall report data related to geometric indications within tool capability to detect such indications. Tool must be able to detect deformation indications 2% (or 0.250” for pipe less than or equal to 12” NPS) and greater. 5.6.3 If EGP ILI run occurs prior to or after an MFL/circumferential MLF UT pipeline inspection, Vendor shall integrate EGP and MFL/circumferential MFL UT data into a single final report. If Vendor cannot issue integrated final report within 180 days of the first successful ILI run, Vendor shall immediately notify Company and issue individual final reports. Field Evaluation of ILI Tool Results 5.7.1 ILI tool data shall be reviewed in the field and compared to the specifications referenced in acceptance limits on lost data in Performance Specification section. <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 10 of 13 5.7.2 If ILI tool data is not of sufficient quality to allow Vendor to meet detection and sizing thresholds in Performance Specification, ILI tool will be scheduled for a re-run. 5.8 ILI Reporting 5.8.1 The following shall be included in pipeline listing (Microsoft Excel format) for each feature: 5.8.1.1 Sequential girth weld number or reference number 5.8.1.2 Feature type 5.8.1.3 Relative distance to upstream weld (as measured from the start of the metal loss or ID reduction indication ), feet 5.8.1.4 Absolute odometer distance, feet 5.8.1.5 Joint length, feet 5.8.1.6 Comments 5.8.1.7 Internal or external location 5.8.1.8 Peak depth of metal loss (% w.t.), crack-like (% w.t.) or ID reduction (%OD) indication 5.8.1.9 Axial length, inches 5.8.1.10 Width, inches (metal loss indications only) 5.8.1.11 Orientation (deepest point of metal loss cluster or centerline of ID reduction indication), clock position 5.8.1.12 RPR (calculated using RSTRENG 85% Area criterion) 5.8.1.13 Nominal wall thickness, inches 5.8.2 5.8.1.14 Predicted Safe Pressure, (calculated using RSTRENG 85% Area criterion), psig 5.8.1.15 Approximate engineering station (based on alignment sheets and AGM benchmarks) 5.8.1.16 5.8.1.17 5.8.1.18 GPS coordinate, if requested by Company Pipe type (ERW, SAW, DSAW, or seamless) Longitudinal seam orientation (for circumferential MFL or ultrasonic ILI) 5.8.1.19 SMYS, psi 5.8.1.20 Relative distance to upstream weld (as measured from deepest point of metal loss or ID reduction indication), feet 5.8.1.21 Indication of which features have been manually reviewed The following shall be reported for each change in pipe wall thickness, type or grade in wall thickness listing: 5.8.2.1 Absolute odometer distance, feet 5.8.2.2 Nominal wall thickness, inches 5.8.2.3 Pipe type <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 11 of 13 5.8.2.4 SMYS, psi Data shall be presented with enough significant digits to reproduce results. 5.8.3 6.0 DEFINITIONS 6.1 Terms and terminology shall be used in accordance with API 1163 Section 4 unless otherwise specified herein. Vendor shall get approval in writing from Company to use other terminology. Additional definitions are as follows: 6.1.1 6.1.2 6.1.3 6.1.4 6.1.5 6.1.6 Seam Weld Feature A (SWFA): Seam weld indication that exhibits possible “crack‐like” characteristics. Seam Weld Feature B (SWFB): Seam weld indication that exhibits some, but not all “crack‐like” characteristics. Seam Weld Metal Loss (SWML): Metal loss indication (including any part of a cluster) that encroaches upon the longitudinal seam weld (LSW). Axial Seam Weld Metal Loss (ASWML): Metal loss indication (including any part of a cluster) that encroaches upon LSW and is less than 2‐inches wide with a length‐to‐ width aspect ratio equal to or greater than 5:1 Seam Weld Deformation (SWD): Deformation that encroaches upon the LSW 6.1.7 Seam Weld Anomaly (SWA): Feature other than a SWFA, SWFB, SWML, or SWD that encroaches upon or is immediately adjacent to LSW and is thought to be non‐injurious. Geometric Anomaly: Internal diameter reduction indication below reporting requirements specified in 49 CFR 195.452h <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 12 of 13 System Integrity Plan Change Log Date Change Location Change By Approved By Brief Description of Change 11/01/05 All Clyde Clausen Mike Pearson Conducted Annual Review 01/01/06 2.52 Clyde Clausen Mike Pearson Added: Longhorn Specific 10/30/06 All Clyde Clausen Mike Pearson Conduct annual review 12/8/06 All Clyde Clausen Mike Pearson Removed all references to RSTRENG Effective Area. 4/30/07 3.3.3.1 Clyde Clausen Mike Pearson Added paragraph for Longhorn Specific requirements. 6/26/07 2.4.2.1 Clyde Clausen Mike Pearson Added Paragraph 6/26/07 2.5.8 Clyde Clausen Mike Pearson Modified Paragraph 6/26/07 3.3.3 Clyde Clausen Mike Pearson Modified paragraph to change seam criteria to two times the wall thickness. Removed Longhorn Specific 3.3.3.1. 6/26/07 3.4.1 Clyde Clausen Mike Pearson Modified paragraph to reflect dent reporting criteria. 6/26/07 3.6.3 Clyde Clausen Mike Pearson Added paragraph 7/10/08 Document Dennis Vasicek Clyde Clausen Changed “contractor” to “vendor” 7/10/08 1.0 Dennis Vasicek Clyde Clausen Added Section 1.0 Purpose and paragraph 1.1 7/10/08 2.0 Dennis Vasicek Clyde Clausen Added Section 2.0 Scope and paragraphs 2.1 through 2.3.3 7/10/08 3.1 Dennis Vasicek Clyde Clausen Revised sentence 7/10/08 3.2 Dennis Vasicek Clyde Clausen Removed, “If requested” from the third sentence 7/10/08 3.3 Dennis Vasicek Clyde Clausen Changed, “will” to, “may” 7/10/08 3.4 Dennis Vasicek Clyde Clausen Rewrote paragraph 7/10/08 3.11 Dennis Vasicek Clyde Clausen Reworded sentence 7/10/08 3.12 Dennis Vasicek Clyde Clausen Added paragraph 7/10/08 4.1.1 Dennis Vasicek Clyde Clausen Reworded sentence 7/10/08 4.1.1.4 Dennis Vasicek Clyde Clausen Added paragraph 7/10/08 4.1.1.9 Dennis Vasicek Clyde Clausen Changed, “defect” to, “anomaly” and added clarification to last sentence. 7/10/08 4.2.1 Dennis Vasicek Clyde Clausen Added clarification to the sentence 7/10/08 4.2.2 Dennis Vasicek Clyde Clausen Revised sentence 7/10/08 4.2.3 Dennis Vasicek Clyde Clausen Added last sentence regarding tool performance specification related to flow rate changes 7/10/08 4.2.8 Dennis Vasicek Clyde Clausen Added “prevent” to first sentence 7/10/08 4.2.10 Dennis Vasicek Clyde Clausen Replaced last sentence with, “The certification levels of the supervisor and other team members shall be advised to the Company by the vendor’s project manager prior to a team arriving on-site.” 7/10/08 4.2.13 Dennis Vasicek Clyde Clausen Added clarification to sentence 7/10/08 4.2.14 Dennis Vasicek Clyde Clausen Deleted sentence 7/10/08 4.2.15 Dennis Vasicek Clyde Clausen Deleted sentence 7/10/08 4.3.2 Dennis Vasicek Clyde Clausen Added “certified to level III in analysis” and change “defects” to “anomalies” 7/10/08 4.3.5 Dennis Vasicek Clyde Clausen Deleted second sentence 7/10/08 4.4.2.1 Dennis Vasicek Clyde Clausen Added sentence 7/10/08 4.4.2.2 Dennis Vasicek Clyde Clausen Added sentence 7/10/08 4.4.2.3 Dennis Vasicek Clyde Clausen Added sentence 7/10/08 4.4.2.4 Dennis Vasicek Clyde Clausen Added sentence 7/10/08 4.4.2.5 Dennis Vasicek Clyde Clausen Added sentence 7/10/08 4.4.2.7 Dennis Vasicek Clyde Clausen Reworded paragraph 7/10/08 4.4.2.10 Dennis Vasicek Clyde Clausen Removed sentence 7/10/08 4.5 Dennis Vasicek Clyde Clausen Added, “and Other Requirements” 7/10/08 4.5.1 Dennis Vasicek Clyde Clausen Added sentence 7/10/08 4.5.6 Dennis Vasicek Clyde Clausen Added clarification to the first sentence 7/10/08 4.5.9 Dennis Vasicek Clyde Clausen Added, “final report” 7/10/08 5.2.3 Dennis Vasicek Clyde Clausen Added paragraph 7/10/08 5.3.3 Dennis Vasicek Clyde Clausen Deleted paragraph related to seam assessment width 7/10/08 5.3.3.4 Dennis Vasicek Clyde Clausen Divided Seam Weld Metal Loss into two categories and added paragraphs 5.3.3.4.1 and 5.3.3.4.2 7/10/08 5.3.4 Dennis Vasicek Clyde Clausen Changed, “valid” to, “used” and added, “but not for the seam weld assessment” 7/10/08 5.4 Dennis Vasicek Clyde Clausen Added Metal Loss in Seamless Pipe paragraph and paragraph 5.4.1 7/10/08 5.6.2 Dennis Vasicek Clyde Clausen Added paragraph <<>> Magellan Midstream Partners, L.P. IN-LINE INSPECTION TECHNICAL SPECIFICATION 7.03–ADM–003 Asset Integrity 01/01/12 Revision: 5 Page 13 of 13 12/19/08 Dennis Vasicek Clyde Clausen Conducted annual review and made minor wording modifications 01/01/10 4.5.3 Removed “Longhorn” 4.5.5 Changed to Bi-weekly 4.5.6 Added weld comparison 5.3.3.4.2 Removed: separate listin of seam weld metal loss features athat are axially oriented metal loss 5.7.1.8/5.7.1.1 4/5.7.1.15/ New. Deleted Upstream reference location/distance and downstream reference Definitions Section Added 01/01/11 Reviewed, no changes 9/1/11 All Clyde Clausen Doug Chabino Re‐worked and Re‐formatted entire document 12/31/11 All 2012 Annual Review complete 6/18/12 5.6.1 Clyde Clausen Doug Chabino Clarified reporting dent criteria in section 5.6.1 <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 1 of 18 1.0 OBJECTIVE 1.1 The Objective of this procedure is to establish the process to analyze In‐Line Inspection (ILI) data to identify features that require repair per DOT 49 CFR 195.452. 2.0 INDEX 1.0 OBJECTIVE ........................................................................................................................................ 1 2.0 INDEX ................................................................................................................................................. 1 3.0 PROCEDURE ..................................................................................................................................... 1 4.0 PRELIMINARY REPORTS ................................................................................................................. 1 5.0 ELECTRONIC DRAFT REPORTS ...................................................................................................... 1 6.0 FINAL REPORTS ................................................................................................................................ 1 7.0 INTEGRITY CONDITIONS ................................................................................................................. 2 8.0 9.0 DISCRETE POINT PRESSURE (DPP) ANALYSIS ............................................................................ 5 SEAM WELD ASSESSMENT ............................................................................................................. 6 10.0 ULTRASONIC WALL MEASUREMENT ASSESSMENT ................................................................... 7 11.0 CASING ANALYSIS ............................................................................................................................ 8 12.0 DENT REVIEW AND DEPTH OF COVER CORRELATION .............................................................. 8 13.0 PROJECTED CORROSION GROWTH ANALYSIS ........................................................................... 9 14.0 CALIBRATION DIGS ......................................................................................................................... 9 15.0 DIG LIST ........................................................................................................................................... 10 16.0 ILI SUMMARY DOCUMENT ............................................................................................................. 11 17.0 CORRELATION AND TOOL TOLERANCE ASSESSMENT............................................................ 11 18.0 DEFINITIONS .................................................................................................................................... 12 19.0 REFERENCES .................................................................................................................................. 13 3.0 PROCEDURE 3.1 3.2 3.3 3.4 This guideline incorporates API 1163, In‐line Inspection Systems Qualification Standard, First Edition, August 2005; NACE Standard RP0102‐2002; and ANSI/ASNT ILI‐PQ‐2005 where applicable. This guideline is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be used, in whole or part, on non‐jurisdictional assets as deemed appropriate. Assets Covered Per Mitigation Plan operate under Longhorn Mitigation Plan requirements in addition to applicable Federal, State, and Local regulations and Company guidelines, processes or best practices. The Pipeline Integrity Engineer and Pipeline Integrity Data Coordinator will utilize this Guideline in conjunction with the In‐Line Inspection Procedure when conducting analyses of Inspection data. . <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 1 of 17 4.0 PRELIMINARY REPORTS 4.1 In‐line Inspection Vendor (Vendor) will provide Preliminary Report (if required) within 21 business days of a successful tool run. Features requiring a Preliminary Report are described in In‐Line Inspection Technical Specification. 4.2 If features meeting preliminary reporting criteria are reported by Vendor, Pipeline Integrity Engineer will: 4.2.1. 4.2.2. 4.2.3. Notify Supervisor of Pipeline Integrity Engineering via email. Initiate immediate investigation and repair process described in In‐Line Inspection Procedure if feature is located in an HCA. 4.3 Ensure that appropriate response is executed within 5 days of receipt of Preliminary Report for features reported on Assets Covered Per Mitigation Plan in accordance with Longhorn Mitigation Plan, Section 3.5.2. 4.2.4. Request Pipeline Integrity Data Analyst to prepare dig sheets. 4.2.5. Provide excavation findings to Vendor upon completion of any field investigations. Pipeline Integrity Data Analyst will: 4.3.1. Prepare dig sheets using Procedure for Creating Dig Sheets. 4.3.2. Prepare Rehab Book for inspector in accordance with Project File Index Form. 5.0 ELECTRONIC DRAFT REPORTS 5.1 Vendor will provide an electronic Draft Report as specified in In‐Line Inspection Technical Specification. 5.2 Pipeline Integrity Data Analyst will verify electronic Draft Report as specified in AGM Verification Guidelines. Verify electronic Draft Report as specified in ILI Data Verification Guidelines. 5.3 Pipeline Integrity Engineer will: 5.3.1. 5.3.2. Approve electronic Draft Report or provide Vendor any comments within 5 business days of receipt of electronic Draft Report. If discrepancies are identified, Vendor will be required to make necessary modifications before issuance of Final Report. 6.0 FINAL REPORTS 6.1 Pipeline Integrity Engineer will 6.1.1. 6.1.2. Perform QA/QC review of Final Report to ensure it is thorough, complete, correct and delivered in accordance with In‐Line Inspection Technical Specification. 6.1.1.1. If a significant issue is observed, Pipeline Integrity Engineer will immediately reject Final Report and notify Vendor in writing. Declare the date of discovery (Discovery) within 5 business days of receipt of a valid Final Report but not later than 180 days after the day ILI tool was trapped in the receiver. 6.1.2.1. 6.1.3. Pipeline Integrity Engineer will calculate 60‐day and 180‐day due dates for HCA conditions based on counting forward from Discovery date. For Assets Covered Per Mitigation Plan Send a copy of MFL Final Report to Operational <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 2 of 17 6.2 6.1.4. 6.1.5. 6.1.6. Reliability Assessment (ORA) Contractor for Probability of Exceedance (POE) analysis, girth weld evaluation and metal loss within 3 inches of girth weld for. Copy electronic documents (i.e. pipeline listing, NWT report, AGM listing and mapping files, LAPA [if provided], certification of calibration) to appropriate line section folder on network drive. Perform detailed analysis of ILI data to identify: immediate, 60‐day, 180‐day and 6‐ month (where applicable) features, DPP features, casings to be worked, ID reduction review, and other features potentially requiring investigation. Schedule a Pre‐Job Roundtable meeting with various stakeholders (as appropriate: Asset Integrity Maintenance Supervisor, Asset Integrity Engineer, Supervisor Corrosion Control, Pipeline Integrity Coordinator, Real Estate Representative, Pipeline Integrity Data Analyst, Supervisor of Pipeline Integrity Engineering and Manager of Asset Integrity) to discuss ILI Summary document, features to be investigated, and other concerns (e.g. integrated depth of cover and corrosion control data) identified by Final Report. Pipeline Integrity Data Analyst will: 6.2.1. Prepare dig sheets using Procedure for Creating Dig Sheets. 6.2.2. Prepare a project field book using Project File Index Form. 6.2.3. Obtain completed project field book from chief inspector and perform checks on information accumulated during rehabilitation upon completion of rehabilitation activities. 7.0 INTEGRITY CONDITIONS 7.1 7.2 7.3 Pipeline Integrity Engineer will obtain High Consequence Area (HCA) begin and end location information from Risk Analyst or from HCA database and calculate corresponding odometer locations to mark in Final Report. Pipeline Integrity Engineer will identify the following conditions: HCAS And Areas That Could Affect HCAs 7.3.1. Immediate Repair Conditions 7.3.1.1. Discovery of an immediate repair condition is to be established no later than 5 business days after condition is reported to Company. Within 5 business days of identification of an immediate repair condition, Pipeline Integrity Engineer will initiate immediate investigation and repair process in accordance with In‐Line Inspection Procedure. 7.3.1.2. Until immediate condition is repaired, the following operating conditions may be implemented (dependent upon the type of feature). 7.3.1.2.1. Reduce operating pressure so that at the location of the anomaly, discrete point pressure (PDPP) does not exceed operating pressure (PSAFE), or PDPP does not exceed the pressure calculated by the formula in Section 451.7 of ASME/ANSI B31.4, or 7.3.1.2.2. Reduce operating pressure so that PDPP does not exceed 80% <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 3 of 17 7.3.1.3. 7.3.1.4. of highest operating pressure actually experienced at location of anomaly within 60‐days preceding inspection, or 7.3.1.2.3. Shutdown pipeline. Metal loss features (including SWFA, SWFB, ASWML and SWML) with predicted depths greater than or equal to 80% of the wall thickness requires reducing operating pressure per 7.3.1.2.2 or shutdown pipeline until repair is made. Features with predicted burst pressure, PBURST, less than PDPP requires reduce operating pressure per 7.3.1.2.1 or shutdown pipeline until repair is made. 7.3.1.4.1. 7.3.1.4.2. Metal loss calculation using 85% Area RSTRENG criterion or CorLASTM (Flow Stress Criterion, 85% Area) SWFA, SWFB, ASWML, or SWML calculation using CorLASTM (Fracture Mechanics Criterion) 7.3.1.5. Top‐side dents (above the 4 and 8 o’clock positions) predicted to contain associated metal loss, cracking or a stress riser requires reducing operating pressure per 7.3.1.2.2 or shutdown pipeline until repair is made. 7.3.1.6. Top‐side dents with a predicted depth greater than 6% of the nominal pipe diameter requires reducing operating pressure per 7.3.1.2.2 or shutdown pipeline until repair is made. 7.3.1.7. Significant features in the judgment of the person evaluating the inspection and test assessment results requires reducing operating pressure or shutdown pipeline based upon type of feature and engineering analysis until repair is made. 7.3.1.8. Deformation anomaly characterized as a pipeline device or repair intrusion such as pig‐sig, IFD, tube, flow improver nozzle, heavy weld, etc. will not be considered an “Immediate Condition.” 7.3.2. 60‐Day Repair Conditions 7.3.2.1. Top‐side dents with a predicted depth greater than 3% of the pipeline diameter (greater than 0.250” in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12). 7.3.2.2. Bottom‐side dents (below 4 and 8 o’clock positions) predicted to contain any metal loss, cracking, or a stress riser. 7.3.3. 180‐day Repair Conditions 7.3.3.1. Dents with a predicted depth greater than 2% of the pipeline’s diameter (0.250” in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld. 7.3.3.2. Top‐side dents with a predicted depth greater than 2% of the pipeline’s diameter (0.250” in depth for a pipeline diameter less than NPS 12). 7.3.3.3. Bottom‐side dents with a predicted depth greater than 6% of the pipeline’s diameter. 7.3.3.4. Features where the calculation of remaining strength of the pipe shows an <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 4 of 17 7.4 operating pressure, PSAFE, that is less than PDPP at the location of the anomaly. 7.3.3.5. Areas of general corrosion with a predicted metal loss greater than 50% of nominal wall 7.3.3.6. Features with predicted metal loss greater than 50% of nominal wall that are located at a crossing of another pipeline, or are in an area with widespread circumferential corrosion, or are in an area that could affect a girth weld 7.3.3.7. Potential crack indications that when excavated are determined to be a crack. 7.3.3.8. Corrosion of or along a longitudinal seam weld (as identified by the ILI service provider as being axially oriented seam weld metal loss) 7.3.3.9. Gouge or grooves with a predicted depth greater than 12.5% of nominal wall 7.3.4. Other Conditions 7.3.4.1. Conditions identified by ILI that could impair the integrity of the pipeline should be repaired as appropriate. Non‐HCAS And Areas Not Affecting HCAS 7.4.1. The following anomalies will be immediately evaluated and scheduled for excavation if deemed necessary. However, all HCA Immediate Conditions shall take priority: 7.4.1.1. Metal loss (including SWFA, SWFB, ASWML, and SWML) greater than or equal to 80% wall thickness 7.4.1.2. Features with predicted burst pressure Pburst, less than discrete point pressure, PDPP. 7.4.1.3. 7.4.1.2.1. Metal Loss calculation using 85% Area RSTRENG Criterion or CorLAS™ (Flow Stress Criterion, 85% Area) 7.4.1.2.2. SWFA, SWFB, ASWML, or SWML calculation using CorLAS™ (Fracture Mechanics Criterion) Top‐side dents with any indicated metal loss, cracking or stress riser 7.4.2. The following anomalies will be evaluated and scheduled for excavation and repair prior to the next integrity assessment if deemed necessary: 7.4.2.1. Features where PSAFE is less than PDPP at location of anomaly. 7.4.2.2. Bottom‐side dents with associated metal loss. 7.4.2.3. Girth weld anomalies 7.4.2.4. Dents in excess of 6% of pipe diameter. 7.4.2.5. Dents located in the girth weld or longitudinal seam that exceed 2% of pipe diameter for NPS 12 and larger or 0.250” for pipe diameters less than NPS 12. 7.4.2.6. Gouges, scratches, or grooves that exceed 12.5% metal loss. 7.4.2.7. Severe mill related defects (lamination, hard spots, etc.). <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 5 of 17 7.4.2.8. Crack‐like anomalies located in girth weld, longitudinal seam weld, or pipe 7.5.2. 8.0 7.5 7.6 body. 7.4.2.9. Field confirmed casing shorts with associated metal loss. 7.4.2.10. Other significant anomalies. 7.4.2.11. Features identified for tool calibration purposes. Assets Covered Per Mitigation Plan 7.5.1. Initiation of a response must be implemented within 5 days of receipt of report for these features in accordance with Longhorn Mitigation Plan Section 3.5.2 7.5.1.1. Metal loss greater than 70% wall thickness 7.5.1.2. Top‐side dents with any indicated metal loss 7.5.1.3. Significant anomalies that in the judgment of the data evaluator require immediate action initiation of a response must be implemented within 60 days of receipt of report for these features in accordance with Longhorn Mitigation Plan Section 3.5.2. 7.5.2.1. Top‐side dents without indicated metal loss and with depths greater than 6% of the pipe diameter 7.5.3. The following indications shall be investigated within 6 months of the receipt of report in accordance with Longhorn Mitigation Plan Section 3.5.2. 7.5.3.1. Dents with any of the following: Metal loss, corrosion, exceeds 6% of the pipe outside diameter, or located in a longitudinal seam or girth weld Features where remaining strength of pipe results in a safe operating pressure, PSAFE, that is less than the current MOP at the location of the anomaly using a suitable safe operating pressure calculating criterion. 7.5.3.3. Casing shorts with associated metal loss 7.5.3.4. Girth weld anomalies 7.5.3.5. Corrosion within 3” of either side and/or across girth welds as determined by ORA contractor 7.5.3.6. Preferential corrosion of or along seam welds. 7.5.3.7. Gouges or grooves greater than 50% of nominal wall thickness 7.5.3.8. Cracks located in the pipe body, girth weld, and longitudinal seam that are determined to be injurious to the integrity of the pipeline. As an alternative to direct examination, an API 579 Fitness‐For‐Service level 1, 2, and/or 3 Engineering Critical Assessment may be performed in order to substantiate the need for direct examination activity. DISCRETE POINT PRESSURE (DPP) ANALYSIS 8.1 Pipeline Integrity Engineer will populate discrete point pressure (DPP) spreadsheet with anomalies with rupture pressure ratio (RPR) less than 1.0. RPR is PBURST divided by pipe design pressure. PSAFE is design factor multiplied by PBURST. RPR will be less than 1.0 when PBURST of an anomaly is less than pipe design pressure (100% SMYS). DPP data sources include: 7.5.3.2. <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 6 of 17 8.1.1. ILI Final Report 8.1.2. Corrosion Growth spreadsheet 8.1.3. Seam Weld Assessment analysis 8.2 Pipeline Integrity Data Analyst will: 8.2.1. Calculate stations using Total AGMs Form and obtain elevations using alignment sheets for features requiring DPP analysis. 8.2.2. Use alignment sheets to determine if any metal loss features greater than 50% are located within 50’ of a foreign pipeline crossing and will indicate on appropriate tab in the DPP spreadsheet. 8.3 Asset Integrity Engineer will complete DPP analysis taking into account pump set points, elevation differences, and surge conditions. 8.3.1. Determine, through available records, design pressure for line and upstream pump maximum discharge set point. 8.3.2. Determine maximum elevation difference between pressure source and feature location. 8.3.3. Determine static head pressure due to elevation change calculated using specific gravity of heaviest product. 8.3.4. Add static head pressure to pump set point to get PDPP at feature location due to static head (Static PDPP). 8.3.5. For incompressible liquid pipelines, conduct surge analysis at each feature location to determine PDPP due to surge (Surge PDPP). 8.3.6. Compare static PDPP and surge PDPP at each feature location. Select greater value to be used as PDPP for anomaly location. 8.4 Pipeline Integrity Engineer will add anomalies in HCA with PBURST < PDPP to dig list as immediate repair conditions (priority conditions in non‐HCA) and will add anomalies in HCA with PSAFE < PDPP to dig list as 180‐day conditions (secondary conditions in non‐HCA). 9.0 SEAM WELD ASSESSMENT 9.1 Pipeline Integrity Engineer or designee will conduct seam weld assessment (SWA) when ILI tool is either circumferential flux leakage (aka TFI, AFD, or SWML ILI) or ultrasonic crack detection (USCD) ILI technology. 9.2 The following anomalies will be assessed and considered for investigation and/or remediation. 9.2.1. Seam Weld Feature A (SWFA) 9.2.2. Seam Weld Feature B (SWFB) 9.2.3. Axial Seam Weld Metal Loss (ASWML) 9.2.4. Seam Weld Deformation (SWD) 9.2.5. Axial Planar features 9.2.6. Crack‐Field 9.2.7. Notch‐Like <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 7 of 17 9.2.8. Weld Anomaly 9.2.9. Other integrity features in the judgment of the person evaluating the data 9.3 Pipeline Integrity Engineer or designee will calculate Pburst and Psafe using CorLAS™ (fracture criterion) or similar remaining strength calculation and using appropriate fracture toughness for SWFA, SWFB, ASWML and SWML anomalies. 9.4 Pipeline Integrity Engineer or designee may use MFL data, when available, to identify additional potential SWML anomalies, defined as those within 2 inches of LSW. For these integrated SWML anomalies, Pipeline Integrity Engineer or designee will calculate Pburst and Psafe for all internal and external anomalies, using 85% Area RSTRENG™ or CorLAS™ (flow stress criterion, 85% Area) 9.5 Pipeline Integrity Engineer will add to DPP spreadsheet features requiring direct examination when PBURST is less than pipe design pressure (100% SMYS) and features identified in SWA report as requiring DPP analysis. RPR and PBURST values listed in SWA report will be used in DPP spreadsheet. 9.6 Pipeline Integrity Engineer will add anomalies in HCA with PBURST < PDPP to dig list as immediate repair conditions (priority conditions in non‐HCA) and will add anomalies in HCA with PSAFE < PDPP to dig list as 180‐day conditions (secondary conditions in non‐HCA). 10.0 ULTRASONIC WALL MEASUREMENT ASSESSMENT 10.1 Pipeline Integrity Engineer or designee will conduct ultrasonic wall measurement (USWM) assessment when ILI tool is USWM ILI technology. 10.2 Pipeline Integrity Engineer or designee will consult with ILI vendor and Magellan’s third party consultant to establish reporting and evaluation criteria guidelines. If needed, modifications will be made to Magellan’s In‐Line Inspection Technical Specification. All laminations as identified by tools reporting capabilities will be included in final report. 10.3 The following Laminations will be evaluated and considered for investigation and/or remediation. 10.3.1. Sloping laminations 10.3.2. Bulging laminations 10.3.3. Surface breaking laminations 10.3.4. Hydrogen blisters 10.3.5. Laminations interacting with deformations, metal loss, cracks, girth and seam welds, and other reported features 10.3.6. Other integrity features in the judgment of the person evaluating the data. 10.4 When applicable, Pipeline Integrity Engineer or designee will review the USWM data for seam weld features and perform calculations described in the Seam Weld Assessment process. 10.5 Pipeline Integrity Engineer or designee will identify and evaluate all reported deformations identified by EGP (Electronic Geometry Pigs) or other applicable ILI inspections that correlate and interact with existing laminations. 10.6 Pipeline Integrity Engineer or designee may use previous ILI data, when available, to identify additional metal loss anomalies and significant features (i.e. cracks, girth welds, long seam, etc.) that may be potentially associated with laminations. For integrated metal loss anomalies > 20% deep, Pipeline Integrity Engineer or designee will calculate PBURST and PSAFE for all internal and <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 8 of 17 external anomalies using CorLASTM (Fracture Mechanics Criterion) 10.7 Pipeline Integrity Engineer will add to DPP spreadsheet features requiring direct examination when PBURST is less than pipe design pressure (100% SMYS) and features identified in USWM report as requiring DPP analysis. RPR and PBURST values listed in USWM report will be used in DPP spreadsheet. 10.8 Pipeline Integrity Engineer will add anomalies in HCA with PBURST < PDPP to dig list as immediate repair conditions (priority conditions in non‐HCA) and will add anomalies in HCA with PSAFE < PDPP to dig list as 180‐day conditions (secondary conditions in non‐HCA). 10.9 Pipeline Integrity Engineer will place all features requiring investigation on the dig list 11.0 CASING ANALYSIS 11.4 Pipeline Integrity Data Analyst will notify Pipeline Integrity Engineer if any casings need to be added to Dig List. 11.5 Pipeline Integrity Engineer will identify casings with metal loss in Final Report. 12.0 11.1 Pipeline Integrity Engineer will create a list of casings with casing begin and end locations in order of absolute distance. 11.2 Pipeline Integrity Data Analyst will determine casings that require rehabilitation. Pipeline Integrity Data Analyst will: 11.2.1. Add metal loss information from Final Report to designate number of metal loss features and maximum and minimum depths of metal loss inside each casing. 11.2.2. Check with Pipeline Integrity Engineer to determine if any casings are scheduled to be investigated due to required ILI investigations. 11.2.3. Review corrosion database for potential shorted or elevated casings. 11.2.4. Request Corrosion Technician field verify casings as required. 11.3 Corrosion Technician will resolve discrepancies and perform field verification of casings as required, notify Pipeline Integrity Data Analyst about casings that need to be investigated during pipeline rehabilitation, and incorporate field verification findings into corrosion database. DENT REVIEW AND DEPTH OF COVER CORRELATION 12.1 Pipeline Integrity Engineer will create a top‐side dent list and a dent comparison list. The dent comparison list will match current dent callouts to previous ILI run dent callouts. 12.2 Pipeline Integrity Engineer may request previous run Vendor to verify data signal to determine if current dents were visible in previous run data. 12.3 Pipeline Integrity Data Analyst will review depth of cover database and/or spreadsheets, if available, to determine depth of cover and land use for each identified top‐side dent. 12.4 Pipeline Integrity Engineer will: 12.4.1. Add top‐side dents located in cultivation with depth of cover less than 18” to the Dig List for investigation. 12.4.2. Add top‐side dents where no depth of cover information is available to the Dig List as “stake only” digs to determine land use and depth of cover. Further investigation of these features may be necessary pending land use and depth of cover information. <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 9 of 17 13.0 PROJECTED CORROSION GROWTH ANALYSIS 13.1 13.2 13.3 13.4 13.5 13.6 13.7 Pipeline Integrity Engineer will analyze metal loss indications to establish a re‐assessment interval based on projected corrosion growth (PCG). Pipeline Integrity Engineer will: 13.1.1. Create PCG analysis spreadsheet and input vital pipeline and ILI data for each metal loss anomaly and corrosion growth time period (typically 6.2 years) 13.1.2. Input 110% MOP for line segment 13.1.3. Input year of construction and year of inspection 13.1.4. Calculate PCG rate for each metal loss anomaly assuming linear corrosion growth starting at time of construction based on the following formula where d/t is depth of metal loss (percentage of wall thickness) as reported by ILI tool. PCG rate = Reported (d/t) / Years Where multiple inspections have been conducted utilizing like technologies, Pipeline Integrity Engineer will calculate a run comparison PCG rate for each metal loss anomaly with a reported peak depth ≥ 25% wall thickness by comparing current reported peak depth with a previous reported peak depth and dividing by years between inspections. 13.2.1. Pipeline Integrity Engineer will input run comparison PCG rate into a separate run comparison projected corrosion growth analysis spreadsheet. 13.2.2. For features indicating “Consider Remediation”, Pipeline Integrity Engineer will contact previous run Vendor to verify feature sizing. Revised feature sizing will be updated in the run comparison spreadsheet and a new PCG rate will be calculated. 13.2.3. For features indicating a10 mils per year or greater PCG rate, Pipeline Integrity Engineer will contact previous run Vendor to verify feature sizing. Revised feature sizing will be updated in the run comparison spreadsheet and a new PCG rate will be calculated. Pipeline Integrity Engineer will calculate a 6.2‐year projected depth of corrosion, (d/t) Projected, based on the following formula. This assessment can also be performed for intervals other than 6.2‐years but (d/t) cannot exceed 1.00 (i.e., depth exceeds wall thickness). (d/t) Projected = (d/t) Reported + 6.2*PCG rate Pipeline Integrity Engineer will calculate PBURST based on (d/t) Projected and add metal loss indications for which PBURST is less than 110% MOP to DPP analysis spreadsheet. DPP analysis will be conducted as described in Discrete Point Pressure Analysis section. Pipeline Integrity Engineer will consider adding to Dig List metal loss anomalies for which (d/t) Projected exceeds 80% wall thickness. Pipeline Integrity Engineer will consider adding to Dig List metal loss anomalies for which the PCG rate is 10 mils per year or greater. Assets Covered Per Mitigation Plan 13.7.1. Identify locations where (d/t) Projected exceeds 70% wall thickness and consider adding to Dig List. 14.0 CALIBRATION DIGS 14.1 If deemed necessary by the Company and/or Vendor, Pipeline Integrity Engineer will add calibration investigations of potential anomalies to Dig List in order to confirm performance of the ILI tool as described in Correlation and Tool Tolerance Assessment Section. <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 10 of 17 14.2 When possible, Pipeline Integrity Engineer will add to Dig List a minimum of one calibration investigation in seamless pipe. 15.0 DIG LIST 15.1 15.2 15.3 15.4 15.5 15.6 15.7 15.8 Pipeline Integrity Engineer will create dig List and include the following: 15.1.1. Immediate conditions and preliminary digs performed prior to receipt of Final Report. 15.1.2. Integrity Conditions (HCA and non‐HCA) 15.1.3. DPP features identified through DPP Analysis 15.1.4. “Features > 50%” located at foreign crossings, in an area of general corrosion, or any areas that affect a girth weld. 15.1.5. Potential crack‐like anomalies, including SFWA, SFWB, ASWML, and SWD and other features identified through Seam Weld Assessment 15.1.6. Laminations and other features identified through section 10 of the Ultrasonic Wall Measurement Assessment 15.1.7. Casings identified through Casing Analysis 15.1.8. Dents identified through Dent Review 15.1.9. Metal loss features identified through Projected Corrosion Growth Analysis 15.1.10. Calibration Digs Pipeline Integrity Engineer will compare proposed Dig List to information from previous rehabilitation projects for locations where anomalies have been previously investigated and will consider eliminating these anomalies from Dig List. Pipeline Integrity Engineer will mark digs in Final Report and document appropriate comments for dig list. Pipeline Integrity Engineer will give Final Report and proposed Dig List to Supervisor of Pipeline Integrity Engineering or Manager Asset Integrity for review. Supervisor of Pipeline Integrity Engineering or Manager of Asset Integrity will review ILI Final Report and proposed Dig List, including: 15.5.1. External metal loss indications reported inside casings 15.5.2. Potential interactions of metal loss indications reported in seamless pipe 15.5.3. Past ILI records and dig results, leak history, corrosion growth analysis, and previous Executive Summary of Risk Analysis. 15.5.4. Send approval of proposed dig list with any additional proposed digs, if applicable, to Pipeline Integrity Engineer. Pipeline Integrity Engineer will incorporate changes requested by Supervisor of Pipeline Integrity Engineering or Manager of Asset Integrity. Pipeline Integrity Engineer will contact Vendor to manually verify location and feature sizing of dig list features. Vendor comments may be added to the dig list. Pipeline Integrity Data Analyst will create dig sheets using Procedure for Creating Dig Sheets. <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 11 of 17 16.0 ILI SUMMARY DOCUMENTS 16.1 Pipeline Integrity Engineer will complete ILI Summary document. 17.0 CORRELATION AND TOOL TOLERANCE ASSESSMENT 17.1 17.2 17.3 17.4 17.5 When inspecting potential anomalies in the field, NDE contractor and Pipeline Integrity Coordinator will use their best efforts to try to understand how/why ILI tool reported various defects observed in the field and will capture this in Pipeline Maintenance Report. Pipeline Integrity Coordinator should be consulted and discrepancies should be resolved in the field before coating and backfilling when possible. Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will review NDE reports and compare ILI reported anomaly dimensions to actual defect dimensions observed in the field. 17.2.1. Comparisons will be used to develop a depth unity plot and data correlation report for each ILI run. 17.2.2. Anomalies to be correlated will include detectible metal loss, SWFA, SWFB, ASWML, SWML and ID reductions. For Assets Subject to Company Consent Decree Effective 9/4/08, 17.3.1. Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will complete comparison described above within three (3) months following completion of anomaly investigations associated with each ILI run. Comparison will include a statistically valid number of anomalies. 17.3.1.1. For ILI runs where an insufficient number of anomalies are identified to perform a statistically valid comparison analysis, anomaly comparisons may include other indications such as casings, girth welds, previous repairs, and other pipeline appurtenances. In these instances, Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will document actual versus predicted indication characteristics for each ILI run. 17.3.2. Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will develop two (2) sets of unity plots (length of axial oriented anomaly and depth into pipe wall) within three (3) months following completion of anomaly investigations associated with each ILI run intended to inspect ERW longitudinal seam weld. 17.3.2.1. ILI cracks/anomalies include detectible seam weld and HAZ features and indications 17.3.2.2. For ILI runs where an insufficient number of seam and HAZ anomalies are identified to perform a statistically valid comparison analysis, anomaly comparisons may include other indications. In these instances, Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will document actual versus predicted indication characteristics for each ILI run. Pipeline Integrity Engineer will review unity plots and data correlation reports and will consider additional excavations, regrading, engineering evaluation assessments, or re- running ILI tool if observed defect sizes are consistently outside of Vendor specified tolerances. If comparison described above suggests that Vendor undersized (or “undercalled”, as in anomalies were observed to be more severe than predicted) anomalies, Pipeline Integrity Engineer will take tool tolerances into account to recalculate corrosion growth rate and <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 12 of 17 consider requesting Vendor regrade data, performing any necessary additional digs, or refining reassessment interval. 17.5.1. A statistically valid representation of investigated anomalies must be present in order to determine undersize percentages. Outlying investigated features may be discounted. 17.5.2. For metal loss, 17.5.2.1. Add average undersize percentage of anomalies that were undersized to peak depth of uninvestigated metal loss anomalies in Projected Corrosion Growth spreadsheet. 17.5.2.2. Recalculate corrosion growth rate 17.5.2.3. 17.5.2.4. Recalculate PBURST and PSAFE to compare with PDPP If, within 6.2 years, an unrepaired metal loss feature is predicted to reach 80% peak depth (70% peak depth for Assets Covered Per Mitigation Plan) or if PBURST is predicted to be less than PDPP, it should be added to Dig List. 17.5.3. For ID reductions, 17.6 17.7 17.8 17.9 17.5.3.1. If the comparison indicates an average undersize of features, add average undersize percentage of all anomalies to depth of uninvestigated ID reductions 17.5.3.2. Compare new depth to repair criteria and add ID reductions meeting repair criteria to Dig List. Pipeline Integrity Engineer may consider a Probability of Exceedance (POE) analysis (required for Assets Covered Per Mitigation Plan) or other engineering analysis as an alternative means to assess tool tolerances in order to determine if additional direct examinations are required. 17.6.1. When direct examination activities result in a statistically significant sample size of observed defects, actual tool performance will be used. Otherwise, Vendor specified tolerance may be used. Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will summarize examination results from Pipeline Maintenance Report and NDE sheets and create a data correlation report. Significant discrepancies should be resolved by Vendor and by NDE contractor. Pipeline Integrity Engineer will provide completed data correlation report to Vendor. Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will notify Supervisor of Pipeline Integrity Engineering that data correlation, unity plots and projected corrosion growth are complete and that additional digs are/are not necessary. 18.0 DEFINITIONS 18.1 Terms and terminology will be used in accordance with API 1163 Section 4, unless otherwise specified herein. Additional definitions are as follows: 18.1.1. Seam Weld Feature A (SWFA): Seam weld indication that exhibits possible “crack‐ like” characteristics 18.1.2. Seam Weld Feature B (SWFB): Seam weld indication that exhibits some, but not all “crack‐like” characteristics 18.1.3. Seam Weld Metal Loss: SWML. Metal loss indication (including any part of a cluster) <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 13 of 17 18.1.4. 18.1.5. 18.1.6. 18.1.7. 18.1.8. 18.1.9. 18.1.10. that encroaches upon the longitudinal seam weld (LSW). Axial Seam Weld Metal Loss (ASWML): Metal loss indication (including any part of a cluster) that encroaches upon the LSW and is less than 2‐inches wide with a length‐ to‐width aspect ratio equal to or greater than 5:1 Seam Weld Deformation (SWD): Deformation that encroaches upon the LSW Seam Weld Anomaly (SWA): Feature other than a SWFA, SWFB, SWML, or SWD that encroaches upon or is immediately adjacent to the LSW and is thought to be non‐ injurious. PBURST: Estimated burst (failure) pressure for an anomaly as calculated according to a given standard or practice (e.g., RSTRENG™, ASME B31G, CorLAS™) PSAFE: PBURST multiplied by a design factor (e.g., 0.72) PDPP: Discrete point operating pressure at a given location Design Factor, F: from ASME B31.4, ASME B31.8, or ASME B31.11. For onshore hazardous liquid pipelines, F is typically equal to 0.72. For natural gas pipelines, F ranges from 0.40 to 0.72 depending on class location 19.0 REFERENCES 19.1 Regulatory 19.1.1. 49 CFR Part 195.452 19.2 Related Policies/Procedures 19.2.1. In‐Line Technical Specification 19.2.2. ILI Data Verification Guidelines 19.2.3. AGM Verification Guideline 19.2.4. 19.2.5. In‐Line Inspection Procedure Procedure for Creating Dig Sheets <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 14 of 17 System Integrity Plan Change Log Date Change Location Change By Approved By 11/08/04 All Clyde Clausen Mike Pearson 11/04/05 All Clyde Clausen Mike Pearson 10/30/2006 All Clyde Clausen Mike Pearson 10/30/2006 2.4.1.2 Mike Pearson Larry Franklin 10/30/2006 2.4.1.19 Dennis Vasicek Mike Pearson 10/30/2006 2.4.1.20 Mike Pearson Dennis Vasicek 10/30/2006 2.4.1.22 Mike Pearson Larry Franklin 10/30/2006 2.4.1 Mike Pearson Larry Franklin 10/30/2006 2.4 Mike Pearson Dennis Vasicek 10/30/2006 2.7.1 Mike Pearson Larry Franklin 10/30/2006 2.7.1 Larry Franklin Mike Pearson 10/30/2006 2.7.1.6 Mike Pearson Larry Franklin 10/30/2006 2.9.1 Mike Pearson Larry Franklin 10/30/2006 2.9.1 Mike Pearson Larry Franklin 10/30/2006 2.9.1.2 Larry Franklin Mike Pearson 10/30/2006 2.9.1 Larry Franklin Mike Pearson 10/30/2006 2.10.1.1 Mike Pearson Larry Franklin 10/31/2006 2.4.1.32.3.10 Larry Franklin Mike Pearson 10/31/2006 2.4.1.33 Larry Franklin Mike Pearson 10/31/2006 2.4.1.34 Larry Franklin Mike Pearson Brief Description of Change Created New Procedure Conducted Annual Review Conduct Annual Review Added Certification of Calibration and Street Atlas files Added “with metal loss” Added “If ILI vendor does not provide GPS Coordinates” Modified to reflect send email to Pipeline Integrity Data Coordinator Insert 2.4.1.24 Determine casings that require rehabilitation based on casing flowchart Insert 2.4.16 Compare proposed dig list to information from previous rehabilitation projects Insert 2.7.1.4 Process casings using ‘Casing Comparison’ spreadsheet Delete 2.7.1.5 Minor modification to paragraph, add link to Rehab book Checklist 2.9.1.1 Insert Receive ‘Casing Comparison’ from PIDC Minor modification to 2.9.1.2 to add ‘Casing Comparison’ comparison Delete 2.9.1.1.1 through 2.9.1.1.3 Insert 2.9.1.3 Added “if ILI vendor does not provide GPS coordinates” Insert 2.4.1.32.3.10 Insert 2.4.1.33 Insert 2.4.1.34 <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 15 of 17 01/01/08 7/10/08 2.2.1.5 Dennis Vasicek Clyde Clausen 7/10/08 2.2.1.6 Dennis Vasicek Clyde Clausen 7/10/08 2.2.1.7 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.2 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.4.2 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.12.1 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.12.4 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.12.5 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.12.6 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.18.1 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.21 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.22 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.30 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.31.3.8 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.31.3.10 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.31.4 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.32.1 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.32.2 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.32.3 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.32.4 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.32.6 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.33.1 Dennis Vasicek Clyde Clausen 7/10/08 2.4.13 Dennis Vasicek Clyde Clausen Reviewed, no changes Added paragraph and subparagraphs Added paragraph Added paragraph Added paragraph Added paragraph Changed 5 years to 6 years Added paragraph Added paragraph Added paragraph Changed 100% to 80% Deleted paragraph and sub‐paragraphs pertaining to sending email to GIS Coordinator to input GPS information for casings Deleted paragraph about receiving GPS coordinators for casings from GIS Coordinator Added sentence to clarify 60 and 180‐day dates for HCAs Added, “(as identified by the ILI vendor as being axially oriented)” Removed condition, “A girth weld anomaly as identified by ILI vendor” Added paragraph and subparagraphs Added sentence, “However, all HCA Immediate Conditions shall take priority.” Added paragraph and subparagraphs Added paragraph Added paragraph and subparagraphs Added paragraph and subparagraph Modified paragraph Modified paragraph and added subparagraphs <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 16 of 17 7/10/08 2.4.14.1 Dennis Vasicek Clyde Clausen 7/10/08 2.4.14.2 Dennis Vasicek Clyde Clausen 7/10/08 2.4.15 Dennis Vasicek Clyde Clausen 7/10/08 2.4.16 Dennis Vasicek Clyde Clausen 7/10/08 2.4.17 Dennis Vasicek Clyde Clausen 7/10/08 2.4.23 Dennis Vasicek Clyde Clausen 7/10/08 2.4.24 Dennis Vasicek Clyde Clausen 7/10/08 2.4.25 Dennis Vasicek Clyde Clausen 7/10/08 2.4.26 Dennis Vasicek Clyde Clausen 7/10/08 2.4.30 Dennis Vasicek Clyde Clausen 7/10/08 2.4.31 Dennis Vasicek Clyde Clausen 7/10/08 2.4.31 Dennis Vasicek Clyde Clausen 7/10/08 2.7.1.8 Dennis Vasicek Clyde Clausen 7/10/08 2.7.1.9 Dennis Vasicek Clyde Clausen 7/10/08 2.7.1.10 Dennis Vasicek Clyde Clausen 7/10/08 2.7.1.11 Dennis Vasicek Clyde Clausen 7/10/08 2.10 Dennis Vasicek Clyde Clausen 7/10/08 2.10 Dennis Vasicek Clyde Clausen Reworded paragraph Reworded paragraph Added paragraph Added paragraph and subparagraphs Modified paragraph Added paragraph Added paragraph Added paragraph Removed Area Facility Integrity Engineer and added Supervisor Corrosion Control Added paragraph Deleted paragraph about Post Job roundtable Added paragraph and sub‐paragraphs about calculating the average undersize of repaired anomalies Added paragraph Added paragraph Added paragraph Added paragraph Removed section containing “The GIS Coordinator shall:” Added section pertaining to “Pipeline Integrity Coordinator” and three subparagraphs 7/10/08 2.11 Dennis Vasicek Clyde Clausen 12/19/08 2.4.1.9.2 Dennis Vasicek Clyde Clausen 12/19/08 2.4.14.2 Dennis Vasicek Clyde Clausen Added section pertaining to “Supervisor Pipeline Integrity or Manager Pipeline Integrity” and four subparagraphs Removed reference to LAPA RPR’s Added reference to UT ILI 12/19/08 2.4.14.2.1 Dennis Vasicek Clyde Clausen 12/22/08 Global Dennis Vasicek Clyde Clausen Added, “and match girth welds between the reports” Changed “vendor” to “service provider” <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 17 of 17 12/22/08 2.4.1.31.4 Dennis Vasicek Clyde Clausen 12/22/08 2.4.1.32.6 Dennis Vasicek Clyde Clausen 12/22/08 Dennis Vasicek Clyde Clausen 3/4/09 All Dennis Vasicek Clyde Clausen 01/01/10 2.2.1.1 all All 2.4.1.8 (Old) 2.4.1.8 (new) 2.4.1.12.3 2.4.1.12.4 2.4.1.12.5/2.4.1.13/ 2.4.1.14/2.4.1.16 2.4.1.21 – 2.4.1.24 2.4.1.25‐2.4.1.30 60‐day repair cond/180 day/ Non HCAS 2.4.14.1 – 2.4.14.2.4 2.4.15/2.4.20‐2.4.22 01/01/11 9/1/11 All Clyde Clausen Doug Chabino 12/31/11 all 12/31/11 All 6/18/12 10.2.5 Clyde Clausen Doug Chabino Deleted section referencing expired Consent Decree (for acquired Shell assets) Deleted section referencing expired Consent Decree (for acquired Shell assets) Conducted annual review Added references to consent decree – not a significant change so version not updated Added “internal diameter” Changed Longhorn to Mitigation Plan General cleanup/updating to reflect current process Deleted: ref – Pipeline Listing ss Reworded DPP information Added “add to DPP ss. Added – create Run Comparison ss deleted Deleted Moved after dig list Dents at 4/8 o’clock changed to top‐side dents/ bottom side dents Deleted Deleted Reviewed, no changes Re‐worked and Re‐formatted entire document Replaced Rehab Book Checklist with Project File Index Form and AGM Calc Spreadsheet with Total AGMs Form 2012 Annual Review complete Added Laminations interacting with deformations to section 10.2.5 <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 18 of 17 <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL SIP–ADM–7.04 Asset Integrity 09/06/11 Revision: 7 Page 1 of 6 1.0 OBJECTIVE 1.1 The objective of this initiative is to maintain asset integrity by establishing a consistent and effective corrosion control process. 2.0 DESCRIPTION 2.1 This initiative outlines the standards and processes necessary to mitigate external and internal corrosion. These include, but are not limited to, the following: system evaluations; coating selection and application; criteria for cathodic protection; and cathodic protection system design, installation, operations and maintenance to mitigate external corrosion and cleaning, treating and monitoring the pipeline for the prevention of internal corrosion. 2.2 All of the standards are developed through sound corrosion engineering concepts and are applied under the direction of qualified personnel trained in the corrosion control field. Corrosion related data will be processed in the overall Risk Management process to determine/modify the frequency of future inspections, surveys and other corrosion mitigation measures or new developing technologies. 3.0 STANDARDS 3.1 The Manager of Asset Integrity shall: 3.1.1 Maintain the Corrosion Control Program for Company operated assets. 3.1.2 Coordinate the implementation, execution, and documentation of the work required by the Corrosion Control Program. 3.1.3 Monthly review corrosion control exceptions and associated remedial action plans. 3.2 The Corrosion Technician shall: 3.2.1 Execute and document the work required by the Corrosion Control Program including Pipe‐to‐Soil Potential Surveys, Close Interval Surveys, Atmospheric Corrosion Inspections, Insulating Flanges, Foreign Line Crossings, Rectifier Inspection Surveys, Bond Surveys, Remedial Actions, etc. 3.3 The Operations Supervisor shall: 3.3.1 Coordinate the execution of pipeline maintenance/cleaning pigging in accordance with the Corrosion Control Program. 3.3.2 Coordinate the inspection of additive/corrosion inhibitor pumps for proper operation and injection rate and ensure that prompt and proper repairs are made. Maintain corrosion inhibitor chemical inventories at proper levels. 3.3.3 Coordinate the collection and delivery of product samples to the Company’s laboratory for analysis in accordance with the Corrosion Control Program. 3.3.4 Coordinate the installation, removal, and replacement of internal corrosion coupons in accordance with the Corrosion Control Program. 3.4 The Supervisor of Laboratory Testing shall: <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL SIP–ADM–7.04 Asset Integrity 09/06/11 Revision: 7 Page 2 of 6 3.4.1 Distribute, collect, analyze, and document internal corrosion coupons in accordance with the Corrosion Control Program. 3.4.2 Analyze and document product samples per the Corrosion Control Program. 3.5 The Supervisor of Quality Control shall: 3.5.1 Notify the Corrosion Specialist when internal product quality tests identify free water, Haze Rating >3, or NACE Corrosion Rating 3, or NACE Rating >> Date 07/03/02 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 Magellan Midstream Partners, L.P. CORROSION CONTROL SIP–ADM–7.04 Asset Integrity 09/06/11 Revision: 7 Page 3 of 6 System Integrity Plan Change Log Change Location Changed By Approved By Brief Description of Change Rick 5.3 Wooldridg Michael Pearson Added Cathodic Protection Exception Report measure. e Modified 2.1 with the underlined language to address the addition of internal corrosion issues: This initiative outlines the Standards and processes necessary to mitigate external and internal corrosion. These include but are not limited Rick 2.1 Wooldridg Michael Pearson e to: system evaluations; coating selection and application; criteria for cathodic protection; and cathodic protection system design, installation, operations and maintenance to mitigate external corrosion and cleaning, treating and monitoring the pipeline for the prevention of internal corrosion. Initiative Name and 1.1 Rick Michael Pearson Deleted “External” from “External Corrosion Control” to broaden the SIP to include Internal Corrosion issues. Wooldridge Rick 3.1 Wooldridge Michael Pearson Changed “Supervisor of Pipeline Integrity” to “Manger of Asset Integrity” to address title changes. 3.1.1, 3.2.1, 3.2.2, and 5.1 Rick Wooldridge Michael Pearson Changed “External Corrosion Control Program” to “Corrosion Control Program” in order to include Internal Corrosion issues. Rick 3.1.1 Wooldridge Michael Pearson Removed “or exceed the” to not require compliance plus Rick 3.2.3 Wooldridge Michael Pearson Deleted entire paragraph as it will be addressed in 3.2.1, Produce an annual Atmospheric Corrosion Report…… Rick 3.2.2 Wooldridge Michael Pearson Replaced “Cathodic Protection” with “Corrosion Control” in order to address the addition of internal corrosion issues Rick 3.2.2 Wooldridge Michael Pearson Changed “Manager of Pipeline Integrity” to “Manager of Asset Integrity” to address title changes. Rick 3.2.2 Wooldridge Michael Pearson Remove “and/or shorted casings” since shorted casings are addressed during integrity assessments and not as stand alone corrosion exceptions. Rick 3.2.2 Wooldridge Michael Pearson Added “exposed pipe and interface areas requiring paint/coating and internal corrosion rates exceeding the established threshold” in order to include atmospheric and internal corrosion exceptions as part of the new Corrosion Control SIP. 3.4 Rick Michael Added: “The Manager of Operations Shall” from the <<>> 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 9/29/03 9/30/03 Magellan Midstream Partners, L.P. CORROSION CONTROL SIP–ADM–7.04 Asset Integrity 09/06/11 Revision: 7 Page 4 of 6 Wooldridge Pearson original Internal Corrosion Control SIP document. Rick 3.4.1 Wooldridge Michael Pearson Added: “Execute the maintenance/cleaning pigging program according to O&M Procedures”. Deleted: “and ensure that any batch treatments are completed within the system's program frequency guidelines. Complete pigging reports and submit to the Corrosion Technician” from the original Internal Corrosion Control SIP document. Rick 3.4.2 Wooldridge Michael Pearson Added: “3.4.2 Perform monthly inspection of Inspect additive corrosion inhibitor pumps for proper operation and injection rate monthly and assure ensure that prompt and proper repairs are made. Maintain corrosion inhibitor chemical inventories at proper levels. Deleted: “Assure that proper repairs are made or that the Corrosion Technician is contacted immediately. Complete the Chemical Injection Check list and submit copies to the Corrosion Technician and Corrosion Control Specialist” from the original Internal Corrosion Control SIP document since it is no longer applicable. Rick 3.4.3 Wooldridge Michael Pearson Added: “Collect samples associated with pigging runs and handle according to O&M Procedures” from the original Internal Corrosion Control SIP document. Replaced: “Internal Corrosion Control Program” with “O&M Procedures” to reflect MMP processes (as opposed to WMB Midstream). Rick 4.1 Wooldridge Michael Pearson Replaced: “Protection Exceptions” with “Corrosion Control Exceptions” to add clarity. Rick 4.2 Wooldridge Michael Pearson Deleted: “Atmospheric Corrosion Exceptions” as they are included in 4.1 Rick 4.3 Wooldridge Michael Pearson Added: “Pipeline releases related to corrosion” since eliminating it is the primary goal 5.2 Rick Wooldridge Michael Pearson Added: “O&M Maintenance/Cleaning Pigging Procedures” 5.3 Rick Wooldridge Michael Pearson Added: “O&M Product Sampling Procedures” Rick 3.2.1 Wooldridge Michael Pearson Added: “Coordinate the implementation, execution and documentation of the work required by the External Corrosion Control Program” in order to clarify the roles and responsibilities of the Supervisor. Rick 3.3.1 Wooldridge Michael Pearson Added: “Execute and document” to imply performance of work. 3.4.4 Rick Michael Added: “Install, remove, replace, and process internal <<>> 9/30/03 10/6/03 8/11/04 8/11/04 10/16/06 10/16/06 10/16/06 09/11/07 9/10/07 9/10/07 9/10/07 9/10/07 1/1/09 7/17/09 11/16/09 Magellan Midstream Partners, L.P. CORROSION CONTROL Asset Integrity 09/06/11 Wooldridge Pearson Rick 5.4 Wooldridge Michael Pearson Annual Review Michael Pearson Michael Pearson Rick 3.4 Wooldridge Michael Pearson Rick 3.5 Wooldridg Michael Pearson e Rick 3.5 Wooldridge Michael Pearson Rick 3.6 Wooldridge Michael Pearson Rick 3.6 Wooldridge Michael Pearson Rick ALL Wooldridge Michael Pearson Rick 3.1.3 Wooldridge Michael Pearson Rick 3.1 Wooldridge Michael Pearson Rick 3.2.1 Wooldridge Michael Pearson Rick 3.2.2 Wooldridge Michael Pearson All E7 Rick Wooldridge 3.5.2 Rick Wooldridge Larry Davied All E7 Rick Wooldridge SIP–ADM–7.04 Revision: 7 Page 5 of 6 corrosion coupons in accordance with O&M procedures.” Added: “O&M Internal Corrosion Coupon Procedures” Conduct annual review of the Corrosion Control SIP in accordance to 3.1.1 Changed “Manager” to “Supervisor” Conduct annual review of the Corrosion Control SIP in accordance to 3.1.1 Added responsibilities for the Supervisor Laboratory Testing Added responsibilities for the Corrosion Specialist Conducted 2006 annual review of the Corrosion Control SIP in accordance to 3.1.1 (see change log) Conducted 2007 annual review, (see change log) Replaced Produce an annual Corrosion Control Exception Report, along with associated Remedial Action Plan, and forward to the Director of Asset Integrity with Annually review corrosion control exceptions and associated remedial action plans. Added Manager deleted Supervisor Added “Remedial Actions” Deleted Conduct detailed analyses of all available Corrosion Control Program data within their area of responsibility. Provide a summary of findings, including associated recommendations for remedial action, to the Corrosion Specialist within 90 days following completion of the surveys. 2008 annual review complete – no changes Added: “product quality control reports (PQCR)” 2009 annual review complete – with minor clean‐up issues. <<>> 8/9/10 9/6/11 CORROSION CONTROL Asset Integrity All; 3.5, 3.6 E7 Rick 3.1.3 Wooldridge Magellan Midstream Partners, L.P. SIP–ADM–7.04 09/06/11 Revision: 7 Page 6 of 6 Rick Wooldridge 2010 annual review; Added 3.5 and 3.6 Responsibilities for the Supervisor of Quality Control and Program Consultant to further enhance notifications when off spec product is present in the pipeline…as required per the DOT advisory related to internal corrosion. Rick Wooldridge Changed annual to monthly to reflect actual practice <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 1 of 27 TABLE OF CONTENTS 1.0 SCOPE 2.0 EXTERNAL CORROSION CONTROL 2.1 External Coating 2.2 Cathodic Protection 2.3 Corrosion Control Criteria 2.4 IR Drop Consideration 2.5 New Construction 2.6 Cathodic Protection Surveys 2.7 Cathodic Protection Rectifiers 2.8 Foreign Crossings and Interference Currents 2.9 Electrical Isolation 2.10 Test Leads 2.11 Exposed Pipe Examination 2.12 Stress Corrosion Cracking Analysis 2.13 Microbiological Influenced Corrosion (MIC) 2.14 Induced AC Corrosion 3.0 ATMOSPHERIC CORROSION CONTROL 3.1 Inspection 3.2 Paint/Coating 4.0 INTERNAL CORROSION CONTROL 4.1 Introduction 4.2 Product Evaluation 4.3 Internal Corrosion Mitigation 4.4 Internal Corrosion Monitoring 4.5 Internal Examination <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 2 of 27 5.0 QUALIFICATION 5.1 Supervisor 5.2 Operator Qualification 6.0 CORROSION CONTROL RECORDS 7.0 INTEGRITY MANAGEMENT PLAN INTEGRATION 8.0 DEFICIENCIES IN CORROSION CONTROL <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 3 of 27 1.0 SCOPE 1.1 This program is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be used in whole or part on non‐jurisdictional assets as deemed appropriate. 1.2 Texas Specific: In addition to applicable Federal, State, and Local regulations, as well as, Magellan guidelines, process, or best practices, certain pipeline system assets in Texas operate under the requirements of the Mitigation Plan. 2.0 EXTERNAL CORROSION CONTROL 2.1 External Coating 195.557, 195.559, 195.561, 16 TAC 8.305(2‐3), 192.455(a)(1) and 192.461. 2.1.1 2.1.2 2.1.3 2.1.4 2.1.5 2.1.6 2.1.7 2.1.8 All buried or submerged newly constructed, relocated, replaced or otherwise changed steel lines shall be coated, including mainlines, terminal and station piping. The external coating shall be applied on a properly prepared surface and have sufficient adhesion to the metal surface to effectively resist underfilm migration of moisture. The coating shall be sufficiently ductile to resist cracking and have sufficient strength to resist damage due to handling and soil stress. The coating shall have properties compatible with the cathodic protection system. Electrically insulating type coatings shall have low moisture absorption and high electrical resistance. The coated pipe shall be electrically inspected using a coating deficiency (holiday) detector prior to installation. Any damage found that impairs the effectiveness of the coating shall be repaired. Furthermore, the coating shall be protected from damage resulting from adverse ditch conditions or damage from supporting blocks. Backfilling operations will be inspected to ensure that rocks, hard lumps of earth, etc. are not backfilled directly onto the pipe where they may damage the effectiveness of the pipeline coating. Precautions will be taken to minimize damage to the coating during installation if coated pipe is installed by boring, driving, or other similar method. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 4 of 27 2.2 2.1.9 Joints, fittings, and tie‐ins shall be coated with material(s) compatible with the coating(s) on the pipe. 2.1.10 Coatings selection, application, and maintenance shall be performed as prescribed in Coatings – Selection, Applications, and Maintenance. Cathodic Protection – 195.563, 195.565, 192.452, 192.453, 192.455 and 192.457 2.2.1 2.2.2 2.2.3 2.2.4 On facilities including newly constructed, relocated, replaced or otherwise changed pipelines, a cathodic protection system will be installed to mitigate corrosion. A cathodic protection system will be installed for breakout tanks to mitigate corrosion. The systems shall be installed in accordance with API Recommended Practice 651, unless noted in this volume why compliance with all or certain provisions of API Recommended Practice 651 is not necessary for the safety of the breakout tank. Noted conditions that will cause compliance with 651 to not be observed may be but are not limited to tanks set on concrete, asphalt pads, or where studies conducted in accordance with API 653 indicate that corrosion will not affect the safe operation of the tank. On facilities including newly constructed, relocated, replaced, or otherwise changed pipelines and tanks, a temporary cathodic system shall be provided as soon as practical during construction and a permanent cathodic protection system shall be provided within one year of completed construction. Refer to Design and Installation of an Impressed Current Deep Groundbed and Design and Installation of an Impressed Current Surface Groundbed for more 2.3 information. 2.2.5 Soil Resistivity may influence the design considerations for cathodic protection systems as well as development of the Relative Risk Score for the line segment. See Soil Resistivity Overview for a general description of expected soil resistivity identified by state. Corrosion Control Criteria 195.571, 192.463 2.3.1 Magellan adheres to the cathodic protection regulations in Part 195, “Transportation of Hazardous Liquids by Pipeline” and to the cathodic protection regulations in Part 192, “Transportation of Natural and Other Gas by ”pipeline: Minimum Federal Safety Standards,” of the DOT/Pipeline and Hazardous Materials Safety Administration Pipeline Safety Regulations. 2.3.2 When practical, Magellan requires maintaining a polarized potential of at least –0.850 volts as measured between the structure surface and a saturated <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 5 of 27 2.4 2.3.3 2.3.4 2.3.5 2.3.6 2.3.7 copper‐copper sulfate reference electrode that is in contact with the electrolyte (earth, soil, water, etc.). Where injurious aerobic bacteria has been identified, or is suspected, a polarized potential of ‐.950 volts or more negative is required. This voltage measurement shall be determined with the protective current applied and IR drop considered as described in paragraph 2.4 below. Assets covered by the Mitigation Plan: For Tier II and Tier III areas, where practical a polarized pipe‐to‐soil potential of ‐.850 volts will be maintained. During close interval surveys, potential drops other than those across the structure to electrolyte boundary will be considered by interrupting the cathodic protection current source(s) and recording the ON” and “OFF” pipe‐ to‐soil potentials Once established, the “ON” potential and “Off” potential will be utilized to correct future pipe‐to‐soil potential readings until such time as the system configuration or coating condition changes, or a new close interval survey is performed. When a ‐0.850 volt potential is not practical, the following criteria are acceptable when approved by the Supervisor of Corrosion Control: 2.3.4.1 A minimum negative (cathodic) polarization shift of 100 millivolts The 100‐millivolt polarization decay criteria specify a minimum negative (cathodic) polarization voltage shift of 100 millivolts, measured between the structure surface and a reference electrode contacting the electrolyte. Overprotection will be monitored and minimized through the analysis of data from annual pipe‐to‐soil surveys, close interval surveys, and pipeline visual inspections. A practical value of ‐1.2 volts (polarized) in reference to a copper/copper sulfate electrode will be used as value beyond which monitoring for overprotection shall be considered. Refer to Cathodic Protection Criteria for more information. IR Drop Consideration 195.571 and 192.463 (a) 2.4.1 IR drop is considered by taking potential readings directly over or as near as practical to the structure surface. The affect on the potential measuring circuit is kept to a minimum by using a high resistance voltmeter and being mindful of lead lengths and condition, contact to structure and contact to electrolyte. 2.4.2 Cathodic protection level should be evaluated utilizing Cathodic Protection Criteria. 2.5 New Construction 195.563 and 192.455(a)(2) <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 6 of 27 2.6 2.5.1 On newly constructed facilities and/or pipelines, a temporary cathodic system shall be provided as soon as practical during construction and a permanent cathodic protection system shall be provided within one year of completed construction. 2.5.2 Newly constructed facilities shall be included in and be managed in accordance with the Magellan System Integrity Plan within one year of completed construction. 2.5.3 On newly constructed facilities and/or pipelines, corrosion personnel, qualified under the Operator Qualification Ruling or with NACE Certification, shall be utilized to identify, mitigate, and monitor for inadequate cathodic protection and detrimental interference currents, prior to and during construction. Refer to Section 2.8, Foreign Crossings and Interference Currents and 2.14, Induced AC Corrosion below. Cathodic Protection Surveys 195.573 (a) (d) and 192.465 2.6.1 A cathodic protection survey shall be conducted on each buried, in contact with the ground, submerged pipeline facility, and/or breakout tank in its pipeline system that is under cathodic protection once each calendar year with intervals not to exceed fifteen months. Pertinent survey information shall be recorded in the Cathodic Protection Data Manager (CPDM) within 30 days after the survey. 2.6.2 Assets covered by the Mitigation Plan: Pipe‐to‐soil surveys shall be performed annually not to exceed 15 months in Tier I areas and semi‐annually not to exceed 7.5 months in Tier II and Tier III areas. Deficiencies will be resolved within one (1) year of discovery, except deficiencies of such a nature they present a more urgent threat to pipeline integrity, in which case corrections will be done immediately. 2.6.3 Pipe‐to‐soil readings shall be obtained at pre‐assigned locations identified as necessary to determine the adequacy of cathodic protection. These locations can include, but are not limited to, test stations, cased crossings, and above ground appurtenances. Refer to Measuring a Pipe‐to‐Soil Potential for more information. 2.6.4 For aboveground breakout tanks where corrosion of the tank bottom is controlled by a cathodic protection system, the cathodic protection system shall be inspected to ensure it is operated and maintained in accordance with API Recommended Practice 651, unless noted in this volume why compliance with all or certain provisions of API 651 is not necessary for the safety of a <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 7 of 27 2.6.5 2.6.6 particular breakout tank. Noted conditions that will cause compliance with 651 to not be observed may be but are not limited to tanks set on concrete, asphalt pads, or where studies conducted in accordance with API 653 indicate that corrosion will not affect the safe operation of the tank. Pertinent survey information shall be recorded in the Cathodic Protection Data Manager (CPDM) within 30 days after the survey. 2.6.4.1 Potential surveys taken on above‐ground storage tanks should be conducted with an adequate level in the tank to maximize the contact of the tank bottom with the cushion material. Adequate level is typically at least 3 feet of liquid. Tank levels shall be recorded along with potential measurements. Tanks with inadequate levels shall be re‐surveyed the same calendar year, once adequate levels are attained. Additional corrosion control surveys, including but not limited to close interval pipe‐to‐soil surveys, will be conducted where practical and determined necessary by sound engineering practices. Indicators of the necessity to conduct such surveys shall include risk assessments, annual pipe‐to‐soil surveys, internal inspection data, pipe inspection, or other related corrosion information or testing. At a minimum, close interval pipe‐to‐soil surveys will be considered under the following circumstances: 2.6.6.1 When identified through risk assessment including Section 6 analysis required by the Integrity Management Plan. 2.6.6.2 Assets covered by the Mitigation Plan: Close Interval surveys in Tier III areas will be conducted annually not to exceed 15 months. For Tier I and II areas close interval surveys will be managed through the Relative Risk Assessment Process within the System Integrity Model and conducted as necessary. Deficiencies will be resolved within one (1) year of discovery, except deficiencies of such a nature they present a more urgent threat to pipeline integrity, in which case corrections will be done immediately. 2.6.6.3 External Corrosion identified on the pipeline with a peak depth greater than 50% of the nominal wall, within 50 feet of a foreign pipeline crossing. Close interval survey may not be required if pipe‐ to‐soil data collected at the location indicates that cathodic protection interference is not a concern. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 8 of 27 2.6.6.4 2.6.6.5 2.6.6.6 Areas of inadequate cathodic protection as identified by pipe‐to‐soil surveys. Close interval survey may not be required if remediation of the low potentials includes the addition, modification, or adjustment of an impressed current cathodic protection that provides cathodic protection current beyond the area of inadequate potentials. Areas of interference from a foreign cathodic protection current source. Locations of potential interference include but are not limited to, construction of new cathodic protection systems near the pipeline, changes in current output from foreign cathodic protection systems, and a reduction in cathodic protection levels without a corresponding reduction in output from the existing cathodic protection system. In each case, the Close Interval Survey shall be conducted at spacing close enough to identify potential integrity threats and extend beyond the area of likely influence. Refer to Close Interval Pipe‐to‐ Soil Survey and Testing for Interference Currents and Remedial Measures for more information. 2.7 Cathodic Protection Rectifiers 195.573 (c) and 192.465 (b) 2.7.1 Each cathodic protection rectifier shall be inspected for proper operation at least six times each calendar year with intervals between inspections not to exceed 2 ½ months. Pertinent survey information shall be recorded in the Cathodic Protection Data Manager (CPDM) within 30 days after survey. Refer to Rectifier Inspection, Cathodic Protection System Troubleshooting (Groundbed), and Rectifier Troubleshooting for more information. 2.8 2.7.2 Assets covered by the Mitigation Plan: Each cathodic protection rectifier shall be inspected for proper operation at least twelve (12) times each calendar year with intervals between inspections not to exceed 45 days. Deficiencies will be resolved within one (1) month of discovery, except deficiencies of such a nature they present a more urgent threat to pipeline integrity, in which case corrections will be done immediately. Foreign Crossings and Interference Currents 195.573(c), 195.577, 16 TAC 7.86(5)(c), 192.465 (c) and 192.473 2.8.1 During each cathodic survey, a check of the integrity of each bond that exists across insulating flanges or other unions of pipeline facilities and each interference bond shall be made. Reverse current switches, diodes and <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 9 of 27 interference bonds whose failure would jeopardize structure protection shall be inspected six times each calendar year with intervals between inspections not to exceed 2 ½ months. Pertinent survey information shall be recorded in the Cathodic Protection Data Manager (CPDM) within 30 days after the survey. Refer to Electrical Bond Inspection for more information. 2.8.2 2.8.3 Impressed current cathodic protection systems or galvanic anode systems will be designed and installed to minimize any adverse effects on existing underground metallic structures. Stray current interference testing, including, but not limited to close interval pipe‐to‐soil surveys, will be conducted where practical and determined necessary by sound engineering practices. Indicators of the necessity to conduct such tests shall include annual pipe‐to‐soil surveys, internal inspection data, pipe inspection, or other related corrosion information or testing. Pertinent survey information shall be recorded on Magellan Foreign Line Interference Test Form. Refer to Testing for Interference Currents and Remedial Measures for more information. 2.9 2.8.4 Texas Intrastate Pipeline specific: Whenever suspected areas of interference are identified, testing will be conducted within 6 months to determine the extent of interference, and appropriate action will be taken. 2.8.5 For Interference Currents related to Induced AC refer to Section 2.14, Induced AC Corrosion below. Electrical Isolation 195.575 and 192.467 2.9.1 Each buried or submerged pipeline shall be electrically isolated from other underground metallic structures, unless the pipeline and the other structures are electrically interconnected and cathodically protected as a single unit. 2.9.2 One or more insulating devices shall be installed where electrical isolation of a portion of a pipeline is necessary to facilitate the application of corrosion control. 2.9.3 During each cathodic survey, a check of the integrity of insulating flanges or other unions of pipeline facilities shall be made if inadequate cathodic protection levels are found. 2.9.4 Shorted Casings 2.9.4.1 During each cathodic protection survey, readings may be taken at each cased crossing to detect any location where the carrier pipe may be shorted to the casing pipe. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 10 of 27 2.9.4.2 2.9.4.3 If the casing potential is greater than ‐.800 volts, the casing shall be tested to determine whether an electrolytic short to the carrier pipe is present. Corresponding classification data documenting the status of the casing shall be recorded in the Cathodic Protection Data Manager (CPDM). Refer to Shorted Casing Testing for more information. If the casing potential is within 100 millivolts of the pipeline potential, the casing shall be tested to determine whether a short to the carrier pipe is present. Corresponding classification data documenting the status of the casing shall be recorded in the Cathodic Protection Data Manager (CPDM). Refer to Shorted Casing Testing for more information. 2.9.4.4 Following internal inspection of a pipeline, the resulting smart pig data will be integrated with and compared to the casing information in the corrosion control database. Where the carrier pipe within the casing exhibits corrosion‐caused metal loss, a risk evaluation will be conducted and action will be taken to mitigate the corrosion if deemed necessary. NOTE: For line sections integrity tested by hydrostatic test, a risk evaluation will be conducted at each shorted casing and action taken to clear the short and/or mitigate the corrosion if deemed necessary. 2.9.4.5 2.9.4.6 Assets covered by the Mitigation Plan: If a shorted casing is verified, a plan of action shall be developed within three (3) months from the time of discovery. The practicality of clearing the short will be considered before any other measures are used. Action shall be taken to clear the short (a) in Tier I areas within six (6) months of development of the action plan; and (b) in Tier II and III areas within three (3) months of development of the action plan. If clearing the short is impractical, the location can be monitored for leaks, or the casing/pipe interstice may be filled with a high dielectric corrosion inhibiting material. If the casing is monitored using leak detection equipment, the test must be performed twice each calendar year not exceeding 7.5 months. If monitored using internal inspection (smart pig) equipment, the inspection must be made at intervals as determined in the Magellan, Integrity Management Plan. These alternative measures, or any other <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 11 of 27 2.10 measures approved by the Manager of Asset Integrity may be employed until it is practical to clear the short. 2.9.4.7 Assets covered by the Mitigation Plan: In the interim, from the time, a short is verified and action is taken to clear the short, the location will be inspected for corrosion or the casing /pipe interstice may be filled with a high dielectric corrosion inhibiting material. During any interval that a casing has been determined to be shorted, casing will be monitored. Tier I areas will be monitored twice per year at intervals not exceeding 7.5 months. Tier II and III areas will be monitored monthly at intervals not exceeding 6 weeks. 2.9.5 Insulating devices installed in areas where a combustible atmosphere is reasonable to foresee shall be installed with precautions to prevent arcing. 2.9.6 Pipelines in close proximity to electrical transmission tower footings, ground cables, or counterpoise, or in other areas where it is reasonable to foresee fault currents or an unusual risk of lightning, shall be protected against damage from fault currents or lightening and protective measures taken at insulating devices. Test Leads 195.567, 192.469 and 192.471 2.10.1 All cathodically protected pipelines and breakout tankage shall have a sufficient number of test stations or other locations for electrical measurement to determine the adequacy of the cathodic protection system. 2.10.2 For design purposes, test lead spacing on pipelines shall be approximately one mile. This spacing shall be affected by conditions along the pipeline. 2.10.3 Breakout tankage will be monitored at the four quadrants. 2.10.4 The test leads shall be connected directly to the structure by Thermit welding or other process, which prevents stress concentration on the pipe and is approved by the Supervisor of Pipeline Integrity. 2.10.5 Test leads shall be maintained so that electrical measurements can be obtained in order to ensure adequate protection. For locations where repair of the test station is impractical, and a reading is necessary to determine the adequacy of cathodic protecting, an insulated probe rod may be used to contact the pipe and obtain the reading. This measure may be utilized until which time the test lead is repaired. 2.10.6 During installation, test leads shall be installed with enough looping or slack to prevent the test leads from undue stress or breakage during backfilling. Test <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 12 of 27 leads installed in conduit shall be suitably insulated from the conduit. Refer to Attaching Cathodic Protection Test Leads for more information. 2.11 2.10.7 Bared test lead wire and bared metallic area at the point of connection to pipeline must be coated with an electrical insulation material compatible with the pipe coating and the insulation on the wire. Exposed Pipeline Examination 195.569 and 192.459 2.11.1 When any buried pipeline is exposed, either intentionally or unintentionally, the exposed portion shall be visually inspected for evidence of external corrosion. Refer to Examining and Documenting the Condition of an Underground Pipeline or Related Facility When Exposed for more information. 2.11.2 When external corrosion requiring remedial action is found, further investigation will be conducted, circumferentially and longitudinally beyond the exposed portion (by visual examination, indirect method, or both) to determine the extent of the corrosion in the vicinity of the exposed portion. Refer to Pipeline Defect Evaluation and Repair for more information. 2.11.3 If the extent of corrosion cannot be determined, plans and scheduling for further investigation or the use of an internal inspection device shall be developed based on the severity of the corrosion encountered. 2.11.4 If the exposed pipe is to remain exposed, proper pipeline markers shall be installed and the pipe shall be monitored for atmospheric corrosion in accordance with paragraph 3.1.1 below. 2.12 Stress Corrosion Cracking (SCC) 2.12.1 Basic SCC awareness information is available to operation and maintenance employees in Stress Corrosion Cracking Information. 2.12.2 The risks associated with SCC are identified and assessed per the Magellan Risk Assessment Methodology book, and include factors such as age of the 2.12.3 2.12.4 pipeline, coating type, operating stress level, proximity of pump stations and history of SCC. In the event that a pipeline system has experienced one or more confirmed incidents of SCC a systematic identification and examination of other potential locations of SCC will be conducted based upon the observations of conditions associated with the confirmed SCC incident. Areas of the pipeline identified as having high susceptibility to SCC, or any other locations identified for SCC investigation, will be investigated per Stress Corrosion Cracking Investigation. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 13 of 27 2.12.5 2.12.6 Pipe cutouts sent to a metallurgical lab for analysis will be investigated for SCC. Results of this analysis will be provided in a comprehensive report provided to Asset Integrity. SCC field examinations will be performed by a NDE Technician trained in the detection of SCC on buried pipelines and will be documented in the Pipeline Maintenance Report. 2.12.7 If SCC is determined to be present, a review of the pipeline as defined in Section 6 of the IMP will be conducted, to be followed by a re‐assessment interval recommendation per Section 7 of the IMP. 2.12.8 Annually, confirmed SCC occurrences will be reviewed to determine if changes to the SCC assessment criteria are necessary. 2.13 Microbiological Influenced Corrosion (MIC) 2.13.1 In the event that a pipeline system has experienced one or more confirmed discoveries of injurious MIC, or where accelerated corrosion from MIC is anticipated, a Bacteria Testing Protocol shall be established to evaluate future 2.13.2 2.13.3 integrity threats from MIC. The line specific protocol shall be utilized until such time that the threat from MIC has been assessed and appropriate mitigation actions have been taken. Testing for MIC shall be conducted in accordance with Bacteria Testing – Serial Dilution Method. 2.14 Induced AC Corrosion 195.577 192.473 2.14.1 AC potential surveys shall be conducted on each buried, in contact with the ground, submerged pipeline facility near high voltage power lines once each calendar year with intervals not to exceed fifteen months. Recording voltmeters should be considered in areas where high voltage transmission lines parallel the pipeline over long distances. Pertinent survey information shall be recorded in the Cathodic Protection Data Manager (CPDM) within 30 days after the survey. Refer to Testing for Induced AC and Remedial Measures for more information. 2.14.2 AC potentials greater than 5 volts will be evaluated to determine if additional testing or remedial actions are required. Refer to Testing for Induced AC and Remedial Measures for more information. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 14 of 27 2.14.3 Remedial actions are required where through testing or calculations, AC current discharge densities are found to be at or greater than 100 A/m2 or AC potentials are greater than 15 volts. Remedial action may be required where AC current discharge densities range from 20‐100 A/m2. Refer to Testing for Induced AC and Remedial Measures for more information. 3.0 ATMOSPHERIC CORROSION CONTROL 3.1 Inspection 195.581, 195.583, 192.479 and 192.481, and 16 TAC 8.305(1) 3.1.1 Facilities and/or pipelines, other than Breakout Tanks, shall be inspected at least once every three (3) calendar years with intervals not exceeding 39 months for onshore and at least once each calendar year, with intervals not exceeding 15 months, for offshore. Refer to Atmospheric Corrosion Inspections for more information. NOTE: Atmospheric corrosion inspections on exposed pipelines must be conducted visually. 3.1.2 Assets covered by the Mitigation Plan: Facilities and/or pipelines, other than Breakout Tanks, shall be inspected annually for atmospheric corrosion. Refer to Atmospheric Corrosion Inspections for more information. 3.1.3 Breakout Tanks shall be inspected at least once every five (5) years with intervals not exceeding 60 months. Refer to Atmospheric Corrosion Inspections for more information. 3.2 3.1.4 Assets covered by the Mitigation Plan: Corrective action for deficiencies found during atmospheric surveys shall be determined and completed as soon as practical. Deficiencies will be resolved within one (1) year of discovery, except deficiencies of such a nature they present a more urgent threat to pipeline integrity, in which case corrections will be done immediately. Coating 195.581, 195.583, 192.479 and 192.481 3.2.1 A suitable coating shall be applied to all new aboveground facilities to prevent atmospheric corrosion damage. Refer to Coatings – Selection, Applications, and Maintenance for more information. 3.2.2 A suitable coating shall be applied to all soil‐to‐air interface areas to prevent atmospheric and electrolytic corrosion damage. Refer to Coatings – Selection, Applications, and Maintenance for more information. 3.2.3 A suitable coating shall be applied to all aboveground facilities to prevent further atmospheric corrosion damage if, through the guidelines established <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 15 of 27 in the Atmospheric Inspection Procedure, a Rust Rating of 2‐G or worse is identified. Refer to Coatings – Selection, Applications, and Maintenance for more information. 3.2.4 The coating conditions on exposed assets shall be documented in the Atmospheric Corrosion database (CPDM). 4.0 INTERNAL CORROSION CONTROL 4.1 Introduction 195.579 and 192.477 4.1.1 The corrosive effects of pipeline cargoes (hazardous liquids or carbon dioxide) shall be investigated and if found to be corrosive, adequate steps shall be taken to mitigate internal corrosion. If steps are taken to mitigate corrosion, the effectiveness of the steps shall be monitored using corrosion coupons and/or other methods. 4.1.2 Circumstance or condition [such as those listed below] that could cause, promote, or increase the likelihood of internal corrosion should be promptly reviewed and internal corrosion mitigation plans implemented as appropriate. 4.1.2.1 Type of commodity 4.1.2.2 Flow rate 4.1.2.3 Velocity 4.1.2.4 Operating Pressure 4.1.2.5 Topography 4.1.2.6 Amount of foreign material and/or contaminants present in the pipeline and/or commodity stream such as sand, silt, water, or other materials that could cause or promote internal corrosion 4.1.2.7 Amount of sulfur, salts, acids, hydrogen sulfide, carbon dioxide or other corrosive material present and corrosive effect based upon partial pressures of material in the pipeline 4.1.2.8 Presence of microbes 4.1.2.9 Temperature 4.1.2.10 Pipe configuration, design, and material specifications <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 16 of 27 4.1.2.11 Operating conditions, including but not limited to, steady state conditions, slack line conditions, upset conditions in the pipeline system, and upset conditions in upstream facilities such as refineries or processing facilities 4.2 Product Evaluation 4.2.1 Crude Oil or natural gas containing water in the liquid phase, solids, and other corrosive constituents such as bacteria, H2S, CO2 and O2, are considered potentially corrosive. 4.2.2 Refined Petroleum Products are evaluated using NACE TM 0172‐2001, “Determining Corrosive Properties of Cargoes in Petroleum Product Pipelines”. Petroleum products are considered "corrosive" if they do not meet at least a "C" rating on this test. Assets covered by the Mitigation Plan have a target NACE rating of “A” 4.2.3 Natural Gas Liquids are evaluated using ASTM D 1838, "Standard Test Method for Copper Strip Corrosion by Liquefied Petroleum Gases.” Natural gas liquids are considered "corrosive" if they fail to meet the Number 1 classification on this test. 4.2.4 Free water in any product is potentially corrosive 4.2.4.1 Refer to Bacteria Testing – Serial Dilution Method for more information. 4.3 Internal Corrosion Mitigation 4.3.1 Adequate steps, including eliminating the possibility of free water, removing corrosive components, or injecting corrosion inhibitor will be taken whenever investigation of the corrosive effect of the product on the metal indicates it is necessary. 4.3.2 Cleaning pigs 4.3.2.1 procedures as required. 4.3.2.2 To reduce the potential for unnecessary shut downs and/or unmanageable product contamination, pipelines with no history of pigging or those with significant amounts of known debris should not be pigged until adequate precautions and/or contingency plans have been developed. Pipeline cleaning pigs should be utilized system wide on mainline piping. Refer to Perform Pigging Operations or location specific <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 17 of 27 4.3.2.3 4.3.2.4 4.3.2.5 4.3.2.6 4.3.2.7 4.3.2.8 The frequency for routine cleaning operations of mainline product piping should be 2 times per year, approximately every 6 months. The frequency for routine cleaning operations of mainline crude piping should be 26 times per year, approximately every two weeks. Frequencies of cleaning pig runs may be adjusted as necessary based upon product upsets and the analysis of results of previous cleaning pig runs. Cleaning of facility piping, pipelines without launching or receiving equipment, and/or other non‐piggable sections should be conducted as required on a case by case basis. Pipelines transporting NH3 do not require routine pigging, but should be cleaned if excessive debris is identified prior to In‐line inspection tool runs. Pipeline pigging or repigging operations should also be considered when excessive debris is identified in the pipeline, following transportation of a corrosive (off spec) product, in preparation for integrity testing with a in‐line inspection tool, following hydrostatic testing of a pipeline, etc. Although the presence of debris in the receiving scraper trap does not necessarily indicate the quantity of material removed from the pipeline, it should be taken into consideration when determining the frequency of the cleaning pig operations. The physical condition of the pigs should also be taken into consideration, as a badly worn pig may be the result of excessive pipeline debris. During normal cleaning operations, a combination cup and brush pig (1st pig) followed, as soon as practical, by a combination cup and disc pig (2nd pig) should be utilized. Where excessive debris and paraffin buildup is thought to exist, specialty pigs such as pin‐wheel, Pit Boss™, scraper/plow blade attachments, and magnetic cleaning pigs shall be utilized as necessary based upon sound engineering judgment. Significant separation between the multiple pigs is not required and separation by more than a few yards will actually decrease the effectiveness of the operation. Cleaning pigs should be maintained in accordance with the manufactures recommendations. Pigs worn beyond the manufactures recommend tolerance should not be used. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 18 of 27 4.3.2.9 If a pig is to be run in a line which has not been pigged in many years or in a line which is suspected to be un‐piggable, soft low density Polly Pigs should be utilized until confidence is achieved that normal cleaning pigs will successfully traverse the pipeline. Specialty pigs with tracking devices may also be warranted if there is concern that the pigs may become stuck in the pipeline. 4.3.2.10 Normal cleaning operations should be conducted at a continuous 3 ft/sec or less where practical. 4.3.2.11 Caution should be observed when pigging lines that start and stop. Debris may fall out in front of the pig causing the pig to become stuck. 4.3.3 Corrosion Inhibitor 4.3.3.1 When a corrosion inhibitor is used to mitigate internal corrosion, a sufficient quantity to protect the entire part of the system the inhibitor is designed to protect will be used. Initial inhibitor injection rates will be based on product characteristics of the product to be inhibited .For refined product systems a hydrocarbon soluble, water dispersible corrosion inhibitor shall be utilized (Smart Chemical SCSF260 or equivalent). For crude pipeline systems, a highly water dispersible/soluble blend of corrosion inhibitors shall be utilized (Smart Chemical SCCI865 or equivalent). 4.3.3.2 Assets covered by the Mitigation Plan: Inhibitors are required to control potential internal corrosion. NOTE: Whenever a corrosion inhibitor injection pump, internal coating, or other equipment to mitigate internal corrosion, is installed or removed a Pipeline Maintenance Report shall be completed. 4.3.4 When installing a tank bottom lining in an aboveground breakout tank, the lining shall be installed in accordance with API Recommended Practice 652 unless noted in this volume why compliance with all or certain provisions of API Recommended Practice 652 is not necessary for the safety of the tank. 4.4 Internal Corrosion Monitoring 4.4.1 When corrosion inhibitors are used to mitigate internal corrosion, coupons or other types of monitoring will be used to determine the effectiveness of the inhibitor and the potential extent of any corrosion. Refer to Coupon Handling and ER Probes for more information <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 19 of 27 NOTE: Whenever new coupon holding devices or ER Probes are installed, a Pipeline Maintenance Report shall be completed. 4.4.2 4.4.3 4.4.4 At least twice each calendar year, and not exceeding intervals of 7 ½ months, corrosion coupons shall be removed from the test locations and forwarded to an appropriate laboratory for corrosion analysis (Reference NACE RPO775 for more information). Assets covered by the Mitigation Plan: At least three times each calendar year, and not exceeding intervals of 4.5 months, corrosion coupons shall be removed from the test locations and forwarded to an appropriate laboratory for corrosion analysis. New corrosion coupons will be installed at this time. Any alternate or supporting corrosion monitoring methods will be accomplished at the same minimum frequency. Pertinent monitoring data shall be documented in the Internal Corrosion Database and/or the appropriate inspection forms. Refer to Coupon Handling and ER Probes for more information. NOTE: There may be instances in which a product is not corrosive, and therefore not inhibited. Corrosion coupons may be used to periodically evaluate these products. In these instances, coupon monitoring may be less frequent than twice per calendar year and 7 ½ month intervals. 4.4.5 4.4.6 4.4.7 Effectiveness of inhibitor will be based on the inhibitor’s success in reducing the internal corrosion rate to an acceptable level. This level of acceptability may be different for each pipeline, but is typically <1 MPY for refined products and <3 MPY for crude. General corrosion rates can be classified as Low<1 mpy, Moderate 1.0 – 4.9 mpy. Sever >10 mpy. Internal corrosion rates greater than >1 MPY (refined products) or >3 MPY (crude) on inhibited pipelines shall be followed up with a detailed analysis regarding injection rates, hydro‐tests, or other unusual activities or circumstances. Action plans shall be developed if deemed necessary using sound engineering judgment. Assets covered by the Mitigation Plan: Coupon corrosion rates over 1 mpy of general corrosion or pitting (including MIC) will trigger a detailed analysis directed by NACE certified corrosion control personnel. This analysis will include a review of incoming product quality sample data, inhibitor injection rates, bacteria testing and, if necessary, inhibitor performance testing. Deficiencies will be resolved within six (6) months of discovery, except <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 20 of 27 4.5 4.4.8 4.4.9 deficiencies of such a nature they present a more urgent threat to pipeline integrity, in which case corrections will be done immediately. For crude pipeline systems, water sample traps will be mounted on the bottom of the pipe to facilitate the collection and analysis of free water. These locations will be inspected for water monthly and if a sufficient amount of water is present (typically >1 pint) this water shall be analyzed for bacteria, pH, iron, manganese, chlorides, and inhibitor residual (Reference API RP‐45, NACE TM0194, NACE RP0192, and ASTM D2327 for more information). Bacteria counts in excess of 10‐100 colonies/ml., pH readings outside a range of 4‐8, inhibitor residual less than ~10ppm, or an increase in iron, manganese, or chlorides could indicate an increase threat to internal corrosion. Water and debris brought into receiving traps during pigging operations will be tested to determine its potential to cause internal corrosion if determined to be necessary after consultation with the Corrosion Specialist. Crude assets covered by the Mitigation Plan: Coupon/water sample collection points will be located in facilities at origination points, along the pipeline system, and end points. Locations chosen for initial sampling points include Ft. McKavett, Cedar Valley, Satsuma, and East Houston. Additional coupon/water sample collection points may be installed as determined necessary through hazard analysis. Internal Examination 195.579(c) and 192.475 (b) 4.5.1 Whenever any pipe is removed from the pipeline for any reason, the internal surface shall be inspected for evidence of corrosion. Refer to Examining and Documenting the Condition of an Underground Pipeline or Related Facility When Exposed for more information. 4.5.2 4.5.3 4.5.4 When corrosion requiring remedial action is found, further investigation will be conducted both circumferentially and longitudinally (by visual examination, indirect method, or both) to determine the extent of the corrosion. Remedial actions will follow if necessary. Refer to Pipeline Defect Evaluation and Repair for more information. If the extent of corrosion cannot be determined, plans and scheduling for further investigation or the use of an internal inspection device shall be developed based on the severity of the corrosion encountered. The internal condition of the pipelines shall be documented on the Pipeline Maintenance Report. 5.0 QUALIFICATION <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 21 of 27 5.1 Supervisor Qualification 195.555 and 192.453 5.1.1 Magellan Asset Integrity Supervisors shall be knowledgeable of Magellan corrosion control procedures, including but not limited to those for design, installation, operation, and maintenance of internal and external corrosion control systems. 5.1.2 Supervisors may be registered professional engineers, or persons recognized as corrosion specialists or cathodic protection specialists by NACE, and/or their professional activities include suitable experience in corrosion control. 5.2 Operator Qualification 5.2.1 Operator Qualification (OQ) is required for personnel to perform identified Covered Tasks. Refer to Operator Qualification (OQ) – Covered Tasks for more information. 5.2.2 Assets covered by the Mitigation Plan: All Corrosion related activities shall be applied under the direction of competent personnel trained in the field of corrosion control. Corrosion control data shall be reviewed by NACE certified corrosion personnel. 6.0 CORROSION CONTROL RECORDS 195.404 and 192.491 6.1 Records or maps shall be maintained to show the location of: 6.1.1 Cathodically protected pipelines 6.1.2 Cathodic protection facilities, including galvanic anodes, installed after January 28, 2002 6.1.3 Neighboring structures bonded to cathodic protection systems. 6.2 Records or maps shall be maintained showing a stated number of anodes, installed in a stated manner or spacing. Specific distances to each buried anode need not be shown. 6.3 Records shall be maintained of each analysis including root cause analysis, check, demonstration, examination, inspection, investigation, review, survey, and test required in sufficient detail to demonstrate the adequacy of corrosion control measures or that corrosion requiring control measures does not exist. These records shall be maintained for a minimum of 5 years. 6.4 All pipe to soil survey, rectifier inspection, and foreign line crossing pipe to soil potential data will be recorded in the appropriate corrosion control database. All close interval pipe to soil potential data will be recorded in a hard copy report as well as the appropriate electronic format, atmospheric inspection data and exposes pipe visual inspection data will be documented on the appropriate forms and distributed <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 22 of 27 appropriately, and will feed into and be processed in overall LPSIP by populating appropriate portions of the relative risk model. 6.5 As long as the pipeline remains in service, records shall be maintained for: 6.5.1 Exposed portions of buried pipelines 6.5.2 Cathodic protection surveys, including close interval or comparable surveys 6.5.3 Internal corrosion coupon examination records and records of internal examination of removed pipe 7.0 INTEGRITY MANAGEMENT PLAN INTEGRATION 7.1 In accordance with the Integrity Management Plan, the Pipeline Risk Engineer will conduct integrated analysis with the External Corrosion Control Program Manager and/or SMEs to ensure effective integration of data, recommendations, and/or program enhancements identified during risk assessments and analysis. 7.2 Recommendations or process changes identified by the External Corrosion Control Program Manager and/or SMEs as a result of the integrated analysis will be communicated to and discussed with Pipeline Risk Engineer in accordance with the Magellan IMP. 7.3 Mitigation measures or process changes conducted by the External Corrosion Control Program Manager and/or SMEs as a result of the integrated analysis will be communicated to and discussed with Pipeline Risk Engineer in accordance with the Magellan IMP. 7.4 Whenever a line is added or removed from the Corrosion Control Program or elements of the Corrosion Control Program (i.e. External, Internal, Atmospheric), the Pipeline Risk Analyst shall be notified in order to update the Risk Assessment Model. All pipelines included in the Corrosion Control Program shall be maintained in accordance with the program guidelines and criteria. Corrosion Control records or data from new construction or pipeline acquisition activities shall be entered into the Corrosion Control database within one year. Pipelines not included in the program are not maintained in accordance with the program and as such, corrosion can be expected. See Inactive Pipelines and Abandoning Pipeline Segments for more details. 8.0 DEFICIENCIES IN CORROSION CONTROL 8.1 Deficiencies in Corrosion Control shall be corrected in a reasonable time. 8.1.1 Unless otherwise specified in this program, a reasonable time to correct deficiencies is defined as by the next scheduled inspection. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 23 of 27 8.1.2 8.1.3 In the case where deficiencies cannot be complete by the next scheduled inspection; planning, scheduling, progress, assessment, testing, monitoring, and/or other process that demonstrates that the threat in being addressed in a prudent and practical manner may be utilized until such time the deficiency has been resolved. A cause analysis will be performed to identify contributing factors and root causes of anomalies/deficiencies identify by corrosion control surveys. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 24 of 27 System Integrity Plan Change Log Date Change Location Changed By Approved By Brief Description of Change 1.1, 1.2 Rick Wooldridge Michael Pearson Revised regulation number 192.461 to 192.452. 1.1.1 Rick Wooldridge Michael Pearson 10/08/02 Replaced “newly buried” with “jurisdictional, newly constructed, relocated, replaced or otherwise changed.” 1.2.1 Rick Wooldridge Michael Pearson Added: “including newly constructed, relocated, replaced or otherwise changed pipelines.” 1.6.1 Rick Wooldridge Michael Pearson 11/20/02 Added “Pertinent survey information shall be recorded in the Cathodic Protection Data Manager (CPDM) within 30 days after the survey.” 1.6.3, 1.71, 1.81 Rick Wooldridge Michael Pearson Added: “within 30 days after the survey.” 1.9.4.2 Rick Wooldridge Michael Pearson Removed wording related to “metallic” or “electrolytic” type of short. 1.9.4.3 Rick Wooldridge Michael Pearson Added wording related to specific requirements for 192 05/06/03 1.10.3 Rick Wooldridge Michael Pearson Removed references to “permanent reference cells.” 2.1.2 Rick Wooldridge Michael Pearson Changed “39” months to “36” months to align with 192 regulations. 05/16/03 5.0 Rick Wooldridge Michael Pearson Added 5.0, Integrity Management Plan Integration. 6/13/03 2.1.3 Rick Wooldridge Michael Pearson Added 2.1.3 Breakout Tanks shall be inspected……….. 10/1/03 1.2.1, 1.6.1 Rick Wooldridge Michael Pearson Changed “Manager of Pipeline Integrity” to “Manager of Asset Integrity to reflect title changes. 10/1/03 2.1.1 Rick Wooldridge Michael Pearson Deleted entire paragraph “On Jurisdictional facilities each pipeline that is exposed…” The criteria for coating are depicted in the new 2.13. 10/1/03 2.1.3 Rick Wooldridge Michael Pearson Added, “A suitable coating shall be applied to all soil‐to‐air interface areas to prevent atmospheric and electrolytic corrosion damage. Refer to Coatings – Selection, Applications and Maintenance.” in order to clarify the coating criteria. Added, “A suitable coating shall be applied to all aboveground facilities to prevent further atmospheric corrosion damage if, through the guidelines established in the Atmospheric Inspection Procedure, a Rust Rating of 2‐G or worse is identified. Refer to Coatings – Selection, Applications and Maintenance.” in order to clarify the coating criteria. 10/1/03 4.1.1 Rick Wooldridge Michael Pearson Changed “Williams Pipeline Integrity Supervisors” to “Magellan Asset Integrity Supervisors” in order to reflect changes in title. Inserted: Internal Corrosion Program 10/1/03 3.0 Rick Wooldridge Michael Pearson 10/1/03 6.1, 6.2, 6.3 Rick Wooldridge Michael Pearson Changed “risk engineer” to “Pipeline Risk Engineer” in order to reflect changes in title and clarify implied responsibilities (i.e. pipeline vs facility) 11/30/03 1.2.3 Rick Wooldridge Michael Pearson Added, “On jurisdictional facilities…cathodic protection system shall be provided within one year of completed construction”. 11/30/03 1.5.2 Rick Wooldridge Michael Pearson Added, “Newly constructed facilities shall be included in and be managed in accordance with the Magellan System Integrity Plan…. 11/30/03 2.5.3 Rick Wooldridge Michael Pearson Added, “On newly constructed facilities, corrosion personnel, qualified under the Operator Qualification Ruling or with <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 25 of 27 NACE Certification, shall be utilized to identify, mitigate, and monitor for inadequate cathodic protection and detrimental interference currents, prior to and during construction. Refer to Section 1.8, Foreign Crossings and Interference Currents below.” 11/30/03 1.6.5 Rick Wooldridge Michael Pearson Added entire section related to CIS 11/30/03 1.11.4 Rick Wooldridge Michael Pearson Deleted, “The external condition of the pipelines shall be reported on Form 02‐LEG‐1035 – Encroachment Agreement (Short Form), Form 02‐OPR‐1581 – Maintenance Report, or equivalent form.” 12/1/03 1.0 Rick Wooldridge Michael Pearson Added Index and renumbered 12/1/03 9.0 Rick Wooldridge Michael Pearson Added Definitions 12/1/03 8.0 Rick Wooldridge Michael Pearson Added References 12/1/03 8.2 Rick Wooldridge Michael Pearson Deleted, “DETERMINING CORROSIVE PROPERTIES OF CARGOES IN PETROLEUM PRODUCTS PIPELINES” 12/1/03 8.2 Rick Wooldridge Michael Pearson Deleted, “Refer to Copper Strip Corrosion by Liquefied Petroleum (LP) Gases.” 12/1/03 8.2 Rick Wooldridge Michael Pearson Deleted, “and Field Gas Analysis For CO2, H2S, O2 and Dew Point.” 12/1/03 8.2 Rick Wooldridge Michael Pearson Deleted, “NOTE: Corrosivity of liquid products (refined petroleum products and natural gas liquids) is rarely evaluated 12/1/03 8.2 Rick Wooldridge Michael Pearson Deleted, “Corrosive gas shall not be transported by pipeline, ……considered to be potentially corrosive.” 12/1/03 4.6 Rick Wooldridge Michael Pearson Rewrite to be consistent with External Examination 3/23/04 4.4.2 Rick Wooldridge Michael Pearson Added: Effectiveness of inhibitor will be based on the inhibitors success.. typically <1 MPY for refined products. 3/23/04 4.4.3 Rick Wooldridge Michael Pearson Added: Internal corrosion rates greater than >1 MPY on inhibited pipelines…..engineering judgment. 6/5/2004 3.1.1 Rick Wooldridge Michael Pearson Note: Atmospheric corrosion inspections on exposed pipelines may be conducted visually or through the use of an in-line inspection device capable of identifying and sizing corrosion. 11/5/2004 2.2.2, 2.6.3 Rick Wooldridge Michael Pearson Modified for clarification: Noted conditions that will cause compliance with 651 to not be observed may be but are not limited to tanks set on concrete, asphalt pads or where studies conducted in accordance with API 653 indicate that corrosion will not affect the safe operation of the tank. 11/30/2004 2.9.4.1 Rick Wooldridge Michael Pearson Replaced “shall” with “may” for 195 lines and added the 192 language. 1/3/05 3.3.1 Rick Wooldridge Michael Pearson Deleted: Operate Auto-Injection Pumps, Added: Internal Corrosion Remediation 1/3/05 3.4.4 Rick Wooldridge Michael Pearson Replaced reference to OJT with “Refer to Coupon Handling and ER Probes” for more information. 1/3/05 3.4.4 Rick Wooldridge Michael Pearson Reviewed the procedure for accuracy and effectiveness. 4/7/05 Overall Rick Wooldridge Michael Pearson Minor modification and editorials added to provide clarification…no process changes. 5/16/05 1.9.4.3 Rick Wooldridge Michael Pearson Added: “Note: For line sections integrity tested by hydrostatic test a risk evaluation will be conducted at each shorted casing and action taken to clear the short and/or mitigate the corrosion if deemed necessary.” 7/6/05 1.12 Rick Wooldridge Michael Pearson Added: Basic SCC awareness information is available to operation and maintenance employees in Stress <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 26 of 27 Corrosion Cracking Information. 7/6/05 1.12 Rick Wooldridge Michael Pearson Added: In the event that a pipeline system has experienced one or more confirmed incidents of SCC a systematic identification and examination of other potential locations of SCC will be conducted based upon the observations of conditions associated with the confirmed SCC incident. 7/6/05 1.12 Rick Wooldridge Michael Pearson Added: or any other locations identified for SCC investigation, 7/6/05 1.12 Rick Wooldridge Michael Pearson Added: Pipe cutouts sent to a metallurgical lab for analysis will be investigated for SCC. Results of this analysis will be provided in a comprehensive report provided to Asset Integrity. Added: SCC examinations will be performed by a NDE Technician trained in the detection of SCC on buried pipelines and will be documented in the Pipeline Maintenance Report. 7/6/05 1.12 Rick Wooldridge Michael Pearson Added: Annually, confirmed SCC occurrences will be reviewed to determine if changes to the SCC assessment criteria are necessary. 8/1/05 1.12 Rick Wooldridge Michael Pearson No confirmed SCC occurrences to review. 11/7/05 All Rick Wooldridge Michael Pearson Added LPP Mitigation and Shell CD requirements. 11/7/05 3.3.2 Rick Wooldridge Michael Pearson Added cleaning pig requirements. 12/14/05 3.5.2 Rick Wooldridge Michael Pearson Added “circumferentially and longitudinally” 1/4/06 1.13, 7.13 Rick Wooldridge Michael Pearson Added MIC related information to the program. 03/06/06 2.9.4.3 Rick Wooldridge Michael Pearson Deleted “clear the short and/or” mitigate the corrosion … 4/6/2006 3.2.1 Rick Wooldridge Michael Pearson Added: Refer to Coatings – Selection, Applications, and Maintenance for more information. 4/6/2006 2.13.1 Rick Wooldridge Michael Pearson Replaced “incidents” with “discoveries” and added “injurious”. 4/6/2006 4.4.1 Rick Wooldridge Michael Pearson Replaced “Internal Corrosion Remediation” with “Auto Injection Pumps”. 9/8/2006 8.0, 10.0 Rick Wooldridge Michael Pearson Section 8 ‐ Deficiencies in Corrosion Control was added and references to “as soon as practical” were removed from the document. Section 10 – Definitions was update to include “reasonable time”. 9/8/2006 ALL Rick Wooldridge Michael Pearson Reviewed entire document…minor editorial changes, no process changes. 10/26/2006 2.3.4.2, 2.3.6 Rick Wooldridge Michael Pearson Removed references to Net Protective current criteria 11/30/06 TOC Rick Wooldridge Michael Pearson Added 2.14 ‐ AC Corrosion 11/30/06 2.5.3 Rick Wooldridge Michael Pearson Changed “Section 1.8 to 2.8 “and added “2.14, Induced AC Corrosion” in the last sentence. 11/30/06 2.8.4 Rick Wooldridge Michael Pearson Added Section 2.8.4 “For interference currents related to AC.........” 11/30/06 2.14 Rick Wooldridge Michael Pearson Added new Section – “2.14 Induced AC Corrosion” and subsections 2.14.1, 2.14.2 and 2.14.3 11/30/06 9.1 Rick Wooldridge Michael Pearson Added link to “Testing for Induced AC and Remedial Measures in Related Policies/Procedures 11/30/06 10 Rick Wooldridge Michael Pearson Added the definition for Induced AC Corrosion to Section 10 – Definitions 11/30/06 Deleted 12/7/09 3.2.4 Rick Wooldridge Michael Pearson Added: Longhorn Specific: A suitable coating shall be applied to all aboveground facilities and soil‐to‐air interface areas to prevent corrosion damage. All areas with signs of coating degradation and/or corrosion shall be coated/recoated. Refer <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 27 of 27 to Coatings – Selection, Applications and Maintenance for more information. 4/25/07 2.1 David Stewart Michael Pearson Added 16 TAC 7.86(3) to regulation references. 4/25/07 2.1.6 David Stewart Michael Pearson Added “…using a coating deficiency (holiday) detector…” 4/25/07 2.1.9 David Stewart Michael Pearson Added new paragraph, “Joints, fittings, and tie‐ins shall be coated with material(s) compatible with the coating(s) on the pipe.” Old 2.1.9 reference to Coatings – Selection, Applications, and Maintenance becomes 2.1.10. 4/25/07 2.8 David Stewart Michael Pearson Added 16 TAC 7.86(5)(c) to regulation references. 4/25/07 2.8.4 David Stewart Michael Pearson Added new paragraph, “Texas Intrastate Pipeline specific: Whenever suspected areas of interference are identified, testing will be conducted within 6 months to determine the extent of interference, and appropriate action will be taken.” Old 2.8.4 reference to AC testing becomes 2.8.5. 1/1/08 4.2.2 David Stewart Rick Wooldridge Added natural gas 1/15/08 2.6.4.1 David Stewart Rick Wooldridge Added paragraph requiring adequate levels in AST’s when taking potential readings, as well as requirement to document the tank levels. 2/15/08 2.3.2 Rick Wooldridge Larry Davied Added: “Where injurious aerobic bacteria has been identified, or is suspected, a polarized potential of ‐.950 volts or more negative is required.” 2/20/08 All E7 Rick Wooldridge 2007 annual review 9/08/08 3.1.1 Rick Wooldridge Larry Davied Removed the note “or through the use of an in‐line inspection device capable of identifying and sizing corrosion…at the request of PHMSA 09/25/08 1.3 Rick Wooldridge Larry Davied Remove references to Shell’s Consent Decree 09/25/08 All E7 Rick Wooldridge 2008 annual review, no changes 11/06/08 4.3.2.3 Rick Wooldridge Larry Davied Pipelines transporting NH3 do not require routine pigging, but should be cleaning if excessive debris is identified and/or prior to In‐line inspection tool runs. 11/16/09 All E7 Rick Wooldridge 2009 annual review; Removed references to Longhorn 12/07/09 4.1.1 E7 Rick Wooldridge Removed…Pipeline cargoes shall be periodically evaluated for corrosivity. Added: The corrosive effects of pipeline cargoes (hazardous liquids or carbon dioxide) shall be investigated. 12/07/09 4.1.2 E7 Rick Wooldridge Added: Circumstance or condition [such as those listed below] that could cause, promote, or increase the likelihood of internal corrosion should be promptly reviewed and internal corrosion mitigation plans implemented as appropriate. 12/07/09 4.1.2.1 thru 4.1.2.11 E7 Rick Wooldridge Added: 4.1.2.1 Type of commodity, 4.1.2.2 Flow rate, 4.1.2.3 Velocity, 4.1.2.4 Operating Pressure, 4.1.2.5 Topography, 4.1.2.6 Amount of foreign material and/or contaminants present in the pipeline and/or commodity stream such as sand, silt, water, or other materials that could cause or promote internal corrosion, 4.1.2.7 Amount of sulfur, salts, acids, hydrogen sulfide, carbon dioxide or other corrosive material present and corrosive effect based upon partial pressures of material in the pipeline 4.1.2.8 Presence of microbes, 4.1.2.9 Temperature, 4.1.2.10 Pipe configuration, design, and material specifications, 4.1.2.11 Operating conditions, including but not limited to, steady <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 28 of 27 state conditions, slack line conditions, upset conditions in the pipeline system, and upset conditions in upstream facilities such as refineries or processing facilities 03/03/10 10 E7 Rick Wooldridge Deleted “Definitions” 03/03/10 8.1.3 Jimmy Puckett Rick Wooldridge Information added to provide a single specific location that addresses LMP requirements…cause analysis will be performed to identify contributing factors and root causes of anomalies/deficiencies identify by corrosion control surveys. 03/03/10 6.4 Jimmy Puckett Rick Wooldridge Information added to provide a single specific location that addresses LMP requirements…All pipe to soil survey, rectifier inspection, and foreign line crossing pipe to soil potential data will be recorded in the appropriate corrosion control database. All close interval pipe to soil potential data will be recorded in a hard copy report as well as the appropriate electronic format, atmospheric inspection data and exposes pipe visual inspection data will be documented on the appropriate forms and distributed appropriately, and will feed into and be processed in overall LPSIP by populating appropriate portions of the relative risk model. 3/25/10 6.3 DOT Rick Wooldridge Modified: Records shall be maintained of each root cause analysis...to read Records shall be maintained for each analysis including root cause analysis. 8/9/10 2.3.4 E7 – Ken Lybarger Rick Wooldridge Changed Supervisor of Asset Integrity to Supervisor of Corrosion Control 8/9/10 2.10.4 E7 – Ken Lybarger Rick Wooldridge Changed Supervisor of Asset Integrity to Supervisor of Pipeline Integrity to maintain consistency with pipeline welding procedures. 2010 annual review; 2.4.2 was simplified to say, “Cathodic protection level should be evaluated utilizing Cathodic 08/09/10 All E7 Rick Wooldridge Protection Criteria.”. This change was necessary to improve/clarify the process for IR drop consideration. Deleted: “4.2.1 Products entering the system shall be sampled in accordance with D 4057‐95 (2000) ‐ Standard Practice for Manual Sampling of Petroleum and Petroleum Products, D 5842‐95 (2000) ‐Standard Practice for Sampling and Handling of Fuels for Volatility Measurement, and D 4177‐95 (2000) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products”. This change removes unnecessary and likely incomplete information. 10/10/11 4.3.2.3 Rick Wooldridge Doug Chabino 2011 Annual Review; Added: The frequency for routine cleaning operations of mainline crude piping should be 26 times per year, approximately every two weeks. Frequencies of cleaning pig runs may be adjusted as necessary based upon product upsets and the analysis of results of previous cleaning pig runs. 12/31/11 All 2012 Annual Review complete 2/16/12 4.3.2.3 Rick Wooldridge Doug Chabino Added clarification to facility piping 5/15/12 2.9.4.4 Rick Wooldridge Doug Chabino Added section to require testing for electrolytic shorted casings 5/15/12 2.9.4 Rick Wooldridge Doug Chabino Removed references to 192 (Gas) assets 5/15/12 4.3.2.6 Rick Wooldridge Doug Chabino Added: Where excessive debris and paraffin buildup is thought to exist, specialty pigs such as pin‐wheel, Pit Boss™, <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 29 of 27 scraper/plow blade attachments, and magnetic cleaning pigs shall be utilized as necessary based upon sound engineering judgment. 5/15/12 4.3.3.1 Rick Wooldridge Doug Chabino Added: For refined product systems a hydrocarbon soluble, water dispersible corrosion inhibitor shall be utilized (Smart Chemical SCSF260 or equivalent). For crude pipeline systems, a highly water dispersible/soluble blend of corrosion inhibitors shall be utilized (Smart Chemical SCCI865 or equivalent). 5/15/12 4.4.5 Rick Wooldridge Doug Chabino Added: and <3 MPY for crude. 5/15/12 4.4.8 Rick Wooldridge Doug Chabino Added: (Reference API RP‐45, NACE TM0194, NACE RP0192, and ASTM D2327 for more information) and For crude pipeline systems, water sample traps will be mounted on the bottom of the pipe to facilitate the collection and analysis of free water. These locations will be inspected for water monthly and if a sufficient amount of water is present (typically >1 pint) this water shall be analyzed for bacteria, pH, iron, manganese, chlorides, and inhibitor residual. Bacteria counts in excess of 10‐100 colonies/ml., pH readings outside a range of 4‐8, inhibitor residual less than ~10ppm, or an increase in iron, manganese, or chlorides could indicate an increase threat to internal corrosion. Water and debris brought into receiving traps during pigging operations will be tested to determine its potential to cause internal corrosion if determined to be necessary after consultation with the Corrosion Specialist. 5/15/2012 4.4.9 Rick Wooldridge Doug Chabino Added: Crude assets covered by the Mitigation Plan: Coupon/water sample collection points will be located in facilities at origination points, along the pipeline system, and end points. Locations chosen for initial sampling points include Ft. McKavett, Cedar Valley, Satsuma, and East Houston. Additional coupon/water sample collection points may be installed as determined necessary through hazard analysis. 5/15/2012 4.4.2, 4.4.8 Rick Wooldridge Doug Chabino Added references to Standard documents 5/15/2012 2.14 Rick Wooldridge Doug Chabino Recording voltmeters should be considered in areas where high voltage transmission lines parallel the pipeline over long distances. <<>> Magellan Midstream Partners, L.P. EXAMINING AND DOCUMENTING THE CONDITION OF AN UNDERGROUND PIPELINE OR RELATED FACILITY WHEN EXPOSED 7.04–ADM–005 Asset Integrity 0/01/11 Revision: 3 Page 1 of 4 1.1 3.13.1 Purpose The purpose of this procedure is to establish a standardized method for examining and documenting the condition of an underground pipeline or related facility when exposed or removed from the system for any reason. 3.13.2 2.0 PROCEDURE NOTE: Each time a buried pipeline or related underground facility is exposed for any reason (intentionally or unintentionally), it must be thoroughly inspected and the conditions noted on the Pipeline Maintenance Report. Additionally, each time pipe is removed from the system; the internal surface of the pipe must be inspected for evidence of corrosion. 2.1 2.2 Performing and Documenting the Coating Examination 2.1.1 Perform an inspection of the pipe coating, if coated, and note the type of coating. 2.1.2 Note the condition of the coating. 2.1.2.1 Well Bonded: Coating is considered “well bonded” if it is intact and doing its intended job with good adhesion and minimal holidays. 2.1.2.2 Partially Bonded: Coating is considered “partially bonded” if it is lightly damaged, shows evidence of deterioration or some loss of adhesion and is not shielding the cathodic protection. 2.1.2.3 Totally Disbonded: Coating is considered “totally Disbonded” if it is damaged, losing adhesion shown by coating falling off the pipe, and/or shielding the cathodic protection. 2.1.3 Note any evidence of soil stress if the coating appears to be deformed and ineffective as if pulled or stretched from its normal status. 2.1.4 Note the environment in which the pipe is in at the exposed site by identifying the total depth of cover, in inches, from top of the pipe to the ground surface. 2.1.5 If after completing the pipeline inspection, the exposed section is recoated, note the details of the coating material used. 2.1.5.1 Reference Coatings – Selection, Application, and Maintenance procedure. Performing and Documenting the Corrosion Examination 2.2.1 Perform an inspection of the pipe and confirm the general pipe specifications. Most of the general pipe information can be found on alignment sheets. 2.2.2 If the internal portion of the pipe is exposed from being cut, coupon extracted, or other reasons, include the internal surface in the corrosion examination. 2.2.3 Note the condition of the pipe when there is evidence of corrosion, SCC, third party damage, pipe defects, or other conditions of concern. 2.2.4 The following external corrosion examination is only necessary if damaged coating and corrosion or SCC has been identified. If the coating is not damaged to the point of being able visually inspect the pipe surface, or if the pipe surface is not corroded or SCC is not noted, go to step 2.2.9. 2.2.5 Measuring Corrosion and Pipe Wall Thickness <<>> Magellan Midstream Partners, L.P. EXAMINING AND DOCUMENTING THE CONDITION OF AN UNDERGROUND PIPELINE OR RELATED FACILITY WHEN EXPOSED 7.04–ADM–005 Asset Integrity 0/01/11 Revision: 3 Page 2 of 4 2.2.6 2.2.7 2.2.8 2.2.9 2.3 Documentation 2.3.1 2.2.5.1 Clean the pit(s) 2.2.5.2 Position the pit gauge over the corrosion to be measured. 2.2.5.3 Obtain the pit depth following the manufactures procedures for the specific pit gauge utilized. 2.2.5.4 Divide the measured pit depth by the nominal wall thickness of the pipe to determine the percentage depth of the corrosion. 2.2.5.4.1 Nominal wall thickness may be obtained from the alignment sheets, from the Line Fill Database (contact Asset Integrity), or by physical measurement. 2.2.5.4.2 Measure wall thickness utilizing ultrasonic thickness equipment following the manufactures recommend procedures. Use the following corrosion definitions to describe the type and extent of the corrosion found. 2.2.6.1 Minor Pitting: Corrosion exhibiting metal loss less than 12.5% of the pipe wall. 2.2.6.2 Moderate Pitting: Concentrated area of uniform metal loss without isolated pitting. 2.2.6.3 Severe Pitting: Concentrated area of metal loss appearing as a dimple, crater or depression in the steel surface. If corrosion is in excesses of 12.5% of the pipewall or any dents, gouges, or SCC is observed, contact a Supervisor of Asset/Pipeline Integrity, Pipeline Risk Engineer, or Pipeline Integrity Engineer/Coordinator immediately. 2.2.7.1 Refer to Pipeline Defect Evaluation and Repair and RSTRENG Analysis of Corrosion procedures if additional data gathering and/or analysis are required. If SCC is observed initiate Pipeline Defect Evaluation and Repair Procedure. Any pipeline or related facility that will remain exposed to the atmosphere after initial inspection should then be inspected in accordance with Atmospheric Corrosion Inspection procedure. Each time a buried pipeline or related underground facility is exposed for any reason (intentionally or unintentionally), it must be inspected, and the conditions documented on the Pipeline Maintenance Report. End of Procedure <<>> Magellan Midstream Partners, L.P. EXAMINING AND DOCUMENTING THE CONDITION OF AN UNDERGROUND PIPELINE OR RELATED FACILITY WHEN EXPOSED 7.04–ADM–005 Asset Integrity 0/01/11 Revision: 3 Page 3 of 4 System Integrity Plan Change Log Date Change Location Changed By Approved By Brief Description of Change 12/1/03 Change Log Rick Wooldridge Wooldridge Rick Added “Changed By” 12/1/03 2.0 Rick Wooldridge Rick Wooldridge Added Note: Examining the condition of an underground pipeline or related facility when exposed is a Covered Task. Reference Operator Qualification (OQ) – Covered Tasks. 12/1/03 2.1.5.1 Rick Wooldridge Rick Wooldridge 2.1.5.1 Reference “Coatings and/or Paint – Selection, Applications and Maintenance”. 12/1/03 2.2.6 Rick Wooldridge Rick Wooldridge 2.2.6 Investigation. If SCC is observed initiate Stress Corrosion Cracking 12/1/03 3.2.3, 3.2.4 Rick Wooldridge Rick Wooldridge Updated procedure list 1/1/06 All E7 Rick Wooldridge 2005 annual review, no changes 1/1/07 All E7 Rick Wooldridge 2006 annual review, no changes 01/01/08 All E7 Rick Wooldridge 2007 annual review, no changes 4/1/08 2.2.4 Rick Wooldridge Rick Wooldridge Added for clarification 11/19/08 2.1.1 Rick Wooldridge Rick Wooldridge Deleted: Most of the general coating information can be found on alignment sheets. 11/19/08 E7 All Rick Wooldridge 2008 annual review, no changes 11/17/09 E7 All Rick Wooldridge 2009 annual review, minor clean-up changes 08/10/10 E7 All Rick Wooldridge 2010 annual review; Revised numbering 12/31/11 2012 Annual Review complete – no changes All <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 1 of 9 1.0 Purpose 1.1 The purpose of this procedure is to establish standardized cathodic protection (CP) criteria to be used to confirm adequate external corrosion control for Company facilities. 2.0 PROCEDURE 2.1 2.2 2.3 Identifying CP Criteria to be Used 2.1.1 Selecting which CP criteria to use 2.1.1.1 Use the –0.850 volts Pipe‐to‐Soil (P/S) potential criteria as the primary criteria for all facilities. 2.1.1.2 Use the 100 millivolt shift criteria whenever the –0.850 volts P/S criteria cannot be achieved or as directed by the Manager of Asset Integrity. 2.1.1.3 The criteria employed must be specified in the Cathodic Protection Data Manager for the facility, segment, or individual test point. Using the –0.850 Volts P/S Criteria 2.1.2 Take P/S potentials per procedure Measuring a Pipe‐to‐Soil Potential. 2.1.3 P/S reading must be at least –0.850 volts, with reference to a saturated copper‐copper sulfate reference half‐cell, while the protective current is applied. 2.1.4 Voltage (IR) drops shall be considered per section 2.5 below. 2.1.5 Whenever –0.850 volts P/S is not achieved, the 100 millivolt shift criteria should be applied, unless corrective actions are planned to remediate the low potential. 100 Millivolts Voltage Shift (Polarization Formation) Criteria 2.3.1 To use the 100 millivolt shift criteria as established by the polarization formation method, follow the procedure described below. 2.3.2 For Existing Pipelines Or Facilities 2.3.2.1 Turn off and/or disconnect all known sources of CP influence. 2.3.2.2 Allow sufficient time for the piping or facility to depolarize. 2.3.2.3 Conduct a complete P/S survey (near native state survey). 2.3.2.4 Near native state survey, results may not be totally native state due to unknown galvanic anodes or foreign impressed and stray current influences. If other CP influences are located, these should be shut down and a new survey performed in the areas of influence. 2.3.3 Apply CP to the Pipeline or Facility 2.3.3.1 Turn on and/or reconnect all known sources of CP influence. 2.3.3.2 Allow sufficient time for the structure to polarize or re‐polarize for existing structures. 2.3.4 Conduct an Interrupted P/S Survey Of The Pipeline Or Facility 2.3.4.1 Install and place in operation interrupter equipment in all influential CP current sources affecting the pipeline or facility being tested. 2.3.4.2 Synchronize all interrupters. <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 2 of 9 2.3.5 2.3.6 2.3.7 2.3.4.3 Use at least an 80% duty cycle (“On” cycle set to 8 seconds and “Off” cycle set to 2 seconds). Keep the “Off” cycle as short as possible to prevent polarization decay but long enough to read after any spike (“Instant Off”) as shown in Figure 1 “Polarization Formation”. 2.3.4.4 After starting the interruption of all current sources, read the “On” potential during the “On” cycle and take the “Off” potential reading instantly after any spike. Conduct a complete P/S survey, recording both the “Instant Off” and the “On” potential readings. Calculate for the 100 millivolt shift. 2.3.6.1 Subtract the Native State or Near Native State potential from the “Instant Off” potential for each location. To meet the 100 millivolt shift criteria, the results must be greater than 100 millivolt. 2.4 2.3.8 Establish Individual Test Point “ON” criteria based on the 100 millivolt test. 2.3.8.1 When 100 millivolt or more shift occurs, the “On” potential reading is established as the P/S criteria, with CP on, for a particular test point. 2.3.8.2 As long as there are no significant changes in the environment, structure, coating, CP systems, etc., this established “On” criteria can be used for satisfying the 100 millivolt criteria through the monitoring of the “On” potentials. 100 Millivolts Voltage Shift (Polarization Decay) Criteria 2.4.1 To use the 100 millivolt shift criteria as established by the polarization decay method 2.4.1.1 Install and place in operation interrupter equipment in all influential CP current sources effecting the pipeline or facility being tested. 2.4.1.2 Synchronize all interrupters 2.4.1.3 Use at least an 80% duty cycle (“On” cycle set to 8 seconds and “Off” cycle set to 2 seconds). The “Off” cycle should be kept as short as possible to prevent polarization <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 3 of 9 2.4.2 2.4.3 2.4.4 decay, but long enough to read after any spike (“Instant Off”) as shown in Figure 2. 2.4.1.4 Conduct a complete P/S survey, recording both the “Instant Off” and the “On” potential readings. Mark each spot of electrode placement. Calculate Targeted Near Native State P/S Potentials as Follows: 2.4.2.1 Subtract 100millivolt from the “Instant Off” potential reading for each test point. This is the targeted near native state P/S potential. Test For Polarization Decay To Targeted Near Native State P/S Potentials As Follows: 2.4.3.1 Turn off and/or disconnect all known sources of CP influence. 2.4.3.2 Conduct a complete P/S survey, recording “Off” potential readings. 2.4.3.3 Observe and record polarization decay potentials. When polarization decay potentials reach targeted near native state P/S potentials, stop decay test to retain as much polarization as possible 2.4.3.4 Targeted near native state potentials may not be totally native state due to unknown galvanic anodes or foreign impressed and stray current influences and a small amount of remaining polarization. 2.4.3.5 Turn on or reconnect all known sources of CP influence as soon as possible to reestablish polarization. Establish Individual Test Point “On” criteria based on the 100 millivolt shift, polarization decay 2.5 test. 2.4.5 When 100 millivolt or more shift occurs, the “On” potential reading is established as the P/S criteria, with CP on, for that test point. 2.4.6 As long as there are no significant changes in the environment, structure, coating, CP systems, etc., these established “On” criteria can be used for satisfying the 100 millivolt criteria through the monitoring of the “On” potentials. Methods for IR Drop Consideration 2.5.1 In accordance with Ohm’s Law of E (volts) = I (current) x R (resistance), any time current flows through a resistance, a voltage drop is produced. For cathodic protection purposes, the current flow in the soil (electrolyte) is the I and the soil resistance is R and the resulting voltage drop is E in volts. Therefore, if the amount of current or the resistance is very low, the resulting voltage or IR drop would also be low or considered negligible. The voltage drop, commonly called the IR Drop, needs to be considered when taking pipe‐to‐soil measurements. See figure below for a depiction of the IR Drop location in P/S measurements below. <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 4 of 9 2.5.2 Various IR Drop correction techniques can be utilized to consider the IR Drop factor in P/S measurements. These include but not limited to the following: Which Method(s) For Considering Voltage Drop (IR) In P/S Measurements Method Process Comments High Resistance Voltmeter See Section 2.5.3 Historical Operating Information See Section 2.5.4 Reference Cell Placement See Section 2.5.5 Is affected by proximity to the current sorce Integrity testing procedures should incorporate historical corrosion rates and growth calculations Requires knowledge of various operating factors and historical information Integrity testing procedures should incorporate historical corrosion rates and growth calculations May be affected by the proximity to current sorce Integrity testing procedures should incorporate historical corrosion rates and growth calculations Calculation See Section 2.5.6 Time consuming and requires various calculations Integrity testing procedures should incorporate historical corrosion rates and growth calculations Current Interruption See Section 2.5.7 For proper use, requires synchronized interruption of all current sources Integrity testing procedures should incorporate historical corrosion rates and growth calculations Buried Coupons See Section 2.5.8 Requires installation of special test stations containing coupons Integrity testing procedures should incorporate historical corrosion rates and growth calculations <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 5 of 9 2.5.3 High Resistance Voltmeter Method 2.5.3.1 This method considers IR drop by minimizing current flow through the measurement circuit, thus decreasing voltage drops associated with the mechanical and electrolytic components of the circuit. 2.5.3.2 A high resistance voltmeter (>50,000 ohm) is necessary to reduce the voltage drop in the external circuit. 2.5.4 Historical Operating Information Method 2.5.4.1 This method utilizes recent and historical operating information to determine if the cathodic protection system is properly protecting the structure at existing voltage levels. 2.5.4.2 The lack of corrosion related leaks or repairs in conjunction with consistent cathodic protection levels and coating condition indicates the adequacy of cathodic protection. 2.5.5 Reference Cell Placement Method 2.5.5.1 Since the amount or quantity of the IR drop is directly proportional to the distance between the reference cell and the structure to be measured, the simplest method for considering IR drop is to minimize this distance. 2.5.5.2 To minimize IR drop at test stations: 2.5.5.2.1 The reference cell should be placed over the centerline of the structure to be tested. 2.5.5.2.2 Permanent reference cells can be placed in close proximity to the buried structure. 2.5.5.2.3 If a quantitative voltage drop reading is required for the location, then a surface reading can be obtained with a portable reference cell and then by subtracting the reference cell reading, the voltage drop is obtained. 3.13.3 Surface Reading – Reference cell reading = IR or voltage drop 2.5.5.2.4 The pipeline can be probed and a small diameter/long cylinder reference cell inserted into the hole where the probing occurred. This cell is then placed very close to the pipe’s surface without contacting the pipe. 2.5.5.2.5 A plastic or non‐conductive tube can be installed directly over the pipeline. The tube should be within one or two inches of the structure, but not contacting the coating. The tube can be filled with soil or left open and the reference cell lowered into the tube for voltage measurements. 2.5.5.3 To minimize IR drop when taking P/S measurements where the structure has been excavated, the reference cell should be placed in close proximity to the structure. <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 6 of 9 3.13.4 2.5.5.4 To minimize IR drop when taking P/S measurements on structures that extend above grade, the reference cell should be placed in close proximity to the structure. 3.13.5 2.5.6 Calculation Method 2.5.6.1 2.5.6.2 2.5.6.3 2.5.6.4 2.5.6.5 This method utilizes an extrapolation calculation for considering the IR drop as further noted below and in Figures 2 and 3 below. 2.5.6.1.1 When potential measurements are taken in close proximity to another structure, this method will not be valid. Obtain a P/S measurement directly over the structure or pipeline. Move the reference cell six feet perpendicular away from the first reading and obtain a second pipe‐to‐soil reading, called the offset potential. Obtain the centerline depth of the structure. Calculate the true or IR free potential using the following formula: TR = D – A[(E – D)/C] TR = True reading in millivolts 3.13.6 3.13.7 3.13.8 <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 7 of 9 3.13.9 <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 8 of 9 2.5.7 Using Current Interruption 2.5.7.1 2.5.7.2 2.5.7.3 This method utilizes current interruption to obtain what is commonly called an “Instant Off” potential. The basis for this method is that the IR or voltage drop disappears when the current is turned off according to Ohms law of E = I x R. However, care must be exercised when using this option as polarization may be lost when the interrupters are installed or during the interruption cycle. Therefore, an 80% duty cycle (8 seconds On and 2 seconds Off) is suggested. For proper consideration of IR drop in this method, all current sources must be interrupted. Foreign current sources must also be interrupted, shut off or not in operation at the time of consideration. To consider IR drop in this manner, the following steps should be followed: 2.5.7.3.1 Synchronize all interrupters to be utilized for this type of survey or consideration method. 2.5.7.3.2 Install the interrupters on all known current sources to include bonds and foreign and Company cathodic protection facilities. 2.5.7.3.3 Record the “On” and “Instant Off” potentials for the structure being tested. 2.5.7.3.4 Remove all interrupters and return all facilities to normal operation. 2.5.7.4 Soil Coupons 2.5.7.4.1 2.5.7.4.2 2.5.7.4.3 2.5.7.4.4 To decrease or eliminate possible errors associated with “current interruption” coupons can be installed next to the pipeline simulating a coating defect (holiday). The coupon should be installed in similar backfill as the structure to be monitored and installed in accordance with the manufacture’s recommendation. The “Off” reading is obtained by measuring the potential of the coupon while removing it from the cathodic protection circuit. Polarization decay and Native potential readings can be obtained while the coupon is disconnected from the cathodic protection system. 3.13.10 <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 9 of 9 System Integrity Plan Change Log Date Change Location Chan ged By Approv ed By Brief Description of Change 12/1/03 Change Log Rick Wooldridge Michael Pearson Added “Changed By” 12/1/03 Document Rick Wooldridge Michael Pearson Replaced Williams with Company 12/1/03 2.3 Rick Wooldridge Michael Pearson Deleted, “For newly constructed pipelines or facilities, the Corrosion Technician shall conduct a complete P/S survey before application of CP. Mark each spot of electrode placement 1/1/06 All E7 Michael Pearson 2005 annual review complete – no changes 10/26/06 2.1.1.3, 2.5, 4.7 Rick Wooldridge Michael Pearson Removed references to net protective current 01/01/08 All E7 Rick Wooldridge 2007 annual review complete – no changes 1/1/09 All E7 Rick Wooldridge 2008 annual review complete – no changes 11/17/09 All E7 Rick Wooldridge 2009 annual review complete – minor clean-up changes 8/3/10 All E7 Rick Wooldridge 2010 annual review – This procedure was rewritten to further clarify Magellan’s process for IR Drop consideration [including the incorporation of historical corrosion rates and growth calculations]. 1/17/11 Various Larry Davied Rick Wooldridge 2011 annual review, Minor revisions 12/31/11 All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. TESTING FOR INDUCED AC AND REMEDIAL MEASURES 7.04‐ADM‐023 Asset Integrity 1/1/12 Revision: 1 Page 1 of 5 1.0 PURPOSE 1.1 The purpose of this procedure is to establish a standardized method for identifying and mitigating induced AC. 2.0 PROCEDURE 2.1 Determining the need for induced AC testing. 2.1.1 Determine the need for induced AC testing based on the potential effects on facilities from High Voltage Alternating Current (HVAC). Primary influences of HVAC systems include: [see NACE RPO177‐2000 for more information]. 2.1.1.1 Resistive Coupling 2.1.1.2 Capacitive Coupling 2.1.1.3 Inductive Coupling 2.1.1.4 Power Arc 2.1.1.5 Lightning 2.1.1.6 Switch Surges or other Transients 2.1.2 Tests that may indicate Induced AC include the following: 2.1.2.1 Inadequate Pipe‐to‐Soil (P/S) potential readings 2.1.2.2 AC potential readings 2.1.2.3 Predictive modeling 2.1.3 Likely areas for Induced AC: 2.1.3.1 Pipelines or facilities that enter or exit the electrical gradient of an HVAC system 2.1.3.2 Pipelines or facilities paralleling in close proximity to an HVAC system 2.1.3.3 Pipelines or facilities in close proximity to an HVAC Sub‐Station 2.1.3.4 Pipelines or facilities in close proximity to HVAC Towers and/or grounding systems 2.2 Testing for and Determining the Effects of Induced AC 2.2.1 Identify test leads and/or above ground appurtenances to be tested based on information in 2.1.3 above. 2.2.2 Measure the AC potential using an AC voltmeter. Contact resistance should be sufficiently low to preclude measurement errors. Suitable references for measurements include: 2.2.2.1 2.2.2.2 2.2.2.3 A metal rod inserted into the earth until no further increases in AC potential are noted. Bare pipeline casings, if adequately isolated from the carrier pipe. Tower legs or power system neutrals, in close proximity to the affected structure. <<>> Magellan Midstream Partners, L.P. TESTING FOR INDUCED AC AND REMEDIAL MEASURES 7.04‐ADM‐023 Asset Integrity 1/1/12 Revision: 1 Page 2 of 5 2.2.2.4 Reference electrodes designed for gathering cathodic protection data (i.e. half‐cells, permanent reference electrodes, etc.) CAUTION: Meter connections may present a hazard during switching surges, lightning strikes, or fault conditions. 2.2.3 Analyze the AC P/S reading from step 2.2.2 of this procedure to determine if soill resistivity data is required. Criteria includes: 2.2.3.1 AC potentials greater than 10 volt 2.2.3.2 Human shock hazards have been identified (electrical shocks may occur at a voltage below the 15 volt threshold recommended by NACE, while not life threatening, mitigation may be necessary to address these shocks.) 2.2.3.3 Areas were AC potentials are cyclic, unstable, or inconsistent over time. 2.2.3.4 Areas were AC corrosion has been identified 2.2.4 If soil resistivity measurements are not required go to 2.7 below. 2.3 Soil Resistivity 2.3.1 Collect soil resistivity measurements at each location as selected per 2.2.3. 2.4 AC Current Density 2.4.1 Using the AC voltage measured in 2.2.2 and the soil resistivity measured in 2.3.1 determine the calculated AC current discharge density per the AC current density calculator in section 2.4.2. Note: Holiday size should be selected based on the typical holiday size expected on the pipeline. 2.4.2 AC Current Density Calculator Calculating AC Current Density Inputs AC Voltage 10 volts Soil Resistivity 5000 ohm-cm Holiday Size 6 cm2 AC Current Density 18.42633309 A/m2 AC Corrosion Potential AC corrosion not likely Cathodic Protection Criteria 100mv polorization AC Mitigative Action No action required AC Voltage Measured or calculated Soil Resistivity Measured or expected <<>> Magellan Midstream Partners, L.P. TESTING FOR INDUCED AC AND REMEDIAL MEASURES 7.04‐ADM‐023 Asset Integrity 1/1/12 Revision: 1 Page 3 of 5 2.4.3 2.4.4 2.4.5 The AC Current Density Calculator utilizes the relationship between the AC driving voltage, soil resistivity, and the estimated size of the coating holiday from which current can discharge, to estimate the discharge density. Where a more precise current discharge density is required coupon test stations should be installed. Determine the potential for AC corrosion 2.4.4.1 AC Current Density <20 A/m2 = AC Corrosion not likely 2.4.4.2 AC Current Density >20 A/m2 but <100 A/m2 = AC Corrosion unpredictable 2.4.4.3 AC Current Density >100 A/m2 = AC Corrosion is likely Determine the need for mitigative action (see AC current density calculator in section 2.4.2) 2.4.5.1 2.4.5.2 2.4.5.3 2.4.6 AC Current Density <20 A/m2 = No action required AC Current Density >20 A/m2 = Action required Rule of Thumb: When the AC potential, in millivolts (mV), is greater than or equal to the resistance of the soil, in ohm‐cm; a more detailed analysis and/or mitigation is typically required. Determine the criteria for cathodic protection ((see AC current density calculator in section 2.4.2) 2.4.6.1 2.4.6.2 2.5 2.6 AC Current Density <20 A/m2 = 100 mV polarization AC Current Density >20 A/m2 but <500 A/m2 = 150 mV to 250mv polarization 2.4.6.3 AC Current Density >500 A/m2 = Cathodic protection is not effective in mitigating corrosion Mitigative Action – Cathodic Protection can be effective at mitigating AC corrosion 2.5.1 Measure and/or calculate the target ON potential for each test point within the area affected by Induced AC. 2.5.1.1 Target ON is the potential, with current applied, where polarization equal to the native potential, plus the cathodic protection criteria established in 2.4.6 is achieved. 2.5.2 Document the Target ON potential in the Corrosion Database (CPDM). 2.5.3 Utilize the target ON potential as the criteria for cathodic protection. This criteria may be used as long as there are no significant changes in the environment, structure, coating, cp systems, etc. 2.5.4 Supplemental cathodic protection and/or coating rehabilitation will be required if the adequate cathodic protection potentials are not achieved. Mitigative Action – In addition to adequate cp as defined in 2.5, managing the negative effects from Induced AC or lightning is accomplished by reducing the interference voltage and/or providing a path to ground for damaging current. 2.6.1 Select and install the appropriate grounding equipment. This equipment may include: 2.6.1.1 Grounding rods (typically made of zinc, copper, graphite or cast‐iron) <<>> Magellan Midstream Partners, L.P. TESTING FOR INDUCED AC AND REMEDIAL MEASURES 7.04‐ADM‐023 Asset Integrity 1/1/12 Revision: 1 Page 4 of 5 2.6.1.2 2.6.1.3 installed where the pipeline enters and exits the electrical gradient of a HVAC system and at select locations where the pipeline parallels the HVAC system. Grounding ribbons (typically made of zinc or copper) installed parallel with and directly connected to the pipeline along the distance where the pipeline is influenced by the HVAC system. Ground mats (typically made of zinc or copper) should be installed at valves, metallic vents, cathodic protection test stations, and other above ground appurtenances where electrical contact with the affected structure is possible. Grounding mats should be large enough to extend beyond the area on which a person may be standing when contacting the affected structure and close enough to the surface that step and touch potentials are adequately reduced. 3.13.11 NOTE: If the ground rod material used has a native voltage potential less negative than the ‐1 volt (as compared to copper‐copper sulfate electrode) an isolation device must be installed to block the flow of DC, while passing AC. Caution is advised when using grounding material with a native potential more negative than the pipeline as the ground will be anodic to the pipeline and thus corrode. 2.6.1.4 2.6.1.5 Where AC surge currents or lighting is a concern, electrical bonds designed to pass AC, should be installed across insulating flanges to prevent arcing. Groundbeds utilized for cathodic protection of the pipeline or facility will provide mitigative grounding as described above. However, precautions should be taken to protect the electrical equipment and wiring from lighting and surge current damage. 3.0 Monitoring 3.1 Induced AC and lightning mitigation equipment should be monitored to ensure its continued effectiveness. 3.2 In areas where induced AC currents have been identified, coupon test stations should be installed and monitored. 4.0 DOCUMENTATION 4.1 Data collected as part of this procedure shall be documented in appropriate sections of the Corrosion Control database (CPDM). <<>> Magellan Midstream Partners, L.P. TESTING FOR INDUCED AC AND REMEDIAL MEASURES 7.04‐ADM‐023 Asset Integrity 1/1/12 Revision: 1 Page 5 of 5 System Integrity Plan Change Log Date Change Location Changed By Brief Description of Change Approved By 12/06/06 NEW Rick Woolridge Michael Pearson New procedure 01/01/08 All E7 Rick Wooldridge Reviewed, no changes All E7 1/1/09 Rick Wooldridge 2008 annual review complete – no changes All E7 01/01/10 Rick Wooldridge E7 Review; no changes All E7 01/01/11 Rick Wooldridge E7 Review, no changes 9/28/11 2.2.3.1 John McMahan Rick Wooldridge E7 Review; Changed 1 volt to 10 volts 12/31/11 All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. OUTSIDE FORCES DAMAGE PREVENTION PROGRAM SIP–ADM–7.05 Asset Integrity 1/01/12 Revision: 8 Page 1 of 3 1.0 OBJECTIVE 1.1 The objective of this initiative is to maintain asset integrity by establishing a consistent and comprehensive Outside Forces Damage Prevention Program. 2.0 DESCRIPTION 2.1 This initiative incorporates processes to proactively identify and manage risks to outside forces damage and achieve public safety. 2.2 This program is intended to prevent outside forces damage in the areas of permanent pipeline markers, ground and aerial surveillance, One Calls, blasting, depth‐of‐cover, right‐of‐way maintenance, navigable water crossings and line spotting activities. 3.0 STANDARDS 3.1 The Employee shall: 3.1.1 Upon discovery or notification of blasting activity, immediately notify the Asset Integrity Engineer. 3.1.2 Upon discovery or notification of an encroachment activity, immediately notify the Real Estate Representative. 3.2 The Asset Integrity Engineer shall: 3.2.1 Investigate, analyze and document the effect of blasting operations per the Blasting Damage Prevention Procedure. Define recommendations and communicate to the appropriate Company personnel and the blasting company within 48 hours of the request. Forward the blasting investigation results, calculations and notes to the Records Coordinator. 3.2.2 Conduct an engineering impact study per the General Encroachment Requirements to evaluate potential impacts to Company assets resulting from Third‐Party Encroachment notifications. 3.3 The Real Estate Representative shall: 3.3.1 Upon notification of an encroachment, initiate the Encroachment Procedure. 3.4 The Field Supervisors shall: 3.4.1 Inspect the surface conditions on or adjacent to each pipeline right‐of‐way in accordance with the Inspection of Right‐of‐Way Procedure. 3.4.2 Investigate, respond and document right‐of‐way defects identified per the Inspection of Right‐of‐Way Procedure. 3.5 The Supervisor of Pipeline Integrity shall: 3.5.1 Maintain the Depth of Cover Program (DOC) and the Right‐of‐Way (ROW) Maintenance Program. 3.5.2 Coordinate the implementation, execution, and documentation of the work required by the DOC and ROW Maintenance Program. <<>> Magellan Midstream Partners, L.P. OUTSIDE FORCES DAMAGE PREVENTION PROGRAM SIP–ADM–7.05 Asset Integrity 1/01/12 Revision: 8 Page 2 of 3 3.6 The Pipeline Integrity Coordinator shall: 3.6.1 3.6.2 Execute and document the work required by the Depth of Cover Program. Execute and document the work required by the Right‐of‐Way (ROW) Maintenance Program. 3.6.3 Upon notification of flooding conditions initiate the process outlined in the Flood Conditions Procedure and update management on a regular basis. Evaluate marker placement relative to the Mark Lines Procedure. Replace or repair 3.7 The Asset Locator shall: 3.7.1 3.7.2 missing and damaged markers as necessary. Complete Pipeline Maintenance Report and the Short Form Encroachment Agreement 3.7.3 and submit to the Records Coordinator. Contact the appropriate Real Estate Representative and utilize Encroachment Agreements before allowing any encroachment to the existing right‐of‐way using the general Encroachment Requirements. 3.7.4 3.7.5 Respond to all dispatched One Call tickets in accordance with the One Call Program. Respond to One Call notifications, and mark Company pipeline assets in accordance with the One Call Program and the Line Locating Procedure. 3.7.6 Notify the Pipeline Integrity Coordinator of Flood Conditions and follow the Flood Conditions Procedure. 3.8 3.9 3.10 The One Call Team Lead shall: 3.8.1 Maintain the One Call Program as described in the One Call Program. The One Call Coordinator shall: 3.9.1 Analyze and administer One Call notifications in accordance with the One Call Program. The Regulatory Compliance Coordinator shall: 3.10.1 Implement the One Call Violation Process including initiating a review with the Legal 3.10.2 Department to determine the appropriate path forward. Advise PHMSA as described in the Flood Conditions Procedure. <<>> Magellan Midstream Partners, L.P. OUTSIDE FORCES DAMAGE PREVENTION PROGRAM SIP–ADM–7.05 Asset Integrity 1/01/12 Revision: 8 Page 3 of 3 System Integrity Plan Change Log Date Change Location Change By Approved By: Brief Description of Change 9/29/04 3.2 Bronson Michael Pearson Moved 3.2.2 & 3.2.3 from “Field Based Supervisors” 9/29/04 3.4 Bronson Michael Pearson Changed title to “Field Based Supervisors” from “Field Based Managers” 9/29/04 3.5 Bronson Michael Pearson Changed Title to “Pipeline Integrity Engineer” from “Engineering & Construction Manager” 9/29/04 3.6 Bronson Michael Pearson Added 3.6.2 ROW Maintenance Program & 3.6.3 Overhead Crossing Program 9/29/04 3.7 Bronson Michael Pearson Deleted ROW Maintenance Program and moved to Pipeline Integrity Coordinator 9/29/04 3.7.5 Bronson Michael Pearson Added Short Form Encroachment 9/29/04 3.8 Bronson Michael Pearson Added 3.8 & 3.8.1 One Call Analyst 9/29/04 3.9 Bronson Michael Pearson Added 3.9.1 & 3.9.3 One Call Violations 9/29/04 4.0 Bronson Michael Pearson Added “1‐Call Violation Process Map” link 9/29/04 All Bronson Michael Pearson Conducted 2004 Annual Review 11/15/05 All Greg Walker Michael Pearson Conducted 2005 Annul Review 01/01/06 3.2, 3.3, 3.6 Greg Walker Michael Pearson Changed titles to reflect re‐organization in Asset Integrity 01/01/06 3.1.6 Greg Walker Michael Pearson Deleted Pipeline Maintenance Procedure. 01/01/06 3.2 Greg Walker Michael Pearson Changed title to Risk Engineer. 01/01/06 3.1 Greg Walker Michael Pearson Removed AI Manager Responsibilities 6/5/06 5.0 Greg Walker Michael Pearson Deleted Measures 01/01/07 All Greg Walker Michael Pearson Conducted 2006 Annual Review 9‐11‐07 All Greg Walker Michael Pearson Conducted 2007 Annual Review. See change log 9‐11‐07 3.3.1 Greg Walker Michael Pearson Change Encroachment Process to Encroachment Procedure 9‐11‐07 All Greg Walker Michael Pearson Updated Titles per Org changes. 9‐25‐08 All Greg Walker Doug Chabino Removed Shell Consent Decree References – Annual Review 12/31/09 3.1.3 Kelli Riddle Kelli Riddle removed 1/1/10 All Annual review complete 9/3/10 3.2.2 Dennis Vasicek Added reference to 7.05‐ADM‐035 – General Encroachment Requirements 3.6.3, 3.7.6, 3.10.2 added 12/31/11 All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. PIPELINE MARKING PROCEDURE 7.05–ADM–002 Asset Integrity 01/01/10 Revision: 7 Page 1 of 5 1.0 PURPOSE 1.1 The purpose of this procedure is to establish a standardized process for safely marking the Company rights‐of‐way (ROW) with permanent line markers, in order to: 1.1.1 1.1.2 1.1.3 1.1.4 Meet all applicable DOT requirements. Effectively delineate the pipeline corridor. Promote public and community awareness. Identify the pipeline location for effective damage prevention. 2.0 SCOPE 2.1 This procedure is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be utilized in whole or part on non‐jurisdictional assets as deemed appropriate. 2.2 Assets covered per the Mitigation Plan: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, other specific marker requirements may be stated within the Mitigation Plan. Refer to the Mitigation Plan for those requirements. 2.3 Consent Decree Specific: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, the Company’s Consent Decree Pipeline Systems operate under the requirements of the Consent Decree. For the period of the Consent Decree, these systems will follow the applicable process and procedures (see Consent Decree for applicable programs). 3.0 PROCEDURE 3.1 Consider using the most appropriate marker type, as dictated by the existing conditions. 3.1.1 3 inch PVC schedule 40 pipe with 3” cap, black/red color coded decal six inches from top of post, with warning decal or warning sign as appropriate. Refer to the Standards List. 3.1.2 Flexible fiberglass composite markers. 3.1.3 Bullet style markers. 3.2 The following special tools/equipment/materials as required for permanent pipeline marking: 3.2.1 Applicable assembled marker post or marker. 3.2.2 Pipeline Warning Decals. Refer to the Standards List. 3.2.3 “Pipeline Under Pavement” decals/or signs where applicable. 3.2.4 Color‐coded decals or stickers. 3.2.5 Signs must include “Warning” followed by “Petroleum Pipeline” with letters at least 1 inch high with an approximate stroke of ¼ inch, Company name and 24 hr phone number. 3.2.6 Posthole digger. 3.2.7 Shovel. 3.2.8 Appropriate post driver. <<>> Magellan Midstream Partners, L.P. PIPELINE MARKING PROCEDURE 7.05–ADM–002 Asset Integrity 01/01/10 Revision: 7 Page 2 of 5 3.2.9 Auger. 3.3 Markers must be placed and maintained over each buried pipeline at the following locations: 3.3.1 Each public road crossing. 3.3.2 Each railroad crossing. 3.3.3 Where the line is above ground in areas that are accessible to the public 3.3.4 In sufficient numbers along the remainder of each buried line so that its location is accurately known. Where practical and appropriate, use the following guidelines to establish locations for additional pipeline marker placement:  Interior cross fences  Both sides of creeks and rivers  Both ends of all pipeline exposures  Developed area, commercial and residential  Vast areas with few fences or areas with changing elevations that limits marker visibility.  Markers should not be placed in an area that impedes and/or prevents landowners or tenants (e.g. ranchers, farmers businesses, etc.) from conducting daily activities, or where prohibited by local ordinances. These are best handled on a ‘case by case’ basis; consult immediate Supervisor with questions or unique circumstances. 3.4 Installation of Pipeline Markers: 3.4.1 When applicable, notify landowner prior to entering property. 3.4.2 When excavating activities are required pertaining to installation of marker posts, follow applicable state One Call regulations. (i.e. use of an auger or posthole digger, etc.) 3.4.3 Locate pipeline per Pipeline Locating Procedure. 3.4.4 Dig post hole for 3” post or drive markers as appropriate. 3.4.5 When required, install milepost numbers directly below warning decal or warning sign (at road crossings and valve sites). 3.4.6 For pipelines paralleling roadways located under the surface of the roadway where marker placement is not practical, markers should be placed at the nearest location adjacent to the pipeline and a “pipeline under pavement” decal placed beneath the existing Company warning decal. 3.4.7 Pipeline markers will be placed as close to the line as possible, however, when a marker is offset a greater distance than five feet from the pipeline; notify the appropriate Asset Integrity Supervisor. 3.5 Assets covered per the Mitigation Plan: 3.5.1 3.5.2 All markers shall be within line of sight of one another in Tier I Areas. If one marker is removed, the location of the pipeline can still be identified from either direction from any point in between Tier II and Tier III Areas <<>> Magellan Midstream Partners, L.P. PIPELINE MARKING PROCEDURE 7.05–ADM–002 Asset Integrity 01/01/10 Revision: 7 Page 3 of 5 3.6 3.5.3 3.5.4 3.5.5 3.5.6 3.5.7 3.5.8 All line markers will be written in English and Spanish. Marker placement and density will be evaluated routinely through aerial and ground surveillance. Missing and damaged markers will be replaced within seven days of discovery. Markers will be located at all aboveground facilities to identify the operator of the system. When practical fence crossings will have fence post on either side painted bright yellow to aid in the identification of the pipeline easement width. Documentation will be completed using Mitigation Right of Way Inspection Form, making appropriate comments including: Stationing, GPS coordinate (where possible), land use change or increased density due to Tier I, Tier II and Tier III requirements, etc. Install aerial milepost markers on jurisdictional lines that are patrolled by aerial methods as follows: NOTE: Aerial Markers are for reference only and may not reflect exact stationing. 3.6.1 3.6.2 3.6.3 3.6.4 3.6.5 3.6.6 Construct Aerial Markers on a triangle framework with mile number identified facing up and down stream. Numbers should be of sufficient size to be seen by aerial patrol pilots with the number being black on a yellow background. Refer to the Standards List. Use heavy gauge aluminum or fiberglass, with decal numbers and arrows. Aerial marker numbers should be assigned to match the nearest milepost number as documented on alignment sheets. Place along all mainline ROW, positioned so that they are legible as a pilot flies the line. Place at public road crossings or other appropriate points (distance between markers generally not to exceed one mile). Use special markers with arrows slanted left, right or vertical to direct pilot around locations requiring deviation of flight. <<>> Magellan Midstream Partners, L.P. PIPELINE MARKING PROCEDURE 7.05–ADM–002 Asset Integrity 01/01/10 Revision: 7 Page 4 of 5 System Integrity Plan Change Log Date Change Location Change By Brief Description of Change 010/01/05 Reviewed, no changes Troy Bronson 01/01/06 2.2.7 Replaced “Examples of universal wastes include lead acid batteries, pesticides, thermostats with liquid mercury, and florescent light bulbs.” With “Pipeline markers will be placed as close to the line as possible, however, when a marker is offset a greater distance than 5’ from the pipeline, a Maintenance Report will be generated documenting the placement and reason why.” 01/01/06 2.4.1 Troy Bronson Added “Follow applicable state one‐call regulations pertaining to installation of marker posts.” 01/01/06 Troy Bronson 2.5.1 Replaced “Numbers on signs to be 4” X 6” with the number being black on a yellow background.” With “Numbers should be of sufficient size to be seen by aerial patrol pilots with the number being black on a yellow background. Recommended size of the sign is 6” x 15” with numbers 4 ½ ” x 13 ½ “.” 01/01/06 2.5.5 Troy Bronson Removed note box: When more than 1 pipeline mile is traveled and a public road is passed without seeing a marker, the marker is considered to be missing. 01/01/06 4.2.1 Troy Bronson Added Line Locating link 01/01/06 2.2.2 Troy Bronson Added “where applicable”. 01/01/06 Applicability Dan Egner Added complete section 01/01/06 1.0 thru 1.1.4 Dan Egner Major modification 01/01/06 2.1 thru 2.1.3 Dan Egner Major modification 01/01/06 2.2.1 Dan Egner Changed to “Applicable markers” 01/01/06 2.2.9 Dan Egner Added “appropriate” 01/01/06 2.3.1 Dan Egner Removed “railroad” 01/01/06 2.3.2 Dan Egner Added “Both sides of all railroad crossings” 01/01/06 2.3.3 Dan Egner Added “appropriate and practical” 01/01/06 2.3.6 Dan Egner Added complete subpart 01/01/06 2.2.6.1 Dan Egner Added for the Consent Decree 01/01/06 2.3.10 thru 2.3.15 Dan Egner Added for the Longhorn Pipeline 01/01/06 2.4.1 Dan Egner Added “where applicable” 01/01/06 2.5.7 Dan Egner Removed (…”only”) added (…”and valve sites”) 01/01/06 2.6 Dan Egner Added NOTE: 01/01/06 2.6.3 Dan Egner Major modification 01/01/06 2.7 thru 2.7.1 Dan Egner Added subparts 01/01/06 2.8 thru 2.8.3 Dan Egner Added subparts 01/01/06 2.9 thru 2.9.2 Dan Egner Added subparts 01/01/06 4.1.2 Dan Egner Added regulation 01/01/06 4.3.2 Dan Egner Added form 01/01/06 5.5 Dan Egner Added definition 01/01/06 Removed references, renamed links 02/01/06 3.3 Clyde Clausen Added section 3.3 02/01/06 3.4 Clyde Clausen Modified section 3.4 02/01/06 3.5 & 3.6 Clyde Clausen Added 3.5 and 3.6 (Consent and Longhorn Specific) 02/01/06 3.7 Clyde Clausen Modified paragraph 3.7 02/01/06 3.8 Clyde Clausen Deleted and incorporated into 3.7 02/01/06 3.9 Clyde Clausen Deleted and incorporated into 3.5 <<>> Magellan Midstream Partners, L.P. PIPELINE MARKING PROCEDURE 7.05–ADM–002 Asset Integrity 01/01/10 Revision: 7 Page 5 of 5 2/3/06 3.2.3 Troy Bronson Changed “sign” to “decal”. 2/3/06 3.2.5 Troy Bronson Deleted “Cordless Drill” 2/3/06 3.7.7 Troy Bronson Insert “standards” link. 2/3/06 3.7.8 Troy Bronson Changed “Sign” to “Decal”. 2/3/06 3.7.9 Troy Bronson Changed “Sign” to “Decal”. 2/3/06 3.7.10 Troy Bronson Changed “contact” to “notify”. 1/1/07 3.7 Greg Walker Link to Pipeline Locating Procedure 5/22/07 3.0 Greg Walker Consolidate procedures. Added information about Warning sign details. 5/22/07 3.3.4 Greg Walker Added clarification where markers should be placed. 12/12/08 2.3 Tim Boudreaux Modified the Consent Decree statement to exclude the previous Consent Order. 12/12/08 4.0 Tim Boudreaux Deleted Pipeline Marker Repair report form link. 12/12/08 4.4 Tim Boudreaux Included Longhorn Mitigation Plan. 01/01/2009 Tim Boudreaux Conducted annual review with no changes. 01/01/2009 3.5.7 Tim Boudreaux Included Longhorn specific documentation requirements. 3‐26 3.5.6 Greg Walker Included Longhorn specific documentation requirements. 9/01/09 2.2 Tim Boudreaux Deleted Longhorn Specific 9/01/09 3.5 Tim Boudreaux Changed Longhorn Specific to Assets covered per Mitigation Plan 9/01/09 3.5.8 Tim Boudreaux Deleted Longhorn 9/01/09 4.4 Tim Boudreaux Deleted Longhorn 9/01/09 Tim Boudreaux Annual Review with changes listed above 01/01/11 Reviewed, no changes 12/31/11 All 2012 Annual review complete – no changes <<>> Magellan Midstream Partners, L.P. NAVIGABLE RIVER CROSSING INSPECTIONS PROCEDURE 7.05–ADM–014 Asset Integrity 01/01/12 Revision: 6 Page 1 of 5 1.0 Objective 1.1 To establish standardized and consistent processes for pipeline operations and maintenance in regards to Navigable River Crossing Inspections. 2.0 SCOPE 2.1 2.2 2.3 This procedure is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be utilized in whole or part on nonjurisdictional assets as deemed appropriate. Assets covered per Mitigation Plan: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices. This pipeline operates under the requirements of the Mitigation Plan. Consent Decree Specific: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, the Company’s Consent Decree Pipeline Systems operate under the requirements of the Consent Decree (see Consent Decree for applicable programs). 3.0 PURPOSE 3.1 Navigable River Crossings 3.1.1 3.1.2 3.1.3 3.1.4 3.1.5 3.1.6 The Pipeline Integrity Coordinator shall annually review the list of pipeline crossings of navigable rivers contained in this procedure to ensure the crossings are inspected within the required timeframe. Pipeline Integrity shall be responsible for having these inspections made and for maintaining the records of such inspections. The inspection records shall be maintained for five years or until another inspection is performed. The results of such inspections will be compared with the previous crossing records to determine any change. Should the inspection indicate that repairs need to be made to the crossing, Pipeline Integrity shall be responsible for having suitable repairs performed. Each pipeline crossing under a DOT identified navigable waterway will be inspected at intervals not exceeding five years. For this inspection, navigable waterways are defined as waterways subject to commercial barge traffic. The inspection shall be conducted by third party personnel qualified to carry out such inspections and to prepare permanent records of their findings. The inspections shall determine the pipeline location and any exposed pipe within the limits of the navigable waterway and the right‐of‐way immediately adjacent on each side. The permanent records shall be of sufficient detail to compare with the previous crossing records to determine any change in the location of the pipeline. They shall also indicate if any, the length and location of exposed pipeline. The third party inspector will prepare both plan and profile drawings detailing the findings of the inspection. 4.0 PROCEDURE 4.1 Navigable River Crossing Inspections <<>> Magellan Midstream Partners, L.P. NAVIGABLE RIVER CROSSING INSPECTIONS PROCEDURE 7.05–ADM–014 Asset Integrity 01/01/12 Revision: 6 Page 2 of 5 4.2 4.3 4.1.1 Contractor will reestablish base line indicated on plan drawing and accurately determine route of the pipeline through the river with reference to this line. The length of this traverse will extend between convenient points on the banks. These points will be above water level and at least 50 feet from the edge of the water. 4.1.2 Location of pipe will be determined by the use of an induced tone or transmitter/receiver pipe locator. 4.1.3 The river bottom and banks between reference points will be profiled over the pipe with elevations referenced to the existing bench mark shown on drawing. If existing benchmark has been destroyed, Contractor will set a new bench mark in as permanent a manner as possible. 4.1.3.1 Profile data will also include elevation of water level and top of pipe at all exposed and suspended sections. Vertical measurements for profile may be made by use of a portable Fathometer or weighted sounding chain. On pipeline inspections where sufficient cover cannot be determined from the profile, a diver is required to complete the inspection. 4.1.4 A diver will make passes over each pipe at intervals of 20 feet or less and if exposed or suspended pipe is located, the diver will follow these sections with continuous passes. He will also determine size and location of any build‐up of debris against exposed or suspended pipe section, the condition of pipe and/or pipe coating, the nature of the river bottom at the pipe, and any other underwater condition that may appear to adversely affect the safety of the pipeline crossing such as scouring of the river bottom or undercutting of the banks. Sonar equipment may be used to detect exposed pipe instead of a diver. Forward results of this survey and the inspection individual written reports for each crossing site. Submit reports to the Pipeline Integrity Project Manager and include, at least the following: 4.2.1 A list of all exposed and suspended pipe sections located by station numbers and showing clearance between pipe and river bottom. 4.2.2 Identification of changes from last inspection. 4.2.3 Recommendations for repair. Contractor will supply plan and profile sheets of each pipeline surveyed at the crossing site. One plan and profile sheet will be used for each single pipeline crossing the stream. 4.3.1 Show dual lines. Include the river bottom and adjacent banks between reference points in the drawings. 4.3.2 Show the condition of the pipe coating, all obstructions and sharp objects, all unusual conditions, such as exposed or suspended pipe, and the location and elevation of benchmarks used by Contractor in the drawings. The profile drawing of the pipeline will extend to a minimum of fifty (50) feet beyond the edge of the water on each side of the river. 4.3.3 Show pipe, river bottom and water elevations from previous inspections (when known) on the drawings. 4.3.4 Retain the inspection records that relate to the navigable river inspections for five years or until a new inspection is performed. <<>> Magellan Midstream Partners, L.P. NAVIGABLE RIVER CROSSING INSPECTIONS PROCEDURE 7.05–ADM–014 Asset Integrity 01/01/12 Revision: 6 Page 3 of 5 4.4 The following crossings are listed as being across navigable waters: Navigable River Crossings State Line Section Waterway #Of Spare Lines Eng. Station Date Last Inspection Date Next Inspection Delaware Wilmington 10” Pipeline Christina River 0 66+18 06/11/10 06/11/15 Illinois 106#3‐12" TCS IL‐Wilmington Illinois River 0 26507+04 08/12/08 08/12/13 036 #5‐8" Des Moines‐ MS River Mississippi River 0 9026+14 05/14/07 05/14/12 037 #6‐12" Des Moines‐ MS River Mississippi River 0 9028+96 05/14/07 05/14/12 Iowa 054 #5‐12 Irv ‐ Sioux Falls Missouri River 1 12520+79 08/17/11 08/17/16 Nebraska/ Iowa West Leg NH3 Missouri River 0 14272+87 08/18/11 08/18/16 Kansas 006 #3‐8" Barnsdall ‐ KC Kansas River 0 10171+48 08/08/08 08/08/13 007 #4‐12 Barnsdall ‐ KC Kansas River 0 10178+52 08/08/08 08/08/13 008 #5‐12" Barnsdall ‐ KC Kansas River 0 10187+55 08/08/08 08/08/13 023 #4‐8" Argentine ‐ KC Kansas River 0 164+00 08/08/08 08/08/13 Kansas/ Missouri 18th Street to Riverside 8” Missouri River 0 10370+33 09/01/11 09/01/16 Louisiana GeoNet Bayou Black 1 08/19/08 08/19/13 Minnesota 069 #7‐8" Rose ‐ Mpls. Air Minnesota River 0 661+44 05/15/07 05/15/12 070 #6‐12" Rosemount ‐ Willmar Minnesota River 0 760+59 05/15/07 05/15/12 121#3‐8" StPP (Aranco) ‐ Pine Bend Mississippi River 0 113+45 05/16/07 05/16/12 007 #4‐12” Des Moines to Minneapolis Mississippi River 1 12740+77 05/16/07 05/16/12 <<>> Magellan Midstream Partners, L.P. NAVIGABLE RIVER CROSSING INSPECTIONS PROCEDURE 7.05–ADM–014 Asset Integrity 01/01/12 Revision: 6 Page 4 of 5 Navigable River Crossings State Line Section Waterway #Of Spare Lines Eng. Station Date Last Inspection 059 #1‐6" Alex ‐ Grand Forks Red River of The North 0 5222+47 05/18/07 060 #2‐8" Alex ‐ Fargo Red River of The North 0 5217+64 05/18/07 Missouri 080 #7‐8” Olathe to Columbia Missouri River 0 6714+85 08/22/11 095 #7‐16" Wathena ‐ Des Moines Missouri River 0 9775+35 08/23/11 105 #3‐12 ' TCS MO ‐ IL Line Mississippi River 1 24398+70 08/10/08 Oklahoma 013 #1‐12” Tulsa‐Barnsdall Arkansas 0 48+35 09/21/10 012 #4‐12” Tulsa‐Barnsdall Arkansas 0 48+24 09/21/10 108 #4‐12” Tulsa‐Tulsa Jct. Arkansas 1 48+24 09/21/10 Oklahoma Verdigris Lateral 6” NH3 Verdigris River 0 6426+05 03/04/09 Texas Amerada Hess Houston Ship Channel 3 151+00 03/31/09 Texas City to Pasadena 18” Clear Lake 0 729+00 04/25/09 Wisconsin 047 #1‐8" Newport ‐ Bateman St. Croix River 0 620+13 05/17/07 Date Next Inspection 05/18/12 05/18/12 08/22/16 08/23/16 08/10/13 09/21/15 09/21/15 09/21/15 03/04/14 03/31/14 04/25/14 05/17/12 <<>> Magellan Midstream Partners, L.P. NAVIGABLE RIVER CROSSING INSPECTIONS PROCEDURE 7.05–ADM–014 Asset Integrity 01/01/12 Revision: 6 Page 5 of 5 System Integrity Plan Change Log Date Change Location Change By Brief Description of Change 12/22/04 New Procedure Tim Boudreaux Removed Navigable River Crossing section from Pipeline Maintenance Document and created new Procedure for Navigable River Crossings. 12/22/04 3.1.2 Tim Boudreaux Included text “On pipeline inspections where sufficient cover cannot be determined from the profile, a diver is required to complete the inspection. 12/15/05 3.4 Tim Boudreaux Included inspection dates on Amerada Hess pipelines and included new asset inspection for Wilmington 10” pipeline. 12/15/05 Intro Tim Boudreaux Included Applicability Statement. 1/1/07 List Tim Boudreaux Updated list for 2006 completed inspections. 01/01/08 Reviewed, no changes 12/18/08 2.3 Tim Boudreaux Modified Consent Decree Specific. 12/18/08 4.4 Tim Boudreaux Updated List of navigable inspections. 01/01/09 Tim Boudreaux Annual Review with no changes. 9/01/09 2.2 Tim Boudreaux Deleted Longhorn 9/01/09 4.4 Tim Boudreaux Updated list of navigable inspections 9/01/09 5.1 Tim Boudreaux Deleted Longhorn 9/01/09 Tim Boudreaux Annual Review with changes listed above 01/01/11 Reviewed, no changes 09/02/11 3.1.1 Dennis Vasicek Added sentence regarding Pipeline Integrity Coordinator’s annual review of list of navigable river crossings 09/02/11 4.4 Dennis Vasicek Added 18th Street to Riverside 8” crossing of the Missouri River and Texas City to Pasadena 18” crossing of Clear Lake 09/02/11 4.4 Dennis Vasicek Updated inspection dates 12/31/11 All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. EARTH MOVEMENT INSPECTION PROCEDURE 7.05–ADM–020 Asset Integrity 01/01/10 Revision: 3 Page 1 of 3 1.0 PURPOSE 1.1 The purpose of this procedure is to establish a standardized method for the investigation and monitoring of areas of the pipeline identified as having high susceptibility to earth movement or where earth movement has been identified. E: Characterizing an area, as having high susceptibility to earth movement does not imply certainty that earth movement will occur or that earth movement is not possible outside an area of high susceptibility. 2.0 SCOPE 2.1 2.2 2.3 This procedure is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be utilized in whole or part on nonjurisdictional assets as deemed appropriate. Assets covered per Mitigation Plan: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, This pipeline operates under the requirements of the Mitigation Plan. Consent Decree Specific: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, the Company’s Consent Decree Pipeline Systems operate under the requirements of the Consent Decree (see Consent Decree for applicable programs. 3.0 PROCEDURE 3.1 Identifying Areas for Inspection. Specific pipeline segments may have regulatory requirements outside DOT 49 CFR. Please refer to those specific Plans for their individual requirements, as listed above in Applicability. 3.1.1 Identify areas to be inspected as defined by the Earth Movement Section of the Depth of Cover Program. 3.2 below. 3.2.1 Select the appropriate inspection method using the guidelines established in 3.2.1 and 3.2.2 3.3 3.4 3.5 Use aerial patrol for inspection and monitoring of areas with high susceptibility to earth movement. If aerial patrol is the selected inspection method go to 3.3 below. 3.2.2 Use close visual inspection in areas where earth movement has been identified. If close visual inspection is the selected inspection method go to 3.4 below. Performing Inspection and Monitoring Utilizing Aerial Patrol 3.3.1 Conduct aerial patrol in accordance with the Inspection of Right‐of‐Way Procedure. Pay particular attention, within the target area, to signs or indicators of earth movement or subsidence such as ground cracks, sink holes, erosion, heaving, buckling, etc. 3.4.1 If earth movement is identified go to 3.5 below otherwise go to 3.6 below. Performing Inspection and Monitoring Utilizing Close Visual Inspection <<>> Magellan Midstream Partners, L.P. EARTH MOVEMENT INSPECTION PROCEDURE 7.05–ADM–020 Asset Integrity 01/01/10 Revision: 3 Page 2 of 3 3.5.1 Conduct close visual inspection in accordance with the Inspection of Right‐Of‐Way Procedure. 3.5.2 Document the nature of the earth movement specifying the type of movement, extent of the affected area (length, width, depth), age, characteristics, soil type, etc. using both a written description and photography (where possible). 3.13.12 NOTE: Notify the appropriate Asset Integrity Engineer as soon as practical to discuss additional data requests and the next course of action. 3.6 Documentation 3.6.1 Use the Pipeline Maintenance Report to document any findings, with copies sent to the Asset Integrity Engineer for continued evaluation. 4.0 Definitions 4.1 4.2 Earth Movement: Unintended movement of the soil around the pipeline. High Susceptibility (to earth movement): An area along the pipeline identified through risk assessment as having a higher likelihood of earth movement as compared to other relative locations. 3.13.13 <<>> Magellan Midstream Partners, L.P. EARTH MOVEMENT INSPECTION PROCEDURE 7.05–ADM–020 Asset Integrity 01/01/10 Revision: 3 Page 3 of 3 System Integrity Plan Change Log Date CHANGE LOCATION Changed By Brief Description of Change 1/4/03 New Rick Wooldridge New Procedure 01/01/06 Applicability Tim Boudreaux Included language to direct to Longhorn and Shell specific requirements. 01/01/06 2.1.1 Tim Boudreaux Included: “Specific pipeline segments may have regulatory requirements outside DOT 49 CFR Parts 195 or Parts 192. Please refer to those specific Plans for their individual requirements, as listed above in Applicability”. Applicability 2.0 Changed to Scope 01/01/07 Reviewed, no changes 01/01/08 Reviewed, no changes 12/18/08 2.3 Tim Boudreaux Modified Consent Decree Specific. 01/01/09 Tim Boudreaux Annual Review with no changes. 9/03/09 2.2 Tim Boudreaux Removed Longhorn and Replaced with Assets covered per Mitigation Plan 9/03/09 4.3 Tim Boudreaux Removed Longhorn and Replaced with Assets covered per Mitigation Plan 9/03/09 Tim Boudreaux Annual Review with changes listed above 01/01/11 Reviewed, no changes 12/31/11 All 2012 Annual Review complete – no changes <<>> Magellan Midstream Partners, L.P. OVERHEAD PIPELINE CROSSING INTEGRITY PROCEDURE 7.05–ADM–030 Asset Integrity 01/01/12 Revision: 3 Page 1 of 6 1.0 Purpose 1.1 The purpose of this procedure is to effectively manage Overhead Pipeline Crossing maintenance through a comprehensive risk-based program which identifies risk reduction projects to improve structural component integrity and ultimately keep the product in the pipe. 2.0 SCOPE 2.1 2.2 2.3 Consent Decree Specific: : In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, the Company’s Consent Decree Pipeline Systems operate under the requirements of the Consent Decree. For the period of the Consent Decree, these systems will follow the applicable process and procedures (see Consent Decree for applicable programs). 3.0 PROcedure 3.1 This procedure is applicable to federal and/or state jurisdictional pipelines and/or facilities. The Manager of Asset Integrity may utilize elements of this program in whole or part on nonjurisdictional assets as deemed appropriate. Assets covered per Mitigation Plan: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, this pipeline operates under the requirements of the Mitigation Plan. The Overhead Pipeline Crossing Integrity Program will cover all above ground pipeline crossings, which are cable supported. This Inspection Procedure is structured in a cycle of four recurring categories: 3.1.1 Gather Data 3.1.1.1 3.1.1.2 Select the initial inspections based on historical knowledge of the condition of the structures using stakeholder, SME, risk data, and process efficiency information. Select subsequent inspections using risk data and further historical knowledge of the structures. The baseline inspections should be completed within six years and re‐inspections will be conducted on a timeframe based on the inspection findings and recommendations but not to exceed ten years from the previous inspection. Use the following three project‐specific standard forms for the overhead pipeline structure inspections. 3.1.1.2.1 Use the Basic Data Form to list all the relevant historical and geometrical information about the structure. Prior to the initial inspection, locate any available information on the structures so that as much information as possible may be filled out on the Basic Data Form. During the field inspection, this information should then be checked and the remainder of the information gathered. 3.1.1.2.2 Use the Inspection Report Form during the field inspection to evaluate and record the existing conditions of the components on the overhead pipeline structure. Each component listed is preceded by a box to be used for a rating number to evaluate the condition of the component and followed by a line to be used for a verbal description of any <<>> Magellan Midstream Partners, L.P. OVERHEAD PIPELINE CROSSING INTEGRITY PROCEDURE 7.05–ADM–030 Asset Integrity 01/01/12 Revision: 3 Page 2 of 6 3.1.1.3 3.1.1.4 problems encountered. 3.1.1.2.3 The Photo Log Sheet is used in the field to document photographs taken of the different overhead pipeline structures inspected. The development of a systematic method of inspection for each type of overhead pipeline structure is important. A well‐planned sequence will provide a working guide for the inspector and will ensure a systematic and thorough inspection of all components of the structure. For the overhead pipeline structure, the components of the structure should be inspected in the following order: 3.1.1.4.1 Foundations 3.1.1.4.2 Base plates and connections to foundations 3.1.1.4.3 Cable anchorage 3.1.1.4.4 Tower frames 3.1.1.4.5 Saddles 3.1.1.4.6 Main cable 3.1.1.4.7 Suspender cables 3.1.1.4.8 Pipe supports 3.1.1.4.9 Pipeline NOTE: There are other considerations observed during the inspection, which will be documented, such as: bank degradation, obvious flood levels, threatening outside forces (trees or other structures), right‐of‐way visibility/marking, public access and vandalism. 3.1.1.5 3.1.1.6 The thoroughness of an inspection is as important as the sequence. Use a checklist during the inspection to prevent the possibility of any components being overlooked. The Inspection Form can be used as a basic outline for the checklist. Complete full documentation reports for each inspection using the Overhead Inspection Basic Data Form, the Overhead Inspection Report Form and the Overhead Inspection Photo Log Sheet. Pipeline Integrity shall maintain these records for further analysis. 3.1.2 Analyze the Data 3.1.2.1 List all findings on the Inspection Report Form. Use the numerical rating system (see Table 1 below) to evaluate the condition of the components. The number best describing the component in the worst condition should be placed in the box next to the name of the component. Include a written description for clarification or further explanation. From this information the SME will make recommendations for maintenance repairs, completion time limits for making those repairs and a general cost estimate based on <<>> Magellan Midstream Partners, L.P. OVERHEAD PIPELINE CROSSING INTEGRITY PROCEDURE 7.05–ADM–030 Asset Integrity 01/01/12 Revision: 3 Page 3 of 6 “Rule of Thumb” estimates. Table 1 Rating Number Rating Description Rating Examples 6 Good Condition 5 Potential Problem 4 Minor Problem 3 Major Problem 2 Critical Problem There are no apparent problems Rust, corrosion or cracked foundation Loose bolts, cables, or spalled foundation Moderate structural cracking or repainting Major structural defects 3.1.2.2 Analyze the individual component ratings further and give weighted scores to achieve an overall Relative Risk Index. This will assist in our maintenance prioritization efforts. 3.1.2.3 Asset Integrity Personnel shall review, approve/reject or submit alternative recommendations. Repair recommendations will be risk ranked in accordance to criteria set forth in the Overhead Crossing Inspection Relative Risk Index Formula. 3.1.2.4 The DOC Coordinator will schedule the maintenance according to these recommendations and list them on the Annual Integrity Plan. 3.1.3 Develop The Mitigation Plan 3.1.3.1 The DOC Coordinator will assign a Project Manager to complete the maintenance work. The Project Manager will follow Project Life Cycle for completing the task. 3.1.3.2 The Project Manager shall follow the recommended maintenance schedule according to the annual integrity plan for repairs unless otherwise approved to proceed with any additional repairs, which would improve the integrity of the structure at a significant cost savings. 3.1.3.3 The Project Manager shall be responsible for all planning, estimating, contracting and execution of the maintenance repairs. 3.1.3.4 An AFE and Project Plan must be submitted and approved by the DOC Coordinator before any work may begin, unless the work needed is considered an emergency and immediate attention is necessary, in which a courtesy call to the DOC Coordinator is all that is required. The afe request and documentation of the work performed may follow the repair, in this case. During the plan development, consult with Area Operations, Asset Integrity Personnel and third party SME Resources. 3.1.4 Execute the Mitigation Plan 3.1.4.1 Following the approval of the project plan, the Project Manager may allocate resources and execute the Mitigation Plan while integrating in synergies with other MMP departments and programs. 4.0 OVERHEAD pipeline cROSSING Prioritization Guidelines <<>> Magellan Midstream Partners, L.P. OVERHEAD PIPELINE CROSSING INTEGRITY PROCEDURE 7.05–ADM–030 Asset Integrity 01/01/12 Revision: 3 Page 4 of 6 4.1.1.2 4.1 The Overhead Pipeline Crossing Integrity Program, along with any resulting mitigation initiatives, will be prioritized in accordance with the following guidelines: 4.1.1 Each structure will receive an initial risk prioritization number based on the Pipeline Risk Model. Factors that may influence the prioritization might be local historical knowledge of inferior structural conditions, past large water flow events, line strikes, near misses and HCA locations. 4.1.1.1 The first phase of the inspections will include the top 20% of the structures listed as highest risk according to the pipeline risk model. All other structures will follow in 20% groupings according to the risk model. 4.2 Following the Overhead Pipeline inspection, each structure will receive a relative risk index number. Maintenance will be performed on the structures that receive the lowest relative risk index score in accordance with the Integrity Management Plan (IMP). 5.0 Data Management and Initiative Implementation 5.1 Data initially obtained and periodically updated via the Overhead Pipeline Crossing Integrity Program will be centralized and maintained in a formal database. Pipeline Integrity will utilize the database as an input to its overall risk management process, which includes the relative risk assessment process. 5.2 Pipeline Integrity will further manage the recommendation and funding process associated with the implementation of this initiative. 6.0 REFERENCES 6.1 Regulatory – 49 CFR Part 195 – U.S. D.O.T. Pipeline Safety Regulations 6.2 Related Policies/Procedures 6.2.1 Pipeline Defect Evaluation and Repair Procedure 6.2.2 RSTRENG Analysis of Corrosion 6.2.3 6.2.4 Asbestos Safety Procedure 6.2.5 Excavation Safety Procedure 6.2.6 Welding and Radiographic Procedures 6.2.7 Specification 100—Construction And Fabrication Of Pipelines And Related Piping Systems 6.2.8 6.3 Forms and Attachments 6.3.1 Pipeline Maintenance Report 6.3.2 6.3.3 6.3.4 Coatings – Selection, Applications and Maintenance Specification 101—Maintenance Welding (Excluding Ethylene Pipelines) Prioritization for Exposed Pipe (Flow Chart) Prioritization for Shallow Pipe (Flow Chart) Shallow Pipe Resolution Process (Flow Chart) <<>> Magellan Midstream Partners, L.P. OVERHEAD PIPELINE CROSSING INTEGRITY PROCEDURE 7.05–ADM–030 Asset Integrity 01/01/12 Revision: 3 Page 5 of 6 7.0 DEFINITIONS 7.1 Stakeholder: Any person or group directly involved with this initiative. 7.2 SME: Subject Matter Expert. 7.3 7.4 7.5 7.6 7.7 7.8 7.9 Risk Data: Furnished by the Risk Assessment Group for specific pipeline segments. Process Efficiencies: Planning optimization of time, materials, labor and funding. Basic Data Form: A standard form to list the relevant historical and geometrical information about the structure. Inspection Report Form: A standard form used during the field inspection to evaluate and record the existing conditions of the components. Photo Log Sheet: A standard form for documenting and organizing photos taken at the inspection site. Rule of Thumb Estimates: Standard costs associated to specific work in the pipeline industry, as an average. It is not region specific. Relative Risk Index Formula: Process by which all component ratings are correlated to give a final overall Risk Score to assist with process management. <<>> Magellan Midstream Partners, L.P. OVERHEAD PIPELINE CROSSING INTEGRITY PROCEDURE 7.05–ADM–030 Asset Integrity 01/01/12 Revision: 3 Page 6 of 6 System Integrity Plan Change Log Date Change Location Change By Brief Description of Change 1/31/05 All Tim Boudreaux New Procedure 01/01/07 Reviewed, no changes 01/01/08 Reviewed, no changes 12/17/08 2.1 Tim Boudreaux Eliminated redundant sentence. 12/17/08 2.2 Tim Boudreaux Modified Consent Decree Specific. 12/17/08 5.1, 5.2 and 5.3 Tim Boudreaux Removed link for Data record sheet, inspection report and photo log sheet. 01/01/09 Tim Boudreaux Annual Review with no changes made. 9/03/09 2.2 Tim Boudreaux Deleted Longhorn and changed to Assets covered per Mitigation Plan 9/03/09 Tim Boudreaux Annual Review with changes listed above 01/01/11 Reviewed, no changes 09/02/11 3.1.1.1 Dennis Vasicek Revised third sentence to, “The baseline inspections should be completed within six years and re‐inspections will be conducted on a timeframe based on the inspection findings and recommendations but not to exceed ten years from the previous inspection.” 12/31/11 All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. ASSETS COVERED PER MITIGATION PLAN RIGHT‐OF‐WAY INSPECTION PROCEDURE 7.05–ADM–031 Asset Integrity 01/01/12 Revision: 10 Page 1 of 5 1.0 PURPOSE 1.1 The purpose of this procedure is to address specific requirements of the Mitigation Plan related to inspection of the surface conditions on or adjacent to each pipeline right‐of‐way (ROW). This document is to be utilized along with the Magellan Midstream Partners, L.P. Inspection of Right of Way Procedure. 2.0 PROCEDURE NOTE: Persons performing inspection shall comply with all state and federal laws, rules, regulations, statutes, ordinances or codes and Mitigation Commitments as may be required. In its contracts with inspection contractors, the Company shall identify requirements specifically related to the petroleum industry. It shall be the obligation of such contractors to comply and maintain appropriate records 2.1 Methods of Inspection 2.1.1 Aerial Patrol: As described below and in Inspection of Right of Way Procedure. 2.1.2 Ground Patrol: As described below and in Inspection of Right of Way Procedure. Also Refer to the guidelines in the Threatened and Endangered Species Avoidance And Minimization Timing Restrictions. 2.2 Patrol Requirements 2.2.1.4 Edwards Aquifer Recharge Zone – Daily (once per week shall be a ground‐level patrol) 2.3 2.2.1 The specified frequency of surveillance shall meet the following requirements: 2.2.1.1 Tier 1 Areas – Once a week, not to exceed 12 days, but at least 52 times per year 2.2.1.2 Tiers 2 and 3 Areas – Every two and one‐half (2.5) days, not to exceed 72 hours 2.2.1.3 Aerial and ground surveillance frequency will be increased across Tier II (Sensitive) and Tier III (Hypersensitive) areas when the threat of flooding and/or severe erosion is identified near the pipeline right‐of‐way. Aerial Patrol and Ground Patrol Notification 2.3.1 Patrol Pilots will be required to contact the Austin Operations Office each morning to communicate the ability to fly or not to fly, “No‐Fly”, their identified patrol segments. Segments are identified as follows: 2.3.1.1 LP 301 Galena Park to Pecos River (MP 0 – MP 528) 2.3.1.2 LP 303 Crane to El Paso (MP 457 – MP 695), Crane to Odessa (MP 0 – MP 28) and El Paso to El Paso Jct. (MP 0 – 10) 2.3.1.3 Austin Operation Office will record notification of flight and await completed Right‐ of‐Way Patrol Report by Aerial/Ground form. 2.3.1.4 The Austin FOA will record each patrol on a patrol tracking spreadsheet to insure the required number of flights are made and file with monthly reports. 2.3.1.5 Upon receipt of the Right‐of‐Way Patrol Report by Aerial/Ground form. The One Call Group will create a One Call ticket and the field locator will respond to the Aerial Patrol in Ticket View. 2.3.1.6 Right‐of‐Way (ROW) Inspection Report will be sent to Austin Operations Office and the One Call Group at the end of the flight day or within 12 hours of flight <<>> Magellan Midstream Partners, L.P. ASSETS COVERED PER MITIGATION PLAN RIGHT‐OF‐WAY INSPECTION PROCEDURE 7.05–ADM–031 Asset Integrity 01/01/12 Revision: 10 Page 2 of 5 2.3.1.7 completion. All emergency sightings by pilot will be called into the Company One‐Call Center. The Company One‐Call Center will send to the field as an emergency ticket under the heading A/P (Aerial Patrol). All A/P emergency tickets will be responded to immediately by field personnel. Non‐emergency sightings will be reported on Right‐ of‐Way Patrol Report by Aerial/Ground form and responded to within 3 working days and documented by the appropriate personnel upon receipt of the report. NOTE: Daily patrols of these segments shall continue until confirmation of flight by the Patrol Pilot has been received. 2.3.2 2.3.3 Each and every morning, the person on call will contact the Austin Area Office message center by calling 1‐ 512‐394‐4099, enter mail box number of 4044, and the password of 404400 and verify the pilots ability to patrol there segment. If a no fly is reported an alert will be issued to personnel to be prepared for ground patrol procedures. First Level Each area COM will maintain a list of personnel designated to patrol a section of the Tier 2 and 3 segments in their area and provide that person with the required maps and other information that will describe in detail the patrol section On the morning of the second day of notification of “No‐Fly” from the patrol pilot, personnel will be instructed to proceed with Second Level Procedures. Second Level Procedure – Tier 2 and 3 segments shall be initiated. The required notification will be made to the ground patrol personnel and unless notified other wise will begin patrol of the assigned area the next morning. All sightings that can not be dealt with at the time will be called to One Call. Second Level segments need to be completed within one and one‐ half (1.5) days of the second day notification and sightings will be recorded on Right‐of‐Way Patrol Report By Aerial/Ground form. 2.3.4 On the morning of the fifth consecutive day of notification from the Patrol Pilot of “No‐Fly”, Third Level Procedures will be initiated. Third Level Procedures – Tier 1 areas shall be initiated. Each area COM will maintain a list of personnel designated to patrol a section of the Tier 1 segments in there area and provide that person with the required maps and other information that will describe in detail the patrol section. The required notification will be made to the ground patrol personnel and unless notified other wise will begin patrol of the assigned area the next morning. All sightings that can not be dealt with at that time will be called to One Call. Second Level segments need to be completed within one and one‐half (1.5) days of the second day notification and sightings will be recorded on Right‐of‐Way Patrol Report By Aerial/Ground form. 2.4 Ground Patrol Observation 2.4.1 Ground Patrol personnel patrolling the right of way need to observe Conditions that may adversely affect the safe operating condition of the pipeline system. Observations need to be documented for continued inspection, maintenance or repair activities. Observations shall be documented on the following forms. 2.4.1.1 Right‐of‐Way (ROW) Inspection Report: Marking repairs, erosion, cathodic 2.4.1.2 2.4.1.3 2.4.1.4 2.4.2 Inspection observations that should be included in the patrol are listed below: protection issues and span conditions Right‐of‐Way Patrol Report By Aerial/Ground Form: Document the section inspected for Department of Transportation (DOT) compliance Pipeline Maintenance Report: Leak, corrosion, pipe and erosion repairs Encroachment Agreement (Short Form): Third party crossings on the ROW <<>> Magellan Midstream Partners, L.P. ASSETS COVERED PER MITIGATION PLAN RIGHT‐OF‐WAY INSPECTION PROCEDURE 7.05–ADM–031 Asset Integrity 01/01/12 Revision: 10 Page 3 of 5 2.4.2.1 2.4.2.2 2.4.2.3 2.4.2.4 2.4.2.5 2.4.2.6 Erosion: Creek, ravines, sink holes, exposed pipe/spans and agricultural land Right‐of‐Way: Clearing/mowing, marking condition and spacing, over‐hanging trees and gate needs Third Party Activity: Dozer, trenching, boring, building construction or fencing activities on or near the ROW Leak Indications: Vapors, odor, dead vegetation, rainbow on water or stains on piping or valves. Vent pipes at road crossings should be inspected for the presents of vapors. Pipe Damage: Indication of coating damage (paint or other protective coating) or pipe damage at exposures or spans. Spans need to be inspected to determine any pipe deviation or denting from previous patrols. Cathodic Protection: Inspect test leads (conduit and face plates) and rectifier locations for visible damage to the rectifier or third activity in the anode field. Verify Anode Field Schematics are available inside the rectifier. 2.4.3 Reporting 2.4.3.1 During each patrol, emergency situations identified during aerial or ground surveillance will be immediately reported to the designated Pipeline Control Center. Aerial Patrol personnel shall remain at report location until otherwise instructed by Operation. All surveillance personnel and line spotters will be trained and certified in Occupational Safety and Health Administration (OSHA) Hazardous Waste Operations and Emergency Response Standard (HAZWOPER) to the first responder level. 2.5 Ground Patrols (Special Conditions) 2.5.1 Several areas have been identified as requiring ground based patrols. These areas will be patrolled at the intervals specified until circumstances warrant a change in the need for ground‐based patrol or the patrol frequency. 2.5.2 Patrol Method 2.5.2.1 not be dealt with at that time will be called to One Call. 2.5.2.2 Silver Mountain Road – Special Containment Inspection:  An area from milepost 174.09 to 174.94, FM 1826 through Silver Mountain Road has been cased with High Density Polyethylene (HDPE) pipe. This casing requires  Various methods may be used to conduct a ground‐based patrol. The method used will be driven by surface conditions, equipment availability and the extensive nature of the patrol. All terrain vehicles, pickup trucks or walking may be used as each situation warrants. Edwards Aquifer Recharge Zone – Austin  Daily patrols of the Edwards Aquifer Recharge Zone, from Brodie Lane to Slaughter Lane, milepost 169.79 to 173.64, are required with one (1) ground based patrol each week. Geology in this area is known to be highly porous and provides ready access to the aquifer from surface runoff or a hydrocarbon spill. Patroller will complete Right‐of‐Way Patrol Report by Aerial/Ground form. All sightings that can <<>> Magellan Midstream Partners, L.P. ASSETS COVERED PER MITIGATION PLAN RIGHT‐OF‐WAY INSPECTION PROCEDURE 7.05–ADM–031 Asset Integrity 01/01/12 Revision: 10 Page 4 of 5 weekly inspection for water infiltration and the presence of hydrocarbon vapors. Refer to HDPE Inspection and Dewatering procedure. Document the inspection and file the documentation in accordance with Section 3.0 of this procedure. 2.5.3 3.0 RECORDS 3.1 Written Pilot Reports 3.2 3.1.1 Pilots shall make a written report using the Right‐of‐Way Patrol Report By Aerial/Ground form of all specified and other material observations as soon as practical following each flight, but in no case more than 12 hours of flight completion with all required information: 3.1.1.1 Date of inspection 3.1.1.2 Name of person conducting the inspection 3.1.1.3 Identification of the pipeline(s), line section or right‐of‐way segment 3.1.1.4 Location of the observations by mile post number 3.1.1.5 Description of observation 3.1.1.6 Identity of Company staff, date and time (If observation was verbally reported to Operations Control) Company Action Taken and Recordkeeping 3.2.1 Employees shall take appropriate action, respond to pilot observations within 3 business days of pilot report and maintain a record of such response. Such disposition records shall reference or be linked to the report of the pilot and indicate as is applicable: 3.2.1.1 Date initially investigated by company personnel 3.2.1.2 What action was taken or will be taken 3.2.1.3 The status or disposition of the item observed or if the observation is or is not a relevant action item 3.2.1.4 All “Non‐Emergency” observations will be responded to in One Call Ticket View within 3 working days of aerial patrol. 3.2.1.5 Date each reported observation is resolved 3.2.1.5.1 Non‐Emergency sightings and comments will be evaluated by aerial patrol for removal. 3.2.1.5.2 With respect to observations that were previously reported, it is not necessary to reinspect and generate a new report, provided there is not a material change in the status or risk of the reported observation. 3.2.1.5.3 Records of the pilot observation and Company action taken shall be maintained for a period of two (2) years or until the next regulatory agency inspection, whichever is longer. <<>> Magellan Midstream Partners, L.P. ASSETS COVERED PER MITIGATION PLAN RIGHT‐OF‐WAY INSPECTION PROCEDURE 7.05–ADM–031 Asset Integrity 01/01/12 Revision: 10 Page 5 of 5 Date Change Location 12/15/2005 1.0, 3.0 and 6.0 01/01/2006 01/01/2007 01/01/2008 06/03/2008 2.3.1.7 & 2.3.1.8 01/01/2009 03/31/2009 2.2.1.3 03/31/2009 2.3.1.1 03/31/2009 2.3.1.7 03/31/2009 3.2.1 03/31/2009 3.2.1.3.1 4/29/09 2.5.2.3 4/29/09 2.5.2.4 9/03/09 header 9/03/09 2.4.3.1 9/03/09 3/4/10 2.4.3.1 01/01/11 12/31/11 All System Integrity Plan Change Log Brief Description of Change Included link to “Inspection of Right of Way procedure” Deleted references section Reviewed, no changes Reviewed, no changes Added “emergency”. Annual Review with no changes. Changed to 2.2.1.4 and added new 2.2.1.3 Changed flight segment - extended to Pecos River Added “within 3 working days” and added requirement to put one-call ticket number on aerial patrol form Added “within 3 business days of pilot report” Added section Boggy Creek ROW Cleared. Visible to aerial patrol. Daily foot patrol discontinued. Removed this section. Re-numbered due to removal of Boggy Creek Changed Longhorn Specific to Assets covered per Mitigation Plan, date and revision number Changed Longhorn to Assets covered per Mitigation Plan Annual Review with changes listed above Changed “assets covered by mitigation plan” to designated pipeline center – not a version change Reviewed, no changes 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. HOUSTON‐EL PASO SPECIFIC HDPE INSPECTION AND DEWATERING PROCEDURE 7.05‐ADM‐037 Asset Integrity 01/01/10 Revision: 1 Page 1 of 5 1.0 PURPOSE 1.1 The purpose of this procedure is to outline the steps required to ensure the double cased section of the Houston–El Paso Pipeline remains free of water. 2.0 DESCRIPTION 2.1 Compliance with this procedure is the responsibility of the Area Supervisor who is accountable for the geographic area of pipelines unless such responsibilities are otherwise delegated in writing. 2.2 Once per calendar year, not to exceed 15 months between events, the Environmental Specialist shall collect a sample of any water collected in the HDPE sections and have them analyzed for any constituents of concern. 3.0 PROCEDURE 3.1 3.1.1 Frequency of High Density Polyethylene (HDPE) Pipe Inspections: Inspect both sections of the HDPE pipe at weekly intervals not to exceed 10 days and following any rainfall event in excess of 0.1 inches, for the presence of water and hydrocarbon vapors. 3.2 Description of HDPE Areas: NOTE: The ball valves on top of the drain pipes are to be locked in the closed position at all times when not in use. 3.2.1 Two sections of HDPE encased pipe are present on the Houston–El Paso Pipeline in Travis County, Texas. The “East Section” runs from ESN 9192+16 to 9198+90. The “West Section” runs from ESN 9214+95 to 9236+95. Both HDPE sections have two‐inch drain pipes located at the topographically lowest points of the HDPE encased section. These drain pipes serve as the point to inspect for water accumulation in the HDPE casing and also for dewatering. 3.2.2 The total depth of each drain pipe is embossed on a stainless steel tag affixed to the two‐inch ball valve. 3.3 Special Considerations: 3.3.1 No avoidance periods or timing restrictions are applicable for any endangered species in the HDPE areas. 3.3.2 Limit travel to and from the HDPE areas to the right‐of‐way (ROW) unless permission for alternative means of ingress or egress has been granted by the landowner. 3.3.3 Conduct all work during normal business hours and avoid excessive noise and travel when possible because the HDPE areas of the Houston‐El Paso Pipeline are in close proximity to residences. 3.4 HDPE Inspection for the presence of hydrocarbon: 3.4.1 Tools/Equipment needed: 3.4.1.1 Houston–El Paso Master Key. 3.4.1.2 HDPE Inspection Form. 3.4.1.3 LEL Meter. <<>> Magellan Midstream Partners, L.P. HOUSTON‐EL PASO SPECIFIC HDPE INSPECTION AND DEWATERING PROCEDURE 7.05‐ADM‐037 Asset Integrity 01/01/10 Revision: 1 Page 2 of 5 3.4.2 3.4.3 3.4.4 Remove the lids on pull boxes 35A, 36A, 39 and 42C. In each pull box on top of the 8” flange, unlock and open the 1” ball valve. Using an LEL Meter, sample the air inside the HDPE section for the presence of hydrocarbon vapor. NOTE: If a hydrocarbon odor is detected, immediately contact Operations Control at (888) 465‐9512 and your immediate supervisor. Do not proceed with the remainder of the procedure. 3.5 3.4.5 Record the results of the LEL Meter on the HDPE Inspection Form HDPE Inspection for the presence of water: 3.5.1 Tools/Equipment needed: 3.5.2 3.5.3 3.5.1.1 Houston–El Paso Master Key. 3.5.1.2 Solinst Model “Mini 101” water level meter. 3.5.1.3 HDPE Inspection Form. 3.5.1.4 Dewatering Pump. Turn the water level meter on and perform a battery test to ensure the meter is operable. Fully open the two ball valves and determine if a hydrocarbon odor is present. NOTE: If a hydrocarbon odor is detected, immediately contact Operations Control at (888) 465‐9512 and your immediate supervisor. Do not proceed with the remainder of the procedure. 3.5.4 Lower the water level meter tape down the drain pipe until the probe touches the bottom of the drain pipe or the audible alarm on the water level meter sounds. 3.5.5 If the audible alarm on the water level meter sounds, take the measurement of the depth to water and compare it to the total depth of the stand pipe embossed on the stainless steel tag. If the difference between the total depth of the stand pipe and the depth to water exceeds 4‐inches, proceed to the dewatering procedure outlined below. 3.5.6 Record the findings of the HDPE Inspection on the HDPE Inspection Form. 3.6 Dewatering: 3.6.1 Tools/Equipment needed: 3.6.1.1 Dewatering Pump. 3.6.1.2 Solinst Model “Mini 101” water level meter. 3.6.1.3 HDPE Inspection Form. 3.6.1.4 LEL Meter. 3.6.1.5 Supply of sorbent pads. 3.6.2 Dewatering Guidelines: <<>> Magellan Midstream Partners, L.P. HOUSTON‐EL PASO SPECIFIC HDPE INSPECTION AND DEWATERING PROCEDURE 7.05‐ADM‐037 Asset Integrity 01/01/10 Page 3 of 5 3.6.2.1 3.6.2.2 Revision: 1 Secure a water filter sock to the end of the pump discharge line when dewatering each HDPE section. Route the discharge line should to a vegetated area on the ROW such that discharged water does not enter any surface water. CAUTION: Always use caution when operating any electrical source near water. Inspect the power cable on the pump for nicks or abrasions before every use. Take care to direct the discharge water away from the generator and prevent the water from pooling in the immediate work area. 3.6.3 Dewatering the east HDPE section: NOTE: It is critical that all vent valves be fully open prior to initiating the dewatering procedure. Failure to do so will result in damage to the HDPE end seals. 3.6.3.1 3.6.3.2 3.6.3.3 3.6.3.4 3.6.3.5 3.6.3.6 3.6.3.7 3.6.3.8 Open the ½‐inch ball valve at HDPE risers 35A and 36A. Open drain line “East 1” (ESN 9196+22). Connect the pump to the two‐inch drain line and place sorbent pads at the discharge end of pump for visual verification of product. Start pump and monitor the discharge to ensure continuous flow. When the pump no longer has a steady discharge, turn the pump “OFF” and wait approximately three minutes for additional water to collect in the drain pipe. Restart the pump and continue to dewater until a steady stream is no longer present. Remove the pump from the two‐inch drain pipe and use the water level meter to verify that less than four inches of water remain in the drain pipe. If greater than four inches of water remain, repeat the dewatering procedure until less than four inches of water remains. Record the pump run time and the estimated volume of water removed on the HDPE Inspection Form. 3.6.4 3.6.3.9 Close the two‐inch drain valve and ½‐inch ball valves at risers 35A and 36A and secure with a Houston–El Paso padlock. Dewatering the west HDPE section: NOTE: It is critical that all vent valves be fully open prior to initiating the dewatering procedure. Failure to do so will result in damage to the HDPE end seals. 3.6.4.1 3.6.4.2 Open the two‐inch valve on drain pipes “West 1” (ESN 9221+22) and “West 2” (ESN 9227+37). Open the ½‐inch ball valves at HDPE risers 39 and 42 and 42C. <<>> Magellan Midstream Partners, L.P. HOUSTON‐EL PASO SPECIFIC HDPE INSPECTION AND DEWATERING PROCEDURE 7.05‐ADM‐037 Asset Integrity 01/01/10 Page 4 of 5 3.6.4.3 3.6.4.4 3.6.4.5 3.6.4.6 3.6.4.7 Revision: 1 Turn the pump to the “ON” position and monitor the pump discharge to ensure continuous flow. When the pump no longer has a steady discharge, turn the pump “OFF” and wait approximately three minutes for additional water to collect in the drain pipe. Restart the pump and continue to dewater until a steady stream is no longer present. Remove the pump from the drain pipe and use the water level meter to verify that less than four inches of water remain in the drain pipe. If greater than four inches of water remain, repeat the dewatering procedure until less than four inches of water remains. Record the pump run time and the estimated volume of water removed on the HDPE Inspection Form. 3.6.4.8 3.6.4.9 Repeat 3.6.4.3 – 3.6.4.7 of this procedure on the “West 2” drain pipe. Close the two‐inch drain valve and ½‐inch ball valves at risers 39, 42 and 42C and secure with a Houston–El Paso padlock. <<>> Magellan Midstream Partners, L.P. HOUSTON‐EL PASO SPECIFIC HDPE INSPECTION AND DEWATERING PROCEDURE 7.05‐ADM‐037 Asset Integrity 01/01/10 Revision: 1 Page 5 of 5 System Integrity Plan Change Log Date Change Location Brief Description of Change 4/1/08 All new 1/1/09 2008 annual review complete – no changes 01/01/10 Reviewed, no changes 2/1/10 4.0 Updated and corrected – not a version change 01/01/11 Reviewed, no changes <<>> Magellan Midstream Partners, L.P. FLOOD CONDITIONS PROCEDURE 7.05‐ADM‐039 Asset Integrity 1/01/12 Revision: 0 Page 1 of 4 3.13.14 PURPOSE The purpose of this procedure is to provide a standardized method for continued surveillance due to severe flooding conditions on mainline piping at water crossings. 3.13.15 SCOPE The severe flooding conditions will trigger Field Personnel to direct their resources in a manner that will enable them to determine the potential effects of flooding on the pipeline system. 3.13.16 Procedure The Asset Locator shall:  Watch for the potential for damage to the pipeline caused by flooding and report it to the Pipeline Integrity Coordinator.  Report evaluations of the pipeline to the Pipeline Integrity Coordinator.  Coordinate their responses to flood conditions with Pipeline Integrity Coordinator. The Pipeline Integrity Coordinator shall:  Distribute the attached form to the affected stakeholders and obtain the data for updates to management.  Evaluate the accessibility of pipeline facilities that may be in jeopardy, such as valve settings, which are needed to isolate water crossings or other sections of a pipeline.  Extend regulator vents and relief stacks above the level of anticipated flooding, as appropriate for Natural Gas lines.  Coordinate with emergency and spill responders on pipeline locations and condition. Provide maps and other relevant information to such responders.  Consider deploying personnel so that they will be in position to take emergency actions, such as shut down, isolation, or containment. List appropriate personnel or contractors that may respond, identify the point of contact or the QI.  Determine if facilities that are normally above ground (e.g., valves, regulators, relief sets, etc) have become submerged and are in danger of being struck by vessels or debris; if possible, such facilities should be marked with an appropriate buoy with Coast Guard approval.  Perform frequent patrols, including appropriate over flights, to evaluate right-of way conditions at water crossings during flooding and after waters subside. Determine if flooding has exposed or undermined pipelines as a result of new river channels cut by the flooding or by erosion or scouring.  Perform surveys to determine the depth of cover over pipelines and the condition of any exposed pipelines, such as those crossing scour holes. Information gathered by these surveys should be shared with affected landowners. Agricultural agencies may help to inform farmers of the potential hazard from reduced cover over pipelines. Where appropriate, surveys of underwater pipe should include the use of visual inspection by divers or instrumented detection.  Ensure that line markers are still in place or replaced in a timely manner. Notify contractors, highway departments, and other involved in post-flood restoration activities of the presence of pipelines and the risks posed by reduced cover. The Compliance Coordinator shall: Advise the appropriate PHMSA Regional Office or State Pipeline safety authority if a pipeline has suffered damage, is shut-in, or is being operated at a reduced pressure as a precautionary measure as a result of flooding, before returning the line to service, increasing its operating pressure, or otherwise changing its operating status. PHMSA or the state will review all available information and advise the operator, on a case by case basis, whether and to what extent a line can safely be returned to full service. <<>> Magellan Midstream Partners, L.P. FLOOD CONDITIONS PROCEDURE 7.05‐ADM‐039 Asset Integrity 1/01/12 Revision: 0 Page 2 of 4 MAINLINE FLOODING COMPLIANCE FORM COMPLETED BY: DATE COMPLETED: LINE SECTION NAME: FLOOD AREA: SECTION 1: TASKS 1. FLOOD TYPE (COMPLETE QUESTIONS 1‐10) 1. ARE THE PIPELINE FACILITIES ACCESSIBLE? YES NO 2. ARE VALVE SETTINGS ACCESSIBLE? YES NO 3. HAS PERSONNEL BEEN DEPLOYED TO BE IN POSITION TO TAKE EMERGENCY ACTIONS, SUCH AS SHUT DOWN, ISOLATION, OR CONTAINMENT? YES NO 4. HAVE FACILITIES THAT ARE NORMALLY ABOVE GROUND BECOME SUBMERGED AND IN DANGER OF BEING STRUCK BY A VESSEL OR DEBRIS? YES NO 5. HAS A MORE FREQUENT PATROL PROGRAM BEEN INITIATED? YES NO 6. HAS COMMUNICATION TO THE EMERGENCY AND SPILL RESPONDERS OF PIPELINE LOCATIONS AND CONDITIONS TAKEN PLACE? (NOTE BELOW IF MAPS AND PIPELINE INFORMATION WERE GIVEN) YES NO 7. CAN IT BE DETERMINED IF THE PIPELINE IS EXPOSED OR UNDERMINED AS A RESULT OF FLOODING, EROSION OR SCOURING? YES NO 8. ARE UNDERWATER SURVEYS BEING PERFORMED TO DETERMINE DEPTH OF COVER OVER PIPELINES DURING FLOODING CONDITIONS OF EXPOSED PIPELINES, SUCH AS THOSE CROSSING SCOUR HOLES? YES NO 9. ARE THE PIPELINE MARKERS STILL IN PLACE? YES NO 10. HAS INFORMATION OBTAINED DURING SURVEY BEEN SHARED WITH AFFECTED LANDOWNERS IN AREAS WHERE COVER MAY HAVE BEEN REMOVED OVER THE PIPELINE? POST FLOOD ? YES NO 2. ARE ADDITIONAL PREVENTATIVE OR MITIGATIVE MEASURES RECOMMENDED TO PREVENT A RELEASE OR DRAINAGE FROM A FLOODED AREA? (COMPLETE THE DISCUSSION SECTION WITH COMMENTARY AND CONSIDERATION FOR THE BELOW RISK FACTORS)  GENERAL PROFILE/TERRAIN OF THE AREA SURROUNDING THE PIPELINE  SURVEYS OF UNDERWATER PIPE / VISUAL INSPECTION BY DIVERS OR INSTRUMENTED DETECTION N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A <<>> Magellan Midstream Partners, L.P. FLOOD CONDITIONS PROCEDURE 7.05‐ADM‐039 Asset Integrity 1/01/12 Revision: 0 Page 3 of 4 SECTION 1: TASKS  CHARACTERISTICS OF THE PRODUCT TRANSPORTED  AMOUNT OF PRODUCT THAT COULD BE RELEASED  THE SWIFTNESS OF LEAK DETECTION AND SHUTDOWN CAPABILITIES INCLUDING THE LOCATION OF RESPONSE PERSONNEL  THE POTENTIAL RATE AND VOLUME OF LEAKAGE  THE POTENTIAL FOR PRODUCT TO REACH AN IGNITION SOURCE  DAMAGED LINE, SHUT IN OR OPERATIONS AT A REDUCED PRESSURE AS A PRECAUTIONARY MEASURE AS A RESULT OF FLOODING, REQUIRE ADVISING THE PHMSA REGIONAL OFFICE OR STATE PIPELINE SAFETY AUTHORITY BEFORE RETURNING THE LINE TO SERVICE, INCREASING THE OPERATING PRESSURE OR CHANGING ITS OPERATING STATUS. DISCUSSION OR COMMENTS: <<>> Magellan Midstream Partners, L.P. FLOOD CONDITIONS PROCEDURE 7.05‐ADM‐039 Asset Integrity 1/01/12 Revision: 0 Page 4 of 4 SIP CHANGE LOG Date Change Location Brief Description of Change 1/1/12 new <<>> Magellan Midstream Partners, L.P. EVAULATING OPERATING PRESSURES 7.07.002 Asset Integrity Page 1 of 3 <<>> Magellan Midstream Partners, L.P. EVAULATING OPERATING PRESSURES 7.07.002 Asset Integrity Page 2 of 3 <<>> Magellan Midstream Partners, L.P. EVAULATING OPERATING PRESSURES Asset Integrity 7.07.002 Page 3 of 3 <<>> Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Revision: 9 Page 1 of 8 1.0 OBJECTIVE 1.1 2.0 DESCRIPTION 2.1 3.0 STANDARDS The objective of this initiative is to provide a framework that complies with the security regulations governing the Company and that protects the assets, employees, the environment, stakeholders and the community from security threats. This initiative incorporates the security requirements required by regulations applicable to Company assets and operations. The Company will follow the landlord’s policies for security in the Bank of Oklahoma (BOK) Tower located in Tulsa, Oklahoma. At any other leased and/or rented office space(s) the landlord’s policies will provide the minimum security requirements for that office space. Without Exception, Personnel Safety Is the First Priority. 3.1 The Director of Environmental, Health, Safety & Security (EHS&S) shall: 3.1.1 3.1.2 Serve as the Company Corporate Security Officer. Establish a Security Management Team (SMT) responsible for ensuring Company security awareness to employees and implementing security measures at the workplace, as needed. Convene as needed to address security‐related topics/incidents. Notify the SMT within 24 hours of any security incident at a Company asset, to include a summary of notifications made and actions taken. Maintain Minimum Physical Security Standards for Company assets. 3.1.3 3.1.4 3.1.5 Annually review the notification information in the Security Events Procedure. 3.1.6 Annually review the Company asset list with the SMT to validate the Company DOT Critical List. 3.1.7 Annually update Company contact information to the Transportation Security Administration (TSA) and the Office of Pipeline Safety (OPS) for execution of notification protocols by each agency, as required. 3.2 The Operations Supervisor shall: 3.2.1 Develop, maintain and comply with the Facility Security Plan (FSP) using the Facility Security Plan (Nonmarine) Template for facilities that have a loading rack and/or other loading area(s) (i.e., butane/ethanol/biodiesel), and facilities that ship loads of more than 792 gallons of hazardous liquids. Complete a Facility Vulnerability Assessment (FVA) template prior to the development of the FSP. Address any vulnerability identified by the FVA in the FSP. 3.2.1.1 Develop a FVA/FSP for any newly purchased loading rack/loading area facilities within 60 days of purchase. NOTE: The FSP for each marine facility will be developed on a site specific basis and should comply with all United States Coast Guard (USCG) requirements. NOTE: The Corporate Security Officer may determine (based on site specific factors) that additional facilities (i.e., tank farm, pump station, etc.) require a FSP. If an additional facility is determined to need a FVA and FSP, the Corporate Security Officer will advise the Supervisor to ensure completion of these documents. 3.2.2 Conduct an annual (once per calendar year) review of the FSP and the FVA with all employees to ensure familiarity with the plan and to identify inaccuracies or improvement opportunities. If there are any <<>> Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Page 2 of 8 Revision: 9 improvements, update the FSP and submit to the EHS&S Compliance Specialist for uploading into the Livelink Security Folder. 3.2.3 3.2.4 3.2.5 3.2.2.1 Note any changes in owner, operator or Corporate Security Officer in the annual review. 3.2.2.2 Complete the In‐Depth Security Training Form. Revise and update the FSP when major changes involving the facility status or security organizations occur, or as necessary to reflect other changing circumstances. Communicate these changes to affected personnel via a SIP meeting, or via email if unable to attend an SIP meeting. Send the revised FSP to the Safety Compliance Specialist for uploading into the Livelink Security Folder. 3.2.3.1 The following conditions at a minimum require a change to the FSP within 30 days: 3.2.3.1.1 Local Facility Security Officer change. 3.2.3.1.2 Modification of physical security. 3.2.3.1.3 Security procedure change. 3.2.3.1.4 Change in the facility’s configuration that materially alters the information included in the FSP. 3.2.3.1.5 Change in the type of products handled, stored, or transferred that materially alters the required response resources. 3.2.3.1.6 Any other changes that materially affect the implementation of the FSP. Include all other conditions in the annual review. Annually assess the facility using the Minimum Physical Security Standards. Assess newly acquired facilities within 60 days of purchase and annually thereafter. Use the appropriate Visitor Log and Safety Guidelines (Inland or Marine) for visitor identification, 3.2.3.2 3.2.4.1 verification and monitoring at each manned facility. Maintain completed logs locally as required. Conduct a Visitor Safety Orientation for all visitors prior to their leaving the main office area. NOTE: “Visitor” is defined as anyone, Company employee, contractor, or other, who is not assigned to work at the facility. “Visitor” is not intended to include drivers, cleaning crews, or delivery services (e.g., UPS, FEDEX, etc.). 3.2.6 Maintain the Key Control Log at the facility, listing by name and contact information whoever has been provided keys and/or automatic gate openers for the facility. NOTE: This requirement applies to employees who have keys and/or automatic gate openers permanently assigned to them until termination or transfer, and temporary keys and/or automatic gate openers that may be occasionally loaned to a contractor, cleaning crew, or utility worker for occasional access to remote facilities. 3.2.7 3.2.8 3.2.9 3.2.10 Ensure all employees newly assigned to the facility receive Security Awareness Training within 90 days of assignment to the facility. Report any employee threat or threat to an employee to the Corporate Security Officer or Alternate Corporate Security Officer with appropriate recommendations for ensuring workplace security. Conduct annual drills and/or exercises as outlined in 6 CFR 27.255 and the Chemical Facility Anti‐Terrorism Standards (CFATS) Site Security Plan if the facility is regulated by CFATS. CFATS facilities will be notified of their status by the Alternate Corporate Security Officer. 3.2.9.1 Document security drills and exercises on the Security Drills and Exercises Form. Comply with the Notification Procedure as outlined in Security Events. <<>> Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Revision: 9 Page 3 of 8 3.3 The Field Supervisor shall: 3.3.1 Periodically, not to exceed three years, review the Security Events Procedure and the Guidelines for Reporting a Suspicious Call and/or Bomb Threat to a Facility with all employees to ensure they are aware of At USCG regulated facilities, annually update Company contact information for execution of notification what constitutes a Security Event 3.4 The Marine Terminal Supervisor shall: 3.4.1 Register all individuals who are assigned at a USCG regulated facility more than 90 days, into the HomePort Database (or alternative approved registration format) within 30 days of their start date. This includes employees, temporary employees, and/or contractors. If an individual has not previously been registered, register the individual within five days, (but no later than the 90 days), at the point it is determined that he/she will need access beyond the 90‐day period. 3.4.2 Ensure all new hire employees obtain a Transportation Workers Identification Credential (TWIC) upon accepting an offer of employment. 3.4.3 Escort all new hire employees until they have acquired their TWIC card to allow unescorted access to the facility. 3.4.4 protocols. 3.4.5 At USCG regulated facilities, annually update Company contact information to the USCG for execution of notification protocols, as required. 3.4.6 Conduct security drills/exercises in accordance with 33 CFR 105.220 at all facilities regulated by the USCG. 3.4.6.1 Conduct drills every three months. 3.4.6.2 Conduct exercises annually, not to exceed 18 months between events. 3.4.6.3 Document security drills and exercises on the Security Drills and Exercises Form. 3.4.7 Maintain security related records at all facilities regulated by the USCG (33 CFR 105) for a period of two years. 3.4.8 Submit and maintain approved USCG Facility Security Plans as regulated by 33 CFR 105. 3.5 The Operations Manager shall: 3.5.1 If employees are officed in a leased or rented space in excess of 30 days, determine if security measures beyond the landlord’s polices are required and implement as needed. 3.5.2 For marine facilities: 3.5.2.1 Assign, in writing, a Facility Security Officer (FSO) for all facilities regulated by the Maritime Transportation Security Act and provide training for the FSO to serve in that capacity. 3.5.2.2 For marine terminals, review security incidents, which are considered Security Sensitive Information, with the personnel specified in the FSP. 3.5.2.3 Submit a 33 CFR 105 compliant FSP for newly acquired facilities regulated by the USCG to the applicable Captain of the Port 60 days prior to close, or as soon as practical based on confirmation of closing the acquisition. 3.5.3 Complete the Facility Security Plan (Nonmarine) Template (including the FVA) for all newly acquired nonmarine facilities within 60 days of purchase and submit to the EHS&S Compliance Specialist. NOTE: The Corporate Security Officer may determine based on site specific factors, that additional facilities (i.e., tank farm, pump station, etc.) require a FSP. If an additional facility is determined to need a FVA and FSP, the Corporate Security Officer will advise the Supervisor to ensure completion of these documents. <<>> Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Page 4 of 8 Revision: 9 3.5.4 Prepare and submit grant applications for security related costs, as applicable. 3.6 The Alternate Corporate Security Officer shall: 3.6.1 Submit “Top Screen” information to the Department of Homeland Security in compliance with CFATS: 3.6.1.1 When a facility is newly acquired. 3.6.1.2 When there are material modifications to an existing facility’s operations or site including facility real estate or tank expansions. 3.6.1.3 On a resubmission schedule noted in CFATS regulations. 3.6.2 Coordinate the development of CFATS Security Vulnerability Analysis (SVA) and Site Security Plans (SSP) for facilities that fall under CFATS regulations and submit when required by regulation. 3.6.3 Coordinate a drill and exercise program for CFATS facilities and facilities that are considered TSA critical. 3.6.4 Coordinate a TSA Critical Facility Workgroup to assess Company facilities against the TSA critical facility standards. 3.6.5 Notify Operations of any facilities considered Transportation Security Administration (TSA) Critical. 3.6.6 Coordinate with Operations to develop Site Security Plans to comply with TSA guidelines. 3.6.7 Develop a Chemical Terrorism Vulnerability Information (CVI) based records retention program for CFATS facilities. 3.6.8 Perform the duties of the Corporate Security Officer as needed. 3.7 The Project Manager shall: 3.7.1 Identify all contractors who have the potential to conduct work at a USCG regulated facility beyond a 90‐ day period on the job plan and/or project plan. Provide the Facility Supervisor the names of the contractors listed on the job plan and/or project plan as soon as available, but no later than 30 days after the project start date. 3.7.2 Require all contractors who conduct work at a USCG regulated facility to require their employees who will be working in Company facility “Restricted” or “Secure” areas to obtain a TWIC card. Contractor employees that do not have a TWIC, are required to be escorted at all times in these areas in compliance with 33 CFR 105. 3.8 The Security Management Team (SMT) shall: 3.8.1 Review security incidents and/or security breaches for nonmarine facilities to assess whether or not any additional workplace security is warranted. 3.8.2 Review reported employee threats or threats to an employee to determine if additional security measures and/or other actions are warranted. 3.8.3 Determine if a national, regional, or facility‐specific security threat could impact or change: 3.8.3.1 The Company’s Security Threat Level and/or 3.8.3.2 Require additional security measures at one or more of the Company’s facilities. NOTE: The SMT is only tasked to address Company workplace security issues/concerns. Employees visiting non‐Company facilities should comply with the security requirements in‐place at those locations. 3.9 3.10 The EHS&S Compliance Specialist shall: 3.9.1 Upload the FSP to the Livelink Security Folder upon receipt. The Supervisor of Pipeline Integrity Engineering shall: <<>> Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Page 5 of 8 Revision: 9 3.10.1 Conduct a security analysis using the Valve Security Process to determine the appropriate security measures to be implemented to protect against vandalism and unauthorized entry for DOT regulated exposed facilities located outside of a facility (e.g., terminal, pump station or tank farm). 3.10.2 Reassessments should be considered whenever circumstances arise that suggests the need for a reassessment. Types of circumstances may include security events, encroachments, land use changes, threats, etc. 3.11 The Vice President of Technical Services shall: 3.11.1 Implement security measures as identified. 3.12 The Employee shall: 3.12.1 Report any personal or work‐related threat (verbal, written, etc.) to you or another employee to Supervisor immediately. 3.12.2 Make notifications as described in the Security Level Procedures. 3.12.3 Make primary and secondary notifications if the Corporate Security Officer or the Alternate Corporate Security Officer cannot be reached, and if the situation requires immediate notification. Notify the Corporate Security Officer via voicemail or email that such notification(s) have been made. 3.12.4 Comply with the Security Events Procedure. 3.12.5 Comply with the Security Level Procedure. 3.12.6 Complete the Security Awareness Training within 90 days of assignment to a facility (terminals and tank farms only). 3.12.7 Complete the Key Control Log as directed by Supervisor. 3.12.8 Lock all manually operated block valves upon completion of activity and prior to leaving the area. 3.12.9 Lock all gates and key buildings (manned and unmanned) anytime the facility is not occupied. 3.12.10 Complete the Visitor Log after verifying that a visitor has left the facility for the day and has not signed out or notified Company personnel that he/she has left the facility. 3.12.11 Successfully obtain a TWIC card when unescorted access is required to secure areas of Company marine facilities. 3.12.12 Complete the Declaration of Security Form for every vessel that comes to the dock only if the Marsec level is elevated to level 2 and higher. <<>> DATE 1/1/05 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 7/1/06 1/1/07 01/01/07 Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Revision: 9 Page 6 of 8 System Integrity Plan Change Log LOCATION BRIEF DESCRIPTION OF CHANGE 2.1 Added any other leased/rented office 3.1.1 Added 3.1.3 Added 3.1.5 Added 3.1.7 Added 3.2.3 Deleted 3.2.4 Added note box 3.2.5 Rephrased 3.2.6 Added 3.2.7 Added 3.2.8 Added 3.2.10 Added 3.3.2 Added 3.3.3 Added 3.4 Added 3.5 Added 3.1 Deleted “ Develop and maintain a Company Security Plan to comply with all regulatory security requirements, including the Department of Homeland Security, Transportation Security Agency and the Department of Transportation (TSA), the United States Coast Guard (USCG) and the Office of Pipeline Safety (OPS). NOTE: The Company Security Plan is a protected document with limited employee access. 3.1 Deleted Annually validate and document that the Company’s facilities are in compliance with the Company Security Plan and document. Develop and maintain security related procedures, as required 3.19 Added for physical changes/improvements made to assets for the primary purpose of meeting the Minimum Physical Security standards and/or security enhancements 3.2.2 Added site‐specific 3.1.8 Added 3.3.4 deleted “ records associated with training, drills and exercises and incidents/breaches of security for a minimum” 3.2.11 added 3.2.3 added 3.2.4 Changed to 1 year from 3 2.1 Added “ At any other leased and/or rented office space(s) the landlord’s policies will provide the minimum security requirements for that office space" 3.3.5 Deleted “Specifically, all Company marine facilities are required to conduct a security drill once every three months. 3.5, 3.51, 3.5.2 and 3.5.3 Added 3.5.3.2 Note box added 3.6.1 Added 3.6.5 Added 4.0 Deleted link to Company Security Plan 4.0 Added “ Workplace Violence Policies and Guidance“ 3.1.2 and 3.1.3 added 3.3.6 and 3.3.7 Added 3.3.7 Split “Complete a Security Vulnerability Assessment and the Facility Security Template for all newly acquired non‐marine facilities within 60 days of purchase”. Into 2 responsibilities. Added as 3.1.9 3.3.7 Deleted “Assess the facility periodically using the Minimum Physical Security Standards. 3.2.12 and 3.6.1 Added to comply with new USCG regulations. 3.1.2 Added “convene as needed to address ….” 3.1.6 deleted <<>> 1/1/07 1/1/07 1/1/07 1/1/07 1/1/07 1/1/07 1/1/07 1/1/07 1/1/07 1/1/08 1/1/08 1/1/08 1/1/08 1/1/08 1/1/08 1/1/08 1/1/08 01/01/09 01/01/10 7/1/10 01/01/11 12/31/11 12/31/11 Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Revision: 9 Page 7 of 8 3.2.8 Combined with 3.2.7 3.3.7 Changed timeframe to 60 days. Added reference to SVA 3.6.1 Rephrased 3.8 added 3.9 and 3.10 added 3.11.7, 3.11.8 added 3.2.13, 3.2.10 added 3.6 added 3.1.8 Added 3.1.6 Added SMT reviews DOT “Critical” list. 3.2.1 plus note Clarify when a FSP is required at Non‐marine loading facilities. 3.2.3 Added requirements including timeframe for changes to FSP. 3.2.15 Added (moved) responsibility for updating COTP with contact information from the Director of EHS to Operations Supervisor. 3.2.16 Added (moved) responsibility for completing drills and exercises from the Operations Manager to the Operations Supervisor. 3.3.5 Added requirement for Submittal and maintain FSP for Marine terminals as required by 33 CFR 105. 3.6.2 Added TWIC credential requirements for contractors. 3.11.9 Added requirement for all affected employees at marine facilities to obtain TWIC as needed. 3.1.10 new 3.2.16.3 new 3.11 New role/responsibilities 3.12.2.1 New 3.12.9 new 3.3 Added marine area supervisor 3.3.2 Added date 3.1.9 Renamed form Facility Vulnerability Assessment 3.2.4 Changed frequency 3.2.8 Changed supervisor role from providing training to ensuring they receive 3.2.5 Changed frequency 3.2.10 Added CFATS language 3.5 Added Alternate Security officer duties 4.2, 4.5, 4.9, 4.10,4.13 Changed name of link to 3.1.8, 3.1.9 Removed. “Maintain BU summary for assest changes/improvements” and “complete FVA for new;y acquired marine facilities” 3.2.2.2 Removed, added annual (once per calendar year) to 3.2.2 3.2.1.1 New 3.4.3 Changed submission to EHSS Compliance Specialist (was Dir EHSS) 3.2.1 Modified per new requlatory requirement for facilities shipping > 792 gallons of hazardous liquids. Reviewed, no changes 3.3.6.2 Removed “once per calendar year not to exceed 365 days”, replaced with “annually, not to exceed 18 months” as per 33 CFR 105.220. 3.11.12 added 3.2.2.2 added 3.2.8 Removed “or newly hired at a facility 3.3 Added field supervisor 3.4 Revised to marine terminal supervisor All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. TEMPORARY TRANSFER OPERATIONS USING PORTABLE PUMPS OR NITROGEN THROUGH HOSES 9.01–ADM–185 Operations 01/01/12 Revision: 2 Page 1 of 3 Purpose: Establish appropriate controls for transfer operations using portable pumps, hoses, or nitrogen. Tools: Valve wrench Portable pump Hoses Pipe wrench Drip pans Sight glass Absorbent pads Various wrenches Safety, Health and Environmental Considerations: Depending upon the type of product, the employee should use the MSDS and take appropriate safety measures. Proper body positioning should be used while performing tasks involving physical or strenuous activity to minimize exposure to strain. NOTE: nitrogen is an asphyxiation hazard and precautions should be taken to keep the head/face away from it. PPE Required: Appropriate personal protective equipment should be used per the Workplace Hazard Assessment, Job Plan, site specific procedure and/or the MSDS. Step 1. Frequency 2. Identification 3. Action Action DETERMINE when to use portable pumps, hoses or nitrogen. Examples include: - Preparing tanks for cleaning - Performing tank bottom water draw - Tank to tank transfers - Loading or Unloading bulk additive - Loading petroleum contact water IDENTIFY type of pump to be used or if nitrogen will be used to push the product IDENTIFY type of hoses and connections to be used IDENTIFY site specific transfer procedure that will be used in conjunction with this procedure. REMAIN (employee, contractor, or driver) in the immediate vicinity to monitor the operation of product transfers involving the use of portable pumps, hoses, or nitrogen. NOTE: The transfer need not be attended if all of the following criteria are met:  Hoses are flanged and bolted or threaded  Hoses are properly rated for the maximum pressure or vacuum to which they could be exposed, and  Hoses are physically checked every 2 hours during operation. STOP the transfer operation and secure the area (e.g., close valves, provide thermal pressure relief) if the operation must be left unattended for any period of time. <<>> Magellan Midstream Partners, L.P. TEMPORARY TRANSFER OPERATIONS USING PORTABLE PUMPS OR NITROGEN THROUGH HOSES 9.01–ADM–185 Operations 01/01/12 Revision: 2 Page 2 of 3 INSPECT hoses and fittings (including condition and placement of gaskets) CAUTION: Use special consideration and caution when working near nitrogen. SET pump and hoses to reduce potential hazards:  Inside containment if practical.  Minimize the number of hoses and fittings by using the most direct route.  Utilize isolation valves at each end of hoses.  Consider using a check valve at the discharge end of hose to minimize drain- up BOND or ground equipment SECURE all fittings with straps or wire-ties to prevent hoses from inadvertently disconnecting during operation. CONTINUE following site specific transfer procedure <<>> Magellan Midstream Partners, L.P. TEMPORARY TRANSFER OPERATIONS USING PORTABLE PUMPS OR NITROGEN THROUGH HOSES 9.01–ADM–185 Operations 01/01/12 Revision: 2 Page 3 of 3 Date Change Location 01/01/07 Global 01/01/07 PPE and SH&E 01/01/08 01/01/09 Step 3 01/01/10 01/01/11 12/31/11 Global 12/31/11 System Integrity Plan Change Log Brief Description of Change New procedure Updated to reflect strain considerations Reviewed, no changes Deleted “quick connect lock” from SECURE action Reviewed, no changes Reviewed, no changes Added nitrogen to title and procedure; inhalation warning.. 2012 annual review complete <<>> Magellan Midstream Partners, L.P. PUBLIC AWARENESS SIP–ADM–10.01 Community Relations 01/01/12 Revision: 8 Page 1 of 5 1.0 OBJECTIVE 1.1 1.2 1.3 The objective of this initiative is to promote public awareness of underground utilities, damage prevention and emergency preparedness. Collectively, this initiative will enhance public safety and minimize damage to property, the environment and Company assets. The Company’s Public Awareness Program was developed to comply with the standards established in American Petroleum Institute’s (API) Recommended Practice (RP) 1162. Company management supports Public Awareness through Company policy, management participation, and allocation of resources and funding as described in the System Integrity Plan Magellan Management Commitment and Support Introduction and the Management Support Cover Letter. Public Awareness is a critical component of our overall safety program. The Public Awareness Program includes the following lines: Company Name Product PHMSA Operator Identification Number Magellan Pipeline Company, L.P. HVL 22610 Magellan Pipeline Company, L.P. Refined 22610 Magellan Pipelines Holdings, L.P. Refined 31579 Magellan Terminals Holdings, L.P. Crude 31580 Magellan Terminals Holdings, L.P. Refined 31580 Magellan Ammonia Pipeline, L.P. Ammonia 12105 Osage Pipe Line Company, LLC Crude 14391 2.0 DESCRIPTION 2.1 The Company’s Pipeline Awareness Program for DOT 195 jurisdictional lines will include information and provide instruction to the affected public, emergency officials, local public officials and excavators on the following: 2.1.1 Pipeline purpose and reliability. 2.1.2 Awareness of hazards or potential hazards and prevention measures. 2.1.3 Damage Prevention Awareness. 2.1.4 One Call requirements. 2.1.5 How to recognize, report and respond to leaks and/or emergencies involving Company operated pipelines and facilities. 2.1.6 How to identify the location of Company operated pipelines, rights-of-way, facilities, and description of the purpose of pipeline markers and the information on them. 2.1.7 Emergency Preparedness Communications. 2.1.8 The “Call Before You Dig!” Campaign and the national One Call number 811. 2.1.9 How to access a list of pipeline operators through the National Pipeline Mapping System (NPMS). 2.1.10 How to obtain additional information. <<>> Magellan Midstream Partners, L.P. PUBLIC AWARENESS SIP–ADM–10.01 Community Relations 01/01/12 Page 2 of 5 Revision: 8 2.2 This initiative provides guidance to Company employees on the communication of Emergency Response Plans (ERPs) to Local Emergency Planning Committees (LEPC) and Emergency Response Agencies (ERA). 3.0 STANDARDS 3.1 The One Call Supervisor and Public Awareness & Communications Specialist shall: 3.1.1 3.1.2 Administer the Public Awareness Program for DOT jurisdictional assets. Determine annually, the acceptable pipeline awareness programs and annual mailings for the upcoming year. Develop the message content of these programs as described in the Message Content Guidelines. 3.1.3 Perform an annual audit of the Public Awareness Program to ensure the program has been developed and implemented according to the guidelines in RP 1162. Document on the Annual Self Assessment. 3.1.4 3.1.5 3.1.6 3.1.7 3.1.8 3.1.9 3.1.10 Perform an Effectiveness Evaluation of the Public Awareness Program before September 1st every four years in accordance to the guidelines in RP 1162. Maintain all program evaluations, including current results, follow-up actions, expected results and annual assessments for five years. Implement the Annual Mailings Procedure annually. Conduct a pretest of public awareness materials for audience appeal, message clarity, understandability, and retention before they are widely used. A pretest can be performed using a small representative audience that is not involved with the development of the Public Awareness Program. Annually review and update the public education and damage prevention section of Magellan’s Internet Site, if necessary. Maintain and annually update the Public Awareness Folder in Livelink and the Emergency Response Guide. Coordinate with Asset Integrity and Operations personnel to ensure that the ERP Summary Folders are prepared, maintained and distributed to the appropriate LEPC and/or specific local ERAs. 3.1.11 Approve any deviations from the print ad or radio ad standards upon request. 3.1.12 Oversee public education efforts for assets covered per the Mitigation Plan to ensure that ERAs within each county that the pipeline passes through will be contacted annually (not to exceed 15 months) in person and provided with maps of the system. 3.2 The Operations Manager shall: 3.2.1 Communicate Emergency Response Plans to LEPC/ERAs. 3.2.2 Maintain a current address listing of LEPC/ERAs that could respond to a Company emergency. Provide this mailing list to the Public Awareness and Communications Specialist for the annual Mail Out Program. 3.2.3 3.2.4 Maintain an ongoing LEPC/ERAs meeting schedule. In addition to annual mailings to LEPCS/ERAs, conduct meetings on a rotating basis, with a minimum of 25% of the listed LEPC/ERAs once every 12 months, not to exceed 15 months. Conduct a meeting with each listed LEPC/ERAs at least once in a four-year calendar period. 3.2.5 Conduct meetings following the LEPC/ERA Meeting Requirements. For Intrastate pipelines in Texas, conduct face-to-face meetings with designated ERA officials annually per the LEPC/ERA Meeting Requirements. 3.2.6 Complete the LEPC/ERA/Stakeholder Meeting Form for each meeting. Distribute the appropriate updated response plan documentation (ERP, ERAP, etc.) during each meeting. 3.2.7 Complete, at a minimum, one supplemental outreach activity per year within each operating area. <<>> Magellan Midstream Partners, L.P. PUBLIC AWARENESS SIP–ADM–10.01 Community Relations 01/01/12 Page 3 of 5 Revision: 8 Consider external factors along the pipeline system and assess if some additional level of public awareness communications is warranted of if other supplemental/enhanced outreach activities are needed. 3.2.7.1 Use the Relevant Factors Assessment in making the evaluation and the Approved Media and Delivery Methods Procedure to determine the appropriate activity. NOTE: are required. There may be circumstances where multiple outreach activities 3.2.7.2 For each Supplemental/Enhanced Outreach Activity, complete the LEPC/ERA/Stakeholder Meeting Form, provide supporting documentation and send to the District Office or location and the Public Awareness and Communication Specialist. Maintain copies of all materials provided to each stakeholder audience in the local files for five 3.2.8 years. 3.2.9 File the completed LEPC/ERA/Stakeholder Meeting Form for five years. 3.3 The Employee shall: 3.3.1 Use the LEPC/ERA/Stakeholder Meeting Form to conduct and document pipeline safety awareness discussions with ERAs, public education and third party damage prevention stakeholder groups. Forward completed forms to the appropriate area office. 3.4 The One Call Coordinator shall: 3.4.1 Request documentation from state One Call Centers for their community outreach or public awareness activities. Information may be obtained by website if available or phone solicitation. Sort the information by state and retain for five years. NOTE: Most state One Call Centers provide public awareness activities; Magellan can incorporate these activities into its Public Awareness Program. 3.5 3.6 3.4.2 3.4.3 3.4.4 3.4.5 Request address listings from each applicable state One Call agency and the Company internal database of all contractors and individuals engaged in excavation activities during the previous 12 months in each state where Company assets are located. Forward the data to the vendor for incorporation into the annual mailings. Advise the Operations Managers, Asset Integrity Supervisors, and Operations Control Manager of the annual mail out messages at least ten days before distributing the mail outs. Utilize the Company Damage Prevention Newsletter to inform employees about the Public Awareness Program objectives. File the LEPC/ERA forms and Supplemental/Enhanced activity documentation in the appropriate Damage Prevention folder in Livelink. The Regulatory Compliance Coordinator shall: 3.5.1 Initiate biennial (beginning January 15, 2005 and every two years thereafter) Educational Center Surveys in accordance with the Texas Public School Survey Procedure for Railroad Commission of Texas regulated assets. The Operations Supervisor in Texas shall: 1.1.1 Conduct public school surveys (psb) upon notification from the Regulatory Compliance Coordinator. Forward the PSB Survey information to the Regulatory Compliance Coordinator within 60 days of the request, but no later than December 15th . <<>> Date 1/1/05 1/1/05 1/1/05 1/1/06 1/1/06 1/1/06 1/1/06 1/1/06 1/1/06 1/1/06 1/1/06 1/1/06 1/1/06 1/1/06 1/1/06 1/1/06 1/1/06 1/1/06 1/1/07 1/1/07 1/1/07 1/1/07 1/1/07 9-10-07 9/10/07 9/10/07 9/10/07 9/10/07 10/08/08 10/08/08 10/08/08 10/08/08 10/08/08 10/08/08 10/08/08 10/08/08 10/08/08 10/08/08 1/1/09 02/01/09 7/28/09 07/28/09 07/28/09 Magellan Midstream Partners, L.P. PUBLIC AWARENESS Community Relations 01/01/12 Page 4 of 5 Change Change All 3.2.6 Greg Walker 3.2.1 All 2.1 3.0 3.0 3.2.2 3.5 3.5.2 3.5.3 Greg Walker 3.5.4 Multiple 3.1.6 3.2.4 3.4.1, 3.4.2 3.2.3 3.2.2 All 1.0 3.1.3 Greg Walker 2.1.1, 2.1.7 3.2.1.1 All 3.2.1.6 3.4.1 Greg Walker 3.2.2 3.3.1 All 3.1.8 3.1.10 3.2.2.5 3.3.1 Greg Walker 3.4.1 3.5.1 3.5.2 3.5.4 3.5.5 3.6, 3.7 3.5.2 All Greg Walker 3.1.7 Mike 3.2 SIP–ADM–10.01 Revision: 8 SYSTEM INTEGRITY PLAN CHANGE LOG Brief Description of Change Conducted 2004 Annual Review see change log Moved responsibility to develop and maintain lists of Emergency responders to Operations Supervisors as new Section 10 3 1 5 Added Public Education and Third Party Damage Prevention Program Conducted 2005 Annual Review see change log Deleted the objectives of a public awareness program Deleted information about the federal stds. the procedure was developed under. Developed Magellan’s “Commitment to the Program.” Deleted Operator’s responsibility of overseeing and approving budgetary responsibility. Changed OneCall Analyst to OneCall Coordinator Deleted request for address of Contractors form OneCall and documentation of Awareness Program distributed Also requirement to have this information forwarded to Operations Mgr Deleted requirement to establish and maintain the Public Awareness Program and annual review of program Deleted references to National Alliance Programs. Added content for API RP1162 compliance. Added “to determine if additional outreach programs are needed.” added clarified Added retention time and location Rephrased and defined summary report Conducted 2006 Annual Review see change log Added Management Support Documentation: E1 Goals and Management Support Cover Letter Added Effectiveness Evaluation Requirements added added Conducted 2007 Annual Review see change log Moved this to new section entitled, “3.3 Longhorn Specific Requirements:” Added One Call membership requirement in response to PHMSA Clearing House comments Added additional Relevant Factors and clarified direction for Supplemental Outreach Activities in response to PHMSA Clearing House comments Added new wording to this section Conducted 2008 Annual Review see change log Deleted – Monitor activities and determine if additional is needed. Added from E12-Maintain Public Awareness folder and ER Guide. This replaces the previous ERP distribution process Added location for supplemental documentation Added administrator for Longhorn. Moved previous 3.3.1 to 3.3.2 Deleted Operations Manager or Asset Integrity (AI) Supervisor and changed to appropriate area office Added option for website retrieval and retention time. Deleted distribution to Operations Managers/ AI Supervisors Added Manager of Damage Prevention for incorporation into the annual mailings. Deleted distribution to Operations Manager/AI Supervisors Added: Include PA objectives in One-Call newsletter Added: File Supplemental Documents in Livelink folder Moved from SIP 7.08 Changed Title to Mgr of Damage Prevention and Design Services Conducted 2009 Annual Review see change log Changed “Pipeline” to “Public” Changed the title to, “Assets Covered Per Mitigation Plan” <<>> Magellan Midstream Partners, L.P. PUBLIC AWARENESS SIP–ADM–10.01 Community Relations 01/01/12 Page 5 of 5 Date Change Change 07/28/09 3.3.2.3 Hampton 07/28/09 3.3.4 07/28/09 3.3.5 07/28/09 3.4 07/28/09 3.6.2 07/28/09 3.6.4 01/01/11 2.1 3.1 3.1/3.2.2/3.2.7 8/29/11 2.1 8/29/11 3.1 3.1.4 8/29/11 3.2.2 8/29/11 3.2.7.2 12/31/11 All Revision: 8 Brief Description of Change Added “And Design Services” Deleted Section Maintain the information sent from the One Call Coordinator in the Local file for five years Added “For Five Years” This information includes documentation of the Public Awareness activities Deleted Section Added “ And Magellan’s Internal Database” Deleted “Sort this information by operating area and forward to the manager of Damage Prevention and Design Services” Added “Forward Deleted “Include Public Awareness Objectives in the One Call Newsletter.” Added “ Utilize Removed DOT 192 Changed Mgr of Design Services and Compliance to One Call Team Changed title to One Call Team Leader Added list of specific pipeline assets covered by the PAP. Changed title to One Call Supervisor Public Awareness Comm. Spec. Added date Changed title to Public Awareness Comm. Spec. Changed title to Public Awareness Comm. Spec. 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. INCIDENT INVESTIGATION SIP–ADM–13.02 Incident Management 01/01/12 Revision: 13 Page 1 of 7 1.0 OBJECTIVE 1.1 The objectives of this initiative are to investigate selected incidents for probable cause, identify corrective actions to prevent recurrence, complete a management review, and communicate findings and lessons learned. 2.0 DESCRIPTION 2.1 This initiative is applicable to all classified incidents. For assets covered by the Mitigation Plan, those classifications are Minor, Significant, Major, Repair, and Near Miss. For all other Company operated assets, the classifications are Minor, Serious, Major, and Near Miss. 2.2 Incident type and classification will be used to determine responsibility for initiating investigations. 2.3 Incident investigations should identify the probable cause, the corrective actions and lessons learned. The detail and resource commitment associated with an incident investigation and the management level involved should be commensurate with the incident's severity and/or loss potential. 3.0 STANDARDS 3.1 The Employee shall: 3.1.1 Participate in incident investigations as requested by their Supervisor. 3.2 The Supervisor shall: NOTE: For all incidents the management group responsible for supervising the activity that results in an incident or that is operating the associated asset when an incident occurs is accountable for initiating the incident reporting and incident investigation and completing the required documentation. If the management groups involved cannot reach consensus on these responsibilities the issue should be raised to the next level of management. 3.2.1 3.2.2 Initiate and complete a draft Incident Investigation Report for Serious, Significant or Major incidents only upon approval from the Associate General Counsel of Operations, the Vice President of Operations, the Vice President of Technical Services, and the Director of Environmental, Health, Safety and Security. Initiate and complete a draft Incident Investigation Report for the following types of Minor incidents within five working days of the event: 3.2.2.1 OSHA Recordable Injury/Illness. 3.2.2.2 Third Party Property Damage (including motor vehicle damage) 3.2.2.3 Incorrect execution of an OQ Task. 3.2.2.4 Fire. 3.2.2.5 Explosion. 3.2.2.6 Agency Reportable Release. 3.2.2.7 One Call Violation. 3.2.2.8 Incident involving a Process Safety Management (PSM), Risk Management Program (RMP) or Mitigation Plan asset. NOTE: For PSM/RMP facilities, an incident investigation team shall be established consisting of at least one person knowledgeable in the process involved, including a contract employee if the incident <<>> Magellan Midstream Partners, L.P. INCIDENT INVESTIGATION SIP–ADM–13.02 Incident Management 01/01/12 Revision: 13 Page 2 of 7 involved work of the contractor, and other persons with appropriate knowledge and experience to thoroughly investigate and analyze the incident. NOTE: For LMP facilities, an incident investigation team shall be established consisting of at least two persons knowledgeable in the process involved, including a contract employee if the incident involved work of the contractor, and other persons with appropriate knowledge and experience to thoroughly investigate and analyze the incident. NOTE: All incident investigations on PSM/RMP and LMP assets must be initiated within 48 hours of the event. 3.2.2.9 Repair Incident for LMP covered assets if required by the Repair Investigation Decision Tree. 3.2.3 3.2.4 3.2.5 3.2.6 3.2.7 For all other Minor incidents, provide recommendation to the Manager on whether an investigation should be conducted. Forward the draft Incident Investigation Report to the Manager and the Safety Specialist upon completion of the draft. Complete revisions based on feedback from the Manager, Safety Specialist and Director within five working days of receipt. Forward final Incident Investigation Report to the Field Office Administrator/Compliance Coordinator‐Mitigation Plan for posting. Investigate and document all Near Miss events that could have resulted in a release or a catastrophic release at a designated PSM//RMP asset using the Incident Investigation Report as promptly as possible but no later than 48 hours following the incident. Forward the Incident Investigation Report to the Manager and Safety Specialist within two working days of completion. Review Hazard/Near Miss Reports within 30 days of receipt, identify additional corrective actions 3.2.8 as appropriate, document on card and forward to Safety Specialist. Consult with Manager to determine if an incident investigation is warranted. Consult with the Manager of Compliance and share lessons learned, as appropriate, from the Incident Investigation Reports and the Hazard/Near Miss Reports with all affected personnel 3.3 whose job tasks are relevant to the incident findings, including contract employees where applicable. 3.2.9 Forward completed One Call Incident Investigation Reports to the One Call group for review. 3.2.10 Update the Incident Investigation Report when new information is obtained, forward for posting, and make any new notifications if required. The Associate General Counsel of Operations, the Vice President of Operations, the Vice President of Technical Services, and the Director of Environmental, Health, Safety and Security shall: 3.3.1 Assemble upon notification of a Serious, Significant, or Major incident to determine whether a management directed incident investigation should be conducted. If so: 3.3.2 Determine if the investigation will be directed by Legal. <<>> Magellan Midstream Partners, L.P. INCIDENT INVESTIGATION SIP–ADM–13.02 Incident Management 01/01/12 Revision: 13 3.3.3 3.3.2.1 3.3.2.2 3.3.2.3 Page 3 of 7 Define the scope of the investigation, identify the Lead Investigator, and determine completion timetable for management directed incident investigations Review management directed incident investigation results and approve resulting action items. At the conclusion of the investigation, assemble the Incident Investigation Group, the lead investigator and any other identified stakeholders to review the incident and approve the significant lessons learned that should be conveyed to affected stakeholders. Communicate to the responsible party whether the II will be management directed or field directed. 3.4 The Manager shall: 3.4.1 Review all (except those “management” led) draft Incident Investigation Reports and Hazard/Near Miss Incident Investigation Reports to ensure that the reports are complete and include all relevant information within five working days of receipt. Forward approval or suggested revisions to the Supervisor. 3.4.2 Forward any draft Incident Investigation Report involving a MVA or with the potential for human factors to be a contributing cause to the appropriate Director upon completion of the manager review. 3.4.3 Obtain consensus from the Manager of Compliance if an Incident Investigation for a Minor Incident where an investigation is not required, will not be conducted. 3.5 The Safety Specialist shall: 3.5.1 Review all (except those “management” led) draft Incident Investigation Reports and Hazard/Near Miss Incident Investigation Reports to ensure that the reports are complete and include all relevant information within five business days of receipt. Forward approval or suggested revisions to the Supervisor. 3.6 The Field Office Administrator/Compliance Coordinator‐Mitigation Plan shall: 3.6.1 Post completed Incident Investigation Reports and Hazard/Near Miss Reports in Livelink. 3.6.2 Place action items resulting from Incident Investigations into CMS for tracking and documentation of completion. 3.7 The Director shall: 3.7.1 Review draft Incident Investigation Reports for causes and contributing factors related to MVA and human involvement incidents within five working days of receipt. Forward approval or suggested revisions to the Manager and Supervisor. 3.8 The Manager of Asset Integrity Engineering shall: 3.8.1 Review and analyze all Incident Investigation Reports to identify trends and common issues that should be shared within the Company. 3.8.2 Prepare and distribute a quarterly summary of Incident Investigation Report findings and recommendations to the applicable Operations and Technical Services stakeholders as appropriate. Coordinate quarterly meetings to discuss and review these findings. <<>> 3.9 3.10 Magellan Midstream Partners, L.P. INCIDENT INVESTIGATION SIP–ADM–13.02 Incident Management 01/01/12 Revision: 13 Page 4 of 7 The Health and Safety Specialist shall: 3.9.1 3.9.2 Review and analyze all Incident Investigation Reports to identify trends and common issues that should be shared within the Company. Prepare and distribute a quarterly summary of Incident Investigation Report findings and recommendations to the Manager of Asset Integrity Engineering for distribution to appropriate Asset Integrity Engineers. The Asset Integrity Engineer supporting assets covered by the LMP shall: 3.10.1 Conduct an Incorrect Operations Mitigation review on a quarterly basis. <<>> Date 10-1-2004 10-1-2004 10‐1‐2004 10‐1‐2004 10‐1‐2004 10‐1‐2004 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 4/20/06 01/01/07 1/17/07 10/20/07 1/2009 Magellan Midstream Partners, L.P. INCIDENT INVESTIGATION SIP–ADM–13.02 Incident Management 01/01/12 Revision: 13 Page 5 of 7 System Integrity Plan Change Log Change Location Brief Description of Change 2.1 Added all OSHA recordable injuries shall be investigated and possibly investigate NOVs 3.2.1 Added all OSHA recordable injuries shall be investigated 3.2.1.2 Added investigate all incidents that require a 7000‐1 filing 3.2.1.3 Added that the management group that is responsible for the incident initiates the incident investigation. 3.2.1.4 Added team members shall be knowledgeable of the assets involved. 4.0 Added link to Incident Investigation Form 3.2.1 Added Consult with legal on all incidents involving 3rd party to determine the level of investigation required. 4.2 Added incident investigation guidelines. 3.2.2 Added fires/explosions 3.8.2 Added “NOTE” box “Within 24 hours or as soon as possible, gather material evidence important to the investigation such as video, photographs, employee logs, injury reports, etc.” 3.2.3 Changed to a note box 3.2.2, 3.2.2.2, 3.2.2.3 Deleted “Incident Investigation Guidelines” 3.2.2.3 Deleted “with a determination of whether performance of a Covered Task contributed to the incident.” 3.2.3 Rephrased 3.6.7 Added 3.8.1 Added 3.5.1 Deleted 3.2.1 Modified to include all serious and major incidents Purpose Lessons Learned added Description 2.1 Reworded, Supervisor investigation deleted 2.2 Reworded – Lessons Learned added 3.2.1 2‐day reporting req added 3.2.2, 3.2.3 5‐day reporting req added, 2‐day forwarding and Incident Investigation Report link added 3.2.4 New 3.2.3 – 3.2.6 (old) Deleted 3.3.1 Reworded – CMS added and IIR link added 3.3.2 (old) Deleted – draft IIR 3.4 (old) Director resp deleted 3.4.1 IIR link added 3.5.1, 3.5.2 New 3.6.1 – 3.6.6 Safety Rep resp deleted (see 3.5 for new rsp) 3.6 Monthly req added, IIR link added 3.7, 3.8 New 3.8 (old) Lead Incident Investigator resp deleted 3.5.1 Added requirement to post incident reports. All Annual Review 1.1 modified 2.1 modified 3.1.2 added 3.2.2 modified 3.2.2 – 2nd notebox added 3.2.3 modified 3.3 (2007) removed 3.3.1 notebox modified 3.4.1 and 3.4.2 modified 3.5 and 3.5.1 modified 3.6.2 modified 2.1 updated language <<>> Date 1/2009 1/2009 1/2009 1/2009 8/2009 8/2009 8/2009 8/2009 01/01/10 3/4/10 7/1/10 09/01/10 09/01/10 09/01/10 09/01/10 09/01/10 04/08/11 04/08/11 04/08/11 7/19/11 12/31/11 12/31/11 12/31/11 12/31/11 12/31/11 12/31/11 12/31/11 12/31/11 12/31/11 Magellan Midstream Partners, L.P. INCIDENT INVESTIGATION SIP–ADM–13.02 Incident Management 01/01/12 Revision: 13 Page 6 of 7 Change Location Brief Description of Change 2.3 modified 3.2.2 updated language 3.2.3 updated language 3.8 added 4.3 inserted Incorrect Operations Mitigation Program document 3.2.4 Added 3.2.6 Modified name of decision tree 3.5.2 New 3.2.2 Added additional language to Note Box, NOV’s, removed some language 3.3 Changed General Counsel to Associate GC; Added AGC requirements (3.3.1 and 3.3.2); modified 3.3.3, added other 3.5.2 Added Near Miss language 3.7 Removed Environmental Specialists requirement Minor rewording, updated responsibility titles 3.2.1.9 noteboxes Added/clarified LMP requirements – not a version change 3.2.1 added 1.1. Added “to prevent recurrence” as result of regulatory inspector suggestion 1.1. Reworded for clarification 3.2.2. Moved Minor incident note box to end of 3.2. for clarity 3.2.2. Removed Legal Dept note box. No longer necessary due to 3.2.1. 3.2.2.3. Removed parens, 3rd party dmg is serious under SIP and contractor is not a third party 3.2.5 Removed reference to Safety Rep 3.2.7/3.2.8/3.5 Changed Safety Rep to Safety Specialist 3.2.6 Changed Safety Rep to Safety Specialist and added FOA 3.5.2/ 3.5.3.1 (now 3.6.1/3.6.2) Moved to FOA 3.5.3 deleted 3.5.4 (now 3.2.9) Moved to supervisor 3.8 (now 3.9) Changed from SIP Coordinator to Health and Safety Specialist shall 3.9.2 Modified to reflect managerial decision 3.10 Removed to reflect managerial decision 3.2 note Moved from below 3.2.2 removed 3.2.3 clarified 3.2.8 removed 3.2.11 Removed redundancy with onecall 3.2.14 added 3.2.15 revised 3.3.3 Added for clarification 3.4.1, 3.5.1 Clarified <<>> Date 12/31/11 12/31/11 12/31/11 12/31/11 Magellan Midstream Partners, L.P. INCIDENT INVESTIGATION SIP–ADM–13.02 Incident Management 01/01/12 Revision: 13 Page 7 of 7 Change Location Brief Description of Change 3.6.2 Removed psm/rmp 3.2.10/3.6 Added compliance coordinator 3.4.2, 3.7 Changed to all directors All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. INTERNAL AUDITS AND INSPECTIONS SIP–ADM–14.01 Compliance Management 01/01/12 Revision: 8 Page 1 of 5 1.0 OBJECTIVE 1.1 The objective of this initiative is to describe the methods used to assess the status, effectiveness and the level of compliance with SIP and other applicable regulations. 2.0 DESCRIPTION 2.1 This initiative applies to various means of assessing and verifying compliance to the SIP and other applicable regulations. 2.2 This initiative also applies to Facility Safety Reviews. 2.3 This initiative includes the effectiveness requirements for the assets covered by the Mitigation Plan. 3.0 STANDARDS 3.1 The General Auditor shall: 3.2 3.1.1 Establish an annual SIP audit schedule based on factors that may include but are not limited to, risk assessment, management requests or business needs. Submit the SIP audit schedule and protocol to the SIP Oversight Council for review and approval by February 28th and discuss with Legal to determine applicability of federal and state self disclosure regulations and policies. 3.1.2 Complete SIP audits in accordance with the annual SIP audit schedule. 3.1.3 Report the SIP audit results to the local leadership immediately upon completion of the site visit. 3.1.4 Work with local leadership to ensure corrective action plans are developed to address deficiencies prior to distribution of the audit report. 3.1.5 Document and distribute the results of the audits to appropriate personnel within 60 days of completion of the fieldwork. 3.1.6 Present summary findings to the SIP Oversight Council at scheduled SIP Oversight Council meetings. The Director of Environmental, Health, Safety and Security (EHS&S) shall: 3.2.1 Review, with assistance from the Legal Department, proposed audits to determine if it is appropriate to conduct any of the proposed audits pursuant to a Federal or State Audit Privilege regulation or policy. This applies to internal environmental, safety, and security related compliance audits. 3.2.2 Coordinate, if applicable, through the Legal Department to provide written notification to the appropriate state or federal agency 30 days prior to a scheduled audit. 3.2.3 Assess deficiencies and areas of noncompliance discovered during audits. In consultation with Legal, determine an action plan and assign responsibilities. Comply with state or federal requirements for disclosing, addressing and documenting closure of action items. <<>> Magellan Midstream Partners, L.P. INTERNAL AUDITS AND INSPECTIONS SIP–ADM–14.01 Compliance Management 01/01/12 Revision: 8 Page 2 of 5 3.3 The Supervisor of Facility Integrity Engineering shall: 3.3.1 Conduct a Process Safety Management (PSM)/Risk Management Program (RMP) audit at the Company PSM facilities using the PSM/RMP Audit Checklist at least every three years. The audit shall be conducted by someone knowledgeable in the process. Certify the audit adequately evaluated compliance with the PSM/RMP regulations through the audit sign‐ off in CMS. Enter action items from the PSM/RMP audits into CMS within 30 days of audit completion. Initial action item due dates should not exceed six months from completion of the audit. Retain the completed audit form at the facility for at least two previous audits and file in Livelink here: (Section O ‐ Compliance Audits). 3.3.2 3.3.3 3.3.4 3.4 The Marine Facility Security Officer shall: 3.4.1 Conduct a Marine Security Plan Audit annually at each marine facility utilizing the Marine Security Plan Audit Form. 3.4.2 Maintain a copy at the field location and retain for three years. 3.5 The Supervisor shall: 3.5.1 Conduct and document a Facility Safety Review at each manned facility in their area of responsibility once per calendar year, not to exceed 18 months, and at each unmanned facility at least once every two calendar years using the Facility Safety Review. 3.5.2 Use the Facility Safety Review Guidance Document as a guide to complete this form. 3.5.3 Maintain a copy of the completed form in the Facility Safety Review Livelink folder. Retain the current and previous inspection and retain. 3.5.4 Forward any corrective actions identified during the Facility Safety Review to the Field Office Administrator for entry into CMS. 3.6 The Mitigation Plan (MP) Asset Integrity Engineer shall: 3.6.1 Coordinate a self‐audit annually for the assets covered by the Mitigation Plan and upon notification of a throughput increase. Provide a copy of the audit report to applicable Company representatives. 3.7 The Air Specialist/Environmental Specialist shall: 3.7.1 Follow the procedures listed in Environmental Compliance Management. 3.8 The Asset Integrity Analyst shall: 3.8.1 Distribute the required performance update reports quarterly for the assets covered by the Mitigation Plan. 3.9 The Mitigation Plan (MP) Compliance Coordinator shall: 3.9.1 Maintain and update scorecards to measure Program Effectiveness for the assets covered by the Mitigation Plan. 3.10 The Employee shall: 3.10.1 When functioning as Lead Auditor: 3.10.1.1 Assemble the appropriate stakeholders to comprise an Audit Team, as necessary. 3.10.1.1.1 Notify the Director of EHS&S prior to conducting an audit to determine if the Company will invoke Audit Privilege. Communicate team responsibilities to the Audit Team prior to conducting the audit/inspection. 3.10.1.2 <<>> Magellan Midstream Partners, L.P. INTERNAL AUDITS AND INSPECTIONS SIP–ADM–14.01 Compliance Management 01/01/12 Revision: 8 3.10.1.3 Page 3 of 5 Utilize the appropriate form(s) when conducting the audit/inspection. Obtain the appropriate audit protocol and documentation requirements from the Director of EHS&S if performing an audit in conjunction with Audit Privilege. NOTE: Some audits/inspections may have specific protocols developed by regulatory agencies, or others, and approved by the Audit Team for use in lieu of, or in conjunction with, Company audit/inspection forms. 3.10.1.4 3.10.1.5 3.10.1.6 3.10.1.7 3.10.1.8 3.10.1.9 Review the audit/inspection with the Supervisor(s) and other appropriate personnel. Communicate and review the discovery of any deficiencies or noncompliance with the location management to determine whether the Legal Department should be immediately consulted for validation and potential disclosure. 3.10.1.5.1 Notify the Director of EHS&S of any deficiencies or noncompliance discovered during an audit conducted under Audit Privilege. Conduct a post audit meeting with the area leadership team upon completion of the audit in order to validate the findings and recommendations of the audit/inspection and to assign responsibility for completion of action items. Record and track the corrective action items identified during the audit utilizing CMS. Complete and distribute the final audit report within 30 days of the completion of the audit/inspection if not otherwise specified. Distribute as appropriate and retain the audit work papers and final report at the field location for three years, unless otherwise noted on the specific form. <<>> Magellan Midstream Partners, L.P. INTERNAL AUDITS AND INSPECTIONS Compliance Management 01/01/12 Revision: 8 SIP–ADM–14.01 Page 4 of 5 System Integrity Plan Change Log Date Change Location Brief Description of Change 9‐17‐04 Element #14 2005 Annual review and update: Remove Safety and Training Supervisor, and Legal. Add General Auditor, Sup of Facilities Integrity, and Supervisor of Environmental. Add Action Item Resolution initiative from Element #1. Review and update forms and links. 11‐15‐04 Element #14 Add Response to Written Regulatory Inquiries from Element #7. 1/1/06 2006 review Changed Facility Inspection timing from “not to exceed 15 months”, to “not to exceed 18 months”. Added Audit Privilege Matrix and Voluntary Audit Process Map links. Added Link for Marine Security Plan Audit Form. 1/1/06 3.1.5 Added 1/1/06 3.1.6 Changed to quarterly presentation from 30 days of completion of review. 1/1/06 3.2.2 Deleted documentation retention information. 1/1/06 3.5 Added Facility Security Officer duties 1/1/06 3.6 Combined Inspection Procedure document into Initiative under “All Employees Shall.”. New to procedure 01/01/06 3.6.2 Added 01/01/07 2.2 Added 01/01/07 3.2.1 rephrased 01/01/07 3.2.3 Rephrased to reflect CMS (AI Tracking removed) 01/01/07 3.3 Changed from Sup of Facility Integrity to Supervisor of Risk Engineering 01/01/07 3.4 Added Dir of HSS&S and responsibilities and deleted Supervisor of Envir and responsibility 01/01/07 3.6.1.1.1 added 01/01/07 3.6.1.3 01/01/07 3.6.1.5.1 Added “Obtain the appropriate audit protocol and documentation requirements from the Director of EHS&S if f i di i j i i h A di P i il ” Added 01/01/07 3.6.1.7 added 01/01/07 3.6.2 Deleted (Notify ES of noncomp issues per Voluntary Audit Process Map) 01/01/07 3.6.1.9 Added (deleted Doc Retention Guideline) 1/1/08 3.1.6 Modified to SIP Oversight Council 1/1/08 3.3 Corrected title 1/1/08 All Clarified PSM/RMP 1/1/08 2.3 added 1/1/08 3.6, 3.7 added 1/1/09 D. Chancellor Annual Review 1/1/09 Heading Added INTERNAL to the heading 1/1/09 3.2.1 Reworded by Paul Pratt 1/1/09 3.2.2 Deleted by Paul Pratt 1/1/09 3.2.4 Reworded by Paul Pratt 1/1/09 3.4.2 Added retention location and period 1/1/09 3.6 Clarified 1/1/09 3.8.1.9 Added distribution, retention location, and wording “unless otherwise noted on the specific form” 1/1/10 Annual review for 2010 1/1/10 2.3, 3.6, 3.7 Removed Longhorn reference and reworded to just Mitigation Plan 1/1/10 3.6 Added section for the Environmental Specialist 1/1/10 3.5.2 Clarified retention per the form 9/1/10 All 2011 SIP Review done 3rd Qrt 2010 9/1/10 3.1.1 Deleted January 1st of each year added “submittal to SIP Council by 2/28 and involving legal for self di l l i d li i R d i b l l d i l di <<>> Magellan Midstream Partners, L.P. INTERNAL AUDITS AND INSPECTIONS SIP–ADM–14.01 Compliance Management 01/01/12 Revision: 8 Page 5 of 5 Date Change Location Brief Description of Change 9/1/10 3.2.1 9/1/10 3.2.1.1 Deleted Annual SIP audit schedule, added proposed audits Recommendation by legal and internal di Deleted “work with General Auditor Recommendation by legal and internal audit 9/1/10 3.3.1 – 3.3.4 Broke up paragraph into sections – Recommendation by AI Engineering 9/1/10 3.3.2 Added Certification statement ‐ Recommendation by AI Engineering regulatory requirement 9/1/10 3.3.3 Added Action item due dates should not exceed 6 months‐ Recommendation by AI Engineering 9/1/10 3.5.1 9/1/10 3.6.1 Deleted as a guideline – Recommendation; form should be completed in its entirety until specific id li i Deleted paragraph as this is in SIP ADM 6.05 added reference to procedure 9/1/10 4.4 Deleted Environmental review form and added E6 Environmental Compliance Management 04/08/11 3.5 Changed Safety Rep to Supervisor 04/08/11 3.5.2 Changed from maintain copy of the completed form at the location and in the in 04/08/11 3.5.3 Modified 12/1/11 Annual Review for 2012 12/1/11 2.2, 3.5.1, Changed name of form & link to Facility Safety Review 12/1/11 3.5.2 Added the Guidance Document (new document created to give more clarity to 12/1/11 3.5.3 Removed “location” for filing as Livelink is available to everyone; deleted 12/1/11 12/1/11 3.6 3.6.1/3.9.2 Added the Mitigation Plan (MP) Asset Integrity Engineer Moved 3.9.2 from the MP Compliance Coordinator to the MP AI Engineer 12/1/11 3.3.4 Added Livelink folder location 12/31/11 All 2012 Annual Review complete <<>> ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 5B VALVE SCHEMATIC <<>> LOCATION: 171 SATSUMA STATION LOCATION: 711 EAST HOUSTON TERMINAL LOCATION: 480 HOLLAND AVE. JCT. STATION GALENA PARK STATION LOCATION: 170 Xт-(мо) MAGELLAN INSAN FANA DE LONGHORN PIPELINE PIPELINE COMPANY, LP. PROCESS 100 DACRAM DRAWING NUMBER TAFE APPROVED SECTON LP-PF-1_8 <<>> WARDA STATION (EXISTING-FUTURE) LOCATION: 177 SA 501288 EO MADELTAN PIECELL AN LONGHORN PIPELINE COMPANY, LP. PROST 200 DIAGRAM ORNING MUSE NONE SECTON APPROVED LP-PF-2_8 <<>> BASTROP STATION (EXISTING) LOCATION: 6081250015 ® arens MADELTAN PIPELINE COME LONGHORN PIPELINE PIPELINE COMPANY, LP. PROCESS FLOW DIAGRAM SHT. 3 OF 8 _ ZRI 8/11/04 SCALE RAWING NUMBE ONE TAFE APPROVED SECTION LP-PF-3_8 <<>> LOCATION: 172 CEDAR VALLEY STATION _HICKORY GREEK PEDERALES RNER FAT CREEK 57 1813826 51 1090537 STA 10742+78 MP 203.46 STA 1059657 8 51 10 19657 - MADELTAN PIPELINE COME PIPELINE COMPANY, LP. LONGHORN PIPELINE PROCESS 40V DIAGRAN 4 OF 8 _ ZRI 8/11/04 SCALE DRAWING NUMBER NONE TAFE APPROVED SECTION LP-PF-4_8 <<>> LOCATION: 178 ECKERT STATION (EXISTING-FUTURE #7999| 55A 165076200 5TA 1202836 80 5TA 1502847A 51 1627648 MMAGELLAN LONGHORN PIPELINE PIPELINE COMPANY, LP. PROCEST 5 O BAGRAM DRAWING NUMBER NoNE TAFE LP-PF-5_8 <<>> FORT MCKAVETT STATION LOCATION: 186 LOCATION: 173 KIMBLE COUNTY STATION SIA 158621 23 MAGELLAN PIPELINE COMPANY, LP PROCESS FLOW DIAGRAM LONGHORN PIPELINE SHT. 6 OF 8 ZRI 8/11/04 SCALE DRAWING NUMBER NONE ARE. APPROVED LP-PF-6_8 <<>> KEMPER STATION BIG LAKE STATION-179 (FUTURE) MADELAN PAGELLAN PIPELINE COMPANY, LP. LONGHORN PIPELINE PROST 100 DACRAM ORNING MUS NONE SECTON LP-PF-7_8 <<>> CRANE STATION-174 50 20618 55A 278682 8 2 STA 2252582 STA 248155 TA 27828065 SIA 2781618 : STA 2 48-58 50 20 572- MAGELLAN PIPELINE COMPANY, LP. MISTREAM PARTNEA LA PROCESS FLOW DIAGRAM LONGHORN PIPELINE SHT. 8 OF 8 ZRI 8/11/04 SCALE DRAWING NUMBER NONE ARE. APPROVED LP-PF-8_8 <<>> ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 5C TRENCH INTEGRITY AND CONSTRUCTION METHODOLOGY OF THE MAGELLAN LONGHORN PIPELINE FROM MILE POST 169.88 TO 188.8 <<>> TRENCH INTEGRITY AND CONSTRUCTION METHODOLOGY OF THE MAGELLAN LONGHORN PIPELINE: MILE POST 169.88 TO 188.8 Prepared for: Zephyr Environmental Corporation October 15, 2012 LBG-Guyton Associates 1101 South Capital of Texas Highway Suite B-220 Austin, Texas 78746 <<>> Table of Contents BACKGROUND ..................................................................................................................................................... 1 PROOF OF CONCEPT ............................................................................................................................................ 2 Figure 1: Typical Cross Section of Trench ............................................................................................................. 3 TRENCH CONSTRUCTION ..................................................................................................................................... 4 SERVICE LIFE OF GUNITE-LINED TRENCH .............................................................................................................. 5 LEACHING ........................................................................................................................................................ 5 DELAYED ETTRINGITE FORMATION .................................................................................................................. 5 SULFATE ATTACK ............................................................................................................................................. 5 ACID AND BASE ATTACK ................................................................................................................................... 6 SALT CRYSTALLIZATION .................................................................................................................................... 6 FREEZING AND THAWING ................................................................................................................................ 6 ABRASION, EROSION AND CAVITATION ............................................................................................................ 6 THERMAL DAMAGE.......................................................................................................................................... 6 SEISMIC / STRUCTURAL LOADS ........................................................................................................................ 7 CONTAINMENT STRUCTURES ............................................................................................................................... 7 RISKS AND HAZARDS ............................................................................................................................................ 7 LONG-TERM INTEGRITY ....................................................................................................................................... 8 CONCLUSION ....................................................................................................................................................... 9 REFERENCES ...................................................................................................................................................... 10 Appendix A Trench Construction Photos Appendix B Supporting Documents <<>> BACKGROUND The ultimate goal of the Longhorn pipeline trench design and sealing protocol used within the Edwards Aquifer Recharge Zone (EARZ) was to prevent a material volume of fluid from infiltrating into any recharge feature exposed within the trench over a short period of time. To achieve this goal, the trench, road bore pits, diversion berms and trench sealing materials were designed to collectively capture and contain any potential product release. This secondary containment system was constructed in order to prevent significant product migration to either a groundwater recharge feature or surface water feature that might directly or indirectly recharge the Edwards aquifer (LBG-Guyton Associates, 2001). The focus of this report is to summarize the trench design and the materials and methodologies that were utilized to prevent material impacts within the EARZ. However, it should be noted here that the trench itself was only the final in a series of safeguards that were put in place to prevent product migration from the pipeline to the aquifer. Other design elements of the integrated safeguard system consist of: 1. 2. 3. 4. 5. 6. 7. 8. Lowering of the pipe relative to ground elevation, Replacement of the original pipe with an improved thicker walled (0.375 in), higher grade (X65) pipe and improved fusion bond epoxy outer coating, Placement of a leak detection cable that will detect a 0.003 bbl/hr leak of crude oil in 100 to 200 minutes (Magellan PHMSA letter, 2012), Backfilling with high-permeability fill materials, As-built trench and bore pit capacity designed to contain five minutes of unchecked flow during a 100-yr/24-hr design event (10-in rainfall), Subsurface (bore pits) and surface diversion structures (berms) to contain product exceeding the design capacity of the trench (Paragon, 2001a), Bore pit sumps with standpipes for vacuum-removal of accumulated water, and Flow restriction devices (automatic check valves, remote-controlled block valves). In addition, maintenance elements of the integrated safeguard system include: 1. 2. ROW access restrictions to prevent heavy loads from crossing the pipeline, Monitoring of pressure gradients in conjunction with a hydraulic leak detection system monitored remotely at a control room manned 24/7, 3. 4. Flow gradients and potential water accumulation in the trench, The maintenance of containment berms and the low-permeability clay ditch crown installed over the pipeline trench, and 5. Scheduled daily aerial surveillance. 1 <<>> PROOF OF CONCEPT In order to verify the effectiveness and integrity of the trench sealing techniques and design features utilized over the EARZ, Longhorn agreed to perform a Proof of Concept (POC) field test to demonstrate that the applied materials and methodologies would prevent a material volume of fluid from infiltrating into any recharge feature exposed in the trench cut. The criteria for success were threefold: 1) evaluation of the rate of water loss after a 24-hour period, 2) quantification of tracer dye concentrations made during the over-excavation of the test trench and 3) analysis of potential tracer concentrations in samples from Barton Springs and local water wells (LBG-Guyton Associates, 2001). To test the trench sealing techniques, six trenches were excavated in series within the ROW in the Leached/Collapsed Member of the Edwards Formation. POC tests were performed in two of the six trenches which exhibited the largest number and variety of features thus making them the most difficult to seal. Three different sealing approaches were utilized during the POC. The trench materials and methodologies determined to be most effective for the POC field test were subsequently implemented across the approximately 3-mile segment of the pipeline replacement corridor (PRC) within the EARZ. The results of the POC indicated that the trench sealing materials successfully prevented direct infiltration of a material volume of water over the test period. A typical cross section of the trench is shown in Figure 1. 2 <<>> Figure 1: Typical Cross Section of Trench 3 <<>> TRENCH CONSTRUCTION Potential hydrogeologic features were identified, photographed and spot cemented prior to continuous sealing. Continuous sealing of the trench floor and walls consisted of: 1) 2) 3) 4) 5) Application (pour) of a wall-to-wall concrete and aggregate mix on the trench floor. High velocity spray application of polypropylene ¾” fiber-reinforced gunite on trench walls (Paragon, 2001b, see Appendix B). Inspection of gunite thickness (nail test) integrity and consistency. Repair of any gunite spider cracks or flaws with an overcoat of the Magnacoat epoxy- polyurethane mix sealant (Magnacoat, 2002) Application of an epoxy-polyurethane joint seal to the cove of the trench (Appendix B) Materials placed in the trench (below the concrete cap) after the continuous sealing phase included: 6) 7) 8) Six-inches of pea-size gravel were placed on the trench floor as padding. 18-inch diameter product pipe placed in trench. Hydrocarbon-sensing leak-detection cable (Tyco TraceTek TT5000), sheathed in a perforated PVC conduit, were placed on top of pea gravel between 18-inch product pipe and trench wall. (Magellan PHMSA letter, 2012, see Appendix B) 9) Additional pea gravel backfilled to a height of approximately 6 inches above the product pipe 10) A 3-feet thick layer of aggregate backfill (with an average lab porosity of 43%) was placed in the trench to provide structural integrity and containment capacity (see Appendix B) Installation of a concrete cap and ditch crown involved the following procedures: 11) To enhance the bonding between the concrete cap and the gunite walls, a bonding agent was applied to the gunite walls at the top of the aggregate backfill prior to pouring the concrete cap. 12) A four-inch layer of fiberglass-reinforced red-dyed concrete was then poured on top of the trench materials to complete the upper seal (to prevent any influx of precipitation into the trench) and provide a warning indicator for any potential future excavation. 13) A low-permeability clayey soil was placed above the concrete cap to grade and the same material was used to construct an additional six-inch crown on top of the trench in order to shed runoff away from the trench. Photos of the various trench components are included in Appendix A. 4 <<>> SERVICE LIFE OF GUNITE-LINED TRENCH There are several important factors controlling the service life of concrete or gunite. These primary risk factors affecting service life are described below: LEACHING Water containing little or no calcium ions (soft water) or acidic ground water can hydrolyze or dissolve the alkali oxides and calcium containing products resulting in increased permeability of the concrete. The potential for this leaching action to occur is highly unlikely as the gunite is bonded to the face of the Edwards Limestone where the expected Total Dissolved Solids (TDS) usually range from 250 to 350 mg/l. The cations for the typical Edwards water are dominated by calcium and magnesium. In addition, the rate of leaching is a function of the permeability of the concrete and that the gunite has a low permeability due to the application method. DELAYED ETTRINGITE FORMATION Generally, delayed ettringite formation (DEF) is seen as a form of internal sulfate attack. Concrete undergoing DEF can exhibit expansion and cracking. DEF is believed to be a result of improper heat curing of the concrete where the normal ettringite formation is suppressed. The development of DEF is dependent on the amount of sulfate available, curing temperature and on the presence of water during the service life. (Hine, 1996) DEF almost certainly will not occur because the groundwater in vicinity of the trench has sulfate concentrations that are typically less than 50 mg/L, which are considered minimal. In addition, the gunite cure process was not accelerated and the gunite is not frequently exposed to significant amounts of water. The trench was installed above the water table and its’ design inhibits water from entering the trench. For these reasons, DEF is not considered a potential threat. SULFATE ATTACK Sulfates present in the aggregates, soils, and ground water can react with the calcium hydroxide and the hydrated tri-calcium hydroxide to form gypsum and ettringite, respectively. These reactions can result in deleterious expansion and produce concretes with reduced strength because of decomposition and expansion of the hydrated calcium aluminates. In addition to the chemical attack described above, sulfates can also attack concrete physically. As groundwater enters the concrete by capillary action and diffusion and evaporates, the sulfate salts concentrate, sometimes generating pressures large enough to cause cracking. The Edwards Aquifer is composed of a freshwater zone and a sulfidic, saline water zone. The sulfidic, saline zone is located to the east and down dip from the gunite trench which is in the freshwater zone where the sulfate concentrations are typically less than 50 mg/L. Concentrations of sulfate (SO4) in the 5 <<>> ground water less than 150 mg/L are considered minimal exposure conditions. In both the chemical and physical sulfate attack, the common link is the requirement for the sulfate solution to enter the pore spaces of the concrete. Studies have shown that it is essential to limit the ability of the sulfates from entering the concrete; this is done by reducing the permeability of the concrete (minimizing the water-to-cementitious materials ratio and provide good curing). In that the presence of sulfate concentrations are considered minimal, a chemical or physical sulfate attack is not considered a potential factor for the deterioration of the gunite trench. ACID AND BASE ATTACK Acids can combine with calcium compounds in the hydrated cement causing it to become soluble and therefore leachable. This leaching will increase the concrete’s porosity and permeability. The main factors for this type of attack are the type of acid, its’ concentration and pH. The soils of the Edwards Aquifer recharge zone should be expected to be basic (with pH values >7.0). Basic solutions, particularly solutions containing high concentrations of sodium and potassium hydroxide (>20%), can cause concrete to degenerate. It should be noted that gunite is resistant to mild acid and base chemical attacks, due to its’ low w/cm (low permeability). SALT CRYSTALLIZATION Crystal growth within the concrete can result in internal pressures causing cracks in concrete. This type of physical attack results from repeated crystallization due to the evaporation of salt laden water in the pores of the concrete. Because of the inherit design of the trench, in that it inhibits the entry of water into the trench and the low permeability of the gunite, salt crystallization is not a potential damage scenario. FREEZING AND THAWING Concrete is susceptible to damage if saturated with water and exposed to freezing/thawing cycles. Since the gunite trench will not experience these temperature fluctuations due to its’ burial, the potential for damage to occur from this type of physical attack is minimal. ABRASION, EROSION AND CAVITATION These types of physical attack result in the loss of surface material. Because of the trench’s burial depth, none of these physical attacks are considered a potential damage scenario. THERMAL DAMAGE Elevated temperatures and thermal gradients affect concrete’s strength and stiffness. Surface spalling can occur if the rate of heating is high and the permeability is low. Typically, a design oriented 6 <<>> approach is used when considering thermal loads on concrete structures. In the case of the gunite trench, thermal loads and their impact on the gunite trench are considered negligible due its’ burial depth and inherent lack of temperature cycles. SEISMIC / STRUCTURAL LOADS In service stresses induced by mechanical loads such as fault movement and vehicular traffic are considered minimal as the faults identified in the recharge zone are not active, and daily inspection of the pipeline right of way limits uncontrolled vehicular traffic. CONTAINMENT STRUCTURES The trench is designed to be a conduit for product to migrate under the force of gravity to either a road bore pit or diversion berm. Bore pits were installed on both sides of all road crossings to provide additional containment capacity. The elevation of the bore pit floor is a minimum of 2.5 feet lower than the trench floor. The dimensions of the berms vary, depending on the containment capacity required in each particular drain-down section; however, the typical length of the bore pit is a minimum of 55 feet. The sealing protocol for the bore pits is identical to the trench; however, a geotextile fabric was added between the bore pit fill and the concrete cap for stability. A 4-inch sump with an above-grade riser in each bore pit provides both a method of inspection as well as a means for water or product removal (Paragon, 2001a). Diversion berms were designed to divert surface flow away from certain known karst features within the EARZ. The floors of the berm structures contain a 6-inch thick clay material liner. There are four berms located on the EARZ and just east of the EARZ between approximately Deer Lane (west of Brodie Lane) and the corner of Cameron Loop Road (east of Brodie Lane). These structures protect the Goat Cave Karst Preserve, Deer Park Cave, the Blowing Sink Tract and the Dry Branch of Williamson Creek. RISKS AND HAZARDS Naturally-occurring hazards that could potentially undermine the integrity of the trench include (hydro) geologic hazards such as earthquakes, subsidence, aseismic movement along fault planes, earth material failure or deformation, scour, erosion, and flood potential (Longhorn Pipeline Partners, 2001). There is a 0.19% chance of a major earthquake within 50 kilometers of Austin, Texas within the next 50 years. The largest earthquake within 100 miles of Austin, Texas was a 3.9 Magnitude in 2008 (USGS Earthquake Hazards Program). Although earthquakes do occur in south-central Texas, they are not considered a significant risk factor to the integrity of the pipeline and associated structures. 7 <<>> Fault locations identified in the Geologic Assessment of the 3-mile ROW within the EARZ (Horizon, 2000) were published by the USGS (Small, et. al., 1996). There are nine mapped faults within the Balcones Fault Zone (BFZ) that transect the EARZ segment of the ROW. These faults typically are southwest-northeast trending normal faults that are downthrown toward the east-southeast. The BFZ was last active in the early Miocene, which was approximately 15 million years ago (Young, 1972). There are four faults in the Houston area that are being monitored for aseismic movement, but they are not considered as an issue in this report. Materials failure such as structural wall collapse due to lateral pressure is inhibited by the presence of limestone bedrock as well as the materials that fill the trench, which lend structural stability to the entire trench system within the EARZ. Additionally no shrink-swell clays (vertisols) were encountered in the trench in the EARZ. The Del Rio Clay (a vertisol) is located just east of the EARZ in the Edwards Aquifer Transition Zone (EATZ). The EARZ and EATZ are separated by fault S-1 (Small, et. al., 1996). Gunite was not applied to trench walls east of this fault. The Del Rio Clay typically fails via bulging from increasing principal stress difference, which is alleviated with drying. The presence of the trench and associated high-permeability fill material within the low- permeability clay will provide a preferential flow path for water. The trench fill physically inhibits significant expansive movement by the native materials, provides a flow conduit for water, and serves to inhibit bulging failure within the Del Rio by reducing the water content of the clay adjacent to the trench (Tonan, 2009). Water forces that might affect the pipeline were the subject of numerous studies which concluded that the most significant concerns associated with water include scour, erosion, flood potential and the effects of floodwater movement across the ROW. Thus, the pipeline crossing at Barton Creek was replaced (lowered) to minimize the threat of stream bed scour (Longhorn Mitigation Plan, 2000). This stream crossing is located west of the EARZ. LONG-TERM INTEGRITY In the Longhorn Mitigation Plan (LMP), Longhorn has committed to 40 mitigation measures to address the four leading causes of pipeline failures which are: 1) outside force damage, 2) corrosion, 3) operator error and 4) material defects. Longhorn created a System Integrity Program (SIP) in order to analyze and manage the various risks inherent to pipeline operations in order to ensure long-term safety and minimize environmental impacts. Longhorn also committed to perform annual Operational Reliability Assessments (ORAs). The LMP, LMP first and second supplements, annual ORA summary reports, LPSIP self-audit reports and commitment implementation status reports are available online for years 2008 through 2011. A few examples of the long-term maintenance commitments that have been committed to in order to extend the service life of the trench include: 8 <<>> 1. Restricting access to the ROW in order to keep traffic and heavy loads off of the pipeline 2. 3. structures. Monitoring and removal of water accumulated in trench bore pits via sumps with risers. Maintenance of the low permeability soil crowns on the trench and the bore bits to keep water off of the trench structures. In a third-party review of the engineering design prepared for U.S. Fish & Wildlife, Dr. Konuk reviewed the engineering design report (Paragon, 2001a) and the alignment sheets and stated the following: “Considering the quality of the new line pipe, the conservativeness of the design, and the prevention measures from the third-party damage, including the protective concrete slabs, and the redundant leak detection system (cable), the author considers the risk posed by this segment to be very low, well below the historical records collected from other pipelines.[…] The author believes that, assuming that all the operations procedures are implemented and commitments to improve these procedures as more experience is gained from the pipeline followed, the probability of a significant leak, defined as a release of product more than one barrel, in this three mile section should be much smaller than the score of 1 incident per 2000 years per mile of pipe. Also the author cannot see any design improvements that can significantly decrease this risk score for this three-mile segment.” (Konuk, 2001, see Appendix B). CONCLUSION Service life prediction for the gunite trench is not an exact science because the trench is buried; however the engineering safeguards utilized during installation, lack of seismic/structural loads, lack of physical and chemical deterioration factors relative to the trench components lead to a high level of confidence that the trench integrity remains intact. With similar structures lasting 50+ years it is reasonable to expect this trench to last at least this time period, given the lack of degradation processes. 9 <<>> REFERENCES ACI Committee, 2000. Service-Life Prediction State-of-the-Art Report, by the American Concrete Institute, Committee 365. Hime, William G., July – August, 1996. Delayed Ettringite Formation – A Concern for Precast Concrete?, PCI Journal, Precast / Prestressed Concrete Institute Horizon, 2000. Geologic Assessment for Longhorn Pipeline 3-mile Right-of-Way, Edwards Aquifer Recharge Zone, Travis County, Texas, June, 2000. LBG-Guyton Associates, 2001. Results of Proof of Concept Tests To Verify the Design and Construction Methods for the Longhorn Partners Pipeline Trench over the Edwards Aquifer Recharge Zone in Austin, Texas, December, 2001. Konuk, I., PhD. 2001. Review of Engineering Design Basis for Containment – Nineteen Mile Replacement Section, Longhorn Partners Pipeline, L.P., prepared for U.S. Fish & Wildlife Service, dated November 31, 2001. Longhorn Pipeline Partners, 2000. The Longhorn Mitigation Plan, dated September 11, 2000, at http://www.magellanlp.com/longhorninfo.aspx Magellan PHMSA letter, dated February 14, 2012, RE: Longhorn Pipeline Reversal – LMP changes. Magnacoat Industrial Coatings, 2002. Information Request for News Release, Bayer/Magnacoat Spray Elastomer Coating, Longhorn Pipeline 19-mile Pipeline Replacement Project, Travis and Hays Counties, Texas, December-July 2002. Paragon Engineering Services, Inc., 2001a. Engineering Design basis for Containment, Nineteen Mile Replacement Section 18” Products Pipeline, October 2001. Paragon Engineering Services, Inc., 2001b. Trench Gunite Sealing Specification, Specification Number: 99059-SP-001. RCP, 2011. 2010 Annual System Integrity Plan Self-Audit Reports for Magellan Midstream Partners, L.P. Longhorn Pipeline, dated December 16, 2011. Small, T.A., et. al., 1996. Geologic Framework and Hydrogeologic Characteristics of the Edwards Aquifer Outcrop (Barton Springs Segment), Northeastern Hays and Southwest Travis Counties, Texas. U.S. Geologic Survey Water-Resources Investigations 96-4306. Tonon, F., et. al., 2009. Effect of Verification Cores on Tip Capacity of Drilled Shafts (with emphasis on the material properties of four clay shales (Del Rio Clay, Eagle Ford Shale, Taylor Marl, and Navarro Shale) in central Texas, Center for Transportation Research at the University of Texas at Austin, Technical Report 0-5825-1, October 2008, revised February 2009. USGS Earthquakes Hazards Program website http://earthquake.usgs.gov/aboutus/, a component of the multi-agency National Earthquake Hazards Reduction Program. Young, K., 1972. Mesozoic History, Llano Region in Geology of the Llano Region and Austin Area Field Excursion Guidebook 13, edited by Barnes, V.E. et. al., Bureau of Economic Geology, University of Texas at Austin 10 <<>> Appendix A Trench Construction Photos <<>> Trench Cut (Flags Mark Potential Features for Inspection) Bore Pit (Corran Ferry Road) <<>> Boring under Corran Ferry Road Trench Inspection <<>> Trench Inspection Feature at 9138+40 <<>> Feature at 9296+50 Spot Cementing <<>> Spot Cementing Concrete Floor <<>> Concrete Floor Core l Concrete Floor Core <<>> Gunite Crew Gunite Crew (from trench inspection box) <<>> -2-4-02 9038-00 Gunite Wall POC*2 CORE 2 Gunite Core <<>> Gunite Bore Pit Wall Gunite Core with FIbers <<>> Gunite Bore Pit (Sendera Mesa) Sealant Application <<>> Contact between Gunite and Sealant Cove Seal <<>> Sealed Trench 05/30/2002cg Sealed Trench <<>> Gunite Inspection COK Sealed Weld on Pipe <<>> Pipeline on Pad Leak-Detection Cable PVC Conduit <<>> Concrete Cap and Gunite-Cap Seal Bore Pit Geotextile Fabric and Concrete Cap <<>> Appendix B Supporting Documents <<>> Longhorn Partners Pipeline Nineteen Mile Pipeline Segment Replacement 18” Products Pipeline Project 99059-SP-001 November 2, 2001 Trench Gunite Sealing Specification Specification Number: 99059-SP-001 REVISION A B 0 1 2 STATUS For Review For Construction Prepared By: GAT Checked By: JRB Approved By: Project Manager JRB Date of Issue: 2-Nov-01 S:\Projects\Magellan\Magellan Longhorn\white paper\references\Gunnite Spec 99059-SP-001 2Nov01.doc <<>> Longhorn Partners Pipeline Nineteen Mile Pipeline Segment Replacement 18” Products Pipeline Project 99059-SP-001 November 2, 2001 Dry Mix Shotcrete Application Equipment The dry mix shotcrete equipment shall be the feed bowl type as per ACI 506R-10 3.2.2.2 such as Ridley Rotary Gunite Machine Model C-9A and the equipment shall be operate by a qualified applicator. Dry mix shotcrete material performance specification. 1. Portland Cement Type I – 760 lbs / cy 2. Aggregate gradation ACI 506R-8 2.4.1 – 2878 lbs / cy 3. Water – 266 lbs / cy 4. Harbourite polypropylene ¾” fibers manufactured by Synthetic Industries, Chattanooga, TN – 4 lbs / cy 5. Compressive Strength (7 days) – f ‘c > 4,000 PSI S:\Projects\Magellan\Magellan Longhorn\white paper\references\Gunnite Spec 99059-SP-001 2Nov01.doc Page 2 of 2 <<>> Information Request for News Release Bayer / Magnacoat Spray Elastomer Coating Longhorn Pipeline 19-Mile Pipeline Replacement Project Travis and Hays Counties, Texas December - July 2002 Bayer's questions presented in italics. 1. Details about the pipeline project to the extent possible without revealing sensitive or proprietary information: How long is the section of pipeline that was repaired or rebuilt? What will the pipeline transport? Who owns the pipeline? This project consisted of the full replacement of approximately nineteen miles of 18-inch steel pipeline through the city of Austin, Texas and nearby environs in Travis and adjoining Hays Counties, Texas. This distance crosses the environmentally sensitive Edwards Aquifer Recharge Zone and Contributing Zone as will be discussed below. The pipeline will transport refined petroleum products, namely: unleaded gasoline, Diesel fuel, and jet fuel. The pipeline is owned by Longhorn Pipeline Partners, LLP of Dallas, Texas. 2. Were there any sensitive environmental requirements or concerns that the pipeline project had to address or comply with that could be discussed int eh news release? i.e. groundwater safety? The pipeline replacement project occurred as the result of an environmental lawsuit and subsequent settlement negotiated with agencies of the Federal Government. Chief among the concerns in the suit was protection of sensitive groundwater resources of the Edwards Aquifer Recharge Zone (EARZ) from sources of potential pollution. 3. Describe the problem posed by the Longhorn Pipeline project that caused your engineering firm and / or the pipeline's owners to look for a solution that would seal the concrete floor and gunnite walls. One of the settlement stipulations of the project was that no material volume of pipeline product would be allowed to leave the pipeline right of way in the unlikely event of a pipeline leak. To ensure that this stipulation was met, a design had to be implemented that would essentially capture any product released within the Bayer Magnacoat News Release information.doc 1 6/7/2012 <<>> confines of the pipeline trench so that it could be recovered, thus preventing it from entering the groundwater supply. Approximately three miles of the nineteen miles replaced crossed the EARZ. This zone is geologically characterized by very porous rock formations often providing very direct paths for surface water to enter the groundwater system. This three mile long section was treated with the gunnite / concrete trench lining, further sealed at the wall and floor junctures with the elastomeric material and a select gravel backfill material providing interstitial storage for a fluid release. 4. What specific properties or performance were you seeking in a material? As the trench design specified spray-applied gunnite to the trench walls and a poured concrete floor, the leak integrity of the wall-to-floor joint had to be ensured. This leak integrity was ensured by a combination of controlled joint geometry, the use of a synthetic bonding agent between the gunnite wall and concrete floor, and finally, the over-coating of the entire joint area with the Magnacoat synthetic elastormer product to seal any remaining gaps. The Magnacoat product was selected because it met the requirements for longevity, flexibility, resistance to deterioration whether exposed to acidic or alkaline soils, and resistance to deterioration if ever exposed to refined hydrocarbon products. As with the gunnite and concrete materials, the Magnacoat elastomer could not electrically interfere with the pipeline cathodic protection corrosion prevention measures. 5. Were there any local, state, or federal guidelines the material would have to meet? There are, at this time, neither governmental requirements nor guidelines for the provision tor or design of lined pipeline trenches such as that implemented by Longhorn Pipeline. However, this design was submitted and reviewed by the local, state, and federal agencies having oversight participation in this project. 6. What lead you to Mike Swearingen and his Magnacoat Industrial Coatings business? From its inception, this project was deemed newsworthy in the Austin, Texas press. As Longhorn conducted full-scale mockup testing of the sealed trench design, Mike Swearingen read published accounts regarding the project in the Austin newspapers. He approached Longhorn suggesting that the Magnacoat product might have application in meeting Longhorn's stringent design and performance criteria for the sealed trench. Bayer Magnacoat News Release information.doc 2 6/7/2012 <<>> 7. Why was the material solution proposed by Mike Swearingen appealing to your firm or the pipeline owner? The unprecedented sensitivity of this project required Longhorn Pipeline and the engineering design team to make every reasonable effort to ensure the long-term performance of the trench design. Because the sealed trench design is buried below ground, inspection and routine maintenance of materials for the trench seal would be problematic if not impossible in the future. For this reason, all materials chosen for use in the design had to demonstrate long-term performance in the environment in which they were installed with no subsequent maintenance. The Magnacoat product met these performance criteria. It seems an ideal match for the design challenge to which it is applied. 8. Was your engineering company pleased with the installation and performance of the spray polyurethane elastomer? As with any first-time or unique engineering solution, there are bugs to be worked trenches with remote devices to meet excavation safety requirements, out. For this project, there were challenges in applying the product in deep scheduling challenges, and the cooperation of the local weather conditions to ensure optimal application conditions. Magnacoat worked diligently to meet these challenges and both they and their product performed as expected. 9. Would you consider using this material again for a project with similar requirements? Should another project with similar requirements present itself for such a solution, this product should certainly be considered. Bayer Magnacoat News Release information.doc 3 6/7/2012 <<>> Pipeline Replacement Corridor (PRC) Longhorn Pipeline Trench Fill Data Austin, Texas Sample Pre-trenching sample data ID Sample Porosity Field Porosity Permeability cm/sec Absorption Comments TCS-066 TCS-063 44 TCS-262 8/8/2001 42 large gravel TCS-066 8/8/2001 8/8/2001 48.7 3.3 7.9 6.1 2.2 2.8 pea gravel medium gravel TCS-063 48.7 51.9 2.4 medium gravel large gravel Vulcan - 1" dirty Yarrington - 1-2" mixed /ulcan - 1" clean 12/17/2001 12/17/2001 46 12/17/2001 12/17/2001 43 49.1 48.7 1.6 Yarrington - 1* mixed 48 45.8 1.4 Yarrington - 3/4" pipe bedding Yarrington - 3/4" crushed 12/17/2001 12/17/2001 42 43 45.4 44.2 2.2 1.4 East End PRC sample data 38 40.7 2.1 1.4 East End East End 1/22/2002 1/21/2002 40.5 1/31/2002 40 field measurement 40 field measurement field measurement West End 1 East End 1 2/4/2002 2/8/2002 43.2 43.1 1.0 West End 3 West End 2 2/14/2002 2/13/2002 44.1 43.4 1.1 0.4 RR 12 stockpile 1.2 Cedar Valley station West End 5 West End 4 2/27/2002 43.7 0.6 Cedar Valley station West End 7 West End 6 2/22/2002 43.6 0.4 0.5 Kinser Ranch Fitzhugh Place 3/4/2002 East End 2 3/12/2002 3/6/2002 45.9 45.6 0.8 0.4 Kinser Ranch Fitzhugh Place West End 8 East End 3 3/12/2002 3/12/2002 41.6 40.8 41.6 0.9 1.3 Cameron Loop Deer Lane West End 9 East End 4 West End 10 4/2/2002 3/27/2002 42.7 42.4 0.7 1.0 btn 290 and Derecho - from padder Fitzhugh xing at Barton East End 5 4/18/2002 4/17/2002 41.7 0.5 at Ramble Three - from padder 42.4 1.1 1.2 FM 1826 East End 6 East End 7 4/26/2002 43.0 47.0 west side Slaughter Average - PRC samples 6/9/2002 0.8 0.9 Slaughter xing 43.3 Slaughter east borepit Note: All lab results provided by Trinity Engineering/Kleinfelder, Austin, Texas. <<>> MAGERLAN PO BOX 22186 One Williams Center MIDSTREAM PARTNERS, L.P. Tulsa, OK 74172-2186 Via Certified Mail - Hardcopy Requested February 14, 2012 Mr. R.M. Seeley, Director Southwest Region, Pipeline Hazardous Materials and Safety Administration 8701 South Gessner, Suite 1110 Houston, TX 77074 Re: Longhorn Pipeline Reversal - LMP Changes Dear Mr. Seeley, As previously communicated, Magellan Midstream Partners is developing a project, which is currently under NEPA review, to reverse the Longhorn Pipeline from Crane to Houston, Texas to transport crude oil. As part of this Proposed Project, Magellan has evaluated the Longhorn Mitigation Plan (LMP) requirements and proposes the following changes to the LMP contingent upon approval of the Proposed Project: 1. Mitigation Appendix - Item 13. This item currently outlines a leak detection performance commitment for the hydrocarbon sensing leak detection cable that was installed and currently functional over the Edwards Aquifer Recharge Zone and the Slaughter Creek watershed in the Edwards Aquifer Contributing Zone. The current commitment does not contain a performance specification for crude oil. Magellan is proposing to add the performance commitment for crude oil as follows (red text): <<>> • Page 2 - Longhorn Pipeline Reversal- LMP Changes 2/14/2012 Leak Detection Performance Commitment: Longhorn is committed to implementing the best available leak detection systems with the following design specifications: SYSTEM DESIGN LOCATION SPECIFICATIONS Tier I 1% of flow detected within one-half hour. Tier II •. .5%- 1% of flow detected within one hou % or more of flow detected within one-half hou Tier III • Same as Tier II, except Edwards Aquifer Recharge Zone. Edwards Aquifer Recharge Zone and Same as Tier II, and sensor-based detection of 0.0030467 barrel/hour from contact for the following products: (Slaughter Creek Contributing Zone Gasoline - 12 minutes watershed) : Diesel Fuel - 60 to 120 minutes : Crude Oil - 100 to 2000 minutes Jet Fuel - 50 to 70 minutes Magellan contracted with Tyco Thermal Controls to conduct tests of the sensitivity of the existing TT-5000 leak cable on two different types of crude oil currently anticipated to be transported on the Longhom System. See Report # TT 1106-006 (Attachment #1). These tests confirmed the cable sensitivity as published by TraceTek. See Attachment #2. Additionally, Magellan contracted with Spartan Engineering Inc. to evaluate the existing systems capabilities in crude oil compared to other direct detection methods. Spartan determined that the existing leak detection cable is the best available technology for crude oil. The Spartan report is contained herein as Attachment #3. <<>> • Page 3 - Longhorn Pipeline Reversal- LMP Changes 2/14/2012 2. Mitigation Appendix - Item 22. - This item was completed prior to original start-up in 2005 and required the installation or relocation of check valves to mitigate potential drain down volumes. Due to the elevation profile of the line, check valves would not effectively mitigate a leak when flowing in the reverse direction. Therefore, as part of the proposed project, Magellan is proposing to replace currently installed check valves specified by Mitigation Item 22 with remotely controlled valves (RCV). Both devices are considered Emergency Flow Restricting Devices (EFRD's) in accordance with 49 CFR 195.450. In some cases RCV's will be relocated for greater accessibility to power utilities and for maintenance and thus minimize the environmental impact of the change. Potential drain down volumes affected by these modifications will remain below maximum drain volumes as specified within Mitigation Appendix Item 22. All RCV's will be in place and functional prior to initiating crude flow from Crane to Houston. River Basin Station Location Approximate Current Approximate (Check Valve) Proposed Station Location Description Notes Pedernales 10210+24 Location (RCV) River (maximum 10210+24 Near Flat Creek No change in location drain down 200,000 gallons) volume of 10263+24 10263+24 Ulrich Rd and Co Rd 301 No change in location 10503+95 10503+95 Near the Pedernales River No change in location 10538+00 10538+00 West Side of Pederales R. No change in location 10742+50 10742+50 Near Cottonwood Creek No change in location 10850+40 10810+80 Near Hwy 281 Relocated 11192+24 11192+24 School Rd Near FM 1323 and Sandy No change in location 11310+24 11267+52 Near White Oak Relocated between Austin Colorado River 7110+58 7154÷40 Near Colorado River Relocated (maximum drain and Bastrop 7357+15 7386+72 Near Bastrop, TX Relocated 300,000 gallons) down volume of 7877+23 7824+96 Close to Jenkins Road Relocated (maximum drain Liano River 14606+59 14612+40 Near the Liano River Relocated 250,000 gallons) down volume of 14834+24 14834+24 Hwy 377 near London, TX No change in location 15014+74 14988+86 London, TX Relocated (maximum drain San Saba River 17143+24 17143+24 Co. RD 245 No change in location 350,000 gallons) down volume of 17886+00 17946+72 Eldorado, TX Relocated 18299+24 18299+24 Hwy 190 W. of Eldorado, TX No change in location <<>> • Page 4 - Longhorn Pipeline Reversal- LMP Changes 2/14/2012 See Attached Drain down Summary (Attachment #4) and Drain Down profiles (Attachment #5) illustrating changes to drain down associated with the new locations of some of the required EFRD's. 3. Section 2.1 - System Description - This language will replace section 2.1 and 2.2 in its entirety. The pipeline system covered under the Longhorn Mitigation Plan is made up of two distinct systems. The first system transports refined products from Odessa to El Paso, Texas. The refined product system with an initial capacity of 64,000 bpd is made up of the following segments: • A 29 mile, 8" pipeline from Odessa, Texas to a station in Crane County (Crane Station). A 237 mile, 18" pipeline from Crane Station to El Paso Terminal. Pumping units cou otentially be added at an existing site called Cottonwood Station to assist wit expansion of capacity. • Four, 9.4 mile, lateral pipelines connecting El Paso Terminal to El Paso Junction (also known as the El Paso Laterals). i. El Paso to Kinder Morgan, 12" ili. El Paso to Chevron, 8" ii. El Paso to Kinder Morgan, 8" iv. Kinder Morgan 8" Flush Line The crude oil system with an initial capacity of 135,000 barrels per day is made up of the following segments: intermediate pumping stations A 424 mile, 18" pipeline from Crane Station to Satsuma Station with the following • Cedar Valley - Hays County, TX Kimble County - Kimble County, TX • A 32 mile, 20" pipeline from Satsuma Station to East Houston Terminal. • A 9 mile, 20" pipeline from East Houston Terminal to 9* street junction. • A 1 mile inactive and purged section of 20" pipeline from gth street junction to Galena Park Terminal. bpd. To reach this capacity, Magellan may, in the future, build the following pump stations: Based upon shipper demand, Magellan may increase capacity of the crude system to 225,000 • Texon • Barnhart • I Cartman Eckert (existing scraper trap site) James River • Bastrop (existing site) • Industry Warda (existing scraper strap site) Buckhorn Satsuma (existing scraper trap site) <<>> • Page 5 - Longhorn Pipeline Reversal- LMP Changes 2/14/2012 Per Mitigation Commitment Item 39, this change to the LMP is submitted for PHMSA eview and approval. The proposed change in the form of this letter is made available to the public by posting on the Magellan website. Copies of this letter are made available to the General Manager of the Lower Colorado River Authority (LCRA) and to the Mayors of Houston, Austin, and El Paso at the addresses shown below. If you have any questions or need additional information, please contact me at your convenience. Sincerely, Doug Chabino Director, Asset Integrity Office phone: (918) 574-7326 Cell phone: (918) 645-3342 doug.chabino@magellanlp.com Cc: Rebecca S. Motal General Manager, LCRA Austin, Texas 78703 3700 Lake Austin Blvd. Mayor Annise D. Parker City of Houston P.O. Box 1562 Houston, TX 77251 Mayor Lee Leffingwell 301 W. 2nd St. 2nd Floor Office: City Hall Austin, Texas 78701 #2 Civic Center Plaza Mayor John Cook 10th floor of City Hall El Paso, Texas 79901 <<>> • Page 6 - Longhorn Pipeline Reversal- LMP Changes 2/14/2012 Attachment 1 Tyco Thermal Controls Report # TT 1106-006 <<>> tyco TraceTok Thermal Controls Magellan West Texas Crude Oil (Intermediate & Sour) TT-5000 Response Time 307 Constitution Drive Tyco Thermal Controls Menlo Park, CA Report # TT 1106-006 (7/21/2011) Lail Bednes Prepared by: Neil Bednar Approved by: Ken McCoy (Report# TT 1106-006) Tyco Thermal Controls Proprietary Page 1 of 3 <<>> TEST: TT5000 Response Time to WTI and WTS 1. Applicable Standards None 2. Test Description electrical resistance of each segment, so that the elapsed time to reach 10 kg (alarm threshold) could be measured. The segments of sensor cable were inserted into clear plastic tubing and then gently depressed to form a low spot in the center of each test cable. 5 ml of crude oil was injected into the open end of temperature which averaged 20.3 °C during the test period for samples #1 #2, #4, and #5. The each tube and allowed to form a pool in the low spot. Tests were conducted at ambient lab ambient temperature was 21.2 °C during the test period for samples # 3 and #6 Fig. 1 TT5000 WTI and WTS detection time test setup. Fig. 1 Crude oil pooling in specimen tubes. The resistance between the two internal sensor electrodes in the center of the cable core is monitored to determine sensor cable response. The beginning resistance value is essentially an open circuit and remains a very high resistance until the cable jacket has absorbed sufficient oil to cause the cable to "trip'. The detection time is indicated by a very precipitous drop in the resistance between the electrodes from greater than 50 MS to less than 10 kg. time as the point where the resistance between electrode wires drops below 10k. Electrical resistance We noted the start time at the moment when the cable was exposed to the crude oil and the ending and time were measured by a Fluke Data Logger and computer. 3. Test Responsibility Neil Bednar (Report# TT 1106-006) Tyco Thermal Controls Proprietary Page 2 of 3 <<>> 4. Test Results All samples reached alarm threshold of less than 10 kg in less than four hours. The WTI was detected in an average of 92 minutes and the WTS was detected in an average of 184 minutes at room temperature. Às temperature rises, the detection time will decrease on the order of approximately one half the reaction time for every 10°C as a rule of thumb. Specimen Number (#) Type of Crude Oil Time to Alarm Average Time to 1 (min) WTI 99 Alarm (min) 3 2 WTI 94 92 WTI 83 4 WTS 186 WTS WTS 189 184 177 5. Equipment Used Description Datalogger Manufacturer Fluke Model Hydra Software rev NA Serial No. 6095601 6. References Neil Bednar's Lab book 1344-30 (Report# TT 1106-006) Tyco Thermal Controls Proprietary Page 3 of 3 <<>> • Page 7 - Longhorn Pipeline Reversal- LMP Changes 2/14/2012 Attachment #2 Trace Tek Chemical Response <<>> TraceTek Chemical Response TraceTek. response times at 20 deg C under laboratory test conditions. For critical applications, customers should NOTE: This data is provided for general reference only and is not guaranteed. Values are nominal Controls for more information. confirm response times based on application specific installation parameters. Contact Tyco Thermal Tyco, TraceTek and the TraceTek logo are trademarks of Tyco Thermal Controls LLC or its affiliates. Group Chemical TT3000 TT5000 (TT5001 1/010 Notes Acid Acetic Acid 25% / СНЗСО-ОН Yes Yes Acetic acid 50%~99.4% / Yes Yes СНЗСООН FeCI3 Ferric Chloride / Yes 9.5~37% / HCI Hydrochloric acid Yes Yes / HF Hydrofluoric acid 49% Yes Nitric acid 15~65% Yes il Yes / H2S04 Sulfuric acid 25-98% Yes Yes Alcohol Ethanol (95% in H2O) / CH3-CH2-OH Yes 60 min CH2-OН Ethanol 100% / CH3- 60 min ilisopropanol Yes 90 min (IPA) / (CH3)2 CHOH i Isopropyl Alcohol 90 min CH40 Methanol (100%) / 45 min a.k.a. wood spirit, wood alcohol, methyl alcohol in H20) [Methanol (up to 95% Yes fetection at 95% concentration. Sensitivity increase Ip to 150mm of TT3000 must be wetted fo (less cable must be wet) for lower concentrations. Caustic Sodium hydroxide (concentrated) / Yes Also known as Caustic Soda NaOH Sodium Hypochlorite / NaOCI Yes Fuel Diesel #1 | 60 min | Diesel #2 120 min Fuel oil #6 * @ 60 C * no response @ 20 C, 41~64 hrs @ 40 C, 9~11 hrs gasoline 9~20 min* 48 min • depends on grade and type of gasoline gasoline vapor 3 days 5 days Jet A 50 min 4~11 hrs Jet B Yes Yes JP-10 40 min JP-4 15 min <5 hrs JP-5 70 min <4 hrs JP-7 25 min 10 hrs <<>> TraceTek Chemical Response Trace Tek. response times at 20 deg C under laboratory test conditions. For critical applications, customers should NOTE: This data is provided for general reference only and is not guaranteed. Values are nominal Controls for more information. confirm response times based on application specific installation parameters. Contact Tyco Thermal Tyco, TraceTek and the TraceTek logo are trademarks of Tyco Thermal Controls LLC or its affiliates. Group Chemical HOOD MEADO ATTORe i Do Notes Fuel kerosene 47 min Light Sweet Crude 3 hrs Hydraulic fluid Automotive transmission fluid 4-8 hrs Response time may vary considerably by brand and Dextron I/ brand ~8.3 hrs Ford brand 4.1 hrs type. brake fluid (DOT 3) hrs* ~30 hydraulic oil days* 3~8 "depends on type Lubricant SAE 20 motor oil <1 day SAE 30 motor oil 2 days Other Aliphatic (generic) hydrocarbon Varies Fuels and oils are typically aliphatic (long chain) HC's, translates into viscosity (longer = heavier) and hence with some aromatics blended in. Length of chain into longer response times. Hydroxide / NH4OH Ammonium Yes must be in solution; will not detect dry form anisole Yes 1.7 hrs 33 min carbon disulfide 3 min chloroform 12 min 10 min dimethylformamide Yes 2 hrs Dowtherm A 10 hrs 90 min Dowtherm J = alkylated aromatic Dowtherm A = diphenyl oxide / biphenyl blend ethyle acetate 20 min ethylene glycol Yes Formaldehyde temperature. (Boiling Point -21C) When it is dissolved See Formalin. Formaldehyde is a gas at room in water (remember the frogs in your biology class) it is called formalin. Usually the commercial concentration is 40% in H20 Formalin Yes (dissolved in H20, typically 40% solution). This is the typical liquid form of Formaldehyde Freon TF 22 min : 42 min gum turpentine 10 min 20 min (heptane 10 min 60 min Hydrogen Peroxide / H202 Yes mineral spirits Mobiltherm 603 20 min <9 hrs <4 hrs Naptha 15 min PCB <9 hrs <<>> TraceTek Chemical Response Trace Tek. NOTE: This data is provided for general reference only and is not guaranteed. Values are nominal confirm response times based on application specific installation parameters. Contact Tyco Thermal response times at 20 deg C under laboratory test conditions. For critical applications, customers should Controls for more information. Tyco, TraceTek and the TraceTek logo are trademarks of Tyco Thermal Controls LLC or its affiliates. Group Chemical TT3000 TT5000 TT5001 TT7000 Notes Other Prestone antifreeze Yes Shell Diala X transformer oil 13 hrs Transformer oils vary considerably. styrene monomer 20 min 8 min (tetrahydrothiophene 25 min 27 min Solvent /methanol 50/50 methylene chloride < 10 min Blend of methylene chloride and methanol acetone | 10 min Acetone (30% in H20) Yes Acetone 50% in 20) Yes 80 min butyl acetate 20 min carbon tetrachloride 20 min 20 min chlorobenzene 21 min 10 min cyclohexane 32 min dichloromethane 13 min 5 min Ethyl benzene Yes Methy! Ethyle Ketone (MEK) 10 min T73000 Avoid exposure to TT1000 or Methylene Chloride ~5 min N-methyl pyrrolodone 60 min (dissolves kynar) Will damage TT3000 / TT1000 toluene 18 min 10 min [trichloroethane 20 min trichloroethylene 8 min (xylene 20 min 35 min <<>> • Page 8 - Longhorn Pipeline Reversal- LMP Changes 2/14/2012 Attachment #3 Pipeline Leak Detection Systems Direct Detection Spartan Engineering, Inc. <<>> Pipeline Leak Detection Systems - Direct Detection Prepared for: MAGELLAN MIDSTREAM PARTNERS, L.P. October 18, 2011 (R3) By: SPARTAN ENGINEERING INC. <<>> CONTENTS 1.0 Overview 2.0 Executive Summary 3.0 Types of Leak Detection Systems 3.1 General 3.2 Liquid Sensing Leak Detection 3.3 Vapor Sensing Leak Detection 3.4 Fiber Optic Leak Detection 3.5 Ultrasonic/Acoustical Leak Detection 3.6 Comparison 4.0 Conclusions and Recommendations 5.0 Appendix 5.1 Corporate Contact Info 5.2 Tycho Thermal Controls Data 5.3 Asel-Tech Data 5.4 Nitor Technologies Data 5.5 Sensornet Data <<>> 1.0 Overview Magellan is interested in currently available technology for early detection of pipeline leaks that can be employed on the section of the Longhorn pipeline traversing the Edwards Aquifer. Additionally, because the Longhorn Reversal project will introduce crude oil to the line, there is interest in the capability of these systems to adequately detect crude oil. This report focuses on the direct sensing style of pipeline leak detection systems that are most capable of detecting small leaks. The direct methods include liquid sensing cables, fiber optic cables, vapor sensing tubing, and ultrasonic sensing. Information on these direct sensing methods (and companies that can provide them) has been compiled from an extensive search and is included in appendices of this report. 1 <<>> 2.0 Executive Summary Each of the four direct pipeline leak detection technologies investigated will detect crude oil. Direct detection methods are best at detecting leaks that are less than about 0.5% of the pipeline flow rate, while computational methods are best at detecting leaks that are greater than about 0.5% of the pipeline flow. Therefore, to cover all circumstances, it is recommended Magellan maintain both types of systems. For the direct sensing method, it is recommended to retain the existing Tyco TraceTek TT5000 system. It has the advantage of already being in place, it has the ability to detect leaks as small as 0.01 GPH, it can locate leaks accurately, and it has proven to be reliable. The liquid sensing cable systems are the most sensitive for detecting small leaks with a 2-3 hour response time. The existing Tyco TraceTek TT5000 is extremely robust and reliable and capable of detecting leaks as low as 0.01 GPH and is not impacted as much because of soil porosity, soil temperature and low vapor pressure as the other systems reviewed. See Section 3.2 under Tyco TraceTek TT5000 for a detailed discussion. Vapor sensing systems are not as sensitive to small leaks or to leaking materials with very low vapor pressures, such as heavy oils. Additionally, response time is more dependent on soil porosity and soil temperature than the liquid sensing systems. The minimum detectable leak size is 0.04 GPH, in high-sensitivity mode. See Section 3.4 under Nitor Technologies for a detailed discussion. Fiber-optic cable systems and acoustic sensing systems are very poor at detecting small leaks. These units rely on either a change in temperature or an acoustic footprint to detect leaks. These systems are very reliable when detecting leaks of highly volatile liquids but they are not suitable for crude oil since the leak does not develop a sufficient differential temperature (essentially ground temperature) nor does it develop enough acoustic energy to allow the system to reliably detect a small leak. Additionally, the reliability decreases as the vapor pressure of the material to be detected approaches zero. See Section 3.4 Fiber Optic Leak Detection and Section 3.5 Ultrasonic/Acoustical Leak Detection for a brief discussion. 2 <<>> 3.0 Types of Leak Detection Systems 3.1 General The available pipeline leak detection systems (LDS) fall, generally, into two broad classes; 1) discussed because this topic is beyond the scope of this report. Direct detection, and 2) Computational/Statistical. Computational/Statistical will not be API Publication 1149 outlines methods for calculating the size of a leak in terms of the total pipeline flow rate. This leak rate is often described as a percent of the total pipeline flow with the total flow given to estimate the leak size. The direct detection methods are associated with efforts to detect leaks with sensing systems that can locate the leak within a few meters of its origin. These include: 1) Liquid Sensing leak detection, 2) Vapor sensing leak detection, 3) Fiber-optic leak detection, and (4) Ultrasonic/Acoustical leak detection. Direct leak detection depends upon a sensing system in the area around the location that has been deemed to be most sensitive to the effects of a pipeline leak. These detection techniques depend upon a change in some physical property associated with the pipeline, the pipeline surroundings, or changes to a sensor based on some characteristic of the leaking fluid. These can be summarized as: 1) the conductivity (or electrical resistance) of the cable; 2) localized temperature changes; 3) some characteristic physical effect that is always associated with a leak, such as the presence of vapor, or the sound associated with a leak. 3.2 Liquid Sensing Leak Detection Liquid sensing cables are buried beneath or adjacent to a pipeline and are specifically designed to detect changes in transmitted energy pulses as a result of impedance differentials induced by contact with hydrocarbon liquids. Safe energy pulses are continuously sent by a microprocessor through the cable. The pulses are reflected and returned to the micro- processor. Based on the specific installation of the cable, a baseline reflection map is stored in the memory of the microprocessor. When a leak occurs, a portion of the cable is saturated with fluid. The fluid alters the impedance of the sensing cable, which in turn alters the reflection pattern returning to the microprocessor. The change in signal pattern causes the microprocessor to register a leak alarm that also locates the position of the altered impedance. Controller interface software is available to provide real-time information on leak detection and record keeping. Cable types are chosen for each application based on the specific type of fluid being monitored. The cable detects a leak independently of the leak rate and thus is a good choice for small leaks, which are more difficult to detect than large leaks. The sensor cable responds directly to the presence of the liquid and not to the rate at which it arrived. Additionally, the leak detection cable can report the spill location to an accuracy of a few feet. Liquid sensing leak detection is typically marketed as a self-contained leak detection and location system, including all hardware and software. Advantages include relatively high <<>> accuracy in determining leak location, no modifications to existing pipeline, and simple software configuration and maintenance. A system that detects oil leaks based on a change in electrical resistance is the Tyco TraceTek TT5000. The Tyco system can locate leaks to within a few feet of their source. An analysis of the Tyco TraceTek TT5000 leak detection cable currently used on the Longhorn Pipeline System is provided to determine its applicability to a crude oil pipeline. Iyco TraceTek TT5000 Leak Detection Cable The Tyco TraceTek TT5000 leak detection cable currently in use on the Longhorn Pipeline System is usable for detecting crude oil leaks, as demonstrated by Tyco (see Table below). The minimum detectable leak size is 0.01 GPH. The TraceTek cable system is apparently the only electrical conductivity cable available. It should be noted that after a leak is detected by the cable, the portion of the cable that was exposed to the leak must be replaced. Tyco Thermal Controls has performed testing on three different oils, West Texas Intermediate summarized in the table below. (WTI), West Texas Sour (WTS) and ARCO North Slope Oil. The results of these tests are TT5000 Response Time Oil Type Temperature 68°F Temperature 104°F WTI 92 to 93 minutes 15-20 to 22 min WTS 184 to 190 minutes 42 to 45 min ARCO North Slope 180 minutes 42 minutes The results indicate that the TT5000 will respond to the presence of a WTS oil leak within about 3-hours after the sensor cable has been in contact with the oil. In other words, for very small leaks the TT5000 will always set off an alarm. 3.3 Vapor Sensing Leak Detection The Leak Alarm System for Pollutants (LASP) consists of a vapor sensing tube installed along the entire length of the pipeline. This tube is impervious to water but allows petroleum vapors to pass and accumulate. A vacuum pump periodically draws the air from the tube and passes the air stream through a sensor which detects the presence of petroleum vapors. Detectable substances include a wide range of gases, hydrocarbon liquids and vapors, halogenated hydrocarbons, landfill gases, water vapor, and many others. This vapor sensing system has the potential to detect leaks of all sizes; however, very small leaks can take 30 hours or more to detect. The detection tube is manufactured in the form of a cable and is highly permeable to the substances to be detected in the particular application. If a leak occurs, the substances to be measured come into contact with the tube in the form of vapor, or gas dissolved in water. In the event of a leak, some of the leaking substance diffuses into the tube. After a period of time 4 <<>> has passed, enough vapor will accumulate inside the tube so that when the air in the tube is pulled past the detector there will be enough vapor to produce an accurate identification of the substances surrounding the tube. The detector unit at the end of the sensor tube is equipped with gas sensors so that an increase in gas concentration results in a pronounced "leakage peak," which is proportional to the concentration of the vapor from the leaking medium at the sensor tube surface. A disadvantage of the LASP technology is that the time required to draw a vapor slug to the detector will vary substantially because of diurnal and seasonal changes causing decreased leak location accuracy. Nitor Technologies, Inc. PROWLER LDS Nitor Technologies, Inc. carries the PROWLER system and has upgraded the LASP system technology. The published minimum detectable leak size is 0.04 GPH. However, this leak rate is not referenced with a statement about the volatility and temperature of the leaking substance was not specified in the literature. Vapors emitted by the leaking crude oil diffuse into the PROWLER tubing and reach a steady state or equilibrium concentration. The PROWLER pump is then activated to move the vapors in the tubing to the detector, where measurements are made. Depending on soil porosity and oil vapor pressure, several hours may be required for gases and vapors to migrate from the leak site to the PROWLER tubing. To see a change from the baseline condition, a minimum of two runs is needed, each taking as long as 15 minutes. The PROWLER can locate the position of the leak to within 1% of the length of the pipeline. For a twenty mile long section of pipeline, the accuracy would be less than 1100 feet. Using secondary test points, the location of the leak can be determined to within 50 feet. More precise leak location requires that a spike of tracer gas, such as Hydrogen or Ethane, be injected at the front end near the inlet-air dryer unit. For sizeable leaks, the density of the crude oil has little impact on response time. However, at very low leak rates the crude oil and the vapors emitted by the crude oil require more time to move through soil. Very small leaks of a heavy crude oil, as well as the vapors emitted by that oil, will move through the soil much slower than the rates observed for lighter refined products and their vapors to move through the soil. The reliability of vapor sensing systems is lower than the liquid sensing cable systems. The system is prone to set point drift and requires chromatographs that can lose sensitivity unless properly calibrated and maintained. A second sensor tube can be installed that continuously draws a vacuum. This option allows for a more rapid detection of large leaks (greater than 0.5% to 1.00% of flow) while still enabling the detection of small leaks by the periodic removal of the tubing air from the other tube. Operating with two tubes in this manner is recommended by the manufacturer. 3.4 Fiber Optic Leak Detection 5 <<>> The fiber-optic sensing leak detection method involves the installation of a fiber-optic cable along the entire length of the pipeline. The substances to be measured come into contact with the cable when a leak occurs, changing the temperature of the cable. The distributed fiber- optical temperature-sensing technique offers the possibility to measure temperature along the determined, leading to leak detection. pipeline. Scanning the entire length of the fiber, the temperature profile along the fiber is Optical fiber sensor cables have been demonstrated to be useful for the measurement of a wide variety of physical and chemical parameters because they have: 1) an immunity to wide variety of measured quantities, 4) avoidance of electric sparks, 5) resistance to harsh electromagnetic interference, 2) avoidance of ground loops, 3) capability of responding to a environments, 6) remote operation, 7) capability of multiplexing, and 8) ease of integration into large-scale fiber networking and communication systems. The reliability of the optical fiber cables is questionable for long-term use because of their fragility and the possibility of false positive signals caused by the presence of groundwater. For small crude oil leaks under low pressure, the leaking substance will have adequate time to thermally equilibrate with the material that surrounds the pipeline and the thermal sensor. Since the liquids and sensor will sensor to determine. This makes the fiber-optic LDS less desirable for crude oil applications. In be at the same temperature there will be little or no differential temperature for the fiber-optic fact, no reference has been found where fiber optic cable has been used in the determination and location of crude oil leaks from pipelines. Two of the companies that supply fiber-optic based LDS's are Sensornet and Westminster, Intl. The Sensornet Fiber-Optic Based LDS The Sensornet fiber-optic cable system allows the inference of a leak by detecting the change in temperature of the fiber-optic cable when it becomes exposed to the leaking fluid or a change in temperature of the space around the cable caused by the nearby presence of the leaking fluid. To date, the use of Sensornet's leak detection system has been for the detection of leaks on and around highly pressurized natural gas liquid products such as ethane, ethylene, propane, Y-grade products, and ammonia. Westminster, International Fiber-Optic Based LDS Westminster International appears to be in the private sector security business. They propose leaking from pipelines and storage tanks. that their fiber-optic cable systems be used to detect temperature changes caused by NGL's 3.5 Ultrasonic/Acoustical Leak Detection Leak detection in pipelines using acoustic emission technology is based on the principle that an leak occurs, the resulting low frequency acoustic signal is detected and analyzed by system escaping liquid creates an acoustic signal as it passes through a perforation in the pipe. When a processors. Deviations from the baseline acoustic profile would signal an alarm. The received signal is stronger near the leak site, thus enabling leak location. 6 <<>> Asel-Tech Asel-Tech has developed an acoustic/mass-balance/computational LDS that holds the possibility of improving the computational technology. Response time can be as short as a minute for leaks that are large enough to be acoustically detectable; however, the system's ability to detect small leaks is greatly reduced in low vapor pressure liquids that cannot generate sufficient acoustic energy to be detected over background noise. 3.6 Comparison The following table summarizes the properties of the various direct leak detection systems: Leak Detection Response Time Detectable Leak Size System TraceTek Tyco The detection response time is not dependent Leak rates lower than 0.01 GPH upon the leak rate. It is dependent upon the soil are detectable over a long TT5000 Leak porosity and the substance temperature. From period of time. The cable is Detection the data supplied by Tyco for Magellan: the responsive to both small and Cable response time for the WTS heavy crude is about large leaks. Response is not 45 minutes at 104°F and 190 minutes at 68°F; and for WTI light crude about 22 minutes at 68°F and dependent on the leak rate. The TT5000 is immune to the 93 minutes at 68°F. As a comparison, response presence of water. times for data done by Tyco for Arco on their North Slope crude: 42 minutes at 104°F and 180 minutes at 68°F. Leak location is typically within "a few meters" of the leak. Nitor Vapor Sensing The detection response time is dependent upon the leak rate, the soil porosity, and System - the oil volatility. In the high speed mode the system can detect leaks of 600 to 1300 High Speed GPH within a few hours. Large leaks, 12600 GPH or larger, can be detected in less Mode than 30 minutes. Additional response time factors include calibration frequency and the type and sensitivity of the chromatograph. The maximum detectable leak has no upper limit. The system is immune to the presence of water. Nitor Vapor As with the high speed mode, the detection response time is dependent upon the Sensing leak rate, the soil porosity, calibration frequency, and the oil volatility. In the high System - sensitivity mode detection time for the PROWLER is determined by the system's High setup parameters but is often given as 12 hours. While the published minimum Sensitivity Mode detectible leak rate is about 0.04 GPH the response time for this small leak rate may be as long or longer than 30 days. The system is immune to the presence of water Fiber Optic The leak detection time for a fiber optic system Fiber optic LDS is responsive to Leak depends upon the time required for the leak to both small and large leaks. Detection - cause a temperature change in the cable. Response time is dependent on Sensornet Response times are very fast for high volatility the vapor pressure of the and West- fluids like ethane, but for small low pressure minster leaking material and on the leak crude oil leaks there may not be a response. rate. 7 <<>> Leak Detection Response Time Detectable Leak Size System Hybrid Asel-Tech has developed an acoustic/mass- Leaks less than about 0.1% of Computa- balance/computational LDS that holds the total flow may not be detected. tional LDS - possibility of improving the computational Leaks that are greater than 0.5% Asel-Tech technology. Response time can be as short as a to 1% of total flow can be minute for leaks that are large enough to be detected. acoustically detectable. 4.0 Conclusions and Recommendations Each of the four direct pipeline leak detection technologies investigated will detect crude oil. For small leaks that are less than about 0.1% to 0.5% of the total pipeline flow rate, the TraceTek TT5000 is the most sensitive to crude oil. The Prowler vapor sensing system can also detect oil but its response time will be slower than the TT5000 because the loss of sensitivity associated with low vapor pressure crude oil. For leaks that are greater than 0.5% to 1% of the total pipeline flow rate, the fiber-optic cable and acoustic detection systems provide the fastest response time, giving indication of a leak in less than a minute after being contacted by the leaking substance. However, the Sensornet and Westminster fiber-optic systems may be less sensitive to crude oil than the other three leak detection systems because there will be little if any temperature change associated with a leak from a low pressure crude oil pipeline. Acoustic leak detection systems are also hampered by crude oil at low pressures because small leaks will not generate enough acoustic energy to be detected over the background noise. Because direct detection methods are best at detecting leaks that are less than 0.5% of the pipeline flow rate, and while computational methods are best at detecting leaks that are greater than about 0.5% of the pipeline flow, it is recommended that Magellan maintain both types of systems. For the direct sensing method, it is recommended to retain the existing Tyco Trace-Tech system. It has the advantages of already being in place, it can pinpoint the leak accurately, and has been proven to be reliable. The Nitor system is not recommended for detecting small leaks because the response time due to the low volatility crude oil is too great to detect them in a timely manner. The Sensornet, Westminster, and Asel-Tech systems are not recommended for use in detecting small leaks from low pressure crude oil applications for the reasons noted in section 3.4, above. 8 <<>> 5.0 Appendix 5.1 Corporate Contact Information Tyco Thermal Controls LLC 2415 Bay Road Redwood City, CA 94063-3032 Tel: (800) 545-6258 Fax: (650) 474-7215 TraceTek TT5000 http://www.tycothermal.com/ Asel-Tech Sao Carlos, Brazil Brazilian Corporation USA (281) 619-5754 USA (281) 990-2574 http://asel-tech.com/ PROWLER Nitor Technologies, Inc. 2750 Constitution Boulevard Beaver Falls, Pennsylvania 15010 Telephone (724) 891-4115 Fax (724) 847-6444 http://www.nitortechnologies.com/ Sensornet (British Company) 2002 Timberloch PL Suite 200, The Woodlands TX 77380, USA Alan Sanderson Ph: +1 281-296-5827 alan.sanderson@tendeka.com http://www.sensornet.co.uk/ Westminster, International, Ltd Westminster House, Blacklocks Hill Banbury Oxfordshire OX17 2BS United Kingdom +44 (0) 1295 756300 Phone +44 (0) 1295 756302 Fax Use website to make contact www.wi-ltd.com 9 <<>> • Page 9 - Longhorn Pipeline Reversal- LMP Changes 2/14/2012 Attachment #4 Drain Down Summary <<>> Longhorn Pipeline Reversal LMP Changes Drain Down Summary - Attachment #4 Page 1 of 1 Colorado Basin Valve 1 Location Existing MP Valve 3 Valve 2 139.34| 134.67 Proposed MP 135.51 Existing Station Proposed Station 149.19 139.91 7357+15 7110+58 7154+93 148.08 7877+23 7818-22 Pederales Basin Vaive 4 Valve 5 205.49 214.21 20175- 10849+87| 11310+29 11268+05 10810+80 Liano Basin Valve 7 Valve 6 236511 14606+59 15014+74 4616+1 4987+8 San Saba Basin Valve 8 338.75 339.91 17886+00 17947+25 Colorado drain down (gal) Existing Max Proposed Max 116,622 99,203 Drain down (gal) Drain down (gal) Settlement Max Between Bastrop and Valve 1 191,061 120,344 300,000 Between Valve 1 and Valve 2 263,689| 191,061 300,000 Between Valve 3 and Austin Between Valve 2 and Valve 3 263,689 300,000 300,000 Pedernales Between Valve 4 and MP 211.97 Between MP 203.44 and Valve 4 80,634 84,365 43,423 Between Valve 5 and End of Basin 136,472| 55,830 131,510| 200,000 Between MP 211.97 and Valve 5 136,472 37,220| 200,000 200,000 200,000 Llano Between MP 276.46 and Valve 6 Between MP 280.94 and Valve 7 Between Vaive 6 and MP 280.94 107,937 23,573[ 23,573 Between Valve 7 and End of Basin 126,547 94,290 107,937 250,000 250,000 140,241 250,000 250,000 San Saba Between Valve 8 and MP 346.57 Between MP 324.68 and Valve 8 275,426 181,136| 241,928 270,463 350,000] 350,000| proposed valve relocations with drain down volumes 1-25-12.xlsx <<>> • Page 10 - Longhorn Pipeline Reversal- LMP Changes 2/14/2012 Attachment #5 Drain Down Volumes <<>> Attachment 5 - Drain Down Volumes East Houston to Crane 18" Bastrop to Austin To Houston To Crane 1000.00 350000 300000 - 250000 200000 Elevation (ft) Volume (gal) 500.00 150000 100000 N - 50000 0.00 0 133 143 153 Milepost (miles) - Elevation -- Proposed Valves -• Non relocated valves - Existing, Valves - Proposed Draindown - Original Draindown <<>> Attachment 5 - Drain Down Volumes East Houston to Crane 18" Pedernales River Basin To Houston To Crane 2500.00 250000 200000 2000.00 - 150000 Volume (gal) 1500.00 100000 1000.00 50000 500.00 + 191 201 211 221 Milepost (miles) - Elevation -Proposed Valves -• Non relocated valves → Existing Valves — Proposed Draindown — Original Draindown <<>> Attachment 5 - Drain Down Volumes East Houston to Crane 18" Llano River Basin To Houston To Crane 2500.00 350000 300000 250000 - 200000 Elevation (ft) Volume (gal) 2000.00 150000 - 100000 1500.00 276 286 Milepost (miles) — Elevation →-Proposed Valves -• Non relocated valves Existing Valves —- Proposed Draindown ——- Original Draindown <<>> Attachment 5 - Drain Down Volumes East Houston to Crane 18" San Saba River Basin To Houston To Crane 3000.00 400000 350000 300000 250000 Elevation (ft) 2500.00 150000 100000 - 50000 2000.00 + 323 333 343 Milepost (miles) — Elevation -- Proposed Valves - Non relocated valves - Existing Valves - Proposed Draindown -- Original Draindown <<>> Review of Engineering Design Basis for Containment - Nineteen Mile Replacement Section Longhorn Partners Pipeline, L.P. Report prepared for US Fish & Wildlife Service November 30, 2001 Prepared by Dr. Ibrahim Konuk 39 Rocky Hill Road Princeton, NJ 08540 Tel: (732) 355-1544 <<>> Table of Contents Section Page 1.0 Introduction and Purpose 2 2.0 General Discussion of Effectiveness of the Proposed Containment System for 2 Different Pipeline Failure Scenarios 3.0 Comments on the Design Basis Document and the Performance of the 4 Proposed Containment System 4.0 Observations and Recommendations 5 Appendix: List of Documents 7 <<>> 1.0 Introduction and Purpose Longhorn Pipeline Partners (Longhorn) decided to replace about 18 mile section of the Longhorn Pipeline from the mile post 169.8 (Station 8965+00) to the mile post 188.8 (Station 9968+64). This pipeline segment crosses the Edwards Aquifer area: Edwards Recharge Zone, a segment about three miles long, starting at about mile post 170, and the Contributing Zone about 15 Miles in length to the west of the recharge zone. As part of this replacement program, Longhorn designed a product containment system, which would contain any released product or divert it to designated berm locations in case of a pipeline failure involving a product release. This system involves a specially designed pipeline trench of different depth and size depending on the location, road bore pits on either side of all the road crossings, and diversion berms at select locations that would promote any product reaching the surface to be diverted to designated locations. The U.S Fish & Wildlife Service (Service) and Longhorn Pipeline Partners have requested that the author review the proposed containment plan and comment on the validity of the calculations prepared to support the system design and the effectiveness of this system for the purpose of containment of any product release from the pipeline. This document presents an overall assessment of the proposed containment system in case of various size pipeline ruptures or leaks. It verifies the sample calculations provided in the design basis document (Reference 1). It also comments on the assumptions used in deriving the spill volumes. The author would like to note that two reports were prepared by the author in 1999 and 2000 on the pipeline risks and effectiveness of the mitigation measures to prevent or limit the risks resulting from a pipeline leak for the original pipeline that covered an area from the mile post 170 to the milepost 179. The proposed pipeline replacement plan contains this area and it addresses or voids all of the issues raised in those two reports. The proposed containment system addresses issues that were not directly within the scope of those two reports. This work was requested by the U.S. Fish and Wildlife Service and paid for by the Longhorn Pipeline Partners. The author would like to note that he received full cooperation from Longhorn and Service officials in conducting this work. 2.0 General Discussion of Effectiveness of the Proposed Containment System for Different Pipeline Failure Scenarios The following few paragraphs are taken from the report prepared by the author on August 31,2001: "The pipeline is well above the current code of practice and exceeds the requirements of the current applicable regulations. In addition, the company agreed to apply a very stringent public awareness and third party education programs including extensive signage. The company is also going install a secondary leak detection system in this three-mile segment to detect small leaks. 2 <<>> During a telephone conference arranged prior to the June 23 meeting, the author pointed out that the procedure for the remediation of the potential unsupported sections over any caves or cavities found during the trenching operation is left to the contractor. The company has agreed to develop procedures in advance and incorporate them into the construction specifications that will be used for contracting the installation of the pipe. During the June 23 meeting, the company representatives explained that all cavities would be grouted and, where the cavity is larger than a certain size, a (steel) reinforced concrete support will be constructed. In addition, during the June 23 meeting, it was explained that red colored fiber reinforced concrete slabs would cover the pipeline trench, to reduce third party intrusion. Considering the quality of the new line pipe, the conservativeness of the design, and the prevention measures from the third party damage, including the protective concrete slabs, and the redundant leak detection system (cable), the author considers the risk posed by this segment to be very low, well below the historical records collected from other pipelines. Although some attempt has been made to estimate this risk in References 1 and 2, these estimates are grossly conservative for this segment of the pipeline. The author believes that, assuming that all the operations procedures are implemented and commitments to improve these procedures as more experience is gained from the pipeline followed, the probability of a significant leak, defined as a release of product more than one barrel, in this three mile section should be much smaller than the score of 1 incident per 2000 years per mile of pipe. Also the author cannot see any other design improvements that can significantly decrease this risk score for this three-mile segment. Longhorn is to be commended for the risk reduction measures proposed over the Recharge zone of the Edwards Aquifer. The author believes that the risk from this pipeline is reduced by at least one order of magnitude when compared to the Contributing Zone, which is discussed in the next section." At the time, these comments were directed towards the pipe replacement plan, which applied only to a subsection of the contributing zone. These observations now apply to the whole of the recharge and contributing zones. It should, therefore be noted that the scenarios discussed in this section are, in general, a very low probability - well below the risks posed by most engineering systems. They are included for the sake of completeness and also to clarify the context of assessments presented in this report on the containment system. Small and medium size leaks (from 1/10th 'of inch to several inches) can result from corrosion or a construction defect fatigue (dent and gouge) coupled with corrosion or a small weld defect opening. Longhorn will employ measures during the construction and commissioning to ensure that no such defects exist in the pipeline when it is commissioned. In addition, they intend to utilize monitoring procedures that would detect such defect before it leads to a failure. The probability of such a failure would be extremely low if the monitoring procedures that were presented to the author during the review of the original pipe are being applied. The detection of such defects is well within the capabilities of the inspection tools planned to be used by Longhorn. The chance of a corrosion defect leading to failure is, therefore, a very unlikely scenario due to the fact 3 <<>> that Longhorn is committed to regular monitoring. Longhorn is planning to X-ray 100% of the field welds. It is also very unlikely that a weld defect could lead to such a failure. Even if a leak occurred, it should normally happen at relatively low pressure close to the design or the operating pressure of the pipeline. If a small or medium size leak happens during the normal operation of the pipeline at around 350 psi, the pore pressures within the trench in the vicinity of the failure location would gradually increase until the pipeline is shut-down. Since the maximum shutdown period is 5 minutes, if we assume that 350- psi would be maintained during that period at the rupture point, the pore pressures may reach to these levels several yards away from the failure location. Although all the construction joints in the pipeline trench are planned to be sealed, it is possible that a small quantity of the product may seep through some of the weak points between the cover slabs and the trench wall. It is very difficult to predict the volume of seepage without conducting some kind of pressure tests in a sample trench. However, the author would not recommend such a test as the likelihood of this occurrence is too low and the potential volume of product that can seep is extremely small. Large leaks can result from operator error such as accidental closing of valves and/or a brittle crack propagation event initiated at a defect by a similar over-pressurization condition. Normal maximum design pressure for the proposed 18 inch × 0.375 inch pipe is about 2000 psi depending on the safety factor used. The actual burst pressure for this pipe would be 2 to 3 times higher for a properly manufactured and inspected line pipe of this grade. In addition, the quality of the steel (high toughness) to be used for this pipeline is such that a brittle crack propagation event is extremely unlikely. Given current pipeline constructions standards and commitment by Longhorn to inspect the pipeline during construction and commissioning, and to monitor it during operation, the probability of a large leak occurrence is too small to be meaningfully calculated. However, if such a leak occurred, it would likely mean that the product pressure at failure location could reach a fairly high pressure (compared to 350psi normal operating pressure in this segment). In this case, the transient pore pressures developed in the trench may be high enough to lift the pipeline cover and some of the concrete slabs and discharge some of the product to the surface before a steady state condition is reached. At that point, a normal drain-down process would start as intended by the designers of the containment system. The quantity of material reaching the soil surface would depend on the location and the pressure at failure. Given the overall design of this pipeline and considering that this 18-mile segment is bound by pipe with lower pressure rating, this scenario could not reasonably be considered in the design. As it is stated above, it is included in this report for the sake of completeness. Regular third party damage scenarios are also very unlikely due to the installation of reinforced and specially colored concrete slabs. Regular construction equipment can normally not penetrate through the trench cover. As it is practice for commercial oil and gas pipeline designs, intentional third party damage is not included in the design. In the same way, major construction interference scenarios are also not considered, as appropriate precautions would be expected before such construction operations take place close to or within the pipeline right-of-way. The author would like to note again that the Longhorn pipeline, in the subject area, is designed against all required (by codes and regulations) load and failure conditions that can reasonably be incorporated in a pipeline 4 <<>> design. The design also incorporates features that address scenarios resulting from such failure conditions. 3.0 Comments on the Design Basis Document and the Performance of the Proposed Containment System Based on the discussion presented in the previous section, in the rest of this document, he tocus Will be on the small size leaks. The containment system provides a combinatior of Containment Trench, Road Bore Pits, Containment Berms, diversion berms, and Flow Restricting Devices. The overall objective of the system is to capture any released product within the pipeline trench or divert any excess volume to the Containment Berms. The pipeline trench is designed to include material with large porosity, which would provide the first line of defense by providing the space for the leaked product. The pipeline trench would be inspected by using sumps (pipes) to ensure that voids in the fill material are not filled with water. The sumps also can be used to remove any water that may seep into the trench. The Containment Berms are designed to capture any excess product. They would be equipped with special hydrocarbon sensing devices to allow the rainwater to drain out but not the product in case of a pipeline leak. The berms are always designed to be positioned on the lower side of the trench that they drain. This is done to promote gravity drainage. The trench size and berms are designed to contain the product released during the shut-down period (5 minutes) at worst case rate, subsequent drain- down volume, about 1% allowance for the pipeline expansion due to pressure, 12 hours 10 inch rain storm water (stated to be the 100 year rain storm). Flow Restricting devices are to be installed in eight locations to isolate different sections of the pipeline and minimize the drain volumes. These devices are check-valves and remotely operated block-valves. The elevation profile between these devices or the highest applicable drain- down point is kept between about 40 feet to 130 feet. Reference 1 describes design features as part of the containment system for 51 locations. Some of these features are coupled in function. The volume of containment for the relevant part of the trench considering the appropriate elevations and the berm or bore pits are calculated in each case. The direction of drainage is clearly specified. Sample calculations are provided in Reference 1 for one pipeline trench location and one road crossing. The Reference 1 also contains sample drawings for the trench and bore pits at those locations. The author would like to confirm that the sample calculations provided in Reference 1 are correct and are based on valid assumptions. However, the graph provided in Appendix B appears to contain some shift in the horizontal scale in comparison to the figures provided in the Excel printout included in the same appendix. It is recommended that this graph be re-drawn at a larger scale if it is to be used for the purpose described in the next section. The author would like to note that some of the extreme scenarios discussed in the previous section are not discussed or mentioned in Reference 1. <<>> 4.0 Observations and Recommendations It is recommended that the description of the 51 containment features (locations) and the graph included in the Appendix C be provided to all emergency response personnel along with the regulatory authorities (after it is updated to a larger scale). Any deviation in observed volumes in case of a pipeline failure occurrence should be explained in order to ensure that other unknown pathways do not provide drainage. The author observes that great effort is gone into design of the containment system. It is recommended that this be complimented by similar supervision of the construction procedures so that intended quality is maintained throughout, thus not creating any weak points in the system. The author would like to mention that the proposed system is the most comprehensive global containment system for any pipeline in North America known to the author although local containment berms have been used in some instances. 6 <<>> Appendix: List of Documents Engineering Design Basis for Containment - Nineteen Mile Replacement Section 18" Products 2. Pipeline Alignment Sheets from 6645-AL-0076A1 (Station 8965+00) to 6645-AL-0080G (Station Pipeline, L.P., Prepared by Paragon Engineering Services, Inc., October 2001. 9982+00), Dated 8/31/00 to 9/12/00. Revised on November 30, 2001, 2001. November 16, 2001. 7 <<>> ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 5D TRENCH INTEGRITY INSPECTION REPORT OF THE MAGELLAN LONGHORN PIPELINE FROM MILE POST 169.88 TO 173.38 <<>> TRENCH INTEGRITY INSPECTION REPORT OF THE MAGELLAN LONGHORN PIPELINE: EDWARDS AQUIFER RECHARGE ZONE (EARZ) MILE POST 169.88 TO 173.38 Prepared for: Zephyr Environmental Corporation and Magellan Midstream Partners, L.P. November 11, 2012 LBG-Guyton Associates 1101 South Capital of Texas Highway Suite B-220 Austin, Texas 78746 <<>> Introduction The Magellan Longhorn pipeline extends from El Paso, Texas through the greater Austin area and terminates at Magellan’s East Houston facility. The pipeline is located north of and runs roughly parallel to the IH-10 corridor (Figure 1). Magellan proposes both a reversal of the flow direction within the existing Longhorn pipeline as well as a change of service from refined petroleum to crude oil. This report documents an assessment of the gunite liner in the trench and associated containment system integrity across the Edwards Aquifer Recharge Zone (EARZ) segment of the pipeline replacement corridor and provides a detailed report of the excavation activities for Magellan’s records. Inspection Sites Magellan excavated and inspected the trench. The goal of the inspection was to determine the current integrity of the gunite liner and other trench components to determine if the system would continue to meet the intended design purpose – to prevent a material volume of fluid from infiltrating into any recharge features exposed in the trench. To accomplish this goal, two inspection sites were selected: 1) east of Mopac, and 2) west of Escarpment Boulevard (Figure 1). The Mopac excavation and refill activities took place between October 16 and October 26, 2012; activities at the Escarpment site occurred between October 22 and October 26, 2012. Inspection activities at Mopac and Escarpment were conducted on October 22 and October 24, respectively. Excavation Methodology Vacuum excavation was utilized in order to minimize potential impact to the existing trench structure. The VacMasters System 4000 was used, which allows for efficient digging with air into hard soils without harming underground utilities. All air excavation work was performed while: 1) standing at grade on the sidewall of the trench; 2) standing on the concrete cap in the trench; or 3) standing on fill materials in the trench at an elevation higher than the top of pipe. Once the top of the fill material in the trench was greater than four feet below grade, the workers were harnessed and continued to excavate from grade. One truck was used at the Mopac site and two trucks were operated at the Escarpment site to minimize total excavation time and the associated noise to adjacent homeowners. Fill materials were piled adjacent to the excavation, and were ultimately used to refill the trench. Materials removed from the trench were sorted; fines were placed separate from trench gravel/aggregate. The broken concrete cap was placed further from the trench for eventual removal by a third-party hauler. 1 <<>> Photos of excavation operations are included as Appendix A. The first step in the excavation process consisted of locating the top of the concrete cap. Five transects perpendicular to the ROW (at each site) were vacuum-excavated until the concrete cap was encountered. The dimensions of the transects were approximately 5’ long x 1’ wide x 2.5’ deep, and were located about 20 feet apart (Figure 2). Silt fences were installed at both locations during excavation of the transects. Once the concrete cap was located in the subsurface, the excavation footprint was generally defined by the transect locations. Each footprint was expanded slightly beyond the outermost transects to dimensions of approximately 100’ long by 5’ wide, and the materials above the concrete cap were subsequently removed using a backhoe. Figure 2. Trench Transects and Excavation Footprint (not to scale) Once the concrete cap was exposed at the Mopac excavation, the cap was initially cut with a Stihl cut- off machine and masonry blade. The sawing approach was quickly abandoned due to slow progress and an associated dust nuisance. Thereafter, a jackhammer was used to break through the concrete cap, as it proved to be a much more efficient (and dustless) method. A jackhammer was used at the Escarpment excavation to break through the entire section of concrete cap. Once the cap had been broken up, it was removed to a separate spoil pile on the ROW. The concrete cap was removed off- site and disposed of at 973 Materials in Del Valle, Texas. The remainder of the trench fill material was then removed via vacuum excavation into segregated piles on the ROW. The tank capacity of the VacMasters 4000 is less than 3 cu. yds. and approximately 60 cu. yds. of fill was removed from each excavation. The fill materials were allowed to slope from the end of the concrete cap cut to the floor of the trench with an approximate 3:1 to 4:1 slope, which left about 50 feet of gunite wall exposed on both sides of the trench excavation. A total of approximately 200 linear feet of gunite wall was exposed in both trenches. 2 <<>> Trench Inspection Overall, the gunite liner and trench were in excellent condition at both locations. The trench floor and walls were dry and the various components of the trench (fill, pipe, conduit, gunite liner and cap) appeared to be in original condition after ten years. The gunite liner was inspected at Sta. 9063+83 (Mopac) and Sta. 9114+54 (Escarpment) on October 22 and October 24, respectively. The gunite liner was observed to be smooth and continuous, both laterally and vertically, with only a few minor variances from the as-built condition. Photos of the trench inspection are included as Appendix B. The minor anomalies observed during inspection of the 200 ft of trench that was uncovered for inspection include: 1) minor divots in the poly coat sealant that occurred during fill removal, 2) peel cracks where the poly coat spot-treatment sealant separated from the gunite liner, and 3) infrequent penetration by small roots (two roots observed in a total 200 feet of exposed wall). The two roots (1/4 – 1/2 in. dia.) were found during the trench inspection at the Mopac site. One root was located above the concrete cap; one root was located below the cap. No radial cracking of gunite around the roots was observed. Hair-like roots were also present in the poly sealant material but were not observed to significantly penetrate the gunite or compromise the integrity of the gunite liner. The peel cracks are places where the poly sealant had separated from the gunite, however the gunite was observed to be completely intact behind the peel and crack features. The divots were small (<4 in dia.) areas where the gunite separated and fell from the wall only after the trench fill was removed. There is no evidence that the poly seal was not intact prior to excavation. Overall, the gunite and trench were in excellent condition at both locations. The trench floor and walls were dry and the various components of the trench (fill, pipe, conduit, gunite liner and cap) appeared to be in pristine condition after ten years. The poly coat spot-treatment sealant was observed to have a dark color that during initial inspection appeared to be moist sections of the walls. However, upon further inspection, it was determined that the discolored swatches on the gunite wall were associated with the poly sealant and not associated with moisture. The dark poly patches at the Mopac site had numerous hair-like roots growing within the poly seal only. The roots did not expand beyond the poly patches. The poly coat spot-treatment sealant was the only material observed that exhibited any signs of deterioration (peel cracks and divots) which we suspect may have occurred during excavation activities. Photos of the trench inspection are included as Appendix B. Trench Reconstruction The features in the trench noted above (divots, cracks, peels and roots) were repaired with materials recommended by the original gunite contractor: Shep-Patch Plus powder and acrylic polymer. The tree root was clipped flush with the wall surface and then patched. It should be noted that the tree root itself was observed to essentially fill the penetration hole that it had created in the gunite. Once 3 <<>> the gunite patches had dried, the fill gravel was put back into the trench to the level of the original concrete cap. Since the red dye in the original cap had stained the trench wall, the desired depth of the fill material was easy to determine. Approximately six cu. yd. of concrete was poured to cap each excavation. The red dye that was added to the concrete, CSI #120 Conduit Red, is a synthetic iron oxide (Fe203) that is lightfast, chemical and weather resistant. After the concrete cap had set, the original fill and native soils that were excavated from above the concrete cap were put back over the new cap. A trench crown was also constructed parallel to the pipe to allow for settling of the soils and to help divert runoff away from the excavation. Photos of the trench re-construction are included as Appendix C. Conclusions Overall, the gunite and trench were in excellent condition at both locations. The trench floor and walls were dry and the various components of the trench (fill, pipe, conduit, gunite liner and cap) appeared to be in original condition after ten years. The poly coat spot-treatment sealant was the only material observed that exhibited any signs of deterioration (peel cracks and divots) which we suspect may have occurred during excavation activities. The minor anomalies observed during inspection include: 1) minor divots in the poly coat sealant that occurred with fill removal, 2) peel cracks, where the poly coat spot-treatment separated from the gunite liner, and 3) infrequent penetration of small roots (two roots between 1/4 and 1/2 in. dia. observed in a total 200 feet of exposed wall). The minor anomalies were repaired prior to refill activities and are not considered significant enough to compromise the trench integrity or the original design goals of the liner. We therefore conclude that the pipeline trench design and sealing protocol used within the Edwards Aquifer Recharge Zone (EARZ) will continue to prevent a material volume of fluid from infiltrating into any recharge feature exposed within the trench during a potential spill event. The trench, road bore pits, diversion berms and trench sealing materials are performing well to collectively capture and contain any potential product release. The secondary containment system is functioning as designed and constructed in order to prevent significant product migration to either a groundwater recharge feature or surface water feature that might directly or indirectly recharge the Edwards aquifer. 4 <<>> EXPLANATION Longhorn Pipeline ROW Edwards Aquifer Zones Edwards Aquifer Contributing Zone Edwards Aquifer Contributing Zone within the Transition Zone Edwards Aquifer Transition Zone LBG-GUYTON ASSOCIATES *Service Layer Credits: Image courtesy of USGS © 2012 Microsoft Corporation ImagePatch.com © 2010 NAVTEQ © AND +N 0 2,000 1,000 Feet Figure 1 Trench Excavation Location Map Edwards Aquifer Recharge Zone (EARZ) Austin, Texas <<>> Appendix A Trench Excavation Photos <<>> Silt Fence Installation (Mopac) Vacuum Excavation Truck (Mopac) A-1 <<>> Trench Transect Cut to Tag Concrete Cap (Mopac) Trench Transect Cut, note Gunite Wall (Mopac) A-2 <<>> Removing Fill above Concrete Cap (Mopac) Concrete Cap Surface (Mopac) A-3 <<>> Saw Cut in Concrete Cap (Mopac) Breaking Concrete Cap (Mopac) A-4 <<>> Broken Concrete Cap (Mopac) Cement Cap, note Fiberglass (Mopac) A-5 <<>> Removing Trench Fill (Mopac) Pipe, Product Sensor-Cable Conduit and Electrical Conduit (Mopac) A-6 <<>> Fill removed, note exposed Cove and original Concrete Cap Contact (Escarpment) Trench Ready for Inspection (Escarpment) A-7 <<>> Appendix B Trench Inspection Photos <<>> Escarpment Excavation – South Wall, looking West Escarpment Excavation – South Wall, looking East B-1 <<>> Escarpment Excavation – North Wall, looking West Escarpment Excavation – North Wall, looking East B-2 <<>> Divots in Gunite Wall – Mopac Excavation, South Wall Divots in Gunite Wall – Mopac Excavation, South Wall B-3 <<>> Peel (Poly Coat separated from Gunite) – Mopac Excavation, North Wall Peel – Mopac Excavation, North Wall B-4 <<>> Vertical Cracks in Poly Coat – Mopac Excavation, South Wall Vertical Cracks in Poly Coat – Mopac Excavation, South Wall B-5 <<>> Root in Gunite (<1/2 in dia) – Mopac Excavation, North Wall Hair-like Roots in Poly Coat – Mopac Excavation, South Wall B-6 <<>> Appendix C Trench Refill Photos <<>> Divot Patches - Mopac Excavation – South Wall Gunite Patch Materials C-1 <<>> New Concrete Cap - Mopac Excavation, looking East Pouring New Cap - Escarpment Excavation, looking East C-2 <<>> Red Dye Material used in New Concrete Cap Fill to Grade with Crown – Mopac Excavation, looking WestC-3 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 6.0 PIPELINE RISK ASSESSMENT 6.1 INTRODUCTION This chapter provides a detailed assessment of risks associated with the operation of the System under the proposed reversal and change of product. This risk assessment addresses new and changing threats that may result from the reversal and change of product of the system and measures the change in risk from current operations of the existing assets in refined product service to operations under the Proposed Project. The risk assessment concludes that the risk associated with the Proposed Project will be lower than those experienced under current operations as a result of the mitigation measures outlined in Chapter 9. The Proposed Project introduces different risks to the System, however; additional proposed mitigation measures are seen to offset all potential probability of failure (PoF) increases. The 1999 EA used an indexing risk assessment model (relative risk model) as a basis for developing a risk profile. The relative risk model is still widely used in the industry today; however this risk assessment utilized a quantitative model which provides a greater degree of granularity for assessing risk along the system. The proprietary Quantitative Risk Assessment (QRA) model was developed and used by Kent Muhlbauer, P.E. in assessing the risks for the Proposed Project. The QRA is the most rigorous and complex risk assessment model available and is used in the chemical, nuclear, and aerospace industries and more limited in the petrochemical industry (Muhlbauer, 2004). The QRA is used in the pipeline industry as a robust alternative to the relative risk assessments in part because of its data intensive requirements. The QRA provides an absolute risk assessment of all possible failure events. As further described by Muhlbauer, it is a “rigorous and mathematical and statistical technique that relies heavily on historical failure data and event-tree/fault –tree analyses. Initiating events such as equipment failure and safety system malfunction are flowcharted forward to all possible concluding events, with probabilities being assigned to each branch along the way.” (Muhlbauer,2004). To assist the reader, the Risk Assessment methodology, definitions, and generally the more technical aspects, are included in Appendix 6A with the more discrete processes and procedures to manage these risks outlined in the main body of Chapter 6 below. 6.2 THREATS This Section focuses on the change in threats that will be introduced by (i) the change in product service from refined products to Permian Basin crude oil, (ii) the reversal of flow, and (iii) new facilities. The changing threats associated with the change in product service include the following: 6-1 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • Internal Corrosion • Hydrogen Blistering The changing threats associated with the reversal of flow from Crane to East Houston include the following: • Surge Pressure and Hydraulic Profile • Cracking • Stress Corrosion Cracking The changing threats associated with new facilities include the following: • Incorrect Operations • Security Threats The following threats will not be affected to a relevant extent by the Proposed Project. These threats will continue to be managed by existing processes and procedures. Some enhancements to data management and risk assessment processes are described in this section. • Atmospheric Corrosion • External Corrosion • Third Party Damage • External Forces 6.2.1.1 Internal Corrosion The System is currently in refined product service, however; historically the pipeline was in crude oil service for a period of about 45 years. Under the Proposed Project, internal corrosion potential is increased compared to current operations, due to the re-introduction of sweet and sour crude to the System. Representative crude samples of the two types of crude oil that will be transported (i.e. West Test Intermediate and West Texas Sour) were analyzed by an independent laboratory. West Test Intermediate (WTI) indicated no measurable H2S (less than 1 PPM). West Texas Sour (WTS) indicated H2S concentrations of 10 PPM (See Appendix 6B for further information). It should be recognized that crude characteristics vary across the Permian Basin but these samples are considered representative. The increased potential is primarily due to the presence of constituents in the crude oil, primarily H2S, which in the presence of water and oxygen can cause internal corrosion. As discussed below, internal corrosion can be reduced through mitigation by eliminating air and the use of an inhibitor. EnhanceCo cites prior work from Dr. Sheldon Evans that corrosion can be reduced through mitigation by eliminating air and the use of an inhibitor (Appendix 6C). Additional corrosion rate reductions can be achieved by removing water and solids from the line with the use of an aggressive cleaning pig program. Water can settle in low spots in the pipeline 6-2 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL and solids can promote entrapment of water and/or microbes, both of which can be a source of corrosion. Regular running of cleaning tools is designed to eliminate water and debris that may settle in low areas during periods of time when the pipeline is not flowing. Water and debris brought into the receiving trap by the cleaning tools will be tested to determine its potential to cause internal corrosion. Water will be tested per American Petroleum Institute RP-45. Monitoring will include select coupons located on the bottom of the pipe in low spots, where water and solids are likely to accumulate. These locations will be monitored for water and corrosion products, and coupons will be examined for the presence of pitting corrosion and pitting corrosion rates. A Drag Reducing Agent (DRA) will be injected into the pipeline to minimize friction loss on the pipe walls and thus minimize the need for additional pumping stations or higher operating pressures at select locations. DRA will be injected in low concentrations in the range of 85 parts per million (0.0085%). A safety data sheet for LiquidPowerTM Flow Improver, the DRA chosen for the crude oil application, is included in Appendix 6D. The DRA, LiquidPowerTM Flow Improver, is shown through testing to not increase the corrosivity of the crude oil. A series of tests were conducted to consider any potential effect of the DRA on the corrosivity of crude oil or crude oil/salt water mixtures. These tests were corrosion wheel tests, a widely used oil industry adaptation of ASTM standards (G-31 and G-46), based on weight loss of metal coupons placed in the test environment in a sealed vessel and rotated on a wheel or axle at constant temperature. The coupons utilized in the tests were made of cold- rolled mild steel stock. Corrosion rates were measured under two atmospheres for the crude oil: inert with nitrogen and oxidized with air. For the crude oil/salt water tests, the mixtures were sparged and blanketed with CO2. All tests were conducted at 70°F, and utilized Alaska North Slope (ANS) crude oil. ANS is similar in properties to the WTS crude. Half of the crude oil samples were treated with 150 ppm DRA to compare with the untreated crude oil. All tests were conducted in triplicate. The results of the corrosion tests are shown in the Table below. Any pitting is reflected in the table as a pitting index which varies from one to three. An index of 1 means no observable pitting; an index of 3 means lots of pitting. The test results indicate that addition of DRA to a crude oil system does not increase the corrosion rate of the system. Corrosion Rate Average (MPY) change with Crude Oil Corrosion Wheel Vapor Corrosion Pit 150ppm DRA Test Results Liquid Space Rate (MPY) Index added* Crude oil Nitrogen 0.8 1 No change Crude oil Air 0.7 1 Decrease by 0.1 50% crude oil/50% saltwater CO2 4.6 3 No change *Test conducted with LiquidPowerTM Flow Improver and ANS crude oil Detailed protocols governing the use of corrosion inhibitor injection, frequency of maintenance pigging, coupon installations, monitoring of coupons, and sampling are discussed in Section 6-3 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 9.3.2.2. Magellan currently operates an interstate pipeline transporting sour crude and mitigation measures have been shown to be effective in controlling internal corrosion. The continued use of metal loss ILI tools will enable Magellan to monitor any localized corrosion metal loss along the entire length of the pipeline. Mitigation discussed in Chapter 9 includes periodic re-assessments of the threat of external corrosion due to potential damages caused by internal corrosion. Table 5.3.1-1 details the currently established integrity assessment intervals per the Operational Reliability Assessment (ORA) Process to evaluate the internal corrosion threat. Corrosion rates established through the ORA are completed by third party consultant approved by PHMSA. These corrosion rates are utilized as part of the Probability of Exceedance (POE) analysis process. This process evaluates each unrepaired feature to ensure a low probability of a feature growing to a level that would exceed repair criteria. All corrosion features identified by the ILI tools are repaired to a level to ensure that remaining strength of pipe exceeds 1.39 times the maximum pressure allowed at the location of the feature. This maximum pressure determined includes any potential surge pressures as evidenced by pipeline surge analysis. Mitigation measures that target general internal corrosion are also effective in controling threats associated with internal corrosion selective to the longitudinal seam weld. Magellan’s processes and procedures contained within the SIP Integrity Management Program, SIP-ADM-7.06 (Appendix 6E), provide for determinations of re-assessment intervals to evaluate the integrity of longitudinal seam welds. Future longitudinal seam weld inspections are designed to detect any indications of corrosion along the longitudinal seam, which could be selective seam weld corrosion. Additionally, Magellan’s processes for evaluation of future metal loss features identified by MFL or UT tools are integrated with seam location information gathered from the TFI tools. This information is utilized to evaluate any metal loss of or along the longitudinal seam. This evaluation will determine if high corrosion rates are occurring at selected areas which may indicate selective seam corrosion is occurring. Through the ORA process, any information indicating areas of high corrosion rates would be investigated. Information gathered from the investigation of features would be used to establish appropriate re-inspection intervals via the POE and ORA processes. The risk assessment model completed for this FEA established estimates of risk along the entire length of the pipeline associated with internal corrosion. The estimates are represented as a PoF. For this FEA, PoF has been quantified for all portions of the System. Estimates are based on integration of all available location-specific information, producing a PoF profile along the pipeline route. This profile produced over 32,000 segments (average segment length is approximately 100 ft.), demonstrating a high level of resolution. Based on the proposed mitigation for internal corrosion, the PoF associated with internal corrosion for the Proposed Project is less than the existing PoF for current operations in refined product service. 6-4 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 6.2.1.2 Hydrogen Blistering National Association of Corrosion Engineers (NACE) discusses failure causes associated with H2S (NACE International, 2003). Hydrogen blistering is the major threat of failure resulting from H2S in pipelines with hydrogen induced cracking (HIC) being the failure mechanism once blisters have formed. Hydrogen from anaerobic corrosion is an important source of absorbed hydrogen for steel. The lattice hydrogen concentration is a function of the severity of the corrosive environment and generally increases with the presence of H2S. Based upon literature reviews, the failure mechanisms associated with blistering and H2S follows this process as summarized below (King, 2009). The time to failure is difficult to predict because the process involves many steps as described below. 1. Hydrogen must be absorbed by the steel. Although determining the absorption rate is difficult, it appears related to the concentration of H2S, H2O and the pH of the fluid. 2. Hydrogen (H+) must be diffused and recombined into molecular hydrogen (H2) at a lamination site. The chemical composition of the site would affect the rate at which atomic hydrogen combines and forms H2. It is thought that certain elements in the matrix such as sulfur and manganese increase the absorption or conversion of H+ to H2. 3. An H2 buildup would increase the pressure at the lamination until the lamination breaks, forming a hydrogen gas filled cavity or blister. 4. A blister would continue to grow and create a deformation toward the ID of the pipe and a stress concentration at the tips or in the center of the blister. 5. The stress concentration could eventually be large enough to cause crack initiation. 6. HIC cracks can grow and connect along the ID of the pipeline, causing a pressure connection between the lamination and the inside of the pipe. 7. Once the crack becomes large enough, the inner ligament can no longer carry hoop stress resulting in the outer ligament carrying all the stress. This is approximately double the normal load on the pipe steel since laminations tend to form at the mid-wall position in pipe steel. 8. The outer ligament may fail from crack initiation created during the link-up of individual laminations during blister formation. The crack may be influenced by HIC causing a through-wall crack to form resulting in a release of product. Prior history on the original pipeline in crude oil service shows this to be a slow process. There were no in-service failures caused by hydrogen blisters in the 23 failures reported during the 29 year interval from 1966-1995 (Johnson and Kiefner, 1999) where failure records exist. In 1995, 45 years after the pipeline was built, there were two documented hydrotest failures from blisters at Sta. No. 16518+08 (MP 312.8) and Sta. No. 16661+01 (MP 315.5) (Kiefner and Johnson, 2004). In this risk assessment, laminations are considered to be potential crack initiation points. They are modeled as having no immediate reduction on current strength but rather serve as locations of future crack initiation if the lamination becomes a blister. With the re-introduction of a source 6-5 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL of hydrogen, blister and crack formation is again a potential integrity threat. To model this in a risk assessment, lamination locations, as detected by in-line inspection (ILI), are treated as potential blister locations. These locations are modeled to be crack initiators and are assessed in Section 6.2.1.4, Cracking/Fatigue Monitoring. Monitoring of corrosion on the inside of the pipe with coupons and ILI and regular pipeline cleaning with pigs can help monitor and minimize the hydrogen generating environment. After running a UT wall measurement ILI tool in 2009 and 2010, Magellan has documentation on the locations of the laminations that existed in the original pipeline. In the formation of a blister, the outside ligament is held taught and the inside ligament is the one capable of deforming inward thus allowing for detection by a deformation ILI. LMC 12A requires deformation inspection every three years. The 45-year life of the blister that failed during the hydrostatic test is 15 times this required inspection interval and ILI should be capable of monitoring for blister formation and allowing for remediation before any HIC cracking penetrates both the internal and external ligament. The ILI inspections combined with a preventative program to monitor and keep water out of the pipeline from crude production can keep the potential of hydrogen blister failures to a very low likelihood. As part of the mitigation discussed in Section 9.3.2.3, Magellan will maintain sufficiently low probabilities of blister formation via existing inspections and analyses as per SIP- ADM-7.03, Integrity Testing and Rehabilitation (Appendix 6E). Ongoing risk analysis will identify if any additional mitigation measures, such as more frequent integrity testing, is required. As discussed above, the risk assessment for hydrogen blistering has been included as part of the Cracking/Fatigue Monitoring assessment (Section 6.2.1.4). PoF estimates derived from risk assessment modeling indicate that risk levels can be managed to levels at or below those associated with current operations when mitigation is applied. 6.2.1.3 Surge and Hydraulic Profile As a result of the flow reversal, change in product, and change in flow rates, the hydraulic profiles will change. The pipe on the east side of the pump stations are presently the suction side and normally experience lower pressure. Under the Proposed Project, this suction side will become the discharge side (downstream side) and experience the higher pressures produced by the pumping stations. It is likely that some pipe segments have not experienced the elevated operating pressures that will be produced in the reversed mode. Furthermore, there will be additional pumping stations installed as part of Phase 2 and these new pump stations will again produce pressures in localized areas that are likely higher than the historical pressure of the past 10 years. As a result of the changing hydraulic profile under the Proposed Project, the potential surge pressures along the pipeline route will change. As detailed in Section 9.3.2.4, a surge analysis has been conducted to ensure that mitigation measures employed as a part of the Proposed 6-6 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Project ensure that safe operating pressure levels are not exceeded. Mitigation recommendations submitted to PHMSA for approval (under 49 CFR Part 195) consist of a combination of relief systems and high pressure control switches to limit surge pressure to less than 100% MOP in Tier 2 and 3 areas. Surge pressures are limited to 110% in remaining areas. Appendix 6F contains an Operating Pressure Summary Table that contains the maximum surge pressures for each pump station segment as compared to the MOP of the pipeline in that segment. Appendix 6F contains a table of overpressure protective devices utilized to prevent and/or mitigate surge. Appendix 6A details the PoF estimates for surge and overpressure potentials. The risk assessment model established PoF estimates at all points along the pipeline route. Algorithms modeling the surge threat are shown in Appendix 6A. PoF estimates derived from risk assessment modeling indicate that risk levels can be managed to levels at or below those associated with current operations when mitigation as detailed in Section 9.2.3.4 is applied. This mitigation includes overpressure protective devices to maintain operating pressures at safe levels. 6.2.1.4 Cracking/ Fatigue Monitoring Pressure-cycle-induced fatigue-crack-growth of defects will continue to be a potential threat to the integrity of the Longhorn Pipeline. Manufacturing defects in or immediately adjacent to the longitudinal ERW or EFW seams of the pre-1970 line-pipe material contained in the existing pipeline are considered to be the primary concern. The concern is that a defect that initially may be too small to fail at the operating pressure will grow through fatigue cracking driven by pressure cycling and become large enough to cause a failure if exposed to sufficient numbers of large pressure fluctuations. The ORA Process Manual requires monitoring of pressure cycles during the operation of the pipeline, calculating the worst-case crack growth in response to the pressure cycles, and reassessing the integrity of the pipeline at appropriate intervals to find and eliminate growing cracks before they become large enough to cause a failure of the pipeline. Table 5.3.1-3 shows calculations from the 2010 ORA which identified the shortest time to failure of 92.1 years and a reassessment interval of 41.5 years. There are only two other sections which show reassessment intervals less than 100 years. This analysis shows that the pressure cycles at Cedar Valley and Kimble County produce the shortest fatigue lives and the shortest reassessment interval for the original pipe. The locations with the greatest threat for pressure-cycle-induced fatigue cracking will change because the location of the most aggressive pressure cycles will change. A preliminary assessment using the new flow direction for the existing pre-1970 pipeline from Crane to Galena Park shows this threat can be managed with the existing procedures as part of the ORA. The effects of pressure cycles on the pipe that is currently on the suction side of each station were examined to determine the effect of reversed flow on the pipeline. The shortest time to failure for any of the pre-1970 existing pipe is 83.9 years from the previous TFI tool run completed in 2009. This occurs at the 1950 EFW pipe at Satsuma using Cedar Valley cycle data. The lessening aggressiveness of the cycles as distance increases from the station discharge was not taken into account (the 0.281-inch pipe is over 10 miles from the station) so 6-7 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL this estimate is more conservative than if a pressure drop between the pump and the pipe had been taken into account. Using the factor of safety of 2.22 (45% of the fatigue life as defined within Section 4 of the LMP), the reassessment interval would be in 37.8 years. Although shorter in time, this is similar to the reassessment intervals calculated for westerly flow. This verifies there is no immediate threat from pressure-cycle-induced fatigue cracking and will allow a year of actual data to be collected and analyzed to obtain a more accurate estimate of remaining life from fatigue growth once the pipeline flow has been reversed. In order to investigate worst-case scenarios, doubling and tripling of cycles was investigated. Doubling the cycles will cut the fatigue life in half resulting in a fatigue life of 42.0 years and a reassessment interval of 18.9 years. Similarly, tripling the cycles will reduce the fatigue life by two-thirds resulting in a fatigue life of 28.0 years and a reassessment interval of 12.6 years. Even these worst case scenarios will allow the pipeline to operate for a year to obtain new operating data and calculate estimates of time to failure and reassessment intervals. Within one year from start-up of the pipeline in crude oil service in the reversed direction, third-party ORA contractor will conduct a pressure cycle analysis and determine reassessment intervals for cracks. This calculation will also be completed as part of the annual ORA each subsequent year. Through risk assessment modeling, a crack-related failure potential is estimated. A discussion of factors considered and algorithms modeling this threat are contained in Appendix 6A. PoF estimates derived from risk assessment modeling indicate that risk levels can be managed to levels at or below those associated with current operations when mitigation is applied. This mitigation as detailed in Section 9.3.2.5 includes continued active monitoring of pressure cycles and subsequent integrity testing through ILI and rehabilitation to mitigate cracking. 6.2.1.5 Stress Corrosion Cracking (SCC) Modification to pressure cycle frequencies and intensities affects the threat of SCC. It is prudent to retain SCC as a possible threat. In the same manner through risk assessment modeling, a SCC crack-related failure potential is estimated. Discussion of SCC risk assessment modeling is included in Appendix 6A. PoF estimates derived from risk assessment modeling indicate that risk levels of SCC can be managed to levels at or below those associated with current operations when mitigation is applied. This mitigation includes conducting Non-Destructive Examination (NDE) to examine for the presence of SCC through magnetic particle inspections and active management of pressure cycles. 6.2.1.6 Incorrect Operations The Proposed Project will change the potential for failure due to human error with the introduction of new facilities. These new facilities include new aboveground valves sites 6-8 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL replacing buried check valves as well as new pump stations, new equipment and more complex facilities added as part of the Proposed Project. Facilities tend to be the locations of most incorrect operations incidents or initiators of incidents elsewhere along the pipeline. Facilities are defined as above ground or chambered portions of the System that are comprised of components other than mainline pipe. Pump stations, tank farms, metering stations, valve sites and others are considered to be facilities. Typical scenarios that might lead to a breach of integrity or spill that are modeled as incorrect operations include; • Overpressure due to pumping against a closed valve or other blockage • Blocked-in, liquid-full component over pressured by heat source such as sunlight • Overpressure due to incorrect setting of safety equipment • Overfilling of tank or sump due to improper execution of procedure and/or failure of safety equipment Through risk assessment modeling a failure potential from incorrect operations is estimated. Discussion of incorrect operations modeling is included in Appendix 6A. PoF estimates derived from risk assessment modeling indicate that risk levels associated with incorrect operations can be managed to levels at or below those associated with current operations when mitigation is applied. This mitigation as discussed in section 9.3.2.7 and section 9.3.3.2 of Chapter 9 will ensure a high reliability of redundant controls and safety systems typical of pipeline operations. Formal analyses such as HAZOP and subsequent Layer of Protection Analysis (LOPA) will be conducted. Protective devices and engineering controls specified by this analysis will be applied prior to start-up. Ongoing risk assessments further described in Chapter 9 will measure and maintain PoF associated with incorrect operations below specified levels. Successful application of these risk assessments and subsequent mitigations ensures that the risks associated with incorrect operations are reduced by the Proposed Project to levels below current operations. 6.2.1.7 Security The addition of new facilities brings about additional security risks due to more exposed equipment that is in view of the public that could result in an increased risk of terrorism, vandalism, tampering, or theft. Magellan’s existing procedures include provisions to address appropriate security measures as defined in SIP-ADM-8.01 (Appendix 6E). This initiative provides a framework that complies with the security regulations to protect the assets, the employees, the environment, the stakeholders, and the community from security threats. In general, the Longhorn Pipeline is not thought to be more vulnerable than other pipeline systems. Standard or above-average security measures will be in place in accordance with the LMP and SIP which would generally include fences, locks, increased patrols, and surveillance cameras. The FBI has published a report summarizing 318 terrorism events between 1980 and 2005 (USDOJ/FBI, 2012). The terrorism events include all successful and foiled plots. Only 1 foiled plot related to potential pipeline attack was recorded. In 2005, a terrorist plan to carry out violent 6-9 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL attacks against pipeline systems and energy facilities in Pocatello, Idaho was prevented (Halcrow, 2011). This system has not experienced terrorism or sabotage. Through risk assessment modeling, a failure potential from security threats is estimated. Discussion of incorrect operations modeling is included in Appendix 6A. PoF estimates derived from risk assessment modeling indicate that risk levels associated with security threats can be managed to levels at or below those associated with current operations when mitigation is applied. This mitigation as discussed in section 9.3.2.8 includes security measures such as security fencing, monitoring cameras, physical barriers, and locks to adequately limit access and mitigate security threats. Successful application of these mitigations ensures that the risks associated with security threats are reduced by the Proposed Project to levels below current operations. 6.2.1.8 Atmospheric Corrosion At locations where below ground pipelines are brought above ground such as at existing check valve sites or new facilities, the threat of atmospheric corrosion will change. These locations represent an insignificant percentage of the total pipeline mileage affected by the Proposed Project. It is plausible to predict lower PoF when pipe segments are re-located above ground. In most scenarios, buried metal corrosion rates exceed atmospheric corrosion rates. In the majority of scenarios, with proper installation and maintenance, the corrosion potential for above ground segments should be less than for buried segments. Magellan’s existing procedures contained in 7.04-ADM-002 (Appendix 6E) establish standardized methods for monitoring, inspecting, and reporting atmospheric corrosion conditions on aboveground facilities. Surveys are conducted annually at above ground piping and facilities. Any exposed pipes are visually inspected when the pipeline is exposed for any reason. Design Standards housed within SIP- ADM-4.01 (Appendix 6E) provide specifications for coatings on new installations of above grounding piping, supports, and transition areas to protect from atmospheric corrosion. The Coating Selection Application and Maintenance Procedure, 7.04-ADM-016 (Appendix 6E), provides a standardized reference for the selection, application, and maintenance of coatings used to prevent corrosion. 6.2.1.9 External Corrosion The Proposed Project is not seen to change the potential for failure related to external corrosion including special forms of external corrosion such as: microbiological influenced corrosion (MIC), AC-induced corrosion, stray current, and selective seam corrosion. Factors affecting external corrosion include: • Soil conditions • Pipe coating • Cathodic protection system effectiveness • Environmental conditions • Metallurgical properties of the pipe 6-10 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL These factors affecting external corrosion are not anticipated to change. The fluid (or product) inside the pipeline has no effect on the outside of the pipeline or how the outside of the pipeline interacts or is affected by the environment around the pipeline. Therefore these threats and how they are managed and monitored does not need to change because of the change in product or flow direction. Threats from these causes are monitored by the ORA and if an increase in risk occurs it can be accounted for in the ORA process. 6.2.1.9.1 Pipe Coatings Existing corrosion control and integrity management procedures contained in the SIP are designed to mitigate the effects of deterioration of pipe coatings. Evidence of the current coating condition is found through visual inspection reports, pipe-to-soil potential surveys, and detection of previous corrosion damages through ILI. Design Standards housed within SIP-ADM-4.01 (Appendix 6E) provide specifications for coatings on new installations of buried piping, areas to protect from external corrosion. The Coating Selection Application and Maintenance Procedure, 7.04-ADM-016 (Appendix 6E), provides a standardized reference for the selection, application, and maintenance of coatings used to prevent corrosion. Mitigation discussed in Chapter 9 includes periodic re-assessments of the threat of external corrosion due to potential damages caused by pipe coating failure. Corrosion rates are established through the ORA completed by a third party consultant approved by PHMSA. These corrosion rates are utilized as part of the POE analysis process. This process evaluates each unrepaired feature to ensure a low probability of a feature growing to a level that would exceed repair criteria. All corrosion features identified by the ILI tools are repaired to a level to ensure that remaining strength of pipe exceeds 1.39 times the maximum pressure allowed at the location of the feature. This maximum pressure determined includes any potential surge pressures as evidenced by pipeline surge analysis. 6.2.1.9.2 Cathodic Protection and CP Verifications The Corrosion Control Program, 7.04-ADM-001 (Appendix 6E), provides detailed procedures and processes designed to maintain cathodic protection (CP) systems to prevent external corrosion of buried pipelines. These procedures detail the corrosion control survey frequencies specific to the Longhorn Pipeline and specified in the LMP: • Pipe to Soil Potential Surveys – Conducted annually (not to exceed 15 months) in Tier 1 areas and semi-annually (not to exceed 7 ½ months) in Tier 2 and Tier 3 areas. • Close Interval Pipe to Soil Potential Surveys are conducted annually in Tier 3 areas. • Foreign Line Crossing Surveys – Critical Bonds are inspected six times each calendar year with intervals between inspections not to exceed 2 ½ months. • Rectifier Inspection Surveys are conducted monthly (not to exceed 45 days) at each cathodic protection rectifier. This is double the frequency required by 49 CFR Part 195. 6-11 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Corrective actions for noted pipe to soil deficiencies are determined and completed as soon as practical depending on the severity of the situation with respect to location of the pipeline and the potential for damage. All deficiencies are resolved with one year of discovery, except deficiencies of such a nature that present a more urgent threat to pipeline integrity, in which case corrections are completed immediately. Corrective action for noted deficiencies in rectifier components are determined and completed as soon as practical, depending on the severity of the situation with respect to location of the pipeline and the potential for damage. All rectifier component deficiencies are resolved within one (1) month of discovery except deficiencies of such nature they present a more urgent threat to pipeline integrity, in which case corrections are made immediately. Rectifier outages are typically triggered by a natural event, such as a thunderstorm. A pattern or trend of rectifier outages triggers a detailed analysis by NACE certified corrosion control personnel. This inspection includes the use of a multimeter and/or various other electrical testing equipment as well as visual inspection of the rectifier components. System enhancements identified during this analysis to mitigate against any such pattern or trend are implemented as soon as practical, not to exceed six months. 6.2.1.9.3 IR Drop (CP Voltage Measurement Criteria) The adjustment from readings taken to reading of interest is often termed “IR compensation,” with the implication that "IR" or "IR drop" is the part of the voltage reading that should not be considered in assessing the adequacy of CP. The surface readings can be taken with the impressed electric current supply to the System turned either “on” or “instant off.” The IR drop subtracts the voltage drop through the soil from the reading to yield the “true value” of the pipe- to-reference electrode potential. The -0.85 volt is usually considered a conservative criterion since a safety margin is already included for most soil conditions. Magellan’s Corrosion Control Program, 7.04-ADM-001 (Appendix 6E) of the SIP contains procedures for addressing CP criteria including consideration for IR drop. The Corrosion Control Program in part provides that IR drop is considered by taking potential readings directly over or as near as practical to the structure surface. The effect on the potential measuring circuit is kept to a minimum by using a high resistance volt meter and being mindful of lead lengths and the condition, contact to structure and contact to electrolyte. Furthermore, CP levels are to be evaluated utilizing CP criteria within procedure 7.04-ADM-006 (Appendix 6E) that defines methods for considering the effects of IR drop including the use of: • High resistance voltmeter • Historical operating information • Reference cell placement • Calculation • Current interruption 6-12 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • Buried coupons In addition to deficient CP voltage, excess voltage can also be a concern. In order to avoid excess voltage, Magellan uses -1.2 volts pipe to soil potential as a limit on pipe-to-soil voltage as an informal guideline. Episodes of higher voltage are individually evaluated and mitigated. 6.2.1.9.4 Casings The Proposed Project is not seen to change the external corrosion threat associated with casings. The integrity of pipe in casings in managed through procedures contained in the Corrosion Control Program, 7.04-ADM-001 (Appendix 6E). During each CP survey, readings are taken at each cased crossing to detect any location where the carrier pipe may be shorted to the casing pipe. If the casing potential is within 100 millivolts of the pipeline potential, the casing is investigated to determine whether a metallic short to the carrier pipe is present. If a short is verified, a plan of action shall be developed within three months from the time of discovery. The practicality of clearing the short will be considered before any other measures are used. Action shall be taken to clear the short (a) in Tier 1 areas within six months of development of the action plan; and (b) in Tier 2 and Tier 3 areas within three months of development of the action plan. In the interim, from the time a short is verified and action taken to clear the short, the location will be inspected for corrosion or the casing/pipe interstitial space may be filled with a high dielectric corrosion inhibiting material. During any interval that a casing has been determined to be shorted, the casing/pipe interstitial space will be monitored. Tier 1 areas will be monitored twice per year at intervals not to exceed 7 ½ months. Tier 2 and 3 areas will be monitored monthly at intervals not to exceed six weeks. The integrity of the carrier pipe inside casings in further verified through ILI. Corrosion rates are established through the ORA completed by third party consultant approved by PHMSA. These corrosion rates are utilized as part of the POE analysis process. This process evaluates each unrepaired feature to ensure a low probability of a feature growing to a level that would exceed repair criteria. All corrosion features identified by the ILI tools are repaired to a level to ensure that remaining strength of pipe exceeds 1.39 times the maximum pressure allowed at the location of the feature. This maximum pressure determined includes any potential surge pressures as evidenced by pipeline surge analysis. 6.2.1.9.5 Microbiological Influenced Corrosion (MIC) The Proposed Project is not seen to change the threat associated with external MIC nor has it manifested as an injurious mechanism to the Longhorn Pipeline. The pipeline is evaluated on a periodic basis through integrity testing by ILI tools. Table 5.3.1-1 provides re-inspection dates for each segment to evaluate the corrosion threat associated with MIC. Through the ORA completed by third party consultant approved by PHMSA, new corrosion 6-13 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL rates will be established after each ILI. This evaluation will determine if high corrosion rates are occurring at selected areas which may indicate injurious MIC. Through the ORA process any new information regarding areas of high corrosion rates would be considered to establish appropriate features to investigate. Information gathered from the investigation of features would be used to establish appropriate re-inspection intervals via the POE and ORA processes. Additionally, as defined within the Corrosion Control Program, 7.04-ADM-001 (Appendix 6E), in the event that the pipeline system experiences one or more confirmed discoveries of injurious MIC, or where accelerated corrosion from MIC is anticipated, a Bacteria Testing Protocol will be established to evaluate future integrity threats from MIC. The line specific protocol will be utilized until such time that the threat from MIC has been assessed and appropriate mitigation actions have been taken. Testing for MIC shall be conducted in accordance with Bacteria Testing – Serial Dilution Method. 6.2.1.9.6 AC Induced Corrosion The Proposed Project is not seen to change the threat associated with AC induced corrosion. The SIP procedure, 7.04-ADM-023 (Appendix 6E), establishes a standardized method for identifying and mitigating induced AC. AC potential surveys are conducted on each buried, in contact with the ground, submerged pipeline facility, and/or breakout tank near high voltage power lines once each calendar year with intervals not to exceed fifteen months. AC potentials greater than 5 volts will be evaluated to determine if additional testing or remedial actions are required. To mitigate corrosion, remedial actions will be required where through testing or calculations, AC current discharge densities are found to be greater than 20 A/m2 . To reduce step and touch shock hazards remedial actions and/or protective devices, such as ground mats, are required if AC potentials exceed 15 volts. Recording voltmeters are considered in areas where high voltage transmission lines parallel the pipeline over long distances. The pipeline is evaluated on a periodic basis through integrity testing by ILI tools. Table 5.3.1-1 provides re-inspection dates for each segment to evaluate the corrosion threat associated with AC induced corrosion. Through the ORA completed by third party consultant approved by PHMSA, new corrosion rates will be established after each ILI. This evaluation will determine if high corrosion rates are occurring at selected areas which may indicate AC induced corrosion is occurring. Through the ORA process any new information regarding areas of high corrosion rates would be considered to establish appropriate features to investigate. Information gathered from the investigation of features would be used to establish appropriate re-inspection intervals via the POE and ORA processes. 6.2.1.9.7 Stray Currents The Proposed Project is not seen to change the threat of external corrosion due to stray currents. Stray current interference testing, including, but not limited to close interval pipe-to-soil surveys, will be conducted where practical and determined necessary by sound engineering practices. Indicators of the necessity to conduct such tests shall include annual pipe-to-soil surveys, internal inspection data, pipe inspection, or other related corrosion information or 6-14 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL testing. Pertinent survey information shall be recorded on Magellan Foreign Line Interference Test Form. Procedure 7.04-ADM-015 (Appendix 6E), Testing for Interference Currents and Remedial Measures, establishes a standardized method for identifying, testing for and mitigating the harmful effects of interference currents. Table 5.3.1-1 provides re-inspection dates for each segment to evaluate the corrosion threat associated with stray currents or interference. Through the ORA completed by third party consultant approved by PHMSA, new corrosion rates will be established after each ILI. This evaluation will determine if high corrosion rates are occurring at selected areas which may indicate corrosion due to stray currents in occurring. Through the ORA process any new information regarding areas of high corrosion rates would be considered to establish appropriate features to investigate. Information gathered from the investigation of features would be used to establish appropriate re-inspection intervals via the POE and ORA processes. 6.2.1.9.8 Selective Seam Corrosion (SSC) The Proposed Project is not seen to change the threat associated with external corrosion selective to the pipeline longitudinal seam weld. Per the requirements of the LMP, a TFI smart pig inspection was conducted. The TFI tool is designed to identify any corrosion of or along the longitudinal seam. The Inline Inspection Analysis Guideline, 7.03-ADM-007, provides criteria for determining areas of SSC to investigate. These inspections did not reveal any confirmed metallurgical indications of SSC on the Longhorn Pipeline. Any identified areas of potential SSC were remediated in accordance with the Pipeline Defect Evaluation and Repair Procedure, 7.01- ADM-001. Magellan’s processes and procedures contained within the SIP Integrity Management Program, SIP-ADM-7.06 (Appendix 6E), provide for determinations of re- assessment intervals to evaluate the integrity of longitudinal seam welds. Future longitudinal seam weld inspections are designed to detect any potential indications of corrosion of or along the longitudinal seam which could potentially be corrosion that is selective to the seam weld. Additionally, Magellan’s processes for evaluation of future metal loss features identified by MFL or UT tools are integrated with seam location information gathered from the TFI tools. This information is utilized to evaluate any metal loss of or along the longitudinal seam. This evaluation will determine if high corrosion rates are occurring at selected areas which may indicate SSC is occurring. Through the ORA process any new information regarding areas of high corrosion rates would be considered to establish appropriate features to investigate. Information gathered from the investigation of features would be used to establish appropriate re-inspection intervals via the POE and ORA processes. 6.2.1.10 Third Party Damage Minimal changes to threats from third party damage will occur as a result of the Proposed Project due to localized areas where above ground valve sites and facilities are added. For the overall system the aggregation of local changes should not become a significant driver of risk, even under conservative estimates. 6-15 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Damage prevention programs incorporated within the SIP meet or exceed industry standard requirements of performance. The program is a comprehensive approach designed to educate the public and to prevent accidents resulting from excavation activities. Through cooperative efforts with excavators and the public, this program creates widespread awareness on the importance of damage prevention. The program exceeds 49 CFR Part 195 requirements in the areas of permanent pipeline markers, ground and aerial surveillance, excavator education, public education, and line spotting activities to achieve uncompromising public safety. Per the LMP and LMC 12a, Magellan conducts Electronic Geometry Pig (EGP) Inspections every three years which exceeds regulatory requirements. These inspections are a final intervention to prevent failure from third party damage. Proactive mitigation programs such as One Call, Public Education, Excavator Education, Depth of Cover monitoring and maintenance, Pipeline Marking, Pipeline Surveillance, Encroachment Management, and ROW maintenance are all designed to prevent third party damage to the pipeline. These programs are detailed in the following sections. Magellan annually evaluates the effectiveness of these programs through the Annual Third Party Damage Prevention Program Assessment. This assessment evaluates the potential for inadvertent third party damages through the evaluation of one-call activity levels, tracking of unauthorized encroachments, physical hits, near misses, mechanical damage repairs, and ILI results. This assessment is provided to the third-party ORA contractor to be incorporated into recommendations including integrity inspection intervals. 6.2.1.10.1 One Call Magellan has established a standardized One Call program to protect company assets from damage due to excavation, encroachments, and other third party activities. Magellan has established and maintains a One Call membership with respective state agencies and follows industry standards to receive, record, respond, and document One Call Locate Notifications. 6.2.1.10.2 Public Education Magellan will revise public awareness programs to account for changes in product characteristics from refined product to crude oil. Public education is an important element for insuring widespread awareness and cooperation to protect the public, property, and the environment. This program as defined within the SIP-ADM-10.01 (Appendix 6E), Public Awareness Initiative, utilizes mailings, flyers, public meetings, emergency responder meetings, periodic radio public service announcements, and newspaper ads to educate the local public. Annual mailings to groups such as schools, residences, hospitals, churches, retirement homes, and other businesses include the following information: • One Call information • Product identification information • How to identify and report a suspected leak • Personal safety guidelines in the event of a leak • "Dig Safely" or Call 811 program information 6-16 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Annual (not to exceed 15 months) mailings target a one-quarter (1/4) mile radius of the pipeline in metropolitan areas and a one-mile radius in rural areas. Mailings include items such as phone stickers, refrigerator magnets, and rulers to ensure that emergency contact information and "Call 811" information will be readily available. Door-to-door visits with the public in areas adjacent to the pipeline are performed in Tier 2 and 3 areas every two years (not to exceed 30 months). Damage prevention flyers and “Call 811” literature are distributed to the public at county fairs, trade shows, agricultural shows, feed and seed stores, home and garden shows, and equipment rental companies. Non-emergency response government agencies that are exempt from one-call mandates, such as city and county planning, zoning and building permit offices, and agricultural agencies are contacted annually (not to exceed 15 months) with mailings and a personal visit to distribute maps of the pipeline route and inform developers of the presence of the pipeline. Reply cards and records of personal visits, along with third party damage incident scorecards, are used to measure the effectiveness of the program. Emergency response agencies within each county that the pipeline passes through are contacted at intervals not to exceed 15 months, but at least once each calendar year, in person and provided with maps of the system. Specific emergency response requirements and plans are reviewed on an annual basis with applicable LEPC and emergency responders. Annual emergency response drills are conducted. 6.2.1.10.3 Excavator Education Excavator education is an important element of damage prevention in order to reduce the likelihood of unintended third party damage caused from excavation activity. The program as defined within the SIP-ADM-10.01 (Appendix 6E), Public Awareness Initiative, focuses on promoting cooperation and awareness throughout the following groups: • General contractors (i.e., irrigation, dirt, fencing, plumbing, landscaping) • Land owners • Real estate developers • Utility companies • Mining and quarry operations The identified excavators are provided with the following: • Information on the "Dig Safely" program initiated by DAMQAT (Damage Prevention Quality Action Team - a joint industry and government effort to educate the public on the prevention of damages to all underground and submerged facilities). • Information on the Texas One-Call system. 6-17 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • Information about the location of the pipeline and products in the line. • What to do in the event that unintentional damage of the pipeline occurs. • Instructions on how to recognize and report a leak. Direct mail flyers, written in English and Spanish, include items such as dashboard calendars and stickers so that emergency contact information and "Dig Safely" information will be readily available. Reply cards will be included to measure the damage prevention program effectiveness. Advertisements are placed in various trade journals and/or community publications along the Longhorn right of way to reinforce the "Dig Safely" program and to instruct the excavators to use the One-Call system. 6.2.1.10.4 Depth of Cover and Exposed Pipe Changes in exposure will occur at locations where valves are reconfigured and at station modifications due to potential external impacts. Risk changes will occur for several short segments of pipe. For the overall system, the aggregation of local changes should not become a significant driver of risk, even under conservative estimates. The aggregation represents less than 0.1% of the total System mileage associated with the project. Threats from third party damage are mitigated through the SIP Depth of Cover (DOC) Program, 7.05-ADM-009 (Appendix 6E). The purpose of the DOC Program is to manage risks associated with areas of shallow or exposed pipe. Land use, population density, environmental issues and changes to the absolute depth of cover are expected to change over time. Continual monitoring of these changes is performed through DOC Surveys, Aerial Patrols, In-Line (Smart Pig) Inspections, One-Calls and Line Spotting. Through a formalized DOC Mitigation Process risks are managed through a variety of methods, all designed to reduce the likelihood of unintended outside force damage and consequential damages to a defined level. The DOC Program focuses effort and resources to those areas of highest relative risk. The investigative and resulting mitigation processes consequently focus on High Consequence Areas (HCAs) and on the defined areas of hypersensitive (Tier 3), sensitive (Tier 2), and other (Tier 1), in descending order. 6.2.1.10.5 Pipeline Markers Permanent pipeline markers are used to notify the public of the general location of the pipeline. Pipeline marker are installed and maintained in accordance with SIP procedure 7.05-ADM-002 (Appendix 6E). Permanent pipeline markers are maintained in Tier 1 (general), Tier 2 (Sensitive), and Tier 3 (Hypersensitive) areas as follows: • Pipeline markers meet or exceed all requirements of 49 C.F.R. §195.410. • Marker spacing for Tier 1 areas are placed within line-of-sight of each other. Exceptions may be necessary for land use (i.e., cultivation), and landowner and tenant issues. 6-18 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Discussions explaining the importance of line markers, as identified in our Public Education program are held with landowners or tenants. • Marker spacing for Tier 2 and 3 areas are placed such that if any one marker is removed, the location of the pipeline can still be identified from either direction from any point in between. • All line markers are written in English and Spanish. • Marker placement and density is evaluated routinely through aerial and ground surveillance. • Missing or damaged markers are replaced within 7 days of discovery. • Markers are located at all aboveground facilities to identify the operator of the system. • Markers are located on each side of each public road crossing, water crossing, and railroad crossing. 6.2.1.10.6 Pipeline Surveillance Most pipeline rights-of-way corridors are accessible through aerial surveillance, which is the primary method of right-of-way inspection and damage prevention. Periodic conditions such as weather, however, may render certain segments of the right-of-way inaccessible via fixed wing aircraft or helicopter and thus ground surveillance can supplement air surveillance. In addition, ground surveillance is utilized when vegetation temporarily obstructs aerial surveillance. Pipeline surveillance is conducted in accordance with the SIP procedure 7.05-ADM-031 (Appendix 6E). Surveillance intervals are conducted as follows: • Tier 2 and 3 areas: Every 2.5 days, not to exceed 72 hours • Tier 1 areas: Once a week, not to exceed 12 days, but at least 52 times per year • Edwards Aquifer Recharge Zone: Daily (one day per week shall be a ground-level patrol) Aerial and ground surveillance frequency is increased across Tier 2 (sensitive) and Tier 3 (hypersensitive) areas when the threat of flooding and/or severe erosion is identified near the pipeline right-of-way. Emergency situations identified during aerial or ground surveillance are immediately reported to the Pipeline Control Center located in Tulsa, Oklahoma. All surveillance personnel and line spotters are trained and certified in OSHA HAZWOPER to the first responder level. Every consideration is given to endangered species when conducting ground surveillance in and around the pipeline right-of-way. Maps depicting the location and habitat of endangered species are utilized for this purpose. 6.2.1.10.7 Encroachments and ROW Maintenance Magellan manages encroachments in accordance with 7.05-ADM-012 (Appendix 6E), Encroachment Procedure and the requirements of the LMP. Execution of this procedure ensures that: 6-19 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL • Encroachments do not hinder the ability to safely operate and maintain the assets. • Pipeline adjustments are designed in accordance with sound engineering judgment to ensure compliance with governing regulations. • The respective rights and privileges in the easements are maintained. • Proper reimbursement for work performed. An encroachment is any infringement on the pipeline and associated ROW. An encroachment is any activity or structure that materially or unreasonably interferes with or impedes the pipeline(s) or easement rights. In accordance with the LMP and SIP procedure 7.05-ADM-003 (Appendix 6E), Right-of-Way Maintenance Program, ground cover is mowed to a level so that all pipeline markers, including painted fence posts, are visible from the air and while standing on the ground. High canopy vegetation is cleared or trimmed to the extent necessary to allow clear visibility. All debris is cleared from the right-of-way. 6.2.1.11 External Forces The Proposed Project will not change the potential of failure related to geohazards such as seismic activity, aseismic faulting, landslides, scouring, subsidence, inclement weather, or unrelated adjacent fires. Magellan will instruct emergency responders to contact Magellan in the event that wildfires are threatening the facility. In the event of wildfires, facilities threatened will be shut-down and blocked-in. Magellan continues to manage external force threats as recommended by studies conducted as part of the 1999 EA and as required by the SIP. These studies and their conclusions remain valid for the System, and as such, the discussion as found in the 1999 EA is still relevant. The Proposed Project may change failure potential from these threats at certain locations where valves are re-configured and possibly at station modifications. Threats are very location- dependent. An assessment of their frequency and magnitude is part of the design process. Industry accepted design and construction practices will ensure that integrity is not compromised by such threats. 6.2.1.11.1 Flooding Scheduled inspections occur at various water crossings at six-month and five-year intervals. Inspections also occur after certain flood events to evaluate for scouring, erosion and flood potential. As a result of PHMSA Advisory ADB-11-04, Magellan implemented the Flooding Conditions Procedure, 7.05-ADM-039 (Appendix 6E) to provide standards for recognition, surveillance, and responses to flooding conditions near mainline pipelines. 6-20 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL 6.2.1.11.2 Geohazards Studies are performed every six months to evaluate for ground movement, subsidence and aseismic faulting. Surveys are conducted every five years to evaluate landslide potential. Additionally, the Earth Movement Inspection Procedure, 7.05-ADM-020 (Appendix 6E), provides methods for the investigation and monitoring of areas of the pipeline identified as having high susceptibility to earth movement or where earth movement has been identified. Pipeline surveillance activities pay particular attention, within the target area, to signs or indicators of earth movement or subsidence such as ground cracks, sink holes, erosion, heaving, or buckling. ORAs since 2005 have updated geohazard threat analysis, especially aseismic faulting threat. No new issues have been identified and some previously identified issues have been recognized as being less severe than was initially (and conservatively) deemed plausible. 6.2.1.11.3 Crossings Magellan manages the integrity of overhead pipeline crossings with the Overhead Pipeline Crossing Integrity Procedure, 7.05-ADM-030 (Appendix 6E). This procedure manages integrity through a comprehensive risk-based program which identifies risk reduction projects to improve structural component integrity. Magellan manages the integrity of buried navigable river crossings with the Navigable Crossings Integrity Procedure, 7.05-ADM-014 (Appendix 6E). This procedure requires inspection to determine pipeline depths at these crossing at least once every five years per regulatory requirements. 6.2.2 Staffing and Training Magellan anticipates staffing additions as a result of the Proposed Project. Increased frequency and locations of cleaning pig operations, coupon monitoring, and sampling will result in the need for additional manpower. New facilities that include tanks, rotating equipment, and valves will create a need for new maintenance and operating tasks. New employees will be trained in accordance with requirements outlined in the SIP-ADM-2.01 and the Company Operator Qualification Program per SIP-ADM-2.02 (Appendix 6E). 6.2.3 Risk Assessment Processes 6.2.3.1 ORA Section 3.3 of the LPSIP requires Magellan to perform an ORA on an annual basis (not to exceed 15 months). The ORA adjusts integrity verification frequencies in response to the changing uncertainties over time in response to environmental changes along the pipeline route and in response to data collected from integrity testing, additional attributes, changed attributes, root cause analysis results, or other programs identified in the LPSIP. As discussed in Section 5.3.3.1, the ORA is a key program to monitor and maintain the integrity of the System. The fatigue analysis and monitoring program previously discussed in Section 6.2.1.4 will be 6-21 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL executed in accordance with the existing LMP requirements as discussed in Section 9.3.2.5 to model pressure cycles and crack growth rates in the reversed flow direction. Additional process improvements to the ORA are detailed as mitigation measures in Chapter 9. 6.2.3.2 Data Management Magellan manages existing integrity data through processes defined within the SIP. These data management processes provide support for the risk assessment processes currently in compliance with 49 CFR 195.452 and the LMP requirements. Under the Proposed Project the following integrity factors were considered: • Product specifications • Operating parameters • Pipe specifications (i.e., date, seam type, wall, grade, coating, etc.) • Stress levels • Surge potential • Depth of cover • Internal corrosion control • Locations of potential increased internal corrosion (i.e., low spots, dead legs) • Drain volumes • Pumps, valves, and other facilities A matrix showing the risk implications of physical changes under the Proposed Project is shown in Appendix 6G. Enhancements are discussed in Section 9.3.2 to address the enhancements to data collection, maintenance, and integration processes. This includes conversion to an electronic data management model that will provide greater automation and flexibility to integrate data and conduct risk assessments. 6.2.3.3 Pipeline Risk Assessment Magellan’s existing pipeline risk model meets the requirements of 49 CFR Part 195.452 and LMP Commitments. Changes in commodity characteristics, internal corrosion threats, pressure cycles, surge potentials, incorrect operations, security threats, and facility complexity lead to changes in Magellan’s pipeline risk model, risk assessment and management processes currently in place. Enhancements to risk assessment, data management, and risk assessment processes are included as part of the mitigations detailed in Section 9.3.3.4. To facilitate enhanced risk management, a risk profile or PoF profile quantifying risks within each portion of the system will be generated. This profile will utilize integrated data and incorporate a dynamic segmentation process to identify enhancements and mitigation measures necessary to maintain PoF desired levels. 6.2.3.4 Facility Risk Assessment Conceptually, managing the integrity of stations and terminals is similar to main line pipe. The various elements described in the integrity management programs apply to pipeline stations and 6-22 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL terminals, as well as to the pipeline itself. However, some aspects of data gathering, risk assessment, inspection tools and techniques, and mitigation are specific to pump stations and terminals. The data used for facility assessments will vary from that used to model a pipeline. The relatively more complex nature of facility piping including manifolds, numerous valves, flanged connections, CP systems, dead legs/low flow piping legs, and auxiliary and instrumentation piping are considered in facility assessments. The procedure for a Facility Relative Risk Assessment can be found in the Facility Risk Ranking Tool Instruction Sheet within the Facility Risk Assessment Model. 6.2.3.5 PHA/LOPA As a result of the project, new facilities, equipment, and valve sites will be modified or added to accommodate the change to crude oil and reversed flow direction. These changes create a need for rigorous analysis of process hazards and subsequent evaluation of protection measures and safeguard to mitigate hazards. As a requirement of the LMP, Magellan is required to conduct PHAs (HAZOP, What/If checklists, etc.). An additional industry available method to evaluate sufficiency of safeguards to mitigate hazards is called LOPA. LOPA is a semi-quantitative risk analysis technique. The technique evaluates risks by orders of magnitude of the selected accident scenarios and builds on the information developed in qualitative hazard evaluation (e.g. PHA). This enhanced level of analysis is not currently required by regulation or the LMP. LOPA is included as part of the mitigations detailed in Chapter 9 (Section 9.3.3.2). 6.2.4 Control Systems (SCADA) 6.2.4.1 Leak Detection LMC 13 outlines the requirements of leak detection systems for the Longhorn Pipeline. The LMP requires employing the best available leak detection software system for modeling of operational transients. Such a system is classified as Computational Pipeline Monitoring (CPM) system per 49 CFR Part 195 and American Petroleum Institute 1130 which provides guidance on how pipeline companies should operate and maintain CPM systems. For the Longhorn System, a means to detect leaks by monitoring pressure, flow and volume balancing through pipeline leak detection system (PLDS) and SCADA is in place. The pipeline will be shut down within 5 minutes in the event of a PLDS alarm, issued at 1% of normal flow in a 30 minute window and 0.5 – 1% normal flow in a 60 minute window. Magellan currently complies with both LMP and American Petroleum Institute Recommended Practice 1130 first edition of September 2007 and will ensure compliance for the reversal and conversion to crude oil service. Magellan will perform an American Petroleum Institute 1149 theoretical study to determine necessary enhancements to PLDS prior to start-up. The study will provide a theoretical based assessment on future leak detection capabilities, and determine 6-23 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL required system adjustments. The adjustments will be configured in PLDS and within the Stoner Pipeline Simulator. Pipeline Controllers in the training simulator environment will be trained prior to starting the real line operation. The training will focus on achieving emergency shutdown within five minutes of a probable leak indication, and other abnormal operating conditions (AOC) scenarios. Magellan will perform tuning of PLDS with data generated by the simulation. Per LMC 13, this will be completed prior to start-up in reversed crude service. CPM will be adjusted to become operational over approximately two weeks of pipeline operation and be further optimized within 6 month per LMC 13. Additionally, LMC 13 currently outlines a leak detection performance commitment for the hydrocarbon sensing leak detection cable that was installed and currently functional over the Edwards Aquifer Recharge Zone and the Slaughter Creek watershed in the Edwards Aquifer Contributing Zone. The current commitment does not contain a performance specification for crude oil. Magellan is proposing to add the performance commitment of 100 to 200 minutes from contact for crude. This performance commitment was determined based upon testing conducted by Tyco Thermal Controls to determine the sensitivity of the existing TT-5000 leak cable on WTI and WTS crudes. The Report # TT 1106-006 is included in Appendix 6H. These tests confirmed the cable sensitivity as published by TraceTek, the manufacturer of the leak detection cable. Additionally, Magellan contracted with Spartan Engineering Inc. to evaluate the existing systems capabilities in crude oil compared to other direct detection methods. Spartan determined that the existing leak detection cable is the best available technology for crude oil. The Spartan report is also provided in Appendix 6H. 6.2.4.2 Control Room Procedures As a result of the Proposed Project, any line specific Operations Control procedures will be modified prior to start-up. All applicable Operations Control employees will be trained on any new or revised operating and/or maintenance procedures. Appropriate pressure settings will be established and the Maximum Pressure Charts will be updated with these settings. PHMSA regulation CFR 195.446 has specific requirements related to SCADA point to point verification, change management and training which will be applicable to this project. Compliance with CFR 195.446 and other internal Magellan practices will be completed prior to start-up. 6.2.5 Pipeline Inspection and Testing 6.2.5.1 Pressure Testing New pipeline, pump station, or breakout station pressure testing will be conducted in accordance with 7.03-ADM-001 Pressure Testing Procedure and applicable regulatory 6-24 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL requirements (Appendix 6E). This procedure establishes the requirements, process, and documentation for pressure testing. 6.2.5.2 In-Line Inspections (ILI) Future integrity tests intervals are established in accordance with the ORA and in conjunction with the procedures established within the IMP contained within SIP-ADM-7.06 (Appendix 6E). Table 5.3.1-1 provides a summary of re-assessment intervals for each segment. Integrity tests and subsequent rehabilitation is conducted in accordance with the procedures outlined in SIP- ADM-7.03 (Appendix 6E), Integrity Testing and Rehabilitation and applicable regulatory requirements. 6.2.6 Spill and Emergency Response Plans Magellan’s existing Emergency Response Procedures, in compliance with regulatory requirements as detailed in Section 5.4.2 and requirements within the LMP, are designed to minimize the impact of pipeline emergencies by establishing, employing and maintaining a consistent system of Emergency Response and Preparedness (ER&P) standards and procedures. The ER&P Program is coordinated using three distinct processes: (1) Preparedness, (2) Training, and (3) Response. The program provides a process of developing and maintaining a system of emergency response plans and equipment and subsequent training to utilize the system. The existing response plans have been enhanced by adding over 120 site specific tactical response plans that provide the location, equipment, personnel needed, and response tactics to respond to a theoretical pipeline release. These tactical plans have been recently reviewed for accuracy. As a result in the change in commodity, the emergency response tactics will be reviewed prior to start-up to determine any necessary modifications. The enhanced response plans also identify both groundwater and surface water intakes that could potentially be impacted by a refined product spill and the methodology for identifying replacement water sources in the event of an impact, or, detailed engineering designs for bolt-on application of a water scrubbing system in the case of a municipal surface water treatment system. As a result of the crude reversal, the potential impacts are being identified and the water scrubbing systems are being reviewed to ensure they are consistent with the current designs of the individual treatment centers. 6.2.7 Worst Case Spill Volume The worst case spill volumes for both the 19-mile segment within the Edwards Aquifer Contributing and Recharge Zones and for the remainder of the Longhorn Pipeline is calculated assuming that the pipeline is operating at a maximum system capacity of 225,000 barrels per day. Then, it is assumed that the pipeline is completely severed, allowing crude to freely flow from the pipe at a rate of approximately 160 barrels per minute. Although Magellan has agreed to a five-minute shut down time (LMC 13) and has trained its employees to meet this timeline, the worst case spill assumes that it actually take Magellan 12.5 minutes (2.5 times the agreed 6-25 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL upon time frame) to shut down the pipeline. Once the pipeline has been shut down, the product from the nearest closed valves to the rupture site will flow from the pipe. This is known as the “drain down volume.” The worst case drain down volume is calculated by assuming the least favorable topography (i.e. a downhill slope from the nearest valve to the rupture site) and farthest distance between valves. Due to topography and valve placement, the worst case spill volume within the 19-mile Edwards Aquifer Contributing and Recharge Zone is 5,131 barrels. This volume includes 2,000 barrels of crude oil which would flow from a completely severed pipe at a rate of about 160 barrels per minute for 12.5 minutes (2.5 times the LMP requirement). The remaining volume of 3,131 barrels could drain from the severed pipe once the system was shut down. The worst case spill volume for the Longhorn Pipeline not within the 19-mile segment of the Edwards Aquifer Contributing Recharge Zone is 22,087 barrels. This includes 2,000 barrels of crude oil which would flow from a completely severed pipe at a rate of about 160 barrels per minute for 12.5 minutes. The remaining volume of 20,087 barrels could drain from the severed pipe once the system was shut down. This worst case spill volume was utilized to conduct an overland flow analysis and determine potential environmental receptors that could potentially be affected by a spill (zone of potential impact). The analysis led to new designations of Tier II and Tier III areas along the ROW. 6.3 CONSEQUENCE POTENTIAL (COF) Consequence potential varies along the System as a function of variables such as: • Low spots/drain • Leak detection capabilities • Ignition probability • Dispersion/migration potential • Receptor sensitivities As a part of Magellan’s existing annual procedures within SIP-ADM-7.06 (Appendix 6E), additional analyses to strengthen knowledge of consequence potential will be completed. Results of these analyses will be integrated with PoF estimates and receptor sensitivities (see Chapter 7) to identify locations were additional risk mitigation may be warranted. While risk thresholds, responsive to changing consequential potential along the System, have not been identified, PoF thresholds have been established under the Proposed Project and are to be maintained as a minimum at all locations. The focus of this chapter is on PoF but an observation regarding overall risk is that potential consequences of human fatality and injury are reduced by the Proposed Project due to the reduced ignition potential of crude oil compared to the refined products currently transported. 6-26 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Hazard zone determination is discussed in Chapter 5 and applied as part of the potential impacts analyses in Chapter 7. 6.4 CONCLUSIONS Based upon the mitigation detailed in Chapter 9, System-wide risk is reduced under the Proposed Project. PoF risk measurements equate to a target under 0.0001 (1E-4) PHMSA reportable incidents per mile-year at all mainline portions of the System. This equates to a PHMSA reportable failure about once every 20 years somewhere along the mainline portions of the System. This incident rate is superior to current Longhorn incident rates as well as the average performance of US hazardous liquid transmission pipelines, as shown in Chapter 5. At facilities, Magellan commits to limit PoF risk measurement to an average of 0.01 (1E-2) PHMSA reportable incidents per facility per year. This equates to a PHMSA reportable spill once every 2.6 years System-wide, assuming a count of 39 facilities over the 496 miles of the Proposed Project. (These target values will be reviewed as detailed in Chapter 9.). This target incident rate is superior to current Longhorn incident rates for the last seven years. Comparison to US Hazardous Liquid transmission pipeline incident rates is not available since identification of ‘facility’ is not reliably done in the comparison database. The risk assessment concludes that the Proposed Project, with the mitigations outlined in Chapter 9, will experience incident rates lower than current operations. The Proposed Project introduces new threats, but additional project mitigations are seen to offset any increase in risk as measured by PoF. In addition, potential consequences of human fatality and injury are reduced by the Proposed Project due to the reduced ignition potential of crude oil compared to the refined products currently transported. 6.5 REFERENCES CorrPro report June-July 2010, Magellan Longhorn Tier 3, Segment 1-56 CIS on ~37 miles of pipeline. Email: Ref Halcrow: National Grid USA Service, Co, Inc., Risk Assessment for Gas Pipeline Adjacent to Marine Parkway Bridge Agreement No. 573927 Final Report August 2011 Halcrow, 2011. National Grid USA Service, Co., Inc.: Risk Assessment for Gas Pipeline Adjacent to Marine Parkway Bridge, Agreement No. 573927, Final Report, May 2011, Halcrow, Inc. Johnston, D.C., and Kiefner, J.F., “Audit of Existing Portions of Longhorn Pipeline”, February 24, 1999, Final Report to Jenkins and Gilchrist. King, F., “Hydrogen Effects on Carbon Steel Used Fuel Containers”, December 2009, Nuclear Waste Management Organization Report TR-2009-29 6-27 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Muhlbauer, W.K., Pipeline Risk Management Manual (Elsevier Inc. 3rd Ed. 2004). NACE International, Review of Published Literature on Wet H2S Cracking of Steels through 1989”, September 2003, Item No. 24185, NACE International 2003 Project Scope: “Magellan Pipeline LP Technical Services Texas Pipeline Project Prepared By Robert A. Jackson” U.S. Department of Justice / FBI, Terrorism 2002-2005 http://www.fbi.gov/stats- services/publications/terrorism-2002-2005/terror02_05.pdf, page 11, accessed May 2012. University of Texas (UT) analyses by DNV—multiple reports 6-28 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL CHAPTER 6 APPENDICES <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 6A RISK ASSESSMENT METHODOLOGY <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 6A Risk Assessment Methodology This risk assessment concluded that the Proposed Project, with the mitigations outlined in Chapter 9, will experience incident rates lower than current operations. The Proposed Project introduces new threats, but additional project mitigations are seen to offset probability of failure (PoF) increases. The following methodology, risk assessment comparisons and PoF assessments of various threats are intended to provide the framework for the conclusions stated in Chapters 6 and 9. Risk estimates of the existing System in refined product service are generated based on available information. Risk levels under the Proposed Project are predicated on commitments to design, operate, and maintain in a manner that ensures that the levels of risk of the Proposed Project are at or below the baseline levels of risk for the current operation. Associated mitigation measures are in place to perform robust and conservative4 risk measurements to ensure acceptable risk levels as part of the overall risk management process. In the absence of the additional mitigation discussed in Chapter 9, there is evidence that the Proposed Project could result in increased incident rates compared to current operations. This evidence is predicated on a conservative assumption regarding aspects of the Proposed Project including the following: • Location-specific number and severity of potential surge events, • Frequency and compositions of sour crude shipments, • Potential for blister formation and subsequent cracking, • Pressure cycling severity, and • Internal corrosion potential in new service Mitigations, described in Chapter 9, are designed to maintain the PoF (from all failure mechanisms below a pre-determined, specified level). Overall conclusions are that the risk management enhancements will improve risk management and reduce failure potential from current levels. Maintaining all portions of the pipeline at or below specified levels requires that each independent threat be kept lower than this so that the combination of all threats remains below the threshold. Since new threats are introduced by the Proposed Project, those must be offset by mitigations in order to keep overall PoF at all locations below the threshold. Uncertainty due to passage of time is to be modeled as an increased PoF and must also be offset under this commitment. 4 Using inputs and relationships that tend to overstate the risk and treating increased uncertainty as increased risk. 6A-1 <<>> APPENDIX 6A (continued) These thresholds effectively cap maximum allowable PoF at all points along the System. The threshold PoF level is below the PoF level associated with current operations, as is evidenced by both the PoF assessment and the recent incident rates. Although future risk estimates are predicated on successful mitigation, the underlying processes to identify and manage those future mitigations are defined in Chapter 9 and are well established standards of integrity management. Threshold risk levels are achievable as is demonstrated by other operating pipelines and by the operational history of the System. However, given certain specific characteristics of the Longhorn System and its intended future operation, reaching and maintaining those levels will require additional mitigations and risk management (See Chapter 9). Risk Assessment Definitions: For purposes of assessing PoF, ‘failure’ is defined in terms of loss of integrity and/or spills emanating directly from a system component, rather than a more broad definition that includes operability and serviceability criteria. Similarly, references to incidents and incident rates refer to loss of integrity and spills, unless otherwise specified. Other relevant terms that are used in specific ways in this report include anomaly, damage, and weakness. Anomalies are indications that are deemed to be abnormal—they may or may not represent damages, weaknesses, or otherwise indicate active failure mechanisms. Anomalies are most often used in referring to ILI indications, but can also apply to overline surveys and other inspections. Damages include metal loss, enlarged cracks, dents, and other potentially weakening features that have been introduced into a pipeline system since installation. A weakness is a location of reduced strength. A weakness may be caused by damage or by the imperfect manufacture or installation of a component. PHMSA reporting criteria were changed in 2002 to include spill amounts of hazardous liquids greater than 5 gallons. Using this more stringent reporting regime, ‘failure’, for purposes of this risk assessment, is equivalent to ‘reportable failure’ where reportable refers to criteria in 49 CFR Part 195.50. Defining ‘failure’ in this context provides consistency with widely known criteria defining what level of incident warrants additional action. This also avoids potential confusion related to use of incident statistics from Magellan’s internal practice of documenting minor incidents that do not rise to the level of ‘reportable’ by the PHMSA definition. Failures also include spills that do not involve damages to integrity-containing components. For example, overfilling of a sump or tank is considered a failure for this risk assessment when the PHMSA criteria are met. The PoF is an estimate of probability of failure, expressed as a percentage over a specified time period for a specified portion of the System. Frequencies and probabilities can be interchangeable when values are numerically very small. Otherwise, a conversion from frequency to probability is calculated, based on an underlying relationship. Time dependent failure mechanisms on a pipeline include corrosion and cracking. These require the estimation 6A-2 <<>> APPENDIX 6A (continued) of a Time to Failure (TTF) as part of the overall estimate of PoF. Time independent failure mechanisms such as third party damage and human error are estimated directly from frequency of events and benefits of mitigation and resistance to failure. In this analysis, a TTF is determined from each time-dependent failure mechanism for each pipe segment. An assumed relationship between TTF and PoF ensures that, when TTF is small (short time to potential failure), then the PoF is large, but as TTF gets longer, the PoF dramatically decreases. This is intuitive since, for example, a segment with a TTF of 50 years has very, very low PoF in the early years, up until the time near year 50,when PoF rapidly increases toward 100%. This is akin to the ‘failure free’ period commonly seen in reliability probability distributions such as exponential distributions and Weibull distributions. To ensure that PoF is appropriately high when TTF is low, especially considering the uncertainty surrounding the TTF estimate, the following relationship is used in the PoF profiles: if(TTF_ext99<1,iif(TTF_ext<[year of interest],0.99,1/TTF_ext),1/([factor]*TTF_ext)) This relationship ensures appropriate consideration of the full range of TTF values. For segments passing the initial conditionals (ie, segments with longer TTF’s) in this relationship, the factor relating a large TTF with early years’ PoF will determine the PoF. The terms “threshold” and “maintain” or” maintenance” are used in conjunction with mitigation under the Proposed Project. These terms are used in the same way that they apply to well- known industry recognition of actionable limits such as pipe-to-soil voltage criteria for measuring CP effectiveness. Threshold refers to a trigger that prompts additional action. Maintenance refers to intent to continuously meet or improve upon a threshold. Instances where thresholds are not met are expected. When issues are identified, the operator is obligated to, as soon as reasonably possible, take action to address the issue and ensure that thresholds are again met. Conservatism A risk assessment should employ a target level of conservatism. Depending on the intended use of the risk assessment results, various levels of conservatism might be appropriate. When an assessment uses conservative inputs, layers of conservatism are created, resulting in an overall conservatism greater than the sum of the individual inputs. This is an intentional use of excess conservatism done to encourage future data collection as a means of risk reduction and, more importantly, to ensure that risks are fully understood and not underestimated. This approach is employed in the estimation of future risks under the Proposed Project. A less conservative estimate is generated for the profile of current PoF levels. Use of less conservatism in assessing the current state ensures that, in a comparison with the Proposed Project, an artificially low ‘hurdle’ has not been set. Otherwise, conservatively estimated risk 6A-3 <<>> APPENDIX 6A (continued) levels, showing higher risks than actually exist, would generate targets that are unrealistically high and achievable with minimal mitigation. The more conservative risk assessment, tending to over-estimate actual risks, generated for the future risks under the Proposed Project uses inputs biased towards over-estimation of risk. In the absence of a stronger technical basis for any required input, conservative but plausible values are chosen. This higher level of conservatism is intentional and useful since it better supports decision-making in several ways: • If a project is deemed to have acceptable risk, even under conservative assumptions, then more rigorous analysis is unnecessary. • Underestimation of risk is often a more costly long-term error than overestimation. • Conservative defaults highlight knowledge gaps, encouraging acquisition of better information. • More conservatism at the segment level (individuals) identifies location-specific risk management opportunities. • More conservatism in overall assessment reduces the chances of undesirable aberrations in performance of specific pipeline segments (see discussion of predictive capability below). Less conservative assumptions are sometimes needed for practical reasons. For instance, a depth of cover survey may contain a gap in data points with sufficient cover indicated on either side of the gap. It would be counter-productive to assume that the depth of the pipeline is “0 inches” where data is not available, even though such an assumption would be very conservative. Sources of conservatism in the current assessment include the following: • combining ILI data from three ILI’s, thereby treating duplicate anomalies as new anomalies, • use of MOP to represent normal operating pressures along all points even though most segments would rarely experience such high pressure, and • assumption of more aggressive failure mechanisms when information is incomplete All assumptions will be re-examined for consistency with appropriate levels of conservatism as part of the risk assessment enhancements in Chapter 9. Measurement Units for Inputs In this risk assessment, all factors are expressed as measurements rather than a score or point assignment. Measurements include corrosion and crack growth rates (mpy), event frequencies (e.g., events per mile-year), and percent effectiveness. As an example of the latter, a mitigation measure estimated to be 70% effective means that 7 out of the next 10 events are ‘blocked’ by that mitigation measure. The use of consistent measurement units provides more precise and consistent input into a risk assessment. It also facilitates validation and future refinement of inputs. 6A-4 <<>> APPENDIX 6A (continued) Where actual measurement data is unavailable, the measurement is estimated by expert judgment. While not as desirable as an actual measurement for a specific characteristic at a specific location, experience shows that expert judgment based estimates will normally be of sufficient accuracy. In this application, ‘sufficient accuracy’ means that input values assumed by experts will produce risk estimates close enough to actual values that decisions can be reliably made based on the produced estimates. Expert judgment based inputs are further refined via the use of conservatism. By acknowledging the role of conservatism, a range of possible inputs is identified, corresponding to the possible range of actual values under varying levels of conservatism. This results in more insight into possible ranges of actual risks. Predictive Capability A desirable output of any risk assessment is accurate predictions of future failure potential. The predictive capability of any risk assessment is highly dependent upon the available information and the predictability of the system being studied. Predictive capability must be judged with knowledge of the level of conservatism employed in making the predictions (see previous discussion). A conservative assessment will produce many ‘false positives’ while use of less conservatism will miss some indicators of higher risk, producing ‘false negatives’. The balance between these two, losing sensitivity in order to reduce nuisance alarms or tolerating nuisance alarms in order to avoid missing something significant, is an important consideration for modeling, diagnostic, and monitoring systems such as a risk assessment. In the conservative aspect of this risk assessment, a higher rate of false positives is tolerated to ensure that few false negatives (missing actual risk issues) occur. The actual risks associated with a given pipe segment will vary over time. It is best expressed as a probability distribution that encompasses plausible failure scenarios with their associated probabilities of occurrence. This probability distribution characterizes the expected behavior of a population of pipeline segments. Aggregated Data versus Individual Data Part of the inaccuracies inherent in probabilistic prediction lie in inferring behaviors of individual data based on behaviors of aggregated data. The latter is much more reliably estimated. An individual pipeline segment may have radically different experience from its neighbors but still be within expected behavior ranges of the population pipeline segments. Behavior of the collection of individuals, the population, is shown by the range of possibilities of the individuals. Each individual can demonstrate behavior anywhere within this range of possibilities and still be consistent with the population. Part of the prediction process is identifying a theoretical population of pipeline segments that fairly represents the segment(s) being evaluated. Some segments may belong to a theoretical population with very low failure probabilities and low potential consequences. Other segments may be better characterized as belonging to less desirable populations, higher failure potential 6A-5 <<>> APPENDIX 6A (continued) and/or higher consequence potential. A goal of the risk estimate is to correctly place each segment into its representative population. The 34,000+ event changes along the pipeline routes generated the final count of dynamic segments for use in the risk assessment. Using all data in a dynamic segmentation process results in over 32,000 segments, each with PoF characteristics unique from its neighbors. Average segment length is about 100 ft. A risk profile must have sufficient resolution to accurately portray real changes in risk levels along a route. This sufficiency is evidenced by segment length. Segment length should reflect the frequency with which conditions or pipeline characteristics change. Min Max Avg Segment Length of Pipeline Line ID Segment Segment Length (ft) (ft) Length (ft) Length (ft) Galena Park to East 1 107 1744 50,000 Houston (6643) East Houston to 0.101 74 1300 3,654,000 Crane (6645) Crane to Odessa 1 1119 24277 154,000 (6648) These concepts are the basis for the calibration of the initial PoF estimates as discussed below. To support risk management, PoF from various threats or from various pipeline segments are often combined. To ensure that thresholds levels are met, appropriate aggregation of individual threat levels must be made. Algorithms in the table below produce PoF values for each segment, taking into account the segment’s length. PoF for each segment therefore includes length effects. A normalization is performed to generate ‘per mile’ PoF estimates to compare to threshold levels. This simply extrapolates segments’ PoF values to a hypothetical 5,280 ft length, under an assumption of PoF being proportional to length. To aggregate either the length-sensitive or the normalized values, a probabilistic summation is required to ensure that masking of higher values does not occur and that the aggregation of lower-valued threats is fairly represented. At each location along the System, the individual PoF values from each threat are combined using an OR gate approach, illustrated as follows: PoF = 1 – (1 – Pof1) x (1 - PoF2) x . . . (1 – PoFn) The same relationship is used to combine PoFs from a collection of segments to show their combined PoF. The probabilistic summation is required to ensure that PoF thresholds established by the mitigations of the Proposed Project are met. 6A-6 <<>> APPENDIX 6A (continued) Estimates produced by this risk assessment are concluded to be accurate representations of the behavior of the entire pipeline, the population of all individual pipeline segments, over long periods of time. Performance of subsets of the overall population over shorter periods of time may vary significantly from the overall performance. The use of conservatism ensures that such performance aberrations do not result in unacceptable estimates that could lead to inappropriate risk management decisions. For example, as the overall behavior estimate is increasingly biased towards over-estimation, the chances of unexpected behavior of a portion of the system decreases. PoF Estimates In the current PoF profile, a measurement or estimate is made of the exposure, mitigation, and resistance related to every failure mechanism, as defined below: • Exposure - likelihood or aggressiveness of force or failure mechanism acting on the pipe when no mitigation applied. This can be thought of as a measure of the attack on the system. • Mitigation - actions that reduce or block the force or failure mechanism from the pipe. This can be thought as the defense against the attack, usually consisting of multiple mitigation measures. • Resistance - the system’s ability to resist a force or failure mechanism applied to the pipe. Probability of Damage—damage without immediate failure—also emerges from these definitions. Using the first two terms without the third—exposure and mitigation, but not resistance—yields the probability of damage. Probability of Damage (PoD) = f (exposure, mitigation) Probability of Failure (PoF) = f (PoD, resistance) Damage does not always result in immediate failure. Some damage may trigger or accelerate a time-dependent failure mechanism. Calculation of both PoD and PoF values creates an opportunity to gain better understanding of their respective risk contributions. In this risk assessment, all calculations result in measurements units, just as with inputs to the assessment. Exposures are measured as either material degradation rates (measured in mpy) or event frequencies (measured in events per mile-year). Mitigations and resistance are measured in percentage effectiveness. Risk Assessment Comparison This risk assessment measures the change in risk from current operations of the existing assets in refined product service to operations under the Proposed Project. Risks associated with current operations are termed ‘Baseline’. 6A-7 <<>> APPENDIX 6A (continued) Baseline risk reflects current operations characterized as transportation of refined product flowing through approximately 496 miles of pipeline and 4 pump stations from Galena Park to Crane and Crane to Odessa. A system characterization and discussion of current operations, maintenance, and safety controls is provided in Chapter 5. PoF profiles are generated to understand the baseline risk and the risk presented by the Proposed Project. As a collection of thousands of pipeline segments, a profile shows discrimination along the pipeline, identifying changes in risk corresponding to changes in the pipeline itself, its hydraulic profile, and its surroundings. Risk estimates that treat the entire pipeline as a single facility are also produced. This approach has been used to characterize a pipeline that is assumed to have risks consistent with some comparable population of other pipelines whose risks have been measured over time. Since risk varies along any pipeline, this process must assume average or worst case conditions exist everywhere or perform some type of grouping of pipe and environmental characteristics. It also relies on a representative population, such as incident rates from comparable US transmission pipelines, to characterize the subject pipeline. Estimates produced from this generalized approach can be valid characterizations of the risks presented by populations of pipeline segments over long periods of time. Predictions of behaviors of populations are more reliable than predictions of behavior of individuals. The population-based estimates are therefore useful in calibrating a collection of pipeline segments to the expected behavior of the underlying population from which the segments are thought to arise. PoF profiles for the existing system and the Proposed Project have been produced. The focus is on threats to System integrity and accompanying changes in risk that will occur due to the Proposed Project. The System has experienced leaks, mostly in facilities, since its initiation of operations in 2005. These releases were always contained within property boundaries. Experiences of leaks, damages, ILI anomalies, and near misses are relevant to baseline risk levels and are detailed in Chapter 5. Baseline risk levels include both past damages and potential for future damages. Past events on the System are discussed in Chapter 5. Incident rates are calculated and compared to other representative pipelines, as discussed below. INTEGRITY THREATS The following integrity threats were addressed in the risk assessment and explained further below: POF ASSESSMENT FOR INTERNAL CORROSION 6A-8 <<>> APPENDIX 6A (continued) If not properly mitigated, localized, pitting corrosion from sour crude effects may occur. The risk assessment model estimates show high internal corrosion damage without mitigation measures employed. The estimates are represented as a PoF. For this FEA, PoF has been quantified for all portions of the System. Estimates are based on integration of all available location-specific information, producing a PoF profile along the pipeline route. This profile produced over 32,000 segments (average segment length is approximately 100 ft.), demonstrating a high level of resolution. In this PoF assessment, the PoF profile is calibrated using incident histories that reflect the past performance of the System in both crude and product operation, and similar pipeline systems. For generation of the current PoF profile, probability of failure by internal corrosion is assessed as follows. Unmitigated corrosion rates and effectiveness of mitigations along the pipeline are estimated, using low spots and ILI-findings as the main distinguishing aspects. An estimate of current pipe wall thickness, adjusted for possible weaknesses by previous damages and manufacturing/construction, is theoretically degraded by the mitigated corrosion rate to predict a time to failure. A relationship between this predicted time to failure and probability of failure within a certain time period is then used to produce the PoF estimate. This risk assessment models aggressiveness of internal corrosion as a function of accumulation potential, previous ILI identified damages, and estimates of plausible internal corrosion rates under current and future product transport plans. Current corrosion rates, reflecting the transport of refined product (very low corrosivity), are modeled to range from 1 to 3 mpy multiplied by an accumulation potential of 1 to 3, for a final range of 1 to 9 mpy unmitigated corrosion potential. Future unmitigated corrosion rates of sour crude oil are modeled to range from 10 to 30 mpy, also multiplied by the same 1 to 3 factor, for a final range of from 10 to 90 mpy unmitigated corrosion potential. Background for these modeling assumptions is presented below. For this analysis, several sources of potential corrosion rate information were examined as noted in the following discussions. Internal corrosion rates as reported in the ORA state that 1-3 mills per year were generally assumed in previous Magellan analyses (ORA, 2008). Internal corrosion coupon rates are reported in each ORA. Magellan proposes a mitigation measure to improve the monitoring of future internal corrosion potential, as discussed in Chapter 6and Chapter 9. Chapter 5 reports on internal corrosion damages to portions of the System from Crane to Cottonwood, non-operational circumstances. In 2008, corrosion was detected and determined to be as a result of remnant pressure test water left in the pipe. This pipeline segment was subsequently replaced. This damage is not thought to be reflective of current in-service corrosion rates but provides insight into possible corrosion under special circumstances. 6A-9 <<>> APPENDIX 6A (continued) As noted in the discussion on data integration, a damage rate in mills per year (mpy) (i.e. 1/1000 inch per year) is estimated from ILI anomaly findings and associated measurements. The rate is modeled to be the maximum depth of any anomaly of type ‘metal loss internal’ appearing within each 100 ft segment of pipe, divided by 10 years to arrive at a percent wall thickness per year. This is multiplied by nominal pipe wall thickness to arrive at mpy. This calculation is performed for anomaly type ‘metal loss internal’ and used in this analysis. This analysis produces the following histogram (see figure below). The vertical axis shows the combined lengths of pipeline segments with the corresponding corrosion growth rates (on horizontal axis). Histogram of Modeled Internal Corrosion Rates 400000 350000 300000 250000 200000 150000 100000 50000 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 18 19 Modeled Internal Corrosion Rate, mpy* *mpy int- internal corrosion rate = 1/1000 inch per year The use of 10 years reflects a plausible time period under which corrosion damage could have occurred. The 1950 vintage pipe was in sour crude service for periods of its service life (1999 EA). The pipeline’s more recent operational life was in a product service believed to be non- corrosive except under upset conditions. Some ILI TFI internal metal loss anomalies are identified as false positives according to ORA 2010. It is conservative to assume all indications are correct. Therefore, all ILI indications remain in the risk profile. Corrosion Rates under Proposed Project Internal corrosion can result from the transport of sour crude oil containing H2S because of the oxidation potential that can occur when H2S is in the presence of water and/or oxygen. Because 6A-10 <<>> APPENDIX 6A (continued) of this potential, the corrosion rates for the Proposed Project has been evaluated by an independent third party internal corrosion expert (see 6C). Mitigation under the Proposed Project is designed to address these other constituents. To recognize the additional internal corrosion mechanism created by the Proposed Project, the future corrosion rates are modeled to be significantly higher than those estimated using the previously discussed procedure at each location along the pipeline. As additional data is acquired from the mitigation activities corrosion rate assumptions can be adjusted. Accumulation Potential Internal corrosion in a pipeline transporting hydrocarbons typically occurs where corrosive constituents, usually heavier than the hydrocarbon, accumulate and are in contact with the pipe wall for periods of time. Water and solids can settle in low spots in the pipeline and promote entrapment of other corrosive agents and/or microbes, both of which can be a source of accelerated corrosion. Where Microbiologically Induced Corrosion (MIC) processes become active, corrosion rates can be very high. To acknowledge changes in corrosion potential along the route, locations of higher drain down volumes are assumed to be more likely locations of contaminant accumulation and therefore internal corrosion, if mitigation fails. Similarly, where lesser drain down volume occurs, there is lowered expectation of accumulation potential. Under these assumptions, probabilities are assigned to each location based on drain volume to that location. Inspection Intervention Preventing damages through mitigation is logically the preferred method of managing the threat of internal corrosion. Intervention through integrity testing is a necessary aspect of risk management of internal corrosion mechanisms. Successful scheduling of intervention requires an understanding of potential corrosion rates. The uncertainty surrounding anomaly sizing is well defined in the ORA’s Probability of Exceedance (POE) process for metal loss. Magellan has investigated methods to estimate corrosion growth rates (mpy) when data from like-tool technical data is not available (i.e. TFI vs, MFL vs, UT). Under the mitigations of the Proposed Project, the ORA processes are enhanced related to corrosion growth rate estimates. The continued use of metal loss ILI tools will enable the monitoring of any localized corrosion metal loss along the pipeline. In addition, ILI as an intervention tool reduces failure potential since it can interrupt the accumulation of damages prior to failure. This is taken into account in the risk assessment by examining the highest PoF that may occur before the next ILI (5 year intervals assumed). Mitigation Effectiveness EnhanceCo conducted an independent analysis and cites prior work from Dr. Sheldon Evans (see Appendix 6C) that internal corrosion rates when transporting sour crude can be controlled by eliminating air and the use of an inhibitor. Additional rate reductions may be achievable by removing water and solids from the line with the use of an aggressive cleaning pig program. 6A-11 <<>> APPENDIX 6A (continued) EnhanceCo cites the need for important mitigations when transporting sour crude, including: • Use of corrosion inhibitors • Coupon monitoring at preferential accumulation points • Monitoring for MIC • Regular cleaning pigs to eliminate water and debris that may settle in low areas during periods of time when the pipeline is not flowing as sufficient velocities to sweep potential accumulations. • Avoidance of low flow and stagnant conditions These mitigation measures are included in Section 9.3.2.2 and are proven to be effective based on years of transport of sour crude oils in other pipelines. For purposes of this FEA risk profile, estimates of mitigation effectiveness are made and applied consistently along all portions of the pipeline. Since the modeled exposure rate varies according to some location-specific characteristics, the modeled corrosion rates will vary. Current activities to control internal corrosion involve control of product specification entering the pipeline, monitoring by coupon, and ILI. For purpose of generating the PoF profile, the current internal corrosion control activities conducted for transport of refined product is assigned a numerical estimate of effectiveness. This effectiveness is chosen as a plausible value that, when coupled with estimates of aggressiveness of current product transport, yields conservative but plausible values for PoF less than or equal to 1E-4 for a population of pipeline segments. Mitigation effectiveness is assumed for generation of a risk profile of the Proposed Project. Effectiveness values are conservative. However, they reflect the proposed additional mitigation measures and, when coupled with the high estimates for aggressiveness of corrosion, conservative results are produced. POF ASSESSMENT FOR SURGE The probability of a surge of a magnitude threatening any portion of the System can be estimated from an analysis of potential surge initiators, the effectiveness of surge prevention or mitigation, and the hydraulic behavior of the surge event. For the purpose of conducting this risk assessment analysis surge pressures were assumed using conservative estimates at all points. This presents an overstated estimate for this threat at most locations and does not allow discrimination along the pipeline with regards to surge potential, pipe stress levels, and effectiveness of safety devices. This risk assessment does discriminate regarding Maximum Allowable Surge Pressure (MASP) and presence of potential weaknesses. For conservative modeling purposes only, a PoD associated with surge was modeled. A PoD associated with surge is modeled to be one event in 10 years for 480 miles of pipeline. With the assumption of no resistance, the PoF equals this value. Under future conditions of the Proposed Project, increases are conservatively forecast for probabilities and aggressiveness of surges. Unmitigated surge frequencies are modeled to be 0.5 per year at all locations under 6A-12 <<>> APPENDIX 6A (continued) future operations. Future resistance level is modeled to be inversely proportional to stress level, the latter calculated as shown in the PoF algorithm table below. Under future conditions of the Proposed Project, increases are conservatively forecast for probabilities and aggressiveness of surges. Unmitigated surge frequencies are modeled at all locations under future operations. Resistance is modeled to be inversely proportional to stress level, the latter calculated as shown below. The theoretical available pipe wall is placed into the Barlow internal pressure equation to calculate the maximum pressure to which the pipe wall could be subjected. This pressure is compared to the MASP. When MASP exceeds the tolerable pressure of the theoretical pipe wall available, pipe failure is forecast upon application of the surge pressure. When left unmitigated, the results show pipe potentially subjected to surge pressures beyond their conservatively adjusted pressure containing capacity, under the assumptions used. Surge will be mitigated with industry standard protective devices to keep surge pressures within regulatory and LMP requirements. Additionally, events which can ultimately lead to surge overpressures are mitigated with administrative and engineering controls. Modeled exceedances of safe pressures are believed to be due solely to conservatism and limitations in current data. Surge Mitigation An analysis was performed by Willbros Engineering to determine whether surge pressures can occur that exceed 110% MOP limits. Those limits are defined by 49 CFR Part 195. Per the Longhorn Mitigation Plan (LMP), Commitment Item 31, Magellan will be seeking PHMSA approval of the measures to mitigate surge. LMC 31 states that “Longhorn shall perform a surge pressure analysis prior to any increase in the pumping capacity above those rates for which analyses have been performed or any other change which has the capability to change the surge pressures in the system. Longhorn will be required to submit mitigation measures acceptable to DOT/OPS prior to any such change in the system, which mitigation measures will adequately address any MASP problems on the system identified by the surge pressure analysis.” To demonstrate on-going risk management of this threat, mitigations as detailed in Chapter 9 are designed to measure and take appropriate steps to ensure failure potential from this threat does not exceed a pre-determined level at any location along the System. Coupled with the commitment to improve data management and risk analyses, risk levels can be managed to levels at or below those associated with current operations. This ensures that future PoF are less than 1E-4 and below current levels. After completion of the final surge analysis and PHA/LOPA process as discussed in section 9.3.3.2, overpressure protection measures will be established and approved by PHMSA in accordance with the LMP. A combined effectiveness of 99.9999% from all mitigation measures is used. This value indicates a simultaneous failure of all overpressure-prevention measures 6A-13 <<>> APPENDIX 6A (continued) once in every 10,000 demands. This value is chosen based on a review of systems in place including proposed pressure regulation and safety devices. Given the high reliability of redundant control/safety systems typical of pipeline operations, a value this high is realistic. POF ASSESSMENT FOR CRACKING AND FATIGUE MONITORING The actual rate of crack growth is dependent upon the three phases of crack advancement through a material: initiation, activation, propagation. Factors such as crack configuration, stress level, frequency and magnitude of stress cycles, and metallurgy are important considerations in crack growth rates. Based on the issues and evidence noted above, several cracking failure mechanisms are included in this PoF analysis. Fatigue, sulfide stress cracking, hydrogen-induced cracking from blistering, and SCC are rare, but possible phenomena. Probability of failure by cracking is assessed as follows. Unmitigated cracking rates and effectiveness of mitigations along the pipeline are estimated. An estimate of current pipe wall thickness, adjusted for possible weaknesses in manufacturing/construction, is theoretically degraded by the mitigated cracking rate to predict a time to failure. A relationship between this predicted time to failure and probability of failure within a certain time period is then used to produce the PoF estimate. Exposure: Fatigue and Hydrogen Assisted Cracking For risk assessment purposes, the likelihood of the existence of cracks must be estimated, activation is assumed, and then a relationship for the constant crack growth phase can be used to estimate propagation rate. The likelihood of incorrect assumptions in the crack growth calculations is also considered. Initiation Initiation is a function of the probability of a feature of sufficient size and characteristics to provide a starting point from which a crack can emerge. Outside force damages (i.e. gouges), Low Frequency ERW and EFW longitudinal seam defects, girth weld imperfections, arc burns, and laminations are identified as possible initiation points in the System, in addition to other weaknesses possibly introduced by the pipe manufacturing or construction process. The probability of an initiating point is modeled to be related to the frequency of relevant anomalies detected by ILI, especially crack-sensitive ILI (TFI). Some fraction of the population of detected anomalies is assumed to be potential crack initiators. While some of the relationships between anomalies and initiation points are currently unknown, the algorithms used to generate the PoF profile (detailed below) reflect the reasonable assumption that either deeper seam-type anomalies or a higher incidence rate of manufacturing defects or laminations leads to higher potential for crack initiation points. Activation 6A-14 <<>> APPENDIX 6A (continued) Activation, as used here, is the probability that conditions exist to begin a crack from an initiating point. One form of activation is sufficient cyclic fatigue at a susceptible location, including possible fatigue sources of internal pressure cycles, external pressure (load) cycles, and others. This potential is addressed in the annual ORA via analyses of actual internal pressure cycling on an assumed initiator defect and applied to crack growth models. No source of significant external force fatigue cycling on the System has been identified. Another form of activation is modeled as the probability of atomic hydrogen at a lamination. A literature review has found no models to predict the progression from a lamination to a blister to a failure on a pipe. This assessment assumes greater crack probability at locations of more and/or larger unrepaired laminations. In addition to these identified activation mechanisms, some probability of activation for other potential mechanisms, is assumed. Assumed probabilities are conservative. Propagation Propagation is modeled as a function of stress level and material toughness, with the latter being inferred by pipe age. Surge potential is included in the stress consideration, noting that rate of loading influences failure potential. Three regions of crack growth (propagation through a material) are identified and include: near threshold, linear, and instability. Many structures operate in the linear region. The Paris equation is popularly used to model crack behavior in this region. Crack growth rate versus stress intensity is approximately linear in this region and lies roughly between 10-6 and 10-3 in/cycle according to various literature sources. Crack growth rate increases with increasing applied stress. Most of the life of the component is spent while the crack length is relatively small. Stress concentrators play a significant role in fatigue initiation. Under future conditions, increases are conservatively forecast for probabilities of both initiation and activation. Pending acquisition of more accurate estimates of actual measured operation pressure cycles, the following assumptions are incorporated into the TTF estimates along the pipeline for the Proposed Project. . • fatigue cycling equivalent to three times currently estimated, shown as increased crack propagation rates • all anomalies of types ‘manufacturing’, ‘lamination’, ‘seam’, and ‘girth’ are considered to be initiation points • higher activation probability at all of these anomalies To account for inaccuracies and limitations in tool technology associated with the intervention process, the following assumptions are incorporated into the analysis: • Undetected or under-sized initiation points exist at a rate proportional to the identified initiation points. • Anomalies remain for every anomaly that is repaired. 6A-15 <<>> APPENDIX 6A (continued) These assumptions are reasonable, conservative, and useful for PoF estimates and lead to increased crack growth rate estimates, lower TTF, and increased PoF compared to the current operation, unless mitigation is applied. Using the existing commitment under the LMP to schedule intervention at 0.45 of the estimated TTF, leads to a modeled shortened intervention timing until actual pressure cycles are re-evaluated after reverse flow. Mitigation and Intervention Intervention is often the most practical option for risk management of fatigue cracking mechanisms. Reducing damage potential is the preferred approach to risk management. There are some cracking damage prevention opportunities. Prevention of blistering may be possible through the control of internal corrosion. Preventing the introduction of water and other corrosive agents, monitoring of potential corrosion on the inside of the pipe, and regular sweeping of accumulations with cleaning pigs can minimize the hydrogen generating environment. A direct assessment (DA) type process as defined in the ORA Process Manual is one of the tools currently used to manage the threat of SCC. In addition, a magnetic particle inspection is conducted at every excavation. Other crack damage prevention typically involves unrealistic changes in product or operating parameters. Intervention therefore plays an important role in crack risk management. Intervention acknowledges that damage might be occurring, but interrupts damage progression that would otherwise result in failure. Successfulness of intervention depends on timeliness of inspection, ability to detect potentially injurious anomalies, and error free remediation of those anomalies. Using conservative assumptions, cracking Time to Failure’s (TTFs) and associated PoFs are calculated along the pipeline by applying cracking growth rates to effective pipe wall estimates. For all cracking failure mechanisms, integrity assessment is seen as a critical intervention aspect of risk management. Intervention, as the final opportunity to prevent failure, under the Proposed Project mitigations is designed to prevent PoF from exceeding 1E-4 failures per mile- year during intervals between interventions. Mitigations detailed in Chapter 9 add both conservatism and robustness to the intervention process. TTF estimates that drive the intervention timing are to be improved, as are considerations for the range of potential damage rates that could occur. Incorrect Operations An important aspect of assessing this threat is a modeled variable called ‘overpressure potential’. This modeled variable is a measure of the potential to overpressure a portion of the pipeline through human error or certain equipment failures. From a risk standpoint, the worst situation is where a pipeline could be immediately over pressured in a relatively simple scenario. The best case is where there are no pressure sources powerful enough to overpressure the pipeline under any condition or where an overpressure scenario is only achievable after a long period of multiple, undetected operational missteps. 6A-16 <<>> APPENDIX 6A (continued) Given the relatively low compressibility of fluids and higher operating pressures and flow rates, the System is judged to be susceptible to overpressure unless engineered safeguards are in place. Engineered safeguards that include redundant overpressure protection devices such as pressure transmitters, fail-safe switches, and pressure relief valves are in place and tested in accordance with regulatory requirements. The potential for failure due to incorrect operations often shows little variation along a pipeline route since many aspects of this failure mode are not location specific. Examples of system- wide consistency in human error potential aspects includes: training, the use of procedures, risk assessments, condition of maps and records, and the presence of error-prevention devices. Location-specific aspects of human error potential which do change for the Proposed Project are as follows: • Locations of higher human activity such as stations • Potential for overpressure (higher where the surge potential and pipe stresses are higher); • Construction and design (higher for the older portions of pipeline and included in pipe strength analysis). Mitigation measures have been defined after completion of the final surge analysis and are designed to prevent PoF from exceeding 1E-4 failures per mile-year. The LMP requires Magellan to submit mitigation measures acceptable to PHMSA prior to any change which could impact surge pressures. Other safety system designs are assumed to be similar to existing operational schemes. A relatively high reliability value can be assigned to mitigation effectiveness when several levels of safety redundancies are included in the proposed control schemes. A formal LOPA type analysis, required as mitigation in Chapter 9, will be conducted once pump station designs, including safety systems, are finalized. Algorithms modeling this threat are shown at the end of this document and are discussed as follows: Profile of Current PoF from Incorrect Operations To generate a risk profile, a measurement or estimate is made for the exposure, mitigation, and resistance related to this threat. Although these values are currently assumed, based upon similar existing operational schemes, it is necessary to establish a model that is well-structured and ready to utilize more accurate information. A related mitigation requires such a structure to demonstrate achievement of the risk level. The failure potential from this threat is modeled to reflect the following: • Leak history • Previous human error incidents • Increased complexity with addition of more pump stations, inhibitor injection, need for regular maintenance (cleaning) pigging. 6A-17 <<>> APPENDIX 6A (continued) Since the System is to undergo a new operation with new equipment, new procedures, and perhaps newly assigned personnel, the human error potential could initially be higher. Pending full HAZOP-type analyses to identify and quantify issues, and application of risk-based mitigation measures, it is conservative to assume the Proposed Project brings an increase in failure potential from incorrect operations. Additional mitigation is intended to offset this potential increase as discussed in Chapter 9. Given the changes brought on by the Proposed Project, the accompanying increase in complexity, and some uncertainty regarding future operations, the estimated failure rate for the current operation is increased to show a future failure rate for the mainline. Similarly, at facilities, the rate is increased to account for changes and uncertainties. The future PoF values used in the PoF profile are generated by the algorithm(s) shown at the end of this document... Exposure The assessment does not discriminate location-specific characteristics along the mainline such as overpressure potential, safety device effectiveness, and source pressure influences. It is conservatively assumed that all portions are connected to sources that can theoretically generate pressures exceeding System capabilities. Overpressure potential is assumed to represent most of the incorrect operations exposure and is assumed to apply to all segments. For initial quantification of this threat at all mainline segments, an estimate of unmitigated event frequency is first made. Incorrect operations events threatening the mainline will typically be generated at facility locations. Additional potential overpressure events such as surges and thermal overpressure of blocked in components is assumed to be included in this exposure value. Mitigation A reliable set of mitigation measures against overpressure is assumed based upon information provided for the Proposed Project. A combined effectiveness of 99.9999% from all mitigation measures is used. This value indicates a simultaneous failure of all overpressure-prevention measures once in every 10,000 demands. This value is chosen based on a review of systems in place including proposed pressure regulation and safety devices. Given the high reliability of redundant control/safety systems typical of pipeline operations, a value this high is realistic. Formal analyses such as Layer of Protection Analysis (LOPA) following formal PHA’s will be conducted as part of the mitigation of the Proposed Project described in Chapter 9. Depending on measured risks, additional location-specific mitigation may be required, such as: additional redundancy in safety systems, additional training, and changes to processes and procedures. Changes to the assets will result in new or modified site specific operating procedures. Magellan establishes operating procedures as per SIP-ADM-9.01 (Appendix 6E) to prevent adverse impacts to the public, employees, environment, and the community. These operating procedures will be revised and employees will be trained prior to startup. Additionally these changes will result in new or modified maintenance procedures. Magellan has established Mechanical Integrity and Tank Integrity Programs to maintain the integrity of all equipment and tanks through risk based inspections and preventive maintenance. 6A-18 <<>> APPENDIX 6A (continued) To assess on-going risk management of Incorrect Operations, mitigation as described in Chapter 9 will maintain risk level thresholds during the intervals between intervention opportunities at or below risk levels that existed prior to the implementation of the Proposed Project. The threshold selected as appropriate for all threats combined is 1E-4 failures per mile- year at each non-facility portion and 0.01 per year at each facility. These values are below the estimated current levels for the threat of incorrect operations alone. Therefore, successful application of this mitigation measure ensures that the risks associated with this failure mechanism are reduced by the Proposed Project to levels below current. Security The threat level currently appears to be low compared to other threats. The frequency of integrity threatening events on US transmission pipelines is less than 1E-6 per mile-year. This is based on a FBI report showing one pipeline-related incident in 25 years and assuming 400,000 miles of potential US targets with increased attack potential in recent years (USDOJ/FBI, 2012). This pipeline risk assessment established a probability of failure from security threats. Security threats are modeled to change by the Proposed Project. Stations, casings with vents, and valve locations are thought to be more susceptible sites on the System due to visibility and ease of access. Locations where cover condition are changed would experience an increased threat and these would normally generate only minor changes in overall PoF. This threat at other locations is relevant due to the commitment to maintain PoF levels below pre-established thresholds under the Proposed Project. Algorithms modeling this threat are shown at the end of this document and are discussed as follows: In general, the Longhorn Pipeline is not thought to be more vulnerable than other pipeline systems. Standard or above-average security measures will be in place in accordance with the LMP and SIP which would generally include fences, locks, increased patrols, and surveillance cameras. The FBI has published a report summarizing 318 terrorism events between 1980 and 2005 (USDOJ/FBI, 2012). The terrorism events include all successful and foiled plots. Only 1 foiled plot related to potential pipeline attack was recorded. In 2005, a terrorist plan to carry out violent attacks against pipeline systems and energy facilities in Pocatello, Idaho was prevented. (Halcrow) This system has not experienced terrorism or sabotage. The threat level currently appears to be low compared to other threats. The frequency of integrity threatening events on US transmission pipelines is less than 1E-6 per mile-year. This is based on the U.S. Department of Justice’s, FBI report, Terrorism 2002-2005, showing one pipeline-related incident in 25 years and assuming 400,000 miles of potential US targets with increased attack potential in recent years (USDOJ/FBI, 2012). 6A-19 <<>> APPENDIX 6A (continued) For purposes of PoF profiling, the algorithms shown at the end of this document are used to estimate PoF from security threats. Logically some portions of the System make more attractive targets, either from the standpoint of ease of access or potential consequences. Pending analyses of such locations, only distinctions between above- and below-grade portions of the System are made. The calculations assume an incident every 5 years at above-ground locations and 10% of this incident rate elsewhere for both current and future PoF. Mitigation As part of the Proposed Project, mitigations detailed in Chapter 9 are designed to improve data management and tracking related to location-specific sabotage threats and maintain this knowledge in a database. This should improve estimates of PoF. Additional mitigations in Chapter 9 to improve risk assessment and risk management, and to maintain PoF levels below 1E-4 and will reduce failure potential from this threat when applied successfully. Magellan’s existing procedures contained in SIP-ADM-8.01 (Appendix 6E) provide for security measures such as security fencing, monitoring cameras, physical barriers, and locks to adequately limit access and mitigate security threats. PoF Assessment for Accidental Releases (predictions, frequency, Comparisons, Calibration) Leak Predictions A very generalized approach to risk assessment for a long, linear asset, such as a transmission pipeline, uses summary values representing all portions of the system. The summary values either assume a consistent set of characteristics and conditions exist along the entire route or that the variations along the system are defined by a ‘population’ of pipeline segments. The set of characteristics and conditions can be based on ‘worst case’ seen anywhere along the route or, more commonly, is based on an assumed set of characteristics and conditions embedded in a population of pipelines from which a comparable incident rate is to be derived. As an example of the latter, an average incident rate for US hazardous liquid transmission pipelines, perhaps filtered by decade of construction or other parameter, is obtained. Then, under the assumption that the subject pipeline ‘behaves’ like this comparison population, that incident rate is applied to all portions of the subject pipeline. Effectively, this means that the subject pipeline is thought to be a part of the population of pipelines to which a comparison is being made. Sometimes this approach includes a subsequent step to adjust this ‘baseline’ incident rate for portions of the subject pipeline, where it is postulated that the subject pipeline has differing characteristics and/or conditions sufficient to warrant a deviation from a rate implied by the overall average of the comparison population. Historical leak and spill frequency data, discussed in Chapter 5 for various spill sizes, were used as inputs into probability estimates. Since data is limited in both quantity and quality, additional estimates, often based on expert judgments are required in all assessments of real world, complex systems. 6A-20 <<>> APPENDIX 6A (continued) Regardless of the specific assumptions and methodology employed, results of such generalized analyses should not be used in isolation. They can easily over or understate the actual probability of future failures at specific locations or in short time periods. Behaviors of populations of segments over long periods of time are more reliably predicted than individual behaviors. The probabilities calculated here are intended to complement the risk profile discussed in previous sections. Leak Frequency In a generalized analysis as described previously, historical leak frequencies are sometimes used to predict future leak frequencies. In this type of analysis, there are no considerations for the changing PoF along the length of the pipeline. Leak frequencies are assumed to be uniformly distributed in time and space. This is not an accurate reflection of real risks so this type of analysis is limited in its ability to characterize risk. “Reportable” spill or leak refers to DOT criteria for formal reporting of accidents at 49 CFR §195.50. A spill size of 50 bbl was one of the triggers requiring the incident to be reported through 2001. Most pre-2002 incidents in DOT spill databases predominantly contain spills of 50 barrels or greater, although there are cases where a different criterion has mandated the reporting of an incident. Beginning in 2002, the reportable leak criterion based on volume spilled was reduced to 5 gallons. Magellan records incidents and leaks that do not meet minimum reporting criteria. These minor events are treated as learning opportunities. As discussed in Chapter 5, the Longhorn system has experienced 42 leaks since 2004, where 13 of those met minimum PHMSA reporting criteria (2 of those are noted to be ‘agency reportable’ but not ‘DOT reportable’, in data provided). Since such minor leaks are recognized by regulating agencies as having minimal consequence, they are not included in the following historical leak calculations. Comparisons with other Pipeline Leak Data Three "frequency of reportable leak" cases are examined. These cases use only historical data with no consideration given to possible benefits of future mitigation or to changes in leak rates along the System. They include all failure mechanisms that historically generated reportable incidents. Therefore, some failure mechanisms not affected by the Proposed Project are included. The cases examined are as follows: Case 1 Comparable Pipelines (Texas and US hazardous liquid pipeline leak rate) The total leak incident rate for reportable incidents on Texas hazardous liquids pipelines, from 2001-2010 is 1.96 incidents per 1000 mile-year for all incidents using the assumptions shown in Table 5.4.1-4. 6A-21 <<>> APPENDIX 6A (continued) The total leak incident rate for reportable incidents on US hazardous liquids pipelines, from 2001-2010 is 2.01 incidents per 1000 mile-year for all incidents using the assumptions shown in Table 5.4.1-5. For the 496 miles of the Proposed Project, these historical rates, if appropriate for the Proposed Project, suggest a reportable incident rate of 496 miles x 2 reportable incidents per 1000 mile- year/1000 = 1.0 reportable leak per year Magellan contracted with Allegro Energy Consulting to extract mainline pipe only incident data for the years 2010-2011 as a benchmark comparision for the risk threshold of 1E-4 mainline incidents/year. This equates to 0.1 incidents per 1000 mile-year. The mainline pipe only incident rate for reportable incidents on US hazardous liquids pipelines, from 2010-2011 is 0.830 incidents per 1000 mile-year for crude oil pipelines or 0.695 incidents/1000 mile-year for crude and refined product pipelines combined. The mainline pipe only incident rate for reportable incidents on Texas hazardous liquid pipelines from 2010-2011 was reported to be 1.057 incidents/1000mile-year for crude oil pipelines and 0.838 incidents/1000 mile-year for crude and refined product pipelines combined. Case 2 (System operation since January 2005, reportable leak rate) The reportable incident rate for 722.5 miles of this System in 6.5 years is 13 incidents or leaks. (Incident rate) = (13 leaks) / (722.5 miles x 6.5 years) * 1000 = 1.70 incidents per 1000 mile- year. Excluding reportable spills at stations, the reportable leak rate is 1. Therefore: (Incident rate) = (1 leak) / (722.5 miles x 6.5 years) * 1000 = 0.2 incidents per 1000 mile-year for mainline portions. If the historical reportable rate is more appropriately derived from only the 496 miles of the Proposed Project (the one reportable incident on the mainline occurred in Travis County), then , (Incident rate) = (1 leak) / (496 miles x 6.5 years) * 1000 = 0.3 incidents per 1000 mile-year for mainline portions. The expectation generated by values produced in this case would be (496 miles/1000 miles) x (0.2 to 0.3) = 0.1 to 0.15 reportable leaks per year. Case 3 (Longhorn operation since January 2005, overall leak rate) The overall leak rate, regardless of spill size or reportable nature, on the 722.5 miles of the System is 28 in 6.5 years. (Incident rate) = (28 leaks) / (722.5 miles x 6.5 years) * 1000 = 6.0 per 1000 mile-year. Excluding spills at stations, the leak rate for all leak types is 4. (Incident rate) = (4 leaks) / (722.5 miles x 6.5 years) * 1000 = 0.85 per 1000 mile-year along the mainline. 6A-22 <<>> APPENDIX 6A (continued) This case makes use of Magellan’s practice of documenting even very minor and inconsequential leaks. Therefore, very conservative results emerge, compared to an analysis limiting historical data to more significant leaks. For the 496 miles of the System, the expectation generated by this case would range from 0.85 to 6.0 failures per 1000 mile-year. This equates to between 0.4 and 3 leaks per year System-wide. Summary of Cases The above analysis suggests that, if the System performs either like it has in the past or as an average of other liquid pipelines, then reportable failure rates in the range of 0.1 to 1.0 reportable leaks per year are to be expected. These leak frequency estimates have a high degree of uncertainty as predictors of the future. The use of averages alone to describe the comparable populations is one example of possible significant mischaracterization of incident rates. Using subsets of the industry-wide data in attempts to better characterize similar populations might entail filtering by decade of construction, diameter, product, or other parameter deemed to produce a better comparable. However, each filtering further reduces the amount of data available for comparison. No data set that would better refine these estimates are known to be available. As noted earlier, frequencies and probabilities like these are statistically valid only over long periods of time for large populations of pipelines. Short time periods and short lengths of pipeline can have radically different experience and still be appropriately represented by these frequencies. Calibration of PoF Profile Each of these cases can be compared to the PoF profile estimates for the same locations. This provides a check on the plausibility of the assumptions used in the PoF profile. Approximately 90% of the PoF profile segments show values between 1E-3 and 0.1 failures per mile-year. These segments are short in length, so their respective PoF values are scaled from a few feet up to a mile. The remaining 10% of the profile show higher PoF values, thought to be due to errors in data or excessive conservatism in one or more specific failure mechanisms. Based on the comparisons, the PoF profile shows exaggerated amounts of conservatism when segments are scaled to longer lengths or numerous segments are combined. As discussed earlier, a high level of conservatism is beneficial in several ways and is intentionally included in initial PoF estimates. For other purposes, less conservative estimates are more appropriate. Using a value of 0.0005 failures/mile-year, consistent with the comparison cases above, suggests that the profile currently overestimates PoF by a factor that is estimated under certain assumptions. This factor can be used to adjust individual segment PoF estimates so that the population of segments carries an expectation consistent with past behavior of this and similar systems. Adjusting the profile with estimates of population behaviors preserves the location- specific understanding generated by the profile without biasing the overall expectations with excessive conservatism. 6A-23 <<>> APPENDIX 6A (continued) Using this approach, a calibration factor is applied to the PoF profile values. This value recognizes the uncertainties in several key aspects of the Proposed Project and includes a level of conservatism (i.e., includes historically dominant facility leaks). As with other modeling relationships employed in this analysis, alternative underlying assumptions may be appropriate, depending on availability of additional information and/or desire for different levels of conservatism. Using this calibration factor to adjust each segment’s PoF, the following PoF estimates are produced for the 496 miles evaluated: PoF Estimates Per Segment (of varying length) Per mile Min Avg Max Sum Min Avg Max fails/mi- fails/mi- fails/mi- Scenario fails/yr fails/yr fails/yr fails/yr yr yr yr PoF current state, calibrated 5E-09 8E-05 1E-02 2.8 3E-05 1.8E-01 9.9E-01 PoF future state (Unmitigated), calibrated 1E-08 1E-03 2E-02 48.8 5E-05 9E-01 9.9E-01 The value of 2.8 failures per year estimated for the current state equates to about 0.006 failures per mile-year for this System. This is in the range of values produced in the conservative Case 3 (leak history for mainline and facilities). Some of the high ‘per mile’ values in the PoF profile estimates for the PoF Future State (unmitigated) are due to extrapolation of pipe with very localized ILI-detected damage (very short segment length), to one mile lengths, effectively treating the local damages as if they extend for an entire mile. This does not materially impact the overall assessment since these per-mile values have limited use here. To examine certain location-specific changes in PoF brought about by the Proposed Project, segments involved in proposed valve reconfigurations can be viewed independently. When examining potential risks at specific locations along the System route, estimates generated by the adjusted PoF profile are applied to specific receptors potentially present at those locations. Overall, this risk assessment concluded that the Proposed Project, with the mitigations outlined in Chapter 9, will experience incident rates lower than current operations. The Proposed Project introduces new threats, but additional project mitigations are seen to offset PoF increases. The POF Algorithms used in the risk assessment are provided in the table below. 6A-24 <<>> APPENDIX 6A (continued) PoF Algorithms (Updated) The algorithms applied to the database to generate PoF profile (with brief descriptions) are shown below: RA Model Element Units Algorithm for Current Operation PoF Algorithm for Future Operation PoF Estimates Estimates Description pipe_wall*iif(val([repair_ID])>0,1,smaller( pipe_wall iit|val([repair_D])>0,1,lit [above pipe_wall_avail inches 1-nz(maxofseam_depth,0),(1- _graF future',1,smaller(1- nz(maxofmaxofpeak_depth,0)),nz(minofm nz(maxofseam_depth, 0), (1- apparent effective pipe wall nz(maxofmaxofpeak_depth,0)),nz(minofmi thickness, based on ILl info inofrpr,1))) nofrpr,1))) mpy_ext_ILI Mpy nz([MaxOfdmg_rate_vel_ext]*[pipe_wall]* iif([above_grd]=future',0,nz([MaxOfdmg_r 1000,0) ate_vel_ext]*[pipe_wall]*1000,0)) ILI-implied corr rate mpy_int_ILl Mpy nz([MaxOfdmg_rate_vel_int]*[pipe_wall]* nz([MaxOfdmg_rate_vel_int]*[pipe_wall]*1 1000,0) 000,0) *1.5 ILI-implied corr rate (Ipipe_wall_avail]*1000)/larger(0,mpy_ext ([pipe_wall_avail]*1000)/larger(0,mpy_ext_ TTF_ext years _ LI,mpy_ext_general*mpy_ext_accel"(1- ILl,mpy_ext_general*mpy_ext_accel*(1- TTF corr_ext mit)) corr_ext mit)) TTF_ext99 years ([pipe_wall_avail]*1000)/larger(0,mpy_ext ([pipe_wall_avail]*1000)/larger(0,mpy_ext_ _LI,mpy_ext_general*mpy_ext_accel) ILI,mpy_ext_general*mpy_ext_accel) worst case TTF TTF_int years ([pipe_wall_avail]*1000)/larger(0,mpy_int ([pipe_wall_avail]*1000)/larger(0,mpy_int_ LI,mpy int general* (1-corr_int _mit)) ILI,mpy_int_general*(1-corr_int_mit)) TTF TTF_int99 years (Ipipe_wall_avail]*1000)/larger(0,mpy_int (Lpipe_wall_availl*1000)/larger(0,mpy_int_ _LI,mpy_int_general) ILI,mpy_int_general) worst case TTF general corrosion rate; mpy_ext_general Mpy iif([above_grd]="present",3,16) lif([above_grd|=future",,if[above_grd|= atmospheric or soil; low present, 3, 16)) corrosivity if aerial, high if buried mpy_ext_accel Mpy iif([above_grd]='present",2,1) if([above_grd]=future", 2,if[above_grd]= increase in mpy to account present",2,1)) for 'hot spots' such as air/ground interface 6A-25 <<>> APPENDIX GA (continued) corr_ext_mit % smaller(999,0.99999,exp(- smaller(999,0.99999,exp(- % eff of mitigation, per [gaps/ft/CIS_fctr*len)) [gaps/ft]/CIS_fctr*len)) linear ft CIS_fctr factor larger(0,1,11-(year(now())- larger(0,1,11-(year(now())- factor to decrease modeled year(nz(CIS_date,1900)))) year(nz(CIS_date, 1900)))) mitigation gap rate when recent CIS is available mpy_int_general Mpy iif(drain_low=0,1,nz(drain_low/10000*3,1)) iif(drain_low=0,10,nz(drain_low/10000*30, internal corrosion mpy; based on low spot corr_int_mit % effectiveness of mitigation; modeled to decrease mpy len Ft [sectioned1_by_ID].endstation- [sectioned1_by_ID].endstation- [sectioned1_by_ID].begstation [sectioned1_by_ID].begstation segment length prob of one or more initiation points, takes larger iif/val([repair_ID])>0,0.00001, larger(nz(ma iif(val([repair_ID])>0,0.00001,larger(nz(ma of seam anomaly depth or crack_initiate % xofseam_depth, 0.00001), nz(sumofman_d xofseam_depth,0.00001),nz(sumofman_de fraction of surface area ef_rate,0.00001), nz(sumoflam_rate,0.0000 f_rate, 0.00001),nz(sumoflam_rate,0.00001) impacted by laminations or manufacturing anomalies; non-conservative assumption of 100% PoDetection prob of initiating point crack_activate % 0.0001 0.1 activating a crack; constant, pending improved info crack_propagate Mpy 2 6 mpy crack growth rate, based on ORA max assume no mitigation; (pipe_wall_avail*1000)/larger((crack_initia (pipe_wall_avail*1000)/larger((crack_initia resistance is pipe wall anc TTF_crack years te*crack_activate*crack_propagate), 0,0.0 te*crack_activate*crack_propagate), 0,0.00 0001) 001) Presume ro bo r ra ire effective TTF_SCC years (pipe_wall_avail*1000)/(SCC_mpy) (pipe_wall_avail*1000)/(SCC_mpy) TTF 6A-26 <<>> APPENDIX 6A (continued) probabilistic mpy, length- sensitive (mpy/ft); based on SCC_mpy Mpy 1.68350168350168E-06*len Round(nz([mop1]/[2st/d],1.0),3)*(1e- no failures in 50 yrs, 450 4) *len*10 miles, 0.2" pipe; ie, had there been X prob-mpy for 450 miles over 50 yrs, 0.200" wall pipe would fail now calibrate for incident occurring now at abvgrd PoF _sabotage failures 11490°5 flabove gra]=present; 1,10)) 11490°5'i|[above grd] = present, 1, ilab location; 1 incident in Syr /year en/5280 ove_grd]= future', 1,10))) *len/5280 for System mileage; 10X less for buried mit_cover % lif([above_grd]=present", 0,0.9) iif([above_grd]='present",0, iif|[above_grd] ='future",0,0.9)) mit eff of cover mit_other_excav % 0.9 0.9 combined mit eff of all other measures assume cover (and anything else used) is 99% eff against mit_impacts % iif([above_grd]="present",0.2,0.99) iif(jabove_grd]=present, 0.2,if|[above_gr impacts; if no cover, then d]=future',0.2,0.99)) other measures 20% (barriers, distance, trees, ditches, etc events/ exp_impacts mile- 0.1 0.1 freg of unmitigated 'events', year per mile of pipe per yr events/ exp_excav mile- 0.2 0.2 freq of unmitigated 'events', per mile of pipe per yr year 6A-27 <<>> APPENDIX 6A (continued) resistance; fraction of damages not manifesting as failures; 80% resistance to res _ext_force % iif(pipe_wall_avail>0.3,0.8,0.5) iif(pipe_wall_avail>0.3,0.8,0.5) failure when pipe wall thickness exceeds 0.3", 50% otherwise; includes ILI anomalies as reductions in pipe wall thickness PoF_excav failures 1-exp(-exp_excav*len/5280*(1-(1-(1- 1-exp(-exp_excav*len/5280*(1-(1-(1- /year mit_cover)*(1-mit_other_excav)))*(1- mit_cover)*(1-mit_other excav)))*(1- probability of damage res_ext_force)) res _ext force)) PoF_impacts failures 1-exp(-exp_impacts*len/5280*(1- 1-exp(-exp_impacts len/5280*(1- /year mit_impacts)* (1-res_ext_force)) mit_impacts)*(1-res_ext force)) probability of damage MOP1 Psig longhorn_MAOP_fixed.mop longhorn_MAOP_fixed.mop use MOP from database, not RRA 0 0 0 0 [2st/d] Psig 2"[pipe_wall_avail]*[smys]/[pipe_size] 2*[pipe_wall_avail]*[smys]/[pipe_size] Barlow formula for maximum internal pressure % of allowable pressure surge_stress % Round(nz([masp]/[2st/d],1.0),3)*100 Round(nz([masp]/[2st/d],1.0),3)*100 consummed by surge pressure events/ surge_freq mile- 0.5 0.5 event count, system-wide year surge_resis % iif(surge_stress>100,0,1- current resist included in surge_stress/100) PoD rate PoD_surge damag 1 iif(surge_stress<100,0,surge_freq)*len/52 calibrate to 1 incident in 0.000204*len/5280 10yrs for System mileage; es/year no mitigation PoF_surge failures |I 1-exp(-(PoD_surge*(1-surge_resis))) III 1-exp(-(PoD_surge*(1-surge_resis))) Lyear probability of failure 6A-28 <<>> APPENDIX 6A (continued) PoF_IncOps failures /year smaller(0,0.99,iif([above_grd]='present',0. 6/20,2e-7)*len) iif([above_grd]='present',0.8/20,iif([above_ grd]='future',0.8/20,1.5*2e-7))*len includes equip; 13 spills in facilities since 2000; PHA rate is 0.6 per yr per facility (even valve site) with facility = 20 ft of pipe; for non- facility, use mainline rate = 3 equip fails since 04, assume 450 miles 6A-29 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 6B CRUDE OIL SPECIFICATIONS <<>> lntertek Report of Analysis NTERI Client: Magellan Pipeline Co. L.P. Job Location: Cushing, OK USA Our Reference Number: US180-0000069 Client Reference Number: None Sample ID: 2011-CUSH-000076-001 Sample Designated As: Crude Vessel/Location: Odessa, TX Representing: MAGELLAN- ODESSA- 7-12-11- WTS Date Taken: 15-July-2011 Date Submitted: 15-July-2011 Date Tested:21-July-2011 Drawn By:Ciient Method ASTM D287 ASTM D4294 ASTM D445 ASTM D5191 ASTM D4007 _MOD ASTM D97 ASTM D4530 ASTM D664 ASTM D5708 Test Result Units ASTM D7169 UOP 163 API Gravity (Hydrometer Method) API Gravity @ 60 °F 31.9 Sulfur Content in Petroleum Products by ED-XRF Sulfur Content 2.00 Kinematic I Dynamic Viscosity Test Temperature 37.8 Kinematic Viscos~ty 5.540 Vapor Pressure of Petroleum Products (Mini-Method) Dry Vap?r Pressure Equival~nt, ASTM 3.13 Water and Sediment in Crude Oil Solvent STODDARD SOL VENT Total Water and Sediment 0.05 Pour Point of Petroleum Products Pour Point -15 Pour Point 5.0 Micro Carbon Residue Average M icro Method Carbon Residue _ 3.45 Acid Number of Petroleum Products by Potentiometric Titration Procedure Used A Acid Number 0.10 Metals by ICP-AES Procedure Test Method B Nickel Content 5.21 Vanadium Content 9.60 Boiling Point Distribution of Samples with Residues by High Temperature GC Boiling Point Distribution See Attached Report Hydrogen Sulfide and Mercaptan Sulfur H2S 10 Mercaptan Sulfur 521 Wt% eSt i ps_ Vol% Wt% mg KOH/g m(Jikg mg/kg ppmWt ppmWt Page 1 of 2 688224 804 E. North Street, Cushing, Oklahoma 74023 USA Tel : 918-306-4206 Fax.: 918-306-4208 Email: amerusa.cushing@intertek.com 21-Jul-2011 14:02 US180-0000069 <<>> lntertek Report of Analysis R This report has been reviewed for accuracy, completeness, and comparison against specifications when available. The reported results are only representative of the samples submitted for testing and are subject to confirmation upon completion of the final report, which may contain warnings, exceptions and terms and conditions which are pertinent to the data supplied herein. It is the position of lntertek that the final report is the prevailing document, and that the use of interim documents by the client is at their own risk. This report shall not be reproduced except in full without written approval of the laboratory. Date: Signed : --------------------------~~~------------------------lntertek --------------------------------- Kevin Gilbert, Branch Manager ) Page 2 of 2 688224 804 E. North Street, Cushing, Oklahoma 74023 USA Tel.: 918-306-4206 Fax.: 918-306-4208 Email: amerusa.cushing@intertek.com 21-Jul-2011 14:02 US180-0000069 <<>> lntertek Report of Analysis E I Client: Magellan Pipeline Co. L.P. Job Location: Cushing, OK USA Our Reference Number: US180-0000069 Client Reference Number: None Sample ID: 2011-CUSH-000076-002 Sample Designated As: Crude Vessel/Location: Odessa, TX Representing: MAGELLAN- ODESSA -7-12-11- WTI Date Taken: 15-July-2011 Date Submitted:15-July-2011 Date Tested:21-July-2011 Drawn By: Client Method Test Result Units ASTM D287 ASTM D4294 ASTM D445 ASTM D5191 ASTM D4007 _MOD ASTM D97 ASTM D4530 ASTM D664 ASTM D5708 ASTM D7169 UOP 163 API Gravity (Hydrometer Method) API Gravity @ 60 °F 40.3 Sulfur Content in Petroleum Products by ED-XRF Sulfur Content 0.405 Kinematic I Dynamic Viscosity Test Temperature 37.8 Kinem atic Visco~ity _ 2.858 Vapor Pressure of Petroleum Products (Mini-Method) Dry Vap?r Pressure Equiv~lent, ASTM 5.40 Water and Sediment in Crude Oil Solvent STODDARD SOL VENT Total Water and Sediment . . . 0.05 Pour Point of Petroleum Products Pour Point <-30 Pour Point <-22.0 Micro Carbon Residue Av~ra~e Micro Method Carbon Residue 1.04 Acid Number of Petroleum Products by Potentiometric Titration Procedure Used A Acid Number 0.20 Metals by ICP-AES Procedure Test Method B Nickel Content 0.961 Vanadium Content 1.55 Boiling Point Distribution of Samples with Residues by High Temperature GC Boiling Point Distrib~tion See Attached Report Hydrogen Sulfide and Mercaptan Sulfur H2S < 1 Mercaptan Sulfur 164 O API WI% o c eSt psi Vol% oc O F Wt% mg KOH/g ppm WI ppmWt Page 1 of 2 688222 804 E. Nort/7 Street, Cushing, Oklahoma 74023 USA Tel.: 918-306-4206 Fax.: 918-306-4208 Email: amerusa.cushing@intertek.com 21-Jul-2011 14:01 US180-0000069 <<>> ) lntertek Report of Analysis I TE IM This report has been reviewed for accuracy, completeness, and comparison against specifications when available. The reported results are only representative of the samples submitted for testing and are subject to confirmation upon completion of the final report, which may contain warnings, exceptions and terms and conditions which are pertinent to the data supplied herein. It is the position of lntertek that the final report is the prevailing document, and that the use of interim documents by the client is at their own risk. This report shall not be reproduced except in full without written approval of the laboratory. Signed: ____________ __,----,------------- lntertek Kevin Gilbert, Branch Manager Date: ------------------- ) Page 2 of 2 688222 804 E. North Street, Cushing, Oklahoma 74023 USA Tel.: 918-306-4206 Fax.: 918-306-4208 Email: amerusa.cushing@intertek.com 21-Jul-2011 14:01 us 180-0000069 <<>> 11-CUSH-76-001 Injected On: 20-Jul-11, 15:53:54 by TB Page: 1 Procedure File: D7169 Cushing.prc Data File: C:Chem32/1DATAID716SID7169 2011-07-20 10-49-54\006F0601.D1006F0601.CDF Blank File: C:Chem32/DATAID71651D7169 2011-07-20 10-49.541001 F0102. D1001 F0102.CDF Calib File: C:ICHEM3211 DATA10628111D7169 2011-06-28 08-56-13\002F0201.DI002F0201 CDF Solvent Exclusions: Mins BaseLine Zero: 4.86315 Quench Region: [0.202...0.392] Mins - QF: 1.930 Response Factor: 1.59399996846332E-6 Uncorr Total Sample Area: 5.8562E5 Corr Total Sample Area: 5.7122E5 Start Of Material (mins): 0.135 End Of Material (mins): 29.850 SOM Thrsh: (0.00001000%) EOM Thrsh: (0.00001000%) Sample Weight (g): 0.1049 Solvent Weight (g): 10.5344 Material Search Restricted To: NO RESTRICTION Material End Forced To: NO FORCE Warnings: Material Bal (W1%): 92.35 Wt% D7169 HiTemp Simulated Distillation Plot миллени 12 04 High Temp D7169 Boiling Point Distribution *IBP ... 94.59 1.00%... 99.75 15.00% ... 289.35 16.00%... 302.45 31.00% ... 453.88 30.00% ... 443.59 46.00%... 598,23 45.00% ... 587.53 61.00% ... 760.68 60.00%.. 749.10 76.00% ... 956.10 75.00%.. 940.58 90.00%.. 1255.40 3.00%.. 172,65 2.00% ... 157.09 18.00% ... 318.59 17.00% ... 312.97 32,00% ,.. 462.33 33.00%.. 472.97 47,00%,. 604.78 48.00% ... 615.62 62.00% ... 772.79 63.00% ... 784.26 78.00%.. 989.79 77.00% ... 973.13 91.00%.. 1285,50 92.35%.. 1327.1 92.00% ... 1315.90 4.00%.. 185.73 5.00% ... 193.21 19.00%.. 329.64 20.00% ... 342.58 35.00% ... 490.52 34.00% .... 482.33 50.00% ... 636.42 49.00%... 625.93 6.00% ... 209.31 21.00% ... 350.30 36.00% ... 501.98 51.00% … 648.47 65.00% ... 807.35 64.00%.. 795.49 79.00% ... 1007.20 66.00% ... 819.25 80.00% ... 1026.40 FBP >1328 81.00% ... 1046.00 %Recovery: 92.35 % Residue - 7.65 8.00% ... 227.37 7.00% ... 213.05 22.00%:.. 358.87 23,00%.. 372.53 37.00%.. 510.42 38.00% ... 519.73 53.00% … 670.16 52.00% 658.18 67.00%.. 831.35 68.00%.. 844.10 83.00% ... 1085.90 82.00% 1065.20 10.00% ... 244.13 9.00% ... 237.75 24.00%... 383.98 25.00% ... 391.82 40.00% ... 540.69 39.00%.. 529.89 54.00%.. 680.44 11.00% ... 258.96 26.00%.. 404.07 41.00%... 549.82 55.00% ... 692.37 69.00% 857.26 56.00%... 702.68 70.00% ... 871.12 84.00%.. 1107.00 71.00%.. 884.35 86.00%... 1152.50 85.00% ... 1129.40 13.00%.. 273.62 12.00%.. 267.04 27.00% ..416.33 28.00% ... 423.31 43.00% ... 570.35 42.00% .560.59 58.00%.. ..725.22 57.00%.. 714.43 72.00%.. 897.87 73.00% ... 912.17 88.00% ... 1199.10 87.00%.. 1175.20 14.00% ... 278.80 29.00% ... 432.55 44,00% 577.86 59.00% ... 736.58 74.00% ... 926.80 Warning: Items preceded by * denote material eluted prior to the earliest retention time or later than the latest retention time in the current calibration 89.00%... 1224.40 High Temp D7169 Cut Point Distribution Cut Point Range ..% Off Cut Point #1 ~ (54.00 - 220.00]-l-0,000 - 1.003Min.] ~ 7.2225% Cut Point #3 - (1020.00 - 1641.00)- 20.052 - 40.297 Min.] - 12,6697% Cut Point #2 ~ [220.00 - 1020.00] [1.003 - 20.052Min.] ~ 72.4565% Simdist-2000 7/20/20114:43:28 PM <<>> 11 -CUSH-76-002 Injected On: 20-Jul-11, 16:42:59 by TB Data File: C.\Chem32\1\0ATA\07169107169 2011·07·20 10-49-54\007F0701 .DI007F0701 COF Blank File: C:IChem3211 IOATAI071691 07169 2011-07-20 10-49-541001 F01 02.01001 F01 02.COF Calib File: C:ICHEM321110ATAI062811107169 2011-06-28 08·58-131002F0201 .D\002F0201 .COF Solvent Exclusions: Mins Quench Region: [0.202 .. . 0.392] Mins - QF: 1 .930 Uncorr Total Sample Area: 6.0276E5 Corr Total Sample Area: 5.9333E5 Page: 1 Procedure File: 0 7169 Cushing.prc BaseLine Zero: Response Factor: 4.90957 1.59399996846332E-6 Start Of Material (mins): 0.135 End Of Material (mins) : 29.883 SOM Thrsh: (0.00001000%) EOM Thrsh: (0.00001000%) Material Search Restricted To: NO RESTRICTION Material End Forced To: NO FORCE Warnings: D7169 HiTemp Simulated Distillation Plot Sample Weight (g) Solvent Weight (g): 0.1044 10.4698 Material Bal (Wt%): 95.79 Wt% · ~ .. , High Temp D7169 Boiling Point Distribution *IBP ... 87.79 15.00% ... 222.82 30.00% ... 344.12 *1 .00% .. . 93 .70 16.00%. . 228.61 31.00% .. . 351 .68 45.00% ... 488.48 60.00% ... 643.68 75.00% ... 832.62 90.00% ... 1110.00 46.00% ... 498.31 61.00% .. . 654.35 76.00% - . 846.78 91 .00% ... 1138.70 2.00% . . 97.10 17.00% ... 238.10 32.00% . . 360.08 47.00% - - 508.51 62.00% ... 667.65 77.00% ... 861 .66 92.00% -- · 1169.70 3.00% . . 99.62 18.00% ... 240.99 33.00% ... 372.94 48.00% ... 518.63 63.00% ... 678.90 78.00% ... 876.70 93.00% ... 1203.20 4.00% ... 147.47 19.00% - . 248.10 34.00% .. . 383.72 49.00% ... 527.76 64.00% . . 692.27 79.00% -- - 891.50 94.00% . - 1243.70 5.00% ... 155.78 20.00% ... 259.40 35.00% ... 390.46 50.00% ... 539.34 65.00% ... 703.64 80.00% ... 906.91 95.00% ... 1290.80 6.00% 160.30 21 .00% - - 266.60 36.00% ... 402.08 7.00% ·- - 166.52 22.00% ... 273.76 37.00% .. 412.93 8.00% ... 176.17 23.00% ... 280.54 38.00% 421.49 9 .00% .. 186.46 24.00% 288.75 39.00% .. . 430.19 51 .00% ... 549.36 66.00% .. 716.00 81 .00% - - 922.98 95.79% ... 1328.1 52.00% 560.87 67.00% ... 728.91 82.00%-- -938.18 FBP >1328 53.00% ... 571 .36 54 .00% .. 578.32 68.00%- . 741.59 69.00% ... 754.86 83.00% -- - 955.25 84 .00% --- 974.34 % Residue - 4.21 %Recovery: 95.79 10.00% ... 192.12 25.00% ... 300.50 40.00% ... 440.63 11 .00% .. . 196.79 26.00% ... 304.53 41 .00%- . 450.23 55.00% ... 588.86 70.00% ... 768.20 85.00% ... 993.43 56.00% ... 599.90 71.00% --- 780.79 86.00% ... 1013.60 12.00% ... 209.66 27.00% ... 316.26 42 .00% ... 457 .98 57.00% ... 608.43 72.00% .. . 792.83 87.00% . - 1036.50 13.00% ... 211.16 28.00% .. 324.45 43 .00% ... 469 .80 58.00% ... 620.73 73.00% ... 806.05 88.00% ... 1059.40 14.00% . . 212.54 29.00% ... 331 .80 44 .00% ... 479.64 59.00% ... 630.30 74.00% ... 819.25 89.00% - - 1083.80 Warning: Items preceded by • denote material eluted prior to the earliest retention time or later than the latest retention time in the current calibration High Temp D7169 Cut Point Distribution Cut Point Range ... % Off Cut Point #1- [54.00 · 220.00]-[·0.000 - 1.003Min.]- 14.7639% Cut Point #2- [220.00- 1020.00]-[1.003- 20.052Min.] -71 .5183% Cut Point #3- [1020.00 -1641.00]-[20.052- 40.297Min.]- 9.5097% Simdist-2000 7/21/2011 8:20:52 AM <<>> Whole Crude Analysis CRUDE : Eagleford LOCATION : Texas REPRESENTATIVE OF : REPORT NO. : U2010.011 LAB WORK BY : Clinton Assay Lab CONTACT : EMRE F. Hagardorn REPORT BY : EMRE B. J. Throop REPORT DATE: Prepared for external release on August 23, 2010 APPROVED BY : EMRE M. D. Monahan EMRE F. Hagardorn EMRE M Hamrick ASSAY COMMENTS: This assay information is provided to you courtesy of ExxonMobil Research and Engineering Company (EMRE) and is based on a range of data and information. While care has been taken in preparing these materials, no representations, warranties or guarantees are made as to their accuracy, reliability, quality, correctness or completeness. Each user must make its own determination and judgment on applying any information in this assay. Any and all use of this information shall be the sole responsibility of the user, and the user releases EMRE, parent and its affiliates from any and all claims arising from its use and shall defend and hold EMRE, its parent and its affiliates harmless from any third party claims arising from the user's application or use of the assay information. <<>> TABLE 1 WHOLE CRUDE PROPERTIES (DRY BASIS) CRUDE Eagleford DATE August 19, 2010 CRUDE BALANCE GRAVITY API 40.1 40.4 SPECIFIC GRAVITY 60/60 .8246 .8229 SULFUR WGT% 0.13 0.13 MERCAPTAN SULFUR WGT PPM <2 POUR POINT DEG F 24 NITROGEN WGT % 0.034 0.032 BASIC NITROGEN WGT % 0.006 0.006 CON CARBON WGT % 0.54 0.53 SALT CONTENT PTB REID VAPOR PRESSURE PSI 2.8 NEUT. NUMBER MG KOH/GM 0.05 0.05 H2S DISSOLVED WGT PPM 0 H2O BY DISTILLATION VOL % 0.00 VANADIUM WGT PPM 0.10 0.06 NICKEL WGT PPM 0.20 0.05 VISCOSITIES DEG F DEG C CRUDE CST AT 40 4.4 10.05 60 15.6 6.98 77 25.0 5.35 80 26.7 5.12 100 37.8 3.93 104 40.0 3.74 122 50.0 3.06 140 60.0 2.56 LIGHT HYDROCARBONS % ON CRUDE VOLUME% WEIGHT% ETHANE 0.00 0.00 PROPANE 0.19 0.12 ISOBUTANE 0.16 0.11 NORMAL BUTANE 0.80 0.57 ISOPENTANE 0.79 0.61 NORMAL PENTANE 1.32 1.02 VOLUME % DISTILLED AT 10 DEGREE F INTERVALS DEG F 0 10 20 30 40 50 60 70 80 90 0 0.18 0.24 0.30 0.42 0.60 0.78 0.95 1.16 1.51 1.85 100 2.36 2.86 3.52 4.34 5.17 6.02 6.88 7.76 8.67 9.59 200 10.53 11.49 12.47 13.48 14.51 15.56 16.63 17.73 18.85 19.99 300 21.15 22.34 23.54 24.77 26.01 27.28 28.55 29.84 31.14 32.45 400 33.76 35.08 36.39 37.70 39.00 40.29 41.57 42.84 44.09 45.32 500 46.53 47.72 48.89 50.05 51.18 52.30 53.40 54.49 55.56 56.62 600 57.66 58.68 59.69 60.69 61.67 62.64 63.60 64.54 65.48 66.40 700 67.31 68.21 69.09 69.97 70.83 71.68 72.52 73.35 74.16 74.96 800 75.75 76.53 77.30 78.05 78.80 79.53 80.25 80.97 81.67 82.36 900 83.04 83.71 84.37 85.02 85.66 86.29 86.92 87.53 88.13 88.71 1000 89.28 89.84 90.37 90.89 91.40 91.88 92.35 <<>> TABLE 1A Eagleford Balance Whole Crude GRAVITY API 40.4 40.1 SPECIFIC GRAVITY 60/60 0.8246 SULFUR WGT% 0.13 Ni WGT PPM 0.20 V WGT PPM 0.10 POUR POINT DEG F 24 WATER VOL% 0.00 Fraction Wt % Crd Cum Wt % Vol % Crd Cum Vol % API Gravity -200/160 160/360 360/530 530/650 650/1049 1049/FBP 5.4 5.4 20.1 25.5 21.2 46.7 12.8 59.6 31.3 90.8 9.2 100.0 6.9 6.9 21.7 28.6 21.5 50.1 12.6 62.6 29.2 91.8 8.2 100.0 53.9 42.5 37.3 29.1 21.7 z VOL % ON CRUDE 8.2% 6.9% 21.7% -200/160 160/360 360/530 530/650 650/1049 1049/FBP 29.2% 21.5% 12.6% <<>> TABLE 2 CUT QUALITIES Eagleford 40.1 API ------- TEMP ------- -- NORMALIZED VOLUME % -- ------- GRAVITY ------- -- NORMALIZED WEIGHT % -- MERC RI --------------------- DEG F ---------------------- VOL % DEG DEG ON DEG SPEC ON SULFUR SULF AT 67 ANIL PER 10 F C CRUDE CUM MID API 60/60 CRUDE CUM MID WGT % PPM DEG C PT. POUR CLOUD FREEZE DEG F -175 -115 0.00 0.00 0.00 246.8 0.3740 0.00 0.00 0 -18 0.18 0.18 0.09 147.0 0.5081 0.11 0.11 25 -4 0.15 0.33 0.25 119.8 0.5631 0.10 0.21 68 20 0.77 1.10 0.71 110.8 0.5840 0.54 0.76 90 32 0.76 1.85 1.47 94.9 0.6250 0.57 1.33 115 46 1.26 3.11 2.48 92.7 0.6311 0.97 2.30 158 70 3.59 6.71 4.91 77.5 0.6769 2.95 5.25 3.78 0.0002 <2 185 85 2.42 9.12 7.91 69.5 0.7040 2.07 7.32 6.29 0.0003 <2 212 100 2.56 11.68 10.40 63.5 0.7258 2.26 9.58 8.45 0.0004 2 248 120 3.66 15.34 13.51 57.6 0.7483 3.33 12.91 11.25 0.0005 2 275 135 2.94 18.28 16.81 53.0 0.7668 2.74 15.65 14.28 0.0007 3 0.8349 0.8963 0.9481 1.0167 1.0889 302 150 3.10 21.38 19.83 50.0 0.7795 2.94 18.59 17.12 0.0008 3 1.1481 320 160 2.16 23.54 22.46 48.1 0.7880 2.07 20.65 19.63 0.0010 3 1.4181 129.1 -107 -101 -94 1.2000 347 175 3.35 26.90 25.22 46.5 0.7948 3.24 23.89 22.27 0.0012 3 1.4204 133.3 -97 -90 -84 1.2407 374 190 3.47 30.36 28.63 45.1 0.8011 3.37 27.26 25.58 0.0016 3 1.4232 138.3 -85 -78 -71 1.2852 401 205 3.53 33.89 32.13 44.1 0.8059 3.46 30.72 28.99 0.0020 3 1.4261 143.2 -73 -65 -58 1.3074 428 220 3.54 37.44 35.67 43.3 0.8096 3.49 34.21 32.47 0.0026 3 1.4290 148.1 -61 -52 -45 1.3111 455 235 3.50 40.93 39.19 42.6 0.8129 3.45 37.66 35.94 0.0033 4 1.4320 153.1 -48 -39 -32 1.2963 482 250 3.40 44.34 42.63 41.8 0.8164 3.37 41.04 39.35 0.0046 4 1.4349 158.3 -35 -26 -19 1.2593 509 265 3.27 47.60 45.97 41.0 0.8204 3.26 44.30 42.67 0.0085 4 1.4379 163.6 -22 -13 -7 1.2111 536 280 3.13 50.73 49.17 40.0 0.8249 3.14 47.43 45.87 0.0227 4 1.4408 168.9 -9 0 6 1.1593 563 295 3.00 53.73 52.23 39.0 0.8300 3.03 50.46 48.95 0.0570 4 1.4436 174.2 4 12 18 1.1111 590 310 2.88 56.62 55.18 37.9 0.8355 2.93 53.39 51.93 0.1062 1.4464 179.4 16 24 617 325 2.77 59.39 58.00 36.6 0.8416 2.84 56.22 54.81 0.1539 1.4490 184.3 28 35 650 343 3.25 62.64 61.02 35.2 0.8490 3.35 59.58 57.90 0.1916 1.4518 189.2 41 47 671 355 2.00 64.64 63.64 33.9 0.8556 2.08 61.65 60.62 0.2140 1.4542 193.1 51 57 1.0667 1.0259 0.9848 0.9524 698 370 2.49 67.13 65.88 32.7 0.8616 2.61 64.26 62.96 0.2309 1.4563 196.4 60 65 725 385 2.41 69.53 68.33 31.6 0.8674 2.54 66.80 65.53 0.2459 1.4585 199.8 68 752 400 2.32 71.85 70.69 30.8 0.8718 2.46 69.25 68.03 0.2570 1.4607 203.3 76 779 415 2.23 74.08 72.97 30.2 0.8749 2.37 71.62 70.44 0.2645 1.4628 206.8 82 806 430 2.14 76.22 75.15 29.8 0.8773 2.28 73.91 72.76 0.2690 1.4649 210.7 88 0.9222 0.8926 0.8593 0.8259 0.7926 833 445 2.06 78.28 77.25 29.4 0.8796 2.20 76.10 75.01 0.2713 1.4669 215.2 93 851 455 1.33 79.61 78.94 28.9 0.8820 1.42 77.52 76.81 0.2721 1.4687 219.3 96 887 475 2.55 82.15 80.88 28.2 0.8858 2.74 80.26 78.89 0.2726 1.4707 225.1 100 914 490 1.82 83.97 83.06 27.4 0.8906 1.97 82.24 81.25 0.2737 1.4732 232.5 104 950 510 2.32 86.29 85.13 26.6 0.8948 2.52 84.76 83.50 0.2769 1.4756 240.1 107 0.7630 0.7389 0.7083 0.6741 0.6444 968 520 1.11 87.41 86.85 26.1 0.8979 1.22 85.98 85.37 0.2823 1.4779 246.4 110 995 535 1.59 89.00 88.21 25.7 0.9002 1.74 87.72 86.85 0.2897 1.4797 251.2 112 1022 550 1.48 90.48 89.74 25.2 0.9030 1.62 89.34 88.53 0.3010 1.4821 256.6 114 1049 565 1.36 91.83 91.16 24.7 0.9059 1.49 90.83 90.09 0.3126 1.4845 261.7 117 FBP FBP 8.17 100.00 21.7 0.9240 9.17 100.00 0.3714 46 0.6167 0.5889 0.5481 0.5037 <<>> TABLE 2A CUT QUALITIES Eagleford 40.1 API TEMP MID ----------------- CENTISTOKES AT ------------------- SMOKE LUMIN NEUT ------- VOLUME % ------- ----------- WEIGHT % ------------- --------------- WEIGHT PPM ----------------- F VOL % -30 F 100 F 150 F 210 F MM NO NO PARA NAPH AROM N2 BN2 CCAR FE NI V NA 185 7.91 64.7 30.6 4.7 212 10.40 55.8 38.6 5.6 248 13.51 55.1 33.5 11.4 275 16.81 57.8 28.2 14.0 302 19.83 51.8 29.8 18.4 320 22.46 2.22 0.80 0.63 0.49 30.8 71 52.6 29.4 18.0 347 25.22 2.73 0.90 0.69 0.54 29.9 69 53.9 26.8 19.3 374 28.63 3.59 1.03 0.78 0.60 28.7 66 52.0 32.1 15.9 401 32.13 4.90 1.19 0.88 0.66 27.6 63 42.0 46.0 12.0 428 35.67 6.97 1.40 1.01 0.74 26.4 60 0.04 41.7 44.7 13.6 455 39.19 10.33 1.65 1.16 0.83 25.2 57 0.04 49.0 36.1 14.9 0.000 0.000 482 42.63 15.88 1.97 1.34 0.94 24.0 54 0.05 50.6 33.4 16.0 0.000 0.000 509 45.97 25.39 2.37 1.55 1.06 22.7 51 0.06 51.3 34.0 14.6 0.000 0.000 536 49.17 42.53 2.90 1.80 1.20 21.5 48 0.07 53.8 33.6 12.5 0.001 0.000 563 52.23 73.11 3.56 2.11 1.36 20.2 45 0.09 53.6 33.1 13.2 0.001 0.000 590 55.18 4.43 2.49 1.54 0.10 0.003 0.001 617 58.00 5.59 2.98 1.77 0.11 0.006 0.001 650 61.02 7.25 3.65 2.06 0.11 0.013 0.003 671 63.64 9.12 4.36 2.37 0.10 0.022 0.004 <0.005 <0.1 <0.1 <0.1 <0.1 698 65.88 11.29 5.15 2.70 0.09 0.032 0.005 <0.005 <0.1 <0.1 <0.1 <0.1 725 68.33 14.32 6.22 3.14 0.08 0.043 0.005 0.01 <0.1 <0.1 <0.1 <0.1 752 70.69 18.21 7.53 3.65 0.07 0.051 0.005 0.01 <0.1 <0.1 <0.1 <0.1 779 72.97 23.25 9.15 4.27 0.07 0.057 0.006 0.02 <0.1 <0.1 <0.1 <0.1 806 75.15 29.82 11.17 5.01 0.06 0.059 0.007 0.03 <0.1 <0.1 <0.1 <0.1 833 77.25 38.51 13.72 5.91 0.06 0.059 0.008 0.04 <0.1 <0.1 <0.1 <0.1 851 78.94 47.97 16.36 6.80 0.05 0.059 0.009 0.07 <0.1 <0.1 <0.1 <0.1 887 80.88 62.80 20.28 8.07 0.05 0.060 0.010 0.12 <0.1 <0.1 <0.1 <0.1 914 83.06 87.20 26.34 9.92 0.05 0.061 0.012 0.21 <0.1 <0.1 <0.1 <0.1 950 85.13 122.51 34.51 12.27 0.04 0.063 0.013 0.34 <0.1 <0.1 <0.1 0.1 968 86.85 166.14 43.94 14.83 0.04 0.066 0.015 0.49 0.1 <0.1 <0.1 0.3 995 88.21 215.45 53.97 17.42 0.04 0.068 0.016 0.62 0.1 <0.1 <0.1 0.4 1022 89.74 297.69 69.69 21.27 0.03 0.072 0.017 0.77 0.1 0.1 0.1 0.6 1049 91.16 416.26 90.82 26.14 0.03 0.076 0.019 0.89 0.1 0.1 0.1 0.8 FBP 3511.28 487.79 96.01 0.02 0.150 0.033 5.06 4.3 0.5 0.6 10.0 <<>> TABLE 3 CALCULATED BLENDS Eagleford 40.1 API TEMP RANGE CUT RANGE VOLUME % API SPEC WGT % ABP SULFUR MERC RI ----------------- DEG F ------------------ DIE CI 90 SMK LUM NEUT DEG F DEG C VOLUME % YIELD MID GRAV GRAV YIELD F WGT% PPM 67 C ANIL POUR CLD FRZ IND IND MM NO. NO. 68/158 20/70 1.1/6.7 5.6 3.9 83.0 0.6596 4.5 68/185 20/85 1.1/9.1 8.0 5.1 78.8 0.6730 6.6 68/212 20/100 1.1/11.7 10.6 6.4 74.8 0.6858 8.8 68/248 20/120 1.1/15.3 14.3 8.2 70.1 0.7018 12.2 68/302 20/150 1.1/21.4 20.3 11.2 64.2 0.7231 17.8 68/374 20/190 1.1/30.4 29.3 15.7 58.4 0.7453 26.5 158/212 70/100 6.7/11.7 5.0 9.2 66.3 0.7152 4.3 185 0.0004 2 158/650 70/343 6.7/62.6 55.9 34.7 45.6 0.7992 54.3 404 0.0317 185/302 85/150 9.1/21.4 12.3 15.3 55.7 0.7559 11.3 244 0.0006 2 212/248 100/120 11.7/15.3 3.7 13.5 57.6 0.7483 3.3 230 0.0005 2 212/302 100/150 11.7/21.4 9.7 16.5 53.7 0.7639 9.0 257 0.0007 3 248/302 120/150 15.3/21.4 6.0 18.4 51.5 0.7733 5.7 275 0.0008 3 248/374 120/190 15.3/30.4 15.0 22.9 48.4 0.7866 14.4 311 0.0011 3 302/374 150/190 21.4/30.4 9.0 25.9 46.4 0.7956 8.7 338 0.0013 3 1.4209 134.2 -94 -87 -80 62 34 30 68 302/401 150/205 21.4/33.9 12.5 27.6 45.7 0.7985 12.1 352 0.0015 3 1.4224 136.7 -87 -79 -73 62 37 29 67 302/455 150/235 21.4/40.9 19.6 31.2 44.7 0.8031 19.1 379 0.0020 3 1.4253 141.7 -73 -63 -56 63 41 28 64 302/509 150/265 21.4/47.6 26.2 34.5 43.9 0.8070 25.7 406 0.0032 3 1.4281 146.7 -57 -46 -39 64 46 27 61 0.04 302/536 150/280 21.4/50.7 29.4 36.1 43.4 0.8089 28.9 419 0.0053 3 1.4295 149.2 -49 -37 -31 65 47 26 60 0.04 302/698 150/370 21.4/67.1 45.7 44.3 40.7 0.8217 45.7 500 0.0605 1.4368 163.1 -1 13 66 53 320/650 160/343 23.5/62.6 39.1 43.1 41.2 0.8193 38.9 485 0.0440 1.4357 161.1 -12 1 66 53 347/698 175/370 26.9/67.1 40.2 47.0 39.9 0.8257 40.4 523 0.0683 1.4391 166.9 4 17 67 55 0.06 0.06 0.07 374/482 190/250 30.4/44.3 14.0 37.4 42.9 0.8111 13.8 428 0.0031 3 1.4305 150.6 -52 -43 -36 65 48 26 59 0.04 374/536 190/280 30.4/50.7 20.4 40.6 42.2 0.8147 20.2 455 0.0070 4 1.4332 155.8 -37 -27 -21 66 52 25 56 0.05 401/509 205/265 33.9/47.6 13.7 40.8 42.2 0.8147 13.6 455 0.0047 4 1.4334 155.7 -40 -30 -24 66 52 25 56 0.05 401/650 205/343 33.9/62.6 28.8 48.3 39.8 0.8260 28.9 526 0.0588 1.4401 168.3 -1 10 67 58 428/536 220/280 37.4/50.7 13.3 44.1 41.4 0.8185 13.2 482 0.0095 4 1.4363 161.0 -27 -17 -11 67 56 23 53 0.06 509/590 265/310 47.6/56.6 9.0 52.1 39.0 0.8300 9.1 550 0.0610 1.4435 174.0 5 13 68 64 509/650 265/343 47.6/62.6 15.0 55.1 37.7 0.8362 15.3 580 0.1069 1.4463 179.2 19 27 68 66 536/650 280/343 50.7/62.6 11.9 56.7 37.1 0.8392 12.1 593 0.1287 1.4478 181.9 25 32 68 67 590/650 310/343 56.6/62.6 6.0 59.6 35.8 0.8456 6.2 620 0.1743 1.4505 186.9 36 42 67 70 590/698 310/370 56.6/67.1 10.5 61.9 34.7 0.8513 10.9 644 0.1955 1.4526 190.4 45 52 66 70 0.07 0.09 0.09 0.10 0.11 0.10 650/698 343/370 62.6/67.1 4.5 64.9 33.2 0.8590 4.7 674 0.2234 1.4553 194.9 56 62 65 72 650/752 343/400 62.6/71.9 9.2 67.3 32.2 0.8644 9.7 701 0.2378 1.4575 198.3 65 650/851 343/455 62.6/79.6 17.0 71.1 31.0 0.8706 18.0 751 0.2521 1.4611 204.7 77 650/1049 343/565 62.6/91.8 29.2 77.2 29.1 0.8810 31.3 850 0.2660 1.4677 218.0 93 752/851 400/455 71.9/79.6 7.8 75.7 29.7 0.8780 8.3 802 0.2688 1.4655 212.3 89 779/995 415/535 74.1/89.0 14.9 81.5 27.9 0.8878 16.1 887 0.2753 1.4717 228.1 101 851/950 455/510 79.6/86.3 6.7 83.0 27.5 0.8902 7.2 901 0.2744 1.4731 232.3 104 851/1049 455/565 79.6/91.8 12.2 85.7 26.5 0.8955 13.3 950 0.2847 1.4767 242.3 108 950/1049 510/565 86.3/91.8 5.5 89.1 25.4 0.9019 6.1 1000 0.2969 1.4812 254.3 114 995/1049 535/565 89.0/91.8 2.8 90.4 25.0 0.9044 3.1 1022 0.3066 1.4833 259.0 116 64 64 63 63 64 64 64 65 65 0.09 0.09 0.07 0.06 0.06 0.05 0.05 0.04 0.03 0.03 1049/FBP 565/FBP 91.8/100.0 8.2 21.7 0.9240 9.2 0.3714 46 0.02 995/FBP 535/FBP 89.0/100.0 11.0 22.5 0.9189 12.3 0.3550 56 950/FBP 510/FBP 86.3/100.0 13.7 23.1 0.9150 15.2 0.3417 64 851/FBP 455/FBP 79.6/100.0 20.4 24.5 0.9069 22.5 0.3201 72 752/FBP 400/FBP 71.9/100.0 28.2 25.9 0.8989 30.8 0.3063 77 698/FBP 370/FBP 67.1/100.0 32.9 26.7 0.8947 35.7 0.2986 79 650/FBP 343/FBP 62.6/100.0 37.4 27.4 0.8904 40.4 0.2899 81 563/FBP 295/FBP 53.7/100.0 46.3 29.1 0.8812 49.5 0.2646 84 428/FBP 220/FBP 37.4/100.0 62.6 32.0 0.8654 65.8 0.2038 93 0.02 0.03 0.03 0.04 0.05 0.05 0.06 0.06 <<>> TABLE 3A CALCULATED BLENDS Eagleford 40.1 API RANGE CUT RANGE ----------- VISCOSITY IN CENTISTOKES AT ------------- --------- VOLUME % --------- ----------------------- WEIGHT % -------------------- --------------- WEIGHT PPM ---------------- DEG F VOLUME % -30 F 100 F 150 F 210 F PARA NAPH AROM AR NR N2 BN2 CCAR FE NI V NA 68/158 1.1/6.7 68/185 1.1/9.1 68/212 1.1/11.7 68/248 1.1/15.3 68/302 1.1/21.4 68/374 1.1/30.4 158/212 6.7/11.7 60.2 34.7 5.2 158/650 6.7/62.6 51.8 34.0 14.1 185/302 9.1/21.4 55.1 32.4 12.6 212/248 11.7/15.3 55.1 33.5 11.4 212/302 11.7/21.4 54.9 30.7 14.4 248/302 15.3/21.4 54.7 29.0 16.3 248/374 15.3/30.4 53.6 29.3 17.1 302/374 21.4/30.4 2.87 0.92 0.71 0.55 52.9 29.5 17.7 13.6 19.1 302/401 21.4/33.9 3.32 0.99 0.76 0.58 49.8 34.1 16.1 12.0 21.6 302/455 21.4/40.9 4.57 1.16 0.86 0.65 48.2 36.4 15.4 10.9 23.5 302/509 21.4/47.6 6.43 1.35 0.98 0.73 48.9 35.7 15.4 10.9 22.9 302/536 21.4/50.7 7.67 1.47 1.05 0.77 49.4 35.5 15.1 10.6 22.6 302/698 21.4/67.1 2.33 1.53 1.05 10.1 20.8 320/650 23.5/62.6 2.14 1.43 1.00 14.9 9.8 21.3 347/698 26.9/67.1 2.69 1.71 1.15 9.5 21.2 374/482 30.4/44.3 8.46 1.52 1.08 0.79 45.8 40.1 14.1 9.4 25.8 374/536 30.4/50.7 12.55 1.80 1.24 0.88 47.9 38.1 13.9 9.2 24.1 401/509 33.9/47.6 12.64 1.80 1.24 0.88 48.1 37.2 14.8 9.9 24.1 401/650 33.9/62.6 2.83 1.77 1.18 14.7 9.3 21.0 428/536 26.9/50.7 19.67 2.15 1.43 0.99 51.1 34.3 14.6 9.8 21.9 0.000 0.000 509/590 47.6/56.6 3.54 2.10 1.35 13.2 8.0 19.1 0.002 0.000 509/650 47.6/62.6 4.44 2.50 1.55 8.7 18.3 0.005 0.001 536/650 50.7/62.6 5.02 2.75 1.66 8.9 17.9 0.006 0.001 590/650 56.6/62.6 6.42 3.32 1.92 9.6 17.3 0.010 0.002 590/698 56.6/67.1 7.80 3.86 2.16 10.1 17.3 0.017 0.003 650/698 62.6/67.1 10.25 4.78 2.55 10.7 17.4 0.027 0.004 <0.005 <0.1 <0.1 <0.1 <0.1 650/752 62.6/71.9 12.85 5.71 2.94 11.0 17.2 0.037 0.005 0.01 <0.1 <0.1 <0.1 <0.1 650/851 62.6/79.6 19.12 7.84 3.78 10.9 16.6 0.047 0.006 0.02 <0.1 <0.1 <0.1 <0.1 650/1049 62.6/91.8 40.57 14.25 6.08 11.1 15.3 0.055 0.009 0.20 <0.1 <0.1 <0.1 0.1 752/851 71.9/79.6 32.03 11.83 5.25 10.9 15.9 0.058 0.007 0.04 <0.1 <0.1 <0.1 <0.1 779/995 74.1/89.0 70.70 22.24 8.66 11.0 14.6 0.062 0.011 0.22 <0.1 <0.1 <0.1 0.1 851/950 79.6/86.3 86.08 26.06 9.83 11.0 14.3 0.061 0.012 0.22 <0.1 <0.1 <0.1 <0.1 851/1049 79.6/91.8 139.12 38.10 13.25 11.3 13.5 0.066 0.014 0.44 <0.1 <0.1 <0.1 0.3 950/1049 86.3/91.8 260.04 62.60 19.56 11.6 12.6 0.071 0.017 0.70 0.1 0.1 <0.1 0.5 995/1049 89.0/91.8 348.91 79.00 23.45 11.7 12.0 0.074 0.018 0.83 0.1 0.1 0.1 0.7 1049/FBP 91.8/100.0 3511.28 487.79 96.01 0.150 0.033 5.06 4.3 0.5 0.6 10.0 995/FBP 89.0/100.0 1827.97 290.94 64.30 0.131 0.029 3.99 3.3 0.4 0.4 7.7 950/FBP 86.3/100.0 1117.56 197.07 47.51 0.118 0.026 3.32 2.6 0.3 0.4 6.2 851/FBP 79.6/100.0 439.33 94.01 26.68 0.100 0.022 2.32 1.8 0.2 0.2 4.3 752/FBP 71.9/100.0 193.06 48.87 15.97 0.089 0.018 1.71 1.3 0.2 0.2 3.1 698/FBP 67.1/100.0 126.59 34.92 12.25 0.083 0.016 1.47 1.1 0.1 0.2 2.7 650/FBP 62.6/100.0 87.88 26.14 9.75 0.077 0.015 1.30 1.0 0.1 0.1 2.4 563/FBP 53.7/100.0 45.94 15.71 6.55 0.064 0.012 1.06 428/FBP 37.4/100.0 17.37 7.42 3.68 0.048 0.009 0.80 <<>> TABLE 4 GASOLINES & NAPHTHAS Eagleford 40.1 API 15/5 CUT POINTS DEG F VT 68/158 68/212 158/212 212/302 248/374 302/374 158/302 DEG C VT 20/70 20/100 70/100 100/150 120/190 150/190 70/150 YIELD CUT RANGE VOL % 1.1/6.7 1.1/11.7 6.7/11.7 11.7/21.4 15.3/30.4 21.4/30.4 6.7/21.4 YIELD ON CRUDE VOL % 5.6 10.6 5.0 9.7 15.0 9.0 14.7 MIDPOINT VOL % 3.9 6.4 9.2 16.5 22.9 25.9 14.1 GRAVITY API 83.0 74.8 66.3 53.7 48.4 46.4 57.8 SPECIFIC GRAVITY 60/60 0.6596 0.6858 0.7152 0.7639 0.7866 0.7956 0.7474 DENSITY AT 15 C KG/DM3 0.6592 0.6853 0.7146 0.7632 0.7859 0.7948 0.7467 TOTAL SULFUR WGT % 0.0004 0.0007 0.0011 0.0013 0.0006 MERCAPTAN SULFUR WGT PPM 2 3 3 3 2 REID VAPOR PRESSURE PSI 2.80 0.70 1.50 ANILINE POINT DEG F 134.2 RESEARCH OCTANE NUMBER CLEAR 70.1 62.3 53.3 46.2 42.8 41.8 48.0 PARAFFINS VOL % NAPHTHENES VOL % AROMATICS VOL % 60.2 54.9 53.6 52.9 56.7 34.7 30.7 29.3 29.5 32.1 5.2 14.4 17.1 17.7 11.3 CARBON WGT % 83.80 84.39 85.00 85.72 85.88 85.92 85.49 HYDROGEN WGT % 16.20 15.61 15.00 14.28 14.12 14.08 14.51 YIELD ON CRUDE WGT % 4.5 8.8 4.3 9.0 14.4 8.7 13.3 <<>> TABLE 5 HYDROCARBON ANALYSIS Eagleford 40.1 API 15/5 CUT POINT DEG F VT IBP TO 68 YIELD CUT RANGE VOL % 0.0 TO 1.1 YIELD CUT RANGE WT% 0.0 TO 0.8 15/5 CUT POINT DEG C VT IBP TO 20 YIELD ON CRUDE VOL % 1.10 YIELD ON CRUDE WT% 0.76 % ON CUT % ON CUT % ON CUT COMPONENT VOL WGT COMPONENT VOL WGT COMPONENT VOL WGT METHANE 0.00 0.00 ETHANE 0.15 0.10 PROPANE 16.95 15.14 ISOBUTANE 14.43 14.29 N-BUTANE 67.04 68.91 ISOPENTANE 1.42 1.56 N-PENTANE 0.00 0.00 CYCLOPENTANE 0.00 0.00 2,2-DIMETHYLBUTANE 0.00 0.00 2,3-DIMETHYLBUTANE 0.00 0.00 2-METHYLPENTANE 0.00 0.00 3-METHYLPENTANE 0.00 0.00 N-HEXANE 0.00 0.00 METHYLCYCLOPENTANE 0.00 0.00 BENZENE 0.00 0.00 CYCLOHEXANE 0.00 0.00 2,2-DIMETHYLPENTANE 0.00 0.00 2,4-DIMETHYLPENTANE 0.00 0.00 2,2,3-TRIMETHYLBUTANE 0.00 0.00 2-METHYLHEXANE 0.00 0.00 c+t-1,3-DiMe-Cyclopentanes 0.00 0.00 3-METHYLHEXANE 0.00 0.00 c+t-1,2-DiMe-Cyclopentanes 0.00 0.00 N-HEPTANE 0.00 0.00 METHYLCYCLOHEXANE 0.00 0.00 TOLUENE 0.00 0.00 VOL % CUT N-PARAFFINS ISOPARAFFINS TOTAL PARAFFINS CYCLOPENTANES CYCLOHEXANES TOTAL NAPHTHENES AROMATICS TOTAL C1 C2 C3 C4 C5 C6 C7 C8 C9 C10 C11 C12 C13 TOTAL 0.00 0.15 16.95 67.04 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 14.43 1.42 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.15 16.95 81.47 1.42 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.15 16.95 81.47 1.42 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 84.15 15.85 100.00 0.00 0.00 0.00 0.00 100.0 WGT % CUT N-PARAFFINS ISOPARAFFINS TOTAL PARAFFINS CYCLOPENTANES CYCLOHEXANES TOTAL NAPHTHENES AROMATICS TOTAL C1 C2 C3 C4 C5 C6 C7 C8 C9 C10 C11 C12 C13 TOTAL 0.00 0.10 15.14 68.91 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 14.29 1.56 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.10 15.14 83.20 1.56 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.10 15.14 83.20 1.56 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 84.15 15.85 100.00 0.00 0.00 0.00 0.00 100.0 GC component subset and carbon number data from simulating 15/5 tower cuts <<>> TABLE 6 HYDROCARBON ANALYSIS Eagleford 40.1 API 15/5 CUT POINT DEG F VT 68 TO 158 YIELD CUT RANGE VOL % 1.1 TO 6.7 YIELD CUT RANGE WT% 0.8 TO 5.3 15/5 CUT POINT DEG C VT 20 TO 70 YIELD ON CRUDE VOL % 5.61 YIELD ON CRUDE WT% 4.50 % ON CUT % ON CUT % ON CUT COMPONENT VOL WGT COMPONENT VOL WGT COMPONENT VOL WGT METHANE 0.00 0.00 ETHANE 0.00 0.00 PROPANE 0.00 0.00 ISOBUTANE 0.00 0.00 N-BUTANE 1.15 1.01 ISOPENTANE 13.86 13.01 N-PENTANE 23.56 22.33 CYCLOPENTANE 1.98 2.23 2,2-DIMETHYLBUTANE 0.32 0.32 2,3-DIMETHYLBUTANE 1.58 1.56 2-METHYLPENTANE 13.55 13.49 3-METHYLPENTANE 7.99 7.95 N-HEXANE 20.99 20.93 METHYLCYCLOPENTANE 6.41 7.26 BENZENE 1.46 1.94 CYCLOHEXANE 3.69 4.34 2,2-DIMETHYLPENTANE 0.20 0.21 2,4-DIMETHYLPENTANE 0.60 0.62 2,2,3-TRIMETHYLBUTANE 0.02 0.02 2-METHYLHEXANE 1.01 1.04 c+t-1,3-DiMe-Cyclopentanes 0.30 0.34 3-METHYLHEXANE 0.64 0.66 c+t-1,2-DiMe-Cyclopentanes 0.13 0.15 N-HEPTANE 0.00 0.00 METHYLCYCLOHEXANE 0.00 0.00 TOLUENE 0.00 0.00 VOL % CUT N-PARAFFINS ISOPARAFFINS TOTAL PARAFFINS CYCLOPENTANES CYCLOHEXANES TOTAL NAPHTHENES AROMATICS TOTAL C1 C2 C3 C4 C5 C6 C7 C8 C9 C10 C11 C12 C13 TOTAL 0.00 0.00 0.00 1.15 23.56 20.99 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 13.86 23.44 2.80 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.15 37.42 44.43 2.80 0.00 0.00 0.00 0.00 0.00 0.00 1.98 6.41 0.66 0.00 0.00 0.00 0.00 0.00 0.00 3.69 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.98 10.10 0.66 0.00 0.00 0.00 0.00 0.00 0.00 1.46 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.15 39.40 55.99 3.47 0.00 0.00 0.00 0.00 0.00 0.00 45.70 40.10 85.81 9.05 3.69 12.74 1.46 100.0 WGT % CRUDE N-PARAFFINS ISOPARAFFINS TOTAL PARAFFINS CYCLOPENTANES CYCLOHEXANES TOTAL NAPHTHENES AROMATICS TOTAL C1 C2 C3 C4 C5 C6 C7 C8 C9 C10 C11 C12 C13 TOTAL 0.00 0.00 0.00 1.01 22.33 20.93 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 13.01 23.31 2.90 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.01 35.34 44.25 2.90 0.00 0.00 0.00 0.00 0.00 0.00 2.23 7.26 0.75 0.00 0.00 0.00 0.00 0.00 0.00 4.34 0.00 0.00 0.00 0.00 0.00 0.00 0.00 2.23 11.60 0.75 0.00 0.00 0.00 0.00 0.00 0.00 1.94 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.01 37.57 57.78 3.65 0.00 0.00 0.00 0.00 0.00 0.00 44.27 39.22 83.49 10.24 4.34 14.58 1.94 100.0 GC component subset and carbon number data from simulating 15/5 tower cuts <<>> TABLE 7 HYDROCARBON ANALYSIS Eagleford 40.1 API 15/5 CUT POINT DEG F VT 158 TO 374 YIELD CUT RANGE VOL % 6.7 TO 30.4 YIELD CUT RANGE WT% 5.3 TO 27.3 15/5 CUT POINT DEG C VT 70 TO 190 YIELD ON CRUDE VOL % 23.66 YIELD ON CRUDE WT% 22.01 % ON CUT % ON CUT % ON CUT COMPONENT VOL WGT COMPONENT VOL WGT COMPONENT VOL WGT ETHANE 0.00 0.00 2,4-DIMETHYLHEXANE 0.53 0.49 C9 ISOPARAFFINS 8.02 7.64 PROPANE 0.00 0.00 TOLUENE 2.98 3.43 C9 NAPHTHENES 8.39 8.77 ISOBUTANE 0.00 0.00 2,3-DIMETHYLHEXANE 0.39 0.36 C9 CYCLOHEXANES 5.34 5.60 N-BUTANE 0.00 0.00 2-METHYLHEPTANE 2.83 2.63 C9 CYCLOPENTANES 2.51 2.55 ISOPENTANE 0.00 0.00 4-METHYLHEPTANE 0.98 0.91 N-NONANE 5.85 5.56 N-PENTANE 0.00 0.00 3,4-DIMETHYLHEXANE 0.04 0.04 ISOPROPYLBENZENE 0.20 0.23 CYCLOPENTANE 0.00 0.00 C8 NAPHTHENES 7.68 5.86 N-PROPYLBENZENE 0.33 0.38 2,2-DIMETHYLBUTANE 0.00 0.00 3-METHYLHEPTANE 1.82 1.69 C9 TRIMETHYL-PARAFFINS 0.41 0.39 2,3-DIMETHYLBUTANE 0.00 0.00 C+T-1,4-DIME-CYCLOHEXANES 0.79 0.83 C8 TRIMETHYL-PARAFFINS 0.25 0.23 2-METHYLPENTANE 0.00 0.00 1,1-DIMETHYLCYCLOHEXANE 0.27 0.28 1,2,3-TRIME-CYCLOHEXANES(MI) 0.30 0.32 3-METHYLPENTANE 0.06 0.05 C+T-1,3-DIME-CYCLOHEXANES 1.80 1.87 1,2,4-TRIME-CYCLOHEXANES(MI) 1.37 1.44 N-HEXANE 0.96 0.84 N-PROPYLCYCLOPENTANE 0.11 0.12 METHYLCYCLOPENTANE 0.53 0.52 ISOPROPYLCYCLOPENTANE 0.01 0.01 BENZENE 0.45 0.53 C+T-1-ME-3-ET-CYCLOPENTANES 0.14 0.15 CYCLOHEXANE 1.25 1.29 C+T-1-ME-2-ET-CYCLOPENTANES 0.22 0.22 2,2-DIMETHYLPENTANE 0.05 0.05 1-METHYL,1-ETHYLCYCLOPENTANE 0.06 0.06 2,4-DIMETHYLPENTANE 0.20 0.18 C+T-1,2-DIME-CYCLOHEXANES 1.01 1.05 2,2,3-TRIMETHYLBUTANE 0.01 0.00 N-OCTANE 6.22 5.79 3,3-DIMETHYLPENTANE 0.04 0.04 ETHYLCYCLOHEXANE 1.76 1.83 1,1-DIMETHYLCYCLOPENTANE 0.26 0.26 2,2-DIMETHYLHEPTANE 0.14 0.13 2-METHYLHEXANE 2.00 1.81 2,6-DIMETHYLHEPTANE 1.28 1.21 C+T-1,3-DIME-CYCLOPENTANES 0.82 0.81 ETHYLBENZENE 0.73 0.84 3-METHYLHEXANE 2.20 2.00 3,3-DIMETHYLHEPTANE 0.17 0.17 C+T-1,2-DIME-CYCLOPENTANES 0.81 0.81 PARAXYLENE 0.79 0.91 N-HEPTANE 6.53 5.92 METAXYLENE 2.23 2.56 METHYLCYCLOHEXANE 4.81 4.91 2,3-DIMETHYLHEPTANE 1.16 1.10 ETHYLCYCLOPENTANE 0.17 0.17 3,4-DIMETHYLHEPTANE 0.02 0.02 1,1,2-TRIMETHYLCYCLOPENTANE 0.16 0.15 4-METHYLOCTANE 1.00 0.95 1,1,3-TRIMETHYLCYCLOPENTANE 0.43 0.42 2-METHYLOCTANE 1.10 1.05 2,2-DIMETHYLHEXANE 0.06 0.06 3-METHYLOCTANE 1.48 1.40 2,5-DIMETHYLHEXANE 0.34 0.32 ORTHOXYLENE 1.35 1.55 VOL % CUT N-PARAFFINS ISOPARAFFINS TOTAL PARAFFINS CYCLOPENTANES CYCLOHEXANES TOTAL NAPHTHENES AROMATICS TOTAL C1 C2 C3 C4 C5 C6 C7 C8 C9 C10 C11 C12 C13 TOTAL 23.97 30.71 8.95 20.92 30.84 14.48 0.00 0.00 0.00 0.00 0.00 0.96 6.53 6.22 5.85 4.14 0.27 0.00 0.00 0.00 0.00 0.06 5.02 7.37 8.02 8.02 2.23 0.00 0.00 0.00 0.00 0.00 0.00 0.00 1.01 11.55 13.59 13.88 12.16 2.50 0.00 0.00 54.69 0.00 0.53 2.06 2.05 2.51 1.57 0.24 0.01 0.00 1.25 4.81 5.63 5.34 3.36 0.50 0.01 0.00 0.00 1.78 6.87 7.68 8.39 5.34 0.76 0.02 0.00 0.45 2.98 5.10 5.02 0.91 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 3.25 21.41 26.36 27.29 18.40 3.27 0.02 0.00 100.0 WGT % CUT N-PARAFFINS ISOPARAFFINS TOTAL PARAFFINS CYCLOPENTANES CYCLOHEXANES TOTAL NAPHTHENES AROMATICS TOTAL C1 C2 C3 C4 C5 C6 C7 C8 C9 C10 C11 C12 C13 TOTAL 22.38 29.09 9.06 21.74 31.91 16.63 0.00 0.00 0.00 0.00 0.00 0.84 5.92 5.79 5.56 4.00 0.27 0.00 0.00 0.00 0.00 0.05 4.55 6.86 7.64 7.79 2.20 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.89 10.47 12.65 13.20 11.79 2.47 0.00 0.00 51.46 0.00 0.52 2.05 2.04 2.55 1.63 0.25 0.01 0.00 1.29 4.91 5.86 5.60 3.53 0.53 0.01 0.00 0.00 1.82 6.97 7.90 8.77 5.63 0.81 0.02 0.00 0.53 3.43 5.86 5.77 1.04 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.00 3.23 20.86 26.40 27.74 18.46 3.30 0.02 0.00 100.0 GC component subset and carbon number data from simulating 15/5 tower cuts <<>> TABLE 8 HYDROCARBON ANALYSIS Eagleford 40.1 API 15/5 CUT POINT DEG F VT IBP TO 374 YIELD CUT RANGE VOL % 0.0 TO 30.4 YIELD CUT RANGE WT% 0.0 TO 18.6 15/5 CUT POINT DEG C VT IBP TO 190 YIELD ON CRUDE VOL % 30.36 YIELD ON CRUDE WT% 27.26 % ON CUT % ON CUT % ON CUT COMPONENT VOL WGT COMPONENT VOL WGT COMPONENT VOL WGT ETHANE 0.01 0.00 2,4-DIMETHYLHEXANE 0.41 0.39 C9 ISOPARAFFINS 6.25 6.15 PROPANE 0.61 0.42 TOLUENE 2.32 2.76 C9 NAPHTHENES 6.54 7.06 ISOBUTANE 0.523 0.401 2,3-DIMETHYLHEXANE 0.302 0.291 C9 CYCLOHEXANES 4.165 4.512 N-BUTANE 2.642 2.101 2-METHYLHEPTANE 2.207 2.119 C9 CYCLOPENTANES 1.954 2.055 ISOPENTANE 2.617 2.224 4-METHYLHEPTANE 0.762 0.732 N-NONANE 4.562 4.479 N-PENTANE 4.362 3.744 3,4-DIMETHYLHEXANE 0.030 0.029 ISOPROPYLBENZENE 0.158 0.187 CYCLOPENTANE 0.366 0.373 C8 NAPHTHENES 5.983 6.358 N-PROPYLBENZENE 0.260 0.307 2,2-DIMETHYLBUTANE 0.059 0.053 3-METHYLHEPTANE 1.421 1.421 C9 TRIMETHYL-PARAFFINS 0.317 0.316 2,3-DIMETHYLBUTANE 0.292 0.261 C+T-1,4-DIME-CYCLOHEXANES 0.620 0.620 C8 TRIMETHYL-PARAFFINS 0.192 0.188 2-METHYLPENTANE 2.509 2.261 1,1-DIMETHYLCYCLOHEXANE 0.209 0.209 1,2,3-TRIME-CYCLOHEXANES(MI) 0.235 0.255 3-METHYLPENTANE 1.522 1.371 C+T-1,3-DIME-CYCLOHEXANES 1.401 1.401 1,2,4-TRIME-CYCLOHEXANES(MI) 1.068 1.158 N-HEXANE 4.632 4.184 N-PROPYLCYCLOPENTANE 0.089 0.089 METHYLCYCLOPENTANE 1.598 1.638 ISOPROPYLCYCLOPENTANE 0.011 0.011 BENZENE 0.621 0.747 C+T-1-ME-3-ET-CYCLOPENTANES 0.112 0.112 CYCLOHEXANE 1.660 1.769 C+T-1-ME-2-ET-CYCLOPENTANES 0.174 0.174 2,2-DIMETHYLPENTANE 0.079 0.074 1-METHYL,1-ETHYLCYCLOPENTANE 0.047 0.047 2,4-DIMETHYLPENTANE 0.264 0.248 C+T-1,2-DIME-CYCLOHEXANES 0.786 0.786 2,2,3-TRIMETHYLBUTANE 0.007 0.007 N-OCTANE 4.848 4.848 3,3-DIMETHYLPENTANE 0.042 0.040 ETHYLCYCLOHEXANE 1.371 1.371 1,1-DIMETHYLCYCLOPENTANE 0.248 0.255 2,2-DIMETHYLHEPTANE 0.109 0.109 2-METHYLHEXANE 1.742 1.629 2,6-DIMETHYLHEPTANE 0.995 0.995 C+T-1,3-DIME-CYCLOPENTANES 0.691 0.712 ETHYLBENZENE 0.570 0.570 3-METHYLHEXANE 1.836 1.717 3,3-DIMETHYLHEPTANE 0.136 0.136 C+T-1,2-DIME-CYCLOPENTANES 0.657 0.676 PARAXYLENE 0.618 0.618 N-HEPTANE 5.088 4.763 METAXYLENE 1.736 1.736 METHYLCYCLOHEXANE 3.751 3.954 2,3-DIMETHYLHEPTANE 0.902 0.902 ETHYLCYCLOPENTANE 0.130 0.137 3,4-DIMETHYLHEPTANE 0.013 0.013 1,1,2-TRIMETHYLCYCLOPENTANE 0.122 0.124 4-METHYLOCTANE 0.782 0.782 1,1,3-TRIMETHYLCYCLOPENTANE 0.334 0.341 2-METHYLOCTANE 0.860 0.860 2,2-DIMETHYLHEXANE 0.048 0.046 3-METHYLOCTANE 1.150 1.150 2,5-DIMETHYLHEXANE 0.267 0.258 ORTHOXYLENE 1.051 1.051 VOL % CUT N-PARAFFINS ISOPARAFFINS TOTAL PARAFFINS CYCLOPENTANES CYCLOHEXANES TOTAL NAPHTHENES AROMATICS TOTAL C1 C2 C3 C4 C5 C6 C7 C8 C9 C10 C11 C12 C13 TOTAL 30.18 31.91 62.09 8.64 16.97 26.36 11.54 0.00 0.01 0.61 2.64 4.36 4.63 5.09 4.85 4.56 3.22 0.20 0.00 0.00 0.52 2.62 4.38 4.44 5.74 6.25 6.24 1.72 0.00 0.00 0.00 0.01 0.61 3.17 6.98 9.01 9.52 10.59 10.82 9.46 1.92 0.00 0.00 0.37 1.60 1.73 1.60 1.95 1.22 0.18 0.01 0.00 1.66 3.75 4.39 4.16 2.61 0.39 0.01 0.00 0.37 3.26 5.48 5.98 6.54 4.14 0.59 0.01 0.00 0.62 2.32 3.98 3.91 0.70 0.01 0.00 0.00 0.00 0.01 0.61 3.17 7.34 12.89 17.32 20.55 21.26 14.31 2.52 0.01 0.00 100.0 WGT % CUT N-PARAFFINS ISOPARAFFINS TOTAL PARAFFINS CYCLOPENTANES CYCLOHEXANES TOTAL NAPHTHENES AROMATICS TOTAL C1 C2 C3 C4 C5 C6 C7 C8 C9 C10 C11 C12 C13 TOTAL 27.78 30.41 58.20 9.00 18.21 28.10 13.70 0.00 0.00 0.42 2.10 3.74 4.18 4.76 4.66 4.48 3.22 0.21 0.00 0.00 0.40 2.22 3.95 4.15 5.52 6.15 6.27 1.76 0.00 0.00 0.00 0.00 0.42 2.50 5.97 8.13 8.91 10.18 10.63 9.48 1.96 0.00 0.00 0.37 1.64 1.78 1.64 2.05 1.31 0.20 0.01 0.00 1.77 3.95 4.72 4.51 2.83 0.42 0.01 0.00 0.37 3.41 5.73 6.36 7.06 4.51 0.64 0.02 0.00 0.75 2.76 4.71 4.64 0.83 0.01 0.00 0.00 0.00 0.00 0.42 2.50 6.34 12.29 17.40 21.25 22.33 14.82 2.62 0.02 0.00 100.0 GC component subset and carbon number data from simulating 15/5 tower cuts <<>> TABLE 9 HYDROCARBON ANALYSIS Eagleford 40.1 API 15/5 CUT POINT DEG F VT IBP TO 428 YIELD CUT RANGE VOL % 0.0 TO 37.4 YIELD CUT RANGE WT% 0.0 TO 34.2 15/5 CUT POINT DEG C VT IBP TO 220 YIELD ON CRUDE VOL % 37.44 YIELD ON CRUDE WT% 34.21 % ON CUT % ON CUT % ON CUT COMPONENT VOL WGT COMPONENT VOL WGT COMPONENT VOL WGT ETHANE 0.00 0.00 2,4-DIMETHYLHEXANE 0.33 0.32 C9 ISOPARAFFINS 5.07 4.91 PROPANE 0.50 0.34 TOLUENE 1.89 2.20 C9 NAPHTHENES 5.30 5.63 ISOBUTANE 0.42 0.32 2,3-DIMETHYLHEXANE 0.24 0.23 C9 CYCLOHEXANES 3.38 3.60 N-BUTANE 2.14 1.68 2-METHYLHEPTANE 1.79 1.69 C9 CYCLOPENTANES 1.58 1.64 ISOPENTANE 2.12 1.77 4-METHYLHEPTANE 0.62 0.58 N-NONANE 3.70 3.57 N-PENTANE 3.54 2.99 3,4-DIMETHYLHEXANE 0.02 0.02 ISOPROPYLBENZENE 0.13 0.15 CYCLOPENTANE 0.30 0.30 C8 NAPHTHENES 4.85 5.07 N-PROPYLBENZENE 0.21 0.24 2,2-DIMETHYLBUTANE 0.05 0.04 3-METHYLHEPTANE 1.15 1.09 C9 TRIMETHYL-PARAFFINS 0.26 0.25 2,3-DIMETHYLBUTANE 0.24 0.21 C+T-1,4-DIME-CYCLOHEXANES 0.50 0.53 C8 TRIMETHYL-PARAFFINS 0.16 0.15 2-METHYLPENTANE 2.03 1.80 1,1-DIMETHYLCYCLOHEXANE 0.17 0.18 1,2,3-TRIME-CYCLOHEXANES(MI) 0.19 0.20 3-METHYLPENTANE 1.23 1.09 C+T-1,3-DIME-CYCLOHEXANES 1.14 1.20 1,2,4-TRIME-CYCLOHEXANES(MI) 0.87 0.92 N-HEXANE 3.76 3.34 N-PROPYLCYCLOPENTANE 0.07 0.07 METHYLCYCLOPENTANE 1.30 1.31 ISOPROPYLCYCLOPENTANE 0.01 0.01 BENZENE 0.50 0.60 C+T-1-ME-3-ET-CYCLOPENTANES 0.09 0.09 CYCLOHEXANE 1.35 1.41 C+T-1-ME-2-ET-CYCLOPENTANES 0.14 0.14 2,2-DIMETHYLPENTANE 0.06 0.06 1-METHYL,1-ETHYLCYCLOPENTANE 0.04 0.04 2,4-DIMETHYLPENTANE 0.21 0.20 C+T-1,2-DIME-CYCLOHEXANES 0.64 0.67 2,2,3-TRIMETHYLBUTANE 0.01 0.01 N-OCTANE 3.93 3.72 3,3-DIMETHYLPENTANE 0.03 0.03 ETHYLCYCLOHEXANE 1.11 1.18 1,1-DIMETHYLCYCLOPENTANE 0.20 0.20 2,2-DIMETHYLHEPTANE 0.09 0.09 2-METHYLHEXANE 1.41 1.30 2,6-DIMETHYLHEPTANE 0.81 0.78 C+T-1,3-DIME-CYCLOPENTANES 0.56 0.57 ETHYLBENZENE 0.46 0.54 3-METHYLHEXANE 1.49 1.37 3,3-DIMETHYLHEPTANE 0.11 0.11 C+T-1,2-DIME-CYCLOPENTANES 0.53 0.54 PARAXYLENE 0.50 0.58 N-HEPTANE 4.13 3.80 METAXYLENE 1.41 1.64 METHYLCYCLOHEXANE 3.04 3.16 2,3-DIMETHYLHEPTANE 0.73 0.71 ETHYLCYCLOPENTANE 0.11 0.11 3,4-DIMETHYLHEPTANE 0.01 0.01 1,1,2-TRIMETHYLCYCLOPENTANE 0.10 0.10 4-METHYLOCTANE 0.63 0.61 1,1,3-TRIMETHYLCYCLOPENTANE 0.27 0.27 2-METHYLOCTANE 0.70 0.67 2,2-DIMETHYLHEXANE 0.04 0.04 3-METHYLOCTANE 0.93 0.90 2,5-DIMETHYLHEXANE 0.22 0.21 ORTHOXYLENE 0.85 0.99 VOL % CUT N-PARAFFINS ISOPARAFFINS TOTAL PARAFFINS CYCLOPENTANES CYCLOHEXANES TOTAL NAPHTHENES AROMATICS TOTAL C1 C2 C3 C4 C5 C6 C7 C8 C9 C10 C11 C12 C13 TOTAL 28.85 29.72 58.56 9.13 18.14 29.65 11.79 0.00 0.00 0.50 2.14 3.54 3.76 4.13 3.93 3.70 3.23 2.37 1.55 0.00 0.42 2.12 3.55 3.60 4.65 5.07 5.11 3.38 1.51 0.30 0.00 0.00 0.50 2.57 5.66 7.31 7.72 8.59 8.77 8.35 5.75 3.06 0.30 0.30 1.30 1.40 1.29 1.58 1.13 0.90 1.22 0.00 1.35 3.04 3.56 3.38 2.48 1.99 2.27 0.08 0.30 2.64 4.44 4.85 5.30 4.51 3.52 3.94 0.14 0.50 1.89 3.22 3.36 1.40 1.09 0.33 0.00 0.00 0.00 0.50 2.57 5.96 10.45 14.05 16.66 17.43 14.25 10.36 7.33 0.44 100.0 WGT % CUT N-PARAFFINS ISOPARAFFINS TOTAL PARAFFINS CYCLOPENTANES CYCLOHEXANES TOTAL NAPHTHENES AROMATICS TOTAL C1 C2 C3 C4 C5 C6 C7 C8 C9 C10 C11 C12 C13 TOTAL 26.55 28.16 54.71 9.47 19.26 31.50 13.79 0.00 0.00 0.34 1.68 2.99 3.34 3.80 3.72 3.57 3.18 2.37 1.57 0.00 0.32 1.77 3.15 3.31 4.40 4.91 5.05 3.40 1.54 0.30 0.00 0.00 0.34 2.00 4.76 6.49 7.11 8.12 8.48 8.22 5.77 3.11 0.30 0.30 1.31 1.42 1.31 1.64 1.20 0.97 1.33 0.00 1.41 3.16 3.77 3.60 2.64 2.13 2.46 0.09 0.30 2.72 4.58 5.07 5.63 4.90 3.84 4.31 0.16 0.60 2.20 3.76 3.92 1.64 1.28 0.39 0.00 0.00 0.00 0.34 2.00 5.06 9.80 13.89 16.96 18.03 14.77 10.88 7.80 0.47 100.0 GC component subset and carbon number data from simulating 15/5 tower cuts <<>> TABLE 10 KEROSINES Eagleford 40.1 API 15/5 CUT POINTS DEG F VT 302/401 302/455 302/509 374/482 374/536 302/428 DEG C VT 150/205 150/235 150/265 190/250 190/280 150/220 YIELD CUT RANGE VOL % 21.4/33.9 21.4/40.9 21.4/47.6 30.4/44.3 30.4/50.7 21.4/37.4 YIELD ON CRUDE VOL % 12.5 19.6 26.2 14.0 20.4 16.1 MIDPOINT VOL % 27.6 31.2 34.5 37.4 40.6 29.4 GRAVITY API 45.7 44.7 43.9 42.9 42.2 45.2 SPECIFIC GRAVITY 60/60 0.7985 0.8031 0.8070 0.8111 0.8147 0.8009 DENSITY AT 15 C KG/DM3 0.7977 0.8023 0.8062 0.8103 0.8139 0.8002 TOTAL SULFUR WGT % 0.002 0.002 0.003 0.003 0.007 0.002 MERCAPTAN SULFUR WGT PPM 3 3 3 3 4 3 SMOKE POINT MM 29.1 27.9 26.7 25.8 24.7 28.5 LUMINOMETER NUMBER 67.0 64.0 61.0 59.0 56.0 65.0 FREEZE POINT DEG F -73 -56 -39 -36 -21 -65 CLOUD POINT DEG F -79 -63 -46 -43 -27 -71 POUR POINT DEG F -87 -73 -57 -52 -37 -80 ANILINE POINT DEG F 136.7 141.7 146.7 150.6 155.8 139.3 DIESEL INDEX 62 63 64 65 66 63 NEUT. NO. MG/GM 0.04 0.04 0.05 REFRACTIVE INDEX 67 DEG C 1.4224 1.4253 1.4281 1.4305 1.4332 1.4239 NAPHTHALENES VOL % 2.00 VISC @ -30 F/-34.4 C CST 3.32 4.57 6.43 8.46 12.55 3.88 VISC @ 100 F/37.8 C CST 0.99 1.16 1.35 1.52 1.80 1.07 VISC @ 104 F/40.0 C CST 0.97 1.13 1.32 1.48 1.74 1.04 VISC @ 140 F/60.0 C CST 0.79 0.91 1.04 1.15 1.33 0.85 VISC @ 210 F/98.9 C CST 0.58 0.65 0.73 0.79 0.88 0.61 VISC @ 212 F/100.0 C CST 0.58 0.64 0.72 0.78 0.87 0.61 PARAFFINS VOL % 49.8 48.2 48.9 45.8 47.9 48.0 NAPHTHENES VOL % 34.1 36.4 35.7 40.1 38.1 36.5 AROMATICS VOL % 16.1 15.4 15.4 14.1 13.9 15.5 CARBON WGT % 85.89 85.93 85.99 86.00 86.01 85.91 HYDROGEN WGT % 14.11 14.07 14.01 13.99 13.98 14.09 YIELD ON CRUDE WGT % 12.1 19.1 25.7 13.8 20.2 15.6 <<>> TABLE 11 MIDDLE DISTILLATES Eagleford 40.1 API 15/5 CUT POINTS DEG F VT 401/509 509/590 590/650 590/698 320/650 401/650 302/698 158/650 DEG C VT 205/265 265/310 310/343 310/370 160/343 205/343 150/370 70/343 YIELD CUT RANGE VOL % 33.9/47.6 47.6/56.6 56.6/62.6 56.6/67.1 23.5/62.6 33.9/62.6 21.4/67.1 6.7/62.6 YIELD ON CRUDE VOL % 13.7 9.0 6.0 10.5 39.1 28.8 45.7 55.9 MIDPOINT VOL % 40.8 52.1 59.6 61.9 43.1 48.3 44.3 34.7 GRAVITY API 42.2 39.0 35.8 34.7 41.2 39.8 40.7 45.6 SPECIFIC GRAVITY 60/60 0.8147 0.8300 0.8456 0.8513 0.8193 0.8260 0.8217 0.7992 DENSITY AT 15 C KG/DM3 0.8139 0.8291 0.8447 0.8504 0.8184 0.8251 0.8209 0.7984 TOTAL SULFUR WGT % 0.0047 0.0610 0.1743 0.1955 0.0440 0.0588 0.0605 0.0317 DIESEL INDEX ANILINE POINT DEG F 155.7 174.0 186.9 190.4 161.1 168.3 163.1 65.7 67.8 67.0 66.1 66.4 67.0 66.4 CETANE INDEX (90) 52.1 64.1 70.0 70.1 53.1 58.2 53.1 CLOUD POINT DEG F -30 13 42 52 1 10 13 POUR POINT DEG F -40 5 36 45 -12 -1 -1 REFRACTIVE INDEX 67 DEG C 1.4334 1.4435 1.4505 1.4526 1.4357 1.4401 1.4368 NEUT. NO. MG/GM 0.05 0.09 0.11 0.10 0.06 0.07 0.06 0.05 A. RINGS N. RINGS VISC @ 100 F/37.8 C CST 1.80 3.54 6.42 7.80 2.14 2.83 2.33 VISC @ 104 F/40.0 C CST 1.74 3.37 6.03 7.30 2.06 2.71 2.24 VISC @ 140 F/60.0 C CST 1.33 2.30 3.72 4.36 1.54 1.92 1.65 VISC @ 150 F/65.6 C CST 1.24 2.10 3.32 3.86 1.43 1.77 1.53 VISC @ 175 F/79.4 C CST 1.06 1.72 2.58 2.95 1.22 1.48 1.29 VISC @ 210 F/98.9 C CST 0.88 1.35 1.92 2.16 1.00 1.18 1.05 VISC @ 212 F/100.0 C CST 0.87 1.33 1.89 2.13 0.99 1.17 1.04 6.2 6.5 5.7 5.3 6.0 6.1 5.8 23.0 20.8 21.6 22.3 22.7 21.8 22.6 NITROGEN WGT % 0.0020 0.0100 0.0170 YIELD ON CRUDE WGT % 13.6 9.1 6.2 10.9 38.9 28.9 45.7 54.3 <<>> TABLE 12 GAS OILS Eagleford 40.1 API 15/5 CUT POINTS DEG F VT 650/752 752/851 851/950 950/1049 650/851 650/1049 851/1049 995/1049 DEG C VT 343/400 400/455 455/510 510/565 343/455 343/565 455/565 535/565 YIELD CUT RANGE VOL % 62.6/71.9 71.9/79.6 79.6/86.3 86.3/91.8 62.6/79.6 62.6/91.8 79.6/91.8 89.0/91.8 YIELD ON CRUDE VOL % 9.2 7.8 6.7 5.5 17.0 29.2 12.2 2.8 MIDPOINT VOL % 67.3 75.7 83.0 89.1 71.1 77.2 85.7 90.4 GRAVITY API 32.2 29.7 27.5 25.4 31.0 29.1 26.5 25.0 SPECIFIC GRAVITY 60/60 0.8644 0.8780 0.8902 0.9019 0.8706 0.8810 0.8955 0.9044 DENSITY AT 15 C KG/DM3 0.8635 0.8771 0.8893 0.9009 0.8697 0.8801 0.8945 0.9034 TOTAL SULFUR WGT % 0.2378 0.2688 0.2744 0.2969 0.2521 0.2660 0.2847 0.3066 ANILINE POINT DEG F 198.3 212.3 232.3 254.3 204.7 218.0 242.3 259.0 CON CARBON WGT % 0.01 0.04 0.22 0.70 0.02 0.20 0.44 0.83 POUR POINT DEG F 65 89 104 114 77 93 108 116 REFRACTIVE INDEX 67 DEG C 1.4575 1.4655 1.4731 1.4812 1.4611 1.4677 1.4767 1.4833 NEUT. NO. MG/GM 0.09 0.06 0.05 0.03 0.07 0.06 0.04 0.03 NITROGEN WGT % 0.037 0.058 0.061 0.071 0.047 0.055 0.066 0.074 VISC @ 100 F/37.8 C CST 12.85 32.03 86.08 260.04 19.12 40.57 139.12 348.91 VISC @ 104 F/40.0 C CST 11.90 29.14 76.85 227.26 17.57 36.73 123.05 303.18 VISC @ 140 F/60.0 C CST 6.56 14.03 31.98 79.94 9.13 17.05 47.58 101.95 VISC @ 150 F/65.6 C CST 5.71 11.83 26.06 62.60 7.84 14.25 38.10 79.00 VISC @ 175 F/79.4 C CST 4.19 8.11 16.56 36.43 5.59 9.59 23.30 44.89 VISC @ 210 F/98.9 C CST 2.94 5.25 9.83 19.56 3.78 6.08 13.25 23.45 VISC @ 212 F/100.0 C CST 2.88 5.13 9.58 18.95 3.71 5.94 12.87 22.69 BASIC NITROGEN WGT % 0.0050 0.0070 0.0120 0.0170 0.0060 0.0090 0.0140 0.0180 VANADIUM WGT PPM <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 0.1 NICKEL WGT PPM <0.1 <0.1 <0.1 0.1 <0.1 <0.1 <0.1 0.1 IRON WGT PPM <0.1 <0.1 <0.1 0.1 <0.1 <0.1 <0.1 0.1 A. RINGS N. RINGS 4.2 4.0 4.0 4.7 4.1 4.1 4.3 5.0 24.0 24.7 26.6 29.8 24.1 24.9 27.9 30.7 YIELD ON CRUDE WGT % 9.7 8.3 7.2 6.1 18.0 31.3 13.3 3.1 <<>> TABLE 13 RESIDUA Eagleford 40.1 API 15/5 CUT POINTS DEG F VT 650/FBP 698/FBP 752/FBP 851/FBP 950/FBP 995/FBP 1049/FBP DEG C VT 343/FBP 370/FBP 400/FBP 455/FBP 510/FBP 535/FBP 565/FBP YIELD ON CRUDE VOL % 37.4 32.9 28.2 20.4 13.7 11.0 8.2 GRAVITY API 27.4 26.7 25.9 24.5 23.1 22.5 21.7 SPECIFIC GRAVITY 60/60 0.8904 0.8947 0.8989 0.9069 0.9150 0.9189 0.9240 DENSITY AT 15 C KG/DM3 0.8895 0.8938 0.8980 0.9059 0.9140 0.9179 0.9229 TOTAL SULFUR WGT % 0.29 0.30 0.31 0.32 0.34 0.36 0.37 CON CARBON WGT % 1.30 1.47 1.71 2.32 3.32 3.99 5.06 NITROGEN WGT % 0.077 0.083 0.089 0.100 0.118 0.131 0.150 BASIC NITROGEN WGT % 0.0150 0.0160 0.0180 0.0220 0.0260 0.0290 0.0330 NEUT. NO. MG/GM 0.05 0.05 0.04 0.03 0.03 0.02 0.02 POUR POINT DEG F 81 79 77 72 64 56 46 VISC @ 100 F/37.8 C CST 87.88 126.59 193.06 439.33 1117.56 1827.97 3511.28 VISC @ 104 F/40.0 C CST 78.32 112.02 169.48 379.7 948.73 1537.18 2915.84 VISC @ 140 F/60.0 C CST 32.17 43.53 61.85 122.5 265.62 399.26 685.55 VISC @ 150 F/65.6 C CST 26.14 34.92 48.87 94.01 197.07 290.94 487.79 VISC @ 175 F/79.4 C CST 16.52 21.44 29.03 52.31 101.66 144.17 229.12 VISC @ 210 F/98.9 C CST 9.75 12.25 15.97 26.68 47.51 64.3 96.01 VISC @ 212 F/100.0 C CST 9.5 11.91 15.5 25.8 45.73 61.75 91.91 VISC @ 275 F/135 C CST 4.75 5.7 7.05 10.64 16.82 21.35 29.27 ABS. VISC @ 140 F POISES 1.59 1.95 2.5 4.1 7.37 10.16 15.83 SOFTENING POINT DEG F -26.6 -16.7 -6. 12.6 30.7 39.2 49.7 PEN. @ 77 F / 25 C MM >400 >400 >400 >400 >400 >400 >400 PEN. @ 39 F / 4 C MM >400 >400 >400 >400 >400 >400 >400 SODIUM WGT PPM 2.4 2.7 3.1 4.3 6.2 7.7 10.0 VANADIUM WGT PPM 0.1 0.2 0.2 0.2 0.4 0.4 0.6 NICKEL WGT PPM 0.1 0.1 0.2 0.2 0.3 0.4 0.5 IRON WGT PPM 1.0 1.1 1.3 1.8 2.6 3.3 4.3 MNI WGT % 0.10 0.10 0.10 0.20 0.20 0.30 0.40 NHI WGT % 0.10 0.10 0.10 YIELD ON CRUDE WGT % 40.4 35.7 30.8 22.5 15.2 12.3 9.2 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 6C ENHANCECO REPORT <<>> EnhanceCo Consulting Services Monitoring Equipment September 7, 2011 Mr. Rick Wooldridge Manager Asset Integrity Magellan Midstream Partners, LP Dear Sir: EnhanceCo has been asked to review the potential for internal corrosion on the Longhorn Pipeline that will be reversed and bring West Texas Intermediate Crude from Crane, Texas, to the Gulf Coast. The operating conditions provided include (see Intertek Reports of Analysis # 076-001/002): Line Diameter of 18"* Estimated volume of 135,000 bbl/day API gravity of 31/40 BS&W content of .05/.05 % Hydrogen Sulfide (HoS) : 10/<1 ppm Ambient temperature ANSI 600 pressure, estimated at 1000 psi Factors influencing corrosion rates with these conditions would include: Flow velocity of 4.95 ft/second Flow regime: agitated pool (expect some water accumulation at low points) Water volume based on 1% BS&W = 1350 bbl/day Water volume based on .05% BS&W = 67.5 bbl/day Early corrosion studies of West Texas Sour Crude indicated raw corrosion rates in the range of 30 MPY (see attached graph). If more specific raw and protected corrosion rates are desired, laboratory tests of specific samples of crude can be conducted. With proper evaluation and selection of corrosion inhibitor products, a minimum of 90% protection from raw corrosion rates should be expected at or near a rate of 3 MPY. As this rate is still above normally accepted protection in pipelines, additional protection in the form of aggressive pigging should be used. This will not only remove accumulated water but also any solids that may contribute to under-deposit corrosion and/or bacterial corrosion. An aggressive monitoring program will be needed, with corrosion coupons mounted at the 6 o'clock position, analysis of any liquids or solids from the pigging process, and periodic corrosion inhibitor residuals. 2714 Cypress Point Drive, Suite E Missouri City, TX 77459 Telephone: 281-499-4426 Fax: 281-261-5617 e-mail: rust@enhanceco.net web: www.enhanceco.net <<>> EnhanceCo Consulting Services Monitoring Equipment The attached graph shows corrosion rates of West Texas Crude with and without corrosion inhibitor, as well as the effect of Oxygen on corrosion rates. For pipeline applications this may introduced in the loading and unloading of product). only be important when crude is delivered to terminals by truck (where air is most likely Rick, please call with questions or comments. Tom Pickthall Thomas W. Pickthall EnhanceCo, Inc. Corrosion Rates (West Texas Sour Crude) Dr. Sheldon Evans, Conoco Inc. 300 250 200 MPY 150 100 50 No Air/No Inhibitor Inhibitor/No Air Inhibitor Air/No Inhibitor/Air Dr: Sheldon Evans, Conoco Inc. No Air/No Inhibitor CONDITION MPY Inhibitor/No Air 30 Air/No Inhibitor 285 3 Inhibitor/Air 275 2714 Cypress Point Drive, Suite E Missouri City, TX 77459 Telephone: 281-499-4426 Fax: 281-261-5617 e-mail: rust@enhanceco.net web: www.enhanceco.net <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 6D DRAG REDUCING AGENT MSDS <<>> ransition SDS: Product is now manufactured by Phillips 66 Compan For SDS information please email SDS@P66.com or visit www.Phillips66.com. mergency, Customer Service and Technical phone numbers have NOT change LP™M 100 Flow Improver ConocoPhillips Flow Improver Solutions Safety Data Sheet Section 1: Identification of the substance or mixture and of the supplier Product Name: SDS Number: 472980 LP™M 100 Flow Improver Intended Use: Flow Improver Manufacturer: ConocoPhillips Specialty Products Inc. Houston, TX 77079-1175 600N. Dairy Ashford United States of America Emergency Health and Safety Number: +1 703-527-3887 (USA, 24 hours) +1 800-424-9300 (USA, 24 hours) Customer Service: Telephone: +1 832-486-2834 Telefax: +1 832-486-2881 SDS Information: URL: www.conocophillips.com Email: MSDS@conocophillips.com Section 2: Hazard(s) Identification This material is not considered hazardous according to OSHA criteria. NFPA Section 3: Composition/ Information on Ingredients Component Water 7732-18-5 CASRN Concentration Non-hazardous Materials 1 All concentrations are percent by weight unless ingredient is a gas. Gas concentrations are in percent by volume. Proprietary 35 - 45 55 - 65 Section 4: First Aid Measures attention. Eye Contact: If irritation or redness develops from exposure, flush eyes with clean water. If symptoms persist, seek medical Skin Contact: First aid is not normally required. However, it is good practice to wash any chemical from the skin. Inhalation (Breathing): First aid is not normally required. If breathing difficulties develop, move victim away from source of exposure and into fresh air in a position comfortable for breathing. Seek immediate medical attention. Ingestion (Swallowing): First aid is not normally required; however, if swallowed and symptoms develop, seek medical attention. Medical Conditions Aggravated by Exposure: None Known Date of Issue: 12-Jan-2012 472980 - LP ™ 100 Flow improver Status: FINAL Page 1/6 <<>> Emergency, Customer Service and Technical phone numbers have NOT changed. Transition SDS: Product is now manufactured by Phillips 66 Company. For SDS information please email SDS@P66.com or visit www.Phillips66.com. 472980 - LP™ 100 Flow Improver Date of Issue: 12-Jan-2012 Status: FINAL Page 2/6 Section 5: Fire-Fighting Measures NFPA 704 Hazard Class Health: 0 Flammability: 0 Instability: 0 (O-Minimal, 1-Slight, 2-Moderate, 3-Serious, 4-Severe) rupture in the heat of a fire. Unusual Fire & Explosion Hazards: No unusual fire or explosion hazards are expected. If container is not properly cooled, it can Extinguishing Media: Use extinguishing agent suitable for type of surrounding fire. protective clothing. When the potential chemical hazard is unknown, in enclosed or confined spaces, a self contained breathing Fire Fighting Instructions: For fires beyond the initial stage, emergency responders in the immediate hazard area should wear apparatus should be worn. In addition, wear other appropriate protective equipment as conditions warrant (see Section 8). containers from immediate hazard area if it can be done safely. Water spray may be useful in minimizing or dispersing vapors and Isolate immediate hazard area and keep unauthorized personnel out. Stop spill/release if it can be done safely. Move undamaged to protect personnel. Cool equipment exposed to fire with water, if it can be done safely. Hazardous Combustion Products: Combustion may yield carbon monoxide and oxides of nitrogen. See Section 9 for Flammable Properties including Flash Point and Flammable (Explosive) Limits Section 6: Accidental Release Measures persons down wind of the spill/release, isolate immediate hazard area and keep unauthorized personnel out. Wear appropriate Personal Precautions: Stay upwind and away from spill/release. Avoid direct contact with material. For large spillages, notify information on hazards and precautionary measures. protective equipment, including respiratory protection, as conditions warrant (see Section 8). See Sections 2 and 7 for additional Environmental Precautions: Stop spill/release if it can be done safely. Prevent spilled material from entering sewers, storm drains, other unauthorized drainage systems, and natural waterways. Use water sparingly to minimize environmental contamination and reduce disposal requirements. If spill occurs on water notify appropriate authorities and advise shipping of any hazard. cleanup of any spill is recommended. Dike far ahead of spill for later recovery or disposal. Absorb spill with inert material such as Methods for Containment and Clean-Up: Notify relevant authorities in accordance with all applicable regulations. Immediate sand or vermiculite, and place in suitable container for disposal. If spilled on water remove with appropriate methods (e.g. accordance with local regulations. skimming, booms or absorbents). In case of soil contamination, remove contaminated soil for remediation or disposal, in regulations may influence or limit the choice of appropriate actions to be taken. See Sectión 13 for information on appropriate Recommended measures are based on the most likely spillage scenarios for this material; however local conditions and disposal. Section 7: Handling and Storage and wear appropriate personal protective equipment (see section 8). Precautions for safe handling: Wear eye/face protection. Wash thoroughly after handling. Use good personal hygiene practices procedures such as ASTM D-4276 and 29CFR 1910.146. Do not wear contaminated clothing or shoes. Spills will produce extremely slippery surfaces. Do not enter confined spaces such as tanks or pits without following proper entry well-ventilated areas. Store only in approved containers. Keep away from any incompatible material (see Section 10). Protect Conditions for safe storage: Keep containers) tightly closed and properly labeled. Use and store this material in cool, dry, container(s) against physical damage. Section 8: Exposure Controls / Personal Protection Note: State, local or other agencies or advisory groups may have established more stringent limits. Consult an industrial hygienist or similar professional, or your local agencies, for further information. <<>> Emergency, Customer Service and Technical phone numbers have NOT changed. Transition SDS: Product is now manufactured by Phillips 66 Company. For SDS information please email SDS@P66.com or visit www.Phillips66.com. 472980 - LP ™ 100 Flow Improver Date of Issue: 12-Jan-2012 Status: FINAL Page 3/6 controls may be necessary if working with the product in enclosed areas and/or at elevated temperatures. Engineering controls: General ventilation should be adequate for normal conditions of intended use. Additional engineering ye/Face Protection: The use ot eye/tace protection is not normally required; however, good industrial hygiene practice sugges le use of eye protection that meets or exceeds ANSI Z.87.1 whenever working with chemicals use of gloves or other appropriate skin protection whenever working with chemicals. Skin/Hand Protection: The use of skin protection is not normally required; however, good industrial hygiene practice suggests the conditions that could result in significant airborne exposures may require the use of NIOSH approved respiratory protection. An Respiratory Protection: Respiratory protection is not normally required under intended conditions of use. Emergencies or industrial hygienist or other appropriate health and safety professional should be consulted for specific guidance under these situations. available information. Users should consult with the specific manufacturer to confirm the performance of their protective Suggestions provided in this section for exposure control and specific types of protective equipment are based on readily equipment. Specific situations may require consultation with industrial hygiene, safety, or engineering professionals. Section 9; Physical and Chemical Properties are not intended to be specifications. Note: Unless otherwise stated, values are determined at 20°C (68°F) and 760 mm Hg (1 atm). Data represent typical values and Appearance: Physical Form: Liquid Opaque White Odor: Odor Threshold: Mild No data pH: Vapor Pressure: 10.0-12.3 Vapor Density (air=1): > 1 23.8 mm Hg @ 77F / 25°C Melting/Freezing Point: Initial Boiling Point/Range: 32 °F / 0 °C 212 °F / 100 °C Solubility in Water: Specific Gravity (water=1): Partition Coefficient (n-octanol/water) (Kow): Partial 0.87 - 0.94 @ 60°F (15.6°C) No data Viscosity: Bulk Density: 8.09 Ibs/gal Flash Point: Evaporation Rate (nBuAc=1): 350 cP @ 555s-1 @ 77°F / 25°C (Non-Newtonian) No data Lower Explosive Limits (vol % in air): No data N/A Upper Explosive Limits (vol % in air): Auto-ignition Temperature: No data No data Section 10: Stability and Reactivity Stability: Stable under normal ambient and anticipated conditions of use. Conditions to Avoid: Avoid high temperatures and all sources of ignition. Materials to Avoid (Incompatible Materials): Avoid contact with strong oxidizing agents Hazardous Decomposition Products: Not anticipated under normal conditions of use. Hazardous Polymerization: Not known to occur. Section 11: Toxicological Information Information on Toxicological Effects of Substance/Mixture Acute Toxicity Hazard Additional Information LC50/LD50 Data <<>> Transition SDS: Product is now manufactured by Phillips 66 Company. For SDS information please email SDS@P66.com or visit www.Phillips66.com. Emergency, Customer Service and Technical phone numbers have NOT changed. 472980 - LP™M 100 Flow Improver Date of Issue: 12-Jan-2012 Status: FINAL Page 4/6 Inhalation Unlikely to be harmful >5 mg/L (mist, estimated) Skin Absorption Unlikely to be harmful > 2 g/kg (estimated) Ingestion (Swallowing) Unlikely to be harmful > 5 g/kg (estimated) Aspiration Hazard: Not an aspiration hazard. Skin Corrosion/Irritation: Not expected to be irritating. Serious Eye Damage/Irritation: Not expected to be irritating. Signs and Symptoms: No known effects of overexposure. sensitization (or are below the concentration threshold for classification). Skin Sensitization: No information available on the mixture, however none of the components have been classified for skin for respiratory sensitization (or are below the concentration threshold for classification). Respiratory Sensitization: No information available on the mixture, however none of the components have been classified components have been classified for target organ toxicity (or are below the concentration threshold for classification). Specific Target Organ Toxicity (Single Exposure): No information available on the mixture, however none of the components have been classified for target organ toxicity (or are below the concentration threshold for classification). Specific Target Organ Toxicity (Repeated Exposure): No information available on the mixture, however none of the carcinogenicity (or are below the concentration threshold for classification) Carcinogenicity: No information available on the mixture, however none of the components have been classified for Germ Cell Mutagenicity: No information available on the mixture, however none of the components have been classified for germ cell mutagenicity (or are below the concentration threshold for classification). Reproductive Toxicity: No information available on the mixture, however none of the components have been classified for reproductive toxicity (or are below the concentration threshold for classification). Section 12: Ecological Information Toxicity: Not expected to be harmful to aquatic organisms based on test data from the individual components or similar materials. Persistence and Degradability: Not expected to persist in the environment if spilled or released. Bioaccumulative Potential: Not expected to bioaccumulate in the environment based on its physical properties Mobility in Soil: Expected to have low mobility in soil and sediments with adsorption being the predominant physical process Other Adverse Effects: None anticipated. Section 13: Disposal Considerations and local requirements in addition to federal regulations. The generator of a waste is always responsible for making proper hazardous waste determinations and needs to consider state exhibit characteristics of hazardous waste. This material, if discarded as produced, would not be a federally regulated RCRA "listed" hazardous waste and is not believed to Section 9 for physical/chemical properties. It is possible that the material as produced contains constituents which are not required See Sections 7 and 8 for information on handling, storage and personal protection and to be listed in the MSDS but could affect the hazardous waste determination. Additionally, use which results in chemical or physical change of this material could subject it to regulation as a hazardous waste. Container contents should be completely used and containers should be emptied prior to discard. Section 14: Transport Information U.S. Department of Transportation (DOT) <<>> Transition SDS: Product is now manufactured by Phillips 66 Company. Emergency, Customer Service and Technical phone numbers have NOT changed. For SDS information please email SDS@P66.com or visit www.Phillips66.com. Date of Issue: 12-Jan-2012 472980 - LP™ 100 Flow Improver Status: FINAL Page 5/6 Shipping Description: Not regulated International Maritime Dangerous Goods (IMDG) Shipping Description: Not regulated UN/ID #: International Civil Aviation Org. / International Air Transport Assoc. (ICAO/IATA) Not regulated Packaging Instruction #: LTD. QTY Passenger Aircraft Cargo Aircraft Only Max. Net Qty. Per Package: Section 15: Regulatory Information This material does not contain any chemicals subject to the reporting requirements of SARA 302 and 40 CFR 372. CERCLA/SARA - Section 302 Extremely Hazardous Substances and TPQs (in pounds): CERCLA/SARA - Section 311/312 (Title Ill Hazard Categories) Acute Health: Chronic Health: No Fire Hazard: Pressure Hazard: No No Reactive Hazard: No This material does not contain any chemicals subject to the reporting requirements of SARA 313 and 40 CFR 372. CERCLA/SARA - Section 313 and 40 CFR 372: EPA (CERCLA) Reportable Quantity (in pounds): This material does not contain any chemicals with CERCLA Reportable Quantities California Proposition 65: reproductive harm at concentrations that trigger the warning requirements of California Proposition 65. This material does not contain any chemicals which are known to the State of California to cause cancer, birth defects or other International Hazard Classification None GHS Classification: Canada: MSDS contains all the information required by the Regulations. This product has been classified in accordance with the hazard criteria of the Controlled Products Regulations (CPR) and the WHMIS Hazard Class: None All components are either listed on the US TSCA Inventory, or are not regulated under TSCA National Chemical Inventories All components are either on the DSL, or are exempt from DSL listing requirements. U.S. Export Control Classification Number: EAR99 Section 16: Other Information Status: Date of Issue: 12-Jan-2012 Previous Issue Date: FINAL Revised Sections or Basis for Revision: 18-Jun-2008 Identified Hazards (Section 2) Physical Properties (Section 9) Toxicological (Section 11) SDS Number: 472980 Environmental hazards (Section 12) <<>> Transition SDS: Product is now manufactured by Phillips 66 Company. For SDS information please email SDS@P66.com or visit www.Phillips66.com. Emergency, Customer Service and Technical phone numbers have NOT changed. 472980 - LP ™ 100 Flow Improver Date of Issue: 12-Jan-2012 Status: FINAL Page 6/6 ACGIH = American Conference of Governmental Industrial Hygienists; CASRN = Chemical Abstracts Service Registry Number; CEILING = Ceiling Guide to Abbreviations: Agency; GHS = Globally Harmonized System; IARC = International Agency for Research on Cancer; INSHT = National Institute for Health and Limit (15 minutes); CERCLA = The Comprehensive Environmental Response, Compensation, and Liability Act; EPA = Environmental Protection Protection Association; NTP = National Toxicology Program; OSHA = Occupational Safety and Health Administration; PEL = Permissible Exposure Safety at Work; IOPC = International Oil Pollution Compensation; LEL = Lower Explosive Limit; NE = Not Established; NFPA = National Fire Value (ACGIH); TWA = Time Weighted Average (8 hours); UEL = Upper Explosive Limit; WHMIS = Worker Hazardous Materials Information Limit (OSHA); SARA = Superfund Amendments and Reauthorization Act; STEL = Short Term Exposure Limit (15 minutes); TLV = Threshold Limit System (Canada) The information presented in this Material Safety Data Sheet is based on data believed to be accurate as of the date this Material Disclaimer of Expressed and implied Warranties: Safety Data Sheet was prepared. HOWEVER, NO WARRANTY OF MERCHANTABILITY, FITNESS FOR ANY PARTICULAR COMPLETENESS OF THE INFORMATION PROVIDED ABOVE, THE RESULTS TO BE OBTAINED FROM THE USE OF THIS PURPOSE, OR ANY OTHER WARRANTY IS EXPRESSED OR IS TO BE IMPLIED REGARDING THE ACCURACY OR responsibility is assumed for any damage or injury resulting from abnormal use or from any failure to adhere to recommended INFORMATION OR THE PRODUCT, THE SAFETY OF THIS PRODUCT, OR THE HAZARDS RELATED TO ITS USE. No practices. The information provided above, and the product, are furnished on the condition that the person receiving them shall the risk of their use. In addition, no authorization is given nor implied to practice any patented invention without a license. make their own determination as to the suitability of the product for their particular purpose and on the condition that they assume <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 6E REFERENCED PROCEDURES OF THE MAGELLAN 2012 SIP <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 6E REFERENCED PROCEDURES OF THE MAGELLAN 2012 SIP CHAPTER 6: SIP-ADM 2.01 SIP-ADM 2.02 SIP-ADM 4.01 SIP-ADM 7.01 SIP-ADM 7.03 SIP-ADM 7.03-001 SIP-ADM 7.04-001 SIP-ADM 7.04-002 SIP-ADM 7.04-006 SIP-ADM 7.04-015 SIP-ADM 7.04-016 SIP-ADM 7.04-023 SIP-ADM 7.05-002 SIP-ADM 7.05-003 SIP-ADM 7.05-009 SIP-ADM 7.05-012 SIP-ADM 7.05-014 SIP-ADM 7.05-020 SIP-ADM 7.05-030 SIP-ADM 7.05-031 SIP-ADM 7.05-039 SIP-ADM 7.06 SIP-ADM 8.01 SIP-ADM 10.01 <<>> Magellan Midstream Partners, L.P. TRAINING SIP–ADM–2.01 Training 01/01/12 Revision: 8 Page 1 of 4 1.0 OBJECTIVE 1.1 The objective of this initiative is to describe the roles and responsibilities associated with regulatory required training. 2.0 DESCRIPTION 2.1 This initiative represents a baseline of regulatory training requirements as defined by the Company and enables Company personnel, including new and transferred employees, to acquire the knowledge and skills needed to work in a safe, healthy and productive manner and to comply with all training requirements of applicable laws and regulations. 3.0 STANDARDS 3.1 All Employees shall: 3.1.1 Complete federal, state or facility‐specific training as identified on the Training Matrix, or by the immediate supervisor. 3.1.2 Complete assigned training as identified on the Individual Training Plan prior to performing applicable tasks independently when newly assigned to field operations. NOTE: An explanation of the ITP is contained in the plan. 3.2 3.3 3.1.3 Complete professional or Company mandated training as identified by the immediate supervisor. 3.1.4 Document attendance at training sessions on the Training Roster. Leadership shall (as defined on the training matrix): 3.2.1 Assign applicable training requirements per the Individual Training Plan to any employee new or newly transferred to field operations within 30 days of their start date. Upon completion of the training requirements the ITP form shall be sent to the Training Department and a copy maintained locally. 3.2.2 Review and communicate Training Matrix requirements to all existing employees annually. 3.2.3 Identify and communicate any facility‐specific, or state required training to direct reports. 3.2.4 Discuss and review each direct report’s Emergency Response Training skills annually not to exceed 15 months. Provide suggestions as necessary to make the Training more effective. Document the review and any suggestions on the Emergency Response Training Evaluation Form. Maintain the completed form locally. This is intended for any direct report that would reasonably respond in an emergency. 3.2.4.1 Send a copy of suggested changes (if any) to the Training Supervisor within seven days of completing the form. The Supervisor of Training and Staffing shall: 3.3.1 Ensure training requirements and tools are reviewed, developed, and documented to comply with all federally regulated and legally required training. <<>> Magellan Midstream Partners, L.P. TRAINING SIP–ADM–2.01 Training 01/01/12 Revision: 8 Page 2 of 4 3.3.2 3.3.3 3.3.4 3.3.5 3.3.6 Provide guidance to leadership as requested, in order to help ensure compliance with state and local training requirements. Meet with all directors and managers to determine nonregulatory and noncompliance training needs for the following year’s training plans by the end of the 4th quarter. Maintain and communicate available training materials and tools to the Company annually, or as changes are made. Maintain training records in a compliance management system for Company employees and work with appropriate business group representatives to ensure compliance with data management. Maintain an Emergency Response curriculum that is compliant to DOT 195.403 and. Incorporate improvement suggestions into training annually. At a minimum this curriculum shall provide instructions for employees to: 3.3.6.1 Carry out the emergency response procedures applicable to their assignment. 3.3.6.2 Know what the characteristics and hazards of the hazardous liquids or carbon dioxide transported are, including, in case of flammable HVL, flammability of mixtures with air, odorless vapors, and water reactions. 3.3.6.3 Recognize conditions that are likely to cause emergencies, predict the consequences of facility malfunctions or failures and hazardous liquids or carbon dioxide spills, and take appropriate corrective action. 3.3.6.4 Take steps necessary to control any accidental release of hazardous liquid or carbon dioxide and to minimize the potential for fire, explosion, toxicity, or environmental damage. 3.3.6.5 Learn the potential causes, types, sizes and consequences of fire would/could be and how to appropriately use portable fire extinguishers and other on‐site fire control equipment, involving (when feasible), a simulated pipeline emergency condition. 3.4 All Managers shall: 3.5 3.6 3.4.1 Assist the Manager of Training and Staffing in identifying training topics necessary to meet regulatory requirements and/or facility‐specific issues (e.g., Process Safety Management requirements). The Field Office Administrator Shall: 3.5.1 Assist in the coordination of scheduling dates and locations for any training in their area. The Supervisor at Marine Facilities Shall: 3.6.1 Complete the requirements in the Marine Person‐In‐Charge Qualification as needed to certify individuals to perform dock transfer operations. <<>> Magellan Midstream Partners, L.P. TRAINING SIP–ADM–2.01 Training 01/01/12 Revision: 8 Page 3 of 4 SYSTEM INTEGRITY PLAN CHANGE LOG Date Location Brief Description of Change 1/1/05 1.1 Rephrased 2.1 Rephrased 3.1.1 Rephrased, combined 3.1.1 and 3.1.2 (2004) 3.2.1 Added requirement for review of operations and maintenance procedures 3.2.4 Removed requirement 3.3.4, 3.3.5 Removed requirements from 2004 3.4 Added Safety Representatives 3.4.1 Removed requirement from2004 3.4.3 Rephrased into 3.4.1 2005 3.4.3 Added for 2005 3.5 Removed standard from 2004 1/1/06 3.2.1 Changed to 180 days from one week 01/01/06 1.1 Deleted “provide training that will reduce risk to Company employees, the public, environment and property as well as provide professional development to Company employees as appropriate” and added “describe the roles and responsibilities associated with regulatory required training.” 01/01/06 2.1 Added “training requirements of” 01/01/06 3.3.2 Added “to leadership” 01/01/06 3.4.1 Deleted “training team” added “Training Supervisor” 01/01/06 3.4.2 Added training matrix 01/01/06 3.2.4 Moved from 12.01 01/01/06 3.2.4 Deleted “Evaluate participating employees during emergency response exercises and/or actual spill events, as appropriate, utilizing the Emergency Response Training Document.” 01/01/06 3.2.4 added 3.2.4 Modified to correlate with modified form 3.3.1 Deleted standard regarding training matrix as this is covered in annual review. 1/1/07 3.3.5, 3.3.6 added 01/01/08 Reviewed, no changes 6/24/08 3.2.4 Added clarification for “not to exceed 15 months” 1/1/09 All Annual review complete 1/1/09 3.1.2, 3.2.1, Added 1/1/09 3.2 Modified 01/01/10 3.3.3 Changed from Oct to end of 4th qtr 3.3.4 Changed from qtrly to annually 3.1.4 Moved from All Mgrs section 3.5 (old) Removed General Consul and VP HR responsibilities LINKS Removed non referenced links, obsolete links 01/01/10 3.1 Removed note box that referenced :How to Use TM” 01/01/11 Updated Supervisor of Training to Supervisor of Training and Staffing – new title 04/08/11 3.1.1/3.4 Removed reference to safety rep 12/31/11 3.2 Renamed the role of all supervisors to all leadership and clarified applicability (training matrix, emergency response) 12/31/11 3.2.4 Clarified 12/31/11 3.5 FOA directive added (moved from manager) <<>> Magellan Midstream Partners, L.P. TRAINING SIP–ADM–2.01 Training 01/01/12 Revision: 8 Page 4 of 4 12/31/11 3.6 added 12/31/11 3.2.1 Added “Upon completion of the training requirements the ITP form shall be sent to the Training Department and a copy maintained locally.” 12/31/11 All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. OPERATION QUALIFICATION SIP–ADM–2.02 Training 01/01/12 Revision: 8 Page 1 of 8 1.0 OBJECTIVE 1.1 The objective of this initiative is to describe the primary processes used to comply with DOT’s Operator Qualification (OQ) requirements. As such, this initiative and its associated procedures comprise the majority of the Company OQ Plan. 2.0 DESCRIPTION 2.1 This initiative applies to the following components of the Company OQ Plan: 2.1.1 Identification of Covered Tasks 2.1.2 The evaluation process 2.1.3 Span of control 2.1.4 Suspending, assessing and reevaluation of qualified employees 2.1.5 Reevaluation intervals 2.2 2.1.6 Training as related to qualification 2.1.7 Notification for significant changes to the Plan 2.1.8 Program Effectiveness This initiative does not include the following OQ Plan processes which are addressed in their respective elements. 2.2.1 Change Management 2.2.2 Contractor Management 2.2.3 Definitions 2.2.4 Abnormal Operating Conditions (AOC) 3.0 STANDARDS 3.1 The OQ Coordinator shall: 3.1.1 3.1.2 Maintain and document the criteria for the Company Subject Matter Experts (SMEs) who will review the Company Covered Tasks with input from leadership, as appropriate. Maintain the list of Company SMEs for the Covered Tasks. Maintain and document Evaluator Criteria. 3.1.3 Annually, or as needed, coordinate a review with the Company SMEs to review: (1) The Covered Task List, (2) The qualification requirements for contractors and (3) The evaluation materials and procedures. Revise as needed. NOTE: The tasks on the Covered Task List shall, at a minimum, meet the four part test as defined by PHMSA regulations. 3.1.4 3.1.5 Schedule evaluator training as needed. Maintain the Evaluator List showing trained evaluators and the task categories they may evaluate. Update the Evaluator List after completion of evaluator training, as necessary or applicable. Develop, maintain and administer proctor training as needed. Maintain a list of trained proctors on the Proctor List. NOTE: Change communication is not required for updates to the Evaluator List <<>> Magellan Midstream Partners, L.P. OPERATION QUALIFICATION SIP–ADM–2.02 Training 01/01/12 Revision: 8 Page 2 of 8 or the Proctor List. 3.1.6 Establish and maintain the Covered Task List. The Covered Task list shall document at least: 3.1.6.1 3.1.6.2 NOTE: Work Performance History Review and Observation During on the Job Performance are not allowable evaluation methods. 3.1.7 3.1.8 3.1.9 3.1.10 3.1.11 3.1.12 3.1.13 The name, number and description of the covered task. The type of evaluation method(s) allowed. 3.1.6.3 The reevaluation interval. 3.1.6.4 Span of control (criteria for directing and observing). Develop and maintain the Written Evaluations, Study Guides and Answer Keys for those Covered Tasks requiring a written examination for qualification. Maintain document control to limit access to tests and answer keys to the proctors. Maintain and administer the Merger & Acquisition Procedure for incorporating acquired employees into the Company OQ plan. Manage and maintain ISN as the Company’s OQ record-keeping system for employees and for contractors. Records shall be maintained for five years. At a minimum, the record-keeping shall consist of: 3.1.9.1 The identification of the Qualified Individual. 3.1.9.2 Identification of the Covered Tasks that the individual is qualified to perform. 3.1.9.3 Date(s) of current qualification. 3.1.9.4 Qualification method(s). Work with appropriate leadership to identify any mutual assistance arrangements and ensure that mutual assistance individuals are appropriately qualified to perform Covered Tasks. Oversee the Company OQ Plan as needed to ensure compliance. Oversight may consist of, but is not limited to, maintaining the OQ Protocol cross-reference, conducting spot-checks of OQ processes, initiating changes to the OQ Plan, and making final determination for any exception(s) to the plan that may be brought forward. Review any site-specific procedures for a Covered Task prior to local implementation. Develop and maintain OQ effectiveness measures and provide periodic updates to management. Effectiveness measures may include: 3.1.13.1 Adequacy of training for specific covered task(s). 3.1.13.2 Adequacy of evaluation(s) to determine if individual has required knowledge, skills, and abilities. 3.1.13.3 Adequacy of individual to recognize AOC(s). 3.1.13.4 Adequacy of individual to take appropriate action after an AOC. <<>> Magellan Midstream Partners, L.P. OPERATION QUALIFICATION SIP–ADM–2.02 Training 01/01/12 Revision: 8 Page 3 of 8 3.2 3.1.14 Send the OPS Information Resource Manager, and state agencies as applicable, the revised OQ Plan within 60 days of approval and implementation of any significant modifications. At a minimum, significant modifications would include: 3.1.14.1 Increasing evaluation intervals. 3.1.14.2 Increasing span of control ratios. 3.1.14.3 Eliminating covered tasks. 3.1.14.4 Mergers and/or acquisition changes. 3.1.14.5 Evaluation method changes such as written vs. observation. 3.1.14.6 Wholesale changes made to OQ plan. 3.1.15 Provide guidance to management regarding OQ qualifications in the unlikely event of a large workforce displacement due to events such as natural disasters, pandemics, workforce stoppages, etc. 3.1.15.1 Notify PHMSA in writing within 90 days of a workforce displacement if personnel were utilized to perform covered tasks who did not meet the Company OQ requirements. The Subject Matter Expert shall: 3.2.1 Upon request from the OQ Coordinator, utilize their experience and knowledge to review and recommend as necessary, modifications to covered tasks in their area of experience on the Covered Task List. 3.2.2 Upon request from the OQ Coordinator review and update the Task Category Criteria of the Evaluator Criteria . 3.2.3 Upon request from the OQ Coordinator review and update the Evaluation Checklists for covered tasks in their area of expertise. 3.3 All Supervisors shall: 3.3.1 Identify individuals to serve as Company SMEs for the covered task review when requested by the OQ Coordinator. 3.3.2 Require evaluators to meet evaluator requirements as shown on the Evaluator Criteria before conducting OQ evaluations. 3.3.3 Prior to any employee’s initial or non-routine evaluation, assess training needs, document and provide training using the Individual Training Plan (ITP). Maintain the ITP locally for three years. NOTE: Operations Controllers shall comply with required Operations Control training requirements in lieu of the ITP for OQ training and documentation. 3.3.4 Coordinate the evaluation with the individual and the evaluator or proctor upon completion of OQ training or as required. Allow a sufficient amount of time to pass before scheduling an evaluation following a failed evaluation; normally this time is three days for a performance type evaluation or the next business day for a written evaluation. Inform the individual they are not to perform a Covered Task after failing an evaluation unless they perform it in accordance with the Span of Control or have successfully been reevaluated. For performance type evaluations, discuss the evaluation with the individual and sign the completed OQ Checklist upon receipt and forward to the appropriate OQ Records Administrator. <<>> Magellan Midstream Partners, L.P. OPERATION QUALIFICATION SIP–ADM–2.02 Training 01/01/12 Revision: 8 Page 4 of 8 NOTE: Evaluations following a failed evaluation are considered “non-routine.” 3.3.5 Determine applicable Covered Task(s) for each employee in the work group and provide information to the OQ Records Administrator for documentation in ISN. Review and submit updates as required, such as following a job scope change or reorganization. NOTE: AOC evaluations are required for all employees performing OQ covered tasks. 3.3.6 3.3.7 Upon notification of an incident (as defined in the 7000-1 Report) determine if an employee’s performance of a covered task contributed to that incident or if the performance cannot be ruled out as contributing to the incident. If the determination is affirmative: 3.3.6.1 Assess the employee’s actions in performing the covered task, including a procedure review if appropriate, and determine whether the employee’s relevant OQ task(s) should be suspended. 3.3.6.2 If the employee’s relevant OQ task(s) are not suspended: 3.3.6.2.1. Determine if any additional action is required such as a more thorough procedure review, submitting a suggestion to revise the procedure, refresher training, etc., and document on the Corrective Action section of the Incident Report. 3.3.6.3 If the employee’s relevant OQ task(s) are suspended: 3.3.6.3.1. Inform the employee that they are not allowed to perform the applicable Covered Task until they have completed any training or requalification actions. 3.3.6.3.2. Notify the OQ Records Coordinator when feasible to document the assessment results and suspension (if applicable) in ISN. 3.3.6.3.3. Provide training and reevaluation for the individual(s). Document on the Individual Training Plan (ITP). 3.3.6.4 Determine if any information regarding this incident or the safe performance of the applicable covered task beyond the standing incident review agenda item should be included in a SIP meeting. Include this information on the SIP meeting agenda if warranted. Require reevaluation for any employee if there is reason to believe the employee is no longer qualified. The employee shall be suspended from performing the covered task until he/she has successfully completed the applicable OQ evaluation. The suspension and reevaluation shall be documented in ISN. These evaluations shall be considered non-routine. <<>> Magellan Midstream Partners, L.P. OPERATION QUALIFICATION SIP–ADM–2.02 Training 01/01/12 Revision: 8 Page 5 of 8 Examples of situations that may raise concerns about an individual’s ability to perform a Covered Task include, but are not limited to:  Loss of motor skills, vision, or other impairment as evidenced by written notification from a licensed health care professional.  Statement from the employee regarding his/her qualification.  Prolonged period of not performing the task.  Unsatisfactory execution of the task such as during the job or during an inspection.  Substantiated complaints from a third party or another employee regarding incorrect performance of the task.  Involvement in a near miss or other incident (as defined in SIP) or AOC.  Observation of the employee performing the covered task incorrectly. 3.3.8 Submit site-specific procedures for a Covered Tasks to the OQ Coordinator for review and approval prior to implementation. 3.3.9 Quarterly review employees OQ records to ensure that the records are correct and to schedule any evaluations prior to expiration. 3.4 All Managers shall: 3.4.1 Designate an OQ Records Administrator to maintain OQ records in ISN. 3.5 The OQ Evaluator shall: 3.5.1 3.5.2 Attend evaluator training in order to be considered an OQ evaluator. Conduct OQ evaluations according to the Evaluation Procedure and the Covered Task List. 3.6 The OQ Proctor shall: 3.6.1 Conduct OQ written evaluations in accordance with the rules and guidelines provided in Proctor Training. Maintain the confidentiality of the written evaluations and answer keys. 3.7 The Employee shall: 3.7.1 Complete any training prior to initial or nonroutine OQ evaluations as described on the Individual Training Plan (ITP). 3.7.2 Complete OQ evaluations as scheduled and as described in the Evaluation Procedure. 3.7.3 Perform Covered Tasks as required per the Span of Control as shown on the Covered Task List. 3.7.4 Inform contractor employees of their specific expectations following an incident or AOC via the Job Plan and/or ATW. 3.8 The OQ Records Administrator shall: 3.8.1 Enter and update OQ records in ISN upon receipt from Supervisor as described in ISN Directions for Entering OQ Evaluations. 3.8.1.1 3.8.1.2 Enter completed evaluations within two weeks of receipt. Enter suspensions or revocations as soon as feasible. <<>> Magellan Midstream Partners, L.P. OPERATION QUALIFICATION SIP–ADM–2.02 Training 01/01/12 Revision: 8 Page 6 of 8 3.9 3.8.2 Maintain no more than one set of paper copies of evaluations. Ensure that these records have been completed per the ISN Directions for Entering OQ Evaluations. Return any deficient paperwork to the supervisor for correction prior to filing and entering into ISN. The Vice President of Operations shall: 3.9.1 Provide the most qualified workforce possible in the unlikely event of a large workforce displacement due to events such as natural disasters, pandemics, workforce stoppages, etc. Qualification considerations will be based, but not limited to, the following factors: 3.9.1.1 Current Company OQ qualifications. 3.9.1.2 Previous task experience. 3.9.1.3 Task training. 3.9.1.4 Previous Company OQ qualifications. 3.9.1.5 Current or previous OQ qualifications outside of Company OQ requirements. <<>> Magellan Midstream Partners, L.P. OPERATION QUALIFICATION SIP–ADM–2.02 Training 01/01/12 Revision: 8 Page 7 of 8 SYSTEM INTEGRITY PLAN CHANGE LOG DATE LOCATION BRIEF DESCRIPTION OF CHANGE 1/1/05 1.1 Shortened objective. DOT references were redundant. 2.1 Separated description into two standards. 3.1.1 Separated various elements of OQ Plan into separate standards. 3.1.2 Change Management is covered in 11.02 (2005) 3.1.3 Moved to standard 3.1.1 (2005) 3.2.1 Rephrased and moved to 3.3.4 (2005) 3.2.2 Rephrased and moved to 3.3.7 (2005) 3.2.3 Rephrased and moved to 3.3.3 (2005) 3.2.4 Deleted – record-keeping system will do 3.2.5 Rephrased and moved to evaluation procedure (2005) 3.2.6 Deleted 3.4.1 Deleted 3.4.2 Rephrased and moved to 3.5.2 (2005) 3.5.1 Deleted All others Added 4/12/04 1.1 Included DOT 192 part N 3.2.3 Note box Added guidance for when qualification may need to be evaluated 3.2.4 Note box Added 3‐year re‐qualification requirement 3.2.7 Added mutual assistance standard 3.3.1 Note box Added evaluation requirements for mutual assistance 3.4.1 Note box Included options for qualifying on AOCs 01/01/06 3.1.10 Corrected mutual assistance employees to mutual assistance individual. Low impact change. 1/1/06 3.6 Added record-keeping responsibilities 1/1/06 3.3.6 and 3.3.7 Clarified 1/1/06 3.1.12 Added 01/01/06 3.0 Deleted “Maintain the Evaluation Procedure” 1.1 Added clarification to explain this initiative’s role in the OQ Plan. 2.0 Modified to list OQ Plan elements. 3.1.1, 3.1.3, 3.3.2 Minor modifications 3.1.4, 3.1.5, 3.1.7, 3.1.12, 3.2.3 added 3.1.9 Combined contractors and employees - ISN <<>> Magellan Midstream Partners, L.P. OPERATION QUALIFICATION SIP–ADM–2.02 Training 01/01/12 Revision: 8 Page 8 of 8 3.1.14 Added specific criteria 3.3.3 Modified training requirements 3.3.4 added 3.3.6 Modified suspension/revocation standards 3.3.7 Modified 3.3.8 added 1/1/07 3.4 Added Managers responsibilities 3.6 Added proctor standards 3.4.2 Modified for training requirements 3.4.4 Added span of control requirements 3.7 Modified 01/01/08 Reviewed, no changes All Annual review complete 3.1.5 added 3.3.3 Revised to ITP 1/1/09 3.3.5 Modified to include AOCs 3.3.6 revised 3.7.4 added 3.9 added 2/01/09 3.3.3 Changed from 5 to 3 yrs 3.7.1 Changed from OQ Training sheet to ITP 01/01/10 all Activated inactive links 3.1.13, 3.1.14 Modified per PHMSA advisory 3.1.6.2 Added notebox to support PHMSA advisory 01/01/11 Reviewed, no changes 03/09/11 3.1.3 Note Removed DOT 192 and DOT 195 reference and added PHMSA regulations. 12/31/11 3.1.13 Added “may” since list is not inclusive 12/31/11 3.2 Clarified process 12/31/11 3.3.3 Clarified process 12/31/11 3.3.4 Added language to clarify process for written evaluations and for performance evaluations 12/31/11 3.3.9 added 12/31/11 all 2012 annual review complete <<>> Magellan Midstream Partners, L.P. PROJECT MANAGEMENT SIP–ADM–4.01 Project Management 01/01/12 Revision: 8 Page 1 of 4 1.0 OBJECTIVE 1.1 The objective of this initiative is to describe the process used to manage projects. 2.0 DESCRIPTION 2.1 The Project Management initiative applies to the development, design, project management, construction, commissioning, and post project performance assessment of new and modified assets. Non‐complex repairs and like‐kind replacements are generally excluded from this initiative. 2.2 The assets that comprise the Galena Park to El Paso pipeline, Crane to Odessa Pipeline and the associated facilities are covered by the Mitigation Plan. 2.2.1 The Mitigation Plan places specific requirements in addition to applicable Federal, State and Local regulations, Company SIP requirements, Company guidelines, process, or best practices. Refer to the Mitigation Plan for those requirements. 3.0 STANDARDS 3.1 The Project Sponsor shall: 3.1.1 Notify Legal and the Director of Environmental, Health, Safety and Security of any new type of business or operation involving Company assets upon discovery to determine if there are regulatory, permitting, or licensing requirements for construction or operation of new or modified assets. 3.1.2 Review and approve the Definitive Project Plan and the Authorization for Expenditure (AFE). 3.1.3 Advise management of project deviations that impact cost, timing, or functionality, and obtain approvals in accordance with the Company’s Delegation of Authority policy. 3.1.4 Obtain Supplemental AFE approvals in accordance with Magellan’s AFE Policy. 3.2 The Project Manager shall: 3.2.1 Utilize the applicable Company Standards (Design and Construction) List on all projects. 3.2.2 If deviation from a Company standard is desired, consult and obtain approval from the Subject Matter Expert (SME), as designated in the Company Standards (Design and Construction) List on and the Director of Engineering and Construction or Director of 3.2.3 3.2.4 Asset Integrity prior to proceeding. Require design drawings be reviewed and stamped by a Professional Engineer who is appropriately licensed if: 3.2.3.1 Required by any local, state or federal code or law. 3.2.3.2 Required by contract. 3.2.3.3 Required by Project Manager or Project Sponsor. Prepare and obtain approval on a Definitive Project Plan prior to AFE submittal. <<>> Magellan Midstream Partners, L.P. PROJECT MANAGEMENT SIP–ADM–4.01 Project Management 01/01/12 Revision: 8 Page 2 of 4 NOTE: The Definitive Project Plan includes the Objective, Description, Cost Estimate and Basis, Schedule, OBS, Risks, and Core Project Team and Project Sponsor Approvals. 3.2.5 3.2.6 3.2.7 3.2.8 Comply with the Environmental Aspects of Project Management Procedure. Engage with appropriate Environmental SME(s) as required during the project and prior to each of the following milestones: Permit Submittal, Start of Design, Start of Construction and Start Up. Comply with the Project Final Checkout Scheduling Guideline as soon as the AFE is signed. Provide quality control during construction activities to ensure compliance with industry codes, government regulations and Company standards. Select on‐site inspectors in accordance with the Contract Inspector Selection Matrix as applicable or necessary. 3.2.9 For PSM/RMP projects, validate and document that new and modified equipment are designed, installed, tested, and operated in accordance with design specifications and manufacturer’s instructions. Validate and document that associated maintenance materials, spare parts, and equipment are suitable for the process application. Place these documented validations and other PSM/RMP documentation in the local PSM/RMP files (or manual). Utilize the Documentation Checklist for New PSM/RMP Facilities as a guideline for identifying the required PSM/RMP documents. 3.2.10 3.2.11 Manage project costs and provide updates to the Core Project Team and Project Sponsor on anticipated deviations in costs, schedule and scope deviations in advance of their occurrence. Obtain approvals using the Project Change Document for deviations in the Definitive Project Plan that result in more than a $10,000 or a five percent increase in the total 3.2.12 3.2.13 3.2.14 3.2.15 3.2.16 AFE. Notify the Project Sponsor when the forecast of AFE expenditures exceeds the currently approved AFE amount by $100,000 or when the forecast of AFE expenditures is greater than $10,000 and 15% of the currently approved AFE amount. Submit cost estimates for Supplemental AFEs as requested by the Project Sponsor. Obtain Company approvals for service contract revisions (typically an RFS) when the sum of accumulated changes exceeds $100,000, or when the sum of accumulated changes is greater than $10,000 and 15% of the currently approved service contract. 3.2.14.1 Compare labor rates for specific RFS contracts with the rates in the contractor’s current Master Service Agreement (MSA). If those rates exceed rates established in the MSA, then obtain written approval from the next level of Management. Prepare and submit the Notice of Completion Form to Property Accounting when the project is mechanically complete, placed into service, or determined to be ready for service. Provide project documentation to Operations and the Asset Integrity Record Coordinator upon project completion. <<>> Magellan Midstream Partners, L.P. PROJECT MANAGEMENT SIP–ADM–4.01 Project Management 01/01/12 Revision: 8 Page 3 of 4 3.2.17 3.2.18 3.2.16.1 Provide copies of all project governmental and regulatory permits to local operations and to Project Support to post on Livelink. Solicit Stakeholder input on whether a Post Project Assessment Survey should be conducted for projects that require a Supplemental AFE or that exceed $500,000 in total costs. Summarize the Stakeholder input and submit to the Core Project Team and Project Sponsor. Conduct a Post Project Assessment Survey for projects completed in excess of 3.3 3.4 $10,000,000, or as requested by the Core Project Team. The Project Management Element Owner shall: 3.3.1 Maintain the Project Life Cycle Process (PLC) Reference Materials. The Core Project Team shall: 3.4.1 3.4.2 Determine if the Post Project Assessment Survey should be conducted for Projects less Review and approve the Definitive Project Plan and the AFE. than $10,000,000. <<>> Magellan Midstream Partners, L.P. PROJECT MANAGEMENT SIP–ADM–4.01 Project Management 01/01/12 Revision: 8 Page 4 of 4 System Integrity Plan Change Log Date Location Brief Description of Change 1/1/05 3.1.6 Added PSM requirements including Note Box 1/1/06 SIP‐ADM‐4.01 Reviewed, no changes 04‐FORM‐4020 and 4030 Reviewed, no changes 2.1 Added post project assessment 3.1. 3.3, 3.4 added 1/1/07 3.2 Deleted PLC standard, modified Company Standards List standards, added 3.2.8 – 3.2.14 01/01/07 OBJ and DESCRIP reworded 1/17/07 3.2.10 Added more specific requirements for supplemental AFE. 1/25/07 3.2.10 Added “Company” to clarify that the approval is internal. 1/1/09 3.1.3, 3.1.4, 3.2.1.3.1, 3.2.5 added 12/31/09 3.2.8 revised 12/31/09 3.2.11.1 added 12/31/09 All Annual review complete with the change above 12/31/10 All Annual review complete with the changes listed below. 12/31/10 3.2.5 Created an additional process for Environmental review of projects. 12/31/10 3.2.12, 3.2.13 Separated supplemental AFEs and service contract revisions into 2 standard s to clarify the role of the project sponsor for AFE supplements. 12/31/10 2.2, 2.2.1 Added Reference to Mitigation Plan in E4. 2.1 Added note to further define application of project management initiative. 3.2.1, 3.2.2 Updated link to point directly to the “Company Standards List” instead of E&C website. 3.2.2 Added “Director of Asset Integrity” as option for deviation approval. 12/31/11 3.2.4 Updated to reflect current process of Definitive Project Plan required for AFE submittal. 3.2.12 Removed 2nd half of requirement 3.1.4 Added per AFE policy 3.2.13 added 12/31/11 All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECTS REQUIRING REPAIRS AND REPAIR PROCEDURE SIP–ADM–7.01 Asset Integrity 01/01/12 Revision: 6 Page 1 of 2 1.0 OBJECTIVE 1.1 The objective of this initiative is to maintain asset integrity by establishing a consistent process for inspecting, evaluating, and repairing pipeline defects. 2.0 DESCRIPTION 2.1 Pipeline defects discovered through integrity tests such as in‐line inspections (ILI), hydrostatic tests, or routine maintenance shall be assessed and repaired, in a timely and consistent manner utilizing and complying with Company procedures, industry standards and applicable regulations and recommended practices. 3.0 STANDARDS 3.1 The Employee shall: 3.1.1 3.1.2 Comply with the applicable Welding and Radiographic Procedures at all times. 3.1.3 3.2 The Records Coordinator shall: 3.2.1 Upon discovery or notification of a pipeline defect, immediately evaluate and repair the defect in accordance with the Pipeline Defect Evaluation and Repair Procedure. Complete the Pipeline Maintenance Report and forward to the Records Coordinator. Review Pipeline Maintenance Report detail and notify Pipeline Mapping Coordinator of 3.2.2 any pipe record changes. Update TIES database for any pipe record changes or when pipe data discrepancies are discovered. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECTS REQUIRING REPAIRS AND REPAIR PROCEDURE SIP–ADM–7.01 Asset Integrity 01/01/12 Revision: 6 Page 2 of 2 System Integrity Plan Change Log Date Change Location Changed By Approved By Brief Description of Change 9/29/04 All Clyde Clausen Michael Pearson 9/29/04 2.1 Clyde Clausen Michael Pearson 9/29/04 3.1 Clyde Clausen Michael Pearson 9/29/04 3.2 Clyde Clausen Michael Pearson Clyde Clausen Michael Pearson Conducted 2004 Annual Review, (See Change Log) Minor modification to 2.1 Changed Asset Integrity Manager to Pipeline Integrity Supervisor Changed paragraph order of 3.2.1, 3.2.2 and 3.2.3 Changed Measure to: The number of pipeline defects repaired, documented, and categorized (Immediate, 60‐day, 180‐day, 9/29/04 5.1 and other) in accordance with section 8.2.2 of the Integrity Management Program. 10/16/05 All Clyde Clausen Michael Pearson 10/16/06 All Clyde Clausen Michael Pearson 10/16/06 1.1 Clyde Clausen Michael Pearson 10/16/06 2.1 Clyde Clausen Michael Pearson 10/16/06 3.2.3 Clyde Clausen Michael Pearson 10/16/06 4.4 Clyde Clausen Michael Pearson 10/16/06 5.0 Clyde Clausen Michael Pearson 09/11/07 All Clyde Clausen Michael Pearson 9/11/07 3.2.3 Clyde Clausen Michael Pearson 9/11/08 All Clyde Clausen Doug Chabino 9/11/08 3.2.4 Clyde Clausen Doug Chabino 8/21/09 All Clyde Clausen Doug Chabino 01/01/11 9/1/11 All Clyde Clausen Doug Chabino 9/1/11 3.2 & 3.2.1 & Clyde Clausen Doug Chabino 12/31/11 All Conducted 2005 Annual Review, No Changes Conducted 2006 Annual Review, (See Change Log) Minor Modification to paragraph Minor Modifications to paragraph and removed d fi i i f “ i li d f ” Added: For the Chase and Orion systems, complete h PL 0746 Pi d C i R Added Link Deleted the Measure section Conducted 2007 Annual Review, (See Change Log) Removed reference to 30 days Conducted 2008 Annual Review Removed reference to Complete Pipeline Crossing R f C D A Al R d h Conducted Annual Review, minor changes to remove d li i d d i l Reviewed, no changes Conducted Annual Review Added Record Coordinator responsibilities 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 1 of 16 1.0 PURPOSE 1.1 The purpose of this procedure is to establish a standardized method for identification, analysis and repair of pipeline defects when necessary. 2.0 PROCEDURE 2.1 General 2.1.1 2.1.2 2.1.3 Exceptions—This procedure may not apply to the following conditions: 2.1.1.1 Emergency situations such as a major pipeline release 2.1.1.2 Threaded piping Defect assessment, RSTRENG Analysis of Corrosion or KAPA, Nondestructive Testing, Maintenance Welding, Coating Application, and installation of repairs (e.g., clamps, composite repairs) are Covered Tasks. Welding on lines that are under internal pressure (live line welding) shall be done in accordance with Company welding procedures and practices. Refer to Specification 101, Maintenance Welding (Excluding Ethylene Pipelines). 2.2 Precautions 2.2.1 2.2.2 2.2.3 2.2.4 2.2.5 2.2.6 2.2.7 2.2.8 2.2.9 All exposed bell and spigot girth welds shall be reinforced by means of sleeving If needed (when pipe is not resting on the ground) the pipe should be adequately supported prior to backfilling. Consideration should be given to using dirt plugs or sandbags at spacing intervals not to exceed 20 feet particularly in areas where additional weight has been applied by installation of sleeving. All exposed girth welds (including bell and spigot joints) shall be supported (supports to be placed on each side of the girth weld not to exceed 5 feet) via sandbags or equivalent settlement resistant supports prior to backfilling. Pipeline defects discovered through integrity tests such as in-line inspections (ILI), pressure test, and routine maintenance shall be assessed and repaired, in a timely and consistent manner utilizing and complying with Company procedures, industry standards and applicable regulations (DOT 195.452) and recommended practices. Pipeline defects (including general or localized corrosion) confirmed through actual field findings (not reported by ILI tool) that meet the criteria of a pressure reducing defect shall be repaired immediately. Upon discovery, a pressure and or rate reduction, or line shutdown shall be considered. Pipeline defects not repaired by means of full encirclement sleeving and or pipe replacement should be non-destructively tested prior to recoating. All repairs are made in a safe manner and are made so as to prevent damage to persons or property and to comply with DOT 195.422. All materials used for repairs or replacement such as sleeves, pipe, fittings, and valves shall meet the minimum design requirements of the asset. Ensure that the site and/or bell hole are safe, prior to and during pipeline excavation activities. For specific guidelines to trenching, refer to the Excavation Safety Procedure. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 2 of 16 2.3 2.4 2.2.10 Determine if the coating contains asbestos, before authorizing or allowing any pipeline coating removal. Refer to the Asbestos Performance Procedure. 2.2.11 If the defect appears to be associated with product loss (leaking), take appropriate measures as indicated by the Emergency Response Plans to shut the line in or reduce the pressure in the pipeline to a safe pressure based on the preliminary evaluation, feature site and pipeline operation information. 2.2.12 When cleaning pipe (i.e. sand blasting or power brushing) for preparation of evaluating, repairing, or coating pipeline defects exercise extreme care as actual depth of defect may be greater than reported or predicted. To ensure safe work practices lightly clean pipe until it is evident that sufficient remaining wall exist to allow thorough cleaning of the defect. Review and Perform the Following General Steps For Evaluation of All Defects 2.3.1 Upon completion of the excavation, photograph the repair site prior to removing the coating. 2.3.2 Prepare the site and pipeline for a detailed evaluation of the defect after it has been determined it is safe to work on or near the pipeline. This includes removing cover to fully expose the pipe, coating removal and appropriately cleaning the feature to be evaluated in order to make detailed measurements of the feature and to determine the type of defect. 2.3.3 2.3.4 Document all defect information on Pipeline Maintenance Report. Visually determine the type of defect then use the appropriate part of this procedure, listed below, to assist with feature evaluation and the recommended repair options. Refer to Table 1 for a detailed listing of repair options. Under special circumstances, the Manager of Asset Integrity can approve deviations from the approved/preferred repair methods listed in Table 1. 2.3.4.1 Corrosion—Paragraph 2.4 2.3.4.2 Pipe body gouges and/or mill defects—Paragraph 2.5 2.3.4.3 Dents and Dents with associated gouges/stress risers—Paragraph 2.6 2.3.4.4 Arc Burns—Paragraph 2.7 2.3.4.5 Weld Defects—Paragraph 2.8 2.3.4.6 Stress Corrosion Cracking (SCC)—Paragraph 2.9 2.3.4.7 Selective Seam Corrosion (SSC)- Paragraph 2.10 2.3.4.8 Hard Spots—Paragraph 2.12 2.3.4.9 Buckling—Paragraph 2.13 2.3.4.10 Cracks- Long Seam and Pipe Body- Paragraph 2.13 Evaluate and Select Repair Options For Corrosion 2.4.1 After carefully reviewing the corrosion footprint or characteristics, clean the area suitably to aid in the evaluation of the corrosion. When cleaning pipe (i.e. sand blasting or power brushing) for preparation of evaluating, repairing, or coating pipeline defects exercise extreme care as actual depth of defect may be greater than reported or predicted. To ensure safe work practices lightly clean pipe until it is evident that sufficient remaining wall exist to allow thorough cleaning of the defect. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 3 of 16 2.5 2.6 2.7 2.4.2 If determined necessary, measure the length (in the longitudinal direction) and determine the depth of the deepest pitting within a corroded area or a segment of that area. The corrosion analysis criterion for RSTRENG or KAPA requires division of the pitted area into segments of consistent predetermined lengths and measurement of the maximum depths within each segment. Refer to RSTRENG Analysis of Corrosion Procedure for details. 2.4.3 Refer to Paragraph 2.16 of this procedure for corrosion repair methods and options. 2.4.4 Notify Asset Integrity for assistance with repair options when internal corrosion is found or suspected. Evaluate and Select Repair Options for Pipe Body Gouges and/or Mill Defects 2.5.1 Measure the defect circumferential width, length and depth at the deepest point and several other points along its length. Measure the angle, when applicable, of the defect relative to the run of the pipeline. 2.5.2 Refer to Table 1 of this procedure for gouges, pipe body and/or mill defects repair methods and options. 2.5.3 If the repair is made by removing the defect by means of sanding/grinding, upon completion, the area shall be nondestructively inspected to ensure that a stress riser, stress concentration, crack or other injurious defect does not exist prior recoating the area. Evaluate and Select Repair Options for Dents 2.6.1 Measure the dent area (the length, circumference and depth at the deepest point). Examine the bottom of the dent for scratches, gouges, grooves, metal loss or heavily work-hardened material. Measure scratch, gouge, groove or metal loss, if present, length and depth at the deepest point along its length. 2.6.2 (Reference Section, when required for use with Table 1) Any dent that exceeds 2% or 0.250” in NPS < 12”, with or without visible metal loss, shall be repaired with a Type B sleeve. Dents 2% or less in NPS <12” that are proven by nondestructive inspection that a stress riser, stress concentration, crack or other injurious defect does not exist within the dent may be recoated. 2.6.3 Refer to Paragraph 2.16 of this procedure for dent repair methods and options. Evaluate and Select Repair Options for Arc Burns NOTE: If the arc burn is on a new line under construction, the arc burn shall be removed as a cylinder, per the Onshore Construction Specifications. 2.8 2.7.1 2.7.2 Examine arc burns for cracking and depth. Refer to Specification 101: Maintenance Welding (Excluding Ethylene Pipelines) Paragraph 7.0 and Paragraph 2.16 of this procedure for arc burn repair methods and options. Evaluate and Select Repair Options for Weld Defects 2.8.1 Examine weld defects visually in accordance with Specification 100, Construction and Fabrication of Pipelines and Related Piping Systems and Specification 101, Maintenance Welding (Excluding Ethylene Pipelines). Evaluate welds that have been X-rayed in accordance with latest approved API specification. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 4 of 16 2.9 2.10 2.11 2.12 2.8.2 Repair all in-service joint welds in accordance with Specification 101 – Maintenance Welding (Excluding Ethylene Pipelines). This will usually require the use of a small Type B repair sleeve commonly called a “wedding band”. 2.8.3 The only repair allowed on a long-seam weld is grinding or sanding to remove surface defects that do not exceed 12.5% (reference 2.5.3) of the parent metal wall thickness. Repair all other weld defects by installing a full encirclement Type B repair sleeve or cutting out a cylinder of pipe and replacing it with new pipe. Evaluate and Select Repair Options for Lamination defects 2.9.1 Examine pipe for Lamination by non destructive testing of the surface in the area of concern. 2.9.2 Document the length, orientation, proximity to seam and girth weld if relevant, and note additional interactive features (metal loss, cracks, dents, etc.), if applicable note sloping, bulging, surface breaking, and blistering. 2.9.3 Repairs will be made in accordance with section 2.15. 2.9.4 Inspect the full circumference of the pipeline where the sleeve ends are to be welded to the pipeline using an ultrasonic thickness instrument and/or a magnetic particle inspection technique. Ensure there are no surface cracks, laminations or thin wall that could affect the integrity of the defect, weld, or sleeve. Evaluate and Select Repair Options for Stress Corrosion Cracking (SCC) 2.10.1 Examine pipe for Stress Corrosion Cracking (SCC) by non destructive testing and or magnetic particle inspection of the surface in the area of concern. Document the findings with photographs when possible or draw a sketch showing the area affected by cracking. Document the length, density, spacing and general location of the cracks relative to other surface conditions such as longitudinal and joint welds. 2.10.2 Notify Asset Integrity for assistance with repair options when SCC is found or suspected. 2.10.3 If SCC is discovered on Assets covered by the mitigation plan, refer to the ORA process manual decision tree prior to evaluating and repairing. 2.10.4 Document whether or Not SCC was discovered on Pipeline Maintenance Report. Evaluate and Select Repair Options for Selective Seam Corrosion (SSC) 2.11.1 Examine pipe for Selective Seam Corrosion (SSC) by evaluating the longitudinal seam weld for localized corrosion located along the bond line of low frequency electric resistance welding (LR-ERW) and Electric Flash Welding (EFW) piping, that leads to the development of a wedge shaped groove that is often filled with corrosion products. Document the findings with photographs when possible or draw a sketch showing the area affected by selective seam corrosion. 2.11.2 Notify Asset Integrity for assistance with repair options when SSC is found or suspected. 2.11.3 Document whether or Not SSC was discovered on the Pipeline Maintenance Report. Evaluate and Select Repair Options for Hard Spots 2.12.1 Measure hard spot area (the length and circumference) and map the hardness using calibrated portable testing equipment. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 5 of 16 2.13 2.14 2.15 2.12.2 Measure the hardness and make a sketch showing the hardness distribution. Use the following criteria when evaluating hard spots: Repair all hard spots when the maximum hardness exceeds Rockwell C 35. Refer to Paragraph 2.16 of this procedure for hard spot repair methods and options. Evaluate and Select Repair Options for Buckling/Ripples/Wrinkles 2.13.1 Notify Asset Integrity for assistance with repair criteria and repair methods and options. 2.13.2 Refer to Paragraph 2.13 of this procedure for buckling repair methods and options. Evaluate and Select Repair Options for Long Seam and Pipe Body Cracks 2.14.1 Examine pipe for cracking by non-destructive testing and magnetic particle inspection of the surface in the area of concern. Document the findings with photographs when possible or draw a sketch showing the area affected by cracking. Document the length, density, spacing and general location of the cracks relative to other surface conditions such as longitudinal and joint welds. 2.14.2 Refer to Table 1 of this procedure for crack in pipe body or weld seam for repair methods and options. Repair Methods and Options for Features or Defects 2.15.1 Refer to the chart below for evaluating repair options. Under special circumstances, the Manager of Asset Integrity can approve deviations from the approved/preferred repair methods listed in the following chart. Table 1 Defect Type Re-Coat Grind /Sand Repair Method Type “A” Type “B” Bolt On Composite Cut Out HCA Immediate Condition Metal loss >80% (external) Assets Covered by Mitigation Plan >70% N N N X T N O Metal loss >80% (internal) Assets Covered by Mitigation Plan >70% N N N O T N X PBURST < PDPP at location of anomaly (external) N N O X T O O PBURST < PDPP at location of anomaly (internal) N N N X T N O Dents above 4:00 and 8:00 with any indicated metal loss, cracking, or stress riser N N N X T N O <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 6 of 16 Repair Method Defect Type Re-Coat Grind /Sand Type “A” Type “B” Bolt On Composite Cut Out (See Paragraph 2.6.2) Dents above 4:00 and 8:00 with a depth >6% of nominal pipe diameter (See Paragraph 2.6.2) N N N X T O O HCA 60-Day Condition Dents above 4:00 and 8:00 with a depth>3% of nominal pipe diameter (>0.250” in depth for a pipeline diameter 2% of nominal pipe diameter (>0.250” in depth for a pipeline diameter 2% of pipeline diameter (>0.250” in depth for a pipeline diameter 6% of pipeline diameter (See Paragraph 2.6.2) N N N X T O O PSAFE>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 7 of 16 Repair Method Defect Type Re-Coat Grind /Sand Type “A” Type “B” Bolt On Composite Cut Out PSAFE12.5% nominal wall thickness N N N X T N O Other Conditions N N N X T N O Leaking defect Metal loss <12.5% nominal wall thickness X N N N N N N Non-Injurious Planar Laminations X N O O T N O Sloping Laminations N N N X T N O Bulging Laminations N N N X T N O Surface Breaking Laminations N N N X T N O Hydrogen Blisters N N N X T N O Laminations interacting with Deformations N N N X T N O Arc burn N X N O N N O Hard spot N N O X N N N Gouges or grooves <12.5% nominal wall thickness X X Buckling N O Repair by cutout, pumpkin, Type B sleeve, or call Asset Integrity for assistance N N N SCC suspected Call Asset Integrity for assistance Leaking mechanical (Dresser) coupling Repair by tightening, using housing (pumpkin), or cutout Mechanical leaks (valves and fittings) Repair in accordance with manufacturer’s guidelines or cutout <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 8 of 16 Repair Method Defect Type Re-Coat Grind /Sand Type “A” Type “B” Bolt On Composite Cut Out and replace 2.16 2.15.2 This table outlines the approved/preferred method (X), optional (O), and temporary onshore or permanent offshore (T) methods of repairing imperfections or defects. The methods that are not permitted (N) are also indicated. The optional methods listed do not represent all optional methods but identify normally accepted options. A temporary repair may be made using any method deemed suitable using sound engineering judgment. For detailed information on repair methods, refer to Paragraph 2.17 of this procedure. General Notes on Repair Methods 2.16.1 Defects repaired by grinding and/or sanding, installing a type “A” sleeve, type “B” sleeve, composite reinforced sleeve or replacing the affected pipe as a cylinder are all permanent repairs. Bolt-on or mechanical repair clamps used onshore are considered temporary repairs therefore; replace or upgrade them with a permanent repair as soon as feasible or with approval of the Manager, Asset Integrity, a properly welded mechanical or bolt-on clamp is considered a permanent repair for onshore applications. 2.16.2 When practical, repair defects by sleeving. There are two normally used methods of sleeving non-leaking defects: type “A” and type “B” sleeve. Base the decision to use one type over the other on the specific field circumstances and Table 1 2.16.3 2.16.4 2.16.5 2.16.6 Type “A” full encirclement welded steel sleeve can be used to repair defects. This sleeve cannot be used on leaking defects or to provide longitudinal reinforcement to the pipeline. Refer to Paragraph 2.17.2 for detailed information about installing type “A” sleeves. Repair leaking defects by sleeving with a type “B” sleeve when practical. Type “B” sleeves require welding on the pressurized pipe and should not be used to repair other defects except under special circumstances. Refer to Paragraph 2.17.3 for detailed information about installing type “B” sleeves. Repair of leaking defects caused by isolated corrosion may be made by installing a bolt-on leak clamp (On-Shore Temporary) or a type “B” sleeve. Use composite reinforcement sleeves to repair defects that have been ground out, were caused by corrosion or dents on low stress pipelines without scratches. CAUTION: Do not use composite sleeves to repair leaking defects or cracking. Refer to paragraph 2.17.4 for details. 2.16.7 2.16.8 Repair submerged pipelines in navigable waters containing leaking defects by mechanically applying a full encirclement sleeve or by installing a new section of pre-tested pipe. Repair any defect by removing the defective component (valve, fitting, etc.) or a <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 9 of 16 cylinder of pipe containing the defect and installing a new component or cylinder of pipe. 2.16.9 Patches are not an approved repair method. 2.17 Repair Procedures 2.17.1 Repair defect by grinding and/or sanding, as follows CAUTION: Prior to performing any grinding or sanding on a live line, evaluate the defect to be repaired. If it is estimated that the defect is potentially greater than 10% of the nominal wall thickness, do not perform any grinding or sanding operations and immediately refer Table 1 to determine the appropriate repair method, such as installing a sleeve. 2.17.2 2.17.1.1 Remove the defect by grinding and/or sanding. After grinding or sanding, if the remaining wall thickness is less than 88% of nominal, reevaluate the integrity of the pipeline and grind area using RSTRENG (Refer to RSTRENG Analysis of Corrosion) or KAPA and install a reinforcing sleeve if necessary. The transition from the area where the defect was removed to the surrounding undisturbed material shall be smooth. 2.17.1.2 2.17.1.3 Nondestructively inspect all areas where defects have been removed by grinding, using magnetic particle or dye penetrant inspection method to ensure the entire defect has been removed. During NDT, pay particular attention to any indications of cracking. If the remaining wall thickness passes RSTRENG calculations, the area does not require sleeving and may be properly cleaned and recoated. 2.17.1.4 If the remaining wall thickness is less than required by RSTRENG calculation, perform a repair. 2.17.1.5 The area does not require blend grinding or sanding when the defect requires type “A” or type “B” sleeving. Repair Defect Using a Type “A” Sleeve (Non-pressure Containing), as Follows 2.17.2.1 Prepare the pipeline to install the type “A” sleeve by removing all of the coating and thoroughly power brush or blast cleans the pipe surface in the area the sleeve will cover. 2.17.2.2 2.17.2.3 2.17.2.4 2.17.2.5 Fabricate or obtain a sleeve with the same or greater overall strength (wall thickness x yield strength) as the pipeline being repaired. Refer to Specification 101—Maintenance Welding (Excluding Ethylene Pipelines) Attachment A for details. Use a sleeve that is at least 4 inches in length. Ensure that the sleeve covers the defect(s) plus a minimum of 2" past the defect(s) on each end. Refer to Specification 101—Maintenance Welding (Excluding Ethylene Pipelines) for design details. Clean the inside and outside surface of the sleeve by thoroughly power brushing or abrasive blasting. Apply a hardenable filler material such as an epoxy in dents, corrosion pits, and/or adjacent to the long seam of the pipe to <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 10 of 16 2.17.3 completely fill void areas before installing the sleeve. 2.17.2.6 Apply sleeve with backing strip to pipeline ensuring it is tight. The effectiveness of the sleeve depends on its snugness around the pipe. 2.17.2.7 Apply the sleeve to pipeline ensuring a snug fit. Weld per Specification 101—Maintenance Welding (Excluding Ethylene Pipelines) and the specified welding procedure. 2.17.2.8 Seal the ends of the steel sleeve with a mastic bar, then a shrink sleeve and coat the exterior of the sleeve following Coatings— Selection, Applications And Maintenance. Repair Defect Using a Type “B” Sleeve (Pressure Containing), as follows: 2.17.3.1 Prepare the pipeline to install the type “B” sleeve by removing all the coating and thoroughly power brush or blast clean the pipe surface in the area the sleeve will cover. 2.17.3.2 2.17.3.3 2.17.3.4 2.17.3.5 2.17.3.6 2.17.3.7 2.17.3.8 Fabricate or obtain a sleeve with the same or greater overall strength (wall thickness x yield strength) as the pipeline being repaired. Refer to Specification 101—Maintenance Welding Attachment A for details. Use a sleeve that is at least four inches in length. Ensure that the sleeve covers the defect(s) plus a minimum of 2" past the defect on each end. Type B sleeves may be used for leaking or non-leaking defects including circumferentially oriented defects. When multiple sleeves are used, a Type B sleeve should not be terminated within one-half pipe diameter or 4 inches from a girth weld whichever is greater. The distance between sleeves should be at least one pipe diameter. Separated sleeves may be spaced less than one pipe diameter apart if joined by a welded bridging sleeve or made continuous by butt-welding them together. When installed at a non- leaking defect, a Type B sleeve may be installed in a manner that reduces the hoop stress in the carrier pipe. Methods for accomplishing this include lowering the pressure before the sleeve is installed, applying external mechanical force, or preheating the sleeve to facilitate a “shrink-fit.” Inspect the full circumference of the pipeline where the sleeve ends are to be welded to the pipeline using an ultrasonic thickness instrument and/or a magnetic particle inspection technique. Ensure there are no surface cracks, laminations or thin wall that could affect the integrity of the weld or sleeve. Clean the inside and outside surface of the sleeve by thoroughly power brushing or abrasive blasting. Apply a hardenable filler material such as an epoxy in dents, corrosion pits, and/or adjacent to the long seam of the pipe to completely fill void areas before installing the sleeve. Apply the sleeve with backing strip to pipeline ensuring a snug fit. Weld per Specification 101—Maintenance Welding (Excluding Ethylene Pipelines) and the specified welding procedure. Nondestructively test the completed longitudinal groove weld and <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 11 of 16 2.17.4 2.17.5 2.17.6 circumferential fillet welds in compliance with Specification 101— Maintenance Welding (Excluding Ethylene Pipelines). 2.17.3.9 Coat the exterior of the sleeve with primer and RD-6 Tapecoat following Coatings—Selection, Applications and Maintenance. Repair Defect Using an Approved Composite Reinforced Sleeve 2.17.4.1 Do not use a composite sleeve to repair leaks, cracks, or weld defects. Refer to Table 1 for specifics. 2.17.4.2 2.17.4.3 A qualified person(s) must install composite sleeves. Prepare the pipeline to install the composite reinforced sleeve(s) in accordance with the manufacturer's specifications. Usually abrasive blasting is required. 2.17.4.4 Install the composite sleeve per manufacturer’s specific requirements and specifications. 2.17.4.5 Install metallic (Caron Steel) banding at one-foot intervals on the sleeve for the purpose of ILI tool identification. 2.17.4.6 Coat the exterior of the sleeve with primer and RD-6 Tapecoat following Coatings—Selection, Applications and Maintenance. As an alternative, a “heat shrink sleeve” that fully encompasses the length and circumference of the Composite sleeve may also be used, if the ends of the composite sleeve are appropriately filled in order to prevent any air gaps. The heat shrink sleeve must extend past the ends of the Composite sleeve by at least 4 inches for proper encapsulation/coating of the Composite sleeve and cover adjacent bare steel areas, which may result in the use of multiple heat shrink sleeves. Repair Defects Using a Bolt-On Mechanical Clamp 2.17.5.1 Install properly designed full encirclement mechanical clamp by covering the defect. 2.17.5.2 Follow all manufacturers’ instructions when installing mechanical clamp. 2.17.5.3 Replace mechanical clamps with a permanent repair as soon as feasible. Properly welded mechanical clamps are considered permanent repairs for onshore applications, upon approval by the Manager of Asset Integrity. 2.17.5.4 Weld + Ends or similar compression type fittings shall not be used to join pipe together without a written job specific installation procedure including reviewing and following manufactures procedures to ensure correct installation and other necessary safety measures for safe and reliable operation of the pipeline system. Call Manager of Asset Integrity for further guidance, if necessary. 2.17.5.5 Coat the exterior of the sleeve with primer and RD-6 Tapecoat following Coatings—Selection, Applications and Maintenance. Repair Defects by Cutting Out a Cylinder Of Pipe and Replacing it with New Pipe 2.17.6.1 2.17.6.2 Prior to cutting or welding check for LEL’s with Haz Gas detector Remove pipe or fitting containing the defect as a cylinder. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 12 of 16 2.17.6.3 2.17.6.4 2.17.6.5 2.17.6.6 Ensure any removed section has had adequate time for ventilation prior to cutting and transporting. Whenever possible, ensure that the replacement pipe has a length of not less than one-half the pipe diameter or not less than 3 inches whichever is greater. The replacement pipe, fitting, or valve shall have a greater than or equal design pressure as the existing pipe or fitting and shall be pre- tested. Pipe ends should be checked for magnetism prior to welding. If welding quality becomes an issue, steps to reduce or temporarily eliminate the Magnetic field on the pipe ends should be taken. NOTE: Prior to installing pretested pipe, ensure the appropriate records (i.e., MTRs, Hydrostatic Test Records) have been located, thoroughly reviewed, and verified accurate. 2.17.6.7 Ensure LEL’s have been removed from work area prior to installing new pipe 2.17.6.8 Install the replacement material in accordance with Specification 101, Maintenance Welding (Excluding Ethylene Pipelines). 2.17.6.9 Coat the exterior of the new and adjacent pipe (as needed) with primer and RD-6 Tapecoat following Coatings—Selection, Applications and Maintenance. 2.17.7 Repair defects by Recoat 2.17.7.1 Prepare the pipeline to install coating by removing all of the existing coating and thoroughly power brush or blast clean the pipe surface in the area of the recoat. 2.18 2.17.7.2 Coat the exterior of the sleeve with primer and RD-6 Tapecoat following Coatings—Selection, Applications and Maintenance. 2.17.7.3 After application of the RD-6 coating, install metallic banding (Carbon Steel) four inches from each end of the recoat area and coat the metallic bands with RD-6 coating. Document all repairs on the Pipeline Maintenance Report and ensure a copy is sent to the Records Coordinator in Tulsa. 3.0 DEFINITIONS 3.1 3.2 Arc Burn: Localized points of surface melting caused by arcing between electrode or ground and pipe surface. Bolt-On Fitting: Any onshore or offshore attachment to a pipeline that is attached via bolts. 3.3 Composite Reinforcement Sleeve: A nonmetallic sleeve used to repair some nonleaking 3.4 pipeline defects. Dent: An area of the pipe where the local curvature is no longer part of a circular arc having the same radius as the pipe. The local indentation shall be considered a dent if the measured distance between the lowest point of the indentation and a prolongation of the original contour of the pipe exceeds the value equivalent to 2% of the pipe’s diameter. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 13 of 16 3.5 Hard Spot: Localized spot where the hardness of the material is greater than surrounding material. 3.6 MIC: Microbiologically induced corrosion. 3.7 RSTRENG: A modified corrosion assessment criterion to predict a minimum failure pressure based on detailed corrosion depth and length measurements. 3.8 3.9 Stress Corrosion Cracking (SCC): Cracking which results from stress induced corrosion. Selective Seam Corrosion (SSC): Localized corrosion located along the bond line of low-frequency electric resistance welding (LR-ERW) and electric flash welding (EFW) piping, that leads to the development of a wedge shaped groove that is often filled with corrosion products. 3.10 Type A Sleeve: A band of steel that encircles the pipeline and is not welded to the pipeline. 3.11 Type B Sleeve: A band of steel that encircles the pipeline and is welded to a pipeline at the ends forming a pressure vessel and is normally used for a leaking defect but may be used for non-leaking defects under special circumstances. 3.12 Wedding Band: A short (Usually 6 to 12 inches in length) Type B Sleeve that encompasses a joint weld. 3.13 Weld Defect: A weld imperfection located in a seam or girth weld. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE 7.01–ADM–001 Asset Integrity 01/01/12 Revision: 9 Page 14 of 16 System Integrity Plan Change Log Date Change Location Change By 2.2 Clyde Clausen Mike Pearson 2.12 Clyde Clausen Mike Pearson 2.3 Clyde Clausen Mike Pearson 07/23/02 Various Clyde Clausen Mike Pearson Various Clyde Clausen Mike Pearson 2.6.3 Clyde Clausen Mike Pearson 08/08/02 2.4.3 & 2.13.1 Clyde Clausen Mike Pearson 11/21/03 All Clyde Clausen Mike Pearson 12/22/03 1.0 Clyde Clausen Mike Pearson 12/22/03 2.1.2 Clyde Clausen Mike Pearson 12/22/03 2.1.3 Clyde Clausen Mike Pearson 12/22/03 2.1.4 Clyde Clausen Mike Pearson 12/22/03 2.1.5 Clyde Clausen Mike Pearson 12/22/03 2.2.3 Clyde Clausen Mike Pearson 12/22/03 2.6 Clyde Clausen Mike Pearson 12/22/03 2.12 Clyde Clausen Mike Pearson 12/22/03 2.14.7 Clyde Clausen Mike Pearson 12/22/03 2.15.4.5 Clyde Clausen Mike Pearson 12/22/03 2.15.6.4 Clyde Clausen Mike Pearson 11/21/04 All Clyde Clausen Mike Pearson 9/9/04 2.7 Clyde Clausen Mike Pearson 9/9/04 2.14.3.2 Clyde Clausen Mike Pearson 9/9/04 2.14.3.3 Clyde Clausen Mike Pearson 9/9/04 2.14.6.2 Clyde Clausen Mike Pearson 9/9/04 2.14.6.3 Clyde Clausen Mike Pearson 9/9/04 2.14.6.4 Clyde Clausen Mike Pearson Brief Description of Change Detailed how to perform a visual assessment. Added a repair method to the table for Natural Gas. Provided details on reference sections. Replaced Paragraph 6.12 reference with 2.13. Paralleled repair language with the Welding manual to alleviate conflicts and inconsistencies. Added section for dent repair clarification. Added repair method deviation approval process. Annual Review Deleted Purpose of this procedure is to establish, inserted analysis and repair of Deleted Pump piping and Tanks Deleted DOT Part 195 governs the repairs Williams utilizes for certain pipeline repairs. These regulatory parts and subparts may be referenced within this document. Added OQ qualification paragraph Added live line welding paragraph Deleted paragraph, and re‐worded Deleted Caution Note Become 2.11. Rewrote repair options for buckling/ripples Become 2.13.7. Deleted offshore pipeline Become 2.14.4.5. Added (Carbon Steel) Become 2.14.6.4. Modified Note to read ensure the appropriate records (i.e. MTRs, Hydrostatic Test Records) have been located, thoroughly reviewed, and verified accurate. Annual Review Modified Paragraph within Note Deleted Ethylene Pipelines Modified Paragraph for changes due to new regulated requirements Modified Paragraph for changes due to new regulated requirements Modified Paragraph Added new Paragraph <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE Asset Integrity 01/01/12 11/20/05 All Clyde Clausen Mike Pearson 01/01/06 4.4 Clyde Clausen Mike Pearson 01/01/06 2.6.2 Clyde Clausen Mike Pearson 01/01/06 2.12.1 Clyde Clausen Mike Pearson 01/01/06 References Mike Pearson 1/26/06 2.14.6.3 Clyde Clausen Mike Pearson 1/26/06 2.14.6.5 Clyde Clausen Mike Pearson 2/15/06 2.1.5 Clyde Clausen Mike Pearson 11/16/06 All Clyde Clausen Mike Pearson 11/16/06 2.3.3.7 Clyde Clausen Mike Pearson 11/16/06 2.9.3 Clyde Clausen Mike Pearson 11/16/06 2.10 Clyde Clausen Mike Pearson 11/16/06 4.9 Clyde Clausen Mike Pearson 1/10/07 2.2.4 Clyde Clausen Mike Pearson 1/10/07 2.4.1 Clyde Clausen Mike Pearson 1/10/07 2.2.3 Clyde Clausen Mike Pearson 5/8/07 2.2.4 Clyde Clausen Mike Pearson 5/8/07 2.1.1 Clyde Clausen Mike Pearson 6/28/07 2.2.1 Clyde Clausen Mike Pearson 6/28/07 2.2.2 Clyde Clausen Mike Pearson 6/28/07 2.5.3 Clyde Clausen Mike Pearson 6/28/07 2.8.3 Clyde Clausen Mike Pearson 11/16/07 All Clyde Clausen Mike Pearson 4/01/08 2.2.1 Dennis Vasicek Clyde Clausen 4/01/08 2.2.2 Dennis Vasicek Clyde Clausen 4/01/08 2.2.3 Dennis Vasicek Clyde Clausen 7.01–ADM–001 Revision: 9 Page 15 of 16 Annual Review Added definition Minor modifications Incorporated HCA Repair Criteria removed Minor Modification to Paragraph‐ (Added Valve) Minor Modification to Paragraph‐ (Change Specification 100 to Specification 101) Removed Pressure reduction requirements from Paragraph. Annual Review Added 2.3.3.7 Added Paragraph Added 2.10 Added Definition Added precaution for cleaning pipe. Added precaution for cleaning pipe to existing paragraph. Added Paragraph to comply with 195.422. Added Paragraph to comply with 195.422. Removed reference to MPC Added Paragraph Added Paragraph for pressure reductions for defects that can’t be repaired in 8 hours. Added Paragraph for non‐destructive testing repairs that have been removed by grinding/sanding. Added reference to paragraph Conducted Annual Review Added: All exposed bell and spigot girth welds shall be reinforced by means of sleeving Added: If needed (when pipe is not resting on the ground) the pipe should be adequately supported prior to backfilling. Consideration should be given to using dirt plugs or sandbags at spacing intervals not to exceed 20 feet particularly in areas where additional weight has been applied by installation of sleeving Added: All exposed girth welds (including bell and spigot joints) shall be supported (supports to be placed on each side of the girth weld) via sandbags or equivalent settlement resistant supports prior to backfilling. <<>> Magellan Midstream Partners, L.P. PIPELINE DEFECT EVALUATION AND REPAIR PROCEDURE Asset Integrity 01/01/12 11/14/08 All Dennis Vasicek Clyde Clausen 12/18/08 2.1.3 Dennis Vasicek Clyde Clausen 12/18/08 2.2.5 Dennis Vasicek Clyde Clausen 12/18/08 2.3.1 Dennis Vasicek Clyde Clausen 12/18/08 2.3.4.10 Dennis Vasicek Clyde Clausen 12/18/08 2.13 Dennis Vasicek Clyde Clausen 12/18/08 2.16.3.8 Dennis Vasicek Clyde Clausen 8/21/09 All Clyde Clausen Doug Chabino 8/21/09 2.2.3 Clyde Clausen Doug Chabino 8/21/09 2.2.6 Clyde Clausen Doug Chabino 11/30/09 All Clyde Clausen Doug Chabino 11/30/09 2.16.5.4 Clyde Clausen Doug Chabino 11/30/09 2.16.6.1 Clyde Clausen Doug Chabino 11/30/09 2.16.6.3 Clyde Clausen Doug Chabino 11/30/09 2.16.6.7 Clyde Clausen Doug Chabino 9/3/10 2.1.2, 2.4.2, 2.16.1.1 Clyde Clausen Doug Chabino 9/3/10 2.9.3 Clyde Clausen Doug Chabino 9/3/10 2.14.1 Clyde Clausen Doug Chabino 9/3/10 All Clyde Clausen Doug Chabino 9/1/11 All Clyde Clausen Doug Chabino 9/1/11 2.14.1 Clyde Clausen Doug Chabino 12/31/11 All 6/12/12 2.14 Table Clyde Clausen Doug Chabino 7.01–ADM–001 Revision: 9 Page 16 of 16 Conducted Annual Review Minor modification (installation of repairs, i.e. composite/clamps) to paragraph Minor Modification to paragraph Added paragraph to photograph repair site prior to removing coating Added Section for Cracks Added Section for Cracks Minor Modifications to paragraph Conducted Annual Review, See modifications below Added not to exceed 5’ to paragraph Added requirement to NDE pipeline defects that are not repaired by means of sleeving or pipe replacement Removed reference to contact Pipeline Integrity and added Asset Integrity Added Paragraph Added Paragraph Added Paragraph Added Paragraph Added utilization of KAPA for conducting pressure assessments Added new paragraph to refer to the ORA process manual decision tree if SCC is discovered on assets covered by the mitigation plan Added Immediate repair criteria for Assets covered by the mitigation plan to repair table Conducted Annual Review Conducted Annual Review Added Lamination Repair Options to Table 2012 Annual Review complete Modified Lamination Repair Table <<>> Magellan Midstream Partners, L.P. INTEGRITY TESTING AND REHABILITATION SIP–ADM–7.03 Asset Integrity 01/01/10 Revision: 6 Page 1 of 4 1.0 OBJECTIVE 1.1 The objective of this initiative is to maintain asset integrity by establishing consistent processes for integrity testing. 2.0 DESCRIPTION 2.1 The Company utilizes pressure testing, in‐line inspection (ILI), or a combination thereof, to assess and validate the physical integrity of its pipeline system. In addition to standardized pipeline construction and maintenance practices, the Company adheres to a comprehensive Integrity Management Program that incorporates the use of appropriate integrity testing technologies and rehabilitation practices in order to assist in identifying, understanding and controlling pipeline risk and integrity threats. 2.2 A priority rating system based on relative risk is established to select pipeline segments for integrity testing schedules. The frequency of reassessments will be determined by the processes established within the Integrity Management Plan. 3.0 STANDARDS 3.1 The Project Manager shall: 3.1.1 Consult with the Pipeline or Facility Risk Engineer, as appropriate for type of asset, to ensure review of applicable asset integrity factors is completed prior to testing. 3.1.2 Coordinate the execution of pressure testing projects in accordance with the Pressure Testing Procedure. 3.1.3 Complete the appropriate Hydrostatic Test Documentation (Hydrostatic Test Documentation for Liquids) and remit with the required attachments to the Records 3.1.4 Coordinator within thirty days of the pressure test. Coordinate the execution of ILI projects in accordance with the In‐Line Inspection Procedure. 3.2 The Records Coordinator shall: 3.3 3.4 3.2.1 Review pressure test documentation for thoroughness and adequacy, and retain in Asset Integrity file repository for useful life of the facillity. 3.2.2 Notify the Pipeline Surge Engineer following receipt of pressure test records. 3.2.3 Input the new pressure test data and the new calculated Maximum Operating Pressure (MOP) information into the Hydrostatic Test Database within 60 days following receipt of the pressure test records. The Manager of Asset Integrity Engineering shall: 3.3.1 Coordinate changes to system pressure settings with Operations Control and/or Operations Manager as applicable. The Pipeline Integrity Supervisor shall: 3.4.1 Determine the effect(s) on the MOP of the corresponding asset(s) following notice of receipt of pressure test documentation. 3.4.2 Coordinate the execution and documentation of integrity testing and rehabilitation <<>> Magellan Midstream Partners, L.P. INTEGRITY TESTING AND REHABILITATION SIP–ADM–7.03 Asset Integrity 01/01/10 Revision: 6 Page 2 of 4 3.4.3 3.4.4 plans of existing assets. Notify the Manager of Asset Integrity Engineering of any required adjustments to system operating pressures due to integrity testing results. Maintain and annually review the In‐Line Inspection Procedure and Pressure Testing Procedure for use on Company operated assets. 3.5 The Pipeline Integrity Engineer shall: 3.5.1 Immediately evaluate reports from the ILI vendor and generate a Dig List in accordance with In‐Line Inspection Procedure. 3.5.2 Notify the Pipeline Integrity Coordinator that the Dig List has been developed in order to initiate project execution of feature investigations and rehabilitation, as required. <<>> Magellan Midstream Partners, L.P. INTEGRITY TESTING AND REHABILITATION SIP–ADM–7.03 Asset Integrity 01/01/10 Revision: 6 Page 3 of 4 System Integrity Plan Change Log Date Change Location Change By Approved By Brief Description of Change 10/16/03 All Clyde Clausen Michael Pearson 10/23/03 2.1 & 2.2 Clyde Clausen Michael Pearson 10/23/03 3.2 Clyde Clausen Michael Pearson 10/23/03 3.4.2 Clyde Clausen Michael Pearson 10/23/03 3.5 Clyde Clausen Michael Pearson 10/23/03 3.7.2 Clyde Clausen Michael Pearson 9/29/04 All Mike Pearson Michael Pearson 9/29/04 3.13 Clyde Clausen Michael Pearson 9/29/04 3.3.1 Clyde Clausen Michael Pearson 9/29/04 3.4.3 Clyde Clausen Michael Pearson 10/16/05 All Clyde Clausen Michael Pearson 10/16/06 All Clyde Clausen Michael Pearson 10/16/06 Entire Document Clyde Clausen Michael Pearson 10/16/06 3.1.2 Clyde Clausen Michael Pearson 10/16/06 3.1.4 Clyde Clausen Michael Pearson 10/16/06 3.2.1 Clyde Clausen Michael Pearson 10/16/06 3.2.2 Clyde Clausen Michael Pearson 10/16/06 3.3.1 Clyde Clausen Michael Pearson 10/16/06 3.3.2 Clyde Clausen Michael Pearson 10/16/06 Clyde Clausen Michael Pearson 3.3.2 10/16/06 3.4.4 Clyde Clausen Michael Pearson 10/16/06 Clyde Clausen Michael Pearson 3.5 10/16/06 3.6 Clyde Clausen Michael Pearson 09/11/07 All Clyde Clausen Michael Pearson 9/11/07 3.2.2 Michael Pearson Conducted 2003 Annual Review, (See Change Log) Minor modifications to Paragraph Inserted responsibilities of Pipeline Integrity Coordinator. Added new responsibility to Pipeline Integrity or Facility Supervisor. Added Operations Control Manager responsibilities Added new responsibility to Pipeline Integrity Engineer. Conducted 2004 Annual Review, (See Change Log) Changed 2 weeks to thirty days Added responsibility to Asset Integrity Manager Added new responsibility to Pipeline Integrity or Facility Supervisor. Conducted 2005 Annual Review‐ (No Changes) Conducted 2006 Annual Review‐ (See Change Log) Revised job titles to reflect recent organizational changes. Minor Modification to Paragraph Minor Modification to Paragraph Minor Modification to Paragraph Minor Modification to Paragraph Deleted Paragraph Moves up and becomes 3.3.1 Moved responsibility under Pipeline Integrity/ Risk Engineering Supervisor: Determine the effect(s) on the MOP of the corresponding asset(s) following notice of receipt of pressure test documentation Minor Modification to Paragraph Deleted Operations Control Manager Requirements as it is covered within 7.07 Operating Pressures. Deleted Asset Integrity Analyst Responsibilities Conducted 2007 Annual ,(See Change Log) Deleted Risk Engineer and Inserted Pipeline Surge Engineer. Deleted two weeks. <<>> Magellan Midstream Partners, L.P. INTEGRITY TESTING AND REHABILITATION SIP–ADM–7.03 Asset Integrity 01/01/10 Revision: 6 Page 4 of 4 9/11/07 3.3 Clyde Clausen Michael Pearson 9/11/07 3.4 Clyde Clausen Michael Pearson 9/11.07 3.4.3 Clyde Clausen Michael Pearson 1/1/09 8/21/09 All Clyde Clausen Doug Chabino 8/21/09 3.1.3 Clyde Clausen Doug Chabino 8/21/09 Section 4 Clyde Clausen Doug Chabino 01/01/11 Deleted Director, Inserted Manager Asset Integrity Engineering Deleted Risk Engineering and made sole responsibility of Pipeline Integrity Supervisor Deleted Director and inserted Manager Asset Integrity Engineering 2008 annual review complete – no changes Conducted Annual Reivew Removed Gas Reference Removed Gas Link Reviewed, no changes <<>> Magellan Midstream Partners, L.P. PRESSURE TESTING 7.03–ADM–001 Asset Integrity 01/01/12 Revision: 13 Page 1 of 11 1.0 OBJECTIVE 1.1 The objective of this procedure is to establish the requirements, process, and documentation for pressure testing. 2.0 SCOPE 2.1 2.2 This procedure is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be utilized in whole or part on non‐jurisdictional assets as deemed appropriate. Consent Decree Specific: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, the Company’s Consent Decree Pipeline Systems operate under the requirements of the Consent Decree. For the period of the Consent Decree, these systems will follow the applicable process and procedures identified within the Inspection and Maintenance Manuals (refer to Consent Decree for applicable programs). Exceptions and/or variations to these processes are identified in the System of Operating Manuals‐ Disclaimer. 3.0 PROCEDURE 3.1 General 3.1.1 3.1.2 3.1.3 3.1.4 3.1.5 3.1.6 3.1.7 Pressure tests are planned and conducted in order to meet stated acceptance criteria and pressure test objectives. Each new pipeline system and each pipeline system in which pipe has been relocated or replaced, or that part of a pipeline system that has been relocated or replaced (tie‐ins), must be pressure tested without leakage. In‐place pressure testing is not required for repairs if the individual joints of the pipe have been previously tested to the applicable requirements and documentation in accordance with the requirements outlined in Section 3.10 Records is available. Pressure tests must include all pipe and attached fittings, including components. Pressure testing is not required for a single new component other than pipe that is the only item being added or replaced if the manufacturer certifies that either: 3.1.4.1 The component was hydrostatically tested at the factory; or 3.1.4.2 The component was manufactured under a quality control system that ensures each component is at least equal in strength to a prototype that was hydrostatically tested at the factory. All hydrostatic test failures shall be removed from the pipeline and consideration shall be given to submit the failed section for metallurgical review per Analysis of Pipe Cutouts. Results of the metallurgical review will be integrated into the overall Integrity Management Plan. Upon completion of a successful pressure test, prior to relieving test pressure contact the Pipeline or Facility Integrity Engineer for hydrostatic test acceptance approval. Upon completion of a successful pressure test of a line segment, in addition to the bi‐ annual requirement, Operations should consider running cleaning pigs within 2 months after startup. 3.1.8 Test Medium 3.1.8.1 For Liquid Pipelines, water shall be used as the test medium except as <<>> Magellan Midstream Partners, L.P. PRESSURE TESTING 7.03–ADM–001 Asset Integrity 01/01/12 Revision: 13 Page 2 of 11 provided in 49 CFR 195.306. 3.1.9 The Project Manager shall: 3.1.10 3.1.11 3.1.9.1 Ensure the pipeline is properly cleaned, filled, tested, de‐watered; test water disposed of, and dried. Drawings and Right‐of‐Way and Permit Stipulations should be referenced for special requirements. 3.1.9.2 Special consideration shall be given to the injection of corrosion inhibitors to prevent internal corrosion to preserve the line in the event that the start‐up or introduction of product into the line is delayed after completion of dewatering and drying of the line. Consult with the Manager of Asset Integrity and Corrosion Control Specialist to determine necessary mitigation measures and timing of implementation 3.1.9.3 Complete all required test records including charts, reports, forms, and calculations. The Contractor testing supervisor and the Company Inspector shall sign the test chart and the hydrostatic test log upon successful completion of a hydrostatic test. All test records along with test equipment calibration records and completed calculations shall be sent to Asset Integrity Engineering promptly for approval and filing. 3.1.9.4 Consider if anti‐freeze, methanol, glycol, corrosion inhibitors, biocides or other chemicals are needed. Consult the Supervisor, Asset Integrity for specifics and notify the Environmental Specialist prior to applying for a hydrostatic test discharge permit if additives are to be used. 3.1.9.5 Determine the test method, test pressure, and the test duration of pipelines and complete the proper documentation (Hydrostatic Test Form) to ensure the desired MAOP or MOP is achieved. The MAOP/MOP documentation shall be retained for the useful life of the pipeline. Pipeline taps to vent air are permitted but the pipeline should only be excavated and exposed to install a tap after alternative methods have been evaluated and ruled out. If pipeline taps to vent air are required, consult with Manager of Asset Integrity for approval and to initiate a detailed work plan to include involvement of all key stakeholders. Prior to excavating the pipeline to install a tap, a detailed work plan shall be written. The plan shall consider a detailed review of the following, but not limited to; original construction records, previous ILI logs, leak history, drawings and alignment sheets, line fill data, and maintenance reports. Land topography must be evaluated and a determination made whether there is the potential for existing inherent mechanical stresses in the pipeline. This includes a review of previous work activity or previous events in the area. If the determination is made that there could be inherent mechanical stresses in the pipeline due to topography or events mentioned above, then extra length and width of ditch shall be excavated in the vicinity of the planned tap to allow the pipe to flex and relieve existing stress. This guidance shall be provided in the detailed work plan. Taps on in‐service lines shall be piped to an atmospheric tank. If the pipeline is being tested to satisfy Integrity Management requirements, consideration should be given to conducting a spike test. 3.2 Responsibilities 3.2.1 Sponsor – Manager of Asset Integrity 3.2.2 Implementation <<>> Magellan Midstream Partners, L.P. PRESSURE TESTING 7.03–ADM–001 Asset Integrity 01/01/12 Revision: 13 Page 3 of 11 3.3 3.2.2.1 The Project Manager is responsible to ensure pipelines are tested to the proper pressure and for the required duration. 3.2.2.2 The Manager of Asset Integrity is responsible for audits. Hydrostatic Test Job Plan (prior to any testing activities) 3.3.1 The Project Manager shall: 3.3.1.1 Ensure a Test Job Plan is completed and followed. The Test Job Plan shall include, but not be limited to, the following information: 3.3.1.1.1 The schedule and sequence of cleaning, filling, testing, dewatering and drying the test sections, including which sections will be filled from or dewatered to adjacent sections 3.3.1.1.2 The location of test manifolds, fill‐water sources, de‐water areas, air compressors, pressure recorders, deadweights and temperature recorders 3.3.1.1.3 Fill‐meter types and quantities 3.3.1.1.4 Contractor shall provide containment structure material and design for pumps near streams and wetlands 3.3.1.1.5 Dewater structure material, design, discharge line size and type, maximum discharge rate. NOTE: Project Manager shall ensure discharge piping is designed for the expected discharge pressures and shall ensure discharge piping is anchored to prevent whipping in the event of failure. 3.3.1.1.6 3.3.1.1.7 3.3.1.1.8 3.3.1.1.9 3.3.1.1.10 3.3.1.1.11 Air compressor quantity and rating (c.f.m. at psig.) Quantity, model, range and accuracy for temperature recorders, pressure recorders, electronic pressure gauges, deadweight gauges and fill‐volume meters Types and quantity for each of the following: cleaning pigs, fill pigs, de‐water pigs and drying pigs Drying equipment, procedure and specified dew point, if required Contractor shall design and provide spill containment material and equipment at fill site Method to control speed of fill pig with back‐pressure to prevent acceleration on downhill sections. Ensure that necessary permits are obtained to complete the pressure test and identify who needs to be notified. 3.3.2 3.4 Safety 3.4.1 3.4.2 Pressure test shall be implemented by qualified personnel. Personnel safety and environmental impact shall be considered during the planning of a <<>> Magellan Midstream Partners, L.P. PRESSURE TESTING 7.03–ADM–001 Asset Integrity 01/01/12 Revision: 13 Page 4 of 11 pressure test project. 3.4.3 Persons not directly engaged in the testing operation shall remain out of the test area during testing. No work shall be permitted on the pipeline after 50  of test pressure is achieved. 3.4.4 Personnel, test trailer, pressure recorders and deadweight gauges shall be located a safe distance from the facility being tested. If the test manifold or facility contains a longitudinal seam, the test equipment shall be located on the side opposite the seam when possible. 3.4.5 Pipe, hose and fittings shall be manufactured to proper pressure rating and in good condition. Hoses and pipes shall be anchored to prevent whipping in the event of failure. 3.4.6 Prior to pressurization, the pipeline shall be completely backfilled except test‐header locations, pipeline valves, flanged or screwed connections, or any other locations where leakage could be expected or pipe that cannot be backfilled such as an existing span. 3.4.7 While separating and isolating piping for a hydrostatic test, consider the use of a solid blind flange without a tapped hole whenever possible. 3.4.8 Signs shall be installed and placed over the pipeline in critical areas notifying the public when testing is in progress. Individuals living in close proximity to the pipeline shall be notified prior to project implementation. 3.5 Special Equipment Requirements 3.5.1 The pipe temperature recorder shall be located in an insulated housing and the capillary line shall be insulated to the sensing bulb, which shall be taped to the pipeline after removal of the coating. The sensing bulb shall be installed an appropriate distance from the test header so as not to be affected by the temperature of the pressure water injected into the pipeline. For buried/underground pipelines, the line shall be excavated at a location with typical depth of cover for placement of the temperature sensing bulb. The pipeline will be backfilled and tamped around the sensing bulb. 3.6 Certification of Test Equipment 3.6.1 Consistent with the calibration requirements in API RP 1110 – Pressure Testing of Liquid Petroleum Pipelines, electronic pressure gauges or deadweight gauges shall be calibrated in accordance with NIST standards by an approved third‐party, within the previous 12 months. Certificates of calibration with instrument serial numbers must be reviewed prior to starting any testing. 3.6.2 Pressure recorders (continuous recording chart recorders) shall be calibrated immediately before each use (using the deadweight tester) or calibrated in accordance with the manufacturer’s recommendations. Certificates of calibration with instrument serial numbers must be reviewed prior to starting any testing. 3.6.3 An approved third party shall properly calibrate temperature recorders within the previous 12 months. Certificates of calibration with instrument serial numbers must be reviewed prior to starting any testing. 3.7 Filling for a Hydrostatic Test 3.7.1 Prior to filling each test section, the facility shall be checked carefully to ensure the facility is ready—including checking that pipe, hose, flange and fitting connections are <<>> Magellan Midstream Partners, L.P. PRESSURE TESTING 7.03–ADM–001 Asset Integrity 01/01/12 Revision: 13 Page 5 of 11 properly installed and block valves used for filling are in open position. Other valves that are part of the test but not used for fill connections should be in the half open position and plugged or blind‐flanged. TOR nipples that are installed with check valve plugs should have the check valve plugs removed and replaced with solid TOR plugs for the duration of the test. Upon completion of the test the TOR check valve plugs may be returned. 3.7.2 Filling shall be continuous from start of filling until test section(s) is/are completely filled. The Project Manager shall consider means to control the speed of the fill pig with back‐pressure to prevent acceleration on downhill sections. After test section(s) is/are filled, connections shall be checked for leaks with air vented as required. 3.8 Hydrostatic Testing 3.8.1 Project Manager shall initiate completion of Hydrostatic Test Documentation (Liquids) for liquid pipelines or Hydrostatic Test Documentation (Gas) taking into consideration pressure rating of pipe fittings, flanges, and valves; previous pressure test records; and appropriate design calculations. 3.8.2 If a pipeline segment is determined to be susceptible to longitudinal seam oriented failures and hydrostatic testing is the chosen integrity assessment, then a spike test shall be performed in addition to the normal test in accordance with 49 CFR 195 Subpart E. A spike test is generally conducted at a pressure of at least 1.39 x MOP for 10–30 minutes prior to the normal 49 CFR 195 Subpart E test. All pipeline hydrostatic test failures shall be removed from the pipeline and consideration shall be given to submit the failed section to a metallurgist for failure analysis and reporting. 3.8.3 The pipeline shall be tested for the duration and at the minimum test pressure identified in the Hydrostatic Test Documentation (Liquids) or Hydrostatic Test Documentation (Gas). Pressure tests must be maintained at or above the minimum test 3.8.4 3.8.5 3.8.6 3.8.7 3.8.8 pressure (equal to 125 percent or more of the MOP) for a minimum of four (4) continuous hours. If the tested pipeline segment cannot be visually inspected during the pressure test, an additional four (4) hours of testing is required. The test pressure during the additional four (4) hours may be reduced to a minimum of 110 percent of the desired MOP. Valves must be tested in the half‐open position to prevent seal damage. Below‐grade valves and flanged connections shall be considered for excavation Adequate time shall be allowed for temperature stabilization prior to starting testing unless circumstances dictate otherwise. Prior to start of testing, new charts shall be installed on the pressure and temperature recorders so that the full test is on the same chart. The Contractor shall record the time, pipe temperature, ambient temperature, dead‐weight pressure readings and the location of the dead‐weights (mile posts and engineering stations) on forms at testing start and as specified in Test Plan. Any volume of water added or drained to maintain test pressure must be measured accurately and volumes recorded along with time, pipe and ambient temperatures, if required by Test Plan. If the test pressure drops below the specified minimum at any time during the test, a determination shall be made regarding the existence of a leak. If the determination is made that a leak does not exist, the test section shall be re‐pressurized and the entire test restarted. <<>> Magellan Midstream Partners, L.P. PRESSURE TESTING 7.03–ADM–001 Asset Integrity 01/01/12 Revision: 13 Page 6 of 11 3.8.8.1 For pressure drops or losses that don’t fall below specified minimum test pressure requirements, determine if pressure losses correspond with measured temperature loss using industry accepted calculation method. 3.9 Crossings 3.9.1 Water, railroad, and highway crossing carrier pipe shall be hydrostatically pre‐tested for a minimum of 2 hours before installation, and again for 8 hours after pulled in place by boring process, except for in‐service pipelines in place. 3.10 Records 3.10.1 3.10.2 3.10.3 3.10.4 Upon completion of a successful hydrostatic test, the Pipeline or Facility Integrity Engineer shall conduct a final review of all pertinent records and documentation associated with the project per 3.10.3 and 3.10.4 of this section. Complete, signed original records shall be maintained for the useful life of the facility for each test. Handwritten records must be legible. Pressure recorder and temperature recorder charts shall provide the following information: 3.10.3.1 Company name 3.10.3.2 Test Supervisor and pipeline Contractor 3.10.3.3 Project name 3.10.3.4 AFE number 3.10.3.5 Test medium, source and quality 3.10.3.6 Facility tested (pipeline or fabricated assembly name) 3.10.3.7 Pipe outside diameter, wall thickness and grade 3.10.3.8 Beginning and ending milepost and engineering stations 3.10.3.9 Location of pipeline test section or final fabrication location (section, township, range, county and state) 3.10.3.10 Recorder location 3.10.3.11 Recorder model and serial number 3.10.3.12 Beginning time, date and test pressure 3.10.3.13 Ending time, date and test pressure 3.10.3.14 Signatures of Test Supervisor and Company Inspector Record packages for each pipeline test section shall include the following: 3.10.4.1 Test‐section profiles (where elevation differences in the section under test exceed 100 feet) with corrected manifold locations and test pressures. 3.10.4.2 Pipeline Facility Test Reports, signed by Test Supervisor and Company Inspector 3.10.4.3 Pressure and temperature recorder charts 3.10.4.4 Pipeline Failure Report and charts and photos of leaks and failures 3.10.4.5 Hydrostatic Test Documentation form Hydrostatic Test Documentation <<>> Magellan Midstream Partners, L.P. PRESSURE TESTING 7.03–ADM–001 Asset Integrity 01/01/12 Revision: 13 Page 7 of 11 (Liquids) or Hydrostatic Test Documentation (Gas) completed and signed 3.11 by the Project Manager, Contract Test Supervisor, and Test Inspector. 3.10.4.6 Certifications for all temperature and pressure recorders and gauges 3.10.4.7 All records shall be sent to Pipeline Integrity for approval and retention for the useful life of the tested segment. Completion of Pressure Test Assessment 3.11.1 A Pressure Test Integrity Assessment will be considered complete and accepted upon completion of a successful pressure test without leakage meeting the requirements set forth within Section 3.8 and 3.10 of this procedure. 3.12 Dewatering 3.12.1 Block valves shall be in the fully open position for de‐watering. Water shall be drained from the valve bodies after the dewatering is complete. 3.12.2 At the end of a successful test, the pipeline pressure shall be lowered by slowly releasing water while maintaining a positive pressure at the highest point of the test section to prevent air‐lock. Water shall be displaced using pigs driven either by air or nitrogen. Refer to Section 3.7 regarding hydrostatic test water discharge piping. 3.12.3 The Project Manager shall ensure water is discharged as outlined in Right‐of‐Way and Permit Stipulations. 3.12.4 The Project Manager shall consider using hammer unions on high‐pressure hoses connected to frac tanks and/or vacuum trucks during the dewatering process. 3.12.5 Dewatering of the pipeline shall be complete when no free water is received with the running of a new pig through the pipeline. 3.12.6 After a new pipeline has been de‐watered a gauge plate/sizing ring shall be run. Any defects found that might require the line be opened to the atmosphere for repair shall be corrected prior to drying. 3.13 Drying 3.13.1 Project Manager shall determine the required dew point for drying. Specific dew point shall be selected based upon industry standards to meet moisture specifications for the delivered product. 3.13.2 Bleed any residual moisture from valve bodies 3.14 Integrity Assessment Integration 3.14.1 The Project Manager shall conduct a pre and post data review with Asset Integrity Representatives (i.e. Corrosion, Risk Engineering, Pipeline Integrity, etc.) to ensure integration of the other pipeline integrity attributes. 4.0 DEFINITIONS 4.1 4.2 Maximum Operating Pressure (MOP) For Liquid Pipelines: The maximum pressure at which a pipeline or segment of a pipeline may be operated under 49 CFR 195. Dew Point: The temperature at which water vapor begins to condensate out of a gas at atmospheric pressure <<>> Magellan Midstream Partners, L.P. PRESSURE TESTING 7.03–ADM–001 Asset Integrity 01/01/12 Revision: 13 Page 8 of 11 System Integrity Plan Change Log Date Change Location y Approve d By Brief Description of Change 11/08/03 All Clyde Clausen Mike Pearson Conducted Annual Review 12/03/03 1.0 Clyde Clausen Mike Pearson Purpose to Objective 12/03/03 2.1.3 Clyde Clausen Mike Pearson Data Resources to Pipeline Integrity; changed grammar of paragraph 12/03/03 2.1.4 Clyde Clausen Mike Pearson Internal Corrosion Specialist to Supervisor, Asset Integrity 12/03/03 2.1.7 Clyde Clausen Mike Pearson Added: f the pipeline is being tested to satisfy Integrity Management requirements, consideration should be given to conducting a spike test. 12/03/03 2.2.1 Clyde Clausen Mike Pearson Changed: Manager of Pipeline Integrity to Manager of Asset Integrity 12/03/03 2.2.2 B Clyde Clausen Mike Pearson Same as 2.2.1 12/03/03 2.3 Clyde Clausen Mike Pearson Re‐formatted numbering of sub‐paragraphs 12/03/03 2.3 Clyde Clausen Mike Pearson Added 2.3.15 12/03/03 2.4.1 Clyde Clausen Mike Pearson Changed to read 50  of test pressure is achieved 12/03/03 2.4.4 Clyde Clausen Mike Pearson Added: or pipe that cannot be backfilled such as an existing span 12/03/03 2.4.5 Clyde Clausen Mike Pearson Added: in critical areas 12/03/03 2.5.1 Clyde Clausen Mike Pearson Change Ambient to pipeline temperature; Added: an appropriate distance from the test header so as not to be effected by the temperature of the pressure water injected into the pipeline 12/03/03 2.6 Clyde Clausen Mike Pearson Changed Calibration to Certification 12/03/03 2.6.1 Clyde Clausen Mike Pearson Changed immediately prior to start to within the previous 12 months 12/03/03 2.7.1 Clyde Clausen Mike Pearson Added: TOR nipples that are installed with check valve plugs should have the check valve plugs removed and replaced with solid TOR plugs for the duration of the test. Upon completion of the test the TOR check valve plugs may be returned 12/03/03 2.8.1 Clyde Clausen Mike Pearson Changed WES to MMP; Added: taking into consideration pressure rating of pipe fittings, flanges, and valves; previous pressure test records; and appropriate design calculations 12/03/03 2.8.2 Clyde Clausen Mike Pearson Added: If a pipeline segment is determined to be susceptible to longitudinal seam oriented failures and hydro‐static testing is the chosen integrity assessment, then in addition to the normal 195 Sub Part E test a spike test would need to be performed. A spike test is generally conducted at a pressure of at least 1.39 x MOP for 30 – 60 minutes prior to 195 Sub Part E test. All pipeline hydrostatic test failures will be removed from the pipeline and sent to a metallurgist for failure analysis and reporting. 12/03/03 2.8.3 Clyde Clausen Mike Pearson Changed WES to MMP 12/03/03 2.8.6 Clyde Clausen Mike Pearson Added: unless circumstances dictate otherwise 12/03/03 2.8.8 Clyde Clausen Mike Pearson Deleted reference to Offshore 12/03/03 2.9.1 Clyde Clausen Mike Pearson Deleted Offshore; Changed Engineering Manager to Technical Services 12/03/03 2.9.1 B Clyde Clausen Mike Pearson Changed Engineering Manager to Technical Services <<>> Magellan Midstream Partners, L.P. PRESSURE TESTING 7.03–ADM–001 Asset Integrity 01/01/12 Revision: 13 Page 9 of 11 12/03/03 2.12.3 Clyde Clausen Mike Pearson Deleted on company for WES xx (under development 12/03/03 2.13.1 Clyde Clausen Mike Pearson Added: hydrostatically pre‐tested for 4 hours before installation, and again for 8 hours after pulled in place by boring process, except for in‐ service pipelines in place. 12/03/03 2.14.3 G Clyde Clausen Mike Pearson Added: All records shall be sent to Pipeline Integrity for retention 12/03/03 2.15 Clyde Clausen Mike Pearson Added: 2.15.5 After pipeline has been de‐watered a gauge plate/sizing ring shall be run. Any defects found that might require the line be opened to the atmosphere for repair shall be corrected prior to drying. 12/03/03 2.16 Clyde Clausen Mike Pearson Deleted: and Gauging 12/03/03 2.1.6.1 Clyde Clausen Mike Pearson Changed grammar of paragraph; Deleted: reference to running gauge pig 12/03/03 4.0 Clyde Clausen Mike Pearson Added: 4.3 Dew point is the temperature at which water vapor begins to condensate out of a gas at atmospheric pressure 12/03/03 2.9, 2.10, 2.11, 2.12, 2.14, Clyde Clausen Mike Pearson Re‐formatted numbering of sub‐paragraphs 11/07/04 All Clyde Clausen Mike Pearson Conducted Annual Review 12/10/04 2.1.3 Clyde Clausen Mike Pearson Reworded 2nd sentence. Added: “for approval and filing” to last sentence. 12/10/04 2.1.6 Clyde Clausen Mike Pearson Added: Hydrostatic Test Form No. 07‐FORM‐13 12/10/04 2.3.8 Clyde Clausen Mike Pearson Added: (Note: Project Manager shall ensure discharge piping is designed for the expected discharge pressures and shall ensure discharge piping is anchored to prevent whipping in the event of failure.) 12/10/04 2.7.2 Clyde Clausen Mike Pearson Reworded 2nd sentence 12/10/04 2.8.1 and 2.8.3 Clyde Clausen Mike Pearson Changed Hydrostatic Test Form Numbers 12/10/04 2.8.2 Clyde Clausen Mike Pearson Reworded 2nd sentence 12/10/04 2.8.3 Clyde Clausen Mike Pearson Added: “for hazardous liquids pipelines” 12/10/04 2.8.6 Clyde Clausen Mike Pearson Changed grammar 12/10/04 2.8.8 Clyde Clausen Mike Pearson Changed grammar of paragraph 12/10/04 2.9.2 Clyde Clausen Mike Pearson Reformatted numbering of sub‐paragraphs 12/10/04 2.10.1 Clyde Clausen Mike Pearson Changed grammar of 1st sentence 12/10/04 2.14.3.5 Clyde Clausen Mike Pearson Changed Hydrostatic Test Form Numbers 12/10/04 2.14.3.7 Clyde Clausen Mike Pearson Added: “approval and” 12/10/04 2.15.2 Clyde Clausen Mike Pearson Changed grammar of paragraph and added reference to Paragraph 2.3.8 12/10/04 2.15.5 Clyde Clausen Mike Pearson Added: “new” 12/10/04 2.16.1 Clyde Clausen Mike Pearson Changed grammar and corrected paragraph number 11/05/05 All Clyde Clausen Mike Pearson Conducted Annual Review 01/01/06 2.6 Dennis Vasicek Mike Pearson Changed Paragraph 2.6.1 and added paragraphs 2.6.2 and 2.6.3. 01/01/06 Applicability Dennis Vasicek Mike Pearson Added Applicability Section. 01/01/06 2.1 Dennis Vasicek Mike Pearson Added 2.1.1 through 2.1.3. 01/01/06 2.3.2 Dennis Vasicek Mike Pearson Reworded paragraph <<>> Magellan Midstream Partners, L.P. PRESSURE TESTING 7.03–ADM–001 Asset Integrity 01/01/12 Revision: 13 Page 10 of 11 01/01/06 2.8.3 Dennis Vasicek Mike Pearson Reworded paragraph to be more consistent with DOT Part 195.304. 01/01/06 2.9 Dennis Vasicek Mike Pearson Grouped all of Gas Testing sections under 2.9. 01/01/06 2.12.4 Dennis Vasicek Mike Pearson Added consideration for using hammer unions on discharge hoses. 01/01/06 All Clyde Clausen Mike Pearson Deleted References 10/30/06 All Clyde Clausen Mike Pearson Conducted annual review 10/30/06 3.1.1 Dennis Vasicek Mike Pearson Reworded paragraph to be more consistent with DOT Part 195.302 10/30/06 3.1.5.4 Dennis Vasicek Mike Pearson Added second sentence 10/30/06 3.3.1.1.4 Dennis Vasicek Mike Pearson Deleted paragraph 10/30/06 3.3.1.1.5 Dennis Vasicek Mike Pearson Deleted paragraph 10/30/06 3.3.1.1.7 Dennis Vasicek Mike Pearson Added electronic pressure gauges 10/30/06 3.5.1 Dennis Vasicek Mike Pearson Reworded paragraph to further clarify using a buried pipe temperature sensing bulb. 10/30/06 3.6.1 Dennis Vasicek Mike Pearson Added electronic pressure gauges 10/30/06 3.10.1 Dennis Vasicek Mike Pearson Changed 4 hours to a minimum of 2 hours 10/30/06 3.11.3.7 Dennis Vasicek Mike Pearson Added “for the useful life of the tested segment” 1/5/07 3.1.4 Clyde Clausen Mike Pearson Added Paragraph requiring all hydrostatic test failures be sent in for metallurgical review per SIP 7.02 1/5/07 3.1.5 Clyde Clausen Mike Pearson Added Paragraph requiring Engineering or Project Manager approval 1/5/07 3.1.6 Clyde Clausen Mike Pearson Added Paragraph to consider running cleaning pigs 2 months after a successful hydrostatic test. 1/5/07 3.11.1 Clyde Clausen Mike Pearson Added Paragraph requiring final review of records and documentation by Pipeline or Facility Integrity Engineer. 1/5/07 3.14.2 Clyde Clausen Mike Pearson Added Paragraph to bleed residual moisture from valve bodies. 1/5/07 3.15 & 3.15.1 Clyde Clausen Mike Pearson Added Integrity Assessment Integration section and paragraph for pre and post data review with AI representatives. 5/23/07 3.1.2* Deaundra chancellor Clyde Clausen Modified to include “without leakage” 6/26/07 3.1.1 Clyde Clausen Mike Pearson Added paragraph 6/26/07 3.12 Clyde Clausen Mike Pearson Added Section 6/26/07 3.4.1 Clyde Clausen Mike Pearson Added paragraph 6/26/07 3.4.2 Clyde Clausen Mike Pearson Added paragraph 6/26/07 3.11.2 Clyde Clausen Mike Pearson Modified Paragraph 12/14/07 3.11.4.1 Dennis Vasicek Clyde Clausen Modified to include “(where elevation differences in the section under test exceed 100 feet)” 01/31/08 global Updated hydrostatic links 12/22/08 3.9.1.1 Dennis Vasicek Clyde Clausen Revised paragraph for compliance with CFR Part 192.503 12/22/08 3.9.11 Dennis Vasicek Clyde Clausen Clarified facility type in the table as non‐jurisdictional gas gathering lines 12/22/08 Dennis Vasicek Clyde Clausen Annual Review 1/12/09 3.6.1 Doug Chabino Clyde Clausen Added “Consistent with the calibration requirements in SIP 9.01‐ADM‐077” 8/7/09 3.6.1 Dennis Vasicek Clyde Clausen Replaced, “SIP 9.01‐ADM‐077” with “API RP 1110 – Pressure Testing of Liquid Petroleum Pipelines” 8/28/09 3.1.5 Dennis Vasicek Clyde Clausen Reworded paragraph and inserted “consideration shall be given to submit the failed section to metallurgical analysis” 8/28/09 3.9 Dennis Vasicek Clyde Clausen Removed Section 3.9 Gas Testing 9/1/09 3.2.1 Dennis Vasicek Clyde Clausen Changed “Director” to “Manager” <<>> 9/1/09 9/2/09 9/4/09 10/9/09 11/9/09 11/9/09 11/9/09 11/9/09 5/27/10 5/27/10 5/27/10 12/1/10 01/01/11 03/09/11 9/1/11 9/1/11 9/1/11 9/1/11 9/1/11 12/31/11 12/31/11 Magellan Midstream Partners, L.P. PRESSURE TESTING 7.03–ADM–001 Asset Integrity 01/01/12 Revision: 13 Page 11 of 11 3.2.2.2 Dennis Vasicek Clyde Clausen Changed “Director” to “Manager” 3.11.1 Dennis Vasicek Clyde Clausen Removed reference to Gas Testing section and corrected reference to 3.10 3.9.1.3 Dennis Vasicek Clyde Clausen Added comment to notify Environmental Specialist if additives are to be used. 3.8.2 Dennis Vasicek Clyde Clausen Revised typical duration of spike test and reworded paragraph to be consistent with 3.1.5 revision 2.2 Dennis Vasicek Clyde Clausen Removed Longhorn Specific paragraph 3.1.6 Dennis Vasicek Clyde Clausen Removed “or Project Manager” 3.1.9.2 Dennis Vasicek Clyde Clausen Revised requirement to submit records to “Pipeline Integrity” to “Asset Integrity Engineering” Dennis Vasicek Clyde Clausen Annual Review 3.1.3 Chabino Clausen In‐place pressure testing is not required for repairs if>>>> 3.1.4 Chabino Clausen Added.. Pressure tests must include all pipe and attached fittings, including components. 3.1.5. Chabino Clausen Modified to reference Analysis of Pipe Cutouts program. 3.1.10 Dennis Vasicek Clyde Clausen Added precautionary language about excavating a pipeline to install a tap 3.4.7 Added dec 1 2010 email from Clyde Clausen 3.1.8.2/5.1 Removed reference to DOT 192 All Clyde Clausen Doug Chabino Conducted Annual Review 3.8.5 Clyde Clausen Doug Chabino Added Shall be considered for excavation to paragraph 3.8.8.1 Clyde Clausen Doug Chabino Added paragraph 3.1.9.2 Clyde Clausen Doug Chabino Added new paragraph under Project Manager Shall: 3.1.10 Clyde Clausen Doug Chabino Added guidance to paragraph 4.0 (old) Removed Links section All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 1 of 18 1.0 OBJECTIVE 1.1 The Objective of this procedure is to establish the process to analyze In‐Line Inspection (ILI) data to identify features that require repair per DOT 49 CFR 195.452. 2.0 INDEX 1.0 OBJECTIVE ........................................................................................................................................ 1 2.0 INDEX ................................................................................................................................................. 1 3.0 PROCEDURE ..................................................................................................................................... 1 4.0 PRELIMINARY REPORTS ................................................................................................................. 1 5.0 ELECTRONIC DRAFT REPORTS ...................................................................................................... 1 6.0 FINAL REPORTS ................................................................................................................................ 1 7.0 INTEGRITY CONDITIONS ................................................................................................................. 2 8.0 9.0 DISCRETE POINT PRESSURE (DPP) ANALYSIS ............................................................................ 5 SEAM WELD ASSESSMENT ............................................................................................................. 6 10.0 ULTRASONIC WALL MEASUREMENT ASSESSMENT ................................................................... 7 11.0 CASING ANALYSIS ............................................................................................................................ 8 12.0 DENT REVIEW AND DEPTH OF COVER CORRELATION .............................................................. 8 13.0 PROJECTED CORROSION GROWTH ANALYSIS ........................................................................... 8 14.0 CALIBRATION DIGS ......................................................................................................................... 9 15.0 DIG LIST ........................................................................................................................................... 10 16.0 ILI SUMMARY DOCUMENT ............................................................................................................. 10 17.0 CORRELATION AND TOOL TOLERANCE ASSESSMENT............................................................ 11 18.0 DEFINITIONS .................................................................................................................................... 12 19.0 REFERENCES .................................................................................................................................. 13 3.0 PROCEDURE 3.1 3.2 3.3 3.4 This guideline incorporates API 1163, In‐line Inspection Systems Qualification Standard, First Edition, August 2005; NACE Standard RP0102‐2002; and ANSI/ASNT ILI‐PQ‐2005 where applicable. This guideline is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be used, in whole or part, on non‐jurisdictional assets as deemed appropriate. Assets Covered Per Mitigation Plan operate under Longhorn Mitigation Plan requirements in addition to applicable Federal, State, and Local regulations and Company guidelines, processes or best practices. The Pipeline Integrity Engineer and Pipeline Integrity Data Coordinator will utilize this Guideline in conjunction with the In‐Line Inspection Procedure when conducting analyses of Inspection data. . <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 1 of 18 4.0 PRELIMINARY REPORTS 4.1 In‐line Inspection Vendor (Vendor) will provide Preliminary Report (if required) within 21 business days of a successful tool run. Features requiring a Preliminary Report are described in In‐Line Inspection Technical Specification. 4.2 If features meeting preliminary reporting criteria are reported by Vendor, Pipeline Integrity Engineer will: 4.2.1. 4.2.2. 4.2.3. Notify Supervisor of Pipeline Integrity Engineering via email. Initiate immediate investigation and repair process described in In‐Line Inspection Procedure if feature is located in an HCA. 4.3 Ensure that appropriate response is executed within 5 days of receipt of Preliminary Report for features reported on Assets Covered Per Mitigation Plan in accordance with Longhorn Mitigation Plan, Section 3.5.2. 4.2.4. Request Pipeline Integrity Data Analyst to prepare dig sheets. 4.2.5. Provide excavation findings to Vendor upon completion of any field investigations. Pipeline Integrity Data Analyst will: 4.3.1. Prepare dig sheets using Procedure for Creating Dig Sheets. 4.3.2. Prepare Rehab Book for inspector in accordance with Project File Index Form. 5.0 ELECTRONIC DRAFT REPORTS 5.1 Vendor will provide an electronic Draft Report as specified in In‐Line Inspection Technical Specification. 5.2 Pipeline Integrity Data Analyst will verify electronic Draft Report as specified in AGM Verification Guidelines. Verify electronic Draft Report as specified in ILI Data Verification Guidelines. 5.3 Pipeline Integrity Engineer will: 5.3.1. 5.3.2. Approve electronic Draft Report or provide Vendor any comments within 5 business days of receipt of electronic Draft Report. If discrepancies are identified, Vendor will be required to make necessary modifications before issuance of Final Report. 6.0 FINAL REPORTS 6.1 Pipeline Integrity Engineer will 6.1.1. 6.1.2. Perform QA/QC review of Final Report to ensure it is thorough, complete, correct and delivered in accordance with In‐Line Inspection Technical Specification. 6.1.1.1. If a significant issue is observed, Pipeline Integrity Engineer will immediately reject Final Report and notify Vendor in writing. Declare the date of discovery (Discovery) within 5 business days of receipt of a valid Final Report but not later than 180 days after the day ILI tool was trapped in the receiver. 6.1.2.1. 6.1.3. Pipeline Integrity Engineer will calculate 60‐day and 180‐day due dates for HCA conditions based on counting forward from Discovery date. For Assets Covered Per Mitigation Plan Send a copy of MFL Final Report to Operational <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 2 of 18 6.2 6.1.4. 6.1.5. 6.1.6. Reliability Assessment (ORA) Contractor for Probability of Exceedance (POE) analysis, girth weld evaluation and metal loss within 3 inches of girth weld for. Copy electronic documents (i.e. pipeline listing, NWT report, AGM listing and mapping files, LAPA [if provided], certification of calibration) to appropriate line section folder on network drive. Perform detailed analysis of ILI data to identify: immediate, 60‐day, 180‐day and 6‐ month (where applicable) features, DPP features, casings to be worked, ID reduction review, and other features potentially requiring investigation. Schedule a Pre‐Job Roundtable meeting with various stakeholders (as appropriate: Asset Integrity Maintenance Supervisor, Asset Integrity Engineer, Supervisor Corrosion Control, Pipeline Integrity Coordinator, Real Estate Representative, Pipeline Integrity Data Analyst, Supervisor of Pipeline Integrity Engineering and Manager of Asset Integrity) to discuss ILI Summary document, features to be investigated, and other concerns (e.g. integrated depth of cover and corrosion control data) identified by Final Report. Pipeline Integrity Data Analyst will: 6.2.1. Prepare dig sheets using Procedure for Creating Dig Sheets. 6.2.2. Prepare a project field book using Project File Index Form. 6.2.3. Obtain completed project field book from chief inspector and perform checks on information accumulated during rehabilitation upon completion of rehabilitation activities. 7.0 INTEGRITY CONDITIONS 7.1 7.2 7.3 Pipeline Integrity Engineer will obtain High Consequence Area (HCA) begin and end location information from Risk Analyst or from HCA database and calculate corresponding odometer locations to mark in Final Report. Pipeline Integrity Engineer will identify the following conditions: HCAS And Areas That Could Affect HCAs 7.3.1. Immediate Repair Conditions 7.3.1.1. Discovery of an immediate repair condition is to be established no later than 5 business days after condition is reported to Company. Within 5 business days of identification of an immediate repair condition, Pipeline Integrity Engineer will initiate immediate investigation and repair process in accordance with In‐Line Inspection Procedure. 7.3.1.2. Until immediate condition is repaired, the following operating conditions may be implemented (dependent upon the type of feature). 7.3.1.2.1. Reduce operating pressure so that at the location of the anomaly, discrete point pressure (PDPP) does not exceed operating pressure (PSAFE), or PDPP does not exceed the pressure calculated by the formula in Section 451.7 of ASME/ANSI B31.4, or 7.3.1.2.2. Reduce operating pressure so that PDPP does not exceed 80% <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 3 of 18 7.3.1.3. 7.3.1.4. of highest operating pressure actually experienced at location of anomaly within 60‐days preceding inspection, or 7.3.1.2.3. Shutdown pipeline. Metal loss features (including SWFA, SWFB, ASWML and SWML) with predicted depths greater than or equal to 80% of the wall thickness requires reducing operating pressure per 7.3.1.2.2 or shutdown pipeline until repair is made. Features with predicted burst pressure, PBURST, less than PDPP requires reduce operating pressure per 7.3.1.2.1 or shutdown pipeline until repair is made. 7.3.1.4.1. 7.3.1.4.2. Metal loss calculation using 85% Area RSTRENG criterion or CorLASTM (Flow Stress Criterion, 85% Area) SWFA, SWFB, ASWML, or SWML calculation using CorLASTM (Fracture Mechanics Criterion) 7.3.1.5. Top‐side dents (above the 4 and 8 o’clock positions) predicted to contain associated metal loss, cracking or a stress riser requires reducing operating pressure per 7.3.1.2.2 or shutdown pipeline until repair is made. 7.3.1.6. Top‐side dents with a predicted depth greater than 6% of the nominal pipe diameter requires reducing operating pressure per 7.3.1.2.2 or shutdown pipeline until repair is made. 7.3.1.7. Significant features in the judgment of the person evaluating the inspection and test assessment results requires reducing operating pressure or shutdown pipeline based upon type of feature and engineering analysis until repair is made. 7.3.1.8. Deformation anomaly characterized as a pipeline device or repair intrusion such as pig‐sig, IFD, tube, flow improver nozzle, heavy weld, etc. will not be considered an “Immediate Condition.” 7.3.2. 60‐Day Repair Conditions 7.3.2.1. Top‐side dents with a predicted depth greater than 3% of the pipeline diameter (greater than 0.250” in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12). 7.3.2.2. Bottom‐side dents (below 4 and 8 o’clock positions) predicted to contain any metal loss, cracking, or a stress riser. 7.3.3. 180‐day Repair Conditions 7.3.3.1. Dents with a predicted depth greater than 2% of the pipeline’s diameter (0.250” in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld. 7.3.3.2. Top‐side dents with a predicted depth greater than 2% of the pipeline’s diameter (0.250” in depth for a pipeline diameter less than NPS 12). 7.3.3.3. Bottom‐side dents with a predicted depth greater than 6% of the pipeline’s diameter. 7.3.3.4. Features where the calculation of remaining strength of the pipe shows an <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 4 of 18 7.4 operating pressure, PSAFE, that is less than PDPP at the location of the anomaly. 7.3.3.5. Areas of general corrosion with a predicted metal loss greater than 50% of nominal wall 7.3.3.6. Features with predicted metal loss greater than 50% of nominal wall that are located at a crossing of another pipeline, or are in an area with widespread circumferential corrosion, or are in an area that could affect a girth weld 7.3.3.7. Potential crack indications that when excavated are determined to be a crack. 7.3.3.8. Corrosion of or along a longitudinal seam weld (as identified by the ILI service provider as being axially oriented seam weld metal loss) 7.3.3.9. Gouge or grooves with a predicted depth greater than 12.5% of nominal wall 7.3.4. Other Conditions 7.3.4.1. Conditions identified by ILI that could impair the integrity of the pipeline should be repaired as appropriate. Non‐HCAS And Areas Not Affecting HCAS 7.4.1. The following anomalies will be immediately evaluated and scheduled for excavation if deemed necessary. However, all HCA Immediate Conditions shall take priority: 7.4.1.1. Metal loss (including SWFA, SWFB, ASWML, and SWML) greater than or equal to 80% wall thickness 7.4.1.2. Features with predicted burst pressure Pburst, less than discrete point pressure, PDPP. 7.4.1.3. 7.4.1.2.1. Metal Loss calculation using 85% Area RSTRENG Criterion or CorLAS™ (Flow Stress Criterion, 85% Area) 7.4.1.2.2. SWFA, SWFB, ASWML, or SWML calculation using CorLAS™ (Fracture Mechanics Criterion) Top‐side dents with any indicated metal loss, cracking or stress riser 7.4.2. The following anomalies will be evaluated and scheduled for excavation and repair prior to the next integrity assessment if deemed necessary: 7.4.2.1. Features where PSAFE is less than PDPP at location of anomaly. 7.4.2.2. Bottom‐side dents with associated metal loss. 7.4.2.3. Girth weld anomalies 7.4.2.4. Dents in excess of 6% of pipe diameter. 7.4.2.5. Dents located in the girth weld or longitudinal seam that exceed 2% of pipe diameter for NPS 12 and larger or 0.250” for pipe diameters less than NPS 12. 7.4.2.6. Gouges, scratches, or grooves that exceed 12.5% metal loss. 7.4.2.7. Severe mill related defects (lamination, hard spots, etc.). <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 5 of 18 7.4.2.8. Crack‐like anomalies located in girth weld, longitudinal seam weld, or pipe 7.5.2. 8.0 7.5 7.6 body. 7.4.2.9. Field confirmed casing shorts with associated metal loss. 7.4.2.10. Other significant anomalies. 7.4.2.11. Features identified for tool calibration purposes. Assets Covered Per Mitigation Plan 7.5.1. Initiation of a response must be implemented within 5 days of receipt of report for these features in accordance with Longhorn Mitigation Plan Section 3.5.2 7.5.1.1. Metal loss greater than 70% wall thickness 7.5.1.2. Top‐side dents with any indicated metal loss 7.5.1.3. Significant anomalies that in the judgment of the data evaluator require immediate action initiation of a response must be implemented within 60 days of receipt of report for these features in accordance with Longhorn Mitigation Plan Section 3.5.2. 7.5.2.1. Top‐side dents without indicated metal loss and with depths greater than 6% of the pipe diameter 7.5.3. The following indications shall be investigated within 6 months of the receipt of report in accordance with Longhorn Mitigation Plan Section 3.5.2. 7.5.3.1. Dents with any of the following: Metal loss, corrosion, exceeds 6% of the pipe outside diameter, or located in a longitudinal seam or girth weld Features where remaining strength of pipe results in a safe operating pressure, PSAFE, that is less than the current MOP at the location of the anomaly using a suitable safe operating pressure calculating criterion. 7.5.3.3. Casing shorts with associated metal loss 7.5.3.4. Girth weld anomalies 7.5.3.5. Corrosion within 3” of either side and/or across girth welds as determined by ORA contractor 7.5.3.6. Preferential corrosion of or along seam welds. 7.5.3.7. Gouges or grooves greater than 50% of nominal wall thickness 7.5.3.8. Cracks located in the pipe body, girth weld, and longitudinal seam that are determined to be injurious to the integrity of the pipeline. As an alternative to direct examination, an API 579 Fitness‐For‐Service level 1, 2, and/or 3 Engineering Critical Assessment may be performed in order to substantiate the need for direct examination activity. DISCRETE POINT PRESSURE (DPP) ANALYSIS 8.1 Pipeline Integrity Engineer will populate discrete point pressure (DPP) spreadsheet with anomalies with rupture pressure ratio (RPR) less than 1.0. RPR is PBURST divided by pipe design pressure. PSAFE is design factor multiplied by PBURST. RPR will be less than 1.0 when PBURST of an anomaly is less than pipe design pressure (100% SMYS). DPP data sources include: 7.5.3.2. <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 6 of 18 8.1.1. ILI Final Report 8.1.2. Corrosion Growth spreadsheet 8.1.3. Seam Weld Assessment analysis 8.2 Pipeline Integrity Data Analyst will: 8.2.1. Calculate stations using Total AGMs Form and obtain elevations using alignment sheets for features requiring DPP analysis. 8.2.2. Use alignment sheets to determine if any metal loss features greater than 50% are located within 50’ of a foreign pipeline crossing and will indicate on appropriate tab in the DPP spreadsheet. 8.3 Asset Integrity Engineer will complete DPP analysis taking into account pump set points, elevation differences, and surge conditions. 8.3.1. Determine, through available records, design pressure for line and upstream pump maximum discharge set point. 8.3.2. Determine maximum elevation difference between pressure source and feature location. 8.3.3. Determine static head pressure due to elevation change calculated using specific gravity of heaviest product. 8.3.4. Add static head pressure to pump set point to get PDPP at feature location due to static head (Static PDPP). 8.3.5. For incompressible liquid pipelines, conduct surge analysis at each feature location to determine PDPP due to surge (Surge PDPP). 8.3.6. Compare static PDPP and surge PDPP at each feature location. Select greater value to be used as PDPP for anomaly location. 8.4 Pipeline Integrity Engineer will add anomalies in HCA with PBURST < PDPP to dig list as immediate repair conditions (priority conditions in non‐HCA) and will add anomalies in HCA with PSAFE < PDPP to dig list as 180‐day conditions (secondary conditions in non‐HCA). 9.0 SEAM WELD ASSESSMENT 9.1 Pipeline Integrity Engineer or designee will conduct seam weld assessment (SWA) when ILI tool is either circumferential flux leakage (aka TFI, AFD, or SWML ILI) or ultrasonic crack detection (USCD) ILI technology. 9.2 The following anomalies will be assessed and considered for investigation and/or remediation. 9.2.1. Seam Weld Feature A (SWFA) 9.2.2. Seam Weld Feature B (SWFB) 9.2.3. Axial Seam Weld Metal Loss (ASWML) 9.2.4. Seam Weld Deformation (SWD) 9.2.5. Axial Planar features 9.2.6. Crack‐Field 9.2.7. Notch‐Like <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 7 of 18 9.2.8. Weld Anomaly 9.2.9. Other integrity features in the judgment of the person evaluating the data 9.3 Pipeline Integrity Engineer or designee will calculate Pburst and Psafe using CorLAS™ (fracture criterion) or similar remaining strength calculation and using appropriate fracture toughness for SWFA, SWFB, ASWML and SWML anomalies. 9.4 Pipeline Integrity Engineer or designee may use MFL data, when available, to identify additional potential SWML anomalies, defined as those within 2 inches of LSW. For these integrated SWML anomalies, Pipeline Integrity Engineer or designee will calculate Pburst and Psafe for all internal and external anomalies, using 85% Area RSTRENG™ or CorLAS™ (flow stress criterion, 85% Area) 9.5 Pipeline Integrity Engineer will add to DPP spreadsheet features requiring direct examination when PBURST is less than pipe design pressure (100% SMYS) and features identified in SWA report as requiring DPP analysis. RPR and PBURST values listed in SWA report will be used in DPP spreadsheet. 9.6 Pipeline Integrity Engineer will add anomalies in HCA with PBURST < PDPP to dig list as immediate repair conditions (priority conditions in non‐HCA) and will add anomalies in HCA with PSAFE < PDPP to dig list as 180‐day conditions (secondary conditions in non‐HCA). 10.0 ULTRASONIC WALL MEASUREMENT ASSESSMENT 10.1 Pipeline Integrity Engineer or designee will conduct ultrasonic wall measurement (USWM) assessment when ILI tool is USWM ILI technology. 10.2 Pipeline Integrity Engineer or designee will consult with ILI vendor and Magellan’s third party consultant to establish reporting and evaluation criteria guidelines. If needed, modifications will be made to Magellan’s In‐Line Inspection Technical Specification. All laminations as identified by tools reporting capabilities will be included in final report. 10.3 The following Laminations will be evaluated and considered for investigation and/or remediation. 10.3.1. Sloping laminations 10.3.2. Bulging laminations 10.3.3. Surface breaking laminations 10.3.4. Hydrogen blisters 10.3.5. Laminations interacting with deformations, metal loss, cracks, girth and seam welds, and other reported features 10.3.6. Other integrity features in the judgment of the person evaluating the data. 10.4 When applicable, Pipeline Integrity Engineer or designee will review the USWM data for seam weld features and perform calculations described in the Seam Weld Assessment process. 10.5 Pipeline Integrity Engineer or designee will identify and evaluate all reported deformations identified by EGP (Electronic Geometry Pigs) or other applicable ILI inspections that correlate and interact with existing laminations. 10.6 Pipeline Integrity Engineer or designee may use previous ILI data, when available, to identify additional metal loss anomalies and significant features (i.e. cracks, girth welds, long seam, etc.) that may be potentially associated with laminations. For integrated metal loss anomalies > 20% deep, Pipeline Integrity Engineer or designee will calculate PBURST and PSAFE for all internal and <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 8 of 18 external anomalies using CorLASTM (Fracture Mechanics Criterion) 10.7 Pipeline Integrity Engineer will add to DPP spreadsheet features requiring direct examination when PBURST is less than pipe design pressure (100% SMYS) and features identified in USWM report as requiring DPP analysis. RPR and PBURST values listed in USWM report will be used in DPP spreadsheet. 10.8 Pipeline Integrity Engineer will add anomalies in HCA with PBURST < PDPP to dig list as immediate repair conditions (priority conditions in non‐HCA) and will add anomalies in HCA with PSAFE < PDPP to dig list as 180‐day conditions (secondary conditions in non‐HCA). 10.9 Pipeline Integrity Engineer will place all features requiring investigation on the dig list 11.0 CASING ANALYSIS 11.4 Pipeline Integrity Data Analyst will notify Pipeline Integrity Engineer if any casings need to be added to Dig List. 11.5 Pipeline Integrity Engineer will identify casings with metal loss in Final Report. 12.0 11.1 Pipeline Integrity Engineer will create a list of casings with casing begin and end locations in order of absolute distance. 11.2 Pipeline Integrity Data Analyst will determine casings that require rehabilitation. Pipeline Integrity Data Analyst will: 11.2.1. Add metal loss information from Final Report to designate number of metal loss features and maximum and minimum depths of metal loss inside each casing. 11.2.2. Check with Pipeline Integrity Engineer to determine if any casings are scheduled to be investigated due to required ILI investigations. 11.2.3. Review corrosion database for potential shorted or elevated casings. 11.2.4. Request Corrosion Technician field verify casings as required. 11.3 Corrosion Technician will resolve discrepancies and perform field verification of casings as required, notify Pipeline Integrity Data Analyst about casings that need to be investigated during pipeline rehabilitation, and incorporate field verification findings into corrosion database. DENT REVIEW AND DEPTH OF COVER CORRELATION 12.1 Pipeline Integrity Engineer will create a top‐side dent list and a dent comparison list. The dent comparison list will match current dent callouts to previous ILI run dent callouts. 12.2 Pipeline Integrity Engineer may request previous run Vendor to verify data signal to determine if current dents were visible in previous run data. 12.3 Pipeline Integrity Data Analyst will review depth of cover database and/or spreadsheets, if available, to determine depth of cover and land use for each identified top‐side dent. 12.4 Pipeline Integrity Engineer will: 12.4.1. Add top‐side dents located in cultivation with depth of cover less than 18” to the Dig List for investigation. 12.4.2. Add top‐side dents where no depth of cover information is available to the Dig List as “stake only” digs to determine land use and depth of cover. Further investigation of these features may be necessary pending land use and depth of cover information. 13.0 PROJECTED CORROSION GROWTH ANALYSIS <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 9 of 18 13.1 13.2 13.3 13.4 13.5 13.6 13.7 Pipeline Integrity Engineer will analyze metal loss indications to establish a re‐assessment interval based on projected corrosion growth (PCG). Pipeline Integrity Engineer will: 13.1.1. Create PCG analysis spreadsheet and input vital pipeline and ILI data for each metal loss anomaly and corrosion growth time period (typically 6.2 years) 13.1.2. Input 110% MOP for line segment 13.1.3. Input year of construction and year of inspection 13.1.4. Calculate PCG rate for each metal loss anomaly assuming linear corrosion growth starting at time of construction based on the following formula where d/t is depth of metal loss (percentage of wall thickness) as reported by ILI tool. PCG rate = Reported (d/t) / Years Where multiple inspections have been conducted utilizing like technologies, Pipeline Integrity Engineer will calculate a run comparison PCG rate for each metal loss anomaly with a reported peak depth ≥ 25% wall thickness by comparing current reported peak depth with a previous reported peak depth and dividing by years between inspections. 13.2.1. Pipeline Integrity Engineer will input run comparison PCG rate into a separate run comparison projected corrosion growth analysis spreadsheet. 13.2.2. For features indicating “Consider Remediation”, Pipeline Integrity Engineer will contact previous run Vendor to verify feature sizing. Revised feature sizing will be updated in the run comparison spreadsheet and a new PCG rate will be calculated. 13.2.3. For features indicating a10 mils per year or greater PCG rate, Pipeline Integrity Engineer will contact previous run Vendor to verify feature sizing. Revised feature sizing will be updated in the run comparison spreadsheet and a new PCG rate will be calculated. Pipeline Integrity Engineer will calculate a 6.2‐year projected depth of corrosion, (d/t) Projected, based on the following formula. This assessment can also be performed for intervals other than 6.2‐years but (d/t) cannot exceed 1.00 (i.e., depth exceeds wall thickness). (d/t) Projected = (d/t) Reported + 6.2*PCG rate Pipeline Integrity Engineer will calculate PBURST based on (d/t) Projected and add metal loss indications for which PBURST is less than 110% MOP to DPP analysis spreadsheet. DPP analysis will be conducted as described in Discrete Point Pressure Analysis section. Pipeline Integrity Engineer will consider adding to Dig List metal loss anomalies for which (d/t) Projected exceeds 80% wall thickness. Pipeline Integrity Engineer will consider adding to Dig List metal loss anomalies for which the PCG rate is 10 mils per year or greater. Assets Covered Per Mitigation Plan 13.7.1. Identify locations where (d/t) Projected exceeds 70% wall thickness and consider adding to Dig List. 14.0 CALIBRATION DIGS 14.1 14.2 If deemed necessary by the Company and/or Vendor, Pipeline Integrity Engineer will add calibration investigations of potential anomalies to Dig List in order to confirm performance of the ILI tool as described in Correlation and Tool Tolerance Assessment Section. When possible, Pipeline Integrity Engineer will add to Dig List a minimum of one calibration <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 10 of 18 investigation in seamless pipe. 15.0 DIG LIST 15.1 15.1.1. 15.1.2. 15.1.3. 15.1.4. 15.1.5. 15.1.6. Pipeline Integrity Engineer will create dig List and include the following: Immediate conditions and preliminary digs performed prior to receipt of Final Report. Integrity Conditions (HCA and non‐HCA) DPP features identified through DPP Analysis “Features > 50%” located at foreign crossings, in an area of general corrosion, or any areas that affect a girth weld. Potential crack‐like anomalies, including SFWA, SFWB, ASWML, and SWD and other features identified through Seam Weld Assessment Laminations and other features identified through section 10 of the Ultrasonic Wall Measurement Assessment 15.1.7. Casings identified through Casing Analysis 15.1.8. Dents identified through Dent Review 15.1.9. Metal loss features identified through Projected Corrosion Growth Analysis 15.1.10. Calibration Digs 15.2 15.3 15.4 15.5 15.6 15.7 15.8 Pipeline Integrity Engineer will compare proposed Dig List to information from previous rehabilitation projects for locations where anomalies have been previously investigated and will consider eliminating these anomalies from Dig List. Pipeline Integrity Engineer will mark digs in Final Report and document appropriate comments for dig list. Pipeline Integrity Engineer will give Final Report and proposed Dig List to Supervisor of Pipeline Integrity Engineering or Manager Asset Integrity for review. Supervisor of Pipeline Integrity Engineering or Manager of Asset Integrity will review ILI Final Report and proposed Dig List, including: 15.5.1. External metal loss indications reported inside casings 15.5.2. Potential interactions of metal loss indications reported in seamless pipe 15.5.3. Past ILI records and dig results, leak history, corrosion growth analysis, and previous Executive Summary of Risk Analysis. 15.5.4. Send approval of proposed dig list with any additional proposed digs, if applicable, to Pipeline Integrity Engineer. Pipeline Integrity Engineer will incorporate changes requested by Supervisor of Pipeline Integrity Engineering or Manager of Asset Integrity. Pipeline Integrity Engineer will contact Vendor to manually verify location and feature sizing of dig list features. Vendor comments may be added to the dig list. Pipeline Integrity Data Analyst will create dig sheets using Procedure for Creating Dig Sheets. 16.0 ILI SUMMARY DOCUMENTS <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 11 of 18 17.0 16.1 Pipeline Integrity Engineer will complete ILI Summary document. CORRELATION AND TOOL TOLERANCE ASSESSMENT 17.1 17.2 17.3 17.4 17.5 When inspecting potential anomalies in the field, NDE contractor and Pipeline Integrity Coordinator will use their best efforts to try to understand how/why ILI tool reported various defects observed in the field and will capture this in Pipeline Maintenance Report. Pipeline Integrity Coordinator should be consulted and discrepancies should be resolved in the field before coating and backfilling when possible. Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will review NDE reports and compare ILI reported anomaly dimensions to actual defect dimensions observed in the field. 17.2.1. Comparisons will be used to develop a depth unity plot and data correlation report for each ILI run. 17.2.2. Anomalies to be correlated will include detectible metal loss, SWFA, SWFB, ASWML, SWML and ID reductions. For Assets Subject to Company Consent Decree Effective 9/4/08, 17.3.1. Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will complete comparison described above within three (3) months following completion of anomaly investigations associated with each ILI run. Comparison will include a statistically valid number of anomalies. 17.3.1.1. For ILI runs where an insufficient number of anomalies are identified to perform a statistically valid comparison analysis, anomaly comparisons may include other indications such as casings, girth welds, previous repairs, and other pipeline appurtenances. In these instances, Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will document actual versus predicted indication characteristics for each ILI run. 17.3.2. Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will develop two (2) sets of unity plots (length of axial oriented anomaly and depth into pipe wall) within three (3) months following completion of anomaly investigations associated with each ILI run intended to inspect ERW longitudinal seam weld. 17.3.2.1. ILI cracks/anomalies include detectible seam weld and HAZ features and indications 17.3.2.2. For ILI runs where an insufficient number of seam and HAZ anomalies are identified to perform a statistically valid comparison analysis, anomaly comparisons may include other indications. In these instances, Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will document actual versus predicted indication characteristics for each ILI run. Pipeline Integrity Engineer will review unity plots and data correlation reports and will consider additional excavations, regrading, engineering evaluation assessments, or re- running ILI tool if observed defect sizes are consistently outside of Vendor specified tolerances. If comparison described above suggests that Vendor undersized (or “undercalled”, as in anomalies were observed to be more severe than predicted) anomalies, Pipeline Integrity Engineer will take tool tolerances into account to recalculate corrosion growth rate and consider requesting Vendor regrade data, performing any necessary additional digs, or refining reassessment interval. <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 12 of 18 17.5.1. A statistically valid representation of investigated anomalies must be present in order to determine undersize percentages. Outlying investigated features may be discounted. 17.5.2. For metal loss, 17.5.2.1. Add average undersize percentage of anomalies that were undersized to peak depth of uninvestigated metal loss anomalies in Projected Corrosion Growth spreadsheet. 17.5.2.2. Recalculate corrosion growth rate 17.5.2.3. 17.5.2.4. Recalculate PBURST and PSAFE to compare with PDPP If, within 6.2 years, an unrepaired metal loss feature is predicted to reach 80% peak depth (70% peak depth for Assets Covered Per Mitigation Plan) or if PBURST is predicted to be less than PDPP, it should be added to Dig List. 17.5.3. For ID reductions, 17.6 17.7 17.8 17.9 17.5.3.1. If the comparison indicates an average undersize of features, add average undersize percentage of all anomalies to depth of uninvestigated ID reductions 17.5.3.2. Compare new depth to repair criteria and add ID reductions meeting repair criteria to Dig List. Pipeline Integrity Engineer may consider a Probability of Exceedance (POE) analysis (required for Assets Covered Per Mitigation Plan) or other engineering analysis as an alternative means to assess tool tolerances in order to determine if additional direct examinations are required. 17.6.1. When direct examination activities result in a statistically significant sample size of observed defects, actual tool performance will be used. Otherwise, Vendor specified tolerance may be used. Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will summarize examination results from Pipeline Maintenance Report and NDE sheets and create a data correlation report. Significant discrepancies should be resolved by Vendor and by NDE contractor. Pipeline Integrity Engineer will provide completed data correlation report to Vendor. Pipeline Integrity Engineer or Pipeline Integrity Data Analyst will notify Supervisor of Pipeline Integrity Engineering that data correlation, unity plots and projected corrosion growth are complete and that additional digs are/are not necessary. 18.0 DEFINITIONS 18.1 Terms and terminology will be used in accordance with API 1163 Section 4, unless otherwise specified herein. Additional definitions are as follows: 18.1.1. Seam Weld Feature A (SWFA): Seam weld indication that exhibits possible “crack‐ like” characteristics 18.1.2. Seam Weld Feature B (SWFB): Seam weld indication that exhibits some, but not all “crack‐like” characteristics 18.1.3. Seam Weld Metal Loss: SWML. Metal loss indication (including any part of a cluster) that encroaches upon the longitudinal seam weld (LSW). 18.1.4. Axial Seam Weld Metal Loss (ASWML): Metal loss indication (including any part of a <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 13 of 18 18.1.5. 18.1.6. 18.1.7. 18.1.8. 18.1.9. 18.1.10. cluster) that encroaches upon the LSW and is less than 2‐inches wide with a length‐ to‐width aspect ratio equal to or greater than 5:1 Seam Weld Deformation (SWD): Deformation that encroaches upon the LSW Seam Weld Anomaly (SWA): Feature other than a SWFA, SWFB, SWML, or SWD that encroaches upon or is immediately adjacent to the LSW and is thought to be non‐ injurious. PBURST: Estimated burst (failure) pressure for an anomaly as calculated according to a given standard or practice (e.g., RSTRENG™, ASME B31G, CorLAS™) PSAFE: PBURST multiplied by a design factor (e.g., 0.72) PDPP: Discrete point operating pressure at a given location Design Factor, F: from ASME B31.4, ASME B31.8, or ASME B31.11. For onshore hazardous liquid pipelines, F is typically equal to 0.72. For natural gas pipelines, F ranges from 0.40 to 0.72 depending on class location 19.0 REFERENCES 19.1 Regulatory 19.1.1. 49 CFR Part 195.452 19.2 Related Policies/Procedures 19.2.1. In‐Line Technical Specification 19.2.2. ILI Data Verification Guidelines 19.2.3. AGM Verification Guideline 19.2.4. 19.2.5. In‐Line Inspection Procedure Procedure for Creating Dig Sheets <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 14 of 18 System Integrity Plan Change Log Date Change Location Change By Approved By 11/08/04 All Clyde Clausen Mike Pearson 11/04/05 All Clyde Clausen Mike Pearson 10/30/2006 All Clyde Clausen Mike Pearson 10/30/2006 2.4.1.2 Mike Pearson Larry Franklin 10/30/2006 2.4.1.19 Dennis Vasicek Mike Pearson 10/30/2006 2.4.1.20 Mike Pearson Dennis Vasicek 10/30/2006 2.4.1.22 Mike Pearson Larry Franklin 10/30/2006 2.4.1 Mike Pearson Larry Franklin 10/30/2006 2.4 Mike Pearson Dennis Vasicek 10/30/2006 2.7.1 Mike Pearson Larry Franklin 10/30/2006 2.7.1 Larry Franklin Mike Pearson 10/30/2006 2.7.1.6 Mike Pearson Larry Franklin 10/30/2006 2.9.1 Mike Pearson Larry Franklin 10/30/2006 2.9.1 Mike Pearson Larry Franklin 10/30/2006 2.9.1.2 Larry Franklin Mike Pearson 10/30/2006 2.9.1 Larry Franklin Mike Pearson 10/30/2006 2.10.1.1 Mike Pearson Larry Franklin 10/31/2006 2.4.1.32.3.10 Larry Franklin Mike Pearson 10/31/2006 2.4.1.33 Larry Franklin Mike Pearson 10/31/2006 2.4.1.34 Larry Franklin Mike Pearson Brief Description of Change Created New Procedure Conducted Annual Review Conduct Annual Review Added Certification of Calibration and Street Atlas files Added “with metal loss” Added “If ILI vendor does not provide GPS Coordinates” Modified to reflect send email to Pipeline Integrity Data Coordinator Insert 2.4.1.24 Determine casings that require rehabilitation based on casing flowchart Insert 2.4.16 Compare proposed dig list to information from previous rehabilitation projects Insert 2.7.1.4 Process casings using ‘Casing Comparison’ spreadsheet Delete 2.7.1.5 Minor modification to paragraph, add link to Rehab book Checklist 2.9.1.1 Insert Receive ‘Casing Comparison’ from PIDC Minor modification to 2.9.1.2 to add ‘Casing Comparison’ comparison Delete 2.9.1.1.1 through 2.9.1.1.3 Insert 2.9.1.3 Added “if ILI vendor does not provide GPS coordinates” Insert 2.4.1.32.3.10 Insert 2.4.1.33 Insert 2.4.1.34 <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 15 of 18 01/01/08 7/10/08 2.2.1.5 Dennis Vasicek Clyde Clausen 7/10/08 2.2.1.6 Dennis Vasicek Clyde Clausen 7/10/08 2.2.1.7 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.2 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.4.2 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.12.1 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.12.4 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.12.5 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.12.6 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.18.1 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.21 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.22 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.30 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.31.3.8 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.31.3.10 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.31.4 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.32.1 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.32.2 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.32.3 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.32.4 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.32.6 Dennis Vasicek Clyde Clausen 7/10/08 2.4.1.33.1 Dennis Vasicek Clyde Clausen 7/10/08 2.4.13 Dennis Vasicek Clyde Clausen Reviewed, no changes Added paragraph and subparagraphs Added paragraph Added paragraph Added paragraph Added paragraph Changed 5 years to 6 years Added paragraph Added paragraph Added paragraph Changed 100% to 80% Deleted paragraph and sub‐paragraphs pertaining to sending email to GIS Coordinator to input GPS information for casings Deleted paragraph about receiving GPS coordinators for casings from GIS Coordinator Added sentence to clarify 60 and 180‐day dates for HCAs Added, “(as identified by the ILI vendor as being axially oriented)” Removed condition, “A girth weld anomaly as identified by ILI vendor” Added paragraph and subparagraphs Added sentence, “However, all HCA Immediate Conditions shall take priority.” Added paragraph and subparagraphs Added paragraph Added paragraph and subparagraphs Added paragraph and subparagraph Modified paragraph Modified paragraph and added subparagraphs <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 16 of 18 7/10/08 2.4.14.1 Dennis Vasicek Clyde Clausen 7/10/08 2.4.14.2 Dennis Vasicek Clyde Clausen 7/10/08 2.4.15 Dennis Vasicek Clyde Clausen 7/10/08 2.4.16 Dennis Vasicek Clyde Clausen 7/10/08 2.4.17 Dennis Vasicek Clyde Clausen 7/10/08 2.4.23 Dennis Vasicek Clyde Clausen 7/10/08 2.4.24 Dennis Vasicek Clyde Clausen 7/10/08 2.4.25 Dennis Vasicek Clyde Clausen 7/10/08 2.4.26 Dennis Vasicek Clyde Clausen 7/10/08 2.4.30 Dennis Vasicek Clyde Clausen 7/10/08 2.4.31 Dennis Vasicek Clyde Clausen 7/10/08 2.4.31 Dennis Vasicek Clyde Clausen 7/10/08 2.7.1.8 Dennis Vasicek Clyde Clausen 7/10/08 2.7.1.9 Dennis Vasicek Clyde Clausen 7/10/08 2.7.1.10 Dennis Vasicek Clyde Clausen 7/10/08 2.7.1.11 Dennis Vasicek Clyde Clausen 7/10/08 2.10 Dennis Vasicek Clyde Clausen 7/10/08 2.10 Dennis Vasicek Clyde Clausen Reworded paragraph Reworded paragraph Added paragraph Added paragraph and subparagraphs Modified paragraph Added paragraph Added paragraph Added paragraph Removed Area Facility Integrity Engineer and added Supervisor Corrosion Control Added paragraph Deleted paragraph about Post Job roundtable Added paragraph and sub‐paragraphs about calculating the average undersize of repaired anomalies Added paragraph Added paragraph Added paragraph Added paragraph Removed section containing “The GIS Coordinator shall:” Added section pertaining to “Pipeline Integrity Coordinator” and three subparagraphs 7/10/08 2.11 Dennis Vasicek Clyde Clausen 12/19/08 2.4.1.9.2 Dennis Vasicek Clyde Clausen 12/19/08 2.4.14.2 Dennis Vasicek Clyde Clausen Added section pertaining to “Supervisor Pipeline Integrity or Manager Pipeline Integrity” and four subparagraphs Removed reference to LAPA RPR’s Added reference to UT ILI 12/19/08 2.4.14.2.1 Dennis Vasicek Clyde Clausen 12/22/08 Global Dennis Vasicek Clyde Clausen 12/22/08 2.4.1.31.4 Dennis Vasicek Clyde Clausen Added, “and match girth welds between the reports” Changed “vendor” to “service provider” Deleted section referencing expired Consent <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 17 of 18 12/22/08 2.4.1.32.6 Dennis Vasicek Clyde Clausen 12/22/08 Dennis Vasicek Clyde Clausen 3/4/09 All Dennis Vasicek Clyde Clausen 01/01/10 2.2.1.1 all All 2.4.1.8 (Old) 2.4.1.8 (new) 2.4.1.12.3 2.4.1.12.4 2.4.1.12.5/2.4.1.13/ 2.4.1.14/2.4.1.16 2.4.1.21 – 2.4.1.24 2.4.1.25‐2.4.1.30 60‐day repair cond/180 day/ Non HCAS 2.4.14.1 – 2.4.14.2.4 2.4.15/2.4.20‐2.4.22 01/01/11 9/1/11 All Clyde Clausen Doug Chabino 12/31/11 all 12/31/11 All 6/18/12 10.2.5 Clyde Clausen Doug Chabino Decree (for acquired Shell assets) Deleted section referencing expired Consent Decree (for acquired Shell assets) Conducted annual review Added references to consent decree – not a significant change so version not updated Added “internal diameter” Changed Longhorn to Mitigation Plan General cleanup/updating to reflect current process Deleted: ref – Pipeline Listing ss Reworded DPP information Added “add to DPP ss. Added – create Run Comparison ss deleted Deleted Moved after dig list Dents at 4/8 o’clock changed to top‐side dents/ bottom side dents Deleted Deleted Reviewed, no changes Re‐worked and Re‐formatted entire document Replaced Rehab Book Checklist with Project File Index Form and AGM Calc Spreadsheet with Total AGMs Form 2012 Annual Review complete Added Laminations interacting with deformations to section 10.2.5 <<>> Magellan Midstream Partners, L.P. IN‐LINE INSPECTION ANALYSIS GUIDELINES 7.03–ADM–007 Asset Integrity 01/01/12 Revision: 4 Page 18 of 18 <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 1 of 29 TABLE OF CONTENTS 1.0 SCOPE 2.0 EXTERNAL CORROSION CONTROL 2.1 External Coating 2.2 Cathodic Protection 2.3 Corrosion Control Criteria 2.4 IR Drop Consideration 2.5 New Construction 2.6 Cathodic Protection Surveys 2.7 Cathodic Protection Rectifiers 2.8 Foreign Crossings and Interference Currents 2.9 Electrical Isolation 2.10 Test Leads 2.11 Exposed Pipe Examination 2.12 Stress Corrosion Cracking Analysis 2.13 Microbiological Influenced Corrosion (MIC) 2.14 Induced AC Corrosion 3.0 ATMOSPHERIC CORROSION CONTROL 3.1 Inspection 3.2 Paint/Coating 4.0 INTERNAL CORROSION CONTROL 4.1 Introduction 4.2 Product Evaluation 4.3 Internal Corrosion Mitigation 4.4 Internal Corrosion Monitoring 4.5 Internal Examination <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 2 of 29 5.0 QUALIFICATION 5.1 Supervisor 5.2 Operator Qualification 6.0 CORROSION CONTROL RECORDS 7.0 INTEGRITY MANAGEMENT PLAN INTEGRATION 8.0 DEFICIENCIES IN CORROSION CONTROL <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 3 of 29 1.0 SCOPE 1.1 This program is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be used in whole or part on non‐jurisdictional assets as deemed appropriate. 1.2 Texas Specific: In addition to applicable Federal, State, and Local regulations, as well as, Magellan guidelines, process, or best practices, certain pipeline system assets in Texas operate under the requirements of the Mitigation Plan. 2.0 EXTERNAL CORROSION CONTROL 2.1 External Coating 195.557, 195.559, 195.561, 16 TAC 8.305(2‐3), 192.455(a)(1) and 192.461. 2.1.1 2.1.2 2.1.3 2.1.4 2.1.5 2.1.6 2.1.7 2.1.8 All buried or submerged newly constructed, relocated, replaced or otherwise changed steel lines shall be coated, including mainlines, terminal and station piping. The external coating shall be applied on a properly prepared surface and have sufficient adhesion to the metal surface to effectively resist underfilm migration of moisture. The coating shall be sufficiently ductile to resist cracking and have sufficient strength to resist damage due to handling and soil stress. The coating shall have properties compatible with the cathodic protection system. Electrically insulating type coatings shall have low moisture absorption and high electrical resistance. The coated pipe shall be electrically inspected using a coating deficiency (holiday) detector prior to installation. Any damage found that impairs the effectiveness of the coating shall be repaired. Furthermore, the coating shall be protected from damage resulting from adverse ditch conditions or damage from supporting blocks. Backfilling operations will be inspected to ensure that rocks, hard lumps of earth, etc. are not backfilled directly onto the pipe where they may damage the effectiveness of the pipeline coating. Precautions will be taken to minimize damage to the coating during installation if coated pipe is installed by boring, driving, or other similar method. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 4 of 29 2.2 2.1.9 Joints, fittings, and tie‐ins shall be coated with material(s) compatible with the coating(s) on the pipe. 2.1.10 Coatings selection, application, and maintenance shall be performed as prescribed in Coatings – Selection, Applications, and Maintenance. Cathodic Protection – 195.563, 195.565, 192.452, 192.453, 192.455 and 192.457 2.2.1 2.2.2 2.2.3 2.2.4 On facilities including newly constructed, relocated, replaced or otherwise changed pipelines, a cathodic protection system will be installed to mitigate corrosion. A cathodic protection system will be installed for breakout tanks to mitigate corrosion. The systems shall be installed in accordance with API Recommended Practice 651, unless noted in this volume why compliance with all or certain provisions of API Recommended Practice 651 is not necessary for the safety of the breakout tank. Noted conditions that will cause compliance with 651 to not be observed may be but are not limited to tanks set on concrete, asphalt pads, or where studies conducted in accordance with API 653 indicate that corrosion will not affect the safe operation of the tank. On facilities including newly constructed, relocated, replaced, or otherwise changed pipelines and tanks, a temporary cathodic system shall be provided as soon as practical during construction and a permanent cathodic protection system shall be provided within one year of completed construction. Refer to Design and Installation of an Impressed Current Deep Groundbed and Design and Installation of an Impressed Current Surface Groundbed for more 2.3 information. 2.2.5 Soil Resistivity may influence the design considerations for cathodic protection systems as well as development of the Relative Risk Score for the line segment. See Soil Resistivity Overview for a general description of expected soil resistivity identified by state. Corrosion Control Criteria 195.571, 192.463 2.3.1 Magellan adheres to the cathodic protection regulations in Part 195, “Transportation of Hazardous Liquids by Pipeline” and to the cathodic protection regulations in Part 192, “Transportation of Natural and Other Gas by ”pipeline: Minimum Federal Safety Standards,” of the DOT/Pipeline and Hazardous Materials Safety Administration Pipeline Safety Regulations. 2.3.2 When practical, Magellan requires maintaining a polarized potential of at least –0.850 volts as measured between the structure surface and a saturated <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 5 of 29 2.4 2.3.3 2.3.4 2.3.5 2.3.6 2.3.7 copper‐copper sulfate reference electrode that is in contact with the electrolyte (earth, soil, water, etc.). Where injurious aerobic bacteria has been identified, or is suspected, a polarized potential of ‐.950 volts or more negative is required. This voltage measurement shall be determined with the protective current applied and IR drop considered as described in paragraph 2.4 below. Assets covered by the Mitigation Plan: For Tier II and Tier III areas, where practical a polarized pipe‐to‐soil potential of ‐.850 volts will be maintained. During close interval surveys, potential drops other than those across the structure to electrolyte boundary will be considered by interrupting the cathodic protection current source(s) and recording the ON” and “OFF” pipe‐ to‐soil potentials Once established, the “ON” potential and “Off” potential will be utilized to correct future pipe‐to‐soil potential readings until such time as the system configuration or coating condition changes, or a new close interval survey is performed. When a ‐0.850 volt potential is not practical, the following criteria are acceptable when approved by the Supervisor of Corrosion Control: 2.3.4.1 A minimum negative (cathodic) polarization shift of 100 millivolts The 100‐millivolt polarization decay criteria specify a minimum negative (cathodic) polarization voltage shift of 100 millivolts, measured between the structure surface and a reference electrode contacting the electrolyte. Overprotection will be monitored and minimized through the analysis of data from annual pipe‐to‐soil surveys, close interval surveys, and pipeline visual inspections. A practical value of ‐1.2 volts (polarized) in reference to a copper/copper sulfate electrode will be used as value beyond which monitoring for overprotection shall be considered. Refer to Cathodic Protection Criteria for more information. IR Drop Consideration 195.571 and 192.463 (a) 2.4.1 IR drop is considered by taking potential readings directly over or as near as practical to the structure surface. The affect on the potential measuring circuit is kept to a minimum by using a high resistance voltmeter and being mindful of lead lengths and condition, contact to structure and contact to electrolyte. 2.4.2 Cathodic protection level should be evaluated utilizing Cathodic Protection Criteria. 2.5 New Construction 195.563 and 192.455(a)(2) <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 6 of 29 2.6 2.5.1 On newly constructed facilities and/or pipelines, a temporary cathodic system shall be provided as soon as practical during construction and a permanent cathodic protection system shall be provided within one year of completed construction. 2.5.2 Newly constructed facilities shall be included in and be managed in accordance with the Magellan System Integrity Plan within one year of completed construction. 2.5.3 On newly constructed facilities and/or pipelines, corrosion personnel, qualified under the Operator Qualification Ruling or with NACE Certification, shall be utilized to identify, mitigate, and monitor for inadequate cathodic protection and detrimental interference currents, prior to and during construction. Refer to Section 2.8, Foreign Crossings and Interference Currents and 2.14, Induced AC Corrosion below. Cathodic Protection Surveys 195.573 (a) (d) and 192.465 2.6.1 A cathodic protection survey shall be conducted on each buried, in contact with the ground, submerged pipeline facility, and/or breakout tank in its pipeline system that is under cathodic protection once each calendar year with intervals not to exceed fifteen months. Pertinent survey information shall be recorded in the Cathodic Protection Data Manager (CPDM) within 30 days after the survey. 2.6.2 Assets covered by the Mitigation Plan: Pipe‐to‐soil surveys shall be performed annually not to exceed 15 months in Tier I areas and semi‐annually not to exceed 7.5 months in Tier II and Tier III areas. Deficiencies will be resolved within one (1) year of discovery, except deficiencies of such a nature they present a more urgent threat to pipeline integrity, in which case corrections will be done immediately. 2.6.3 Pipe‐to‐soil readings shall be obtained at pre‐assigned locations identified as necessary to determine the adequacy of cathodic protection. These locations can include, but are not limited to, test stations, cased crossings, and above ground appurtenances. Refer to Measuring a Pipe‐to‐Soil Potential for more information. 2.6.4 For aboveground breakout tanks where corrosion of the tank bottom is controlled by a cathodic protection system, the cathodic protection system shall be inspected to ensure it is operated and maintained in accordance with API Recommended Practice 651, unless noted in this volume why compliance with all or certain provisions of API 651 is not necessary for the safety of a <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 7 of 29 2.6.5 2.6.6 particular breakout tank. Noted conditions that will cause compliance with 651 to not be observed may be but are not limited to tanks set on concrete, asphalt pads, or where studies conducted in accordance with API 653 indicate that corrosion will not affect the safe operation of the tank. Pertinent survey information shall be recorded in the Cathodic Protection Data Manager (CPDM) within 30 days after the survey. 2.6.4.1 Potential surveys taken on above‐ground storage tanks should be conducted with an adequate level in the tank to maximize the contact of the tank bottom with the cushion material. Adequate level is typically at least 3 feet of liquid. Tank levels shall be recorded along with potential measurements. Tanks with inadequate levels shall be re‐surveyed the same calendar year, once adequate levels are attained. Additional corrosion control surveys, including but not limited to close interval pipe‐to‐soil surveys, will be conducted where practical and determined necessary by sound engineering practices. Indicators of the necessity to conduct such surveys shall include risk assessments, annual pipe‐to‐soil surveys, internal inspection data, pipe inspection, or other related corrosion information or testing. At a minimum, close interval pipe‐to‐soil surveys will be considered under the following circumstances: 2.6.6.1 When identified through risk assessment including Section 6 analysis required by the Integrity Management Plan. 2.6.6.2 Assets covered by the Mitigation Plan: Close Interval surveys in Tier III areas will be conducted annually not to exceed 15 months. For Tier I and II areas close interval surveys will be managed through the Relative Risk Assessment Process within the System Integrity Model and conducted as necessary. Deficiencies will be resolved within one (1) year of discovery, except deficiencies of such a nature they present a more urgent threat to pipeline integrity, in which case corrections will be done immediately. 2.6.6.3 External Corrosion identified on the pipeline with a peak depth greater than 50% of the nominal wall, within 50 feet of a foreign pipeline crossing. Close interval survey may not be required if pipe‐ to‐soil data collected at the location indicates that cathodic protection interference is not a concern. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 8 of 29 2.6.6.4 2.6.6.5 2.6.6.6 Areas of inadequate cathodic protection as identified by pipe‐to‐soil surveys. Close interval survey may not be required if remediation of the low potentials includes the addition, modification, or adjustment of an impressed current cathodic protection that provides cathodic protection current beyond the area of inadequate potentials. Areas of interference from a foreign cathodic protection current source. Locations of potential interference include but are not limited to, construction of new cathodic protection systems near the pipeline, changes in current output from foreign cathodic protection systems, and a reduction in cathodic protection levels without a corresponding reduction in output from the existing cathodic protection system. In each case, the Close Interval Survey shall be conducted at spacing close enough to identify potential integrity threats and extend beyond the area of likely influence. Refer to Close Interval Pipe‐to‐ Soil Survey and Testing for Interference Currents and Remedial Measures for more information. 2.7 Cathodic Protection Rectifiers 195.573 (c) and 192.465 (b) 2.7.1 Each cathodic protection rectifier shall be inspected for proper operation at least six times each calendar year with intervals between inspections not to exceed 2 ½ months. Pertinent survey information shall be recorded in the Cathodic Protection Data Manager (CPDM) within 30 days after survey. Refer to Rectifier Inspection, Cathodic Protection System Troubleshooting (Groundbed), and Rectifier Troubleshooting for more information. 2.8 2.7.2 Assets covered by the Mitigation Plan: Each cathodic protection rectifier shall be inspected for proper operation at least twelve (12) times each calendar year with intervals between inspections not to exceed 45 days. Deficiencies will be resolved within one (1) month of discovery, except deficiencies of such a nature they present a more urgent threat to pipeline integrity, in which case corrections will be done immediately. Foreign Crossings and Interference Currents 195.573(c), 195.577, 16 TAC 7.86(5)(c), 192.465 (c) and 192.473 2.8.1 During each cathodic survey, a check of the integrity of each bond that exists across insulating flanges or other unions of pipeline facilities and each interference bond shall be made. Reverse current switches, diodes and <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 9 of 29 interference bonds whose failure would jeopardize structure protection shall be inspected six times each calendar year with intervals between inspections not to exceed 2 ½ months. Pertinent survey information shall be recorded in the Cathodic Protection Data Manager (CPDM) within 30 days after the survey. Refer to Electrical Bond Inspection for more information. 2.8.2 2.8.3 Impressed current cathodic protection systems or galvanic anode systems will be designed and installed to minimize any adverse effects on existing underground metallic structures. Stray current interference testing, including, but not limited to close interval pipe‐to‐soil surveys, will be conducted where practical and determined necessary by sound engineering practices. Indicators of the necessity to conduct such tests shall include annual pipe‐to‐soil surveys, internal inspection data, pipe inspection, or other related corrosion information or testing. Pertinent survey information shall be recorded on Magellan Foreign Line Interference Test Form. Refer to Testing for Interference Currents and Remedial Measures for more information. 2.9 2.8.4 Texas Intrastate Pipeline specific: Whenever suspected areas of interference are identified, testing will be conducted within 6 months to determine the extent of interference, and appropriate action will be taken. 2.8.5 For Interference Currents related to Induced AC refer to Section 2.14, Induced AC Corrosion below. Electrical Isolation 195.575 and 192.467 2.9.1 Each buried or submerged pipeline shall be electrically isolated from other underground metallic structures, unless the pipeline and the other structures are electrically interconnected and cathodically protected as a single unit. 2.9.2 One or more insulating devices shall be installed where electrical isolation of a portion of a pipeline is necessary to facilitate the application of corrosion control. 2.9.3 During each cathodic survey, a check of the integrity of insulating flanges or other unions of pipeline facilities shall be made if inadequate cathodic protection levels are found. 2.9.4 Shorted Casings 2.9.4.1 During each cathodic protection survey, readings may be taken at each cased crossing to detect any location where the carrier pipe may be shorted to the casing pipe. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 10 of 29 2.9.4.2 2.9.4.3 If the casing potential is greater than ‐.800 volts, the casing shall be tested to determine whether an electrolytic short to the carrier pipe is present. Corresponding classification data documenting the status of the casing shall be recorded in the Cathodic Protection Data Manager (CPDM). Refer to Shorted Casing Testing for more information. If the casing potential is within 100 millivolts of the pipeline potential, the casing shall be tested to determine whether a short to the carrier pipe is present. Corresponding classification data documenting the status of the casing shall be recorded in the Cathodic Protection Data Manager (CPDM). Refer to Shorted Casing Testing for more information. 2.9.4.4 Following internal inspection of a pipeline, the resulting smart pig data will be integrated with and compared to the casing information in the corrosion control database. Where the carrier pipe within the casing exhibits corrosion‐caused metal loss, a risk evaluation will be conducted and action will be taken to mitigate the corrosion if deemed necessary. NOTE: For line sections integrity tested by hydrostatic test, a risk evaluation will be conducted at each shorted casing and action taken to clear the short and/or mitigate the corrosion if deemed necessary. 2.9.4.5 2.9.4.6 Assets covered by the Mitigation Plan: If a shorted casing is verified, a plan of action shall be developed within three (3) months from the time of discovery. The practicality of clearing the short will be considered before any other measures are used. Action shall be taken to clear the short (a) in Tier I areas within six (6) months of development of the action plan; and (b) in Tier II and III areas within three (3) months of development of the action plan. If clearing the short is impractical, the location can be monitored for leaks, or the casing/pipe interstice may be filled with a high dielectric corrosion inhibiting material. If the casing is monitored using leak detection equipment, the test must be performed twice each calendar year not exceeding 7.5 months. If monitored using internal inspection (smart pig) equipment, the inspection must be made at intervals as determined in the Magellan, Integrity Management Plan. These alternative measures, or any other <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 11 of 29 2.10 measures approved by the Manager of Asset Integrity may be employed until it is practical to clear the short. 2.9.4.7 Assets covered by the Mitigation Plan: In the interim, from the time, a short is verified and action is taken to clear the short, the location will be inspected for corrosion or the casing /pipe interstice may be filled with a high dielectric corrosion inhibiting material. During any interval that a casing has been determined to be shorted, casing will be monitored. Tier I areas will be monitored twice per year at intervals not exceeding 7.5 months. Tier II and III areas will be monitored monthly at intervals not exceeding 6 weeks. 2.9.5 Insulating devices installed in areas where a combustible atmosphere is reasonable to foresee shall be installed with precautions to prevent arcing. 2.9.6 Pipelines in close proximity to electrical transmission tower footings, ground cables, or counterpoise, or in other areas where it is reasonable to foresee fault currents or an unusual risk of lightning, shall be protected against damage from fault currents or lightening and protective measures taken at insulating devices. Test Leads 195.567, 192.469 and 192.471 2.10.1 All cathodically protected pipelines and breakout tankage shall have a sufficient number of test stations or other locations for electrical measurement to determine the adequacy of the cathodic protection system. 2.10.2 For design purposes, test lead spacing on pipelines shall be approximately one mile. This spacing shall be affected by conditions along the pipeline. 2.10.3 Breakout tankage will be monitored at the four quadrants. 2.10.4 The test leads shall be connected directly to the structure by Thermit welding or other process, which prevents stress concentration on the pipe and is approved by the Supervisor of Pipeline Integrity. 2.10.5 Test leads shall be maintained so that electrical measurements can be obtained in order to ensure adequate protection. For locations where repair of the test station is impractical, and a reading is necessary to determine the adequacy of cathodic protecting, an insulated probe rod may be used to contact the pipe and obtain the reading. This measure may be utilized until which time the test lead is repaired. 2.10.6 During installation, test leads shall be installed with enough looping or slack to prevent the test leads from undue stress or breakage during backfilling. Test <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 12 of 29 leads installed in conduit shall be suitably insulated from the conduit. Refer to Attaching Cathodic Protection Test Leads for more information. 2.11 2.10.7 Bared test lead wire and bared metallic area at the point of connection to pipeline must be coated with an electrical insulation material compatible with the pipe coating and the insulation on the wire. Exposed Pipeline Examination 195.569 and 192.459 2.11.1 When any buried pipeline is exposed, either intentionally or unintentionally, the exposed portion shall be visually inspected for evidence of external corrosion. Refer to Examining and Documenting the Condition of an Underground Pipeline or Related Facility When Exposed for more information. 2.11.2 When external corrosion requiring remedial action is found, further investigation will be conducted, circumferentially and longitudinally beyond the exposed portion (by visual examination, indirect method, or both) to determine the extent of the corrosion in the vicinity of the exposed portion. Refer to Pipeline Defect Evaluation and Repair for more information. 2.11.3 If the extent of corrosion cannot be determined, plans and scheduling for further investigation or the use of an internal inspection device shall be developed based on the severity of the corrosion encountered. 2.11.4 If the exposed pipe is to remain exposed, proper pipeline markers shall be installed and the pipe shall be monitored for atmospheric corrosion in accordance with paragraph 3.1.1 below. 2.12 Stress Corrosion Cracking (SCC) 2.12.1 Basic SCC awareness information is available to operation and maintenance employees in Stress Corrosion Cracking Information. 2.12.2 The risks associated with SCC are identified and assessed per the Magellan Risk Assessment Methodology book, and include factors such as age of the 2.12.3 2.12.4 pipeline, coating type, operating stress level, proximity of pump stations and history of SCC. In the event that a pipeline system has experienced one or more confirmed incidents of SCC a systematic identification and examination of other potential locations of SCC will be conducted based upon the observations of conditions associated with the confirmed SCC incident. Areas of the pipeline identified as having high susceptibility to SCC, or any other locations identified for SCC investigation, will be investigated per Stress Corrosion Cracking Investigation. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 13 of 29 2.12.5 2.12.6 Pipe cutouts sent to a metallurgical lab for analysis will be investigated for SCC. Results of this analysis will be provided in a comprehensive report provided to Asset Integrity. SCC field examinations will be performed by a NDE Technician trained in the detection of SCC on buried pipelines and will be documented in the Pipeline Maintenance Report. 2.12.7 If SCC is determined to be present, a review of the pipeline as defined in Section 6 of the IMP will be conducted, to be followed by a re‐assessment interval recommendation per Section 7 of the IMP. 2.12.8 Annually, confirmed SCC occurrences will be reviewed to determine if changes to the SCC assessment criteria are necessary. 2.13 Microbiological Influenced Corrosion (MIC) 2.13.1 In the event that a pipeline system has experienced one or more confirmed discoveries of injurious MIC, or where accelerated corrosion from MIC is anticipated, a Bacteria Testing Protocol shall be established to evaluate future 2.13.2 2.13.3 integrity threats from MIC. The line specific protocol shall be utilized until such time that the threat from MIC has been assessed and appropriate mitigation actions have been taken. Testing for MIC shall be conducted in accordance with Bacteria Testing – Serial Dilution Method. 2.14 Induced AC Corrosion 195.577 192.473 2.14.1 AC potential surveys shall be conducted on each buried, in contact with the ground, submerged pipeline facility near high voltage power lines once each calendar year with intervals not to exceed fifteen months. Recording voltmeters should be considered in areas where high voltage transmission lines parallel the pipeline over long distances. Pertinent survey information shall be recorded in the Cathodic Protection Data Manager (CPDM) within 30 days after the survey. Refer to Testing for Induced AC and Remedial Measures for more information. 2.14.2 AC potentials greater than 5 volts will be evaluated to determine if additional testing or remedial actions are required. Refer to Testing for Induced AC and Remedial Measures for more information. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 14 of 29 2.14.3 Remedial actions are required where through testing or calculations, AC current discharge densities are found to be at or greater than 100 A/m2 or AC potentials are greater than 15 volts. Remedial action may be required where AC current discharge densities range from 20‐100 A/m2. Refer to Testing for Induced AC and Remedial Measures for more information. 3.0 ATMOSPHERIC CORROSION CONTROL 3.1 Inspection 195.581, 195.583, 192.479 and 192.481, and 16 TAC 8.305(1) 3.1.1 Facilities and/or pipelines, other than Breakout Tanks, shall be inspected at least once every three (3) calendar years with intervals not exceeding 39 months for onshore and at least once each calendar year, with intervals not exceeding 15 months, for offshore. Refer to Atmospheric Corrosion Inspections for more information. NOTE: Atmospheric corrosion inspections on exposed pipelines must be conducted visually. 3.1.2 Assets covered by the Mitigation Plan: Facilities and/or pipelines, other than Breakout Tanks, shall be inspected annually for atmospheric corrosion. Refer to Atmospheric Corrosion Inspections for more information. 3.1.3 Breakout Tanks shall be inspected at least once every five (5) years with intervals not exceeding 60 months. Refer to Atmospheric Corrosion Inspections for more information. 3.2 3.1.4 Assets covered by the Mitigation Plan: Corrective action for deficiencies found during atmospheric surveys shall be determined and completed as soon as practical. Deficiencies will be resolved within one (1) year of discovery, except deficiencies of such a nature they present a more urgent threat to pipeline integrity, in which case corrections will be done immediately. Coating 195.581, 195.583, 192.479 and 192.481 3.2.1 A suitable coating shall be applied to all new aboveground facilities to prevent atmospheric corrosion damage. Refer to Coatings – Selection, Applications, and Maintenance for more information. 3.2.2 A suitable coating shall be applied to all soil‐to‐air interface areas to prevent atmospheric and electrolytic corrosion damage. Refer to Coatings – Selection, Applications, and Maintenance for more information. 3.2.3 A suitable coating shall be applied to all aboveground facilities to prevent further atmospheric corrosion damage if, through the guidelines established <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 15 of 29 in the Atmospheric Inspection Procedure, a Rust Rating of 2‐G or worse is identified. Refer to Coatings – Selection, Applications, and Maintenance for more information. 3.2.4 The coating conditions on exposed assets shall be documented in the Atmospheric Corrosion database (CPDM). 4.0 INTERNAL CORROSION CONTROL 4.1 Introduction 195.579 and 192.477 4.1.1 The corrosive effects of pipeline cargoes (hazardous liquids or carbon dioxide) shall be investigated and if found to be corrosive, adequate steps shall be taken to mitigate internal corrosion. If steps are taken to mitigate corrosion, the effectiveness of the steps shall be monitored using corrosion coupons and/or other methods. 4.1.2 Circumstance or condition [such as those listed below] that could cause, promote, or increase the likelihood of internal corrosion should be promptly reviewed and internal corrosion mitigation plans implemented as appropriate. 4.1.2.1 Type of commodity 4.1.2.2 Flow rate 4.1.2.3 Velocity 4.1.2.4 Operating Pressure 4.1.2.5 Topography 4.1.2.6 Amount of foreign material and/or contaminants present in the pipeline and/or commodity stream such as sand, silt, water, or other materials that could cause or promote internal corrosion 4.1.2.7 Amount of sulfur, salts, acids, hydrogen sulfide, carbon dioxide or other corrosive material present and corrosive effect based upon partial pressures of material in the pipeline 4.1.2.8 Presence of microbes 4.1.2.9 Temperature 4.1.2.10 Pipe configuration, design, and material specifications <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 16 of 29 4.1.2.11 Operating conditions, including but not limited to, steady state conditions, slack line conditions, upset conditions in the pipeline system, and upset conditions in upstream facilities such as refineries or processing facilities 4.2 Product Evaluation 4.2.1 Crude Oil or natural gas containing water in the liquid phase, solids, and other corrosive constituents such as bacteria, H2S, CO2 and O2, are considered potentially corrosive. 4.2.2 Refined Petroleum Products are evaluated using NACE TM 0172‐2001, “Determining Corrosive Properties of Cargoes in Petroleum Product Pipelines”. Petroleum products are considered "corrosive" if they do not meet at least a "C" rating on this test. Assets covered by the Mitigation Plan have a target NACE rating of “A” 4.2.3 Natural Gas Liquids are evaluated using ASTM D 1838, "Standard Test Method for Copper Strip Corrosion by Liquefied Petroleum Gases.” Natural gas liquids are considered "corrosive" if they fail to meet the Number 1 classification on this test. 4.2.4 Free water in any product is potentially corrosive 4.2.4.1 Refer to Bacteria Testing – Serial Dilution Method for more information. 4.3 Internal Corrosion Mitigation 4.3.1 Adequate steps, including eliminating the possibility of free water, removing corrosive components, or injecting corrosion inhibitor will be taken whenever investigation of the corrosive effect of the product on the metal indicates it is necessary. 4.3.2 Cleaning pigs 4.3.2.1 procedures as required. 4.3.2.2 To reduce the potential for unnecessary shut downs and/or unmanageable product contamination, pipelines with no history of pigging or those with significant amounts of known debris should not be pigged until adequate precautions and/or contingency plans have been developed. Pipeline cleaning pigs should be utilized system wide on mainline piping. Refer to Perform Pigging Operations or location specific <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 17 of 29 4.3.2.3 4.3.2.4 4.3.2.5 4.3.2.6 4.3.2.7 4.3.2.8 The frequency for routine cleaning operations of mainline product piping should be 2 times per year, approximately every 6 months. The frequency for routine cleaning operations of mainline crude piping should be 26 times per year, approximately every two weeks. Frequencies of cleaning pig runs may be adjusted as necessary based upon product upsets and the analysis of results of previous cleaning pig runs. Cleaning of facility piping, pipelines without launching or receiving equipment, and/or other non‐piggable sections should be conducted as required on a case by case basis. Pipelines transporting NH3 do not require routine pigging, but should be cleaned if excessive debris is identified prior to In‐line inspection tool runs. Pipeline pigging or repigging operations should also be considered when excessive debris is identified in the pipeline, following transportation of a corrosive (off spec) product, in preparation for integrity testing with a in‐line inspection tool, following hydrostatic testing of a pipeline, etc. Although the presence of debris in the receiving scraper trap does not necessarily indicate the quantity of material removed from the pipeline, it should be taken into consideration when determining the frequency of the cleaning pig operations. The physical condition of the pigs should also be taken into consideration, as a badly worn pig may be the result of excessive pipeline debris. During normal cleaning operations, a combination cup and brush pig (1st pig) followed, as soon as practical, by a combination cup and disc pig (2nd pig) should be utilized. Where excessive debris and paraffin buildup is thought to exist, specialty pigs such as pin‐wheel, Pit Boss™, scraper/plow blade attachments, and magnetic cleaning pigs shall be utilized as necessary based upon sound engineering judgment. Significant separation between the multiple pigs is not required and separation by more than a few yards will actually decrease the effectiveness of the operation. Cleaning pigs should be maintained in accordance with the manufactures recommendations. Pigs worn beyond the manufactures recommend tolerance should not be used. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 18 of 29 4.3.2.9 If a pig is to be run in a line which has not been pigged in many years or in a line which is suspected to be un‐piggable, soft low density Polly Pigs should be utilized until confidence is achieved that normal cleaning pigs will successfully traverse the pipeline. Specialty pigs with tracking devices may also be warranted if there is concern that the pigs may become stuck in the pipeline. 4.3.2.10 Normal cleaning operations should be conducted at a continuous 3 ft/sec or less where practical. 4.3.2.11 Caution should be observed when pigging lines that start and stop. Debris may fall out in front of the pig causing the pig to become stuck. 4.3.3 Corrosion Inhibitor 4.3.3.1 When a corrosion inhibitor is used to mitigate internal corrosion, a sufficient quantity to protect the entire part of the system the inhibitor is designed to protect will be used. Initial inhibitor injection rates will be based on product characteristics of the product to be inhibited .For refined product systems a hydrocarbon soluble, water dispersible corrosion inhibitor shall be utilized (Smart Chemical SCSF260 or equivalent). For crude pipeline systems, a highly water dispersible/soluble blend of corrosion inhibitors shall be utilized (Smart Chemical SCCI865 or equivalent). 4.3.3.2 Assets covered by the Mitigation Plan: Inhibitors are required to control potential internal corrosion. NOTE: Whenever a corrosion inhibitor injection pump, internal coating, or other equipment to mitigate internal corrosion, is installed or removed a Pipeline Maintenance Report shall be completed. 4.3.4 When installing a tank bottom lining in an aboveground breakout tank, the lining shall be installed in accordance with API Recommended Practice 652 unless noted in this volume why compliance with all or certain provisions of API Recommended Practice 652 is not necessary for the safety of the tank. 4.4 Internal Corrosion Monitoring 4.4.1 When corrosion inhibitors are used to mitigate internal corrosion, coupons or other types of monitoring will be used to determine the effectiveness of the inhibitor and the potential extent of any corrosion. Refer to Coupon Handling and ER Probes for more information <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 19 of 29 NOTE: Whenever new coupon holding devices or ER Probes are installed, a Pipeline Maintenance Report shall be completed. 4.4.2 4.4.3 4.4.4 At least twice each calendar year, and not exceeding intervals of 7 ½ months, corrosion coupons shall be removed from the test locations and forwarded to an appropriate laboratory for corrosion analysis (Reference NACE RPO775 for more information). Assets covered by the Mitigation Plan: At least three times each calendar year, and not exceeding intervals of 4.5 months, corrosion coupons shall be removed from the test locations and forwarded to an appropriate laboratory for corrosion analysis. New corrosion coupons will be installed at this time. Any alternate or supporting corrosion monitoring methods will be accomplished at the same minimum frequency. Pertinent monitoring data shall be documented in the Internal Corrosion Database and/or the appropriate inspection forms. Refer to Coupon Handling and ER Probes for more information. NOTE: There may be instances in which a product is not corrosive, and therefore not inhibited. Corrosion coupons may be used to periodically evaluate these products. In these instances, coupon monitoring may be less frequent than twice per calendar year and 7 ½ month intervals. 4.4.5 4.4.6 4.4.7 Effectiveness of inhibitor will be based on the inhibitor’s success in reducing the internal corrosion rate to an acceptable level. This level of acceptability may be different for each pipeline, but is typically <1 MPY for refined products and <3 MPY for crude. General corrosion rates can be classified as Low<1 mpy, Moderate 1.0 – 4.9 mpy. Sever >10 mpy. Internal corrosion rates greater than >1 MPY (refined products) or >3 MPY (crude) on inhibited pipelines shall be followed up with a detailed analysis regarding injection rates, hydro‐tests, or other unusual activities or circumstances. Action plans shall be developed if deemed necessary using sound engineering judgment. Assets covered by the Mitigation Plan: Coupon corrosion rates over 1 mpy of general corrosion or pitting (including MIC) will trigger a detailed analysis directed by NACE certified corrosion control personnel. This analysis will include a review of incoming product quality sample data, inhibitor injection rates, bacteria testing and, if necessary, inhibitor performance testing. Deficiencies will be resolved within six (6) months of discovery, except <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 20 of 29 4.5 4.4.8 4.4.9 deficiencies of such a nature they present a more urgent threat to pipeline integrity, in which case corrections will be done immediately. For crude pipeline systems, water sample traps will be mounted on the bottom of the pipe to facilitate the collection and analysis of free water. These locations will be inspected for water monthly and if a sufficient amount of water is present (typically >1 pint) this water shall be analyzed for bacteria, pH, iron, manganese, chlorides, and inhibitor residual (Reference API RP‐45, NACE TM0194, NACE RP0192, and ASTM D2327 for more information). Bacteria counts in excess of 10‐100 colonies/ml., pH readings outside a range of 4‐8, inhibitor residual less than ~10ppm, or an increase in iron, manganese, or chlorides could indicate an increase threat to internal corrosion. Water and debris brought into receiving traps during pigging operations will be tested to determine its potential to cause internal corrosion if determined to be necessary after consultation with the Corrosion Specialist. Crude assets covered by the Mitigation Plan: Coupon/water sample collection points will be located in facilities at origination points, along the pipeline system, and end points. Locations chosen for initial sampling points include Ft. McKavett, Cedar Valley, Satsuma, and East Houston. Additional coupon/water sample collection points may be installed as determined necessary through hazard analysis. Internal Examination 195.579(c) and 192.475 (b) 4.5.1 Whenever any pipe is removed from the pipeline for any reason, the internal surface shall be inspected for evidence of corrosion. Refer to Examining and Documenting the Condition of an Underground Pipeline or Related Facility When Exposed for more information. 4.5.2 4.5.3 4.5.4 When corrosion requiring remedial action is found, further investigation will be conducted both circumferentially and longitudinally (by visual examination, indirect method, or both) to determine the extent of the corrosion. Remedial actions will follow if necessary. Refer to Pipeline Defect Evaluation and Repair for more information. If the extent of corrosion cannot be determined, plans and scheduling for further investigation or the use of an internal inspection device shall be developed based on the severity of the corrosion encountered. The internal condition of the pipelines shall be documented on the Pipeline Maintenance Report. 5.0 QUALIFICATION <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 21 of 29 5.1 Supervisor Qualification 195.555 and 192.453 5.1.1 Magellan Asset Integrity Supervisors shall be knowledgeable of Magellan corrosion control procedures, including but not limited to those for design, installation, operation, and maintenance of internal and external corrosion control systems. 5.1.2 Supervisors may be registered professional engineers, or persons recognized as corrosion specialists or cathodic protection specialists by NACE, and/or their professional activities include suitable experience in corrosion control. 5.2 Operator Qualification 5.2.1 Operator Qualification (OQ) is required for personnel to perform identified Covered Tasks. Refer to Operator Qualification (OQ) – Covered Tasks for more information. 5.2.2 Assets covered by the Mitigation Plan: All Corrosion related activities shall be applied under the direction of competent personnel trained in the field of corrosion control. Corrosion control data shall be reviewed by NACE certified corrosion personnel. 6.0 CORROSION CONTROL RECORDS 195.404 and 192.491 6.1 Records or maps shall be maintained to show the location of: 6.1.1 Cathodically protected pipelines 6.1.2 Cathodic protection facilities, including galvanic anodes, installed after January 28, 2002 6.1.3 Neighboring structures bonded to cathodic protection systems. 6.2 Records or maps shall be maintained showing a stated number of anodes, installed in a stated manner or spacing. Specific distances to each buried anode need not be shown. 6.3 Records shall be maintained of each analysis including root cause analysis, check, demonstration, examination, inspection, investigation, review, survey, and test required in sufficient detail to demonstrate the adequacy of corrosion control measures or that corrosion requiring control measures does not exist. These records shall be maintained for a minimum of 5 years. 6.4 All pipe to soil survey, rectifier inspection, and foreign line crossing pipe to soil potential data will be recorded in the appropriate corrosion control database. All close interval pipe to soil potential data will be recorded in a hard copy report as well as the appropriate electronic format, atmospheric inspection data and exposes pipe visual inspection data will be documented on the appropriate forms and distributed <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 22 of 29 appropriately, and will feed into and be processed in overall LPSIP by populating appropriate portions of the relative risk model. 6.5 As long as the pipeline remains in service, records shall be maintained for: 6.5.1 Exposed portions of buried pipelines 6.5.2 Cathodic protection surveys, including close interval or comparable surveys 6.5.3 Internal corrosion coupon examination records and records of internal examination of removed pipe 7.0 INTEGRITY MANAGEMENT PLAN INTEGRATION 7.1 In accordance with the Integrity Management Plan, the Pipeline Risk Engineer will conduct integrated analysis with the External Corrosion Control Program Manager and/or SMEs to ensure effective integration of data, recommendations, and/or program enhancements identified during risk assessments and analysis. 7.2 Recommendations or process changes identified by the External Corrosion Control Program Manager and/or SMEs as a result of the integrated analysis will be communicated to and discussed with Pipeline Risk Engineer in accordance with the Magellan IMP. 7.3 Mitigation measures or process changes conducted by the External Corrosion Control Program Manager and/or SMEs as a result of the integrated analysis will be communicated to and discussed with Pipeline Risk Engineer in accordance with the Magellan IMP. 7.4 Whenever a line is added or removed from the Corrosion Control Program or elements of the Corrosion Control Program (i.e. External, Internal, Atmospheric), the Pipeline Risk Analyst shall be notified in order to update the Risk Assessment Model. All pipelines included in the Corrosion Control Program shall be maintained in accordance with the program guidelines and criteria. Corrosion Control records or data from new construction or pipeline acquisition activities shall be entered into the Corrosion Control database within one year. Pipelines not included in the program are not maintained in accordance with the program and as such, corrosion can be expected. See Inactive Pipelines and Abandoning Pipeline Segments for more details. 8.0 DEFICIENCIES IN CORROSION CONTROL 8.1 Deficiencies in Corrosion Control shall be corrected in a reasonable time. 8.1.1 Unless otherwise specified in this program, a reasonable time to correct deficiencies is defined as by the next scheduled inspection. <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 23 of 29 8.1.2 8.1.3 In the case where deficiencies cannot be complete by the next scheduled inspection; planning, scheduling, progress, assessment, testing, monitoring, and/or other process that demonstrates that the threat in being addressed in a prudent and practical manner may be utilized until such time the deficiency has been resolved. A cause analysis will be performed to identify contributing factors and root causes of anomalies/deficiencies identify by corrosion control surveys. <<>> A Fugitive VOC Emissions for Each New Pump Station and Meter Station In Service Equipment Type Representative Equipment Count per Station1 Service VOC Emission Factors2,3 VOC Emissions for Pipeline Pump Station VOC Emissions for Pipeline Meter Station4 (kg/hr/source) (lb/hr/source) Daily (lb/day) Annual (tpy) Daily (lb/day) Annual (tpy) Valves 44 Light liquid 0.000043 0.0000948 0.100 0.0183 Pump seals 383 Light liquid 0.00054 0.00119 10.945 1.9974 Flanges 11 Light liquid 0.000008 0.0000176 0.005 0.0008 Other 5 Light liquid 0.00013 0.000287 0.034 0.0063 TOTAL: 11.08 2.02 0.059 0.011 1Equipment counts are based on the average number of valves, pump seals, flanges, and other equipment for the following Orion pipeline pump stations: Black River, Centerville, Chico, Clyde, Cresson, Grandview, Henrietta, Hueco, Kermit, Marlin, Maypearl, Midland, Waco, 2Source: Protocol for Equipment Leak Emission Estimates, U.S. EPA, EPA-453/R-95-017, November 1995, Table 2-3 3Emission factors are actually for total organic compounds, which inculde methane and ethane; therefore, these factors are conservative for representing VOC emissions 4Total annual VOC emissions per operating metering station based on total VOC emissions for Odessa meter station, as presented in Appendix 7I of original EA Notes: 1. Pumps will operate on electricity from the existing grid; therefore, no combustion-related emissions will be generated at the pump and meter stations. 2. Number of new pipeline pump stations for 'Connected Actions': Number of new pipeline meter stations for 'Connected Actions': 8 (DeLeon, Iatan, Black River, Wink, Odessa (2), and Midland-Oxy, and Cottonwood) 6 (Black River, Wink, Odessa, Crane, Midland-Oxy, and El Paso) (Connected Actions are those associated with the Orion pipeline expansion) 3. Number of new pipeline pump stations for Longhorn pipeline: 9 (Buckhorn, Industry, Warda, Bastrop, Eckert, James River, Cartman, Barnhart, and Texon) Number of new pipeline meter stations for Longhorn pipeline: 6 (Crane (outgoing), Texon, Barnhart, Bastrop, Warda, and Industry) <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 25 of 29 NACE Certification, shall be utilized to identify, mitigate, and monitor for inadequate cathodic protection and detrimental interference currents, prior to and during construction. Refer to Section 1.8, Foreign Crossings and Interference Currents below.” 11/30/03 1.6.5 Rick Wooldridge Michael Pearson Added entire section related to CIS 11/30/03 1.11.4 Rick Wooldridge Michael Pearson Deleted, “The external condition of the pipelines shall be reported on Form 02‐LEG‐1035 – Encroachment Agreement (Short Form), Form 02‐OPR‐1581 – Maintenance Report, or equivalent form.” 12/1/03 1.0 Rick Wooldridge Michael Pearson Added Index and renumbered 12/1/03 9.0 Rick Wooldridge Michael Pearson Added Definitions 12/1/03 8.0 Rick Wooldridge Michael Pearson Added References 12/1/03 8.2 Rick Wooldridge Michael Pearson Deleted, “DETERMINING CORROSIVE PROPERTIES OF CARGOES IN PETROLEUM PRODUCTS PIPELINES” 12/1/03 8.2 Rick Wooldridge Michael Pearson Deleted, “Refer to Copper Strip Corrosion by Liquefied Petroleum (LP) Gases.” 12/1/03 8.2 Rick Wooldridge Michael Pearson Deleted, “and Field Gas Analysis For CO2, H2S, O2 and Dew Point.” 12/1/03 8.2 Rick Wooldridge Michael Pearson Deleted, “NOTE: Corrosivity of liquid products (refined petroleum products and natural gas liquids) is rarely evaluated 12/1/03 8.2 Rick Wooldridge Michael Pearson Deleted, “Corrosive gas shall not be transported by pipeline, ……considered to be potentially corrosive.” 12/1/03 4.6 Rick Wooldridge Michael Pearson Rewrite to be consistent with External Examination 3/23/04 4.4.2 Rick Wooldridge Michael Pearson Added: Effectiveness of inhibitor will be based on the inhibitors success.. typically <1 MPY for refined products. 3/23/04 4.4.3 Rick Wooldridge Michael Pearson Added: Internal corrosion rates greater than >1 MPY on inhibited pipelines…..engineering judgment. 6/5/2004 3.1.1 Rick Wooldridge Michael Pearson Note: Atmospheric corrosion inspections on exposed pipelines may be conducted visually or through the use of an in-line inspection device capable of identifying and sizing corrosion. 11/5/2004 2.2.2, 2.6.3 Rick Wooldridge Michael Pearson Modified for clarification: Noted conditions that will cause compliance with 651 to not be observed may be but are not limited to tanks set on concrete, asphalt pads or where studies conducted in accordance with API 653 indicate that corrosion will not affect the safe operation of the tank. 11/30/2004 2.9.4.1 Rick Wooldridge Michael Pearson Replaced “shall” with “may” for 195 lines and added the 192 language. 1/3/05 3.3.1 Rick Wooldridge Michael Pearson Deleted: Operate Auto-Injection Pumps, Added: Internal Corrosion Remediation 1/3/05 3.4.4 Rick Wooldridge Michael Pearson Replaced reference to OJT with “Refer to Coupon Handling and ER Probes” for more information. 1/3/05 3.4.4 Rick Wooldridge Michael Pearson Reviewed the procedure for accuracy and effectiveness. 4/7/05 Overall Rick Wooldridge Michael Pearson Minor modification and editorials added to provide clarification…no process changes. 5/16/05 1.9.4.3 Rick Wooldridge Michael Pearson Added: “Note: For line sections integrity tested by hydrostatic test a risk evaluation will be conducted at each shorted casing and action taken to clear the short and/or mitigate the corrosion if deemed necessary.” 7/6/05 1.12 Rick Wooldridge Michael Pearson Added: Basic SCC awareness information is available to operation and maintenance employees in Stress <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 26 of 29 Corrosion Cracking Information. 7/6/05 1.12 Rick Wooldridge Michael Pearson Added: In the event that a pipeline system has experienced one or more confirmed incidents of SCC a systematic identification and examination of other potential locations of SCC will be conducted based upon the observations of conditions associated with the confirmed SCC incident. 7/6/05 1.12 Rick Wooldridge Michael Pearson Added: or any other locations identified for SCC investigation, 7/6/05 1.12 Rick Wooldridge Michael Pearson Added: Pipe cutouts sent to a metallurgical lab for analysis will be investigated for SCC. Results of this analysis will be provided in a comprehensive report provided to Asset Integrity. Added: SCC examinations will be performed by a NDE Technician trained in the detection of SCC on buried pipelines and will be documented in the Pipeline Maintenance Report. 7/6/05 1.12 Rick Wooldridge Michael Pearson Added: Annually, confirmed SCC occurrences will be reviewed to determine if changes to the SCC assessment criteria are necessary. 8/1/05 1.12 Rick Wooldridge Michael Pearson No confirmed SCC occurrences to review. 11/7/05 All Rick Wooldridge Michael Pearson Added LPP Mitigation and Shell CD requirements. 11/7/05 3.3.2 Rick Wooldridge Michael Pearson Added cleaning pig requirements. 12/14/05 3.5.2 Rick Wooldridge Michael Pearson Added “circumferentially and longitudinally” 1/4/06 1.13, 7.13 Rick Wooldridge Michael Pearson Added MIC related information to the program. 03/06/06 2.9.4.3 Rick Wooldridge Michael Pearson Deleted “clear the short and/or” mitigate the corrosion … 4/6/2006 3.2.1 Rick Wooldridge Michael Pearson Added: Refer to Coatings – Selection, Applications, and Maintenance for more information. 4/6/2006 2.13.1 Rick Wooldridge Michael Pearson Replaced “incidents” with “discoveries” and added “injurious”. 4/6/2006 4.4.1 Rick Wooldridge Michael Pearson Replaced “Internal Corrosion Remediation” with “Auto Injection Pumps”. 9/8/2006 8.0, 10.0 Rick Wooldridge Michael Pearson Section 8 ‐ Deficiencies in Corrosion Control was added and references to “as soon as practical” were removed from the document. Section 10 – Definitions was update to include “reasonable time”. 9/8/2006 ALL Rick Wooldridge Michael Pearson Reviewed entire document…minor editorial changes, no process changes. 10/26/2006 2.3.4.2, 2.3.6 Rick Wooldridge Michael Pearson Removed references to Net Protective current criteria 11/30/06 TOC Rick Wooldridge Michael Pearson Added 2.14 ‐ AC Corrosion 11/30/06 2.5.3 Rick Wooldridge Michael Pearson Changed “Section 1.8 to 2.8 “and added “2.14, Induced AC Corrosion” in the last sentence. 11/30/06 2.8.4 Rick Wooldridge Michael Pearson Added Section 2.8.4 “For interference currents related to AC.........” 11/30/06 2.14 Rick Wooldridge Michael Pearson Added new Section – “2.14 Induced AC Corrosion” and subsections 2.14.1, 2.14.2 and 2.14.3 11/30/06 9.1 Rick Wooldridge Michael Pearson Added link to “Testing for Induced AC and Remedial Measures in Related Policies/Procedures 11/30/06 10 Rick Wooldridge Michael Pearson Added the definition for Induced AC Corrosion to Section 10 – Definitions 11/30/06 Deleted 12/7/09 3.2.4 Rick Wooldridge Michael Pearson Added: Longhorn Specific: A suitable coating shall be applied to all aboveground facilities and soil‐to‐air interface areas to prevent corrosion damage. All areas with signs of coating degradation and/or corrosion shall be coated/recoated. Refer <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 27 of 29 to Coatings – Selection, Applications and Maintenance for more information. 4/25/07 2.1 David Stewart Michael Pearson Added 16 TAC 7.86(3) to regulation references. 4/25/07 2.1.6 David Stewart Michael Pearson Added “…using a coating deficiency (holiday) detector…” 4/25/07 2.1.9 David Stewart Michael Pearson Added new paragraph, “Joints, fittings, and tie‐ins shall be coated with material(s) compatible with the coating(s) on the pipe.” Old 2.1.9 reference to Coatings – Selection, Applications, and Maintenance becomes 2.1.10. 4/25/07 2.8 David Stewart Michael Pearson Added 16 TAC 7.86(5)(c) to regulation references. 4/25/07 2.8.4 David Stewart Michael Pearson Added new paragraph, “Texas Intrastate Pipeline specific: Whenever suspected areas of interference are identified, testing will be conducted within 6 months to determine the extent of interference, and appropriate action will be taken.” Old 2.8.4 reference to AC testing becomes 2.8.5. 1/1/08 4.2.2 David Stewart Rick Wooldridge Added natural gas 1/15/08 2.6.4.1 David Stewart Rick Wooldridge Added paragraph requiring adequate levels in AST’s when taking potential readings, as well as requirement to document the tank levels. 2/15/08 2.3.2 Rick Wooldridge Larry Davied Added: “Where injurious aerobic bacteria has been identified, or is suspected, a polarized potential of ‐.950 volts or more negative is required.” 2/20/08 All E7 Rick Wooldridge 2007 annual review 9/08/08 3.1.1 Rick Wooldridge Larry Davied Removed the note “or through the use of an in‐line inspection device capable of identifying and sizing corrosion…at the request of PHMSA 09/25/08 1.3 Rick Wooldridge Larry Davied Remove references to Shell’s Consent Decree 09/25/08 All E7 Rick Wooldridge 2008 annual review, no changes 11/06/08 4.3.2.3 Rick Wooldridge Larry Davied Pipelines transporting NH3 do not require routine pigging, but should be cleaning if excessive debris is identified and/or prior to In‐line inspection tool runs. 11/16/09 All E7 Rick Wooldridge 2009 annual review; Removed references to Longhorn 12/07/09 4.1.1 E7 Rick Wooldridge Removed…Pipeline cargoes shall be periodically evaluated for corrosivity. Added: The corrosive effects of pipeline cargoes (hazardous liquids or carbon dioxide) shall be investigated. 12/07/09 4.1.2 E7 Rick Wooldridge Added: Circumstance or condition [such as those listed below] that could cause, promote, or increase the likelihood of internal corrosion should be promptly reviewed and internal corrosion mitigation plans implemented as appropriate. 12/07/09 4.1.2.1 thru 4.1.2.11 E7 Rick Wooldridge Added: 4.1.2.1 Type of commodity, 4.1.2.2 Flow rate, 4.1.2.3 Velocity, 4.1.2.4 Operating Pressure, 4.1.2.5 Topography, 4.1.2.6 Amount of foreign material and/or contaminants present in the pipeline and/or commodity stream such as sand, silt, water, or other materials that could cause or promote internal corrosion, 4.1.2.7 Amount of sulfur, salts, acids, hydrogen sulfide, carbon dioxide or other corrosive material present and corrosive effect based upon partial pressures of material in the pipeline 4.1.2.8 Presence of microbes, 4.1.2.9 Temperature, 4.1.2.10 Pipe configuration, design, and material specifications, 4.1.2.11 Operating conditions, including but not limited to, steady <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 28 of 29 state conditions, slack line conditions, upset conditions in the pipeline system, and upset conditions in upstream facilities such as refineries or processing facilities 03/03/10 10 E7 Rick Wooldridge Deleted “Definitions” 03/03/10 8.1.3 Jimmy Puckett Rick Wooldridge Information added to provide a single specific location that addresses LMP requirements…cause analysis will be performed to identify contributing factors and root causes of anomalies/deficiencies identify by corrosion control surveys. 03/03/10 6.4 Jimmy Puckett Rick Wooldridge Information added to provide a single specific location that addresses LMP requirements…All pipe to soil survey, rectifier inspection, and foreign line crossing pipe to soil potential data will be recorded in the appropriate corrosion control database. All close interval pipe to soil potential data will be recorded in a hard copy report as well as the appropriate electronic format, atmospheric inspection data and exposes pipe visual inspection data will be documented on the appropriate forms and distributed appropriately, and will feed into and be processed in overall LPSIP by populating appropriate portions of the relative risk model. 3/25/10 6.3 DOT Rick Wooldridge Modified: Records shall be maintained of each root cause analysis...to read Records shall be maintained for each analysis including root cause analysis. 8/9/10 2.3.4 E7 – Ken Lybarger Rick Wooldridge Changed Supervisor of Asset Integrity to Supervisor of Corrosion Control 8/9/10 2.10.4 E7 – Ken Lybarger Rick Wooldridge Changed Supervisor of Asset Integrity to Supervisor of Pipeline Integrity to maintain consistency with pipeline welding procedures. 2010 annual review; 2.4.2 was simplified to say, “Cathodic protection level should be evaluated utilizing Cathodic 08/09/10 All E7 Rick Wooldridge Protection Criteria.”. This change was necessary to improve/clarify the process for IR drop consideration. Deleted: “4.2.1 Products entering the system shall be sampled in accordance with D 4057‐95 (2000) ‐ Standard Practice for Manual Sampling of Petroleum and Petroleum Products, D 5842‐95 (2000) ‐Standard Practice for Sampling and Handling of Fuels for Volatility Measurement, and D 4177‐95 (2000) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products”. This change removes unnecessary and likely incomplete information. 10/10/11 4.3.2.3 Rick Wooldridge Doug Chabino 2011 Annual Review; Added: The frequency for routine cleaning operations of mainline crude piping should be 26 times per year, approximately every two weeks. Frequencies of cleaning pig runs may be adjusted as necessary based upon product upsets and the analysis of results of previous cleaning pig runs. 12/31/11 All 2012 Annual Review complete 2/16/12 4.3.2.3 Rick Wooldridge Doug Chabino Added clarification to facility piping 5/15/12 2.9.4.4 Rick Wooldridge Doug Chabino Added section to require testing for electrolytic shorted casings 5/15/12 2.9.4 Rick Wooldridge Doug Chabino Removed references to 192 (Gas) assets 5/15/12 4.3.2.6 Rick Wooldridge Doug Chabino Added: Where excessive debris and paraffin buildup is thought to exist, specialty pigs such as pin‐wheel, Pit Boss™, <<>> Magellan Midstream Partners, L.P. CORROSION CONTROL PROGRAM 7.04–ADM–001 Asset Integrity 02/19/12 Revision: 11 Page 29 of 29 scraper/plow blade attachments, and magnetic cleaning pigs shall be utilized as necessary based upon sound engineering judgment. 5/15/12 4.3.3.1 Rick Wooldridge Doug Chabino Added: For refined product systems a hydrocarbon soluble, water dispersible corrosion inhibitor shall be utilized (Smart Chemical SCSF260 or equivalent). For crude pipeline systems, a highly water dispersible/soluble blend of corrosion inhibitors shall be utilized (Smart Chemical SCCI865 or equivalent). 5/15/12 4.4.5 Rick Wooldridge Doug Chabino Added: and <3 MPY for crude. 5/15/12 4.4.8 Rick Wooldridge Doug Chabino Added: (Reference API RP‐45, NACE TM0194, NACE RP0192, and ASTM D2327 for more information) and For crude pipeline systems, water sample traps will be mounted on the bottom of the pipe to facilitate the collection and analysis of free water. These locations will be inspected for water monthly and if a sufficient amount of water is present (typically >1 pint) this water shall be analyzed for bacteria, pH, iron, manganese, chlorides, and inhibitor residual. Bacteria counts in excess of 10‐100 colonies/ml., pH readings outside a range of 4‐8, inhibitor residual less than ~10ppm, or an increase in iron, manganese, or chlorides could indicate an increase threat to internal corrosion. Water and debris brought into receiving traps during pigging operations will be tested to determine its potential to cause internal corrosion if determined to be necessary after consultation with the Corrosion Specialist. 5/15/2012 4.4.9 Rick Wooldridge Doug Chabino Added: Crude assets covered by the Mitigation Plan: Coupon/water sample collection points will be located in facilities at origination points, along the pipeline system, and end points. Locations chosen for initial sampling points include Ft. McKavett, Cedar Valley, Satsuma, and East Houston. Additional coupon/water sample collection points may be installed as determined necessary through hazard analysis. 5/15/2012 4.4.2, 4.4.8 Rick Wooldridge Doug Chabino Added references to Standard documents 5/15/2012 2.14 Rick Wooldridge Doug Chabino Recording voltmeters should be considered in areas where high voltage transmission lines parallel the pipeline over long distances. <<>> Magellan Midstream Partners, L.P. ATMOSPHERIC CORROSION INSPECTIONS 7.04–ADM–002 Asset Integrity 01/01/11 Revision: 4 Page 1 of 5 1.0 PURPOSE 1.1 The purpose of this procedure is to establish a standardized method for monitoring, inspecting, and reporting atmospheric corrosion conditions on aboveground facilities. 2.0 PROCEDURE 2.1 Identifying Areas For Inspection 2.1.1 Identify all above grade and above water line structures/facilities or parts of structures/facilities as subject for atmospheric corrosion inspection. 2.1.2 Select an appropriate number of representative locations in each facility to adequately evaluate the facility for atmospheric corrosion. Particular attention should be given to pipe and soil to air interface areas, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water. 2.1.3 Maintain a listing of all subject areas, including GPS coordinates, and updated as needed in the Cathodic Protection Data Manager. 2.1.4 Some structures/facilities with corresponding inspection requirements are: 2.1.4.1 Pump/Compressor stations, measuring and regulating stations, storage vessels and tankage, and miscellaneous facilities (building, structure, piping and equipment): 2.1.4.1.1 Pipe ground transition/interface areas 2.1.4.1.2 Pipe above grade coatings 2.1.4.1.3 Pipe condition at building wall entry/exit 2.1.4.1.4 Structure and equipment coating condition 2.1.4.2 Underground pipe or related facilities exposed to the atmosphere due to intentional or unintentional reasons (i.e., erosion, subsidence, etc.) 2.1.4.3.1 Pipe ground level transition and above ground coating conditions 2.1.4.3 Pipe spans (supported and unsupported) 2.1.4.3.1 Pipe ground level transition and above ground coating conditions 2.1.4.4 2.1.4.3.2 Pipe support and traffic guard coating conditions Suspension bridges (piping and structure): 2.1.4.4.1 Physical condition of structural steel towers, assemblies, clamps, pipe hanger system, bolts, cables, cable hardware, cable anchorages, and concrete foundations 2.1.4.4.2 Pipe ground level transition and above ground coating conditions 2.1.4.5 Pipeline valves, expansion loops, and associated piping: 2.1.4.5.1 Pipe ground level transition coating condition <<>> Magellan Midstream Partners, L.P. ATMOSPHERIC CORROSION INSPECTIONS 7.04–ADM–002 Asset Integrity 01/01/11 Revision: 4 Page 2 of 5 2.2 2.3 2.1.4.5.2 Pipe above grade coating condition 2.1.4.5.3 Structure (pipe supports) coating condition Preparing the surface for inspection and or remedial action 2.2.1 The surface to be inspected shall be visible and sufficiently clean, based on the judgment of the inspector, to allow for an accurate assessment of corrosion. 2.2.2 Valves and/or other equipment located inside valve cans should be inspected from the surface if possible. If entry into the valve can is required, the procedures for Confined Space entry shall be followed. 2.2.3 Surface rust and/or oxidation may be removed using a hand or power wire brush and water or abrasive blasting. Files, hammers, or any other equipment that may damage the pipe should not be used. 2.2.4 If pipe or pipe support movement is required: 2.2.4.1 Contact the Risk Engineer to determine the maximum movement allowable for the specific pipe and/or support. 2.2.4.2 Install a temporary support or lift the pipe using pipe protective devices such as pipe saddles or hoist with proper rigging techniques if applicable. 2.2.4.3 2.2.4.4 2.2.4.5 2.2.4.6 2.2.4.7 2.2.4.8 Remove the existing pipe support, if necessary. Perform the visual inspection as indicated in 2.4 below. Replace the pipe support, if necessary. Lower the pipe or raise the support to the desired position. Remove the temporary pipe support, if applicable. Adjust the support height to ensure a level pipe or as directed by the Risk Engineer. Performing visual inspection of surfaces 2.3.1 Visually inspect all surfaces and assign a visual “corrosion” condition code on the Atmospheric Corrosion Inspection data gathering form, in the data logger, or in the Cathodic Protection Data Manager in accordance with SPCC-VIS 2; Standard Method for Evaluating Degree of Rusting on Painted Steel Surfaces, General Rusting Standard. NOTE: Given the similarity between the General Rusting and Spot Rusting SPCC-VIS 2 Standards, the General Rusting Standard (1-G...9-G) is to be used for all assets. NOTE: If pitting corrosion, corrosion is in excesses of 12.5% of the pipewall or any dents, gouges, or SCC is observed, contact an Asset Integrity Supervisor, Risk Engineer, or Pipeline Integrity Engineer/Coordinator immediately. 2.3.2 For Rust Ratings of 2-G or less, utilize the comment section on the Atmospheric Corrosion Inspection data gathering form, in the data logger, or in the Cathodic Protection Data Manager to quantify and describe the structure <<>> Magellan Midstream Partners, L.P. ATMOSPHERIC CORROSION INSPECTIONS 7.04–ADM–002 Asset Integrity 01/01/11 Revision: 4 Page 3 of 5 2.3.3 and/or coating damage. Transfer of hardcopy data to the CPDM System should take place as soon as practical following the inspection. Visually inspect the soil-to-air interface area and classify the “interface coating” as Adequate or Inadequate on the Atmospheric Corrosion Inspection data gathering form, in the data logger, or in the Cathodic Protection Data Manager. Transfer of hardcopy data to the CPDM System should take place as soon as practical following the inspection. NOTE: The interface coating is adequate if it adequately prevents corrosion at the site where the pipeline first comes in contact with the soil. 2.3.4 2.4 Remedial actions 2.4.1 2.5 Documentation 2.5.1 2.5.2 Replicate the Cathodic Protection Data Management System. Areas of atmospheric concern requiring inspection and/or remedial action will be addressed in accordance with the External Corrosion Control Program and Atmospheric Corrosion Workflows. Areas of exposed pipe identified through routine corrosion work, aerial patrol, Depth-of-Cover survey, etc. shall be entered into the Cathodic Protection Data Management System to ensure follow-up inspection. Documentation of atmospheric corrosion inspection data is handled in the Cathodic Protection Data Management System. End of Procedure <<>> Magellan Midstream Partners, L.P. ATMOSPHERIC CORROSION INSPECTIONS 7.04–ADM–002 Asset Integrity 01/01/11 Revision: 4 Page 4 of 5 System Integrity Plan Change Log Date CHANGE LOCATION Changed By Approved By Brief Description of Change 10/03/02 2.2.1 Rick Wooldridge Michael Pearson Revised note before 2.2.2 to point to correct procedure. 5/13/03 2.1.1 Rick Wooldridge Michael Pearson Added NOTE: Select an appropriate number……………… 5/13/03 2.3.2 Rick Wooldridge Michael Pearson Delete reference to the Manager of Equipment Technology 5/13/03 2.4.2 Rick Wooldridge Michael Pearson Delete entire section as it relates to the Manager of Equipment Technology 5/13/03 2.2.4 Rick Wooldridge Michael Pearson Added 2.2.4 Update the Cathodic Protection Data Management System (BASS) 10/29/03 1.0, 2.1.1 Rick Wooldridge Michael Pearson Deleted “and offshore” and “Note” 10/29/03 2.2 Rick Wooldridge Michael Pearson 2.2. was completely rewritten to utilize SPCC-VIS 2 guidelines and processes. 10/29/03 2.3.1 Rick Wooldridge Michael Pearson Replaced “The Supervisor of Pipeline Integrity….” “with Areas of atmospheric concern requiring inspection …..”. 10/29/03 2.0 Rick Wooldridge Michael Pearson Added “Note: performing an atmospheric corrosion inspection is a covered task and should only be performed by those qualified in accordance with the operator qualification ruling”. 10/29/03 4.0 Rick Wooldridge Michael Pearson Deleted “Platform” and “Splash Zone” 08/11/04 2.2 Rick Wooldridge Michael Pearson Added Section 2.2 – “Preparing the surface for inspection and or remedial action” and its subsections. 08/11/04 2.2, 2.5 Rick Wooldridge Michael Pearson Added provisions for how to use In-Line Inspection data to conduct atmospheric corrosion inspections 8/11/04 ALL Rick Wooldridge Michael Pearson Reviewed procedure for accuracy and effectiveness. 1/1/06 All E7 Michael Pearson Reviewed, no changes 5/12/06 2.3.2 Rick Wooldridge Michael Pearson Added: Valves and/or other equipment located inside valve cans should be inspected from the surface if possible. If entry into the valve can is required, the procedures for Confined Space entry shall be ollowed. 01/01/08 All E7 Larry Davied 2007 review, no changes 09/08/08 2.2, 2.5 Rick Wooldridge Larry Davied Removed references to using ILI data to perform atmospheric inspections 09/08/08 2.2, 2.5 Rick Wooldridge Larry Davied Added: Particular attention should be given to pipe and soil to air interface areas, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water. 11/19/08 ALL E7 Rick Wooldridge 2008 review, no changes <<>> Magellan Midstream Partners, L.P. ATMOSPHERIC CORROSION INSPECTIONS 7.04–ADM–002 Asset Integrity 01/01/11 Revision: 4 Page 5 of 5 Date CHANGE LOCATION Changed By Approved By Brief Description of Change 11/17/09 ALL E7 Rick 2009 review, minor clean-up changes Wooldridge 08/10/10 ALL E7 Rick Wooldridge 2010 review; Deleted all references to BASS 12/31/11 ALL 2012 Annual Review complete – no changes <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 1 of 9 The purpose of this procedure is to establish standardized cathodic protection (CP) criteria to be used to confirm adequate external corrosion control for Company facilities. 1.0 PURPOSE 1.1 2.0 PROCEDURE 2.1 2.2 2.3 Identifying CP Criteria to be Used 2.1.1 Selecting which CP criteria to use 2.1.1.1 Use the –0.850 volts Pipe-to-Soil (P/S) potential criteria as the primary criteria for all facilities. 2.1.1.2 Use the 100 millivolt shift criteria whenever the –0.850 volts P/S criteria cannot be achieved or as directed by the Manager of Asset Integrity. 2.1.1.3 The criteria employed must be specified in the Cathodic Protection Data Manager for the facility, segment, or individual test point. Using the –0.850 Volts P/S Criteria 2.1.2 2.1.3 2.1.4 2.1.5 Take P/S potentials per procedure Measuring a Pipe-to-Soil Potential. P/S reading must be at least –0.850 volts, with reference to a saturated copper-copper sulfate reference half-cell, while the protective current is applied. Voltage (IR) drops shall be considered per section 2.5 below. Whenever –0.850 volts P/S is not achieved, the 100 millivolt shift criteria should be applied, unless corrective actions are planned to remediate the low potential. 100 Millivolts Voltage Shift (Polarization Formation) Criteria 2.3.1 2.3.2 To use the 100 millivolt shift criteria as established by the polarization formation method, follow the procedure described below. For Existing Pipelines Or Facilities 2.3.2.1 Turn off and/or disconnect all known sources of CP influence. 2.3.2.2 Allow sufficient time for the piping or facility to depolarize. 2.3.2.3 Conduct a complete P/S survey (near native state survey). 2.3.2.4 Near native state survey, results may not be totally native state due to unknown galvanic anodes or foreign impressed and stray current influences. If other CP influences are located, these should be shut down and a new survey performed in the areas of influence. 2.3.3 Apply CP to the Pipeline or Facility 2.3.3.1 Turn on and/or reconnect all known sources of CP influence. 2.3.3.2 Allow sufficient time for the structure to polarize or re-polarize for existing structures. 2.3.4 Conduct an Interrupted P/S Survey Of The Pipeline Or Facility 2.3.4.1 Install and place in operation interrupter equipment in all influential CP current sources affecting the pipeline or facility being tested. 2.3.4.2 Synchronize all interrupters. <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 2 of 9 2.3.5 2.3.6 2.3.7 2.3.4.3 Use at least an 80% duty cycle (“On” cycle set to 8 seconds and “Off” cycle set to 2 seconds). Keep the “Off” cycle as short as possible to prevent polarization decay but long enough to read after any spike (“Instant Off”) as shown in Figure 1 “Polarization Formation”. 2.3.4.4 After starting the interruption of all current sources, read the “On” potential during the “On” cycle and take the “Off” potential reading instantly after any spike. Conduct a complete P/S survey, recording both the “Instant Off” and the “On” potential readings. Calculate for the 100 millivolt shift. 2.3.6.1 Subtract the Native State or Near Native State potential from the “Instant Off” potential for each location. To meet the 100 millivolt shift criteria, the results must be greater than 100 millivolt. 2.4 2.3.8 Establish Individual Test Point “ON” criteria based on the 100 millivolt test. 2.3.8.1 When 100 millivolt or more shift occurs, the “On” potential reading is established as the P/S criteria, with CP on, for a particular test point. 2.3.8.2 As long as there are no significant changes in the environment, structure, coating, CP systems, etc., this established “On” criteria can be used for satisfying the 100 millivolt criteria through the monitoring of the “On” potentials. 100 Millivolts Voltage Shift (Polarization Decay) Criteria 2.4.1 To use the 100 millivolt shift criteria as established by the polarization decay method 2.4.1.1 Install and place in operation interrupter equipment in all influential CP current sources effecting the pipeline or facility being tested. 2.4.1.2 Synchronize all interrupters 2.4.1.3 Use at least an 80% duty cycle (“On” cycle set to 8 seconds and “Off” cycle set to 2 seconds). The “Off” cycle should be kept as short as possible to prevent <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 3 of 9 2.5 2.4.2 2.4.3 2.4.4 2.4.5 2.4.6 polarization decay, but long enough to read after any spike (“Instant Off”) as shown in Figure 2. 2.4.1.4 Conduct a complete P/S survey, recording both the “Instant Off” and the “On” potential readings. Mark each spot of electrode placement. Calculate Targeted Near Native State P/S Potentials as Follows: 2.4.2.1 Subtract 100millivolt from the “Instant Off” potential reading for each test point. This is the targeted near native state P/S potential. Test For Polarization Decay To Targeted Near Native State P/S Potentials As Follows: 2.4.3.1 Turn off and/or disconnect all known sources of CP influence. 2.4.3.2 Conduct a complete P/S survey, recording “Off” potential readings. 2.4.3.3 Observe and record polarization decay potentials. When polarization decay potentials reach targeted near native state P/S potentials, stop decay test to retain as much polarization as possible 2.4.3.4 Targeted near native state potentials may not be totally native state due to unknown galvanic anodes or foreign impressed and stray current influences and a small amount of remaining polarization. 2.4.3.5 Turn on or reconnect all known sources of CP influence as soon as possible to reestablish polarization. Establish Individual Test Point “On” criteria based on the 100 millivolt shift, polarization decay test. When 100 millivolt or more shift occurs, the “On” potential reading is established as the P/S criteria, with CP on, for that test point. As long as there are no significant changes in the environment, structure, coating, CP systems, etc., these established “On” criteria can be used for satisfying the 100 millivolt criteria through the monitoring of the “On” potentials. Methods for IR Drop Consideration 2.5.1 In accordance with Ohm’s Law of E (volts) = I (current) x R (resistance), any time current flows through a resistance, a voltage drop is produced. For cathodic protection purposes, the current flow in the soil (electrolyte) is the I and the soil resistance is R and the resulting voltage drop is E in volts. Therefore, if the amount of current or the resistance is very low, the resulting voltage or IR drop would also be low or considered negligible. The voltage drop, commonly called the IR Drop, needs to be considered when taking pipe-to- soil measurements. See figure below for a depiction of the IR Drop location in P/S measurements below. <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 4 of 9 High Resistance Voltmeter See Section 2.5.3 2.5.2 Various IR Drop correction techniques can be utilized to consider the IR Drop factor in P/S measurements. These include but not limited to the following: Which Method(s) For Considering Voltage Drop (IR) In P/S Measurements Method Process Comments Is affected by proximity to the current sorce Integrity testing procedures should incorporate historical corrosion rates and growth calculations Requires knowledge of various operating factors and historical information Integrity testing procedures should incorporate historical corrosion rates and growth calculations May be affected by the proximity to current sorce Integrity testing procedures should incorporate historical corrosion rates and growth calculations Historical Operating Information See Section 2.5.4 Reference Cell Placement See Section 2.5.5 Calculation See Section 2.5.6 Time consuming and requires various calculations Integrity testing procedures should incorporate historical corrosion rates and growth calculations Current Interruption See Section 2.5.7 For proper use, requires synchronized interruption of all current sources Integrity testing procedures should incorporate historical corrosion rates and growth calculations Buried Coupons See Section 2.5.8 Requires installation of special test stations containing coupons Integrity testing procedures should incorporate historical corrosion rates and growth calculations <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 5 of 9 2.5.3 High Resistance Voltmeter Method 2.5.3.1 This method considers IR drop by minimizing current flow through the measurement circuit, thus decreasing voltage drops associated with the mechanical and electrolytic components of the circuit. 2.5.3.2 A high resistance voltmeter (>50,000 ohm) is necessary to reduce the voltage drop in the external circuit. 2.5.4 Historical Operating Information Method 2.5.4.1 This method utilizes recent and historical operating information to determine if the cathodic protection system is properly protecting the structure at existing voltage levels. 2.5.4.2 The lack of corrosion related leaks or repairs in conjunction with consistent cathodic protection levels and coating condition indicates the adequacy of cathodic protection. 2.5.5 Reference Cell Placement Method 2.5.5.1 Since the amount or quantity of the IR drop is directly proportional to the distance between the reference cell and the structure to be measured, the simplest method for considering IR drop is to minimize this distance. 2.5.5.2 To minimize IR drop at test stations: 2.5.5.2.1 The reference cell should be placed over the centerline of the structure to be tested. 2.5.5.2.2 Permanent reference cells can be placed in close proximity to the buried structure. 2.5.5.2.3 If a quantitative voltage drop reading is required for the location, then a surface reading can be obtained with a portable reference cell and then by subtracting the reference cell reading, the voltage drop is obtained. Surface Reading – Reference cell reading = IR or voltage drop <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 6 of 9 2.5.5.2.4 The pipeline can be probed and a small diameter/long cylinder reference cell inserted into the hole where the probing occurred. This cell is then placed very close to the pipe’s surface without contacting the pipe. 2.5.5.2.5 A plastic or non-conductive tube can be installed directly over the pipeline. The tube should be within one or two inches of the structure, but not contacting the coating. The tube can be filled with soil or left open and the reference cell lowered into the tube for voltage measurements. 2.5.5.3 To minimize IR drop when taking P/S measurements where the structure has been excavated, the reference cell should be placed in close proximity to the structure. 2.5.5.4 To minimize IR drop when taking P/S measurements on structures that extend above grade, the reference cell should be placed in close proximity to the structure. <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 7 of 9 2.5.6 Calculation Method 2.5.6.1 This method utilizes an extrapolation calculation for considering the IR drop as further noted below and in Figures 2 and 3 below. 2.5.6.1.1 When potential measurements are taken in close proximity to another structure, this method will not be valid. 2.5.6.2 Obtain a P/S measurement directly over the structure or pipeline. 2.5.6.3 Move the reference cell six feet perpendicular away from the first reading and obtain a second pipe-to-soil reading, called the offset potential. 2.5.6.4 Obtain the centerline depth of the structure. 2.5.6.5 Calculate the true or IR free potential using the following formula: TR = D – A[(E – D)/C] TR = True reading in millivolts <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 8 of 9 2.5.7 Using Current Interruption 2.5.7.1 This method utilizes current interruption to obtain what is commonly called an “Instant Off” potential. The basis for this method is that the IR or voltage drop disappears when the current is turned off according to Ohms law of E = I x R. However, care must be exercised when using this option as polarization may be lost when the interrupters are installed or during the interruption cycle. Therefore, an 80% duty cycle (8 seconds On and 2 seconds Off) is suggested. 2.5.7.2 For proper consideration of IR drop in this method, all current sources must be interrupted. Foreign current sources must also be interrupted, shut off or not in operation at the time of consideration. 2.5.7.3 To consider IR drop in this manner, the following steps should be followed: 2.5.7.3.1 2.5.7.3.2 2.5.7.3.3 2.5.7.3.4 2.5.7.4 Soil Coupons 2.5.7.4.1 2.5.7.4.2 2.5.7.4.3 2.5.7.4.4 Synchronize all interrupters to be utilized for this type of survey or consideration method. Install the interrupters on all known current sources to include bonds and foreign and Company cathodic protection facilities. Record the “On” and “Instant Off” potentials for the structure being tested. Remove all interrupters and return all facilities to normal operation. To decrease or eliminate possible errors associated with “current interruption” coupons can be installed next to the pipeline simulating a coating defect (holiday). The coupon should be installed in similar backfill as the structure to be monitored and installed in accordance with the manufacture’s recommendation. The “Off” reading is obtained by measuring the potential of the coupon while removing it from the cathodic protection circuit. Polarization decay and Native potential readings can be obtained while the coupon is disconnected from the cathodic protection system. <<>> Magellan Midstream Partners, L.P. CATHODIC PROTECTION CRITERIA 7.04–ADM–006 Asset Integrity 01/01/12 Revision: 2 Page 9 of 9 System Integrity Plan Change Log Date Change Location Chan ged By Approv ed By Brief Description of Change 12/1/03 Change Log Rick Wooldridge Michael Pearson Added “Changed By” 12/1/03 Document Rick Wooldridge Michael Pearson Replaced Williams with Company 12/1/03 2.3 Rick Wooldridge Michael Pearson Deleted, “For newly constructed pipelines or facilities, the Corrosion Technician shall conduct a complete P/S survey before application of CP. Mark each spot of electrode placement 1/1/06 All E7 Michael Pearson 2005 annual review complete – no changes 10/26/06 2.1.1.3, 2.5, 4.7 Rick Wooldridge Michael Pearson Removed references to net protective current 01/01/08 All E7 Rick Wooldridge 2007 annual review complete – no changes 1/1/09 All E7 Rick Wooldridge 2008 annual review complete – no changes 11/17/09 All E7 Rick Wooldridge 2009 annual review complete – minor clean-up changes 8/3/10 All E7 Rick Wooldridge 2010 annual review – This procedure was rewritten to further clarify Magellan’s process for IR Drop consideration [including the incorporation of historical corrosion rates and growth calculations]. 1/17/11 Various Larry Davied Rick Wooldridge 2011 annual review, Minor revisions 12/31/11 All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. TESTING FOR INTERFERENCE CURRENTS AND REMEDIAL MEASURES 7.04–ADM–015 Asset Integrity 01/01/11 Revision: 3 Page 1 of 9 PURPOSE 1.1 The purpose of this procedure is to establish a standardized method for identifying, testing for and mitigating the harmful effects of interference currents. 2.0 PROCEDURE 2.1 2.1.1 Determining the Need for Interference Current Testing. 2.1.2 2.1.3 Determine the need for interference current testing based on the potential effects on facilities from foreign DC currents. Primary sources of potential interference are: 2.1.1.1 Static DC current: other (foreign) Cathodic Protection (CP) systems (foreign usually refers to other companies, but can refer to other systems operated by the same company, i.e., foreign refers to any system not part of the system being reviewed/surveyed/examined/tested, etc.) 2.1.1.2 Dynamic DC currents: direct current (DC) operated traction systems, such as DC railroads, subways, tramways, and mining equipment/carts 2.1.1.3 Stray currents: either static or dynamic, from an unknown source 2.1.1.4 Other sources may include welding operations, railroad signal batteries, HVDC transmission systems and related ground electrodes, chlorine and aluminum plants which utilize high DC currents, telluric forces, battery chargers, etc. Cathodic protection tests that may indicate potential interference include the following: 2.1.2.1 Low Pipe‐to‐Soil (P/S) potential area tests 2.1.2.2 Hot spot or cell‐to‐cell surveys 2.1.2.3 Line current surveys Determine the need for interference current testing based on the potential effects of Company CP systems on foreign facilities. Some reasons for testing are: 2.1.3.1 Request from foreign company 2.1.3.2 Installation of new CP system 2.1.3.3 Significant increase in output of an existing CP system 2.1.3.4 Installation of a new foreign pipeline or facility 2.1.3.5 Installation of a new pipeline or facility 2.1.3.6 Drastic unexplained change in P/S or current readings on CP surveys 2.1.3.7 Installation of new HVDC or HVAC power transmission systems 2.1.3.8 Any other significant change in the environment that might affect CP current flow/direction/consumption <<>> Magellan Midstream Partners, L.P. TESTING FOR INTERFERENCE CURRENTS AND REMEDIAL MEASURES 7.04–ADM–015 Asset Integrity 01/01/11 Revision: 3 Page 2 of 9 2.1.3.9 2.1.4 Potential contributors to the possibility for having interference current may include: 2.1.3.9.1 Poor to no coating 2.1.3.9.2 High rectifier circuit resistance Likely areas where interference may be suspect are 2.1.4.1 Pipelines or facilities within the ground bed gradient of a foreign CP system 2.1.4.2 Pipelines or facilities located between a foreign CP system and its corresponding facility 2.1.4.3 Paralleling or crossing foreign pipelines 2.1.4.4 Buried isolation locations 2.1.4.5 Metallic structures that will provide a low total resistance path for the DC current in question to complete its electrical circuit 2.2 Testing for and Determining the Effects of Interference Current NOTE: Whenever possible, all interference testing should be a cooperative endeavor and performed mutually. Any testing conducted on or from foreign facilities/systems should be done with the permission and/or jointly with the foreign companies. NOTE: When possible, coordinate interference testing with local Corrosion Control Coordinating Committees 2.2.1 2.2.2 Identify all possible foreign static and dynamic DC current sources. (For the purpose of this procedure, foreign refers to all systems not part of the facility being tested.) Interrupt each foreign static DC current source and, whenever possible, each dynamic DC current source while conducting a P/S survey (spot or CIS) over the effected area (area in question or suspect of interference current discharge). Reference Measuring a Pipe‐to‐Soil Potential. 1.1.1 NOTE: Use an 80% duty cycle (8 seconds “On” and 2 seconds “Off”) in the interruption of current sources when checking for interference. The Supervisor of Corrosion Control may approve other duty cycles. 2.2.3 Analyze the P/S readings from step 2.2.2 of this procedure to determine if: 2.2.3.1 2.2.3.2 2.2.3.3 Interrupted current caused a change in the P/S readings from the Off to On Interrupted current caused a more negative P/S reading from the Off to On Interrupted current caused a more positive P/S reading from the Off to On <<>> Magellan Midstream Partners, L.P. TESTING FOR INTERFERENCE CURRENTS AND REMEDIAL MEASURES 7.04–ADM–015 Asset Integrity 01/01/11 Revision: 3 Page 3 of 9 2.2.4 2.2.3.4 For each test point, add the P/S potential change (net effect) resulting from all foreign DC current sources to get the magnitude of the interference for that point or location: 2.2.3.4.1 If the total effect is Zero, there is no interference 2.2.3.4.2 If the total effect is a negative (‐) figure, the point is a current pick‐up area 2.2.3.4.3 If the total effect is a positive (+) figure, the point is a current discharge area 2.2.3.4.4 The magnitude of the total effect will determine whether the interference must be mitigated or whether it is inconsequential To test for foreign dynamic DC currents that can not be interrupted (mostly DC traction systems), conduct a continuous P/S test at each test point in question per the following steps. 2.2.4.1 Install a data logger or similar equipment at each location capable of continuously recording P/S readings for a predetermined time span. Reference Measuring a Pipe‐to‐Soil Potential. 2.2.4.2 Analyze recorded P/S data that was recorded from step 2.2.4.1 of this procedure. 2.2.4.2.1 Fluctuating P/S readings with no apparent reason indicates possible interference. Further review of the recorded data should be conducted to determine if the fluctuating pattern can be correlated to local DC operating systems 2.2.4.2.2 Comparing P/S readings from each point taken at the same time may help to indicate which point is a current pick‐up or discharge point 2.2.4.2.3 At test points exhibiting fluctuating P/S readings higher than baseline values may indicate that the point is a current pick‐ up area 2.2.4.2.4 At test points exhibiting fluctuating P/S readings lower than baseline values may indicate that the point is a current discharge area 2.2.4.2.5 If the baseline P/S is unknown, it may be determined from the logged readings taken during the continuous testing 2.2.4.2.6 The magnitude of the difference in the lowest or highest P/S reading and the baseline P/S reading will determine whether <<>> Magellan Midstream Partners, L.P. TESTING FOR INTERFERENCE CURRENTS AND REMEDIAL MEASURES 7.04–ADM–015 Asset Integrity 01/01/11 Revision: 3 Page 4 of 9 2.3 2.4 the interference must be mitigated or whether it is inconsequential 2.2.5 Locate the unknown interfering DC current source. 2.2.5.1 In order to locate potential areas of interference, one or more of the following surveys should be conducted: 2.2.5.1.1 Hot spot or cell to cell survey 2.2.5.1.2 Close interval survey 2.2.5.1.3 DCVG survey 2.2.5.1.4 By conducting one of more of the above noted surveys, it may be possible to locate the point(s) of current discharge/pickup and/or to track the current to or from its source 2.2.6 If the attempts to locate or identify the interference source are successful, perform either step 2.2.2 or step 2.2.4 of this procedure to evaluate the effects of the interference source. Determining the Need for Interference Current Mitigation: 2.3.3 Review the data from section 2.2 of this procedure. The magnitude of the interference will determine whether the interference current must be mitigated or if it will be considered inconsequential. 2.3.3.1 A shift in the P/S potential reading that results in a potential of ‐1.000 Volt or more negative, (IR drop free) shall be considered inconsequential, unless field testing dictates otherwise. 2.3.3.2 A shift in the P/S potential reading that results in a potential between ‐ 0.850 volts to –1.000 volts (IR drop free) may require mitigation, depending upon field testing and site conditions. 2.3.3.3 A shift in the P/S potential reading that results in a potential less than ‐ 0.850 volts will require mitigation. Selecting the Type of Mitigation 2.4.1 Eliminate or reduce the potential for current exchange by physically changing the environment or facility. Suggested mitigating actions to reduce current exchange include: 2.4.1.1 Recoat the current discharge areas or current pick‐up areas on the pipeline/facility in question. Reference Coatings – Selection, Application, and Maintenance. 2.4.1.2 Install a highly resistive material between the pipeline/facility in question and the foreign pipeline/facility. <<>> Magellan Midstream Partners, L.P. TESTING FOR INTERFERENCE CURRENTS AND REMEDIAL MEASURES 7.04–ADM–015 Asset Integrity 01/01/11 Revision: 3 Page 5 of 9 2.4.1.3 Reduce high rectifier circuit resistance by installing a new groundbed. Reference Design and Installation of an Impressed Current Deep Groundbed or Design and Installation of an Impressed Current Surface Groundbed. 2.4.1.4 Relocate foreign CP groundbed or entire CP system 2.4.1.5 Move electrical isolation devices from below ground to above ground 2.4.1.1 If practical, increase the distance between foreign and Company facilities 2.4.1.2 Improve/repair DC traction systems isolation between rails and the earth (ballast, ties, padding) 2.4.1.3 Improve/repair DC traction systems electrical connection across rail ends/joints 2.4.2 Design considerations for mitigating potential interference effects include the following: 2.4.2.1 Design of a CP system with groundbed gradient located outside of any existing pipeline/facility 2.4.2.2 Design of a groundbed to reduce interference potential. Deep groundbeds have less potential to cause interference than a conventional/surface groundbed 2.4.2.3 Route new pipelines/facilities outside any potential interference current pick‐up area or groundbed gradient. If at all possible, avoid placing a new pipeline between a foreign groundbed and the structure being protected 2.4.3 Mitigation by electrical bonding 2.4.3.1 Select the appropriate bond type. Some types of bonds are: 2.4.3.1.1 Solid bonds (no control on amount of current or direction of current) 2.4.3.1.2 Resistance bonds (control on amount of current) 2.4.3.1.3 Diode bonds (control on direction of current) 2.4.3.1.4 Resistance diode bonds (control on both direction and amount of current) 2.4.3.2 Select a bonding location as close as practical to the current discharge point or current source. 2.4.3.3 Install cathodic protection cables. Reference Attaching Cathodic Protection Cables. 2.4.3.4 Install a shunt where practical to provide a means for measuring bond current direction and magnitude. <<>> Magellan Midstream Partners, L.P. TESTING FOR INTERFERENCE CURRENTS AND REMEDIAL MEASURES 7.04–ADM–015 Asset Integrity 01/01/11 Revision: 3 Page 6 of 9 2.4.4 2.4.3.5 Classify the bond as “critical to Magellan, critical to Foreign, or Courtesy (see definitions) Mitigation by installing a galvanic anode to serve as a sacrificial discharge or drain point: 2.4.4.1 Locate point of current discharge. 2.4.4.2 Install the galvanic anode(s). Reference Attaching Cathodic Protection Cables and Standard Drawing – Magnesium Anode Typical Mounting. 2.4.5 Mitigate by installing a new CP system to provide additional CP current to counter the effects of the interference current. Reference Design and Installation of an Impressed Current Deep Groundbed or Design and Installation of an Impressed Current Surface Groundbed. 2.4.5.1 2.4.5.2 Identify a groundbed location within the area of cathodic protection interference. Install a groundbed within the area of cathodic protection interference. 1.1.2 NOTE: Groundbeds must be designed and installed so as to avoid causing interference to other facilities. 2.4.6 Designing Mitigation Bonds 2.4.6.1 Conducting a P/S correction adjustment test. 2.4.6.1.1 Locate the point of maximum interference current discharge (control test point) using a close interval survey 2.4.6.1.2 Chose the proposed bond location based on accessibility and the following: 2.4.6.1.2.1 2.4.6.1.2.2 2.4.6.2 2.4.6.3 2.4.6.4 Where the two pipelines cross Where the two paralleling pipelines come closest together 2.4.6.1.2.3 Where the pipeline comes closest to a facility 2.4.6.1.2.4 At a point of ownership with an electrical isolating kit Install a temporary shunted resistance bond Interrupt the interfering current source by installing an interrupter with at least an 80% duty cycle setting. Read the interrupted (Off/On) P/S potentials and the interfering bond current at the control test point. <<>> Magellan Midstream Partners, L.P. TESTING FOR INTERFERENCE CURRENTS AND REMEDIAL MEASURES 7.04–ADM–015 Asset Integrity 01/01/11 Revision: 3 Page 7 of 9 2.4.6.5 Start the test with the bond resistance at a maximum, allowing zero bond current flow. 2.4.6.6 Slowly decrease the bond resistance until the Off/On P/S potential readings are the same. 2.4.6.7 Measure the bond resistance and then install a resistor as close as possible to that measured resistance. The current rating of the resistor must be at least as high as the planned current flow. 2.4.7 Installing Convenience/Courtesy Bonds 2.4.7.1 Install convenience/courtesy bonds for foreign pipelines/facilities, whereby: 2.4.7.1.1 2.4.7.1.2 2.4.7.1.3 2.4.7.1.4 2.4.7.1.5 CP current is temporarily exchanged when agreed upon by a foreign pipeline/facility Sufficient CP current is available Does not jeopardize the cathodic protection levels of the providing pipeline/facility Mutually agreed upon by all parties involved Reference Attaching Cathodic Protection Cables. 2.7 Documentation 1.1.3 2.7.1 Interference testing data must be documented and recorded on the Cathodic Protection Interference Test Form. <<>> Magellan Midstream Partners, L.P. TESTING FOR INTERFERENCE CURRENTS AND REMEDIAL MEASURES 7.04–ADM–015 Asset Integrity 01/01/11 Revision: 3 Page 8 of 9 System Integrity Plan Change Log Date Change Location Changed By Approved By Brief Description of Change 12/01/03 Change Log Rick Wooldridge Michael Pearson Added, “Changed By” 12/01/03 2.0 Rick Wooldridge Michael Pearson Added, “Note: Testing for interference currents and remedial measures on a DOT regulated asset is a covered task and should only be performed by those qualified in accordance with the operator qualification ruling. Reference Operator Qualification (OQ) ‐ Covered Tasks. 12/01/03 2.1.1 Rick Wooldridge Michael Pearson Deleted, “from “One Calls” or interference testing committees.” 12/01/03 2.1.2 Rick Wooldridge Michael Pearson Deleted, “Review results of routine cathodic protection surveys and close interval cathodic protection surveys for signs of possible interference.” 12/01/03 2.1.3 Rick Wooldridge Michael Pearson Deleted, “Review information/notices/reports of installation or intent to install new foreign CP systems or pipeline/facility.” 12/01/03 2.1.4 Rick Wooldridge Michael Pearson Deleted, “Review new pipeline encroachment reports or notices.” 12/01/03 2.7.2 Rick Wooldridge Michael Pearson Deleted, “Interference testing data should be electronically transferred to the Cathodic Protection Data Management System (BASS) for retention and analysis.” 12/01/03 2.7.3 Rick Wooldridge Michael Pearson Deleted, “The data should be retained for use in the design and implementation of any necessary remedial action.” 12/01/03 2.7.4 Rick Wooldridge Michael Pearson Deleted, “The data shall be considered to be accurate based on the pipe, cathodic protection, and environmental conditions at the time of the survey.” 12/01/03 2.7.5 Rick Wooldridge Michael Pearson Deleted, “Survey data on a particular pipe segment shall no longer be considered to be representative if there is a significant replacement or recoating of pipeline or a change in the applied cathodic protection within the segment.” 12/01/03 2.2.2 Rick Wooldridge Michael Pearson Deleted, “Test for foreign static and dynamic DC current sources”. 12/01/03 5.0 Rick Wooldridge Michael Pearson Deleted “Responsibilities” section as it is not part of the standard format. 1/1/06 All Rick Wooldridge Michael Pearson 2005 annual review, no changes 01/01/07 All E7 Rick Wooldridge 2006 annual review, no changes 01/01/08 All E7 Rick Wooldridge 2007 annual review, no changes 10/14/08 All E7 Rick Wooldridge 2008 annual review, no changes <<>> Magellan Midstream Partners, L.P. TESTING FOR INTERFERENCE CURRENTS AND REMEDIAL MEASURES 7.04–ADM–015 Asset Integrity 01/01/11 Revision: 3 Page 9 of 9 11/18/09 All E7 Rick Wooldridge 2009 annual review; Removed references and links; other minor modifications 01/01/11 Reviewed, no changes 12/31/11 All 2012 Annual Review complete – no changes <<>> Magellan Midstream Partners, L.P. COATINGS—SELECTION APPLICATION AND MAINTENANCE PROCEDURE 7.04–ADM–016 Asset Integrity 01/01/10 Revision: 2 Page 1 of 2 PURPOSE 1.1 The purpose of this procedure is to communicate a standardized reference for the selection, application, and maintenance of coatings used to prevent corrosion. 2.0 PROCEDURE Selection, Application, and Maintenance of coatings includes both minor coating repairs and major coating projects. This document and its associated links are intended as a reference for OQ training purposes and for the development of a Project Scope/Job Plan. They are not intended as a step‐by‐step procedure or to replace a project specific Job Plan. The specifications below may be used all or in part as required by the individual Project Manager and assignments to both “Company” and “Contractor” may be applied accordingly. 2.1 Reference applicable Company protective coating specifications Atmospheric Coating Standards And Specifications Plant Applied Fusion Bonded Epoxy (FBE) And Abrasive Resistant Overlays (ARO) External Coatings For Field Joints, Soil‐to‐Air Interface, and Coating Repairs 2.1.1 2.1.2 2.1.3 2.2 Documentation 2.2.1 Documentation for below ground coatings on pipelines and related facilities is stored in the Linefill Database system. 2.2.2 Documentation for above ground coatings on pipelines, tanks, and related facilities is stored in the Atmospheric Corrosion database. 2.2.3 Documentation of coating installation and repairs conducted per this procedure should be documented Project Plan, Job Book, and/or Pipeline Maintenance Report as applicable. <<>> Magellan Midstream Partners, L.P. COATINGS—SELECTION APPLICATION AND MAINTENANCE PROCEDURE 7.04–ADM–016 Asset Integrity 01/01/10 Revision: 2 Page 2 of 2 System Integrity Plan Change Log Date Change Location Changed By Changed By Brief Description of Change 10/29/03 Change Log Rick Wooldridge Michael Pearson Added “changed by” to the change log Michael Pearson 10/29/03 1.1 Rick Wooldridge Replaced “establish” with “communicate”. Revised paragraph to make it easier to understand. 10/29/03 2.1, 3.2.1, 3.2.2 Michael Pearson Rick Wooldridge Removed “Williams” Michael Pearson 10/29/03 2.1.1 Rick Wooldridge Removed THE WILLIAMS COMPANIES SPECIFICATION 15.11.07 LATEST EDITION Michael Pearson 10/29/03 2.2.1 Rick Wooldridge Deleted “Record information concerning below and above ground coatings on pipelines and related facilities on the Maintenance Report.” 10/29/03 2.2.1, 2.2.2 Michael Pearson Rick Wooldridge Split below ground and above ground data storage locations to clarify. Michael Pearson 10/29/03 2.0 Rick Wooldridge Added “Note: The application of coatings is a covered task and should only be performed by those qualified in accordance with the operator qualification ruling.” 1/1/06 All E7 Michael Pearson 2005 review, no changes 01/01/7 All E7 Michael Pearson 2006 review, no changes 01/01/08 All E7 Rick Wooldridge 2007 review, no changes 09/12/08 All E7 Rick Wooldridge 2008 review, reformatted, minor modifications 11/19/09 All E7 Rick Wooldridge 2009 annual review, minor word changes 8/10/10 All E7 Rick Wooldridge 2010 annual review; Updated links 12/31/11 All 2012 Annual Review complete – no changes <<>> Magellan Midstream Partners, L.P. TESTING FOR INDUCED AC AND REMEDIAL MEASURES 7.04‐ADM‐023 Asset Integrity 1/1/12 Revision: 1 Page 1 of 5 1.0 PURPOSE 1.1 The purpose of this procedure is to establish a standardized method for identifying and mitigating induced AC. 2.0 PROCEDURE 2.1 Determining the need for induced AC testing. 2.1.1 Determine the need for induced AC testing based on the potential effects on facilities from High Voltage Alternating Current (HVAC). Primary influences of HVAC systems include: [see NACE RPO177‐2000 for more information]. 2.1.1.1 Resistive Coupling 2.1.1.2 Capacitive Coupling 2.1.1.3 Inductive Coupling 2.1.1.4 Power Arc 2.1.1.5 Lightning 2.1.1.6 Switch Surges or other Transients 2.1.2 Tests that may indicate Induced AC include the following: 2.1.2.1 Inadequate Pipe‐to‐Soil (P/S) potential readings 2.1.2.2 AC potential readings 2.1.2.3 Predictive modeling 2.1.3 Likely areas for Induced AC: 2.1.3.1 Pipelines or facilities that enter or exit the electrical gradient of an HVAC system 2.1.3.2 Pipelines or facilities paralleling in close proximity to an HVAC system 2.1.3.3 Pipelines or facilities in close proximity to an HVAC Sub‐Station 2.1.3.4 Pipelines or facilities in close proximity to HVAC Towers and/or grounding systems 2.2 Testing for and Determining the Effects of Induced AC 2.2.1 Identify test leads and/or above ground appurtenances to be tested based on information in 2.1.3 above. 2.2.2 Measure the AC potential using an AC voltmeter. Contact resistance should be sufficiently low to preclude measurement errors. Suitable references for measurements include: 2.2.2.1 2.2.2.2 2.2.2.3 A metal rod inserted into the earth until no further increases in AC potential are noted. Bare pipeline casings, if adequately isolated from the carrier pipe. Tower legs or power system neutrals, in close proximity to the affected structure. <<>> Magellan Midstream Partners, L.P. TESTING FOR INDUCED AC AND REMEDIAL MEASURES 7.04‐ADM‐023 Asset Integrity 1/1/12 Revision: 1 Page 2 of 5 2.2.2.4 Reference electrodes designed for gathering cathodic protection data (i.e. half‐cells, permanent reference electrodes, etc.) CAUTION: Meter connections may present a hazard during switching surges, lightning strikes, or fault conditions. 2.2.3 Analyze the AC P/S reading from step 2.2.2 of this procedure to determine if soill resistivity data is required. Criteria includes: 2.2.3.1 AC potentials greater than 10 volt 2.2.3.2 Human shock hazards have been identified (electrical shocks may occur at a voltage below the 15 volt threshold recommended by NACE, while not life threatening, mitigation may be necessary to address these shocks.) 2.2.3.3 Areas were AC potentials are cyclic, unstable, or inconsistent over time. 2.2.3.4 Areas were AC corrosion has been identified 2.2.4 If soil resistivity measurements are not required go to 2.7 below. 2.3 Soil Resistivity 2.3.1 Collect soil resistivity measurements at each location as selected per 2.2.3. 2.4 AC Current Density 2.4.1 Using the AC voltage measured in 2.2.2 and the soil resistivity measured in 2.3.1 determine the calculated AC current discharge density per the AC current density calculator in section 2.4.2. Note: Holiday size should be selected based on the typical holiday size expected on the pipeline. 2.4.2 AC Current Density Calculator Calculating AC Current Density Inputs AC Voltage 10 volts Soil Resistivity 5000 ohm-cm Holiday Size 6 cm2 AC Current Density 18.42633309 A/m2 AC Corrosion Potential AC corrosion not likely Cathodic Protection Criteria 100mv polorization AC Mitigative Action No action required AC Voltage Measured or calculated Soil Resistivity Measured or expected <<>> Magellan Midstream Partners, L.P. TESTING FOR INDUCED AC AND REMEDIAL MEASURES 7.04‐ADM‐023 Asset Integrity 1/1/12 Revision: 1 Page 3 of 5 2.4.3 2.4.4 2.4.5 The AC Current Density Calculator utilizes the relationship between the AC driving voltage, soil resistivity, and the estimated size of the coating holiday from which current can discharge, to estimate the discharge density. Where a more precise current discharge density is required coupon test stations should be installed. Determine the potential for AC corrosion 2.4.4.1 AC Current Density <20 A/m2 = AC Corrosion not likely 2.4.4.2 AC Current Density >20 A/m2 but <100 A/m2 = AC Corrosion unpredictable 2.4.4.3 AC Current Density >100 A/m2 = AC Corrosion is likely Determine the need for mitigative action (see AC current density calculator in section 2.4.2) 2.4.5.1 2.4.5.2 2.4.5.3 2.4.6 AC Current Density <20 A/m2 = No action required AC Current Density >20 A/m2 = Action required Rule of Thumb: When the AC potential, in millivolts (mV), is greater than or equal to the resistance of the soil, in ohm‐cm; a more detailed analysis and/or mitigation is typically required. Determine the criteria for cathodic protection ((see AC current density calculator in section 2.4.2) 2.4.6.1 2.4.6.2 2.5 2.6 AC Current Density <20 A/m2 = 100 mV polarization AC Current Density >20 A/m2 but <500 A/m2 = 150 mV to 250mv polarization 2.4.6.3 AC Current Density >500 A/m2 = Cathodic protection is not effective in mitigating corrosion Mitigative Action – Cathodic Protection can be effective at mitigating AC corrosion 2.5.1 Measure and/or calculate the target ON potential for each test point within the area affected by Induced AC. 2.5.1.1 Target ON is the potential, with current applied, where polarization equal to the native potential, plus the cathodic protection criteria established in 2.4.6 is achieved. 2.5.2 Document the Target ON potential in the Corrosion Database (CPDM). 2.5.3 Utilize the target ON potential as the criteria for cathodic protection. This criteria may be used as long as there are no significant changes in the environment, structure, coating, cp systems, etc. 2.5.4 Supplemental cathodic protection and/or coating rehabilitation will be required if the adequate cathodic protection potentials are not achieved. Mitigative Action – In addition to adequate cp as defined in 2.5, managing the negative effects from Induced AC or lightning is accomplished by reducing the interference voltage and/or providing a path to ground for damaging current. 2.6.1 Select and install the appropriate grounding equipment. This equipment may include: 2.6.1.1 Grounding rods (typically made of zinc, copper, graphite or cast‐iron) <<>> Magellan Midstream Partners, L.P. TESTING FOR INDUCED AC AND REMEDIAL MEASURES 7.04‐ADM‐023 Asset Integrity 1/1/12 Revision: 1 Page 4 of 5 2.6.1.2 2.6.1.3 installed where the pipeline enters and exits the electrical gradient of a HVAC system and at select locations where the pipeline parallels the HVAC system. Grounding ribbons (typically made of zinc or copper) installed parallel with and directly connected to the pipeline along the distance where the pipeline is influenced by the HVAC system. Ground mats (typically made of zinc or copper) should be installed at valves, metallic vents, cathodic protection test stations, and other above ground appurtenances where electrical contact with the affected structure is possible. Grounding mats should be large enough to extend beyond the area on which a person may be standing when contacting the affected structure and close enough to the surface that step and touch potentials are adequately reduced. NOTE: If the ground rod material used has a native voltage potential less negative than the ‐1 volt (as compared to copper‐copper sulfate electrode) an isolation device must be installed to block the flow of DC, while passing AC. Caution is advised when using grounding material with a native potential more negative than the pipeline as the ground will be anodic to the pipeline and thus corrode. 2.6.1.4 2.6.1.5 Where AC surge currents or lighting is a concern, electrical bonds designed to pass AC, should be installed across insulating flanges to prevent arcing. Groundbeds utilized for cathodic protection of the pipeline or facility will provide mitigative grounding as described above. However, precautions should be taken to protect the electrical equipment and wiring from lighting and surge current damage. 3.0 MONITORING 3.1 Induced AC and lightning mitigation equipment should be monitored to ensure its continued effectiveness. 3.2 In areas where induced AC currents have been identified, coupon test stations should be installed and monitored. 4.0 DOCUMENTATION 4.1 Data collected as part of this procedure shall be documented in appropriate sections of the Corrosion Control database (CPDM). <<>> Magellan Midstream Partners, L.P. TESTING FOR INDUCED AC AND REMEDIAL MEASURES 7.04‐ADM‐023 Asset Integrity 1/1/12 Revision: 1 Page 5 of 5 System Integrity Plan Change Log Date Change Location Changed By Brief Description of Change Approved By 12/06/06 NEW Rick Woolridge Michael Pearson New procedure 01/01/08 All E7 Rick Wooldridge Reviewed, no changes All E7 1/1/09 Rick Wooldridge 2008 annual review complete – no changes All E7 01/01/10 Rick Wooldridge E7 Review; no changes All E7 01/01/11 Rick Wooldridge E7 Review, no changes 9/28/11 2.2.3.1 John McMahan Rick Wooldridge E7 Review; Changed 1 volt to 10 volts 12/31/11 All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. PIPELINE MARKING PROCEDURE 7.05–ADM–002 Asset Integrity 01/01/10 Revision: 7 Page 1 of 5 1.0 PURPOSE 1.1 The purpose of this procedure is to establish a standardized process for safely marking the Company rights‐of‐way (ROW) with permanent line markers, in order to: 1.1.1 1.1.2 1.1.3 1.1.4 Meet all applicable DOT requirements. Effectively delineate the pipeline corridor. Promote public and community awareness. Identify the pipeline location for effective damage prevention. 2.0 SCOPE 2.1 This procedure is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be utilized in whole or part on non‐jurisdictional assets as deemed appropriate. 2.2 Assets covered per the Mitigation Plan: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, other specific marker requirements may be stated within the Mitigation Plan. Refer to the Mitigation Plan for those requirements. 2.3 Consent Decree Specific: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, the Company’s Consent Decree Pipeline Systems operate under the requirements of the Consent Decree. For the period of the Consent Decree, these systems will follow the applicable process and procedures (see Consent Decree for applicable programs). 3.0 PROCEDURE 3.1 Consider using the most appropriate marker type, as dictated by the existing conditions. 3.1.1 3 inch PVC schedule 40 pipe with 3” cap, black/red color coded decal six inches from top of post, with warning decal or warning sign as appropriate. Refer to the Standards List. 3.1.2 Flexible fiberglass composite markers. 3.1.3 Bullet style markers. 3.2 The following special tools/equipment/materials as required for permanent pipeline marking: 3.2.1 Applicable assembled marker post or marker. 3.2.2 Pipeline Warning Decals. Refer to the Standards List. 3.2.3 “Pipeline Under Pavement” decals/or signs where applicable. 3.2.4 Color‐coded decals or stickers. 3.2.5 Signs must include “Warning” followed by “Petroleum Pipeline” with letters at least 1 inch high with an approximate stroke of ¼ inch, Company name and 24 hr phone number. 3.2.6 Posthole digger. 3.2.7 Shovel. 3.2.8 Appropriate post driver. <<>> Magellan Midstream Partners, L.P. PIPELINE MARKING PROCEDURE 7.05–ADM–002 Asset Integrity 01/01/10 Revision: 7 Page 2 of 5 3.2.9 Auger. 3.3 Markers must be placed and maintained over each buried pipeline at the following locations: 3.3.1 Each public road crossing. 3.3.2 Each railroad crossing. 3.3.3 Where the line is above ground in areas that are accessible to the public 3.3.4 In sufficient numbers along the remainder of each buried line so that its location is accurately known. Where practical and appropriate, use the following guidelines to establish locations for additional pipeline marker placement:  Interior cross fences  Both sides of creeks and rivers  Both ends of all pipeline exposures  Developed area, commercial and residential  Vast areas with few fences or areas with changing elevations that limits marker visibility.  Markers should not be placed in an area that impedes and/or prevents landowners or tenants (e.g. ranchers, farmers businesses, etc.) from conducting daily activities, or where prohibited by local ordinances. These are best handled on a ‘case by case’ basis; consult immediate Supervisor with questions or unique circumstances. 3.4 Installation of Pipeline Markers: 3.4.1 When applicable, notify landowner prior to entering property. 3.4.2 When excavating activities are required pertaining to installation of marker posts, follow applicable state One Call regulations. (i.e. use of an auger or posthole digger, etc.) 3.4.3 Locate pipeline per Pipeline Locating Procedure. 3.4.4 Dig post hole for 3” post or drive markers as appropriate. 3.4.5 When required, install milepost numbers directly below warning decal or warning sign (at road crossings and valve sites). 3.4.6 For pipelines paralleling roadways located under the surface of the roadway where marker placement is not practical, markers should be placed at the nearest location adjacent to the pipeline and a “pipeline under pavement” decal placed beneath the existing Company warning decal. 3.4.7 Pipeline markers will be placed as close to the line as possible, however, when a marker is offset a greater distance than five feet from the pipeline; notify the appropriate Asset Integrity Supervisor. 3.5 Assets covered per the Mitigation Plan: 3.5.1 3.5.2 All markers shall be within line of sight of one another in Tier I Areas. If one marker is removed, the location of the pipeline can still be identified from either direction from any point in between Tier II and Tier III Areas <<>> Magellan Midstream Partners, L.P. PIPELINE MARKING PROCEDURE 7.05–ADM–002 Asset Integrity 01/01/10 Revision: 7 Page 3 of 5 3.6 3.5.3 3.5.4 3.5.5 3.5.6 3.5.7 3.5.8 All line markers will be written in English and Spanish. Marker placement and density will be evaluated routinely through aerial and ground surveillance. Missing and damaged markers will be replaced within seven days of discovery. Markers will be located at all aboveground facilities to identify the operator of the system. When practical fence crossings will have fence post on either side painted bright yellow to aid in the identification of the pipeline easement width. Documentation will be completed using Mitigation Right of Way Inspection Form, making appropriate comments including: Stationing, GPS coordinate (where possible), land use change or increased density due to Tier I, Tier II and Tier III requirements, etc. Install aerial milepost markers on jurisdictional lines that are patrolled by aerial methods as follows: NOTE: Aerial Markers are for reference only and may not reflect exact stationing. 3.6.1 3.6.2 3.6.3 3.6.4 3.6.5 3.6.6 Construct Aerial Markers on a triangle framework with mile number identified facing up and down stream. Numbers should be of sufficient size to be seen by aerial patrol pilots with the number being black on a yellow background. Refer to the Standards List. Use heavy gauge aluminum or fiberglass, with decal numbers and arrows. Aerial marker numbers should be assigned to match the nearest milepost number as documented on alignment sheets. Place along all mainline ROW, positioned so that they are legible as a pilot flies the line. Place at public road crossings or other appropriate points (distance between markers generally not to exceed one mile). Use special markers with arrows slanted left, right or vertical to direct pilot around locations requiring deviation of flight. <<>> Magellan Midstream Partners, L.P. PIPELINE MARKING PROCEDURE 7.05–ADM–002 Asset Integrity 01/01/10 Revision: 7 Page 4 of 5 System Integrity Plan Change Log Date Change Location Change By Brief Description of Change 010/01/05 Reviewed, no changes Troy Bronson 01/01/06 2.2.7 Replaced “Examples of universal wastes include lead acid batteries, pesticides, thermostats with liquid mercury, and florescent light bulbs.” With “Pipeline markers will be placed as close to the line as possible, however, when a marker is offset a greater distance than 5’ from the pipeline, a Maintenance Report will be generated documenting the placement and reason why.” 01/01/06 2.4.1 Troy Bronson Added “Follow applicable state one‐call regulations pertaining to installation of marker posts.” 01/01/06 Troy Bronson 2.5.1 Replaced “Numbers on signs to be 4” X 6” with the number being black on a yellow background.” With “Numbers should be of sufficient size to be seen by aerial patrol pilots with the number being black on a yellow background. Recommended size of the sign is 6” x 15” with numbers 4 ½ ” x 13 ½ “.” 01/01/06 2.5.5 Troy Bronson Removed note box: When more than 1 pipeline mile is traveled and a public road is passed without seeing a marker, the marker is considered to be missing. 01/01/06 4.2.1 Troy Bronson Added Line Locating link 01/01/06 2.2.2 Troy Bronson Added “where applicable”. 01/01/06 Applicability Dan Egner Added complete section 01/01/06 1.0 thru 1.1.4 Dan Egner Major modification 01/01/06 2.1 thru 2.1.3 Dan Egner Major modification 01/01/06 2.2.1 Dan Egner Changed to “Applicable markers” 01/01/06 2.2.9 Dan Egner Added “appropriate” 01/01/06 2.3.1 Dan Egner Removed “railroad” 01/01/06 2.3.2 Dan Egner Added “Both sides of all railroad crossings” 01/01/06 2.3.3 Dan Egner Added “appropriate and practical” 01/01/06 2.3.6 Dan Egner Added complete subpart 01/01/06 2.2.6.1 Dan Egner Added for the Consent Decree 01/01/06 2.3.10 thru 2.3.15 Dan Egner Added for the Longhorn Pipeline 01/01/06 2.4.1 Dan Egner Added “where applicable” 01/01/06 2.5.7 Dan Egner Removed (…”only”) added (…”and valve sites”) 01/01/06 2.6 Dan Egner Added NOTE: 01/01/06 2.6.3 Dan Egner Major modification 01/01/06 2.7 thru 2.7.1 Dan Egner Added subparts 01/01/06 2.8 thru 2.8.3 Dan Egner Added subparts 01/01/06 2.9 thru 2.9.2 Dan Egner Added subparts 01/01/06 4.1.2 Dan Egner Added regulation 01/01/06 4.3.2 Dan Egner Added form 01/01/06 5.5 Dan Egner Added definition 01/01/06 Removed references, renamed links 02/01/06 3.3 Clyde Clausen Added section 3.3 02/01/06 3.4 Clyde Clausen Modified section 3.4 02/01/06 3.5 & 3.6 Clyde Clausen Added 3.5 and 3.6 (Consent and Longhorn Specific) 02/01/06 3.7 Clyde Clausen Modified paragraph 3.7 02/01/06 3.8 Clyde Clausen Deleted and incorporated into 3.7 02/01/06 3.9 Clyde Clausen Deleted and incorporated into 3.5 <<>> Magellan Midstream Partners, L.P. PIPELINE MARKING PROCEDURE 7.05–ADM–002 Asset Integrity 01/01/10 Revision: 7 Page 5 of 5 2/3/06 3.2.3 Troy Bronson Changed “sign” to “decal”. 2/3/06 3.2.5 Troy Bronson Deleted “Cordless Drill” 2/3/06 3.7.7 Troy Bronson Insert “standards” link. 2/3/06 3.7.8 Troy Bronson Changed “Sign” to “Decal”. 2/3/06 3.7.9 Troy Bronson Changed “Sign” to “Decal”. 2/3/06 3.7.10 Troy Bronson Changed “contact” to “notify”. 1/1/07 3.7 Greg Walker Link to Pipeline Locating Procedure 5/22/07 3.0 Greg Walker Consolidate procedures. Added information about Warning sign details. 5/22/07 3.3.4 Greg Walker Added clarification where markers should be placed. 12/12/08 2.3 Tim Boudreaux Modified the Consent Decree statement to exclude the previous Consent Order. 12/12/08 4.0 Tim Boudreaux Deleted Pipeline Marker Repair report form link. 12/12/08 4.4 Tim Boudreaux Included Longhorn Mitigation Plan. 01/01/2009 Tim Boudreaux Conducted annual review with no changes. 01/01/2009 3.5.7 Tim Boudreaux Included Longhorn specific documentation requirements. 3‐26 3.5.6 Greg Walker Included Longhorn specific documentation requirements. 9/01/09 2.2 Tim Boudreaux Deleted Longhorn Specific 9/01/09 3.5 Tim Boudreaux Changed Longhorn Specific to Assets covered per Mitigation Plan 9/01/09 3.5.8 Tim Boudreaux Deleted Longhorn 9/01/09 4.4 Tim Boudreaux Deleted Longhorn 9/01/09 Tim Boudreaux Annual Review with changes listed above 01/01/11 Reviewed, no changes 12/31/11 All 2012 Annual review complete – no changes <<>> Magellan Midstream Partners, L.P. RIGHT‐OF‐WAY MAINTENANCE PROGRAM 7.05–ADM–003 Pipeline Integrity 01/01/12 Revision: 7 Page 1 of 6 1.0 PURPOSE 1.1 The purpose of this program is to safely maintain Company pipeline rights‐of‐way, in order to comply with DOT requirements (Line Markings); (Inspection of Rights‐of‐Way) and Transmission Lines: Patrolling. 2.0 SCOPE 2.1 This program is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be utilized in whole or part on nonjurisdictional assets as deemed appropriate. 2.2 Assets covered per the Mitigation Plan: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, other specific right of way maintenance requirements may be stated within the Mitigation Plan. Refer to the Mitigation Plan for those requirements. 2.3 Consent Decree Specific: In addition to applicable Federal, State, and Local regulations, as well as Magellan guidelines, process, or best practices, Magellan’s Consent Decree Pipeline Systems operate under the requirements of the Consent Decree, (see Consent Decree for applicable programs). 3.0 DESCRIPTION 3.1 The Right‐of‐Way Maintenance Program is a systematic and comprehensive method to effectively manage pipeline rights of way maintenance as related to : 3.1.1 Locating Line: The Pipeline Locating Procedure covers locating underground pipeline facilities for any reason. These may include, but not limited to One Call Program, line locates, Right of Way marking, clearing, mowing, spraying, surveying, inspection, or any maintenance or damage prevention activity. 3.1.2 Marking the line. The Pipeline Marking Procedure covers temporary or permanent mainline facility marker requirements and placements in order to raise public awareness of the location and type of underground facility and therefore reduce the risk of accident, injury or damage. 3.1.3 Pipeline surveillance, ground and aerial surveillance. The Inspection of Right‐of‐Way Procedure covers DOT regulated pipeline surveillance for Refined Product, NGL and 3.1.4 Natural Gas transportation facilities. Clearing Right of Way. The Right‐of‐ Way Clearing Procedure covers major vegetation 3.1.5 clearing activity along Company mainline right of way corridors. Mowing Right of Way. The Right‐of‐Way Mowing Procedure covers moderate 3.1.6 vegetation clearing activity along Company mainline right of way corridors, as well as vegetation control at road crossings. Spraying Right of Way. The Right‐of‐Way Spraying Procedure covers vegetation control 3.1.7 activity using herbicidal applications along Company mainline right‐of‐way corridors, as well as vegetation control at road crossings. Identification and Managing Encroachments. The Encroachment Process and the Encroachment Guidelines aid in identifying, mitigating and documenting easement encroachments along the Company transportation facilities rights‐of‐way. <<>> Magellan Midstream Partners, L.P. RIGHT‐OF‐WAY MAINTENANCE PROGRAM 7.05–ADM–003 Pipeline Integrity 01/01/12 Revision: 7 Page 2 of 6 4.0 PROGRAM 4.1 Gather Right of Way Data 4.1.1 4.1.2 Gather pertinent data for evaluating and managing right‐of‐way and included in the spreadsheet and/or electronic filing system (database). Pertinent data includes, but is not limited to; line segment, geographical location, condition of right‐of‐way, type of vegetation, maintenance needs, maintenance history, risk score, etc. The appropriate procedure listed above should be reviewed to ensure complete data is acquired for each type of maintenance activity. Conduct training, for Assets covered per the Mitigation Plan, on Endangered and Threatened Species and their Habitats for all third party contractors. Coordination of 4.1.3 clearing activities and use of the biologist developed maps depicting the location and habitats of endangered species should be utilized to avoid or minimize adverse effects during this maintenance activity. Obtain pertinent data through aerial surveillance or ground surveillance (walking the line) depending on specific requirements. Annually, a company representative will accompany the aerial patrol pilot to identify areas where excavation activity or leak detection cannot be identified by air. Annual inspections should be performed during high vegetation growth months in order to effectively identify these visibility issues, The results of the annual inspection should be documented on the Right of Way Inspection and Assessment Form and copies sent electronically to the appropriate Right of Way 4.2 4.3 Initiative Manager and Field Supervisor. Assess the Right of Way Data 4.2.1 Develop a plan to systematically address areas of concerns and properly maintain the right‐of‐way, after all pertinent data regarding the right‐of‐way condition has been collected and entered into the Right of Way Inspection and Assessment Form. 4.2.2 Prioritize the plan on the following factors (but not limited to): 4.2.2.1 Prioritization scores based on annual inspections (aerial or ground patrols) regarding ability to clearly identify and view surface conditions. 4.2.2.2 Concerns or comments from previous regulatory audits or inspections or specific regulatory mandated requirements imposed for pipeline section operations. 4.2.2.3 Accessibility for operations and maintenance personnel. 4.2.2.4 Third party activity trends (based on One Calls). 4.2.2.5 Real Estate Services commitments or concerns. 4.2.2.6 Accurate and visible marking of the lines. Mitigation Planning for Right of Way Maintenance: 4.3.1 Develop plans to address areas of concerns on a prioritized basis; highest priority areas receive attention first. Optimum time of year (season) or specific facility requirements such as, the Mitigation Plan, may affect this plan. 4.3.1.1 Assets covered per the Mitigation Plan: Ground cover will be mowed to a <<>> Magellan Midstream Partners, L.P. RIGHT‐OF‐WAY MAINTENANCE PROGRAM 7.05–ADM–003 Pipeline Integrity 01/01/12 Revision: 7 Page 3 of 6 4.4 4.3.2 4.3.3 4.3.4 4.3.5 4.3.6 4.3.7 level so that all pipeline markers, including painted fence posts, will be visible from the air and while standing on the ground. High canopy vegetation will be cleared or trimmed to the extent necessary to allow clear visibility. Address both the short‐term and long‐term needs for proper right‐of‐way maintenance in the plans. Solicit bids and costs estimates for the plan. Consult herbicidal manufactures for assistance in identifying the proper herbicides and application methods for various geographical areas. Submit plan to the initiative manager or proper authority for approval. Submit plan to Pipeline Integrity for inclusion into Area Integrity Plan. Update and revise the right‐of‐way plan systematically as information is received and processed. Consult Environmental Specialists and Pipeline Integrity Real Estate Representatives before implementing initial clearing projects. Right of Way Maintenance Execution 4.4.1 Follow Project Life Cycle as related to maintenance projects which include, but are not limited to: 4.4.1.1 Assign a Project Manager. 4.4.1.2 4.4.1.3 4.4.1.4 4.4.1.5 Initiate the Right of Way Review. Develop a project plan and scope and submit to all stakeholders for review prior to starting the maintenance. Make contacts with the landowners prior to starting the maintenance on the property. Complete the maintenance and all documentation associated with the project and submit all completion reports to the Pipeline Integrity Coordinator. 5.0 REFERENCES 5.1 Related Policies/Procedures 5.1.1 One Call Program 5.1.2 Pipeline Locating Procedure 5.1.3 Pipeline Marking Procedure 5.1.4 Inspection of Right‐of‐Way Procedure 5.1.5 Right‐of‐ Way Clearing Procedure 5.1.6 Right‐of‐Way Mowing Procedure 5.1.7 Right‐of‐Way Spraying Procedure 5.1.8 Encroachment Process <<>> Magellan Midstream Partners, L.P. RIGHT‐OF‐WAY MAINTENANCE PROGRAM 7.05–ADM–003 Pipeline Integrity 01/01/12 Revision: 7 Page 4 of 6 Endangered and Threatened Species and their Habitats Right of Way Inspection and Assessment Form 5.1.9 Encroachment Guidelines 5.1.10 Mitigation Plan 5.1.11 5.1.12 Project Life Cycle 5.2 Forms and Attachments 5.2.1 07‐Form 1585 5.2.2 07‐Form‐1583 On Ground Right of Way Assessment Worksheet 5.2.3 07‐Form‐7035 Encroachment Agreement (Short Form) 5.2.4 07‐Form‐1581 Pipeline Maintenance Report 6.0 DEFINITIONS 6.1 Jurisdictional Lines: Pipeline segments falling under the jurisdiction of a state (i.e., Texas Railroad Commission or PSC) and/or federal regulating authority (i.e., Department of Transportation). 6.2 Spraying: The practice of applying herbicides to control undesirable vegetation growth. 6.3 Mowing: The practice of utilizing various light equipment, such as, mowers, brush hog, weed eater, hand thrasher, etc. to clear right of way of moderate vegetation. 6.4 Clearing: The practice of utilizing heavy equipment, such as dozers, track hoes, chippers, shredders, hydro axes, chainsaws, etc. to clear right of way of heavy vegetation. <<>> Magellan Midstream Partners, L.P. RIGHT‐OF‐WAY MAINTENANCE PROGRAM 7.05–ADM–003 Pipeline Integrity 01/01/12 Revision: 7 Page 5 of 6 System Integrity Plan Change Log Date Change Location Change By Brief Description of Change 12/22/03 1.0 Clyde Clausen Deleted Purpose, Inserted Objective 12/22/03 1.1 Clyde Clausen Deleted the purpose of this procedure is 12/22/03 2.2.9 Clyde Clausen Inserted Pipeline Integrity Real Estate Representatives 12/22/03 3.2 & 3.3 Clyde Clausen Deleted 3.2 and 3.3 10/28/05 1.0 Tim Boudreaux Deleted Objective and included Purpose Tim Boudreaux Included the purpose statement 10/28/05 1.1 Tim Boudreaux 10/28/05 2.0, 3.0, 4.0 Included all new program description, including the sub‐numbered sections 11/10/05 Header Tim Boudreaux Included the Applicability statement in the opening Paragraph. 11/16/05 1.0 Tim Boudreaux Complete rewrite of Purpose section. 11/16/05 2.0 Tim Boudreaux Included all of Description section. 11/17/05 3.0 Tim Boudreaux Rewrite all of Program document in this section. 11/17/05 4.0 Tim Boudreaux Included regulatory numbers and all policy/procedure and form links. 11/17/05 5.0 Tim Boudreaux Included definitions for clearing, mowing, visibility and accessibility. 01/01/07 Reviewed, no changes 10/30/07 All Tim Boudreaux Conducted 2007 Annual Review see change log 10/30/07 4.1.4 Tim Boudreaux Included text on Annual Aerial Patrol Surveys. 10/30/07 4.2.2.1 Tim Boudreaux Changed the paragraph to include Prioritization scores. 10/30/07 4.2.2.3 Tim Boudreaux Eliminated Aerial Patrol comments. 10/30/07 5.2.2 Tim Boudreaux Included Aerial Patrol Annual Inspection Form. 10/30/07 5.2.3 Tim Boudreaux Included On Ground Right of Way Assessment Worksheet. 12/19/08 2.3 Tim Boudreaux Modified Consent Decree Specific. 12/19/08 4.1 Tim Boudreaux Deleted all of previous 4.1.3 Consent Decree Specific. 12/19/08 4.3.1 Tim Boudreaux Deleted reference to CV02‐1178. 12/19/08 5.1.12 Tim Boudreaux Deleted link to CV02‐1178. <<>> Magellan Midstream Partners, L.P. RIGHT‐OF‐WAY MAINTENANCE PROGRAM Pipeline Integrity 01/01/12 12/19/08 5.1.13 Tim Boudreaux 12/19/08 5.1.14 Tim Boudreaux 12/19/08 6.5 Tim Boudreaux 12/19/08 6.6 Tim Boudreaux 01/01/09 Tim Boudreaux 4/3/09 4.3.1.1 Tim Boudreaux 9/01/09 2.2 Tim Boudreaux 9/01/09 4.1.2 Tim Boudreaux 9/01/09 4.3.1 Tim Boudreaux 9/01/09 5.1.10 Tim Boudreaux 9/01/09 Tim Boudreaux 9/02/10 5.2.6, 5.2.7, 5.2.8, 5.2.9, 5.2.10, 5.2.11, 5.2.12, 5.2.13 Tim Boudreaux 9/02/10 Tim Boudreaux 9/02/11 4.1.3 Dennis Vasicek 9/02/11 4.2 Dennis Vasicek 9/02/11 4.3.7 Dennis Vasicek 9/02/11 5.2 Dennis Vasicek 12/31/11 All 7.05–ADM–003 Revision: 7 Page 6 of 6 Deleted link to On the Ground Survey (OTG). Deleted line to Line of Sight Survey (LOS). Deleted definition for Visibility (no longer valid). Deleted definition for Accessibility (no longer valid). Annual Review with no changes. Added Longhorn Commitment Deleted Longhorn, added Assets covered per the Mitigation Plan Deleted Longhorn Deleted Longhorn Deleted Longhorn Annual Review with changes listed above Deleted links to all PL forms Annual Review with changes listed above Replaced reference to “Aerial Patrol Annual Inspection Form” with “Right of Way Inspection and Assessment Form”. Revised distribution list for the Right of Way Assessment Form. Deleted last three sentences. Replaced, “a spreadsheet or electronic filing system” with, “the Right of Way Inspection and Assessment Form.” Added Environmental Specialists Removed, “07‐Form‐1574 Inspection of Right of Way Report” and “07‐Form 1584 Aerial Patrol Annual Inspection Form”. Added, “07‐Form‐1585 Right of Way Inspection and Assessment Form” 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. DEPTH OF COVER PROGRAM 7.05–ADM–009 Asset Integrity 01/01/11 Revision: 4 Page 1 of 4 1.0 PURPOSE 1.1 The purpose of the Depth of Cover (DOC) Program is to manage risks associated with areas of shallow or exposed pipe and earth movements along the Company’s pipeline system. 1.1.1 1.1.2 1.1.3 The DOC program is an on-going process. Land use, population density, environmental issues and changes to the absolute depth of cover are expected to change over time. Consequently, depth of cover data will become outdated as land uses change, land erosion occurs and topsoils are moved over time as a result of wind, rain and mechanical forces. Continual monitoring of these changes is performed through Depth of Cover Surveys, Aerial Patrols, In-Line (Smart Pig) Inspections, One-Calls and Line Spotting. Secondly, through a formalized DOC Mitigation Process, this Program intends to manage the associated risks through a variety of methods, all designed to reduce the likelihood of unintended outside force damage and consequential damages to a defined level. The DOC Program prioritizes those areas of highest relative risk. The investigative and resulting mitigation processes will consequently focus on High Consequence Areas (HCAs) and then the Non-HCAs. Furthermore, as HCAs are modified over time due to changing population and environmental concerns, the DOC prioritizations will also be modified. Assets covered per Mitigation Plan (pg. 96 section 3.5.8 Item 3) specifically states the investigative and resulting mitigation processes will consequently focus on the defined areas of hypersensitive (Tier III), sensitive (Tier II), and other (Tier I), in descending order. 2.0 SCOPE 2.1 2.2 2.3 This procedure is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be utilized in whole or part on nonjurisdictional assets as deemed appropriate. Assets covered per Mitigation Plan: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices. This pipeline system operates under the requirements of the Mitigation Plan. Consent Decree Specific: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, the Company’s Consent Decree Pipeline Systems operate under the requirements of the Consent Decree. For the period of the Consent Decree, these systems will follow the applicable process and procedures (see Consent Decree for applicable programs). 3.0 PROGRAM ELEMENTS 3.1 Shallow and Exposed Pipe 3.1.1 Shallow and exposed pipe locations are identified, prioritized, and mitigated in accordance with Depth of Cover Procedure. A review of the pipeline as defined in Section 6 of the IMP will be conducted, to be followed by a re‐assessment interval recommendation per Section 7 of the IMP. 3.1.1.1 Aerial patrols, operational activities, public input and other means may require depth of cover surveys based upon land use, environmental concerns, population density, and construction and excavation activity levels. <<>> Magellan Midstream Partners, L.P. DEPTH OF COVER PROGRAM 7.05–ADM–009 Asset Integrity 01/01/11 Revision: 4 Page 2 of 4 3.1.1.2 Depth of cover surveys will be conducted in accordance with the Depth of Cover Procedure. 3.1.1.3 Communication to landowners, tenants, developers and local authorities will be conducted as necessary to ensure an appropriate awareness of the location and risks of the pipeline and to coordinate appropriate pipeline adjustments in anticipation of and in connection with construction and development activities. 3.2 Earth Movement 3.2.1 Risks associated with Earth Movement are identified and assessed per the Company Risk Assessment Methodology book, and include factors such as landslide potential, seismic activity, scour, and history of earth movement. 3.2.1.1 Any areas of the pipeline identified as having high susceptibility to earth movement factors or where earth movement has been identified will be investigated and monitored per the Earth Movement Inspection Procedure. 3.2.1.1.1 3.2.1.1.2 Initial investigation of areas identified as having high susceptibility to earth movement will be conducted within one year. Reinspection and/or monitoring of areas identified as having high susceptibility to earth movement or where earth movement has been identified will be conducted per the Earth Movement Inspection Procedure. 3.2.1.2 If earth movement is determined to be present, a review of the pipeline as defined in Section 6 of the IMP will be conducted, to be followed by a re‐ assessment interval recommendation per Section 7 of the IMP. 3.2.1.3 Action items identified during the execution of the Earth Movement Inspection Procedure or through Section 6, Risk Analysis will be documented and tracked in the Asset Integrity Plan. 3.3 Navigable Waterway Crossing Inspections 3.3.1 Navigable River crossing inspections are conducted in accordance with the Navigable River Inspections Procedure. 3.3.1.1 Navigable waterways are derived from the Bureau of Transportation Statistics National Waterways Network database. 3.4 Overhead Pipeline Crossing 3.4.1 The purpose is to effectively manage Overhead Pipeline Crossing maintenance through a comprehensive risk-based program which identifies risk reduction projects to improve structural component integrity. 3.4.1.1 Each Overhead Pipeline Crossing structure will receive an initial risk prioritization number based on the Pipeline Risk Model. The first phase of the inspections will include the top 20% of the structures listed as highest risk based on historical water flow events, proximity to HCA’s, and historical structural knowledge. All other structures will follow (20%) per <<>> 4.0 Magellan Midstream Partners, L.P. DEPTH OF COVER PROGRAM 7.05–ADM–009 Asset Integrity 01/01/11 Revision: 4 Page 3 of 4 year, not to exceed six years. Reinspections will start over upon completion and will be conducted per the Overhead Pipeline Crossing Inspection Procedure. 3.4.1.2 Overhead Pipeline Crossing Inspections are conducted in accordance with the Overhead Pipeline Crossing Inspection Procedure. 3.4.1.3 Maintenance will be performed on structures following the Overhead Pipeline Crossing Inspections as necessary per the Overhead Pipeline Crossing Inspection Procedure. DATA MANAGEMENT AND INITIATIVE IMPLEMENTATION 4.1 Data initially obtained and periodically updated via the DOC program will be centralized and maintained in the DOC database. 4.2 Pipeline Integrity will further manage the recommendation and funding process associated with the implementation of DOC mitigation initiatives. 4.3 Action items associated with the DOC program will be documented and tracked in the Asset Integrity Plan. <<>> Magellan Midstream Partners, L.P. DEPTH OF COVER PROGRAM 7.05–ADM–009 Asset Integrity 01/01/11 Revision: 4 Page 4 of 4 System Integrity Plan Change Log Date Change Location Change By Brief Description of Change 1/09/04 1.2.2 Tim Boudreaux Included Navigable River inspections paragraph. 1/09/04 2.1.3.2 Tim Boudreaux Excluded Certified letters and maps. 1/09/04 2.1.4.3 Tim Boudreaux Replaced “WES” with “MMP” 1/09/04 3.1.1.1 – 3.1.1.3 Tim Boudreaux Modified the prioritization definitions with the current updated version. 1/09/04 4.1 Tim Boudreaux Deleted “ORA”. 1/09/04 5.1.7 Tim Boudreaux Included a link to the Navigable River Inspection procedure. 12/17/04 1.1 Tim Boudreaux Change text and included Earth Movement Statement. 12/17/04 1.1.1 Tim Boudreaux Changed text to: “is an on-going process” 12/17/04 1.2 Tim Boudreaux Changed numbering format. 12/17/04 1.2.1 Tim Boudreaux Changed numbering format. 12/17/04 1.2.2 Tim Boudreaux Included this paragraph on Navigable River Inspections. 12/17/04 2.1 – 2.1.4.3 Tim Boudreaux Deleted most of this section because it is listed in the procedural document. Revised the Program Element to include 2.1 Shallow and Exposed Pipe, 2.2 Earth Movement and 2.3 Navigable River Inspections. 12/17/04 3.0 Tim Boudreaux Eliminated DOC Prioritization Guidelines since these are listed in the DOC Procedures and DOC Guidelines. Modified the Data Management section and renumbered. 12/17/04 5.0 Tim Boudreaux Modified References to include only related links within this document. Other links may be found within the Procedures and other documents. 12/17/04 6.0 Tim Boudreaux Eliminated Forms and Attachments that may be found in other more pertinent documents. 11/30/04 2.2 Rick Wooldridge Added Earth Movement and its supporting discussions 01/01/06 Intro Tim Boudreaux Added Applicability Statement 01/01/06 2.4 Clyde Clausen Added Overhead Pipeline Crossing Section 01/01/06 References Renamed links 01/01/06 Applicability Renamed scope and changed location in doc 01/01/07 Reviewed, no changes 01/01/08 Reviewed, no changes 10/27/08 1.1.1 Tim Boudreaux Included continued monitoring statement. 10/27/08 1.1.3 Tim Boudreaux Modification to Longhorn link and reference to Tier levels. 12/8/08 2.3 Tim Boudreaux Modified Consent Decree Specific statement. 01/01/2009 Tim Boudreaux Annual Review with no changes. 9/01/09 1.1.3 Tim Boudreaux Deleted Longhorn 9/01/09 2.2 Tim Boudreaux Deleted Longhorn 9/01/09 3.1.1 Tim Boudreaux Included IMP Section 6 review language 9/01/09 5.6 Tim Boudreaux Added Assets covered per 9/01/09 Tim Boudreaux Annual Review with changes listed above 3/1/10 3.1.1 Tim Boudreaux Replaced “Guidelines” with “Procedure” 3/1/10 5.2 Tim Boudreaux Removed Depth of Cover Guidelines 9/1/10 Tim Boudreaux Annual Review with no changes 12/31/11 All 2012 Annual Review complete – no changes <<>> Magellan Midstream Partners, L.P. ENCROACHMENT PROCEDURE 7.05–ADM‐012 Asset Integrity 01/01/10 Revision: 4 Page 1 of 4 1.0 PURPOSE 1.1 The purpose of this procedure is to insure safety to the surrounding public, to protect the environment from accidental product releases and to protect the usefulness and value of rights of way owned or operated by Magellan Midstream Partners, L.P. or its affiliated companies (hereinafter, “Company”). 2.0 SCOPE 2.1 The provisions of this document outline procedures to be followed by any person or entity when planning construction or other activities that could affect rights of, or assets owned or operated by Company, on or near easements or rights of way owned or operated by the Company. The use of the words “shall” or “will” when referring to actions or procedures specified in this document are to be interpreted as the Company’s preferred method of operation, but are not to be construed as absolutes which would not allow for exceptions to the preferred method of operation in particular situations with proper approval and documentation of the reasons for such exceptions. 2.2 This procedure is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be utilized in whole or part on non‐jurisdictional assets as deemed appropriate. 2.3 Assets covered per Mitigation Plan: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, this pipeline operates under the requirements of the Mitigation Plan. 2.4 Consent Decree Specific: In addition to applicable Federal, State, and Local regulations, as well as the Company guidelines, process, or best practices, the Company’s Consent Decree Pipeline Systems operate under the requirements of the Consent Decree. For the period of the Consent Decree, these systems will follow the applicable process and procedures (see Consent Decree for applicable programs). 3.0 PROCEDURES 3.1 All Employees shall: 3.1.1 If the notification of an encroachment originates from the One Call Center or was discovered by Field Personnel, immediately forward the encroachment details to the appropriate Asset Locator. 3.1.2 If the notification of an encroachment did not originate from the One Call Center or was not discovered by Field Personnel, immediately forward the encroachment details to the appropriate Real Estate Representative. 3.1.3 Any Employee who observes or learns of a land use change which may impact any Company Easement Tract shall report such change to the Company Real Estate Representative and Company Asset Integrity Risk Engineer for the area where the land is located and provide them the information on the land use change. 3.1.4 On each occasion where an Employee meets with a landowner or tenant, the Employee shall request the landowner or tenant notify the Company at any and every time when the land use will be changed for land on or adjacent to a Company Easement Tract. <<>> Magellan Midstream Partners, L.P. ENCROACHMENT PROCEDURE 7.05–ADM‐012 Asset Integrity 01/01/10 Revision: 4 Page 2 of 4 3.2 All Asset Locator Personnel shall: 3.2.1 3.2.2 Check the depth of cover over its pipeline(s) and for any other potential impacts to Company pipelines and facilities. Evaluate the type of encroachment activity and determine if the Encroachment Agreement (Short Form) is applicable. Encroachment Agreement (Short Form) is to be used only for the following type encroachments that adhere to the General Encroachment Requirements: 3.2.3 3.2.4 3.2.2.1 Unpaved Residential Driveway 3.2.2.2 Temporary Equipment Crossing 3.2.2.3 Gas Line 3.2.2.4 Water Line 3.2.2.5 Telephone Cable 3.2.2.6 Sprinkler System 3.2.2.7 Fence 3.2.2.8 Fiber Optic Cable 3.2.2.9 Drain Tile 3.2.2.10 Television Cable 3.2.2.11 Electric Line 3.2.2.12 Other Pipeline 3.2.2.13 Other low impact encroachments (after receiving approval from the Real Estate Representative and Risk Engineer) If applicable complete and execute the Encroachment Agreement (Short Form) and forward to the Records Coordinator. If the Encroachment Agreement (Short Form) is not applicable, Field Personnel shall 3.2.5 send the encroachment notification to the Real Estate Representative. Monitor and inspect the encroachment activity to insure the General Encroachment Requirements are met. 3.3 The Real Estate Representative shall: 3.3.1 Upon discovery or notification of an encroachment employ the Encroachment Process Map. 3.3.2 3.3.3 3.3.4 Evaluate the type of encroachment activity, gather all available information regarding the type of encroachment, and send the information to the Asset Locator if the encroachment meets the Encroachment Agreement (Short Form) requirements, or to the Risk Engineer for an Impact Review if the Encroachment Agreement (Long Form) is appropriate. After receiving the Impact Review from the Risk Engineer notify the encroaching party of the impact to Company facilities. Prepare, negotiate and execute the Encroachment Agreement (Long Form) and any <<>> Magellan Midstream Partners, L.P. ENCROACHMENT PROCEDURE 7.05–ADM‐012 Asset Integrity 01/01/10 Revision: 4 Page 3 of 4 3.3.5 3.3.6 other applicable agreements. Send a copy of Encroachment Agreement (Long Form) to the Asset Locator and to the Records Coordinator. Send fully executed and recorded original Encroachment Agreement (Long Form) and other applicable agreements to the Real Estate Right of Way Tract File for permanent retention. NOTE: The Real Estate Representative will use 1 of the 3 preapproved Encroachment Agreement (Long Form) documents after evaluating the type of encroachment. 3.4 The Risk Engineer shall: 3.4.1 3.4.2 3.4.3 3.4.4 Upon receiving the encroachment information from the Real Estate Representative, evaluate the integrity risks to any Company facility, conduct an engineering assessment, prepare an Impact Review and forward to the Real Estate Representative. Execute any required pipeline adjustment or relocation made necessary by the proposed encroachment in accordance with SIP 4.01 Project Management. Longhorn personnel will manage and execute all major adjustments or relocations on the Longhorn System. Manage the financial and reimbursement duties for any pipeline adjustment or relocation. Send project documentation to the Records Coordinator. 3.5 The Records Coordinator shall: 3.5.1 Review project documentation and ensure that all Company maps, drawings and records are updated. <<>> Magellan Midstream Partners, L.P. ENCROACHMENT PROCEDURE 7.05–ADM‐012 Asset Integrity 01/01/10 Revision: 4 Page 4 of 4 System Integrity Plan Change Log Date Change Location Change BY Brief Description of Change 12/22/04 Clyde Clausen Created Internal Encroachment Document. Made numerous changes and re‐formatted the entire document. 12/22/04 4.5.7 Clyde Clausen Added Directional Drill Requirements 12/22/04 Clyde Clausen Inserted Change Log into document 01/01/05 Reviewed, no changes 01/01/06 Clyde Clausen Incorporated Shell and Longhorn specific requirements throughout document 01/01/06 Changed Magellan to “Company” 01/01/07 Bill Klein Removed redundant information that was already contained in the General Encroachment Requirements. Listed specific employee roles and responsibilities. Re‐ formatted the entire document. 01/01/08 Reviewed, no changes 01/01/09 2.4 Bill Klein 01/01/10 2.3 Changed Longhorn to Mitigation 01/01/11 Reviewed, no changes 12/31/11 All 2012 Annual Review complete – no changes <<>> Magellan Midstream Partners, L.P. NAVIGABLE RIVER CROSSING INSPECTIONS PROCEDURE 7.05–ADM–014 Asset Integrity 01/01/12 Revision: 6 Page 1 of 5 1.0 OBJECTIVE 1.1 To establish standardized and consistent processes for pipeline operations and maintenance in regards to Navigable River Crossing Inspections. 2.0 SCOPE 2.1 2.2 2.3 This procedure is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be utilized in whole or part on nonjurisdictional assets as deemed appropriate. Assets covered per Mitigation Plan: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices. This pipeline operates under the requirements of the Mitigation Plan. Consent Decree Specific: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, the Company’s Consent Decree Pipeline Systems operate under the requirements of the Consent Decree (see Consent Decree for applicable programs). 3.0 PURPOSE 3.1 Navigable River Crossings 3.1.1 3.1.2 3.1.3 3.1.4 3.1.5 3.1.6 The Pipeline Integrity Coordinator shall annually review the list of pipeline crossings of navigable rivers contained in this procedure to ensure the crossings are inspected within the required timeframe. Pipeline Integrity shall be responsible for having these inspections made and for maintaining the records of such inspections. The inspection records shall be maintained for five years or until another inspection is performed. The results of such inspections will be compared with the previous crossing records to determine any change. Should the inspection indicate that repairs need to be made to the crossing, Pipeline Integrity shall be responsible for having suitable repairs performed. Each pipeline crossing under a DOT identified navigable waterway will be inspected at intervals not exceeding five years. For this inspection, navigable waterways are defined as waterways subject to commercial barge traffic. The inspection shall be conducted by third party personnel qualified to carry out such inspections and to prepare permanent records of their findings. The inspections shall determine the pipeline location and any exposed pipe within the limits of the navigable waterway and the right‐of‐way immediately adjacent on each side. The permanent records shall be of sufficient detail to compare with the previous crossing records to determine any change in the location of the pipeline. They shall also indicate if any, the length and location of exposed pipeline. The third party inspector will prepare both plan and profile drawings detailing the findings of the inspection. 4.0 PROCEDURE 4.1 Navigable River Crossing Inspections <<>> Magellan Midstream Partners, L.P. NAVIGABLE RIVER CROSSING INSPECTIONS PROCEDURE 7.05–ADM–014 Asset Integrity 01/01/12 Revision: 6 Page 2 of 5 4.2 4.3 4.1.1 Contractor will reestablish base line indicated on plan drawing and accurately determine route of the pipeline through the river with reference to this line. The length of this traverse will extend between convenient points on the banks. These points will be above water level and at least 50 feet from the edge of the water. 4.1.2 Location of pipe will be determined by the use of an induced tone or transmitter/receiver pipe locator. 4.1.3 The river bottom and banks between reference points will be profiled over the pipe with elevations referenced to the existing bench mark shown on drawing. If existing benchmark has been destroyed, Contractor will set a new bench mark in as permanent a manner as possible. 4.1.3.1 Profile data will also include elevation of water level and top of pipe at all exposed and suspended sections. Vertical measurements for profile may be made by use of a portable Fathometer or weighted sounding chain. On pipeline inspections where sufficient cover cannot be determined from the profile, a diver is required to complete the inspection. 4.1.4 A diver will make passes over each pipe at intervals of 20 feet or less and if exposed or suspended pipe is located, the diver will follow these sections with continuous passes. He will also determine size and location of any build‐up of debris against exposed or suspended pipe section, the condition of pipe and/or pipe coating, the nature of the river bottom at the pipe, and any other underwater condition that may appear to adversely affect the safety of the pipeline crossing such as scouring of the river bottom or undercutting of the banks. Sonar equipment may be used to detect exposed pipe instead of a diver. Forward results of this survey and the inspection individual written reports for each crossing site. Submit reports to the Pipeline Integrity Project Manager and include, at least the following: 4.2.1 A list of all exposed and suspended pipe sections located by station numbers and showing clearance between pipe and river bottom. 4.2.2 Identification of changes from last inspection. 4.2.3 Recommendations for repair. Contractor will supply plan and profile sheets of each pipeline surveyed at the crossing site. One plan and profile sheet will be used for each single pipeline crossing the stream. 4.3.1 Show dual lines. Include the river bottom and adjacent banks between reference points in the drawings. 4.3.2 Show the condition of the pipe coating, all obstructions and sharp objects, all unusual conditions, such as exposed or suspended pipe, and the location and elevation of benchmarks used by Contractor in the drawings. The profile drawing of the pipeline will extend to a minimum of fifty (50) feet beyond the edge of the water on each side of the river. 4.3.3 Show pipe, river bottom and water elevations from previous inspections (when known) on the drawings. 4.3.4 Retain the inspection records that relate to the navigable river inspections for five years or until a new inspection is performed. <<>> Magellan Midstream Partners, L.P. NAVIGABLE RIVER CROSSING INSPECTIONS PROCEDURE 7.05–ADM–014 Asset Integrity 01/01/12 Revision: 6 Page 3 of 5 4.4 The following crossings are listed as being across navigable waters: Navigable River Crossings State Line Section Waterway #Of Spare Lines Eng. Station Date Last Inspection Date Next Inspection Delaware Wilmington 10” Pipeline Christina River 0 66+18 06/11/10 06/11/15 Illinois 106#3‐12" TCS IL‐Wilmington Illinois River 0 26507+04 08/12/08 08/12/13 036 #5‐8" Des Moines‐ MS River Mississippi River 0 9026+14 05/14/07 05/14/12 037 #6‐12" Des Moines‐ MS River Mississippi River 0 9028+96 05/14/07 05/14/12 Iowa 054 #5‐12 Irv ‐ Sioux Falls Missouri River 1 12520+79 08/17/11 08/17/16 Nebraska/ Iowa West Leg NH3 Missouri River 0 14272+87 08/18/11 08/18/16 Kansas 006 #3‐8" Barnsdall ‐ KC Kansas River 0 10171+48 08/08/08 08/08/13 007 #4‐12 Barnsdall ‐ KC Kansas River 0 10178+52 08/08/08 08/08/13 008 #5‐12" Barnsdall ‐ KC Kansas River 0 10187+55 08/08/08 08/08/13 023 #4‐8" Argentine ‐ KC Kansas River 0 164+00 08/08/08 08/08/13 Kansas/ Missouri 18th Street to Riverside 8” Missouri River 0 10370+33 09/01/11 09/01/16 Louisiana GeoNet Bayou Black 1 08/19/08 08/19/13 Minnesota 069 #7‐8" Rose ‐ Mpls. Air Minnesota River 0 661+44 05/15/07 05/15/12 070 #6‐12" Rosemount ‐ Willmar Minnesota River 0 760+59 05/15/07 05/15/12 121#3‐8" StPP (Aranco) ‐ Pine Bend Mississippi River 0 113+45 05/16/07 05/16/12 007 #4‐12” Des Moines to Minneapolis Mississippi River 1 12740+77 05/16/07 05/16/12 <<>> Magellan Midstream Partners, L.P. NAVIGABLE RIVER CROSSING INSPECTIONS PROCEDURE 7.05–ADM–014 Asset Integrity 01/01/12 Revision: 6 Page 4 of 5 Navigable River Crossings State Line Section Waterway #Of Spare Lines Eng. Station Date Last Inspection 059 #1‐6" Alex ‐ Grand Forks Red River of The North 0 5222+47 05/18/07 060 #2‐8" Alex ‐ Fargo Red River of The North 0 5217+64 05/18/07 Missouri 080 #7‐8” Olathe to Columbia Missouri River 0 6714+85 08/22/11 095 #7‐16" Wathena ‐ Des Moines Missouri River 0 9775+35 08/23/11 105 #3‐12 ' TCS MO ‐ IL Line Mississippi River 1 24398+70 08/10/08 Oklahoma 013 #1‐12” Tulsa‐Barnsdall Arkansas 0 48+35 09/21/10 012 #4‐12” Tulsa‐Barnsdall Arkansas 0 48+24 09/21/10 108 #4‐12” Tulsa‐Tulsa Jct. Arkansas 1 48+24 09/21/10 Oklahoma Verdigris Lateral 6” NH3 Verdigris River 0 6426+05 03/04/09 Texas Amerada Hess Houston Ship Channel 3 151+00 03/31/09 Texas City to Pasadena 18” Clear Lake 0 729+00 04/25/09 Wisconsin 047 #1‐8" Newport ‐ Bateman St. Croix River 0 620+13 05/17/07 Date Next Inspection 05/18/12 05/18/12 08/22/16 08/23/16 08/10/13 09/21/15 09/21/15 09/21/15 03/04/14 03/31/14 04/25/14 05/17/12 <<>> Magellan Midstream Partners, L.P. NAVIGABLE RIVER CROSSING INSPECTIONS PROCEDURE 7.05–ADM–014 Asset Integrity 01/01/12 Revision: 6 Page 5 of 5 System Integrity Plan Change Log Date Change Location Change By Brief Description of Change 12/22/04 New Procedure Tim Boudreaux Removed Navigable River Crossing section from Pipeline Maintenance Document and created new Procedure for Navigable River Crossings. 12/22/04 3.1.2 Tim Boudreaux Included text “On pipeline inspections where sufficient cover cannot be determined from the profile, a diver is required to complete the inspection. 12/15/05 3.4 Tim Boudreaux Included inspection dates on Amerada Hess pipelines and included new asset inspection for Wilmington 10” pipeline. 12/15/05 Intro Tim Boudreaux Included Applicability Statement. 1/1/07 List Tim Boudreaux Updated list for 2006 completed inspections. 01/01/08 Reviewed, no changes 12/18/08 2.3 Tim Boudreaux Modified Consent Decree Specific. 12/18/08 4.4 Tim Boudreaux Updated List of navigable inspections. 01/01/09 Tim Boudreaux Annual Review with no changes. 9/01/09 2.2 Tim Boudreaux Deleted Longhorn 9/01/09 4.4 Tim Boudreaux Updated list of navigable inspections 9/01/09 5.1 Tim Boudreaux Deleted Longhorn 9/01/09 Tim Boudreaux Annual Review with changes listed above 01/01/11 Reviewed, no changes 09/02/11 3.1.1 Dennis Vasicek Added sentence regarding Pipeline Integrity Coordinator’s annual review of list of navigable river crossings 09/02/11 4.4 Dennis Vasicek Added 18th Street to Riverside 8” crossing of the Missouri River and Texas City to Pasadena 18” crossing of Clear Lake 09/02/11 4.4 Dennis Vasicek Updated inspection dates 12/31/11 All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. EARTH MOVEMENT INSPECTION PROCEDURE 7.05–ADM–020 Asset Integrity 01/01/10 Revision: 3 Page 1 of 3 1.0 PURPOSE 1.1 The purpose of this procedure is to establish a standardized method for the investigation and monitoring of areas of the pipeline identified as having high susceptibility to earth movement or where earth movement has been identified. E: Characterizing an area, as having high susceptibility to earth movement does not imply certainty that earth movement will occur or that earth movement is not possible outside an area of high susceptibility. 2.0 SCOPE 2.1 2.2 2.3 This procedure is applicable to federal and/or state jurisdictional pipelines and/or facilities. Elements of this program may be utilized in whole or part on nonjurisdictional assets as deemed appropriate. Assets covered per Mitigation Plan: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, This pipeline operates under the requirements of the Mitigation Plan. Consent Decree Specific: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, the Company’s Consent Decree Pipeline Systems operate under the requirements of the Consent Decree (see Consent Decree for applicable programs. 3.0 PROCEDURE 3.1 Identifying Areas for Inspection. Specific pipeline segments may have regulatory requirements outside DOT 49 CFR. Please refer to those specific Plans for their individual requirements, as listed above in Applicability. 3.1.1 Identify areas to be inspected as defined by the Earth Movement Section of the Depth of Cover Program. 3.2 below. 3.2.1 Select the appropriate inspection method using the guidelines established in 3.2.1 and 3.2.2 3.3 3.4 3.5 Use aerial patrol for inspection and monitoring of areas with high susceptibility to earth movement. If aerial patrol is the selected inspection method go to 3.3 below. 3.2.2 Use close visual inspection in areas where earth movement has been identified. If close visual inspection is the selected inspection method go to 3.4 below. Performing Inspection and Monitoring Utilizing Aerial Patrol 3.3.1 Conduct aerial patrol in accordance with the Inspection of Right‐of‐Way Procedure. Pay particular attention, within the target area, to signs or indicators of earth movement or subsidence such as ground cracks, sink holes, erosion, heaving, buckling, etc. 3.4.1 If earth movement is identified go to 3.5 below otherwise go to 3.6 below. Performing Inspection and Monitoring Utilizing Close Visual Inspection <<>> Magellan Midstream Partners, L.P. EARTH MOVEMENT INSPECTION PROCEDURE 7.05–ADM–020 Asset Integrity 01/01/10 Revision: 3 Page 2 of 3 3.5.1 Conduct close visual inspection in accordance with the Inspection of Right‐Of‐Way Procedure. 3.5.2 Document the nature of the earth movement specifying the type of movement, extent of the affected area (length, width, depth), age, characteristics, soil type, etc. using both a written description and photography (where possible). NOTE: Notify the appropriate Asset Integrity Engineer as soon as practical to discuss additional data requests and the next course of action. 3.6 Documentation 3.6.1 Use the Pipeline Maintenance Report to document any findings, with copies sent to the Asset Integrity Engineer for continued evaluation. 4.0 DEFINITIONS 4.1 4.2 Earth Movement: Unintended movement of the soil around the pipeline. High Susceptibility (to earth movement): An area along the pipeline identified through risk assessment as having a higher likelihood of earth movement as compared to other relative locations. <<>> Magellan Midstream Partners, L.P. EARTH MOVEMENT INSPECTION PROCEDURE 7.05–ADM–020 Asset Integrity 01/01/10 Revision: 3 Page 3 of 3 System Integrity Plan Change Log Date CHANGE LOCATION Changed By Brief Description of Change 1/4/03 New Rick Wooldridge New Procedure 01/01/06 Applicability Tim Boudreaux Included language to direct to Longhorn and Shell specific requirements. 01/01/06 2.1.1 Tim Boudreaux Included: “Specific pipeline segments may have regulatory requirements outside DOT 49 CFR Parts 195 or Parts 192. Please refer to those specific Plans for their individual requirements, as listed above in Applicability”. Applicability 2.0 Changed to Scope 01/01/07 Reviewed, no changes 01/01/08 Reviewed, no changes 12/18/08 2.3 Tim Boudreaux Modified Consent Decree Specific. 01/01/09 Tim Boudreaux Annual Review with no changes. 9/03/09 2.2 Tim Boudreaux Removed Longhorn and Replaced with Assets covered per Mitigation Plan 9/03/09 4.3 Tim Boudreaux Removed Longhorn and Replaced with Assets covered per Mitigation Plan 9/03/09 Tim Boudreaux Annual Review with changes listed above 01/01/11 Reviewed, no changes 12/31/11 All 2012 Annual Review complete – no changes <<>> Magellan Midstream Partners, L.P. OVERHEAD PIPELINE CROSSING INTEGRITY PROCEDURE 7.05–ADM–030 Asset Integrity 01/01/12 Revision: 3 Page 1 of 6 1.0 PURPOSE 1.1 The purpose of this procedure is to effectively manage Overhead Pipeline Crossing maintenance through a comprehensive risk-based program which identifies risk reduction projects to improve structural component integrity and ultimately keep the product in the pipe. 2.0 SCOPE 2.1 2.2 2.3 Consent Decree Specific: : In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, the Company’s Consent Decree Pipeline Systems operate under the requirements of the Consent Decree. For the period of the Consent Decree, these systems will follow the applicable process and procedures (see Consent Decree for applicable programs). 3.0 PROCEDURE 3.1 This procedure is applicable to federal and/or state jurisdictional pipelines and/or facilities. The Manager of Asset Integrity may utilize elements of this program in whole or part on nonjurisdictional assets as deemed appropriate. Assets covered per Mitigation Plan: In addition to applicable Federal, State, and Local regulations, as well as Company guidelines, process, or best practices, this pipeline operates under the requirements of the Mitigation Plan. The Overhead Pipeline Crossing Integrity Program will cover all above ground pipeline crossings, which are cable supported. This Inspection Procedure is structured in a cycle of four recurring categories: 3.1.1 Gather Data 3.1.1.1 3.1.1.2 Select the initial inspections based on historical knowledge of the condition of the structures using stakeholder, SME, risk data, and process efficiency information. Select subsequent inspections using risk data and further historical knowledge of the structures. The baseline inspections should be completed within six years and re‐inspections will be conducted on a timeframe based on the inspection findings and recommendations but not to exceed ten years from the previous inspection. Use the following three project‐specific standard forms for the overhead pipeline structure inspections. 3.1.1.2.1 Use the Basic Data Form to list all the relevant historical and geometrical information about the structure. Prior to the initial inspection, locate any available information on the structures so that as much information as possible may be filled out on the Basic Data Form. During the field inspection, this information should then be checked and the remainder of the information gathered. 3.1.1.2.2 Use the Inspection Report Form during the field inspection to evaluate and record the existing conditions of the components on the overhead pipeline structure. Each component listed is preceded by a box to be used for a rating number to evaluate the condition of the component and followed by a line to be used for a verbal description of any <<>> Magellan Midstream Partners, L.P. OVERHEAD PIPELINE CROSSING INTEGRITY PROCEDURE 7.05–ADM–030 Asset Integrity 01/01/12 Revision: 3 Page 2 of 6 3.1.1.3 3.1.1.4 problems encountered. 3.1.1.2.3 The Photo Log Sheet is used in the field to document photographs taken of the different overhead pipeline structures inspected. The development of a systematic method of inspection for each type of overhead pipeline structure is important. A well‐planned sequence will provide a working guide for the inspector and will ensure a systematic and thorough inspection of all components of the structure. For the overhead pipeline structure, the components of the structure should be inspected in the following order: 3.1.1.4.1 Foundations 3.1.1.4.2 Base plates and connections to foundations 3.1.1.4.3 Cable anchorage 3.1.1.4.4 Tower frames 3.1.1.4.5 Saddles 3.1.1.4.6 Main cable 3.1.1.4.7 Suspender cables 3.1.1.4.8 Pipe supports 3.1.1.4.9 Pipeline NOTE: There are other considerations observed during the inspection, which will be documented, such as: bank degradation, obvious flood levels, threatening outside forces (trees or other structures), right‐of‐way visibility/marking, public access and vandalism. 3.1.1.5 3.1.1.6 The thoroughness of an inspection is as important as the sequence. Use a checklist during the inspection to prevent the possibility of any components being overlooked. The Inspection Form can be used as a basic outline for the checklist. Complete full documentation reports for each inspection using the Overhead Inspection Basic Data Form, the Overhead Inspection Report Form and the Overhead Inspection Photo Log Sheet. Pipeline Integrity shall maintain these records for further analysis. 3.1.2 Analyze the Data 3.1.2.1 List all findings on the Inspection Report Form. Use the numerical rating system (see Table 1 below) to evaluate the condition of the components. The number best describing the component in the worst condition should be placed in the box next to the name of the component. Include a written description for clarification or further explanation. From this information the SME will make recommendations for maintenance repairs, completion time limits for making those repairs and a general cost estimate based on <<>> Magellan Midstream Partners, L.P. OVERHEAD PIPELINE CROSSING INTEGRITY PROCEDURE 7.05–ADM–030 Asset Integrity 01/01/12 Revision: 3 Page 3 of 6 “Rule of Thumb” estimates. Table 1 Rating Number Rating Description Rating Examples 6 Good Condition 5 Potential Problem 4 Minor Problem 3 Major Problem 2 Critical Problem There are no apparent problems Rust, corrosion or cracked foundation Loose bolts, cables, or spalled foundation Moderate structural cracking or repainting Major structural defects 3.1.2.2 Analyze the individual component ratings further and give weighted scores to achieve an overall Relative Risk Index. This will assist in our maintenance prioritization efforts. 3.1.2.3 Asset Integrity Personnel shall review, approve/reject or submit alternative recommendations. Repair recommendations will be risk ranked in accordance to criteria set forth in the Overhead Crossing Inspection Relative Risk Index Formula. 3.1.2.4 The DOC Coordinator will schedule the maintenance according to these recommendations and list them on the Annual Integrity Plan. 3.1.3 Develop The Mitigation Plan 3.1.3.1 The DOC Coordinator will assign a Project Manager to complete the maintenance work. The Project Manager will follow Project Life Cycle for completing the task. 3.1.3.2 The Project Manager shall follow the recommended maintenance schedule according to the annual integrity plan for repairs unless otherwise approved to proceed with any additional repairs, which would improve the integrity of the structure at a significant cost savings. 3.1.3.3 The Project Manager shall be responsible for all planning, estimating, contracting and execution of the maintenance repairs. 3.1.3.4 An AFE and Project Plan must be submitted and approved by the DOC Coordinator before any work may begin, unless the work needed is considered an emergency and immediate attention is necessary, in which a courtesy call to the DOC Coordinator is all that is required. The afe request and documentation of the work performed may follow the repair, in this case. During the plan development, consult with Area Operations, Asset Integrity Personnel and third party SME Resources. 3.1.4 Execute the Mitigation Plan 3.1.4.1 Following the approval of the project plan, the Project Manager may allocate resources and execute the Mitigation Plan while integrating in synergies with other MMP departments and programs. 4.0 OVERHEAD PIPELINE CROSSING PRIORITIZATION GUIDELINES <<>> Magellan Midstream Partners, L.P. OVERHEAD PIPELINE CROSSING INTEGRITY PROCEDURE 7.05–ADM–030 Asset Integrity 01/01/12 Revision: 3 Page 4 of 6 4.1.1.2 4.1 The Overhead Pipeline Crossing Integrity Program, along with any resulting mitigation initiatives, will be prioritized in accordance with the following guidelines: 4.1.1 Each structure will receive an initial risk prioritization number based on the Pipeline Risk Model. Factors that may influence the prioritization might be local historical knowledge of inferior structural conditions, past large water flow events, line strikes, near misses and HCA locations. 4.1.1.1 The first phase of the inspections will include the top 20% of the structures listed as highest risk according to the pipeline risk model. All other structures will follow in 20% groupings according to the risk model. 4.2 Following the Overhead Pipeline inspection, each structure will receive a relative risk index number. Maintenance will be performed on the structures that receive the lowest relative risk index score in accordance with the Integrity Management Plan (IMP). 5.0 DATA MANAGEMENT AND INITIATIVE IMPLEMENTATION 5.1 Data initially obtained and periodically updated via the Overhead Pipeline Crossing Integrity Program will be centralized and maintained in a formal database. Pipeline Integrity will utilize the database as an input to its overall risk management process, which includes the relative risk assessment process. 5.2 Pipeline Integrity will further manage the recommendation and funding process associated with the implementation of this initiative. 6.0 REFERENCES 6.1 Regulatory – 49 CFR Part 195 – U.S. D.O.T. Pipeline Safety Regulations 6.2 Related Policies/Procedures 6.2.1 Pipeline Defect Evaluation and Repair Procedure 6.2.2 RSTRENG Analysis of Corrosion 6.2.3 6.2.4 Asbestos Safety Procedure 6.2.5 Excavation Safety Procedure 6.2.6 Welding and Radiographic Procedures 6.2.7 Specification 100—Construction And Fabrication Of Pipelines And Related Piping Systems 6.2.8 6.3 Forms and Attachments 6.3.1 Pipeline Maintenance Report 6.3.2 6.3.3 6.3.4 Coatings – Selection, Applications and Maintenance Specification 101—Maintenance Welding (Excluding Ethylene Pipelines) Prioritization for Exposed Pipe (Flow Chart) Prioritization for Shallow Pipe (Flow Chart) Shallow Pipe Resolution Process (Flow Chart) <<>> Magellan Midstream Partners, L.P. OVERHEAD PIPELINE CROSSING INTEGRITY PROCEDURE 7.05–ADM–030 Asset Integrity 01/01/12 Revision: 3 Page 5 of 6 7.0 DEFINITIONS 7.1 Stakeholder: Any person or group directly involved with this initiative. 7.2 SME: Subject Matter Expert. 7.3 7.4 7.5 7.6 7.7 7.8 7.9 Risk Data: Furnished by the Risk Assessment Group for specific pipeline segments. Process Efficiencies: Planning optimization of time, materials, labor and funding. Basic Data Form: A standard form to list the relevant historical and geometrical information about the structure. Inspection Report Form: A standard form used during the field inspection to evaluate and record the existing conditions of the components. Photo Log Sheet: A standard form for documenting and organizing photos taken at the inspection site. Rule of Thumb Estimates: Standard costs associated to specific work in the pipeline industry, as an average. It is not region specific. Relative Risk Index Formula: Process by which all component ratings are correlated to give a final overall Risk Score to assist with process management. <<>> Magellan Midstream Partners, L.P. OVERHEAD PIPELINE CROSSING INTEGRITY PROCEDURE 7.05–ADM–030 Asset Integrity 01/01/12 Revision: 3 Page 6 of 6 System Integrity Plan Change Log Date Change Location Change By Brief Description of Change 1/31/05 All Tim Boudreaux New Procedure 01/01/07 Reviewed, no changes 01/01/08 Reviewed, no changes 12/17/08 2.1 Tim Boudreaux Eliminated redundant sentence. 12/17/08 2.2 Tim Boudreaux Modified Consent Decree Specific. 12/17/08 5.1, 5.2 and 5.3 Tim Boudreaux Removed link for Data record sheet, inspection report and photo log sheet. 01/01/09 Tim Boudreaux Annual Review with no changes made. 9/03/09 2.2 Tim Boudreaux Deleted Longhorn and changed to Assets covered per Mitigation Plan 9/03/09 Tim Boudreaux Annual Review with changes listed above 01/01/11 Reviewed, no changes 09/02/11 3.1.1.1 Dennis Vasicek Revised third sentence to, “The baseline inspections should be completed within six years and re‐inspections will be conducted on a timeframe based on the inspection findings and recommendations but not to exceed ten years from the previous inspection.” 12/31/11 All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. ASSETS COVERED PER MITIGATION PLAN RIGHT‐OF‐WAY INSPECTION PROCEDURE 7.05–ADM–031 Asset Integrity 01/01/12 Revision: 10 Page 1 of 5 1.0 PURPOSE 1.1 The purpose of this procedure is to address specific requirements of the Mitigation Plan related to inspection of the surface conditions on or adjacent to each pipeline right‐of‐way (ROW). This document is to be utilized along with the Magellan Midstream Partners, L.P. Inspection of Right of Way Procedure. 2.0 PROCEDURE NOTE: Persons performing inspection shall comply with all state and federal laws, rules, regulations, statutes, ordinances or codes and Mitigation Commitments as may be required. In its contracts with inspection contractors, the Company shall identify requirements specifically related to the petroleum industry. It shall be the obligation of such contractors to comply and maintain appropriate records 2.1 Methods of Inspection 2.1.1 Aerial Patrol: As described below and in Inspection of Right of Way Procedure. 2.1.2 Ground Patrol: As described below and in Inspection of Right of Way Procedure. Also Refer to the guidelines in the Threatened and Endangered Species Avoidance And Minimization Timing Restrictions. 2.2 Patrol Requirements 2.2.1.4 Edwards Aquifer Recharge Zone – Daily (once per week shall be a ground‐level patrol) 2.3 2.2.1 The specified frequency of surveillance shall meet the following requirements: 2.2.1.1 Tier 1 Areas – Once a week, not to exceed 12 days, but at least 52 times per year 2.2.1.2 Tiers 2 and 3 Areas – Every two and one‐half (2.5) days, not to exceed 72 hours 2.2.1.3 Aerial and ground surveillance frequency will be increased across Tier II (Sensitive) and Tier III (Hypersensitive) areas when the threat of flooding and/or severe erosion is identified near the pipeline right‐of‐way. Aerial Patrol and Ground Patrol Notification 2.3.1 Patrol Pilots will be required to contact the Austin Operations Office each morning to communicate the ability to fly or not to fly, “No‐Fly”, their identified patrol segments. Segments are identified as follows: 2.3.1.1 LP 301 Galena Park to Pecos River (MP 0 – MP 528) 2.3.1.2 LP 303 Crane to El Paso (MP 457 – MP 695), Crane to Odessa (MP 0 – MP 28) and El Paso to El Paso Jct. (MP 0 – 10) 2.3.1.3 Austin Operation Office will record notification of flight and await completed Right‐ of‐Way Patrol Report by Aerial/Ground form. 2.3.1.4 The Austin FOA will record each patrol on a patrol tracking spreadsheet to insure the required number of flights are made and file with monthly reports. 2.3.1.5 Upon receipt of the Right‐of‐Way Patrol Report by Aerial/Ground form. The One Call Group will create a One Call ticket and the field locator will respond to the Aerial Patrol in Ticket View. 2.3.1.6 Right‐of‐Way (ROW) Inspection Report will be sent to Austin Operations Office and the One Call Group at the end of the flight day or within 12 hours of flight <<>> Magellan Midstream Partners, L.P. ASSETS COVERED PER MITIGATION PLAN RIGHT‐OF‐WAY INSPECTION PROCEDURE 7.05–ADM–031 Asset Integrity 01/01/12 Revision: 10 Page 2 of 5 2.3.1.7 completion. All emergency sightings by pilot will be called into the Company One‐Call Center. The Company One‐Call Center will send to the field as an emergency ticket under the heading A/P (Aerial Patrol). All A/P emergency tickets will be responded to immediately by field personnel. Non‐emergency sightings will be reported on Right‐ of‐Way Patrol Report by Aerial/Ground form and responded to within 3 working days and documented by the appropriate personnel upon receipt of the report. NOTE: Daily patrols of these segments shall continue until confirmation of flight by the Patrol Pilot has been received. 2.3.2 2.3.3 Each and every morning, the person on call will contact the Austin Area Office message center by calling 1‐ 512‐394‐4099, enter mail box number of 4044, and the password of 404400 and verify the pilots ability to patrol there segment. If a no fly is reported an alert will be issued to personnel to be prepared for ground patrol procedures. First Level Each area COM will maintain a list of personnel designated to patrol a section of the Tier 2 and 3 segments in their area and provide that person with the required maps and other information that will describe in detail the patrol section On the morning of the second day of notification of “No‐Fly” from the patrol pilot, personnel will be instructed to proceed with Second Level Procedures. Second Level Procedure – Tier 2 and 3 segments shall be initiated. The required notification will be made to the ground patrol personnel and unless notified other wise will begin patrol of the assigned area the next morning. All sightings that can not be dealt with at the time will be called to One Call. Second Level segments need to be completed within one and one‐ half (1.5) days of the second day notification and sightings will be recorded on Right‐of‐Way Patrol Report By Aerial/Ground form. 2.3.4 On the morning of the fifth consecutive day of notification from the Patrol Pilot of “No‐Fly”, Third Level Procedures will be initiated. Third Level Procedures – Tier 1 areas shall be initiated. Each area COM will maintain a list of personnel designated to patrol a section of the Tier 1 segments in there area and provide that person with the required maps and other information that will describe in detail the patrol section. The required notification will be made to the ground patrol personnel and unless notified other wise will begin patrol of the assigned area the next morning. All sightings that can not be dealt with at that time will be called to One Call. Second Level segments need to be completed within one and one‐half (1.5) days of the second day notification and sightings will be recorded on Right‐of‐Way Patrol Report By Aerial/Ground form. 2.4 Ground Patrol Observation 2.4.1 Ground Patrol personnel patrolling the right of way need to observe Conditions that may adversely affect the safe operating condition of the pipeline system. Observations need to be documented for continued inspection, maintenance or repair activities. Observations shall be documented on the following forms. 2.4.1.1 Right‐of‐Way (ROW) Inspection Report: Marking repairs, erosion, cathodic 2.4.1.2 2.4.1.3 2.4.1.4 2.4.2 Inspection observations that should be included in the patrol are listed below: protection issues and span conditions Right‐of‐Way Patrol Report By Aerial/Ground Form: Document the section inspected for Department of Transportation (DOT) compliance Pipeline Maintenance Report: Leak, corrosion, pipe and erosion repairs Encroachment Agreement (Short Form): Third party crossings on the ROW <<>> Magellan Midstream Partners, L.P. ASSETS COVERED PER MITIGATION PLAN RIGHT‐OF‐WAY INSPECTION PROCEDURE 7.05–ADM–031 Asset Integrity 01/01/12 Revision: 10 Page 3 of 5 2.4.2.1 2.4.2.2 2.4.2.3 2.4.2.4 2.4.2.5 2.4.2.6 Erosion: Creek, ravines, sink holes, exposed pipe/spans and agricultural land Right‐of‐Way: Clearing/mowing, marking condition and spacing, over‐hanging trees and gate needs Third Party Activity: Dozer, trenching, boring, building construction or fencing activities on or near the ROW Leak Indications: Vapors, odor, dead vegetation, rainbow on water or stains on piping or valves. Vent pipes at road crossings should be inspected for the presents of vapors. Pipe Damage: Indication of coating damage (paint or other protective coating) or pipe damage at exposures or spans. Spans need to be inspected to determine any pipe deviation or denting from previous patrols. Cathodic Protection: Inspect test leads (conduit and face plates) and rectifier locations for visible damage to the rectifier or third activity in the anode field. Verify Anode Field Schematics are available inside the rectifier. 2.4.3 Reporting 2.4.3.1 During each patrol, emergency situations identified during aerial or ground surveillance will be immediately reported to the designated Pipeline Control Center. Aerial Patrol personnel shall remain at report location until otherwise instructed by Operation. All surveillance personnel and line spotters will be trained and certified in Occupational Safety and Health Administration (OSHA) Hazardous Waste Operations and Emergency Response Standard (HAZWOPER) to the first responder level. 2.5 Ground Patrols (Special Conditions) 2.5.1 Several areas have been identified as requiring ground based patrols. These areas will be patrolled at the intervals specified until circumstances warrant a change in the need for ground‐based patrol or the patrol frequency. 2.5.2 Patrol Method 2.5.2.1 not be dealt with at that time will be called to One Call. 2.5.2.2 Silver Mountain Road – Special Containment Inspection:  An area from milepost 174.09 to 174.94, FM 1826 through Silver Mountain Road has been cased with High Density Polyethylene (HDPE) pipe. This casing requires  Various methods may be used to conduct a ground‐based patrol. The method used will be driven by surface conditions, equipment availability and the extensive nature of the patrol. All terrain vehicles, pickup trucks or walking may be used as each situation warrants. Edwards Aquifer Recharge Zone – Austin  Daily patrols of the Edwards Aquifer Recharge Zone, from Brodie Lane to Slaughter Lane, milepost 169.79 to 173.64, are required with one (1) ground based patrol each week. Geology in this area is known to be highly porous and provides ready access to the aquifer from surface runoff or a hydrocarbon spill. Patroller will complete Right‐of‐Way Patrol Report by Aerial/Ground form. All sightings that can <<>> Magellan Midstream Partners, L.P. ASSETS COVERED PER MITIGATION PLAN RIGHT‐OF‐WAY INSPECTION PROCEDURE 7.05–ADM–031 Asset Integrity 01/01/12 Revision: 10 Page 4 of 5 weekly inspection for water infiltration and the presence of hydrocarbon vapors. Refer to HDPE Inspection and Dewatering procedure. Document the inspection and file the documentation in accordance with Section 3.0 of this procedure. 2.5.3 3.0 RECORDS 3.1 Written Pilot Reports 3.2 3.1.1 Pilots shall make a written report using the Right‐of‐Way Patrol Report By Aerial/Ground form of all specified and other material observations as soon as practical following each flight, but in no case more than 12 hours of flight completion with all required information: 3.1.1.1 Date of inspection 3.1.1.2 Name of person conducting the inspection 3.1.1.3 Identification of the pipeline(s), line section or right‐of‐way segment 3.1.1.4 Location of the observations by mile post number 3.1.1.5 Description of observation 3.1.1.6 Identity of Company staff, date and time (If observation was verbally reported to Operations Control) Company Action Taken and Recordkeeping 3.2.1 Employees shall take appropriate action, respond to pilot observations within 3 business days of pilot report and maintain a record of such response. Such disposition records shall reference or be linked to the report of the pilot and indicate as is applicable: 3.2.1.1 Date initially investigated by company personnel 3.2.1.2 What action was taken or will be taken 3.2.1.3 The status or disposition of the item observed or if the observation is or is not a relevant action item 3.2.1.4 All “Non‐Emergency” observations will be responded to in One Call Ticket View within 3 working days of aerial patrol. 3.2.1.5 Date each reported observation is resolved 3.2.1.5.1 Non‐Emergency sightings and comments will be evaluated by aerial patrol for removal. 3.2.1.5.2 With respect to observations that were previously reported, it is not necessary to reinspect and generate a new report, provided there is not a material change in the status or risk of the reported observation. 3.2.1.5.3 Records of the pilot observation and Company action taken shall be maintained for a period of two (2) years or until the next regulatory agency inspection, whichever is longer. <<>> Magellan Midstream Partners, L.P. ASSETS COVERED PER MITIGATION PLAN RIGHT‐OF‐WAY INSPECTION PROCEDURE 7.05–ADM–031 Asset Integrity 01/01/12 Revision: 10 Page 5 of 5 Date Change Location 12/15/2005 1.0, 3.0 and 6.0 01/01/2006 01/01/2007 01/01/2008 06/03/2008 2.3.1.7 & 2.3.1.8 01/01/2009 03/31/2009 2.2.1.3 03/31/2009 2.3.1.1 03/31/2009 2.3.1.7 03/31/2009 3.2.1 03/31/2009 3.2.1.3.1 4/29/09 2.5.2.3 4/29/09 2.5.2.4 9/03/09 header 9/03/09 2.4.3.1 9/03/09 3/4/10 2.4.3.1 01/01/11 12/31/11 All System Integrity Plan Change Log Brief Description of Change Included link to “Inspection of Right of Way procedure” Deleted references section Reviewed, no changes Reviewed, no changes Added “emergency”. Annual Review with no changes. Changed to 2.2.1.4 and added new 2.2.1.3 Changed flight segment - extended to Pecos River Added “within 3 working days” and added requirement to put one-call ticket number on aerial patrol form Added “within 3 business days of pilot report” Added section Boggy Creek ROW Cleared. Visible to aerial patrol. Daily foot patrol discontinued. Removed this section. Re-numbered due to removal of Boggy Creek Changed Longhorn Specific to Assets covered per Mitigation Plan, date and revision number Changed Longhorn to Assets covered per Mitigation Plan Annual Review with changes listed above Changed “assets covered by mitigation plan” to designated pipeline center – not a version change Reviewed, no changes 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. FLOOD CONDITIONS PROCEDURE 7.05‐ADM‐039 Asset Integrity 1/01/12 Revision: 0 Page 1 of 4 PURPOSE The purpose of this procedure is to provide a standardized method for continued surveillance due to severe flooding conditions on mainline piping at water crossings. SCOPE The severe flooding conditions will trigger Field Personnel to direct their resources in a manner that will enable them to determine the potential effects of flooding on the pipeline system. PROCEDURE The Asset Locator shall:  Watch for the potential for damage to the pipeline caused by flooding and report it to the Pipeline Integrity Coordinator.  Report evaluations of the pipeline to the Pipeline Integrity Coordinator.  Coordinate their responses to flood conditions with Pipeline Integrity Coordinator. The Pipeline Integrity Coordinator shall:  Distribute the attached form to the affected stakeholders and obtain the data for updates to management.  Evaluate the accessibility of pipeline facilities that may be in jeopardy, such as valve settings, which are needed to isolate water crossings or other sections of a pipeline.  Extend regulator vents and relief stacks above the level of anticipated flooding, as appropriate for Natural Gas lines.  Coordinate with emergency and spill responders on pipeline locations and condition. Provide maps and other relevant information to such responders.  Consider deploying personnel so that they will be in position to take emergency actions, such as shut down, isolation, or containment. List appropriate personnel or contractors that may respond, identify the point of contact or the QI.  Determine if facilities that are normally above ground (e.g., valves, regulators, relief sets, etc) have become submerged and are in danger of being struck by vessels or debris; if possible, such facilities should be marked with an appropriate buoy with Coast Guard approval.  Perform frequent patrols, including appropriate over flights, to evaluate right-of way conditions at water crossings during flooding and after waters subside. Determine if flooding has exposed or undermined pipelines as a result of new river channels cut by the flooding or by erosion or scouring.  Perform surveys to determine the depth of cover over pipelines and the condition of any exposed pipelines, such as those crossing scour holes. Information gathered by these surveys should be shared with affected landowners. Agricultural agencies may help to inform farmers of the potential hazard from reduced cover over pipelines. Where appropriate, surveys of underwater pipe should include the use of visual inspection by divers or instrumented detection.  Ensure that line markers are still in place or replaced in a timely manner. Notify contractors, highway departments, and other involved in post-flood restoration activities of the presence of pipelines and the risks posed by reduced cover. The Compliance Coordinator shall: Advise the appropriate PHMSA Regional Office or State Pipeline safety authority if a pipeline has suffered damage, is shut-in, or is being operated at a reduced pressure as a precautionary measure as a result of flooding, before returning the line to service, increasing its operating pressure, or otherwise changing its operating status. PHMSA or the state will review all available information and advise the operator, on a case by case basis, whether and to what extent a line can safely be returned to full service. <<>> Magellan Midstream Partners, L.P. FLOOD CONDITIONS PROCEDURE 7.05‐ADM‐039 Asset Integrity 1/01/12 Revision: 0 Page 2 of 4 MAINLINE FLOODING COMPLIANCE FORM COMPLETED BY: DATE COMPLETED: LINE SECTION NAME: FLOOD AREA: SECTION 1: TASKS 1. FLOOD TYPE (COMPLETE QUESTIONS 1‐10) 1. ARE THE PIPELINE FACILITIES ACCESSIBLE? YES NO 2. ARE VALVE SETTINGS ACCESSIBLE? YES NO 3. HAS PERSONNEL BEEN DEPLOYED TO BE IN POSITION TO TAKE EMERGENCY ACTIONS, SUCH AS SHUT DOWN, ISOLATION, OR CONTAINMENT? YES NO 4. HAVE FACILITIES THAT ARE NORMALLY ABOVE GROUND BECOME SUBMERGED AND IN DANGER OF BEING STRUCK BY A VESSEL OR DEBRIS? YES NO 5. HAS A MORE FREQUENT PATROL PROGRAM BEEN INITIATED? YES NO 6. HAS COMMUNICATION TO THE EMERGENCY AND SPILL RESPONDERS OF PIPELINE LOCATIONS AND CONDITIONS TAKEN PLACE? (NOTE BELOW IF MAPS AND PIPELINE INFORMATION WERE GIVEN) YES NO 7. CAN IT BE DETERMINED IF THE PIPELINE IS EXPOSED OR UNDERMINED AS A RESULT OF FLOODING, EROSION OR SCOURING? YES NO 8. ARE UNDERWATER SURVEYS BEING PERFORMED TO DETERMINE DEPTH OF COVER OVER PIPELINES DURING FLOODING CONDITIONS OF EXPOSED PIPELINES, SUCH AS THOSE CROSSING SCOUR HOLES? YES NO 9. ARE THE PIPELINE MARKERS STILL IN PLACE? YES NO 10. HAS INFORMATION OBTAINED DURING SURVEY BEEN SHARED WITH AFFECTED LANDOWNERS IN AREAS WHERE COVER MAY HAVE BEEN REMOVED OVER THE PIPELINE? POST FLOOD ? YES NO 2. ARE ADDITIONAL PREVENTATIVE OR MITIGATIVE MEASURES RECOMMENDED TO PREVENT A RELEASE OR DRAINAGE FROM A FLOODED AREA? (COMPLETE THE DISCUSSION SECTION WITH COMMENTARY AND CONSIDERATION FOR THE BELOW RISK FACTORS)  GENERAL PROFILE/TERRAIN OF THE AREA SURROUNDING THE PIPELINE  SURVEYS OF UNDERWATER PIPE / VISUAL INSPECTION BY DIVERS OR INSTRUMENTED DETECTION N/A N/A N/A N/A N/A N/A N/A N/A N/A N/A <<>> Magellan Midstream Partners, L.P. FLOOD CONDITIONS PROCEDURE 7.05‐ADM‐039 Asset Integrity 1/01/12 Revision: 0 Page 3 of 4 SECTION 1: TASKS  CHARACTERISTICS OF THE PRODUCT TRANSPORTED  AMOUNT OF PRODUCT THAT COULD BE RELEASED  THE SWIFTNESS OF LEAK DETECTION AND SHUTDOWN CAPABILITIES INCLUDING THE LOCATION OF RESPONSE PERSONNEL  THE POTENTIAL RATE AND VOLUME OF LEAKAGE  THE POTENTIAL FOR PRODUCT TO REACH AN IGNITION SOURCE  DAMAGED LINE, SHUT IN OR OPERATIONS AT A REDUCED PRESSURE AS A PRECAUTIONARY MEASURE AS A RESULT OF FLOODING, REQUIRE ADVISING THE PHMSA REGIONAL OFFICE OR STATE PIPELINE SAFETY AUTHORITY BEFORE RETURNING THE LINE TO SERVICE, INCREASING THE OPERATING PRESSURE OR CHANGING ITS OPERATING STATUS. DISCUSSION OR COMMENTS: <<>> Magellan Midstream Partners, L.P. FLOOD CONDITIONS PROCEDURE 7.05‐ADM‐039 Asset Integrity 1/01/12 Revision: 0 Page 4 of 4 SIP CHANGE LOG Date Change Location Brief Description of Change 1/1/12 new <<>> Magellan Midstream Partners, L.P. INTEGRITY MANAGEMENT SIP–ADM–7.06 Asset Integrity 1/01/11 Revision: 7 Page 1 of 4 1.0 OBJECTIVE 1.1 The objective of this initiative is to maintain asset integrity through the Integrity Management Plan. 2.0 DESCRIPTION 2.1 2.2 2.3 Products transported, operating parameters, materials of construction, installation, maintenance methods and routing through a variety of population densities, land uses and environmentally defined areas characterize pipeline systems and facility assets. Taken collectively, a pipeline's or a facility’s physical attributes, products transported and operating systems are factors that characterize the relative risks to the surrounding environment and areas of population. Physical data, collected by and contributed from an integrated team of operating, technical, commercial and subject matter experts, is the cornerstone of Integrity Management. Maintaining integrity of abandoned or inactive segments is also included in Integrity Management. 2.3.1 Abandoned is defined as a pipeline facility that is permanently removed from service and is purged of product. 2.3.2 Inactive is defined as a line that is removed from active service and purged of product, but may be returned to service in the future. 3.0 STANDARDS 3.1 The Director of Asset Integrity shall: 3.1.1 Execute and maintain the Integrity Management Plan. 3.1.2 Develop Annual Asset Integrity Plans. Include input from key stakeholders such as Asset Integrity, Operations, Commercial, Environmental and results from section six and seven analysis of the Integrity Management Plan. 3.2 3.3 3.1.3 Coordinate the execution and track progress of the Asset Integrity Plan. Distribute a monthly Asset Integrity Plan Report. The Manager of Asset Integrity Engineering shall: 3.2.1 Complete the PHMSA Annual Report for Hazardous Liquid Systems and send to the Sr. Vice President of Operations and Technical Services for certification and approval. Send approved reports to PHMSA. 3.2.2 Publish a quarterly report that contains data regarding the leaks that occurred during the previous quarter. The Senior Vice President of Operations and Technical Services shall: 3.3.1 Review, approve and certify the PHMSA Annual Report for Hazardous Liquid Systems upon receipt. Send approved and certified reports to the Manager of Asset Integrity Engineering. <<>> Magellan Midstream Partners, L.P. INTEGRITY MANAGEMENT SIP–ADM–7.06 Asset Integrity 1/01/11 Revision: 7 Page 2 of 4 3.4 The Employee shall: 3.4.1 Document and notify the Asset Integrity Engineer of any new threats to the integrity of the assets (i.e., third party construction, new population, new environmental, potential over pressure issues, right‐of‐way issues, over‐stressed piping, and lack of adequate tank overfill protection, pitting corrosion on tanks or piping, etc.) or operational changes. 3.5 The Project Manager shall: 3.5.1 Document and notify the Asset Integrity Engineer of any proposed change to the Company assets for risk consideration. 3.5.2 Utilize Project Life Cycle to place active pipelines in an abandoned or inactive status, or to convert a line to service. Comply with the Abandoning Pipeline Segments and/or Inactivating Pipeline Segments or Conversion to Service procedures, as appropriate. 3.6 The Asset Integrity Engineer shall: 3.6.1 Utilize the Risk Analysis for New/Modified Pipelines process in consultation with the Project Manager for 3.7 completion and documentation of risk analysis when constructing or significantly altering pipelines. The Supervisor of Pipeline Integrity shall: 3.7.1 Maintain the Abandoning Pipeline Segments Procedure, the Inactivating Pipeline Segments Procedure and the Conversion to Service Procedure. 3.8 The Records Coordinator shall: 3.8.1 Segments and Conversion to Service procedures. Retain and file all records as described in the Abandoning Pipeline Segments, Inactivating Pipeline <<>> Date 2004 10/10/05 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 Magellan Midstream Partners, L.P. INTEGRITY MANAGEMENT SIP–ADM–7.06 Asset Integrity 1/01/11 Revision: 7 Page 3 of 4 System Integrity Plan Change Log Change Location Changed By Approved By: Brief Description of Change Chabino Michael Pearson Integrated 7.12 into this initiative Chabino Michael Pearson Removed the Project Manager requirement to Notify the Facility Risk Engineer of the incoming documents for input/updating of the Facility Risk Model per the Facility Risk Management Program within 30 days of project completion. Chabino Michael Pearson Removed the Project Manager requirement to complete a Pipeline Maintenance report and associated documentation within 30 days of completion of a pipeline project and forward to the Pipeline Integrity Records coordinator. It was redundant. Chabino Michael Pearson Changed title from Facility Integrity Supervisor to Risk Engineering Supervisor Chabino Michael Pearson All Eliminated the Facility Risk Management program and incorporated it into the Integrity Management Plan. Conducted 2004 Annual Review All Chabino Michael Pearson Conducted 2005 Annual Review Michael Pearson 2.3, 3.3.4, 3.3.5, 3.7 Pearson Added standards to include abandoning and inactivating activities 3.3.1 Pearson Michael Pearson Added statement to include Conversion to Service requirements. Chabino Michael Pearson 3.5 Added requirement for Pipeline Risk Engineer to utilize risk analysis process for new/modified pipelines 3.1.1 Chabino/Pearson Michael Pearson Removed “required” and “High Consequence Areas” 3.2.1 Chabino/Pearson Michael Pearson Changed Asset Integrity Manager to Risk Engineer Chabino/Pearson Michael Pearson 3.3.1 Removed reference to Conversion to Service procedure since redundant to new 3.3.4 3.3.2 and 3.3.3 Chabino/Pearson Michael Pearson Moved PHA requirements to Element 11 3.3.4 Chabino/Pearson Michael Pearson Combined 3.3.4 and 3.3.5 3.4.1 Chabino/Pearson Michael Pearson Changed 30 days to 45 days <<>> 01/01/06 01/01/06 06/06/06 06/06/06 06/06/06 10/16/06 05/17/07 09/11/07 9/11/07 9/11/07 9/11/07 02/04/08 10/23/08 01/01/10 08/30/10 01/01/11 12/31/11 Magellan Midstream Partners, L.P. INTEGRITY MANAGEMENT SIP–ADM–7.06 Asset Integrity 1/01/11 Revision: 7 Page 4 of 4 3.4.2 Chabino/Pearson Michael Pearson Moved PHA requirements to Element 11 Chabino/Pearson Michael Pearson 3.5.2 Removed Pipeline Risk Engineer requirement to comply with Conversion to Service Procedure 3.4.1 Chabino/Pearson Michael Pearson Minor Modification to Paragraph. Deleted 45 days and inserted quarterly. 3.6 Chabino/Pearson Michael Pearson Deleted Facility Risk Engineer or Terminal Operations Manager. 3.7 Chabino/Pearson Michael Pearson Deleted word Mapping out of title. All Chabino/Pearson Michael Pearson Conducted 2006 Annual Review, no changes 3.2 Chabino/Pearson Michael Pearson Added Paragraph 3.2 new responsibilities for VP Operations All Chabino/Pearson Michael Pearson Conducted 2007 Annual Review (see change log) 3.1 Chabino/Pearson Michael Pearson Removed Director and inserted Manager of AI Engineering 3.5 Chabino/Pearson Michael Pearson Removed Supervisor and inserted Manager of AI Engineering 3.6 Chabino/Pearson Michael Pearson Removed Risk Engineer and inserted AI Engineer 3.1 Combined Asset Integ Eng Mgr responsibilities 3.3 and 3.4 Matt Argo Doug Chabino 2008 annual review. Changed title Reviewed, no changes 3.8.2 Matt Argo Doug Chabino Removed 3.8.2, class location surveys 3.1 Changed title to Director 3.2 Moved 3.2.1 and 3.2.2 to Mgr of AI Eng responsibility Updated VP title to Sr VP of Operartions 3.8 Removed Compliance Coordinator responsibilities All 2012 annual review complete – no changes <<>> Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Revision: 9 Page 1 of 7 1.0 OBJECTIVE 1.1 2.0 DESCRIPTION 2.1 3.0 STANDARDS The objective of this initiative is to provide a framework that complies with the security regulations governing the Company and that protects the assets, employees, the environment, stakeholders and the community from security threats. This initiative incorporates the security requirements required by regulations applicable to Company assets and operations. The Company will follow the landlord’s policies for security in the Bank of Oklahoma (BOK) Tower located in Tulsa, Oklahoma. At any other leased and/or rented office space(s) the landlord’s policies will provide the minimum security requirements for that office space. Without Exception, Personnel Safety Is the First Priority. 3.1 The Director of Environmental, Health, Safety & Security (EHS&S) shall: 3.1.1 3.1.2 Serve as the Company Corporate Security Officer. Establish a Security Management Team (SMT) responsible for ensuring Company security awareness to employees and implementing security measures at the workplace, as needed. Convene as needed to address security‐related topics/incidents. Notify the SMT within 24 hours of any security incident at a Company asset, to include a summary of notifications made and actions taken. Maintain Minimum Physical Security Standards for Company assets. 3.1.3 3.1.4 3.1.5 Annually review the notification information in the Security Events Procedure. 3.1.6 Annually review the Company asset list with the SMT to validate the Company DOT Critical List. 3.1.7 Annually update Company contact information to the Transportation Security Administration (TSA) and the Office of Pipeline Safety (OPS) for execution of notification protocols by each agency, as required. 3.2 The Operations Supervisor shall: 3.2.1 Develop, maintain and comply with the Facility Security Plan (FSP) using the Facility Security Plan (Nonmarine) Template for facilities that have a loading rack and/or other loading area(s) (i.e., butane/ethanol/biodiesel), and facilities that ship loads of more than 792 gallons of hazardous liquids. Complete a Facility Vulnerability Assessment (FVA) template prior to the development of the FSP. Address any vulnerability identified by the FVA in the FSP. 3.2.1.1 Develop a FVA/FSP for any newly purchased loading rack/loading area facilities within 60 days of purchase. NOTE: The FSP for each marine facility will be developed on a site specific basis and should comply with all United States Coast Guard (USCG) requirements. NOTE: The Corporate Security Officer may determine (based on site specific factors) that additional facilities (i.e., tank farm, pump station, etc.) require a FSP. If an additional facility is determined to need a FVA and FSP, the Corporate Security Officer will advise the Supervisor to ensure completion of these documents. 3.2.2 Conduct an annual (once per calendar year) review of the FSP and the FVA with all employees to ensure familiarity with the plan and to identify inaccuracies or improvement opportunities. If there are any <<>> Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Page 2 of 7 Revision: 9 improvements, update the FSP and submit to the EHS&S Compliance Specialist for uploading into the Livelink Security Folder. 3.2.3 3.2.4 3.2.5 3.2.2.1 Note any changes in owner, operator or Corporate Security Officer in the annual review. 3.2.2.2 Complete the In‐Depth Security Training Form. Revise and update the FSP when major changes involving the facility status or security organizations occur, or as necessary to reflect other changing circumstances. Communicate these changes to affected personnel via a SIP meeting, or via email if unable to attend an SIP meeting. Send the revised FSP to the Safety Compliance Specialist for uploading into the Livelink Security Folder. 3.2.3.1 The following conditions at a minimum require a change to the FSP within 30 days: 3.2.3.1.1 Local Facility Security Officer change. 3.2.3.1.2 Modification of physical security. 3.2.3.1.3 Security procedure change. 3.2.3.1.4 Change in the facility’s configuration that materially alters the information included in the FSP. 3.2.3.1.5 Change in the type of products handled, stored, or transferred that materially alters the required response resources. 3.2.3.1.6 Any other changes that materially affect the implementation of the FSP. Include all other conditions in the annual review. Annually assess the facility using the Minimum Physical Security Standards. Assess newly acquired facilities within 60 days of purchase and annually thereafter. Use the appropriate Visitor Log and Safety Guidelines (Inland or Marine) for visitor identification, 3.2.3.2 3.2.4.1 verification and monitoring at each manned facility. Maintain completed logs locally as required. Conduct a Visitor Safety Orientation for all visitors prior to their leaving the main office area. NOTE: “Visitor” is defined as anyone, Company employee, contractor, or other, who is not assigned to work at the facility. “Visitor” is not intended to include drivers, cleaning crews, or delivery services (e.g., UPS, FEDEX, etc.). 3.2.6 Maintain the Key Control Log at the facility, listing by name and contact information whoever has been provided keys and/or automatic gate openers for the facility. NOTE: This requirement applies to employees who have keys and/or automatic gate openers permanently assigned to them until termination or transfer, and temporary keys and/or automatic gate openers that may be occasionally loaned to a contractor, cleaning crew, or utility worker for occasional access to remote facilities. 3.2.7 3.2.8 3.2.9 3.2.10 Ensure all employees newly assigned to the facility receive Security Awareness Training within 90 days of assignment to the facility. Report any employee threat or threat to an employee to the Corporate Security Officer or Alternate Corporate Security Officer with appropriate recommendations for ensuring workplace security. Conduct annual drills and/or exercises as outlined in 6 CFR 27.255 and the Chemical Facility Anti‐Terrorism Standards (CFATS) Site Security Plan if the facility is regulated by CFATS. CFATS facilities will be notified of their status by the Alternate Corporate Security Officer. 3.2.9.1 Document security drills and exercises on the Security Drills and Exercises Form. Comply with the Notification Procedure as outlined in Security Events. <<>> Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Revision: 9 Page 3 of 7 3.3 The Field Supervisor shall: 3.3.1 Periodically, not to exceed three years, review the Security Events Procedure and the Guidelines for Reporting a Suspicious Call and/or Bomb Threat to a Facility with all employees to ensure they are aware of At USCG regulated facilities, annually update Company contact information for execution of notification what constitutes a Security Event 3.4 The Marine Terminal Supervisor shall: 3.4.1 Register all individuals who are assigned at a USCG regulated facility more than 90 days, into the HomePort Database (or alternative approved registration format) within 30 days of their start date. This includes employees, temporary employees, and/or contractors. If an individual has not previously been registered, register the individual within five days, (but no later than the 90 days), at the point it is determined that he/she will need access beyond the 90‐day period. 3.4.2 Ensure all new hire employees obtain a Transportation Workers Identification Credential (TWIC) upon accepting an offer of employment. 3.4.3 Escort all new hire employees until they have acquired their TWIC card to allow unescorted access to the facility. 3.4.4 protocols. 3.4.5 At USCG regulated facilities, annually update Company contact information to the USCG for execution of notification protocols, as required. 3.4.6 Conduct security drills/exercises in accordance with 33 CFR 105.220 at all facilities regulated by the USCG. 3.4.6.1 Conduct drills every three months. 3.4.6.2 Conduct exercises annually, not to exceed 18 months between events. 3.4.6.3 Document security drills and exercises on the Security Drills and Exercises Form. 3.4.7 Maintain security related records at all facilities regulated by the USCG (33 CFR 105) for a period of two years. 3.4.8 Submit and maintain approved USCG Facility Security Plans as regulated by 33 CFR 105. 3.5 The Operations Manager shall: 3.5.1 If employees are officed in a leased or rented space in excess of 30 days, determine if security measures beyond the landlord’s polices are required and implement as needed. 3.5.2 For marine facilities: 3.5.2.1 Assign, in writing, a Facility Security Officer (FSO) for all facilities regulated by the Maritime Transportation Security Act and provide training for the FSO to serve in that capacity. 3.5.2.2 For marine terminals, review security incidents, which are considered Security Sensitive Information, with the personnel specified in the FSP. 3.5.2.3 Submit a 33 CFR 105 compliant FSP for newly acquired facilities regulated by the USCG to the applicable Captain of the Port 60 days prior to close, or as soon as practical based on confirmation of closing the acquisition. 3.5.3 Complete the Facility Security Plan (Nonmarine) Template (including the FVA) for all newly acquired nonmarine facilities within 60 days of purchase and submit to the EHS&S Compliance Specialist. NOTE: The Corporate Security Officer may determine based on site specific factors, that additional facilities (i.e., tank farm, pump station, etc.) require a FSP. If an additional facility is determined to need a FVA and FSP, the Corporate Security Officer will advise the Supervisor to ensure completion of these documents. <<>> Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Page 4 of 7 Revision: 9 3.5.4 Prepare and submit grant applications for security related costs, as applicable. 3.6 The Alternate Corporate Security Officer shall: 3.6.1 Submit “Top Screen” information to the Department of Homeland Security in compliance with CFATS: 3.6.1.1 When a facility is newly acquired. 3.6.1.2 When there are material modifications to an existing facility’s operations or site including facility real estate or tank expansions. 3.6.1.3 On a resubmission schedule noted in CFATS regulations. 3.6.2 Coordinate the development of CFATS Security Vulnerability Analysis (SVA) and Site Security Plans (SSP) for facilities that fall under CFATS regulations and submit when required by regulation. 3.6.3 Coordinate a drill and exercise program for CFATS facilities and facilities that are considered TSA critical. 3.6.4 Coordinate a TSA Critical Facility Workgroup to assess Company facilities against the TSA critical facility standards. 3.6.5 Notify Operations of any facilities considered Transportation Security Administration (TSA) Critical. 3.6.6 Coordinate with Operations to develop Site Security Plans to comply with TSA guidelines. 3.6.7 Develop a Chemical Terrorism Vulnerability Information (CVI) based records retention program for CFATS facilities. 3.6.8 Perform the duties of the Corporate Security Officer as needed. 3.7 The Project Manager shall: 3.7.1 Identify all contractors who have the potential to conduct work at a USCG regulated facility beyond a 90‐ day period on the job plan and/or project plan. Provide the Facility Supervisor the names of the contractors listed on the job plan and/or project plan as soon as available, but no later than 30 days after the project start date. 3.7.2 Require all contractors who conduct work at a USCG regulated facility to require their employees who will be working in Company facility “Restricted” or “Secure” areas to obtain a TWIC card. Contractor employees that do not have a TWIC, are required to be escorted at all times in these areas in compliance with 33 CFR 105. 3.8 The Security Management Team (SMT) shall: 3.8.1 Review security incidents and/or security breaches for nonmarine facilities to assess whether or not any additional workplace security is warranted. 3.8.2 Review reported employee threats or threats to an employee to determine if additional security measures and/or other actions are warranted. 3.8.3 Determine if a national, regional, or facility‐specific security threat could impact or change: 3.8.3.1 The Company’s Security Threat Level and/or 3.8.3.2 Require additional security measures at one or more of the Company’s facilities. NOTE: The SMT is only tasked to address Company workplace security issues/concerns. Employees visiting non‐Company facilities should comply with the security requirements in‐place at those locations. 3.9 3.10 The EHS&S Compliance Specialist shall: 3.9.1 Upload the FSP to the Livelink Security Folder upon receipt. The Supervisor of Pipeline Integrity Engineering shall: <<>> Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Page 5 of 7 Revision: 9 3.10.1 Conduct a security analysis using the Valve Security Process to determine the appropriate security measures to be implemented to protect against vandalism and unauthorized entry for DOT regulated exposed facilities located outside of a facility (e.g., terminal, pump station or tank farm). 3.10.2 Reassessments should be considered whenever circumstances arise that suggests the need for a reassessment. Types of circumstances may include security events, encroachments, land use changes, threats, etc. 3.11 The Vice President of Technical Services shall: 3.11.1 Implement security measures as identified. 3.12 The Employee shall: 3.12.1 Report any personal or work‐related threat (verbal, written, etc.) to you or another employee to Supervisor immediately. 3.12.2 Make notifications as described in the Security Level Procedures. 3.12.3 Make primary and secondary notifications if the Corporate Security Officer or the Alternate Corporate Security Officer cannot be reached, and if the situation requires immediate notification. Notify the Corporate Security Officer via voicemail or email that such notification(s) have been made. 3.12.4 Comply with the Security Events Procedure. 3.12.5 Comply with the Security Level Procedure. 3.12.6 Complete the Security Awareness Training within 90 days of assignment to a facility (terminals and tank farms only). 3.12.7 Complete the Key Control Log as directed by Supervisor. 3.12.8 Lock all manually operated block valves upon completion of activity and prior to leaving the area. 3.12.9 Lock all gates and key buildings (manned and unmanned) anytime the facility is not occupied. 3.12.10 Complete the Visitor Log after verifying that a visitor has left the facility for the day and has not signed out or notified Company personnel that he/she has left the facility. 3.12.11 Successfully obtain a TWIC card when unescorted access is required to secure areas of Company marine facilities. 3.12.12 Complete the Declaration of Security Form for every vessel that comes to the dock only if the Marsec level is elevated to level 2 and higher. <<>> DATE 1/1/05 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 01/01/06 7/1/06 1/1/07 01/01/07 Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Revision: 9 Page 6 of 7 System Integrity Plan Change Log LOCATION BRIEF DESCRIPTION OF CHANGE 2.1 Added any other leased/rented office 3.1.1 Added 3.1.3 Added 3.1.5 Added 3.1.7 Added 3.2.3 Deleted 3.2.4 Added note box 3.2.5 Rephrased 3.2.6 Added 3.2.7 Added 3.2.8 Added 3.2.10 Added 3.3.2 Added 3.3.3 Added 3.4 Added 3.5 Added 3.1 Deleted “ Develop and maintain a Company Security Plan to comply with all regulatory security requirements, including the Department of Homeland Security, Transportation Security Agency and the Department of Transportation (TSA), the United States Coast Guard (USCG) and the Office of Pipeline Safety (OPS). NOTE: The Company Security Plan is a protected document with limited employee access. 3.1 Deleted Annually validate and document that the Company’s facilities are in compliance with the Company Security Plan and document. Develop and maintain security related procedures, as required 3.19 Added for physical changes/improvements made to assets for the primary purpose of meeting the Minimum Physical Security standards and/or security enhancements 3.2.2 Added site‐specific 3.1.8 Added 3.3.4 deleted “ records associated with training, drills and exercises and incidents/breaches of security for a minimum” 3.2.11 added 3.2.3 added 3.2.4 Changed to 1 year from 3 2.1 Added “ At any other leased and/or rented office space(s) the landlord’s policies will provide the minimum security requirements for that office space" 3.3.5 Deleted “Specifically, all Company marine facilities are required to conduct a security drill once every three months. 3.5, 3.51, 3.5.2 and 3.5.3 Added 3.5.3.2 Note box added 3.6.1 Added 3.6.5 Added 4.0 Deleted link to Company Security Plan 4.0 Added “ Workplace Violence Policies and Guidance“ 3.1.2 and 3.1.3 added 3.3.6 and 3.3.7 Added 3.3.7 Split “Complete a Security Vulnerability Assessment and the Facility Security Template for all newly acquired non‐marine facilities within 60 days of purchase”. Into 2 responsibilities. Added as 3.1.9 3.3.7 Deleted “Assess the facility periodically using the Minimum Physical Security Standards. 3.2.12 and 3.6.1 Added to comply with new USCG regulations. 3.1.2 Added “convene as needed to address ….” 3.1.6 deleted <<>> 1/1/07 1/1/07 1/1/07 1/1/07 1/1/07 1/1/07 1/1/07 1/1/07 1/1/07 1/1/08 1/1/08 1/1/08 1/1/08 1/1/08 1/1/08 1/1/08 1/1/08 01/01/09 01/01/10 7/1/10 01/01/11 12/31/11 12/31/11 Magellan Midstream Partners, L.P. OPERATION ASSET PROTECTION SIP–ADM–8.01 Security 01/01/12 Revision: 9 Page 7 of 7 3.2.8 Combined with 3.2.7 3.3.7 Changed timeframe to 60 days. Added reference to SVA 3.6.1 Rephrased 3.8 added 3.9 and 3.10 added 3.11.7, 3.11.8 added 3.2.13, 3.2.10 added 3.6 added 3.1.8 Added 3.1.6 Added SMT reviews DOT “Critical” list. 3.2.1 plus note Clarify when a FSP is required at Non‐marine loading facilities. 3.2.3 Added requirements including timeframe for changes to FSP. 3.2.15 Added (moved) responsibility for updating COTP with contact information from the Director of EHS to Operations Supervisor. 3.2.16 Added (moved) responsibility for completing drills and exercises from the Operations Manager to the Operations Supervisor. 3.3.5 Added requirement for Submittal and maintain FSP for Marine terminals as required by 33 CFR 105. 3.6.2 Added TWIC credential requirements for contractors. 3.11.9 Added requirement for all affected employees at marine facilities to obtain TWIC as needed. 3.1.10 new 3.2.16.3 new 3.11 New role/responsibilities 3.12.2.1 New 3.12.9 new 3.3 Added marine area supervisor 3.3.2 Added date 3.1.9 Renamed form Facility Vulnerability Assessment 3.2.4 Changed frequency 3.2.8 Changed supervisor role from providing training to ensuring they receive 3.2.5 Changed frequency 3.2.10 Added CFATS language 3.5 Added Alternate Security officer duties 4.2, 4.5, 4.9, 4.10,4.13 Changed name of link to 3.1.8, 3.1.9 Removed. “Maintain BU summary for assest changes/improvements” and “complete FVA for new;y acquired marine facilities” 3.2.2.2 Removed, added annual (once per calendar year) to 3.2.2 3.2.1.1 New 3.4.3 Changed submission to EHSS Compliance Specialist (was Dir EHSS) 3.2.1 Modified per new requlatory requirement for facilities shipping > 792 gallons of hazardous liquids. Reviewed, no changes 3.3.6.2 Removed “once per calendar year not to exceed 365 days”, replaced with “annually, not to exceed 18 months” as per 33 CFR 105.220. 3.11.12 added 3.2.2.2 added 3.2.8 Removed “or newly hired at a facility 3.3 Added field supervisor 3.4 Revised to marine terminal supervisor All 2012 Annual Review complete <<>> Magellan Midstream Partners, L.P. PUBLIC AWARENESS SIP–ADM–10.01 Community Relations 01/01/12 Revision: 8 Page 1 of 5 1.0 OBJECTIVE 1.1 1.2 1.3 The objective of this initiative is to promote public awareness of underground utilities, damage prevention and emergency preparedness. Collectively, this initiative will enhance public safety and minimize damage to property, the environment and Company assets. The Company’s Public Awareness Program was developed to comply with the standards established in American Petroleum Institute’s (API) Recommended Practice (RP) 1162. Company management supports Public Awareness through Company policy, management participation, and allocation of resources and funding as described in the System Integrity Plan Magellan Management Commitment and Support Introduction and the Management Support Cover Letter. Public Awareness is a critical component of our overall safety program. includes the following lines: The Public Awareness Program Company Name Product PHMSA Operator Identification Number Magellan Pipeline Company, L.P. HVL 22610 Magellan Pipeline Company, L.P. Refined 22610 Magellan Pipelines Holdings, L.P. Refined 31579 Magellan Terminals Holdings, L.P. Crude 31580 Magellan Terminals Holdings, L.P. Refined 31580 Magellan Ammonia Pipeline, L.P. Ammonia 12105 Osage Pipe Line Company, LLC Crude 14391 2.0 DESCRIPTION 2.1 The Company’s Pipeline Awareness Program for DOT 195 jurisdictional lines will include information and provide instruction to the affected public, emergency officials, local public officials and excavators on the following: 2.1.1 Pipeline purpose and reliability. 2.1.2 Awareness of hazards or potential hazards and prevention measures. 2.1.3 Damage Prevention Awareness. 2.1.4 One Call requirements. 2.1.5 How to recognize, report and respond to leaks and/or emergencies involving Company operated pipelines and facilities. 2.1.6 How to identify the location of Company operated pipelines, rights-of-way, facilities, and description of the purpose of pipeline markers and the information on them. 2.1.7 Emergency Preparedness Communications. 2.1.8 The “Call Before You Dig!” Campaign and the national One Call number 811. 2.1.9 How to access a list of pipeline operators through the National Pipeline Mapping System (NPMS). 2.1.10 How to obtain additional information. <<>> Magellan Midstream Partners, L.P. PUBLIC AWARENESS SIP–ADM–10.01 Community Relations 01/01/12 Page 2 of 5 Revision: 8 2.2 This initiative provides guidance to Company employees on the communication of Emergency Response Plans (ERPs) to Local Emergency Planning Committees (LEPC) and Emergency Response Agencies (ERA). 3.0 STANDARDS 3.1 The One Call Supervisor and Public Awareness & Communications Specialist shall: 3.1.1 3.1.2 Administer the Public Awareness Program for DOT jurisdictional assets. Determine annually, the acceptable pipeline awareness programs and annual mailings for the upcoming year. Develop the message content of these programs as described in the Message Content Guidelines. 3.1.3 Perform an annual audit of the Public Awareness Program to ensure the program has been developed and implemented according to the guidelines in RP 1162. Document on the Annual Self Assessment. 3.1.4 3.1.5 3.1.6 3.1.7 3.1.8 3.1.9 3.1.10 Perform an Effectiveness Evaluation of the Public Awareness Program before September 1st every four years in accordance to the guidelines in RP 1162. Maintain all program evaluations, including current results, follow-up actions, expected results and annual assessments for five years. Implement the Annual Mailings Procedure annually. Conduct a pretest of public awareness materials for audience appeal, message clarity, understandability, and retention before they are widely used. A pretest can be performed using a small representative audience that is not involved with the development of the Public Awareness Program. Annually review and update the public education and damage prevention section of Magellan’s Internet Site, if necessary. Maintain and annually update the Public Awareness Folder in Livelink and the Emergency Response Guide. Coordinate with Asset Integrity and Operations personnel to ensure that the ERP Summary Folders are prepared, maintained and distributed to the appropriate LEPC and/or specific local ERAs. 3.1.11 Approve any deviations from the print ad or radio ad standards upon request. 3.1.12 Oversee public education efforts for assets covered per the Mitigation Plan to ensure that ERAs within each county that the pipeline passes through will be contacted annually (not to exceed 15 months) in person and provided with maps of the system. 3.2 The Operations Manager shall: 3.2.1 Communicate Emergency Response Plans to LEPC/ERAs. 3.2.2 Maintain a current address listing of LEPC/ERAs that could respond to a Company emergency. Provide this mailing list to the Public Awareness and Communications Specialist for the annual Mail Out Program. 3.2.3 3.2.4 Maintain an ongoing LEPC/ERAs meeting schedule. In addition to annual mailings to LEPCS/ERAs, conduct meetings on a rotating basis, with a minimum of 25% of the listed LEPC/ERAs once every 12 months, not to exceed 15 months. Conduct a meeting with each listed LEPC/ERAs at least once in a four-year calendar period. 3.2.5 Conduct meetings following the LEPC/ERA Meeting Requirements. For Intrastate pipelines in Texas, conduct face-to-face meetings with designated ERA officials annually per the LEPC/ERA Meeting Requirements. 3.2.6 Complete the LEPC/ERA/Stakeholder Meeting Form for each meeting. Distribute the appropriate updated response plan documentation (ERP, ERAP, etc.) during each meeting. 3.2.7 Complete, at a minimum, one supplemental outreach activity per year within each operating area. <<>> Magellan Midstream Partners, L.P. PUBLIC AWARENESS SIP–ADM–10.01 Community Relations 01/01/12 Page 3 of 5 Revision: 8 Consider external factors along the pipeline system and assess if some additional level of public awareness communications is warranted of if other supplemental/enhanced outreach activities are needed. 3.2.7.1 Use the Relevant Factors Assessment in making the evaluation and the Approved Media and Delivery Methods Procedure to determine the appropriate activity. NOTE: are required. There may be circumstances where multiple outreach activities 3.2.7.2 For each Supplemental/Enhanced Outreach Activity, complete the LEPC/ERA/Stakeholder Meeting Form, provide supporting documentation and send to the District Office or location and the Public Awareness and Communication Specialist. Maintain copies of all materials provided to each stakeholder audience in the local files for five 3.2.8 years. 3.2.9 File the completed LEPC/ERA/Stakeholder Meeting Form for five years. 3.3 The Employee shall: 3.3.1 Use the LEPC/ERA/Stakeholder Meeting Form to conduct and document pipeline safety awareness discussions with ERAs, public education and third party damage prevention stakeholder groups. Forward completed forms to the appropriate area office. 3.4 The One Call Coordinator shall: 3.4.1 Request documentation from state One Call Centers for their community outreach or public awareness activities. Information may be obtained by website if available or phone solicitation. Sort the information by state and retain for five years. NOTE: Most state One Call Centers provide public awareness activities; Magellan can incorporate these activities into its Public Awareness Program. 3.5 3.6 3.4.2 3.4.3 3.4.4 3.4.5 Request address listings from each applicable state One Call agency and the Company internal database of all contractors and individuals engaged in excavation activities during the previous 12 months in each state where Company assets are located. Forward the data to the vendor for incorporation into the annual mailings. Advise the Operations Managers, Asset Integrity Supervisors, and Operations Control Manager of the annual mail out messages at least ten days before distributing the mail outs. Utilize the Company Damage Prevention Newsletter to inform employees about the Public Awareness Program objectives. File the LEPC/ERA forms and Supplemental/Enhanced activity documentation in the appropriate Damage Prevention folder in Livelink. The Regulatory Compliance Coordinator shall: 3.5.1 Initiate biennial (beginning January 15, 2005 and every two years thereafter) Educational Center Surveys in accordance with the Texas Public School Survey Procedure for Railroad Commission of Texas regulated assets. The Operations Supervisor in Texas shall: 1.1.1 Conduct public school surveys (psb) upon notification from the Regulatory Compliance Coordinator. Forward the PSB Survey information to the Regulatory Compliance Coordinator within 60 days of the request, but no later than December 15th . <<>> Magellan Midstream Partners, L.P. PUBLIC AWARENESS Community Relations 01/01/12 Page 4 of 5 Date Change Change 1/1/05 All 1/1/05 3.2.6 Greg Walker 1/1/05 3.2.1 1/1/06 All 1/1/06 2.1 1/1/06 3.0 1/1/06 3.0 1/1/06 3.2.2 1/1/06 3.5 1/1/06 3.5.2 1/1/06 3.5.3 Greg Walker 1/1/06 3.5.4 1/1/06 Multiple 1/1/06 3.1.6 1/1/06 3.2.4 1/1/06 3.4.1, 3.4.2 1/1/06 3.2.3 1/1/06 3.2.2 1/1/07 All 1/1/07 1.0 1/1/07 3.1.3 Greg Walker 1/1/07 2.1.1, 2.1.7 1/1/07 3.2.1.1 9-10-07 All 9/10/07 3.2.1.6 9/10/07 3.4.1 Greg Walker 9/10/07 3.2.2 9/10/07 3.3.1 10/08/08 All 10/08/08 3.1.8 10/08/08 3.1.10 10/08/08 3.2.2.5 10/08/08 3.3.1 Greg Walker 10/08/08 3.4.1 10/08/08 3.5.1 10/08/08 3.5.2 10/08/08 3.5.4 10/08/08 3.5.5 1/1/09 3.6, 3.7 02/01/09 3.5.2 7/28/09 All Greg Walker 07/28/09 3.1.7 Mike 07/28/09 3.2 SIP–ADM–10.01 Revision: 8 SYSTEM INTEGRITY PLAN CHANGE LOG Brief Description of Change Conducted 2004 Annual Review see change log Moved responsibility to develop and maintain lists of Emergency responders to Operations Supervisors as new Section 10 3 1 5 Added Public Education and Third Party Damage Prevention Program Conducted 2005 Annual Review see change log Deleted the objectives of a public awareness program Deleted information about the federal stds. the procedure was developed under. Developed Magellan’s “Commitment to the Program.” Deleted Operator’s responsibility of overseeing and approving budgetary responsibility. Changed OneCall Analyst to OneCall Coordinator Deleted request for address of Contractors form OneCall and documentation of Awareness Program distributed Also requirement to have this information forwarded to Operations Mgr Deleted requirement to establish and maintain the Public Awareness Program and annual review of program Deleted references to National Alliance Programs. Added content for API RP1162 compliance. Added “to determine if additional outreach programs are needed.” added clarified Added retention time and location Rephrased and defined summary report Conducted 2006 Annual Review see change log Added Management Support Documentation: E1 Goals and Management Support Cover Letter Added Effectiveness Evaluation Requirements added added Conducted 2007 Annual Review see change log Moved this to new section entitled, “3.3 Longhorn Specific Requirements:” Added One Call membership requirement in response to PHMSA Clearing House comments Added additional Relevant Factors and clarified direction for Supplemental Outreach Activities in response to PHMSA Clearing House comments Added new wording to this section Conducted 2008 Annual Review see change log Deleted – Monitor activities and determine if additional is needed. Added from E12-Maintain Public Awareness folder and ER Guide. This replaces the previous ERP distribution process Added location for supplemental documentation Added administrator for Longhorn. Moved previous 3.3.1 to 3.3.2 Deleted Operations Manager or Asset Integrity (AI) Supervisor and changed to appropriate area office Added option for website retrieval and retention time. Deleted distribution to Operations Managers/ AI Supervisors Added Manager of Damage Prevention for incorporation into the annual mailings. Deleted distribution to Operations Manager/AI Supervisors Added: Include PA objectives in One-Call newsletter Added: File Supplemental Documents in Livelink folder Moved from SIP 7.08 Changed Title to Mgr of Damage Prevention and Design Services Conducted 2009 Annual Review see change log Changed “Pipeline” to “Public” Changed the title to, “Assets Covered Per Mitigation Plan” <<>> Magellan Midstream Partners, L.P. PUBLIC AWARENESS SIP–ADM–10.01 Community Relations 01/01/12 Page 5 of 5 Date Change Change 07/28/09 3.3.2.3 Hampton 07/28/09 3.3.4 07/28/09 3.3.5 07/28/09 3.4 07/28/09 3.6.2 07/28/09 3.6.4 01/01/11 2.1 3.1 3.1/3.2.2/3.2.7 8/29/11 2.1 8/29/11 3.1 3.1.4 8/29/11 3.2.2 8/29/11 3.2.7.2 12/31/11 All Revision: 8 Brief Description of Change Added “And Design Services” Deleted Section Maintain the information sent from the One Call Coordinator in the Local file for five years Added “For Five Years” This information includes documentation of the Public Awareness activities Deleted Section Added “ And Magellan’s Internal Database” Deleted “Sort this information by operating area and forward to the manager of Damage Prevention and Design Services” Added “Forward Deleted “Include Public Awareness Objectives in the One Call Newsletter.” Added “ Utilize Removed DOT 192 Changed Mgr of Design Services and Compliance to One Call Team Changed title to One Call Team Leader Added list of specific pipeline assets covered by the PAP. Changed title to One Call Supervisor Public Awareness Comm. Spec. Added date Changed title to Public Awareness Comm. Spec. Changed title to Public Awareness Comm. Spec. 2012 Annual Review complete <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 6F SURGE ANALYSIS SUMMARY <<>> Milepost 2.4 2.4 2.4 2.4 12.0 12.0 21.2 21.2 34.1 34.1 34.1 63.8 63.8 64.1 64.1 112.9 112.9 112.9 133.9 133.9 135.5 135.5 139.3 139.3 141.8 FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 6F SURGE ANALYSIS SUMMARY MITIGATIONS UPDATED Valve Description Surge Mitigation ROV 235 (East Houston Terminal) PRV-235 ROV 235 (East Houston Terminal) PRS-01 ROV 236 (East Houston Terminal) PRS-02 ROV 237 (East Houston Terminal) PRS-03 ROV (Mesa Road/FM527) GS5 PRS-01 ROV (Mesa Road/FM527) GS5 PRV-01 ROV (Sweetwater Lane) GS6 PRS-11 ROV (Sweetwater Lane) GS6 PRV-11 Satsuma ROV (GS7) PRS-01 Satsuma MOV2 PRS-02 Satsuma MOV4 PRS-04 Satsuma ROV14 (SE1) PRS-14 Satsuma MOV12 PRS-12 Satsuma MOV13 PRS-13 Satsuma overall PRV-01 ROV (E. Side Brazos River) SE2 PRV-11 ROV (E. Side Brazos River) SE2 PRS-11 ROV (W. Side Brazos River) SE3 PRS-01 ROV (W. Side Brazos River) SE3 PRV-01 ROV (Warda Sta) Incoming SE4 PRS-04 ROV (Warda Sta) Incoming SE5 PRS-05 Warda overall PRV-01 ROV (E. Side Colorado River) SE6 PRV-01 ROV (E. Side Colorado River) SE6 PRS-01 ROV (W. Side Colorado River) SE7 PRS-01 ROV (W. Side Colorado River) SE7 PRV-01 ROV (SH 304) SE 7A (formerly CV8) PRS-01 ROV (SH 304) SE 7A (formerly CV8) PRV-01 Bastrop Control Valve PCV-01 Bastrop Control Valve (Bypass Surge Relief) PRV-01 Bastrop MOV4 PRS-04 Bastrop MOV5 PRS-05 Bastrop MOV6 PRS-06 Bastrop MOV7 PRS-07 Bastrop MOV2 PRS-02 Bastrop MOV3 PRS-03 Bastrop ROV1 PRS-01 Set Pressure 340 psig 340 psig 340 psig 340 psig 650 psig 650 psig 650 psig 650 psig 650 psig 650 psig 650 psig 650 psig 650 psig 650 psig 650 psig 650 psig 650 psig 650 psig 650 psig 625 psig 625 psig 625 psig 650 psig 650 psig 650 psig 650 psig 640 psig 640 psig 646 psig 850 psig 850 psig 850 psig 850 psig 850 psig 850 psig 850 psig 850 psig <<>> Milepost 148.3 148.3 166.7 166.7 171.5 171.5 172.3 172.3 174.9 174.9 175.5 175.5 177.1 177.1 181.6 181.7 185.9 185.9 186.9 186.9 194.3 194.3 198.6 198.6 199.0 199.0 199.6 199.6 203.5 203.5 211.9 211.9 216.6 FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Valve Description Surge Mitigation Set Pressure ROV (FM535) SE7B (formerly CV9) PRS-01 825 psig ROV (FM535) SE7B (formerly CV9) PRV-01 825 psig ROV (U.S. HWY 81) SE8 (East Aquifer) PRS-01 825 psig ROV (U.S. HWY 81) SE8 (East Aquifer) PRV-01 825 psig ROV (Sendera Mesa Drive) (Austin Aquifer) PRS-01 700 psig ROV (Sendera Mesa Drive) (Austin Aquifer) PRV-01 700 psig ROV (Beckett Rd) (Austin Aquifer) PRS-01 700 psig ROV (Beckett Rd) (Austin Aquifer) PRV-01 700 psig ROV (Silver Mtn Road) (Austin Aquifer) PRS-01 680 psig ROV (Silver Mtn Road) (Austin Aquifer) PRV-01 680 psig ROV (Ramble 3 St) (Austin Aquifer) SE9 PRS-01 660 psig ROV (Ramble 3 St) (Austin Aquifer) SE9 PRV-01 660 psig ROV (US HWY 290) (Austin Aquifer) PRS-01 610 psig ROV (US HWY 290) (Austin Aquifer) PRV-01 610 psig Cedar Valley Control Valve PCV-01 660 psig Cedar Valley Control Valve (Bypass Surge Relief) PRV-01 850 psig Cedar Valley High Pressure Shutdown PSH-01 710 psig Cedar Valley MOV8 PRS-08 735 psig Cedar Valley MOV9 PRS-09 735 psig Cedar Valley MOV10 PRS-10 735 psig Cedar Valley ROV6 PRS-06 735 psig Cedar Valley MOV11 PRS-11 850 psig Cedar Valley MOV12 PRS-12 850 psig Cedar Valley MOV13 PRS-13 850 psig ROV (Fitzhugh Creek) (Austin Aquifer) PRS-01 815 psig ROV (Fitzhugh Creek) (Austin Aquifer) PRV-01 815 psig ROV (Oak Forest Drive) (Austin Aquifer) PRS-01 780 psig ROV (Oak Forest Drive) (Austin Aquifer) PRV-01 780 psig ROV (Ulrich Rd) (formerly CV10) PRS-01 840 psig ROV (Ulrich Rd) (formerly CV10) PRV-01 840 psig ROV (E. Side Pedernales River) SE11 PRV-01 900 psig ROV (E. Side Pedernales River) SE11 PRS-01 900 psig ROV (W. Side Pedernales River) SE12 PRS-01 900 psig ROV (W. Side Pedernales River) SE12 PRV-01 900 psig ROV (W. Side Pedernales River) SE4 (formerly CV4) PRS-02 900 psig ROV (W. Side Pedernales River) SE4 (formerly CV4) PRV-02 900 psig ROV (Cypress Mill Rd, CR 301) (formerly CV5) PRS-01 925 psig ROV (Cypress Mill Rd, CR 301) (formerly CV5) PRV-01 925 psig ROV (W Side Sandy School Rd) SE13 (formerly CV6) PRS-01 900 psig ROV(W Side Sandy School Rd) SE13 (formerly CV6) PRV-01 900 psig ROV (W. Side White Oak Creek) SE13A (formerly CV7) PRS-01 775 psig <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL Milepost Valve Description Surge Mitigation Set Pressure 216.6 ROV (W. Side White Oak Creek) SE13A (formerly CV7) PRV-01 775 psig 227.9 ROV (Eckert Sta) SE 14 PRV-01 700 psig 227.9 ROV (Eckert Sta) SE 14 PRS-01 700 psig 276.5 ROV (E. Side Llano River) SE16 PRV-01 820 psig 276.5 ROV (E. Side Llano River) SE16 PRS-01 820 psig 276.8 ROV (W. Side Llano River) SE17 PRS-01 820 psig 276.8 ROV (W. Side Llano River) SE17 PRV-01 820 psig 281.0 ROV (US HWY 377) (formerly CV12) PRS-01 750 psig 281.0 ROV (US HWY 377) (formerly CV12) PRV-01 750 psig 282.6 ROV, SE17A (formerly CV13) PRS-01 680 psig 282.6 ROV, SE17A (formerly CV13) PRV-01 680 psig 295.2 Kimble County Control Valve PCV-01 561 psig Kimble County Control Valve (Bypass Surge Relief) PRV-01 700 psig Kimble County High Pressure Shutdown PSH-01 611 psig Kimble County MOV12 PRS-12 636 psig Kimble County MOV13 PRS-13 636 psig Kimble County MOV14 PRS-14 636 psig Kimble County MOV2 PRS-2 636 psig Kimble County MOV4 PRS-4 636 psig Kimble County ROV (SE19) PRS-1 636 psig Kimble County MOV11 PRS-11 636 psig 324.7 ROV (CR 245) (formerly CV14) PRS-01 850 psig 324.7 ROV (CR 245) (formerly CV14) PRV-01 850 psig 341.7 ROV (W. Side Antelope Draw) SE21A (formerly CV15) PRS-01 850 psig 341.7 ROV (W. Side Antelope Draw) SE21A (formerly CV15) PRV-01 850 psig 346.7 ROV (FM 190) SE21B (formerly CV16) PRS-01 850 psig 346.7 ROV (FM 190) SE21B (formerly CV16) PRV-01 850 psig 457.5 Crane Control Valve PCV-01 853 psig Crane High Pressure Shutdown PSH-01 903 psig 9.5 East Houston Control Valve PCV-293 860 psig East Houston High Pressure Shutdown PSH-293 910 psig 1.8 Holland Ave ROV-107 PRS-107 700 psig 1.8 Holland Ave ROV-107 PRV-107 700 psig 0.9 North Houston Ship Channel ROV-100 PRS-100 700 psig 2.5 Speed Jct ROV-200 PRV-201 700 psig Note: PRV = Pressure Relief Valve PRS = Pressure Reversal Switch PCV = Pressure Control Valve PSH = Pressure Shutdown Switch <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL SURGE ANALYSIS SUMMARY OPERATING PRESSURE SUMMARY Segment Description Pump Station Maximum Discharge Set Pressure (psig) MOP (psig) Maximum Pressure Normal Operations (Steady State) (psig) Maximum Surge Pressure (psig) Crane 853 853 820 550 850 900 Crane (MP 457.54) to MP 415.3 (Texon) MP 415.3 (Texon) to MP 341.6 1034 953 MP 341.6 to MP 295.2 (Kimble County) 853 1012 390 910 MP 295.2 (Kimble County) to MP 181.6 (Cedar Valley) Kimble County 561 959 525 955 MP 181.6 (Cedar Valley) to MP 141.72 (Bastrop) Cedar Valley 660 1012 675 960 Bastrop (PCV MP 141.72 (Bastrop) to MP 112.9 (Warda) only) MP 112.9 (Warda) to MP 69.0 646 965 590 750 MP 69.0 to MP 34.1 (Satsuma) MP 34.1 (Satsuma) to MP 2.4 (East Houston) 646 646 646 1012 1012 786 575 550 540 950 795 750 MP 9.47 (East Houston) to MP 1.21 (9th Ave.) East Houston 860 936 860 925 <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 6G RISK IMPLICATION MATRIX <<>> Pro~ed Action Valve reconfigurations Change hydraulic profile Change in product Change in O&M Station reconfigurations Use of existing System Details Possible Initial Impact on PoF Impact on CoF PoF assumptions Reduction in PoF ext corr change In potential release volumes Reduction in PoF third party drain abn corr < soil corr; hot spot added; no AC issues; no shielding 1,607 rt of pipe replaced at 271ocations Increase in Pof impacts leak detect increase in PoF sabotage impacts>excav exp; mit does not offset impact exp; same pipe wall increase in PoF geotech Reduction in other PoF from removal of anomalies erosion, flood, freeze, windstorm, fire, lightning reverse flow increase in PoF cracking change in toxicity higher viscosity product higher Howrate increase in PoF ext carr Increase in Pof int carr change in hazard zone dimensions change in rupture potential increase in PoF inc ops, incl surge -43 miles>100%SMYS_avail crude oil increase In PoF Inc ops, incl surge sour crude Increase in Pof int corr paraffin formation increase in PoF surge ORA injection paraffin formation increase in PoF inc ops increase in PoF surge int corr control maintenance pigging inhibitor injection Reduction in PoF int corr Monitoring IMP Inhibitor injection change in rupture potential ORA injection change in pumps change in pum~related devices increase in PoF inc ops, inc! surge currently existing weaknesses pre-existing active failure mechanisms increase in all PoF increase rupture potential in possibly-weak areas change In rupture potential -43 miles>100%SMYS_avail <<>> FINAL ENVIRONMENTAL ASSESSMENT OF THE LONGHORN PIPELINE REVERSAL APPENDIX 6H SPARTAN ENGINEERING REPORT <<>> Pipeline Leak Detection Systems - Direct Detection Prepared for: MAGELLAN MIDSTREAM PARTNERS, L.P. October 18, 2011 (R3) By: SPARTAN ENGINEERING INC. <<>> CONTENTS 1.0 Overview 2.0 Executive Summary 3.0 Types of Leak Detection Systems 3.1 General 3.2 Liquid Sensing Leak Detection 3.3 Vapor Sensing Leak Detection 3.4 Fiber Optic Leak Detection 3.5 Ultrasonic/Acoustical Leak Detection 3.6 Comparison 4.0 Conclusions and Recommendations 5.0 Appendix 5.1 Corporate Contact Info 5.2 Tycho Thermal Controls Data 5.3 Asel-Tech Data 5.4 Nitor Technologies Data 5.5 Sensornet Data <<>> 1.0 Overview Magellan is interested in currently available technology for early detection of pipeline leaks that can be employed on the section of the Longhorn pipeline traversing the Edwards Aquifer. Additionally, because the Longhorn Reversal project will introduce crude oil to the line, there is interest in the capability of these systems to adequately detect crude oil. This report focuses on the direct sensing style of pipeline leak detection systems that are most capable of detecting small leaks. The direct methods include liquid sensing cables, fiber optic cables, vapor sensing tubing, and ultrasonic sensing. Information on these direct sensing methods (and companies that can provide them) has been compiled from an extensive search and is included in appendices of this report. <<>> 2.0 Executive Summary Each of the four direct pipeline leak detection technologies investigated will detect crude oil. Direct detection methods are best at detecting leaks that are less than about 0.5% of the pipeline flow rate, while computational methods are best at detecting leaks that are greater than about 0.5% of the pipeline flow. Therefore, to cover all circumstances, it is recommended Magellan maintain both types of systems. For the direct sensing method, it is recommended to retain the existing Tyco TraceTek TT5000 system. It has the advantage of already being in place, it has the ability to detect leaks as small as 0,01 GPH, it can locate leaks accurately, and it has proven to be reliable. The liquid sensing cable systems are the most sensitive for detecting small leaks with a 2-3 hour response time. The existing Tyco TraceTek TT5000 is extremely robust and reliable and capable of detecting leaks as low as 0.01 GPH and is not impacted as much because of soil porosity, soil temperature and low vapor pressure as the other systems reviewed. See Section 3.2 under Tyco TraceTek TT5000 for a detailed discussion. Vapor sensing systems are not as sensitive to small leaks or to leaking materials with very low vapor pressures, such as heavy oils. Additionally, response time is more dependent on soil porosity and soil temperature than the liquid sensing systems. The minimum detectable leak size is 0.04 GPH, in high-sensitivity mode. See Section 3.4 under Nitor Technologies for a detailed discussion. Fiber-optic cable systems and acoustic sensing systems are very poor at detecting small leaks. These units rely on either a change in temperature or an acoustic footprint to detect leaks. These systems are very reliable when detecting leaks of highly volatile liquids but they are not suitable for crude oil since the leak does not develop a sufficient differential temperature (essentially ground temperature) nor does it develop enough acoustic energy to allow the system to reliably detect a small leak. Additionally, the reliability decreases as the vapor pressure of the material to be detected approaches zero. See Section 3.4 Fiber Optic Leak Detection and Section 3.5 Ultrasonic/Acoustical Leak Detection for a brief discussion. <<>> 3.0 Types of Leak Detection Systems 3.1 General The available pipeline leak detection systems (LDS) fall, generally, into two broad classes; 1) discussed because this topic is beyond the scope of this report. Direct detection, and 2) Computational/Statistical. Computational/Statistical will not be API Publication 1149 outlines methods for calculating the size of a leak in terms of the total pipeline flow rate. This leak rate is often described as a percent of the total pipeline flow with the total flow given to estimate the leak size. The direct detection methods are associated with efforts to detect leaks with sensing systems that can locate the leak within a few meters of its origin. These include: 1) Liquid Sensing leak detection, 2) Vapor sensing leak detection, 3) Fiber-optic leak detection, and (4) Ultrasonic/Acoustical leak detection. Direct leak detection depends upon a sensing system in the area around the location that has been deemed to be most sensitive to the effects of a pipeline leak. These detection techniques depend upon a change in some physical property associated with the pipeline, the pipeline surroundings, or changes to a sensor based on some characteristic of the leaking fluid. These can be summarized as: 1) the conductivity (or electrical resistance) of the cable; 2) localized temperature changes; 3) some characteristic physical effect that is always associated with a leak, such as the presence of vapor, or the sound associated with a leak. 3.2 Liquid Sensing Leak Detection Liquid sensing cables are buried beneath or adjacent to a pipeline and are specifically designed to detect changes in transmitted energy pulses as a result of impedance differentials induced by contact with hydrocarbon liquids. Safe energy pulses are continuously sent by a microprocessor through the cable. The pulses are reflected and returned to the micro- processor. Based on the specific installation of the cable, a baseline reflection map is stored in the memory of the microprocessor. When a leak occurs, a portion of the cable is saturated with fluid. The fluid alters the impedance of the sensing cable, which in turn alters the reflection pattern returning to the microprocessor. The change in signal pattern causes the microprocessor to register a leak alarm that also locates the position of the altered impedance. Controller interface software is available to provide real-time information on leak detection and record keeping. Cable types are chosen for each application based on the specific type of fluid being monitored. The cable detects a leak independently of the leak rate and thus is a good choice for small leaks, which are more difficult to detect than large leaks. The sensor cable responds directly to the presence of the liquid and not to the rate at which it arrived. Additionally, the leak detection cable can report the spill location to an accuracy of a few feet. Liquid sensing leak detection is typically marketed as a self-contained leak detection and location system, including all hardware and software. Advantages include relatively high 3 <<>> software configuration and maintenance. accuracy in determining leak location, no modifications to existing pipeline, and simple A system that detects oil leaks based on a change in electrical resistance is the Tyco TraceTek TT5000. The Tyco system can locate leaks to within a few feet of their source. An analysis of the Tyco TraceTek TT5000 leak detection cable currently used on the Longhorn Pipeline System is provided to determine its applicability to a crude oil pipeline. Iyco TraceTek TT5000 Leak Detection Cable The Tyco TraceTek TT5000 leak detection cable currently in use on the Longhorn Pipeline System is usable for detecting crude oil leaks, as demonstrated by Tyco (see Table below). The minimum detectable leak size is 0.01 GPH. The TraceTek cable system is apparently the only electrical conductivity cable available. It should be noted that after a leak is detected by the cable, the portion of the cable that was exposed to the leak must be replaced. Tyco Thermal Controls has performed testing on three different oils, West Texas Intermediate (WTI), West Texas Sour (WTS) and ARCO North Slope Oil. The results of these tests are summarized in the table below. TT5000 Response Time Oil Type Temperature 68°F Temperature 104°F WTI 92 to 93 minutes 15-20 to 22 min WTS 184 to 190 minutes 42 to 45 min ARCO North Slope 180 minutes 42 minutes The results indicate that the TT5000 will respond to the presence of a WTS oil leak within about 3-hours after the sensor cable has been in contact with the oil. In other words, for very small leaks the TT5000 will always set off an alarm. 3.3 Vapor Sensing Leak Detection The Leak Alarm System for Pollutants (LASP) consists of a vapor sensing tube installed along the entire length of the pipeline. This tube is impervious to water but allows petroleum vapors to pass and accumulate. A vacuum pump periodically draws the air from the tube and passes the air stream through a sensor which detects the presence of petroleum vapors. Detectable substances include a wide range of gases, hydrocarbon liquids and vapors, halogenated hydrocarbons, landfill gases, water vapor, and many others. This vapor sensing system has the potential to detect leaks of all sizes; however, very small leaks can take 30 hours or more to detect. The detection tube is manufactured in the form of a cable and is highly permeable to the substances to be detected in the particular application. If a leak occurs, the substances to be measured come into contact with the tube in the form of vapor, or gas dissolved in water. In the event of a leak, some of the leaking substance diffuses into the tube. After a period of time <<>> has passed, enough vapor will accumulate inside the tube so that when the air in the tube is pulled past the detector there will be enough vapor to produce an accurate identification of the substances surrounding the tube. The detector unit at the end of the sensor tube is equipped with gas sensors so that an increase in gas concentration results in a pronounced "leakage peak," which is proportional to the concentration of the vapor from the leaking medium at the sensor tube surface. A disadvantage of the LASP technology is that the time required to draw a vapor slug to the detector will vary substantially because of diurnal and seasonal changes causing decreased leak location accuracy. Nitor Technologies, Inc. PROWLER LDS Nitor Technologies, Inc. carries the PROWLER system and has upgraded the LASP system technology. The published minimum detectable leak size is 0.04 GPH. However, this leak rate is not referenced with a statement about the volatility and temperature of the leaking substance was not specified in the literature. Vapors emitted by the leaking crude oil diffuse into the PROWLER tubing and reach a steady state or equilibrium concentration. The PROWLER pump is then activated to move the vapors in the tubing to the detector, where measurements are made. Depending on soil porosity and oil vapor pressure, several hours may be required for gases and vapors to migrate from the leak site to the PROWLER tubing. To see a change from the baseline condition, a minimum of two runs is needed, each taking as long as 15 minutes. The PROWLER can locate the position of the leak to within 1% of the length of the pipeline. For a twenty mile long section of pipeline, the accuracy would be less than 1100 feet. Using secondary test points, the location of the leak can be determined to within 50 feet. More precise leak location requires that a spike of tracer gas, such as Hydrogen or Ethane, be injected at the front end near the inlet-air dryer unit. For sizeable leaks, the density of the crude oil has little impact on response time. However, at very low leak rates the crude oil and the vapors emitted by the crude oil require more time to move through soil. Very small leaks of a heavy crude oil, as well as the vapors emitted by that oil, will move through the soil much slower than the rates observed for lighter refined products and their vapors to move through the soil. The reliability of vapor sensing systems is lower than the liquid sensing cable systems. The system is prone to set point drift and requires chromatographs that can lose sensitivity unless properly calibrated and maintained. A second sensor tube can be installed that continuously draws a vacuum. This option allows for a more rapid detection of large leaks (greater than 0.5% to 1.00% of flow) while still enabling the detection of small leaks by the periodic removal of the tubing air from the other tube. Operating with two tubes in this manner is recommended by the manufacturer. 3.4 Fiber Optic Leak Detection 5 <<>> The fiber-optic sensing leak detection method involves the installation of a fiber-optic cable along the entire length of the pipeline. The substances to be measured come into contact with the cable when a leak occurs, changing the temperature of the cable. The distributed fiber- optical temperature-sensing technique offers the possibility to measure temperature along the pipeline. Scanning the entire length of the fiber, the temperature profile along the fiber is determined, leading to leak detection. Optical fiber sensor cables have been demonstrated to be useful for the measurement of a wide variety of physical and chemical parameters because they have: 1) an immunity to electromagnetic interference, 2) avoidance of ground loops, 3) capability of responding to a wide variety of measured quantities, 4) avoidance of electric sparks, 5) resistance to harsh environments, 6) remote operation, 7) capability of multiplexing, and 8) ease of integration into large-scale fiber networking and communication systems. The reliability of the optical fiber cables is questionable for long-term use because of their fragility and the possibility of false positive signals caused by the presence of groundwater. For small crude oil leaks under low pressure, the leaking substance will have adequate time to thermally equilibrate with the material that surrounds the pipeline and the thermal sensor. Since the liquids and sensor will be at the same temperature there will be little or no differential temperature for the fiber-optic sensor to determine. This makes the fiber-optic LDS less desirable for crude oil applications. In fact, no reference has been found where fiber optic cable has been used in the determination and location of crude oil leaks from pipelines. Two of the companies that supply fiber-optic based LDS's are Sensornet and Westminster, Intl. The Sensornet Fiber-Optic Based LDS The Sensornet fiber-optic cable system allows the inference of a leak by detecting the change in temperature of the fiber-optic cable when it becomes exposed to the leaking fluid or a change in temperature of the space around the cable caused by the nearby presence of the leaking fluid. To date, the use of Sensornet's leak detection system has been for the detection of leaks on and around highly pressurized natural gas liquid products such as ethane, ethylene, propane, Y-grade products, and ammonia. Westminster, International Fiber-Optic Based LDS Westminster International appears to be in the private sector security business. They propose that their fiber-optic cable systems be used to detect temperature changes caused by NGL's leaking from pipelines and storage tanks. 3.5 Ultrasonic/Acoustical Leak Detection Leak detection in pipelines using acoustic emission technology is based on the principle that an leak occurs, the resulting low frequency acoustic signal is detected and analyzed by system escaping liquid creates an acoustic signal as it passes through a perforation in the pipe. When a processors. Deviations from the baseline acoustic profile would signal an alarm. The received signal is stronger near the leak site, thus enabling leak location. <<>> Asel-Tech Asel-Tech has developed an acoustic/mass-balance/computational LDS that holds the possibility of improving the computational technology. Response time can be as short as a minute for leaks that are large enough to be acoustically detectable; however, the system's ability to detect small leaks is greatly reduced in low vapor pressure liquids that cannot generate sufficient acoustic energy to be detected over background noise. 3.6 Comparison The following table summarizes the properties of the various direct leak detection systems: Leak Detection Response Time Detectable Leak Size System Tyco The detection response time is not dependent Leak rates lower than 0.01 GPH TraceTek upon the leak rate. It is dependent upon the soil are detectable over a long TT5000 Leak Detection porosity and the substance temperature. From period of time. The cable is the data supplied by Tyco for Magellan: the responsive to both small and Cable response time for the WTS heavy crude is about large leaks. Response is not 45 minutes at 104°F and 190 minutes at 68°F; and for WTI light crude about 22 minutes at 68°F and dependent on the leak rate. The TT5000 is immune to the 93 minutes at 68°F. As a comparison, response presence of water. times for data done by Tyco for Arco on their North Slope crude: 42 minutes at 104°F and 180 minutes at 68°F. Leak location is typically within "a few meters" of the leak. Nitor Vapor Sensing The detection response time is dependent upon the leak rate, the soil porosity, and System - the oil volatility. In the high speed mode the system can detect leaks of 600 to 1300 High Speed GPH within a few hours. Large leaks, 12600 GPH or larger, can be detected in less Mode than 30 minutes. Additional response time factors include calibration frequency and the type and sensitivity of the chromatograph. The maximum detectable leak has no upper limit. The system is immune to the presence of water. Nitor Vapor As with the high speed mode, the detection response time is dependent upon the Sensing leak rate, the soil porosity, calibration frequency, and the oil volatility. In the high System - sensitivity mode detection time for the PROWLER is determined by the system's High setup parameters but is often given as 12 hours. While the published minimum Sensitivity detectible leak rate is about 0.04 GPH the response time for this small leak rate may Mode be as long or longer than 30 days. The system is immune to the presence of water. Fiber Optic The leak detection time for a fiber optic system Fiber optic LDS is responsive to Leak depends upon the time required for the leak to both small and large leaks. Detection - cause a temperature change in the cable. Response time is dependent on Sensornet Response times are very fast for high volatility the vapor pressure of the and West- fluids like ethane, but for small low pressure leaking material and on the leak minster crude oil leaks there may not be a response. rate. 7 <<>> Detection Leak Response Time Detectable Leak Size System Hybrid Asel-Tech has developed Computa- an acoustic/mass- Leaks less than about 0.1% of tional LDS - balance/computational LDS that holds the possibility of improving the computational total flow may not be detected. Leaks that are greater than 0.5% Asel-Tech technology. Response time can be as short as a minute for leaks that are large enough to be to 1% of total flow can be acoustically detectable. detected. 4.0 Conclusions and Recommendations Each of the four direct pipeline leak detection technologies investigated will detect crude oil. For small leaks that are less than about 0.1% to 0.5% of the total pipeline flow rate, the TraceTek T15000 is the most sensitive to crude oil. The Prowler vapor sensing system can also detect oil but its response time will be slower than the TT5000 because the loss of sensitivity associated with low vapor pressure crude oil. For leaks that are greater than 0.5% to 1% of the total pipeline flow rate, the fiber-optic cable and acoustic detection systems provide the fastest response time, giving indication of a leak in less than a minute after being contacted by the leaking substance. However, the Sensornet and Westminster fiber-optic systems may be less sensitive to crude oil than the other three leak detection systems because there will be little if any temperature change associated with a leak from a low pressure crude oil pipeline. Acoustic leak detection systems are also hampered by crude oil at low pressures because small leaks will not generate enough acoustic energy to be detected over the background noise. Because direct detection methods are best at detecting leaks that are less than 0.5% of the pipeline flow rate, and while computational methods are best at detecting leaks that are greater than about 0.5% of the pipeline flow, it is recommended that Magellan maintain both types of systems. For the direct sensing method, it is recommended to retain the existing Tyco Trace-Tech system. It has the advantages of already being in place, it can pinpoint the leak accurately, and has been proven to be reliable. The Nitor system is not recommended for detecting small leaks because the response time due to the low volatility crude oil is too great to detect them in a timely manner. The Sensornet, Westminster, and Asel-Tech systems are not recommended for use in detecting small leaks from low pressure crude oil applications for the reasons noted in section 3.4, above. 8 <<>> 5.0 Appendix 5.1 Corporate Contact Information Tyco Thermal Controls LLC 2415 Bay Road Redwood City, CA 94063-3032 Tel: (800) 545-6258 Fax: (650) 474-7215 TraceTek TT5000 http://www.tycothermal.com/ Asel-Tech Sao Carlos, Brazil Brazilian Corporation USA (281) 619-5754 USA (281) 990-2574 http://asel-tech.com/ Nitor Technologies, Inc. PROWLER 2750 Constitution Boulevard Beaver Falls, Pennsylvania 15010 Telephone (724) 891-4115 Fax (724) 847-6444 http://www.nitortechnologies.com/ Sensornet (British Company) 2002 Timberloch PL Suite 200, The Woodlands TX 77380, USA Alan Sanderson Ph: +1 281-296-5827 alan.sanderson@tendeka.com http://www.sensornet.co.uk/ Westminster, International, Ltd Banbury Westminster House, Blacklocks Hill Oxfordshire OX17 2BS United Kingdom +44 (0) 1295 756300 Phone +44 (0) 1295 756302 Fax www.wi-ltd.com Use website to make contact 9 ## Provenance - Official: Yes - Source: - Source ID: `regulations-gov` - SHA-256: `867a08a0d87e3c73603a84ed45bc77dd3d1aadfc0ebddecd97b366ea66253f94` - Retrieved: 2026-08-20T02:22:46.679Z - Exported: 2026-08-25T07:18:47.651Z - Document slug: `regulations-gov-attachment-09000064811add8f` ### Source metadata ```json { "materialSubtype": "regulations_gov_agency_attachment", "parentDocumentId": "regulations-gov-document-phmsa-2012-0175-0072", "regulationsGovDocumentId": "PHMSA-2012-0175-0072", "docketId": "PHMSA-2012-0175", "attachmentId": "09000064811add8f", "format": "pdf", "authorshipClass": "agency_authored", "rightsClass": "federal_work", "ingestionDecision": "ingest", "decisionBasis": [ "organization:U.S. DOT/PHMSA", "title:U.S. DOT/PHMSA - Final Environmental Assessment of the Longhorn Pipeline Reversal - Volume 1 of 2: Chapters 1-6" ], "summaryEligibility": "eligible", "jurisdiction": "US" } ```