Failure Report- Panhandle Eastern Pipeline Co 8/25/08

Page 1Official PDFPipeline System: Houstonia 200 Line Pipeline Failure Investigation Report Operator: Panhandle Eastern Pipeline Company, LP Location: Mile Post 21.6 Medium Released: Natural gas Date of Occurrence: 8/25/2008 Quantity: 13,518,578 CF PHMSA Arrival Time & Date: 8/25/08 1:00 p.m. Total Damages $ 1,046,359 Investigation Responsibility: State PHMSA NTSB Other Company Reported Apparent Cause: Corrosion Excavation Natural Forces Incorrect Operation Other Outside Force Damage Material and/or Welds Equipment and Operations Other Rupture Yes No Leak Yes No Fire Yes No Explosion Yes No Evacuation Yes No Number of Persons Area Narrative Summary Short summary of the Incident/Accident which will give interested persons sufficient information to make them aware of the basic scenario and facts. Panhandle Eastern Pipeline Company (PEPL) experienced failure of the Houstonia 200 line near Mile Post 21.6. There were no evacuations, road closings, fires, injuries or fatalities as a result of the failure. The failure did not occur in a high consequence area (HCA). The failure occurred on August 25, 2008, at approximately 8:51 a.m. CDT. The failure is located on a rocky hillside in a rural area west of Pilot Grove, Missouri in Cooper County. The failure was identified by PEPL when Houston Gas Control detected a pressure drop in the Houstonia 200 Line. The failure was located at approximately 9:00 a.m. when a PEPL field technician reported gas blowing near Mile Post 21.6. PEPL isolated the segment at approximately 9:30 a.m., by manually closing mainline valves 2 Gate and 3 Gate. The distance between 2 Gate and 3 Gate is approximately 16 miles. The pipeline experienced a longitudinal rupture in the pipe body. The rupture created a 50 feet by 33 ft by 7 feet deep crater in the ground. Two pipeline segments totalling 28 feet in length and a coupling were ejected from the crater a distance up to 300 feet from the rupture site. The failure origin was a 16 inch long area of reduced wall thickness located at the 6:00 orientation. The portion of the pipeline containing the failure is comprised of 24-inch diameter by 0.281-inch wall thickness, API 5L-X48, manufactured by A.O. Smith and contains a longitudinal electric flash welded (EFW) seam. The reported maximum allowable operating pressure (MAOP) is 800 psig, which corresponds to 71% of the specified minimum yield strength (SMYS). The pressure at the time and location of failure was 795 psig, which corresponds to 70% of the SMYS (99% of MAOP). The MAOP was established in accordance with 192.619 ( c ), the highest actual operating pressure to which the segment was subjected during the five years preceding July 1, 1970. A hydrostatic test of the pipeline was performed in 1955. Details of the hydrostatic test are unknown. The pipeline, installed in 1937, is joined by circumferential girth welds and Dresser couplings. The pipeline external coating is coal tar. The pipeline has an impressed curent cathodic protection system that was reportedly energized in 1955. The findings of PEPL's investigation are as follows: 1) The failure occurred due to tensile overload at a region of wall thinning caused by external corrosion. 2) The maximum wall loss measured at the rupture surface was 0.21 inches depth (75% of wall thickness). - 1 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 2Pipeline Failure Investigation Report PEPL submitted a return to service plan to PHMSA that included a temporary 20% pressure reduction and remediation of anomalies found in a high resoultion MFL tool run. They subsequently remediated 30 anomalies with RPR less than 1.15 and replaced 912 feet of pipe. On 12/19/2009 the temporary pressure restriction was removed. ACTIVITY #: 122653 OPERATOR ID #: 15105 UNIT ID #: 4093 NRC REPORT #: 881717 INCIDENT REPORT # (FORM 7100.2): 20090030 -- 5319 Region/State __Central _______________________ Reviewed by: __David Barrett __original initialed _______ Principal Investigator: _Roger Sneegas________ Title: __Director – Central Region___________________ Date: _10/12/2010 ________________________ Date: __10/13/2010 _________________________ - 2 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 3Pipeline Failure Investigation Report Failure Location & Response Location (City, Township, Range, County/Parish): Pilot Grove, Missouri (Acquire Map) Address or M.P. on Pipeline: 21.6 (1) Type of Area (Rural, City): Rural (1) Date: 8/25/2008 Time of Failure: 8:51 a.m. Time Detected: 9:00 a.m. Time Located: 9:10 a.m. How Located: A technician - Jerry Miller - heard the pipeline blowing from the nearest road at about 9:00 a.m. Gas control had previously noted a pressure drop at 8:51 a.m. NRC Report #: 881717 (Attach Report) Time Reported to NRC: 10:15 a.m. on 8/25/2008 Type of Pipeline: Reported by: Liz Rutherford Gas Distribution Gas Transmission Hazardous Liquid LNG LP Interstate Gas Interstate Liquid LNG Facility Municipal Intrastate Gas Intrastate Liquid Public Utility Jurisdictional Gas Gathering Offshore Liquid Master Meter Offshore Gas Jurisdictional Liquid Gathering Offshore Gas - High H2S CO2 Pipeline Configuration (Regulator Station, Pump Station, Pipeline, etc.): Mainline Houstonia 200 Operator/Owner Information Owner: Panhandle Eastern Pipeline Address: 5444 Westheimer Road Houston TX Company Official: Eric Amundsen Phone No.: 713-989-7460 Fax No.: Operator: Panhandle Eastern Pipeline Address: 5444 Westheimer Road Houston TX Company Official: Eric Amundsen Phone No. 713-989-7460 Fax No. Drug and Alcohol Testing Program Contacts Drug Program Contact & Phone: Brett Laaser Alcohol Program Contact & Phone: 713-989-7549 N/A Damages Product/Gas Loss or Spill(2) 13,518,578 CF Estimated Property Damage $ 25,000 Amount Recovered 0 Associated Damages(3) $ 628,063 1 Photo documentation 2 Initial volume lost or spilled 3 Including cleanup cost - 3 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 4Pipeline Failure Investigation Report Damages Estimated Amount $ 393,296 Description of Property Damage: The failure caused a crater in the right-of-way measuring about 50 X 33 feet and 7 feet deep. Two segments of pipe (46 feet total) were ejected from the crater. Customers out of Service: Yes No Number: Suppliers out of Service: Yes No Number: Fatalities and Injuries Fatalities: Yes No Company: Contractor: Public: Injuries - Hospitalization: Yes No Company: Contractor: Public: Injuries - Non-Hospitalization: Yes No Company: Contractor: Public: Total Injuries (including Non-Hospitalization): Company: Contractor: Public: Name Job Function Yrs w/ Comp. Yrs. Exp. Type of Injury Drug/Alcohol Testing N/A Were all employees that could have contributed to the incident, post-accident tested within the 2 hour time frame for alcohol or the 32 hour time frame for all other drugs? Yes No Results Job Function Test Date & Time Location Type of Drug Pos Neg Gas System Controller 8/25/2008 Houston TX - 4 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 5Pipeline Failure Investigation Report System Description Describe the Operator's System: The Houstonia 200 line runs from Liberal KS to Howell MI. It is 24-inch diameter 0.281-inch wall X48 pipe installed in 1937. Pipe Failure Description N/A Length of Failure (inches, feet, miles): 46 feet (1) Position (Top, Bottom, include position on pipe, 6 O'clock): Bottom 6 O'clock (1)  Description of Failure (Corrosion Gouge, Seam Split): (1) External corrosion. Laboratory Analysis: Yes No Performed by: CC Technologies Inc. Preservation of Failed Section or Component: Yes No If Yes - Method: Wrapped In Custody of: Panhandle Develop a sketch of the area including distances from roads, houses, stress inducing factors, pipe configurations, etc. Bar Hole Test Survey Plot should be outlined with concentrations at test points. Direction of Flow. Component Failure Description N/A Component Failed: (1) Manufacturer: Model: Pressure Rating: Size Other (Breakout Tank, Underground Storage): Pipe Data N/A Material: steel Wall Thickness/SDR: 0.281- inch Diameter (O.D.): 24-inch Installation Date: 1937 SMYS: 48,000 Manufacturer: A. O. Smith Longitudinal Seam: Electric Flash Weld Type of Coating: Coal Tar Pipe Specifications (API 5L, ASTM A53, etc.): API 5L, X48 Joining N/A Type: Girth weld with Coupling every other joint Procedure: NDT Method: Unknown Inspected: Yes No - 5 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 6Pipeline Failure Investigation Report Pressure @ Time of Failure @ Failure Site N/A Pressure @ Failure Site: 795 psig at the Houstonia Station Elevation @ Failure Site: 660 Pressure Readings @ Various Locations: Direction from Failure Site Location/M.P./Station # Pressure (psig) Elevation (ft msl) Upstream Downstream N/A Upstream Pump Station Data N/A Type of Product: API Gravity: Specific Gravity: Flow Rate: Pressure @ Time of Failure (4) Distance to Failure Site: High Pressure Set Point: Low Pressure Set Point: Upstream Compressor Station Data N/A Specific Gravity: .55 Flow Rate: Pressure @ Time of Failure (4) 795 psig Distance to Failure Site: 21.6 miles High Pressure Set Point: 830 psig Low Pressure Set Point: Operating Pressure N/A Max. Allowable Operating Pressure: 800 psig Determination of MAOP: 192.619 (c) Actual Operating Pressure: 795 psig Method of Over Pressure Protection: Engine safeties - first engine speed and torque, then shutdown. Relief Valve Set Point: 830 psig Capacity Adequate? Yes No Integrity Test After Failure N/A Pressure Test Conducted in place? (Conducted on Failed Components or Associated Piping): Yes No If NO, Tested after removal? Yes No Method: N/A Describe any failures during the test. Soil/water Conditions @ Failure Site N/A Condition of and Type of Soil around Failure Site (Color, Wet, Dry, Frost Depth): Dry and very rocky Type of Backfill (Size and Description): Rock 4 Obtain event logs and pressure recording charts - 6 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 7Pipeline Failure Investigation Report Soil/water Conditions @ Failure Site N/A Type of Water (Salt, Brackish): N/A Water Analysis (5) Yes No External Pipe or Component Examination N/A External Corrosion? Yes No (1) Coating Condition (Disbonded, Non-existent): Coal tar - some disbonded (1) Description of Corrosion: The failed pipeline segments showed multiple areas of external corrosion with reduced wall thickness. Description of Failure Surface (Gouges, Arc Burns, Wrinkle Bends, Cracks, Stress Cracks, Chevrons, Fracture Mode, Point of Origin): A 23 foot section of pipe was ejected and completely ruptured by the failure. Chevrons along the rupture pointed toward the origin in an area of external corrosion with reduced wall thickness. Above Ground: Yes No (1) Buried: Yes No (1) Stress Inducing Factors: (1) Depth of Cover: 6 feet (1) Cathodic Protection N/A P/S (Surface): Readings taken this Spring were adequate - > .85 V - Recent reading in the area -2.1 V 3/26/08 P/S (Interface): Not taken Soil Resistivity: No soil - rock pH: Date of Installation: 1955 Method of Protection: Rectifiers Did the Operator have knowledge of Corrosion before the Incident? Yes No How Discovered? (Close Interval Survey, Instrumented Pig, Annual Survey, Rectifier Readings, ECDA, etc): A close interval survey was performed in 2000 from 2 Gate to 3 Gate. Some areas of low pipe to soil potential were found but not in the area of the failure. See Appendix D. Internal Pipe or Component Examination N/A Internal Corrosion: Yes No (1) Injected Inhibitors: Yes No Type of Inhibitors: N/A Testing: Yes No Results (Coupon Test, Corrosion Resistance Probe): N/A Description of Failure Surface (MIC, Pitting, Wall Thinning, Chevrons, Fracture Mode, Point of Origin): The cause of the failure was external corrosion with reduced wall thickness. Cleaning Pig Program: Yes No Gas and/or Liquid Analysis: Yes No 5 Attach copy of water analysis report - 7 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 8Pipeline Failure Investigation Report Internal Pipe or Component Examination N/A Results of Gas and/or Liquid Analysis (6) N/A Internal Inspection Survey: Yes No Results (7) ILI had been scheduled but not done. Did the Operator have knowledge of Corrosion before the Incident? Yes No How Discovered? (Instrumented Pig, Coupon Testing, ICDA, etc.): N/A Outside Force Damage N/A Responsible Party: Telephone No.: Address: Work Being Performed: Equipment Involved: (1) Called One Call System? Yes No One Call Name: One Call Report # (8) Notice Date: Time: Response Date: Time: Details of Response: Was Location Marked According to Procedures? Yes No Pipeline Marking Type: (1) Location: (1) State Law Damage Prevention Program Followed? Yes No No State Law Notice Required: Yes No Response Required: Yes No Was Operator Member of State One Call? Yes No Was Operator on Site? Yes No Did a deficiency in the Public Awareness Program contribute to the accident? Yes No Is OSHA Notification Required? Yes No 6 Attach copy of gas and/or liquid analysis report 7 Attach copy of internal inspection survey report 8 Attach copy of one-call report - 8 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 9Pipeline Failure Investigation Report Natural Forces N/A Description (Earthquake, Tornado, Flooding, Erosion): Failure Isolation N/A Squeeze Off/Stopple Location and Method: Panhandle isolated the failure by manually closing 2 Gate and 3 Gate. (1) Valve Closed - Upstream: 2 Gate Time: 9:38 AM I.D.: M.P.: 12.97 Valve Closed - Downstream: 3 Gate Time: 9:23 I.D.: M.P.: 28.43 Pipeline Shutdown Method: Manual Automatic SCADA Controller ESD Failed Section Bypassed or Isolated: Isolated Performed By: Field Tech. Valve Spacing: 16 miles Odorization N/A Gas Odorized: Yes No Concentration of Odorant (Post Incident at Failure Site): Method of Determination: Yes No % LEL: Yes No % Gas In Air: Yes No Time Taken: Yes No Was Odorizer Working Prior to the Incident? Type of Odorizer (Wick, By-Pass): Yes No Odorant Manufacturer: Model: Type of Odorant: Amount Injected: Monitoring Interval (Weekly): Odorization History (Leaks Complaints, Low Odorant Levels, Monitoring Locations, Distances from Failure Site): - 9 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 10Pipeline Failure Investigation Report Odorization N/A Weather Conditions N/A Temperature: 85 F Wind (Direction & Speed): light Climate (Snow, Rain): Sunny Humidity: Was Incident preceded by a rapid weather change? Yes No Weather Conditions Prior to Incident (Cloud Cover, Ceiling Heights, Snow, Rain, Fog): Clear Gas Migration Survey N/A Bar Hole Test of Area: Yes No Equipment Used: Method of Survey (Foundations, Curbs, Manholes, Driveways, Mains, Services) (9) (1) Environment Sensitivity Impact N/A Location (Nearest Rivers, Body of Water, Marshlands, Wildlife Refuge, City Water Supplies that could be or were affected by the medium loss): (1) OPA Contingency Plan Available? Yes No Followed? Yes No Class Location/High Consequence Area N/A Class Location: 1 2 3 4 Determination: HCA Area? Yes No N/A Determination: Odorization Required? Yes No N/A Pressure Test History N/A (Expand List as Necessary) 9 Plot on site description page - 10 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 11Pipeline Failure Investigation Report Pressure Test History N/A (Expand List as Necessary) Req’d (10)Assessment Deadline Date Test Date Test Medium Pressure (psig) Duration (hrs) % SMYS Installation N/A Next N/A 1955 Water Unknown Unknown Unknown Next Most Recent Describe any problems experienced during the pressure tests. Hydrostatic test done in 1955 - details unknown. Internal Line Inspection/Other Assessment History N/A (Expand List as Necessary) Req’d (10) Assessment Deadline Date Assessment Date Type of ILI Tool (11) Other Assessment Method (12) Indicated Anomaly If yes, describe below Initial 2012 Yes No Next Yes No Next Yes No Most Recent Yes No Describe any previously indicated anomalies at the failed pipe, and any subsequent pipe inspections (anomaly digs) and remedial actions. Not scheduled until 2012. Not in top 50%. Gauge tool run already. Pre-Failure Conditions and Actions N/A Was there a known pre-failure condition requiring (10) the operator to schedule evaluation and remediation? Yes (describe below or on attachment) No If there was such a known pre-failure condition, had the operator established and adhered to a required (10) evaluation and remediation schedule? Describe below or on attachment. Yes No N/A Prior to the failure, had the operator performed the required (10) actions to address the threats that are now known to be related to the cause of this failure? Yes No N/A List below or on an attachment such operator-identified threats, and operator actions taken prior to the accident. Describe any previously indicated anomalies at the failed pipe, and any subsequent pipe inspections (anomaly digs) and remedial actions. N/A Maps & Records N/A 10 As required of Pipeline Integrity Management regulations in 49CFR Parts 192 and 195 11 MFL, geometry, crack, etc. 12 ECDA, ICDA, SCCDA, “other technology,” etc. - 11 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 12Pipeline Failure Investigation Report Are Maps and Records Current? (13) Yes No Comments: Leak Survey History N/A Leak Survey History (Trend Analysis, Leak Plots): Leak survey on 6/25/2007. No leaks were found in the area of the failure. Pipeline Operation History N/A Description (Repair or Leak Reports, Exposed Pipe Reports): N/A Did a Safety Related Condition Exist Prior to Failure? Yes No Reported? Yes No Unaccounted For Gas: None before the incident. Over & Short/Line Balance (24 hr., Weekly, Monthly/Trend): Operator/Contractor Error N/A Name: Job Function: Title: Years of Experience: Training (Type of Training, Background): Was the person “Operator Qualified” as applicable to a precursor abnormal operating condition? Yes No N/A Was qualified individual suspended from performing covered task Yes No N/A Type of Error (Inadvertent Operation of a Valve): Procedures that are required: Actions that were taken: Pre-Job Meeting (Construction, Maintenance, Blow Down, Purging, Isolation): Prevention of Accidental Ignition (Tag & Lock Out, Hot Weld Permit): Procedures conducted for Accidental Ignition: Was a Company Inspector on the Job? Yes No Was an Inspection conducted on this portion of the job? Yes No 13 Obtain copies of maps and records - 12 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 13Pipeline Failure Investigation Report Operator/Contractor Error N/A Additional Actions (Contributing factors may include number of hours at work prior to failure or time of day work being conducted): Training Procedures: Operation Procedures: Controller Activities: Name Title Years Experience Hours on Duty Prior to Failure Shift Alarm Parameters: High/Low Pressure Shutdown: Flow Rate: Procedures for Clearing Alarms: Type of Alarm: Company Response Procedures for Abnormal Operations: Over/Short Line Balance Procedures: Frequency of Over/Short Line Balance: Additional Actions: Additional Actions Taken by the Operator N/A Make notes regarding the emergency and Failure Investigation Procedures (Pressure reduction, Reinforced Squeeze Off, Clean Up, Use of Evacuators, Line Purging, closing Additional Valves, Double Block and Bleed, Continue Operating downstream Pumps): - 13 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 14Pipeline Failure Investigation Report Additional Actions Taken by the Operator N/A The failure was detected by Gas Control in Houston at 8:51 a.m. on 8/25/2008. Field crews located the failure at 9:10 a.m. The failure was isolated by closing valves at about 9:30 a.m. Panhandle sent a team to investigate the failure on 8/26/08. After the initial investigation, the pipeline was repaired and returned to service at 80% of the pressure at the time of the incident (795 psi) pending the results of the investigation. - 14 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 15Pipeline Failure Investigation Report Photo Documentation (1) Overall Area from best possible view. Pictures from the four points of the compass. Failed Component, Operator Action, Damages in Area, Address Markings, etc. Photo No. Description Roll No. Photo No. Description Roll No. 1 View looking west at the crater 1 2 East view of exposed pipe in crater 2 3 West view of exposed pipe in crater 3 4 View of longer ejected pipe segment 4 5 Close view of longer segment 5 6 View of shorter ejected segment 6 7 Another view of shorter segment 7 8 Possible failure origin on shorter segment 8 9 Side view of possible failure. 9 10 View of coupling ejected into the woods 10 11 Close up of corrosion at possible failure origin. 11 12 View of another area of external corrosion near the failure origin 12 13 View of failure origin after the pipe was moved. 13 14 14 15 15 16 16 17 17 18 18 19 19 20 20 21 21 22 22 23 23 24 24 25 25 26 26 27 27 28 28 29 29 30 30 Type of Camera: - 15 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 16Pipeline Failure Investigation Report Photo Documentation (1) Film ASA: Video Counter Log (Attach Copy): Additional Information Sources Agency Name Title Phone Number Police: Cooper County Sheriff Fire Dept.: Pilot Grove Fire Dept State Fire Marshall: State Agency: Missouri DOT Emergency Response Team NTSB: EPA: FBI: ATF: OSHA: Insurance Co.: FRA: MMS: Television: No Newspaper: Other: - 16 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 17Pipeline Failure Investigation Report Persons Interviewed Name Title Phone Number Brad Howard Operations Specialist 660-568-1221 Mike Dawson Steve Atkinson Technical Specialist Jerry Rau Director Pipeline Integrity 913-906-1522 713-989-7417 Rob Wesch Liz Rutherford Brian Kraft Measurement Tech Dan Corpening Area Director Ross Cummins CP Tech Richard Gifford Corrosion Tech Gerald Moore Environmental Coordinator - 17 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 18Pipeline Failure Investigation Report Event Log Sequence of events prior, during, and after the incident by time. (Consider the events of all parties involved in the incident, Fire Department and Police reports, Operator Logs and other government agencies.) Time Event 8:51 a.m. 8/25/08 Gas Control detects a pressure drop on the Houstonia 200 line and asks field techs to check for a leak. 9:00 a.m. Filed techs hear blowing gas near mile post 21.6 9:10 a.m. Field techs locate the failure 9:23 a.m. 3 Gate at MP 28.43 is closed manually 9:38 a.m. 2 Gate at MP 12.97 is closed manually 9:00 -11:00 a.m. Panhandle, Fire and police check the area to see if evacuations are necessary 1:00 p.m. PHMSA investigator arrives on site. 1:00 - 8:00 p.m. Investigation by PHMSA and Panhandle 12:00 p.m. 8/26 Panhandle investigation team from Houston arrives 12:00 - 7:00 p.m. Investigation of the failure site by PHMSA and Panhandle. - 18 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 19Pipeline Failure Investigation Report Investigation Contact Log Time Date Name Description 1:00 p.m. 8/26/08 Brad Howard Operations Specialist 1:30 p.m. 8/26/08 Steve Atkinson Technical Specialist 12:00 p.m. 8/27/08 Jerry Rau Director Pipeline Integrity 1:00 p.m. 8/26- 10/20 Brad Howard Follow up on various issues 10:00 a.m. 9/26/08 David McQuilling Principal Engineer - conference call on cathodic protection 10:00 a.m. 9/26/08 Steve Atkinson Same conference call. - 19 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 20Pipeline Failure Investigation Report Failure Investigation Documentation Log Operator: Unit #: CPF #: Date: Appendix Number Documentation Description Date FOIA Received Yes No A Investigation Pictures 8/25/08 X B Panhandle Incident Report 9/18/08 X C Panhandle Laboratory Failure Analysis 10/29/08 X D Panhandle Close Interval Survey 9/18/08 X - 20 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 21Pipeline Failure Investigation Report Site Description Provide a sketch of the area including distances from roads, houses, stress inducing factors, pipe configurations, etc. Bar Hole Test Survey Plot should be outlined with concentrations at test points. Photos should be taken from all angles with each photo documented. Additional areas may be needed in any area of this guideline. The Failure location was about two miles northwest of Pilot Grove (Cooper County) Missouri near Highway HH. The location was near milepost 21.6 on the Houstonia 200 line on a rocky hillside in a rural area. No structures were close to the failure location. The following page shows a sketch of the location provided by Panhandle. The image below shows the Panhandle system map. Panhandle Eastern Pipe Line Company, LP Panhandle Eastern Pipe Line Company operates a 6,500-mile pipeline system with access to diverse supply sources and can deliver 2.8 Bcf/d of natural gas to Midwest and East Coast markets. Tie-ins to Chicago, Dayton and Cincinnati have added to a Midwest customer base that includes some of the nation's largest utility and industrial natural gas users. We lead the way in offering competitive rates and a constantly evolving array of customer-friendly service options. Panhandle Eastern provides:  Access to diverse Midcontinent and Canadian supply sources and to major Midwest and Northeast markets.  Access to 74 Bcf of storage facilities. To request a receipt and delivery point map, please contact Customer Service at 1-800-275-7375. - 21 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 22Pipeline Failure Investigation Report - 22 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 23Pipeline Failure Investigation Report Appendix A Houstonia 200 failure Pictures – 8/25/08 near Pilot Grove MO. - 23 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 24Pipeline Failure Investigation Report 8/25/08 – #1- views looking West at the crater caused by the Houstonia 200 failure. - 24 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 25Pipeline Failure Investigation Report 8/25/08 #2 - East view of the exposed pipe. 8/25/08 #3 -West close up. - 25 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 26Pipeline Failure Investigation Report 8/25/08 #4 - One of two pipe sections ejected – the longer one – about 30 feet. 8/25/08 #5 -Closer view of the longer ejected section. - 26 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 27Pipeline Failure Investigation Report 8/25/08 #6 -View of the shorter section ejected – about 23 feet – ruptured full length. 8/25/08 #7 -Another view of same looking north. - 27 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 28Pipeline Failure Investigation Report #8 - Areas with external corrosion and reduced wall thickness – possible failure origin. 8/25/08 #9 -Side view of the failure origin site with reduced wall thickness. - 28 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 29Pipeline Failure Investigation Report 8/25/08 #10 -View of coupling ejected from pipeline. 8/25/08 #11 -Close up of external corrosion on the possible origin site. - 29 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 30Pipeline Failure Investigation Report 8/25/08 #12 - Another area of external corrosion on the shorter section near the possible failure. 8/26/08 #13 -Different view of the possible failure origin after the pipe was turned over. - 30 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 31Pipeline Failure Investigation Report Appendix B Panhandle Incident Report - 31 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 32NOTICE: This report is required by 49 CFR Part 191. Failure to report can result in a civil penalty not to exceed $25,000 for each violation for each day that such violation persists except that the maximum civil penalty shall not exceed $500,000 as provided in 49 USC 1678. Form Approved OMB No. 2137-0522 U.S. Department of Transportation Research and Special Programs Administration INCIDENT REPORT - GAS TRANSMISSION AND GATHERING SYSTEMS Report Date No. (DOT Use Only) INSTRUCTIONS Important: Please read the separate instructions for completing this form before you begin. They clarify the information requested and provide specific examples. If you do not have a copy of the instructions, you can obtain one from the Office Of Pipeline Safety Web Page at http://ops.dot.gov . Nearest street or road City and County or Parrish a. b. c. State and Zip Code d. Mile Post/Valve Station e. Survey Station No. f. Latitude: Longitude: (if not available, see instructions for how to provide specific location) g. Class location description Onshore: Class 1 Class 2 Class 3 Class 4 Offshore: Class 1 (complete rest of this item) Area ___________________ Block # ___________ State / / or Outer Continental Shelf h. Incident on Federal Land other than Outer Continental Shelf Yes No i. Is pipeline Interstate Yes No 4. Type of leak or rupture Leak: Pinhole Connection Failure (complete sec. F5) Puncture, diameter (inches) Rupture: Circumferential – Separation Longitudinal – Tear/Crack, length (inches) Propagation Length, total, both sides (feet) N/A Other: PART A – GENERAL REPORT INFORMATION Operator Name and Address Original Report Supplemental Report Final Report a. Operator's 5-digit Identification Number (when known) / / b. If Operator does not own the pipeline, enter Owner’s 5-digit Identification Number (when known) / / c. Name of Operator ______________________________ _______________________________________________________ d. Operator street address ________________________________________________________________________________________ e. Operator address _______________________ City, County or Parrish, State and Zip Code 2. Time and date of the incident / / / / / / / / hr. month day year 3. Location of incident 5. Consequences (check and complete all that apply) a. Fatality Total number of people: / / Employees: / / General Public: / / Non-employee Contractors: / / b. Injury requiring inpatient hospitalization Total number of people: / / Employees: / / General Public: / / Non-employee Contractors: / / c. Property damage/loss (estimated) Total $ Gas loss $ Operator damage $ Public/private property damage $ d. Release Occurred in a ‘High Consequence Area’ e. Gas ignited – No explosion f. Explosion g. Evacuation (general public only) / / people Reason for Evacuation: Emergency worker or public official ordered, precautionary Threat to the public Company policy 6. Elapsed time until area was made safe: / / hr. / / min. 7. Telephone Report / / / / / / / / NRC Report Number month day year 8. a. Estimated pressure at point and time of incident: PSIG b. Max. allowable operating pressure (MAOP): PSIG c. MAOP established by 49 CFR section: 192.619 (a)(1) 192. 619 (a)(2) 192. 619 (a)(3) 192.619 (a)(4) 192. 619 (c) d. Did an overpressurization occur relating to the incident? Yes No PART B – PREPARER AND AUTHORIZED SIGNATURE (type or print) Preparer's Name and Title Preparer's E-mail Address Area Code and Telephone Number Area Code and Facsimile Number Date Area Code and Telephone Number Authorized Signature (type or print) Name and Title Form RSPA F 7100.2 ( 01-2002 ) OPS Data Facsimile Page 1 of 3#

Page 33PART C - ORIGIN OF THE INCIDENT 1. Incident occurred on Transmission System Gathering System Transmission Line of Distribution System 2. Failure occurred on Body of pipe Pipe Seam Joint Component Other: 3. Material involved (pipe, fitting, or other component) Steel Plastic (If plastic, complete all items that apply in a-c) Plastic failure was: a.ductile b.brittle c.joint failure Material other than plastic or steel: _________ 4. Part of system involved in incident Pipeline Regulator/Metering System Compressor Station Other: 5. Year the pipe or component which failed was installed: / / PART D – MATERIAL SPECIFICATION (if applicable) 1. Nominal pipe size (NPS) / / in. 2. Wall thickness / / in. 3. Specification SMYS / / 4. Seam type 5. Valve type 6. Pipe or valve manufactured by PART E – ENVIRONMENT 1. Area of incident In open ditch Under pavement Above ground Under ground Under water Inside/under building Other: 2. Depth of cover: inches in year / / PART F – APPARENT CAUSE Important: There are 25 numbered causes in this section. Check the box to the left of the primary cause of the incident. Check one circle in each of the supplemental items to the right of or below the cause you indicate. See the instructions for this form for guidance. F1 – CORROSION 1. External Corrosion 2. Internal Corrosion If either F1 (1) External Corrosion, or F1 (2) Internal Corrosion is checked, complete all subparts a – e. a. Pipe Coating Bare Coated b. Visual Examination c. Cause of Corrosion Galvanic Stray Current Localized Pitting General Corrosion Improper Cathodic Protection Other: ____________________ Microbiological Stress Corrosion Cracking Other: ____________________ d. Was corroded part of pipeline considered to be under cathodic protection prior to discovering incident? No Yes, Year Protection Started: / / e. Was pipe previously damaged in the area of corrosion? No Yes, How long prior to incident: / / years / / months F2 – NATURAL FORCES 3. Earth Movement => Earthquake Subsidence Landslide Other: 4. Lightning 5. Heavy Rains/Floods => Washouts Flotation Mudslide Scouring Other: 6. Temperature => Thermal stress Frost heave Frozen components Other: 7. High Winds F3 - EXCAVATION 8. Operator Excavation Damage (including their contractors) / Not Third Party 9. Third Party Excavation Damage (complete a-d) a. Excavator group General Public Government Excavator other than Operator/subcontractor b. Type: Road Work Pipeline Water Electric Sewer Phone/Cable Landowner Railroad Other: c. Did operator get prior notification of excavation activity? No Yes: Date received: / / mo. / / day / / yr. Notification received from: One Call System Excavator Contractor Landowner d. Was pipeline marked? No Yes (If Yes, check applicable items i – iv) i. Temporary markings: Flags Stakes Paint ii. Permanent markings: Yes No iii. Marks were (check one) Accurate Not Accurate iv. Were marks made within required time? Yes No F4 – OTHER OUTSIDE FORCE DAMAGE 10. Fire/Explosion as primary cause of failure => Fire/Explosion cause: Man made Natural 11. Car, truck or other vehicle not relating to excavation activity damaging pipe 12. Rupture of Previously Damaged Pipe 13. Vandalism Form RSPA F 7100.2 ( 01-2002 ) Page 2 of 3#

Page 34F5 – MATERIAL AND WELDS Material 14. Body of Pipe => Dent Gouge Wrinkle Bend Arc Burn Other: 15. Component => Valve Fitting Vessel Extruded Outlet Other: 16. Joint => Gasket O-Ring Threads Other: Weld 17. Butt => Pipe Fabrication Other: 18. Fillet => Branch Hot Tap Fitting Repair Sleeve Other: 19. Pipe Seam => LF ERW DSAW Seamless Flash Weld HF ERW SAW Spiral Other: Complete a-g if you indicate any cause in part F5. a. Type of failure: Construction Defect => Poor Workmanship Procedure not followed Poor Construction Procedures Material Defect b. Was failure due to pipe damage sustained in transportation to the construction or fabrication site? Yes No c. Was part which leaked pressure tested before incident occurred? Yes, complete d-g No d. Date of test: / / mo. / / day / / yr. e. Test medium: Water Natural Gas Inert Gas Other: f. Time held at test pressure: / / hr. g. Estimated test pressure at point of incident: PSIG F6 – EQUIPMENT AND OPERATIONS 20. Malfunction of Control/Relief Equipment => Valve Instrumentation Pressure Regulator Other: 21. Threads Stripped, Broken Pipe Coupling => Nipples Valve Threads Mechanical Couplings Other: 22. Ruptured or Leaking Seal/Pump Packing 23. Incorrect Operation a. Type: Inadequate Procedures Inadequate Safety Practices Failure to Follow Procedures Other: b. Number of employees involved who failed post-incident drug test: / / Alcohol test: / / c. Were most senior employee(s) involved qualified? Yes No d. Hours on duty: / / F7 – OTHER 24. Miscellaneous, describe: 25. Unknown Investigation Complete Still Under Investigation (submit a supplemental report when investigation is complete) PART G – NARRATIVE DESCRIPTION OF FACTORS CONTRIBUTING TO THE EVENT (Attach additional sheets as necessary) Form RSPA F 7100.2 ( 01-2002 ) OPS Data Facsimile Page 3 of 3#

Page 35Pipeline Failure Investigation Report Appendix C Panhandle Failure Analysis - 32 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 36Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Panhandle Eastern Pipe Line Company, LP Final Report – 813 8385 1 October 29, 2008 .#

Page 37CC TECHNOLOGIES, INC. Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) for Panhandle Eastern Pipe Line Company, L.P. 5444 Westheimer, Suite 432 Houston, TX 77056 5777 Frantz Road Dublin, Ohio 43017-1386 U.S.A. Tel: (614) 761-1214 Fax: (614) 761-1633 www.dnv.com www.cctechnologies.com Summary: Final Report Prepared by: Gregory T. Quickel, M.S. Staff Engineer Reviewed by: John Beavers, Ph.D., FNACE . Director – Failure Analysis Approved by: Patrick H. Vieth Senior VP – Integrity & Materials Date of Issue: October 29, 2008 Project Number: 813 8385 1 No distribution without permission from the client or responsible organizational unit (however, free distribution for internal use within DNV after 3 years) No distribution without permission from the client or responsible organizational unit Strictly confidential Unrestricted distribution All copyrights reserved CC Technologies, Inc. This publication, or parts thereof, may not be reproduced or transmitted in any form or by any means, including photocopying or recording, without the prior written consent of CC Technologies, Inc. Reference to part of this report, which may lead to misinterpretation, is not permissible. Q:\EAWUS813\Anderson\2008\GREG QUICKEL\PANHANDLE EASTERN PIPE LINE CO (813 8385 1) October 22\Panhandle Final Report (813 8385 1) (October 29).doc#

Page 38Page ii Disclaimer This report documents work performed by CC Technologies, Inc. (CC Technologies) Dublin, Ohio, for Panhandle Eastern Pipe Line Company, L.P. (Panhandle) Houston, Texas. Neither CC Technologies nor any person acting on behalf of CC Technologies: • assumes any liability for consequences or damages resulting from the use, misuse, or reliance upon the information disclosed in this report. • makes any warranty or representations that the use of any information, apparatus, method, or process disclosed in this report may not infringe on privately-owned rights. CC TECHNOLOGIES, INC.#

Page 39Page iii Executive Summary Panhandle Eastern Pipe Line Company, L.P (Panhandle) retained CC Technologies, Inc. (CC Technologies) to perform a metallurgical analysis on a section of pipe from the 24-inch diameter Houstonia 200 natural gas pipeline that failed during service. The failure occurred on August 25, 2008 near Pilot Grove (Cooper County), Missouri at milepost (MP) 21.6. The portion of the pipeline containing the failure is comprised of 24-inch diameter by 0.281-inch wall thickness line pipe with an estimated yield strength (EYS) of 48.0 ksi that was manufactured by A.O. Smith and contains an electric flash welded (EFW) longitudinal seam. The maximum allowable operating pressure (MAOP) and normal operating pressure are 800 psig, which corresponds to 71.2% of the EYS. The operating pressure at the time and location of the failure was 790 psig, which corresponds to 70.3% of the EYS. The pipeline was installed in 1937 and was reportedly externally coated with a bitumastic pipe wrap. The pipeline has an impressed current cathodic protection (CP) system that was installed between 1951 and 1953. CP readings taken on March 25th, 2008 in the vicinity of the failure were -4.162 V (on) and -1.320 V (off). A hydrostatic pressure test was performed in 1955 on Segments 1031+39 to 1317+15, which encompasses the failure site. Four segments of line pipe steel, one which contained the failure origin, were delivered to CC Technologies for analysis. The received segments consisted of: a segment that contained the upstream (U/S) girth weld and failure origin, a mating downstream (D/S) segment, the D/S arrest segment from the joint that failed, and a segment of pipe from the joint D/S of the joint that failed. The objective of the analysis was to document the factual metallurgical evidence. The pipe segments were visually examined and photographed in the as-received condition. Scale samples were removed from the external pipe surface, at and away from a region of wall loss near the failure origin. The following was performed on the scale samples: elemental analysis using energy-dispersive spectroscopy (EDS) with a scanning electron microscope (SEM), bacteria culture inoculation using a serial dilution technique, and qualitative spot testing using 2N HCl for the presence of carbonates and/or sulfides. A grid with 1-inch by 1-inch divisions was drawn on the internal surface of the pipe near the failure origin where external wall loss was present. Wall thickness values were recorded every 1 inch (measured on the internal surface) with an ultrasonic testing (UT) gauge and/or with calipers. Calipers were used where the UT gauge could not be used, because of sharp bends in the pipe. The external surface at the wall loss region near the failure origin was cleaned with a soft bristle brush and inhibited acid. Magnetic particle inspection (MPI) was performed on the external surface at the wall loss region near the failure origin to identify any indications. Transverse cross-sections were removed from the failure origin and seam weld, mounted, polished, and etched. Light photomicrographs were taken to document the corrosion morphology and steel microstructure. CC TECHNOLOGIES, INC.#

Page 40Page iv Executive Summary (continued) A pipe sample for chemical analysis was removed from the joint that failed to determine the composition. Transverse pipe samples for mechanical (duplicate tensiles and Charpy V-notch impact) testing were removed from the base metal of the downstream joint. The predicted burst pressure for the region of wall loss that contained the rupture was calculated using the RSTRENG effective area method embodied in CorLASTM. Two flaw profiles were obtained. The first flaw profile (profile 1) was obtained by using a modified river bottom method. A second flaw profile (profile 2) was constructed by measuring the wall thicknesses at the edge of the counter-clockwise fracture surface. A flow strength of the measured yield stress (MYS)+10 ksi was used for the calculation. Below is a summary of our preliminary observations and conclusions: • The failure occurred at a region of external wall loss from corrosion. • The maximum depth of wall loss at the rupture surface was 0.210 inches (74.7% of wall thickness). • Bacteria did not likely play a role in the external corrosion based on the morphology of the corrosion and the results of the bacteria culture testing. • The morphology of the fracture surfaces suggests that the failure initiated in a ductile manner. • The morphology of the seam weld is consistent with an EFW seam. • The microstructure and steel composition are consistent with line pipe steel. • The results of the tensile and Charpy testing are consistent with this vintage of line pipe steel. • The estimated burst pressure ranged between 663 psig to 868 psig, compared to an actual failure pressure of 790 psig. CC TECHNOLOGIES, INC.#

Page 41Page v Contents 1.0 BACKGROUND ................................................................................................................1 2.0 APPROACH ......................................................................................................................1 3.0 RESULTS AND DISCUSSION..........................................................................................2 3.1 Optical Examination ...............................................................................................2 3.2 Magnetic Particle Inspection (MPI) ........................................................................3 3.3 Metallurgical Analysis.............................................................................................3 3.4 Energy Dispersive Spectroscopy (EDS) ................................................................4 3.5 Qualitative Spot Test..............................................................................................4 3.6 Bacteria Culture Testing.........................................................................................4 3.7 Mechanical Test Results ........................................................................................4 3.8 Chemical Analysis..................................................................................................5 3.9 Predicted Burst Pressure .......................................................................................5 4.0 CONCLUSIONS................................................................................................................5 CC TECHNOLOGIES, INC.#

Page 42Page vi Tables Table 1. Table 2. Table 3. Table 4. Table 5. Table 6. Table 7. Summary of the results (in areas of minimal or no corrosion) of wall thickness measurements performed on the pipe segments.......................................7 Results of elemental analysis of scale samples removed from the external pipe surface using energy dispersive spectroscopy (EDS). .........................7 Results of bacteria analysis performed on scale samples removed from the external surfaces, at and away from the region of external corrosion..................8 Results of tensile tests performed on transverse samples from Pipe Segment C (D/S of failure joint). ................................................................................8 Results of Charpy V-notch impact tests performed on samples removed from the base metal of Pipe Segment C. ...................................................................9 Results of analysis of the Charpy V-notch impact energy and percent shear plots..................................................................................................................9 Results of chemical analysis of a pipe steel sample from Pipe Segment A2 (failure joint) by optical emission spectroscopy (OES) removed from the joint that ruptured. ..............................................................................................10 CC TECHNOLOGIES, INC.#

Page 43Page vii Figures Figure 1. Photograph of Pipe Segment A1 (internal surface) in the as-received condition...................................................................................................................11 Figure 2. Photograph of Pipe Segment B1 in the as-received condition.................................12 Figure 3. Photograph of Pipe Segment C in the as-received condition...................................13 Figure 4. Photograph of Pipe Segment A2 (external surface) in the as-received condition...................................................................................................................14 Figure 5. Photograph of the external surface of Pipe Segment A2 on the clockwise side of rupture..........................................................................................15 Figure 6. Photograph of the external surface of Pipe Segment A2 on the counter-clockwise side of rupture.............................................................................16 Figure 7. Remaining wall in the region of the probable failure origin. .....................................17 Figure 8. Stereo light photomicrograph of a transverse cross-section removed from the rupture near the failure origin (Mount M1, 4% Nital Etchant).....................18 Figure 9. Stereo light photomicrograph of the rupture area indicated in Figure 8 (Mount M1, 4% Nital Etchant). .................................................................................19 Figure 10. Light photomicrograph of the external surface of the pipe in Mount M1 (4% Nital Etchant, area indicated in Figure 8)..........................................................19 Figure 11. Stereo light photomicrograph of the seam weld cross-section (Mount M2, 4% Nital Etchant). .............................................................................................20 Figure 12. Light photomicrograph of the typical base metal microstructure from Mount M2 (4% Nital Etchant). ..................................................................................20 Figure 13. EDS spectrum of scale that was removed from the external surface. .....................21 Figure 14. Plot of percent shear from Charpy V-notch tests as a function of temperature for samples removed from Pipe Segment C........................................22 Figure 15. Plot of Charpy V-notch impact energy as a function of temperature for samples removed from Pipe Segment C. ................................................................22 Figure 16. Flaw depth vs. length profile of the measured flaws. ...............................................23 CC TECHNOLOGIES, INC.#

Page 44Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 1 1.0 BACKGROUND Panhandle Eastern Pipe Line Company, L.P (Panhandle) retained CC Technologies, Inc. (CC Technologies) to perform a metallurgical analysis on a section of pipe from the 24-inch diameter Houstonia 200 natural gas pipeline that failed during service. The failure occurred on August 25th, 2008 near Pilot Grove (Cooper County), Missouri at milepost (MP) 21.6. The portion of the pipeline containing the failure is comprised of 24-inch diameter by 0.281-inch wall thickness line pipe with an estimated yield strength (EYS) of 48.0 ksi that was manufactured by A.O. Smith and contains an electric flash welded (EFW) longitudinal seam. The maximum allowable operating pressure (MAOP) and normal operating pressure are 800 psig, which corresponds to 71.2% of the EYS. The operating pressure at the time and location of the failure was 790 psig, which corresponds to 70.3% of the EYS. The pipeline was installed in 1937 and was reportedly externally coated with a bitumastic pipe wrap. The pipeline has an impressed current cathodic protection (CP) system that was installed between 1951 and 1953. CP readings taken on March 25th, 2008 in the vicinity of the failure were -4.162 V (on) and -1.320 V (off). A hydrostatic pressure test was performed in 1955 on Segments 1031+39 to 1317+15, which encompasses the failure site. Four segments of line pipe steel, one which contained the failure origin, were delivered to CC Technologies for analysis. The received segments consisted of a segment that contained the upstream (U/S) girth weld and failure origin, a mating downstream (D/S) segment, the D/S arrest segment from the joint that failed, and a segment of pipe from the joint D/S of the joint that failed. The objective of the analysis was to document the factual metallurgical evidence. 2.0 APPROACH The procedures used in the analysis were in accordance with industry accepted standards. Six of the general standards governing terminology, chemical analysis, mechanical testing, and specific metallographic procedures used are as follows: • ASTM E3, “Standard Methods of Preparation of Metallographic Specimens.” • ASTM E7, “Standard Terminology Relating to Metallography.” • ASTM E8, “Test Methods for Tension Testing of Metallic Materials.” • ASTM E23, “Standard Test Methods for Notched Bar Impact Testing of Metallic Materials.” • ASTM A751, “Standard Test Methods, Practices, and Terminology for Chemical Analysis of Steel Products.” • ASTM G15, “Standard Terminology Relating to Corrosion and Corrosion Testing.” CC TECHNOLOGIES, INC.#

Page 45Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 2 The pipe segments were visually examined and photographed in the as-received condition. Scale samples were removed from the external pipe surface, at and away from a region of wall loss near the failure origin. The following was performed on the scale samples: elemental analysis using energy-dispersive spectroscopy (EDS) with a scanning electron microscope (SEM), bacteria culture inoculation using a serial dilution technique, and qualitative spot testing using 2N HCl for the presence of carbonates and/or sulfides. A grid with 1-inch by 1-inch divisions was drawn on the internal surface of the pipe near the failure origin where external wall loss was present. Wall thickness values were recorded every 1 inch (measured on the internal surface) with an ultrasonic testing (UT) gauge and/or with calipers. Calipers were used where the UT gauge could not be used, because of sharp bends in the pipe. The external surface at the wall loss region near the failure origin was cleaned with a soft bristle brush and inhibited acid. Magnetic particle inspection (MPI) was performed on the external surface at the wall loss region near the failure origin to identify any indications. Transverse cross-sections were removed from the failure origin and seam weld, mounted, polished, and etched. Light photomicrographs were taken to document the corrosion morphology and steel microstructure. A pipe sample for chemical analysis was removed from the joint that failed to determine the composition. Transverse pipe samples for mechanical (duplicate tensiles and Charpy V-notch impact) testing were removed from the base metal of the downstream joint. The predicted burst pressure for the region of wall loss that contained the rupture was calculated using the RSTRENG effective area method embodied in CorLASTM. Two flaw profiles were obtained. The first flaw profile (profile 1) was obtained by using a modified river bottom method. A second flaw profile (profile 2) was constructed by measuring the wall thicknesses at the edge of the counter-clockwise fracture surface. A flow strength of the measured yield stress (MYS)+10 ksi was used for the calculation. 3.0 RESULTS AND DISCUSSION 3.1 Optical Examination Figure 1 through Figure 4 are photographs of the four as-received pipe segments. The pipe segments were designated as Pipe Segment A1, A2, B1, and C and by Panhandle personnel. Pipe Segments A1, B1, and A2 contained portions of the rupture paths. Pipe Segment C did not contain a rupture path and was used for mechanical testing. None of the pipe segments contained in-tact coating (in the as-received condition) and all segments, except for Segment C, contained localize regions of wall loss. Top-dead-center (TDC) was not indicated on the pipe segments. Flow direction was not identified on the pipe segments but is labeled on pipe segments that ruptured. The wall thicknesses were measured at four equally spaced locations on the pipe segments. The wall thickness values for the segments are shown in Table 1. The wall thickness values were consistent with a nominal wall thickness of 0.281 inches. Figure 1 is a photograph of the internal surface of Pipe Segment A1 is the as-received condition. The pipe segment was approximately 6.5 feet in length and was the D/S mating CC TECHNOLOGIES, INC.#

Page 46Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 3 segment to Segment A2. The seam weld is located between the two rupture faces. The orientation of the chevron markings on the rupture surfaces indicated that the failure origin was U/S. Figure 2 is a photograph of the external and internal surfaces of Pipe Segment B1 in the as-received condition. Pipe Segment B1 was approximately 11 feet in length from the joint that ruptured, and contained the D/S portion of rupture arrest. Again, the orientation of the chevron markings on the rupture surfaces indicated that the failure origin was U/S of this segment. Figure 3 is a photograph of the external surface of Pipe Segment C in the as-received condition. The pipe segment was approximately 1.5 feet in length, was from the joint D/S of the joint that ruptured, and was intact. The diameter of the pipe segment was 23.9 inches, which is consistent with a nominal diameter of 24 inches. Figure 4 is a photograph of Pipe Segment A2 in the as-received condition. The pipe segment was approximately 4.2 feet in length and U/S of Pipe Segment A1. Chevron markings that were located on the fracture surfaces pointed to a rupture origin in the segment. Figure 5 and Figure 6 are photographs of the external pipe surface on the clockwise and counter-clockwise side of the rupture path, respectively. Corrosion wall loss is located on the external pipe surface on adjacent surfaces. The corroded region extended 0.5 feet to 1.79 feet from the U/S girth weld and the fracture surface within the region was at a 45° angle, indicating a shear type of failure. Outside of the region, the fracture surface contained chevron marks and was predominantly perpendicular to the pipe surface. Figure 7 shows remaining wall produced from wall thickness measurements obtained. The measurements were recorded from approximately 34 to 47 inches clockwise of the seam weld and from 6 to 25-inches D/S of the U/S girth weld. The rupture surface regions were located approximately 40 to 41 inches clockwise of the seam weld (looking D/S). This figure shows that the maximum depth of attack ranges from 0.05 to 0.1 inches and the deepest portions of the attack are at/near the fracture surface. Based on a wall thickness of 0.281 inches, the maximum depth of wall loss was 0.188 inches (66.9% of wall thickness). 3.2 Magnetic Particle Inspection (MPI) MPI was performed on the external pipe surface in the region of wall loss associated with the failure origin. No evidence of linear indications was identified on the pipe body. 3.3 Metallurgical Analysis Figure 8 is a photograph of the mounted transverse cross-section (Mount M1) removed near the rupture origin (see Figure 5 and Figure 6 for location). The cross-section shows significant wall loss. Figure 9 is a stereo light photomicrograph of the area indicated in Figure 8. The rupture surfaces are at approximately a 45° angle to each other and there is evidence of necking near the rupture surfaces. Both observations are indicative of a ductile overload failure. Figure 10 is a light photomicrograph showing the cross-section of Mount M1 near the external surface. The CC TECHNOLOGIES, INC.#

Page 47Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 4 figure shows a banded microstructure and there was no evidence in the cross-section of morphology that is indicative of microbial influenced corrosion (MIC). Figure 11 is a stereo light photomicrograph of the mounted cross-section that was removed from the seam weld. The morphology of the weld is consistent with an EFW seam. Figure 12 is a light photomicrograph of the typical microstructure of the base metal from Mount M2. steel. The microstructure consists of ferrite (white areas), pearlite (dark areas consisting of lamellae), and inclusions. This microstructure is typical for this vintage and grade of line pipe 3.4 Energy Dispersive Spectroscopy (EDS) Table 2 is a summary of the EDS results of the scale samples removed from the external pipe surface; see Figure 5 for the locations where the scale was removed. Sample A was removed from the region of wall loss and Sample B was removed away from the region of wall loss. Figure 13 shows a representative EDS spectrum. High amounts of oxygen (O) and iron (Fe), lesser amounts of sodium (Na), magnesium (Mg), aluminum (Al), silicon (Si), sulfur (S), potassium (K), calcium (Ca), manganese (Mn), and carbon (C) were found in the samples. The Fe and O were likely in the form of an iron oxide and other elements are commonly found in soils. 3.5 Qualitative Spot Test Spot tests for the presence of carbonates and/or sulfides were performed on scale at locations where samples were removed for elemental analysis. The deposits were positive for the presence of carbonates (bubbling) and negative for the presence of sulfides (no rotten egg odor). Carbonates are commonly associated with CP. 3.6 Bacteria Culture Testing Scale samples were removed from the external surface, inoculated, and incubated for the presence of aerobic, anaerobic, sulfate-reducing (SRB), acid-producing (APB), and iron-related bacteria (IRB) in concentrations ranging from 1-99,999 bacteria per mL. The samples were removed from the same locations where samples were removed for elemental analysis. Table 3 shows the results of the bacteria testing for the scale samples. The scale samples removed from both locations were positive for the presence of aerobic bacteria, anaerobic bacteria, and acid-producing bacteria (APB) in very high (10,000 – 99,999 bacteria per mL) concentrations. The fact that there was no evidence of an increased concentration of the bacteria near the failure site suggests that bacteria did not play a role in the failure. 3.7 Mechanical Test Results The results of the tensile testing for samples removed from the Segment C (D/S joint) are shown in Table 4. The MYS and ultimate tensile strength (UTS) for the pipe segment were CC TECHNOLOGIES, INC.#

Page 48Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 5 determined to be 51.8-ksi and 71.5-ksi, respectively, compared to an EYS of 48.0-ksi. The failure joint was not tested since it was deformed during the failure event. Table 5 summarizes the results of the Charpy testing while Figure 14 and Figure 15 show the Charpy percent shear and impact energy curves, respectively. An analysis of the data indicates that the 85% FATT is 96.8°F and the upper shelf Charpy energy is 38.8-ft·lbs, full size. The CVN test results can be adjusted to account for material constraint effects by applying temperature shifts to the data.* The modified transition temperatures (brittle-to-ductile fracture initiation temperature) for the pipe segment were estimated as 90.4°F, based on a pipe wall thickness of 0.281 inches; see Table 6. Based on this analysis, the tested material is expected to exhibit ductile fracture propagation behavior above 90.4°F. 3.8 Chemical Analysis The results of the chemical composition analysis conducted on a sample removed from the pipe section that ruptured are shown in Table 7. The composition is consistent with this vintage of line pipe steel. 3.9 Predicted Burst Pressure The predicted burst pressure for the region of wall loss that contained the rupture was calculated using the RSTRENG effective area method embodied in CorLASTM. The predicted burst pressure relied upon the remaining wall thicknesses measurements at and near the rupture of flaw profile 1 and 2, the average mechanical properties from the mechanical testing, and the pipe dimensions; see Figure 16 for flaw profiles. The results of the analysis are summarized in Appendix A. The maximum depth of wall loss in flaw profile 1 and 2 were 0.188 inches (66.9% of wall thickness) and 0.210 inches (74.7% of wall thickness), respectively. The estimated burst pressure ranged between 663 psig to 868 psig, compared to an actual failure pressure of 790 psig. 4.0 CONCLUSIONS Below is a summary of our preliminary observations and conclusions: • The failure occurred at a region of external wall loss from corrosion. • The maximum depth of wall loss at the rupture surface was 0.210 inches (74.7% of wall thickness). • Bacteria did not likely play a role in the external corrosion based on the morphology of the corrosion and the results of the bacteria culture testing. • The morphology of the fracture surfaces suggests that the failure initiated in a ductile manner. * “A Simple Procedure for Synthesizing Charpy Impact Energy Transition Curves from Limited Test Data,” Michael J. Rosenfeld, International Pipeline Conference – Volume 1, ASME 1996, p. 216. CC TECHNOLOGIES, INC.#

Page 49Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 6 • The morphology of the seam weld is consistent with an EFW seam. • The microstructure and steel composition are consistent with line pipe steel. • The results of the tensile and Charpy testing are consistent with this vintage of line pipe steel. • The estimated burst pressure ranged between 663 psig to 868 psig, compared to an actual failure pressure of 790 psig. CC TECHNOLOGIES, INC.#

Page 50Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 7 Table 1. Summary of the results (in areas of minimal or no corrosion) of wall thickness measurements performed on the pipe segments. Segment ID Description Wall Thickness 1 (inches) Wall Thickness 2 (inches) Wall Thickness 3 (inches) Wall Thickness 4 (inches) A1 D/S of and cut from Segment A2 0.271 0.275 0.281 0.280 A2 Segment that contained U/S girth weld and failure origin 0.282 0.281 0.278 0.275 B1 D/S arrest segment 0.279 0.276 0.280 0.280 C Segment for mechanicals 0.281 0.281 0.282 0.283 Table 2. Results of elemental analysis of scale samples removed from the external pipe surface using energy dispersive spectroscopy (EDS). Location A, Corroded Region (wt %) Location B, Non-Corroded Region (wt %) O 26 68 Na <1 - Mg <1 3.4 Al <1 1.6 Si <1 5.6 S <1 <1 K <1 <1 Ca 1.5 4.3 Mn 1.3 - C - 15 Fe 69 2.1 CC TECHNOLOGIES, INC.#

Page 51Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 8 Table 3. Results of bacteria analysis performed on scale samples removed from the external surfaces, at and away from the region of external corrosion. Scale from Location A Scale from Location B Test Result Bacteria Concentration Test Result Bacteria Concentration Aerobic positive Very High positive Very High Anaerobic positive Very High positive Very High Acid-Producing positive Very High positive Very High Sulfate-Reducing negative - negative - Iron-Related negative - negative - Bacteria Concentration Key: Very Low Low Moderate High Very High (1 – 9 bacteria per mL), (10 – 99 bacteria per mL), (100 – 999 bacteria per mL), (1,000 – 9,999 bacteria per mL), (10,000 – 99,999 bacteria per mL) Table 4. Results of tensile tests performed on transverse samples from Pipe Segment C (D/S of failure joint). Pipe Segment C Yield Strength, ksi 51.8 Tensile Strength, ksi 71.5 Elongation in 2 inches, % 33.0 Reduction of Area, % 52.0 CC TECHNOLOGIES, INC.#

Page 52Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 9 Table 5. Results of Charpy V-notch impact tests performed on samples removed from the base metal of Pipe Segment C. Sample ID Temperature, °F Sub-size Impact Energy, ft-lbs Full Size Impact Energy, ft-lbs Shear, % Lateral Expansion, mils 1 -30 2 3.5 0 0 2 -5 3 5.3 5 0 3 20 4 7 15 1 4 45 10 17.6 40 9 5 70 16 28.1 60 22 6 95 21 36.9 85 30 7 120 22 38.7 95 31 8 145 21.5 37.8 98 31 Table 6. Results of analysis of the Charpy V-notch impact energy and percent shear plots. Pipe Segment C Upper Shelf Impact Energy (Full Size), Ft-lbs 38.8 85% FATT, °F 96.8 Maxey Adjusted 85% FATT, °F 90.4 CC TECHNOLOGIES, INC.#

Page 53Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 10 Table 7. Results of chemical analysis of a pipe steel sample from Pipe Segment A2 (failure joint) by optical emission spectroscopy (OES) removed from the joint that ruptured. Base Metal Element (Wt. %) C (Carbon) 0.287 Mn (Manganese) 1.07 P (Phosphorus) 0.011 S (Sulfur) 0.029 Si (Silicon) 0.008 Cu (Copper) 0.023 Sn (Tin) 0.002 Ni (Nickel) 0.014 Cr (Chromium) 0.015 Mo (Molybdenum) 0.000 Al (Aluminum) 0.002 V (Vanadium) 0.001 Nb (Niobium) 0.002 Zr (Zirconium) 0.001 Ti (Titanium) 0.001 B (Boron) 0.0002 Ca (Calcium) 0.0000 Co (Cobalt) 0.003 Fe (Iron) Balance Carbon Equivalent (CEIIW) 0.47 CC TECHNOLOGIES, INC.#

Page 54Draft Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 11 Flow Figure 1. Photograph of Pipe Segment A1 (internal surface) in the as-received condition. CC TECHNOLOGIES, INC.#

Page 55Final Report – 813 8385 1 Flow Figure 2. CC TECHNOLOGIES, INC. Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 12 Photograph of Pipe Segment B1 in the as-received condition.#

Page 56Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 13 Figure 3. Photograph of Pipe Segment C in the as-received condition. CC TECHNOLOGIES, INC.#

Page 57Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 14 U/S girth weld Seam weld Flow Chemistry sample Mount M2 Figure 4. Photograph of Pipe Segment A2 (external surface) in the as-received condition. CC TECHNOLOGIES, INC.#

Page 58Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 15 Scale removed for bacteria testing and EDS, Location A Scale removed for bacteria testing and EDS, Location B Wall loss Axial direction 12 inches from U/S girth weld Mating portion of Mount M1 Figure 5. Photograph of the external surface of Pipe Segment A2 on the clockwise side of rupture. CC TECHNOLOGIES, INC.#

Page 59Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 16 Axial direction Wall loss 12 inches from U/S girth weld Mating portion of Mount M1 Figure 6. Photograph of the external surface of Pipe Segment A2 on the counter-clockwise side of rupture. CC TECHNOLOGIES, INC.#

Page 60Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 17 47 46 Deepest region measured 45 44 Approximate fracture path 43 42 Fracture 41 Face Region 40 39 0.25-0.3 0.2-0.25 0.15-0.2 0.1-0.15 0.05-0.1 0-0.05 38 37 36 Distance Clockwise of Seam Weld Looking D/S 35 Remaining Wall (in) 34 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Distance from U/S Girth Weld (in) Figure 7. Remaining wall in the region of the probable failure origin. CC TECHNOLOGIES, INC.#

Page 61Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 18 OD ID Figure 9 Figure 10 Figure 8. Stereo light photomicrograph of a transverse cross-section removed from the rupture near the failure origin (Mount M1, 4% Nital Etchant). CC TECHNOLOGIES, INC.#

Page 62Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 19 OD ID Figure 9. Stereo light photomicrograph of the rupture area indicated in Figure 8 (Mount M1, 4% Nital Etchant). Figure 10. Light photomicrograph of the external surface of the pipe in Mount M1 (4% Nital Etchant, area indicated in Figure 8). CC TECHNOLOGIES, INC.#

Page 63Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 20 Flow lines OD ID Figure 11. Stereo light photomicrograph of the seam weld cross-section (Mount M2, 4% Nital Etchant). Inclusion Pearlite Ferrite Figure 12. Light photomicrograph of the typical base metal microstructure from Mount M2 (4% Nital Etchant). CC TECHNOLOGIES, INC.#

Page 64Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 21 cps/eV 100 80 O Mn Mg Fe Mn Na Al Si S K Ca Fe 60 Ca 40 20 0 1 2 3 4 5 6 7 8 9 10 keV Figure 13. EDS spectrum of scale that was removed from the external surface. CC TECHNOLOGIES, INC.#

Page 65Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 22 Figure 14. Plot of percent shear from Charpy V-notch tests as a function of temperature for samples removed from Pipe Segment C. Figure 15. Plot of Charpy V-notch impact energy as a function of temperature for samples removed from Pipe Segment C. CC TECHNOLOGIES, INC.#

Page 66Final Report – 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page 23 Distance from U/S girth weld (in) 6.0 8.0 10.0 12.0 14.0 16.0 18.0 20.0 22.0 24.0 26.0 0.000 0% wt 0.050 25% wt Flaw depth (inches) 0.100 50% wt 0.150 0.200 75% wt 0.250 Flaw Profile One Flaw Profile Two 0.281 nominal 100% wall thickness (wt) Figure 16. Flaw depth vs. length profile of the measured flaws. CC TECHNOLOGIES, INC.#

Page 67APPENDIX A DESCRIPTION OF CORLASTM CC TECHNOLOGIES, INC.#

Page 68Final Report - 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page A-1 APPENDIX A Description of CorLAS ™ The CorLAS™ computer program was developed by CC Technologies to evaluate crack-like flaws in pipelines based on inelastic fracture mechanics. Using the effective area of the actual, measured crack length-depth profile, an equivalent semi-elliptical surface flaw is modeled and used to compute the effective stress and the applied value of J for internal pressure loading. The effective stress and applied J are then compared with the flow strength (0s) and fracture toughness (Jc), respectively, to predict the failure pressure. The program also contains a similar inelastic fracture mechanics analysis for through-wall flaws. The fracture toughness of the steel can be estimated from Charpy data or measured by means of a Jic test. In the most recent version of CorLAS™, the fracture toughness analysis automatically checks for plastic instability and only the fracture toughness curve needs to be considered for crack-like flaws. The actual tensile and Charpy properties of the pipe joint, measured trom the samples removed, can be used for the critical leak/rupture length calculation. *******************: ************************************************** Houstonia 200 :SEMI-ELLIPTICAL FLAW PROFILE EST YS 48 ksi UTS, psi = 71500. YS, psi = 51750. FS, psi = 61750. E, ksi = 29500. nexp = 0.110 Jc, Ib/in = 1935. Thin-wall (OD) formula for hoop stress Tmat = 62.5 OD, in. = 24.00 Wall Thickness, in. = 0.281 SUMMARY OF RESULTS FOR EFFECTIVE-AREA METHOD Flaw: Start, in. = 4.000 Length, in. = 9.000 Area, in.^2 = 1.283 Depth,in.: Maximum = 0.188 Equivalent Flaw = 0.182 Failure Stress, psi = 37048. Failure Pressure, psig = 867.53 ******** Input Flaw Profile Data ********* Depth, Length, in. in. 1 0 0.052 3 0.061 0.059 4 0.138 5 0.132 6 0.188 8 0.158 0.155 CC TECHNOLOGIES, INC. MANAGING RISK DNV#

Page 69Final Report - 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page A-2 9 0.086 10 0.126 11 0.145 12 0.173 13 0.102 15 0.071 16 0.079 17 18 0.096 0.03 19 0.029 20 0.021 21 ---------- --------- ******** Effective Flaw Results ********* Flow Flaw Flaw Effective Failure in. Start, Length, Japplied, in. in.^2 Area, Stress, Failure psi lIb/in Tapplied Pressure, psig ----- ------- THOSE BELOW ARE FOR FLOW-STRENGTH FAILURE CRITERION 1.283 37048 4278.6 1794.1 867.5 *************************************** Houstonia 200 :SEMI-ELLIPTICAL FLAW PROFILE EST YS 48 ksi UTS, psi = 71500. YS, psi = 51750. FS, psi = 61750. E, ksi = 29500. nexp = 0.110 Jc, Ib/in = 1935. Thin-wall (OD) formula for hoop stress Tmat = 62.5 OD, in. = 24.00 Wall Thickness, in. = 0.281 SUMMARY OF RESULTS FOR EFFECTIVE-AREA METHOD Flaw: Start, in. = 5.000 Length, in. = 8.000 Area, in.^2 = 1.480 Depth,in.: Maximum = 0.210 Equivalent Flaw = 0.236 Failure Stress, psi = 28328. Failure Pressure, psig = 663.34 ******** Input Flaw Profile Data ********* Depth, Length, in. in. 1 0 0.094 2 0.119 3 0.139 4 0.131 5 0.126 CC TECHNOLOGIES, INC. MANAGING RISK DNV#

Page 70Final Report - 813 8385 1 Metallurgical Analysis of 24-Inch Houstonia 200 Service Failure at MP 21.6 (8/25/08) Page A-3 6 0.21 7 0.201 0.192 0.179 10 0.188 12 0.189 13 0.139 15 16 0.076 0.071 17 0.051 18 0.054 19 0.051 20 0.032 21 0 ******** Effective Flaw Results ********* Flaw Flaw Effective Failure Flow Start, in. Length, in. Area, in.^2 Stress, Japplied, Failure psi Ib/in Tapplied Pressure, psig THOSE BELOW ARE FOR FLOW-STRENGTH FAILURE CRITERION 1.48 28328 10025.2 6519.7 663.3 CC TeCHNOLoGIES, INC.#

Page 71CC Technologies / Det Norske Veritas CCT/DNV is a leading provider of technology in managing corrosion and materials risks. As one of the few firms to combine practical engineering solutions with state-of-the-art research and testing, we can offer our clients innovative, cost effective solutions. We specialize in engineering, research and testing for corrosion control and monitoring, fitness-for-service, pipeline/plant integrity analysis, materials evaluation and selection, failure analysis, litigation support, management systems approaches and instrumentation and software design and development.#

Page 72Pipeline Failure Investigation Report Appendix D Panhandle Close Interval Survey - 33 - Form 11 Pipeline Failure Investigation Report (Revised 03/07/08)#

Page 73NOVEMBER, 2000 HOUSTON, TEXAS CORRPRO COMPANIES, INC. BY CMS PANHANDLE EASTERN FOR TS 24.4 TO EAST EDGE RIVER FROM LINE 200 24 INCH 2 GATE TO 3 GATE CLOSE INTERVAL POTENTIAL SURVEY#

Page 74Pipe/Soil Potential (mv) -300 -600 -900 -1200 - 1500 - 1800 1004+00 1803H76 CHEN ORRE REA OFF- 1154 EDGE OF RIVER NG ON-150‹ 1005+00 200*B16/ 11*30*00 200B10 FIELD DRY 25 1006+00 1007+00 Distance (feet) 1008+00 1009+00 - 1010+00 1011+00 1012+00#

Page 75Pipe/Soil (mv) -300 -600 -900 - 1200 +1500 - 1800 1013+00 1014+00 1015+00 1015+41 C/L FIELD RD 9 1016+00. st: 1017+00 1017+08 C/L DRY CREEK 1018+00 1018+11 C/L CREEK - 1019+00 1019+38 FENCE/MARKER 1020+00 L1021+00 N#

Page 76Pipe/Soi Potential (mv) -300 -600 -900 -1200 - 1800 1022+00 1023+00 1024+00 1025+00 Distance (feet) 1026+00 1027+00 1028+00 1029+00 L1030+00#

Page 77Pipe/Soil Potential (mv) -300 -600 -900 -1200 -1500 J1800 1031+00 1031+24 TS RIVER BLOCK VALVE WIRE 1032+00 1031+94 FENCE/MARKER 1033+00 Distà 1034+00 1035+00 1036+00 1036+36 TS 19.7 FG ON- 1451' OFF-1090| OFF-1D90' IR ON O OFF O NG ON-1451 1036+54 C/L GRAVEL RD RECON WIRE 1037+00 1038+00 1039+00.#

Page 78Pipe/Soil Potential (mv) -300 -600 -900 -1200 -1500 -1800 1040+00 1041+00 1041+04 FENCE/MARKER 1042+00 1043+A0 1043+64 C/L DITCH BOTTOM OF HILL (feet) 1044+00 1045+00 - 1046+00 1Ø46+61 C/L CREEK 1047+00 L1048+00.#

Page 79Pipe/Soil Potential (mv) N -300 -600 -900 - 1200 - 1500 - 1800 1049+00 -2101 -2114_ 1050+00 -2101 _-2101_ -2101 1051+00 1051+01 TOP OF HİLL. _-2101_ - 2143_ -2161 - 2106 -2106 -2103 -2111. ° 1052+00 -2103 ta -2103 eet) -2122 1053+00 -2138 1054+00 1053+94 FENCE 1054+11 C/L CREEK BOTTOM OF HILL 1055+00 1056+00 1055+88 FENCE/MARKER 1056+66 FENCE/MARKER 4957+08#

Page 80Pipe/Soil Potential (mv) -300 -600 -900 -1200 -1500 ·1800 1058+00 1059+00 1058+91 CROP EDGE 1060+00 1060+61 TOP OF HILL 1061+00 istance (feet) 1062+00 1063+00 - 1063+71 CROP EDGE IMMM 1064+00 1065+00 1066+00#

Page 81Pipe/Soil Potential (mv) -300 -600 =900 -1200 -1500 -1800 1067+00 1068+00 my Mom 1069+00 _-2143 1070+00 starde 1070+38 T821260 NG 0~-2097 OFF-1252' IR ON+11 OFF-7 ON-2097 -2130 RECON WIRE -2103 + 1071+00 1071+48 FENCE 1071+34 MARKER -2135_ -2106 -2106 1072+00 1071+88 CROP EDGE -2119 -2106 -2109 _-2180 -2119 -2109 -2185 1073+00 - 2127 -2116 -2140 -2127 -2124 _-2143 1074+00 -2119 -2132 _-2148 -2124 -2124 1075+00 -2175 -2132#

Page 82Pipe/Soil Potential (mv) -300 -600 -900 -1200 -1500 =1800 1076+00 --2140 -2138 -2206 -2132 - 2145 -2156- 1077+00 -2143 -2138 -2172.- -2130 -2132 -2135 1078+00 -2135 -2124 -2130 -2151. -2130 -2138 -2124 Dista. 1079+00 -2124 -2190 -2111 -2124 e (feet) -2159 -2116 1080+00 -2109 --2169 -2116 -2109 -2116 -2103 1081+00 =-2167= -2103 -2111 -2106_ 1082+00 -2101 1083+00 -21837 L1034+00#

Page 83Pipe/Soil Potential (mv) -300 -600 -900 -1200 - 1500 -1800 1085+00 1086+00 1087+00 1088+00 Distance (feet) 1089+00 1090+00 1091+00 1092+00 11093+00#

Page 84Pipe/Soil Potential (mv) -300 -600 -900 - 1200 -1500 -1800 1095+00 1096+00 1096+26 CROP EDGE 1096+54 MARKER/POWER LINE 1096+66 C/L DITCH 1097+00 1038+94 CROP EDGE RD sta feet) 1098+00 1099+R0 1100+00 1101+00 L1102+00#

Page 85Pipe/Soil Potential (mv) -300 -600 -900 - 1200 -1500 1-1800 1104+00 1105+00 ista 1106+00 (fee +) 1107+00 1108+00 - 1109+00 1110+00#

Page 86Pipe/Soil Potential (mv) -300 -600 -900 =1200 +1500 -1800 1112+00 1113+00 1114+00 1114+04 CROP EDGE 1114+38 C/L DITCH 1114+78 CROP EDGE 1115+00 ta. (feet) 1116+00 1117+00 - 1118+00 1119+00 L1129+0R#

Page 87Pipe/Soil Potential (mv) -300 -600 -900 1200 -1500 - 1800 1121+00 1122+00 1122+21 CROP EDGE 1122+66 FENCE/MARKER 1123+00 Dista 1124+00 1125+00 1126+00 - =-2119. 1126+61 C/L CREEK BOTTOM OF HILL -2194 -2248= 1127+00 - 2204 -2222 -2169 -2174. -2138 -2148 -2127 1128+00 L1129+00#

Page 88Pipe/Soil Potential (mv) -300 -600 =900 - 1200 1500 -1800 1130+00 -2109 -2285 1130+56 CROP EDGE -2362 -2247 -2547 1131+00 -2602 -2660 -2697 -2425 -2755 -2752 -2774 1132+00 -2760 -2787 -2803 -2816 -2803 -2824. -2813 -2816 1133+00 istar -2702 -2774 -2708 -2837 -2795 (feet) -2847 1134+00 -2721 - 2668 -2510 -2697 -2679 -2539 -2717 1135+00 -2826 -2708 1135+41 C/L CREEK - -2896 --2981 -3222 -3175 -3373 -3341 1136+00 -3477 -3428- 1136+24 CROP EDGE _-3568 -3562 - 3428 -3510 1137+00 200*B12 11*30*00 200B12 -3336 -3423 --3489 - 3528 1137+61 CROP EDGE FIE DRY -3557 --3560 --3555 L1138+00 _-3575 =-3697.#

Page 89Pipe/Soil Potential (mv) -300 -600 -900 -1200 -1500 -1800 1139+00 --4106• -4001 1137+76 TS_21.3 FG ON- OFF-1349 NG ON-3781 3547 :-4109= OFF-24 RẸCT 21.3 OFF-1327' IR ON+225 -4162 21.3 VOLTS 1137+76 CMS PANHANDLE AMP$ 46.0 EOS =4220° GATE TO 3 GATE EASTERN 2 -4022= -4156- LINE 1140+00 24 IN COATED NG ON-3781 GS TS '21.3 200 1138+31 1138+84 C/L ASPHALT RD OFF-1327 :- 3845= -4064 -3980= 1138+96 MARKER 1140+26 C/L TOP OF FIELD RD 1140+36 FENCE/MARKER HİLL -4075. -3961" -3995 -3966 1141+00 -3824 -3895 -3940 1141+28 BOTTOM OF HILL -3916 -2681 -3929 -3964 sti 1142+00 -3858 -3990 -4127. -2164 -4188 -4217 -4222 (feet) 1143+00 -4228 -4217 -4206 -4206 -4209 -4204 -4217 •-4185 1144+00 -4177— - :-4151= -4048 --3914 --3850 -3885 1145+00 =-3766= --3724 -3795 --3713 -3731 1146+00 1145+86 TOP OF HILL --3721- --3733- -3763 -3739 --3774- -3784 —-3792 LAztaR -3787#

Page 90Pipe/Soil Potential (mv) -300 -600 -900 - 1200 -1500 -1800 1148+00 -3739 -3753 -3737 -3695- - 3642. -3644 -3615 1149+00. -3576 -3492 - 3523 :-3489= -3462. -3494- 1150+00 -3446 - 3382. =-3417= -3362 -2335 -2130= -3299 ° 1151+00 -3264 -3264 -3262 - 3256 -3209 --3235 -3151. 1152+00 1152+01 TOP OF HİLL -3172= -3180 -2291. -3172 -3154 -3159 -3167 -3061- 1153+00 -- 3164- -3169 - -3143 -3095 -3138 -2317. - 3148 1154+ø0. -3159 -3148 -3161 - 3148 -3156 -3156 -2370 1155+00 -3130 -3135 _-3151. -3156 -3151 --3090- - 3138 -3146 L1156+00 --3090#

Page 91Pipe/Soil Potential (mv) -300 -600 -900 - 1200 -1500 -1800 1157+00 -3090 - 307* 307 --2958. -3056 1158+00 -3010 -298 -300€ -3000 -2987 -2971 -2958 1159+00 -2898 -2903. -2874 -2855 -2847 -2797 • 1160+00 -2752 -2766 -2713 -2723 e -2681 -2610 -2655 (feet) -2586 1161+00 -2515 -2549 -2454 -2486 -2423 -2343 -2341 1162+00 --2272. -2288 - -2214 -2214_ 1162+76 TOP OF HILL -2203 -2201 1163+00 -2114 -2174 --2130. -21084 1164+00 -2169 1164+24 TS NO NUMBER FG ON-2303 -2225 OFF-1130 1125| IR ÖN-143 OFF-3 NG ON-2156 O'FF- --2174- RECON WIRE _-2246 -2301 - 2256 L1165+00 _-2322 -2349#

Page 92Pipe/Soil Potential (mv) -300 - 600 -900 ·1200 -1500 -1800 1166+00 -2438 -2465 -2438 -2446 -2444 -2436 -2407 -2407 -2412 -2412 -2412 -2404 -2423. -2430 1168+00 -2462 -2454 - 2425 - 2430 -2415 -2412 ° 1169+00 1168+86 C/L DITCH BOTTOM OF, HILL -2445— -2436 sta -2459- -2457 - 2536 -2494 -2557 -2568 1170+00 -2568 -2565 -2560 -2523 -2475 -2528 -2491 1171+00 -2502 -2504 - _-2499 -2504 -2404 -2510 1172+00 --2507 _-2520_ --2502 -2499 _- 2528. -2512 -2510 1173+00 -2504 -2502- --2196. -25.04. -2507 -2504 L1174+00 --2507. -2483#

Page 93Pipe/Soil Potential (mv) -300 -600 -900 - 1200 -1500 - 1800 1175+00 1174+64 TOP OF HILL _-2481- -2452 -2457 -2446. -2417 -2438 -2272 1176+00 -2452 -2491. -2457 -2467. -2467 _-2512 1176+78 FENCE -2496 -2499 1177+00 _-2536. -2499 -2507 -2515 -2507 -2515 • 1178+00 -2520 -2523 -2520 taine -2523 -2520 -2523 -2515 (fe et) -2557 1179+00 -2520 -2512 -2552 -2504 -2525 1180+00 1179+84 BOTTOM OF HILL _-2496 -2167 -2486 - _-2491 -2483 -2454 -2433 -2275 -2404 -2399 1181+00. -2388 -2401 -2370— -2335 -2335 -2301 -2317 1182+00. -2304 -2304 -2293 -2264 -2280 -2243 -2248 L1183+00 -2156 -2203#

Page 94Pipe/Soil Potential (mv) -300 -600 -900 -1200 -1500 - 1800 1184+00 -2135 -2103 -2164 -2167- 1184+56 TOP OF HILL -2196 -2148: -2214 1185+00 -2222 -2254 -2238 --2280 -2291 1186+00 --2280 -2291 - 2288 -2285 -2298 -230€ 01187+00 -2259 - 2254. 227 227 1187+68 C/L DITCH BOTTOM OF HILL --2285. eet) -230 1188+00 227: -2246 -2254 -224€ -222: 1189+00 1188+84 HOLTSVOLTAGE LINE AC . 5 - 2190. -2188. - 2167 - •214 210 1189+76 TOP OF HILL 1190+00 210 214 1191+00-1191+06 TS NO NUMBER FG ON-2162 OFF-1194 1187 IR ÓN-95 NG ON-2066 OFF-5 O'FF- _-2193 WIRE -2130 -2127 -2114 --2180 4192+00 -2148 -2140#

Page 95Pipe/Soil Potential (mv) -300 -600 -900 r - 1200 - 1500 - 1800 1193+00 -2193— -2130_ -2135 _-2132. -2103_ -2114 -2114_ 1194+00 1195+00 1195+08 C/L CREEK ° 1196+00 sta. 1197+00 1196+91 C/L CREEK BOTTOM OF HILL 1-2119_ 1198+00 - 1199+00 1200+00 1201+00#

Page 96Pipe/Soil Potential (mv) -300 -600 -900 -1200 1500 -1800 1202+00 1203+00 1204+00 1204+16 MARKER 1205+00 ta. (feet) 1206+00 1207+00 1208+00 1209+00 L1219+00#

Page 97: Pipe/Soil Potential (mv) -300 -600 900 -12007 -1500 - 1800 1211+00 1210+64 TOP OF HILL C/L FIELD RD- 1212+00. 1213+00 Dista 1214+00 -e (feet) 1215+00 1216+00 1216+36 BOTTOM OF HILL 1217+00 1217+61 FENCE 1218+00 4219+00#

Page 98Pipe/Soil Potential -300 -600 -900 - -1200 - 1500 - 1800 1220+00 1219+26 ERNEARKER EDGE 1221+00 1222+00 1223+00. Distane (feet) 1224+00 1225+00 1225+16 FENCE/MARKER 1226+00 1227+00 4228+00#

Page 99Pipe/Soi Potential -300 -600 -1200 - 1500 - 1800 1229+00 1229+26 C/L FIELD RD 1230+00 1231+00 1231+16 TEN NG 0N-6199 0274 OFF-998 NG IR ON-98 OFF ON-1179 RECON WIRE ° 1232+00. staine (feet) 1233+00 1234+00 1235+00 1236+00 L1237+00#

Page 100Pipe/Soil Potential (mV) -300 -600 -900 -Iz00 -1500 - 1800 1238+00 1239+00 1240+00 E © 1241+00 tance (fee +) 1242+00 1242+18 FENCE/MARKER 1243+00 1244+00 5 1245+00 1244+91 BOTTOM OF HILL 1246+00#

Page 101Potential (mv) -300 -600 -900 1200 - 1500 - 1800 1247+00 1246+14 FENCE/MARKER 1248+00 1249+00 1250+00 Distance (feet) 1251+00 1252+00 - 1253+00 1254+00 1255+00#

Page 102Pipe/Soil Potential -300 -600 -900 - 1200 -1500 - 1800 1256+00 1255+11 FENCE/MARKER 1257+00 1258+00 ista 1259+00. (feet) 1260+00 1261+00 - 1262+D01262+06 FENCE/MARKER 1263+00 L1264+00.#

Page 103Pipe/Soi (mv) -300 -600 -900 -1.200 - 1500 -1800 1265+00 1266+00 1267+00 ° 1268+00 GaMAaaG Mamaraamdnl tance (feet) 1269+00 1269+38 TS_23.7 FG ON- 1461 OFF-Îi25' IR ON-53" OFF-5 OFF-1132 NG ON-1414 1269+38 SATE TOHAN SAT FASTE 203 1270+00 GATE TO 200B14 23.7 1269+78 FÉNCE/MARKER® GRAVEL 230jal BRELD 1271+00 1271+38 CROP EDGE 1272+00 4273+00#

Page 104Pipe/Soil Potential (mv) ( -300 -600 -900 -1200 =1800 1274+00 1275+00 1276+00 1277+00 stance 1278+00 1278+38 FENCE/MARKER 1279+00 - 1280+00 1281+00 1281+41 C/L DITCH BOTTOM OF HILL L1282+00#

Page 105Pipe/Soil Potential -300 -600 -900 1200 - 1500 - 1800 1283+00 1284+00 1283+88 FENCE/MARKER 1284+61 FENCE/MARKER 1285+00 1285+11 MARKER 1285+54 TOP OF HİLL 1286+00 istance (feet) 1287+00 1288+00 - ПЛП 1289+00. 1289+41 C/L CREEK BOTTOM OF HILL 1290+00 11291+20#

Page 106Pipe/Soil Potential (mv) -300 -600 -900 -1200 -1500 -1800 my hyp 1294+00 1295+00 stance 1295+66 MARKER TOP OF HILL 1296+00. 1297+00 1297+36 MARKER - 1298+00 1299+00 L1300+00#

Page 107Pipe/Soil Potential (mv) -300 -600 -900 -1200 -1500 - 1800 1301+00 1301+66 C/L CREEK BOTTOM OF HILL 1302+00 1303+00 Dista _1304+0.0 (feet) 1305+00 1306+00 1306+68 TS 0FF-1209 24.4 FG ON- 1594 NG ON-1581 1307+00 EOS OFF-1210 IR ON-8 OFF+2 1308+00 L1309+00#