Failure Report-Chevron Pipe Line Company 9/8/2011

Page 1Official PDFDOT US Department of Transportation PHMSA Pipeline and Hazardous Materials Safety Administration OPS Office of Pipeline Safety Southwest Region Investigators Richard Lopez and Joseph Elmer Region Director R. M. Seeley Date of Report April 19, 2012 Subject Failure Investigation Report – Chevron Coahoma LPG Loop Operator, Location, & Consequences Date of Failure 09/08/2011 Commodity Released Liquefied Petroleum Gas (LPG) City/County & State Mitchell County, Texas OpID & Operator Name 2731, Chevron Pipe Line Company Unit # & Unit Name 36804, West Texas LPG System #3 SMART Activity # 135846 Milepost / Location MP 148.8, remote area Type of Failure Crack near weld Fatalities 0 Injuries 0 Description of area Rural – open range impacted Property Damage $1,501,020#

Page 2Failure Investigation Report – Chevron Coahoma LPG Loop Failure Date 9/8/2011 Executive Summary At approximately 07:50 a.m. on September 8, 2011, a failure occurred on the Chevron Pipe Line Company’s (CPL) 10-inch Coahoma LPG Loop pipeline, which resulted in the release of approximately 13,241 barrels of LPG. The failure occurred approximately 40 feet west of CPL’s MP 148.8, 2.7 miles south of Interstate 10 (Exit 200) in Mitchell County, Texas. The area where the leak occurred is remote, isolated ranch land, not an HCA, and there are no known unusually sensitive environmental areas in the vicinity. The incident was reported to the National Response Center as NRC Report # 988809. The product released from the pipeline vaporized, ignited and caused a brush fire. The probable ignition source for the fire was the start up of a production pump. There were no injuries or fatalities. The failure occurred near the fillet weld of a reinforcing sleeve. The damaged segment was transported to Stress Engineering Services (SES) in Houston, TX for analysis. The probable cause of the failure was determined to be a crack in the 10-inch diameter pipe located at the upstream fillet weld of the external sleeve. The crack was the result of a combination of bending loads and excessive hardness in the heat affected zone (HAZ) of the weld. Chevron submitted an initial and final report to PHMSA. Page 2 of 8#

Page 3Failure Investigation Report – Chevron Coahoma LPG Loop Failure Date 9/8/2011 System Details The CPL West Texas LPG pipeline originates at natural gas processing facilities in western Texas and New Mexico and ends at product storage facilities at Mt. Belvieu, TX and is approximately 2750 miles long. The route is shown in a map provided by Chevron (Appendix A). Pipe Specifications The segment of pipeline where the failure occurred was the 10-inch (nominal diameter) Loop line. This segment was fabricated using 0.219-inch wall thickness, Grade X-52, electric fusion welded line pipe manufactured by US Steel and was constructed in 1967. Chevron reports that no known prior accidents exist on this section. The pipeline is cathodically protected by an impressed current system. Chevron further reports that an ILI was performed in 2007 and adequate cathodic protection has been maintained. The maximum operating pressure (MOP) of the segment of pipe where the failure occurred is 1042 psig. The MOP was established in 1967 by an eight-hour hydrostatic test. Actual operating pressure of the pipeline segment at time of failure was 600 psig. Sketch 1 – Pig Trap upstream of failure site (flow is from left to right) The leak site is approx. 17.2 miles east CPL’s Coahoma pump station (Howard Co. TX.) and approx. 40-feet west of the MP 148.8 pig trap (Mitchell Co. TX). The area where the leak occurred is remote, isolated ranch land. The terrain is generally flat with arid soil conditions typical of the West Texas region. Page 3 of 8#

Page 4Failure Investigation Report – Chevron Coahoma LPG Loop Failure Date 9/8/2011 Photo 1 – Facing upstream on line that failed Events Leading up to the Failure CPL’s Houston Control Center, while investigating a potential leak due to system imbalance, had shut down the two 10-inch sections of the LPG System for a stand up test at MP 158 & MP 139. One of the 10-inch lines was blocked in at 06:47 a.m. and the other at 06:58 a.m. Shortly after the shut down the control center received a phone call at 07:52 a.m. reporting a vapor cloud in the vicinity of the Chevron pipelines. The control center then received another phone call a few minutes later reporting that the vapor cloud had ignited. Chevron personnel and local Volunteer Fire Department personnel arrived at the scene and began spraying water around the perimeter to extinguish any grass fires. Photo 2 – Pig trap area facing upstream Page 4 of 8#

Page 5Failure Investigation Report – Chevron Coahoma LPG Loop Failure Date 9/8/2011 The photo is an upstream view of the two 10-inch pipelines within the trap area. The line on the right hand side is the 10-inch Loop line – the line that failed. The line in the middle was not affected. The line on the left is the 14-inch line that continues to Mt. Belvieu. Fire during the accident engulfed both 10-inch pipelines in the trap area. Product from the failure site that is still burning can be seen in the background. Temporary flares can also be seen in the background. Emergency Response CPL’s Houston Control Center (investigating a potential leak, due to system imbalance) had shut down the two 10-inch sections of the LPG System for a stand up test at MP 158 and MP 139. The two 10-inch lines were blocked in at 06:47 and 06:58 a. m. respectively. The failure occurred near the fillet weld of a reinforcing sleeve. The product released from the pipeline, vaporized, ignited and caused a brush fire. The fire continued to burn from the pipeline for several days after the failure likely because the ‘ice ball’ was slow to dissolve and kept supplying LPG vapors entrained in the ice ball. The probable ignition source for the fire was the start up of a production pump. There were no injuries or fatalities. Summary of Return-to-Service Both of the aboveground segments of the 10-inch pipelines and their respective main line valves located at the MP 148 valve site were engulfed in the fire. The aboveground pipe was tested for integrity by Chevron material specialists. They conducted both the Brinnell and Rockwell hardness tests and concluded that both lines were safe to operate. Photo 3 – Chevron specialists performing integrity tests The valves on the inside 10-inch line (Line 2) in the scraper trap were evaluated by Chevron personnel after purging the LPG from the line. The valves internals on the line were then removed and replaced by a contractor. With the valves rebuilt, Line No. 2 was returned to service. No upstream service disruptions to Gas Processing Plants were caused by this accident. The failed piece was cut and shipped to a metallurgical lab in Houston for detailed failure analysis. The valves on Line No. 1 were also inspected and repairs were not required. Page 5 of 8#

Page 6Failure Investigation Report – Chevron Coahoma LPG Loop Failure Date 9/8/2011 During the course of the investigation, PHMSA inspectors reviewed the Return to Service plans prepared by Chevron. No concerns were identified. A close interval cathodic protection survey was performed during the investigation. Levels of protection met the protection criteria. Investigation Details At approximately 09:39 a.m. (EST) on September 8, 2011, CPL reported to the National Response Center a failure on their West Texas LPG pipeline (Appendix B). The leak site is approximately 17.2 miles east CPL’s Coahoma pump station (Howard Co. TX.) and approximately 40-feet west of the MP 148.8 pig trap (Mitchell Co. TX). The area where the leak occurred is remote, isolated ranch land. The terrain is generally flat with arid soil conditions typical of the West Texas region. Chevron submitted an initial report to PHMSA as required by §195.54 Accident reports (Appendix C). PHMSA’s Southwest Region received the incident notification and dispatched investigators to the site the following day. The investigators arrived on site on September 9th. The maximum operating pressure (MOP) of the segment of the pipeline where the failure occurred is 1042 psig. The MOP was established in 1967 by an eight-hour hydrostatic test. Actual operating pressure of the pipeline segment at time of failure was 600 psig. The incident occurred below the specified MOP. The pipeline was last inline inspected (ILI) in 2007. There were no actionable anomalies identified in the area of the failure by the ILI. Chevron prepared a Work Plan to ensure a safe environment for investigating personnel entering the failure site. The Work Plan was reviewed by all involved entities. PHMSA Investigators were able to enter the area of the failure on September 9th but because the release product was still burning Chevron was unable to excavate to enable examination the failed segment of the pipeline. The released product continued to burn for several days likely because the melting of the ice ball kept feeding flammable vapors that ignited. Photos 4 and 5 – Showing the failure and the location of the failure Page 6 of 8#

Page 7Failure Investigation Report – Chevron Coahoma LPG Loop Failure Date 9/8/2011 Metallurgical Analysis The pipeline segments involved in the incident were shipped to SES in Houston, TX for metallurgical analysis. SES’s analysis (Appendix D) identifies that: 1. The failure occurred near the fillet weld of sleeve on an anchor near a pig trap. 2. The controller’s actions were appropriate and the incident location was isolated promptly. Photo 6 – Segment removed for metallurgical testing Findings & Contributing Factors Subsequent initial visual inspection of the failed section of pipeline showed the failure likely initiated at an anchor on the 10-inch Loop line. It is not known when or why the anchor was installed. The failure appeared to have occurred near the fillet weld where a reinforcing sleeve had been welded to the pipeline at an anchor. The damaged segment was transported to Stress Engineering Services (SES) in Houston, TX for analysis. The probable cause of the failure was determined to be a crack in the 10-inch diameter pipe located at the upstream fillet weld of the external sleeve. The crack was the result of a combination of bending loads and excessive hardness in the heat affected zone (HAZ) of the weld. Page 7 of 8#

Page 8Failure Investigation Report – Chevron Coahoma LPG Loop Failure Date 9/8/2011 Appendices A Map of CPL’s West Texas LPG system B Telephonic Notice Report – NRC #988809 C Chevron Accident Report to PHMSA 20110380-16525 D Metallurgical Evaluation Report Page 8 of 8#

Page 9Appendix A Map of CPL’s West Texas LPG system This document is on file at PHMSA#

Page 10Appendix B Telephonic Notice Report – NRC #988809#

Page 11Lewis, Cynthia (PHMSA) From: Sent: HQS-PF-fldr-NRC@uscg.mil To: Thursday, September 08, 2011 8:46 AN Subject: HP Accident/Incident Cadre <PHMSA>; CMC-01 (OST NRC#988809 NATIONAL RESPONSE CENTER 1-800-424-8802 ***GOVERNMENT USE ONLY***GOVERNMENT USE ONLY*** Information released to a third party shall comply with any applicable federal and/or state Freedom of Information and Privacy Laws Incident Report # 988809 INCIDENT DESCRIPTION *Report taken by: MST1 JERRY HARDY at 09:39 on 08-SEP-11 Incident Type: PIPELINE Incident Cause: UNKNOWN Affected Area: Incident was discovered on 08-SEP-11 at 07:50 local incident time. Affected Medium: AIR ATMOSPHERE REPORTING PARTY Name: JOSEPH WHITE Organization: CHEVRON PIPELINE CO. Address: 4800 FOURNACE PL BELLAIRE, TX 77401 PRIMARY Phone: (281)6301927 Type of Organization: PRIVATE ENTERPRISE SUSPECTED RESPONSIBLE PARTY Name: JOSEPH WHITE Organization: CHEVRON PIPELINE CO. Address: 4800 FOURNACE PL BELLAIRE, TX 77401 PRIMARY Phone: (281)6301927 INCIDENT LOCATION County: HOWARD City: COAHOMA State: TX Latitude: 32° 15' 04" N Longitude: 101° 18'21" W 4 MILE SOUTH OF NEAREST TOWN RELEASED MATERIAL(S) CHRIS Code: LPG Official Material Name: LIQUEFIED PETROLEUM GAS Also Known As: Qty Released: 0 UNKNOWN AMOUNT 1#

Page 12________________________________________________________________________ DESCRIPTION OF INCIDENT CALLER REPORTED THAT A THIRD PARTY DISCOVERED A VAPOR CLOUD WHICH THEN IGNITE FROM AN UNKNOWN SOURCE. ________________________________________________________________________ SENSITIVE INFORMATION ________________________________________________________________________ INCIDENT DETAILS Pipeline Type: TRANSMISSION DOT Regulated: YES Pipeline Above/Below Ground: BELOW Exposed or Under Water: NO Pipeline Covered: UNKNOWN ______________________________________________________________________ IMPACT Fire Involved: YES Fire Extinguished: NO INJURIES: NO Hospitalized: Empl/Crew: Passenger: FATALITIES: NO Empl/Crew: Passenger: Occupant: EVACUATIONS:NO Who Evacuated: Radius/Area: Damages: NO Hours Direction of Closure Type Description of Closure Closed Closure N Air: N Major Road: Artery:N N Waterway: N Track: Environmental Impact: UNKNOWN Media Interest: NONE Community Impact due to Material: ______________________________________________________________________ REMEDIAL ACTIONS LINE BLOCKED IN, AREA SECURED. Release Secured: UNKNOWN Release Rate: Estimated Release Duration: ______________________________________________________________________ WEATHER Weather: CLEAR, 68ºF Wind speed: 7 MPH Wind direction: NNE ______________________________________________________________________ ADDITIONAL AGENCIES NOTIFIED Federal: NONE 2#

Page 13State/Local: TEXAS RAILROAD COMMISION State/Local On Scene: NONE State Agency Number: 20112678 _______________________________________________________________________ NOTIFICATIONS BY NRC CALCASIEU PARISH SHERIFF'S DEPT (CRIMINAL INTELLIGENCE UNIT) 08‐SEP‐11 09:45 (337)4913778 USCG ICC (ICC ONI) 08‐SEP‐11 09:45 (301)6693363 DHS TEXAS FUSION CENTER (INTELLIGENCE OFFICERS) 08‐SEP‐11 09:45 (202)3068204 DOT CRISIS MANAGEMENT CENTER (MAIN OFFICE) 08‐SEP‐11 09:45 (202)3661863 U.S. EPA VI (MAIN OFFICE) (866)3727745 USCG NATIONAL COMMAND CENTER (MAIN OFFICE) (202)3722100 JFO‐LA (COMMAND CENTER) 08‐SEP‐11 09:45 (225)3366513 NATIONAL INFRASTRUCTURE COORD CTR (MAIN OFFICE) 08‐SEP‐11 09:45 (202)2829201 NOAA RPTS FOR TX (MAIN OFFICE) 08‐SEP‐11 09:45 (206)5264911 NATIONAL RESPONSE CENTER HQ (MAIN OFFICE) (202)2671136 PIPELINE & HAZMAT SAFETY ADMIN (OFFICE OF PIPELINE SAFETY (AUTO)) 08‐SEP‐11 09:45 (202)3660568 TCEQ (MAIN OFFICE) 08‐SEP‐11 09:45 (512)2392507 TEXAS STATE OPERATIONS CENTER (COMMAND CENTER) 08‐SEP‐11 09:45 (512)4242208 _______________________________________________________________________ ADDITIONAL INFORMATION CALLER HAD NO ADDITIONAL INFORMATION. ______________________________________________________________________ *** END INCIDENT REPORT #988809 *** Report any problems by calling 1‐800‐424‐8802 PLEASE VISIT OUR WEB SITE AT http://www.nrc.uscg.mil 3#

Page 14Appendix C Chevron Accident Report to PHMSA – 20110380#

Page 15NOTICE: This report is required by 49 CFR Part 195. Failure to report can result in a civil penalty not to exceed $100,000 for each violation for each day that such violation persists except that the maximum civil penalty shall not exceed $1,000,000 as provided in 49 USC 60122. OMB NO: 2137-0047 EXPIRATION DATE: 01/31/2013 Report Date: 10/08/2011 No. U.S Department of Transportation Pipeline and Hazardous Materials Safety Administration 20110380 - 16525 -------------------------(DOT Use Only) ACCIDENT REPORT - HAZARDOUS LIQUID PIPELINE SYSTEMS A federal agency may not conduct or sponsor, and a person is not required to respond to, nor shall a person be subject to a penalty for failure to comply with a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of information displays a current valid OMB Control Number. The OMB Control Number for this information collection is 2137-0047. Public reporting for this collection of information is estimated to be approximately 10 hours per response (5 hours for a small release), including the time for reviewing instructions, gathering the data needed, and completing and reviewing the collection of information. All responses to this collection of information are mandatory. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden to: Information Collection Clearance Officer, PHMSA, Office of Pipeline Safety (PHP-30) 1200 New Jersey Avenue, SE, Washington, D.C. 20590. 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 PHMSA Pipeline Safety Community Web Page at http://www.phmsa.dot.gov/pipeline. PART A - KEY REPORT INFORMATION Report Type: (select all that apply) Original: Supplemental: Yes Final: Yes Last Revision Date: 03/27/2012 1. Operator's OPS-issued Operator Identification Number (OPID): 2731 2. Name of Operator CHEVRON PIPE LINE CO 3. Address of Operator: 3a. Street Address 4800 FOURNACE PLACE, Rm C382A 3b. City BELLAIRE 3c. State Texas 3d. Zip Code 774012324 4. Local time (24-hr clock) and date of the Accident: 09/08/2011 07:50 5. Location of Accident: Latitude: 32.251168 Longitude: -101.305851 6. National Response Center Report Number (if applicable): 988809 7. Local time (24-hr clock) and date of initial telephonic report to the National Response Center (if applicable): 09/08/2011 08:36 8. Commodity released: (select only one, based on predominant volume released) HVL or Other Flammable or Toxic Fluid which is a Gas at Ambient Conditions - Specify Commodity Subtype: LPG (Liquefied Petroleum Gas) / NGL (Natural Gas Liquid) - If "Other" Subtype, Describe: - If Biofuel/Alternative Fuel and Commodity Subtype is Ethanol Blend, then % Ethanol Blend: %: - If Biofuel/Alternative Fuel and Commodity Subtype is Biodiesel, then Biodiesel Blend (e.g. B2, B20, B100): B 9. Estimated volume of commodity released unintentionally (Barrels): 13,241.00 10. Estimated volume of intentional and/or controlled release/blowdown (Barrels): 11. Estimated volume of commodity recovered (Barrels): 12. Were there fatalities? No - If Yes, specify the number in each category: 12a. Operator employees 12b. Contractor employees working for the Operator 12c. Non-Operator emergency responders 12d. Workers working on the right-of-way, but NOT associated with this Operator 12e. General public 12f. Total fatalities (sum of above) 13. Were there injuries requiring inpatient hospitalization? No - If Yes, specify the number in each category: 13a. Operator employees 13b. Contractor employees working for the Operator 13c. Non-Operator emergency responders Page 1 of 14 Reproduction of this form is permitted#

Page 1613d. Workers working on the right-of-way, but NOT associated with this Operator 13e. General public 13f. Total injuries (sum of above) 14. Was the pipeline/facility shut down due to the Accident? - If No, Explain: - If Yes, complete Questions 14a and 14b: (use local time, 24-hr clock) 14a. Local time and date of shutdown: 14b. Local time pipeline/facility restarted: - Still shut down? (* Supplemental Report Required) 15. Did the commodity ignite? Yes 16. Did the commodity explode? Yes 17. Number of general public evacuated: 0 18. Time sequence (use local time, 24-hour clock): 18a. Local time Operator identified Accident: 09/08/2011 07:52 18b. Local time Operator resources arrived on site: 09/08/2011 08:20 PART B - ADDITIONAL LOCATION INFORMATION 1. Was the origin of Accident onshore? Yes If Yes, Complete Questions (2-12) If No, Complete Questions (13-15) - If Onshore: 2. State: Texas 3. Zip Code: 79565 4. City Latan 5. County or Parish Mitchell 6. Operator-designated location: Milepost/Valve Station Specify: 148.7 7. Pipeline/Facility name: West Texas LPG 8. Segment name/ID: 10" Coahoma LPG Loop 9. Was Accident on Federal land, other than the Outer Continental Shelf (OCS)? No 10. Location of Accident: Pipeline Right-of-way 11. Area of Accident (as found): Underground Specify: Under soil - If Other, Describe: Depth-of-Cover (in): 39 12. Did Accident occur in a crossing? No - If Yes, specify below: - If Bridge crossing – Cased/ Uncased: - If Railroad crossing – Cased/ Uncased/ Bored/drilled - If Road crossing – Cased/ Uncased/ Bored/drilled - If Water crossing – Cased/ Uncased - Name of body of water, if commonly known: - Approx. water depth (ft) at the point of the Accident: - Select: - If Offshore: 13. Approximate water depth (ft) at the point of the Accident: 14. Origin of Accident: - In State waters - Specify: - State: - Area: - Block/Tract #: - Nearest County/Parish: - On the Outer Continental Shelf (OCS) - Specify: - Area: - Block #: 15. Area of Accident: PART C - ADDITIONAL FACILITY INFORMATION 1. Is the pipeline or facility: Interstate 2. Part of system involved in Accident: Onshore Pipeline, Including Valve Sites - If Onshore Breakout Tank or Storage Vessel, Including Attached Appurtenances, specify: 3. Item involved in Accident: Weld, including heat-affected zone Page 2 of 14 Reproduction of this form is permitted#

Page 17- If Pipe, specify: 3a. Nominal diameter of pipe (in): 3b. Wall thickness (in): 3c. SMYS (Specified Minimum Yield Strength) of pipe (psi): 3d. Pipe specification: 3e. Pipe Seam , specify: - If Other, Describe: 3f. Pipe manufacturer: 3g. Year of manufacture: 3h. Pipeline coating type at point of Accident, specify: - If Other, Describe: - If Weld, including heat-affected zone, specify: Fillet Weld - If Other, Describe: - If Valve, specify: - If Mainline, specify: - If Other, Describe: 3i. Manufactured by: 3j. Year of manufacture: - If Tank/Vessel, specify: - If Other - Describe: - If Other, describe: 4. Year item involved in Accident was installed: 1967 5. Material involved in Accident: Carbon Steel - If Material other than Carbon Steel, specify: 6. Type of Accident Involved: Leak - If Mechanical Puncture – Specify Approx. size: in. (axial) by in. (circumferential) - If Leak - Select Type: Crack - If Other, Describe: - If Rupture - Select Orientation: - If Other, Describe: Approx. size: in. (widest opening) by in. (length circumferentially or axially) - If Other – Describe: PART D - ADDITIONAL CONSEQUENCE INFORMATION 1. Wildlife impact: No 1a. If Yes, specify all that apply: - Fish/aquatic - Birds - Terrestrial 2. Soil contamination: No 3. Long term impact assessment performed or planned: No 4. Anticipated remediation: No 4a. If Yes, specify all that apply: - Surface water - Groundwater - Soil - Vegetation - Wildlife 5. Water contamination: No 5a. If Yes, specify all that apply: - Ocean/Seawater - Surface - Groundwater - Drinking water: (Select one or both) - Private Well - Public Water Intake 5b. Estimated amount released in or reaching water (Barrels): 5c. Name of body of water, if commonly known: 6. At the location of this Accident, had the pipeline segment or facility been identified as one that "could affect" a High Consequence Area (HCA) as determined in the Operator's Integrity Management Program? No 7. Did the released commodity reach or occur in one or more High Consequence Area (HCA)? No 7a. If Yes, specify HCA type(s): (Select all that apply) - Commercially Navigable Waterway: Was this HCA identified in the "could affect" Page 3 of 14 Reproduction of this form is permitted#

Page 18determination for this Accident site in the Operator's Integrity Management Program? - High Population Area: Was this HCA identified in the "could affect" determination for this Accident site in the Operator's Integrity Management Program? - Other Populated Area Was this HCA identified in the "could affect" determination for this Accident site in the Operator's Integrity Management Program? - Unusually Sensitive Area (USA) - Drinking Water Was this HCA identified in the "could affect" determination for this Accident site in the Operator's Integrity Management Program? - Unusually Sensitive Area (USA) - Ecological Was this HCA identified in the "could affect" determination for this Accident site in the Operator's Integrity Management Program? 8. Estimated Property Damage: 8a. Estimated cost of public and non-Operator private property damage $ 0 8b. Estimated cost of commodity lost $ 1,001,020 8c. Estimated cost of Operator's property damage & repairs $ 400,000 8d. Estimated cost of Operator's emergency response $ 100,000 8e. Estimated cost of Operator's environmental remediation $ 0 8f. Estimated other costs $ 0 Describe: 8g. Total estimated property damage (sum of above) $ 1,501,020 PART E - ADDITIONAL OPERATING INFORMATION 1. Estimated pressure at the point and time of the Accident (psig): 600.00 2. Maximum Operating Pressure (MOP) at the point and time of the Accident (psig): 1,040.00 3. Describe the pressure on the system or facility relating to the Accident (psig): Pressure did not exceed MOP 4. Not including pressure reductions required by PHMSA regulations (such as for repairs and pipe movement), was the system or facility relating to the Accident operating under an established pressure restriction with pressure limits below those normally allowed by the MOP? No - If Yes, Complete 4.a and 4.b below: 4a. Did the pressure exceed this established pressure restriction? 4b. Was this pressure restriction mandated by PHMSA or the State? 5. Was "Onshore Pipeline, Including Valve Sites" OR "Offshore Pipeline, Including Riser and Riser Bend" selected in PART C, Question 2? Yes - If Yes - (Complete 5a. – 5f. below) 5a. Type of upstream valve used to initially isolate release source: Manual 5b. Type of downstream valve used to initially isolate release source: Manual 5c. Length of segment isolated between valves (ft): 100,320 5d. Is the pipeline configured to accommodate internal inspection tools? Yes - If No, Which physical features limit tool accommodation? (select all that apply) - Changes in line pipe diameter - Presence of unsuitable mainline valves - Tight or mitered pipe bends - Other passage restrictions (i.e. unbarred tee's, projecting instrumentation, etc.) - Extra thick pipe wall (applicable only for magnetic flux leakage internal inspection tools) - Other - - If Other, Describe: 5e. For this pipeline, are there operational factors which significantly complicate the execution of an internal inspection tool run? No - If Yes, Which operational factors complicate execution? (select all that apply) - Excessive debris or scale, wax, or other wall buildup Page 4 of 14 Reproduction of this form is permitted#

Page 19- Low operating pressure(s) - Low flow or absence of flow - Incompatible commodity - Other - If Other, Describe: 5f. Function of pipeline system: > 20% SMYS Regulated Trunkline/Transmission 6. Was a Supervisory Control and Data Acquisition (SCADA)-based system in place on the pipeline or facility involved in the Accident? Yes If Yes 6a. Was it operating at the time of the Accident? Yes 6b. Was it fully functional at the time of the Accident? Yes 6c. Did SCADA-based information (such as alarm(s), alert(s), event(s), and/or volume calculations) assist with the detection of the Accident? Yes 6d. Did SCADA-based information (such as alarm(s), alert(s), event(s), and/or volume calculations) assist with the confirmation of the Accident? No 7. Was a CPM leak detection system in place on the pipeline or facility involved in the Accident? Yes - If Yes: 7a. Was it operating at the time of the Accident? Yes 7b. Was it fully functional at the time of the Accident? Yes 7c. Did CPM leak detection system information (such as alarm(s), alert(s), event(s), and/or volume calculations) assist with the detection of the Accident? Yes 7d. Did CPM leak detection system information (such as alarm(s), alert(s), event(s), and/or volume calculations) assist with the confirmation of the Accident? No 8. How was the Accident initially identified for the Operator? CPM leak detection system or SCADA-based information (such as alarm(s), alert(s), event(s), and/or volume calculations) - If Other, Specify: 8a. If "Controller", "Local Operating Personnel", including contractors", "Air Patrol", or "Guard Patrol by Operator or its contractor" is selected in Question 8, specify the following: 9. Was an investigation initiated into whether or not the controller(s) or control room issues were the cause of or a contributing factor to the Accident? No, the Operator did not find that an investigation of the controller(s) actions or control room issues was necessary due to: (provide an explanation for why the Operator did not investigate) - If No, the Operator did not find that an investigation of the controller(s) actions or control room issues was necessary due to: (provide an explanation for why the operator did not investigate) Control center personnel had detected the system imbalance, ordered the system blocked in & initated field investigation in the area of the imbalance, prior to receiving the phone call confirming the location of the leak. - If Yes, specify investigation result(s): (select all that apply) - Investigation reviewed work schedule rotations, continuous hours of service (while working for the Operator), and other factors associated with fatigue - Investigation did NOT review work schedule rotations, continuous hours of service (while working for the Operator), and other factors associated with fatigue Provide an explanation for why not: - Investigation identified no control room issues - Investigation identified no controller issues - Investigation identified incorrect controller action or controller error - Investigation identified that fatigue may have affected the controller(s) involved or impacted the involved controller(s) response - Investigation identified incorrect procedures - Investigation identified incorrect control room equipment operation - Investigation identified maintenance activities that affected control room operations, procedures, and/or controller response - Investigation identified areas other than those above: Describe: PART F - DRUG & ALCOHOL TESTING INFORMATION Page 5 of 14 Reproduction of this form is permitted#

Page 201. As a result of this Accident, were any Operator employees tested under the post-accident drug and alcohol testing requirements of DOT's Drug & Alcohol Testing regulations? No - If Yes: 1a. Specify how many were tested: 1b. Specify how many failed: 2. As a result of this Accident, were any Operator contractor employees tested under the post-accident drug and alcohol testing requirements of DOT's Drug & Alcohol Testing regulations? No - If Yes: 2a. Specify how many were tested: 2b. Specify how many failed: PART G – APPARENT CAUSE Select only one box from PART G in shaded column on left representing the APPARENT Cause of the Accident, and answer the questions on the right. Describe secondary, contributing or root causes of the Accident in the narrative (PART H). Apparent Cause: G5 - Material Failure of Pipe or Weld G1 - Corrosion Failure - only one sub-cause can be picked from shaded left-hand column External Corrosion: Internal Corrosion: - If External Corrosion: 1. Results of visual examination: - If Other, Describe: 2. Type of corrosion: (select all that apply) - Galvanic - Atmospheric - Stray Current - Microbiological - Selective Seam - Other: - If Other, Describe: 3. The type(s) of corrosion selected in Question 2 is based on the following: (select all that apply) - Field examination - Determined by metallurgical analysis - Other: - If Other, Describe: 4. Was the failed item buried under the ground? - If Yes : 4a. Was failed item considered to be under cathodic protection at the time of the Accident? If Yes - Year protection started: 4b. Was shielding, tenting, or disbonding of coating evident at the point of the Accident? 4c. Has one or more Cathodic Protection Survey been conducted at the point of the Accident? If "Yes, CP Annual Survey" – Most recent year conducted: If "Yes, Close Interval Survey" – Most recent year conducted: If "Yes, Other CP Survey" – Most recent year conducted: - If No: 4d. Was the failed item externally coated or painted? 5. Was there observable damage to the coating or paint in the vicinity of the corrosion? - If Internal Corrosion: 6. Results of visual examination: - Other: 7. Type of corrosion (select all that apply): - Corrosive Commodity - Water drop-out/Acid - Microbiological - Erosion - Other: - If Other, Describe: 8. The cause(s) of corrosion selected in Question 7 is based on the following (select all that apply): - Field examination Page 6 of 14 Reproduction of this form is permitted#

Page 21- Determined by metallurgical analysis - Other: - If Other, Describe: 9. Location of corrosion (select all that apply): - Low point in pipe - Elbow - Other: - If Other, Describe: 10. Was the commodity treated with corrosion inhibitors or biocides? 11. Was the interior coated or lined with protective coating? 12. Were cleaning/dewatering pigs (or other operations) routinely utilized? 13. Were corrosion coupons routinely utilized? Complete the following if any Corrosion Failure sub-cause is selected AND the "Item Involved in Accident" (from PART C, Question 3) is Tank/Vessel. 14. List the year of the most recent inspections: 14a. API Std 653 Out-of-Service Inspection - No Out-of-Service Inspection completed 14b. API Std 653 In-Service Inspection - No In-Service Inspection completed Complete the following if any Corrosion Failure sub-cause is selected AND the "Item Involved in Accident" (from PART C, Question 3) is Pipe or Weld. 15. Has one or more internal inspection tool collected data at the point of the Accident? 15a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run: - Magnetic Flux Leakage Tool Most recent year: - Ultrasonic Most recent year: - Geometry Most recent year: - Caliper Most recent year: - Crack Most recent year: - Hard Spot Most recent year: - Combination Tool Most recent year: - Transverse Field/Triaxial Most recent year: - Other Most recent year: Describe: 16. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Accident? If Yes Most recent year tested: Test pressure: 17. Has one or more Direct Assessment been conducted on this segment? - If Yes, and an investigative dig was conducted at the point of the Accident:: Most recent year conducted: - If Yes, but the point of the Accident was not identified as a dig site: Most recent year conducted: 18. Has one or more non-destructive examination been conducted at the point of the Accident since January 1, 2002? 18a. If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most recent year the examination was conducted: - Radiography Most recent year conducted: - Guided Wave Ultrasonic Most recent year conducted: - Handheld Ultrasonic Tool Most recent year conducted: - Wet Magnetic Particle Test Most recent year conducted: - Dry Magnetic Particle Test Most recent year conducted: - Other Most recent year conducted: Page 7 of 14 Reproduction of this form is permitted#

Page 22Describe: G2 - Natural Force Damage - only one sub-cause can be picked from shaded left-handed column Natural Force Damage – Sub-Cause: - If Earth Movement, NOT due to Heavy Rains/Floods: 1. Specify: - If Other, Describe: - If Heavy Rains/Floods: 2. Specify: - If Other, Describe: - If Lightning: 3. Specify: - If Temperature: 4. Specify: - If Other, Describe: - If High Winds: - If Other Natural Force Damage: 5. Describe: Complete the following if any Natural Force Damage sub-cause is selected. 6. Were the natural forces causing the Accident generated in conjunction with an extreme weather event? 6a. If Yes, specify: (select all that apply) - Hurricane - Tropical Storm - Tornado - Other - If Other, Describe: G3 - Excavation Damage - only one sub-cause can be picked from shaded left-hand column Excavation Damage – Sub-Cause: - If Excavation Damage by Operator (First Party): - If Excavation Damage by Operator's Contractor (Second Party): - If Excavation Damage by Third Party: - If Previous Damage due to Excavation Activity: Complete Questions 1-5 ONLY IF the "Item Involved in Accident" (from PART C, Question 3) is Pipe or Weld. 1. Has one or more internal inspection tool collected data at the point of the Accident? 1a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run: - Magnetic Flux Leakage Most recent year conducted: - Ultrasonic Most recent year conducted: - Geometry Most recent year conducted: - Caliper Most recent year conducted: - Crack Most recent year conducted: - Hard Spot Most recent year conducted: - Combination Tool Most recent year conducted: - Transverse Field/Triaxial Most recent year conducted: - Other Most recent year conducted: Describe: 2. Do you have reason to believe that the internal inspection was completed BEFORE the damage was sustained? 3. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Accident? - If Yes: Page 8 of 14 Reproduction of this form is permitted#

Page 23Most recent year tested: Test pressure (psig): 4. Has one or more Direct Assessment been conducted on the pipeline segment? - If Yes, and an investigative dig was conducted at the point of the Accident: Most recent year conducted: - If Yes, but the point of the Accident was not identified as a dig site: Most recent year conducted: 5. Has one or more non-destructive examination been conducted at the point of the Accident since January 1, 2002? 5a. If Yes, for each examination, conducted since January 1, 2002, select type of non-destructive examination and indicate most recent year the examination was conducted: - Radiography Most recent year conducted: - Guided Wave Ultrasonic Most recent year conducted: - Handheld Ultrasonic Tool Most recent year conducted: - Wet Magnetic Particle Test Most recent year conducted: - Dry Magnetic Particle Test Most recent year conducted: - Other Most recent year conducted: Describe: Complete the following if Excavation Damage by Third Party is selected as the sub-cause. 6. Did the operator get prior notification of the excavation activity? 6a. If Yes, Notification received from: (select all that apply) - One-Call System - Excavator - Contractor - Landowner Complete the following mandatory CGA-DIRT Program questions if any Excavation Damage sub-cause is selected. 7. Do you want PHMSA to upload the following information to CGADIRT (www.cga-dirt.com)? 8. Right-of-Way where event occurred: (select all that apply) - Public - If "Public", Specify: - Private - If "Private", Specify: - Pipeline Property/Easement - Power/Transmission Line - Railroad - Dedicated Public Utility Easement - Federal Land - Data not collected - Unknown/Other 9. Type of excavator: 10. Type of excavation equipment: 11. Type of work performed: 12. Was the One-Call Center notified? 12a. If Yes, specify ticket number: 12b. If this is a State where more than a single One-Call Center exists, list the name of the One-Call Center notified: 13. Type of Locator: 14. Were facility locate marks visible in the area of excavation? 15. Were facilities marked correctly? 16. Did the damage cause an interruption in service? 16a. If Yes, specify duration of the interruption (hours) 17. Description of the CGA-DIRT Root Cause (select only the one predominant first level CGA-DIRT Root Cause and then, where available as a choice, the one predominant second level CGA-DIRT Root Cause as well): Root Cause: - If One-Call Notification Practices Not Sufficient, specify: - If Locating Practices Not Sufficient, specify: - If Excavation Practices Not Sufficient, specify: - If Other/None of the Above, explain: G4 - Other Outside Force Damage - only one sub-cause can be selected from the shaded left-hand column Page 9 of 14 Reproduction of this form is permitted#

Page 24Other Outside Force Damage – Sub-Cause: - If Nearby Industrial, Man-made, or Other Fire/Explosion as Primary Cause of Incident: - If Damage by Car, Truck, or Other Motorized Vehicle/Equipment NOT Engaged in Excavation: 1. Vehicle/Equipment operated by: - If Damage by Boats, Barges, Drilling Rigs, or Other Maritime Equipment or Vessels Set Adrift or Which Have Otherwise Lost Their Mooring: 2. Select one or more of the following IF an extreme weather event was a factor: - Hurricane - Tropical Storm - Tornado - Heavy Rains/Flood - Other - If Other, Describe: - If Routine or Normal Fishing or Other Maritime Activity NOT Engaged in Excavation: - If Electrical Arcing from Other Equipment or Facility: - If Previous Mechanical Damage NOT Related to Excavation: Complete Questions 3-7 ONLY IF the "Item Involved in Accident" (from PART C, Question 3) is Pipe or Weld. 3. Has one or more internal inspection tool collected data at the point of the Accident? 3a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run: - Magnetic Flux Leakage Most recent year conducted: - Ultrasonic Most recent year conducted: - Geometry Most recent year conducted: - Caliper Most recent year conducted: - Crack Most recent year conducted: - Hard Spot Most recent year conducted: - Combination Tool Most recent year conducted: - Transverse Field/Triaxial Most recent year conducted: - Other Most recent year conducted: Describe: 4. Do you have reason to believe that the internal inspection was completed BEFORE the damage was sustained? 5. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Accident? - If Yes: Most recent year tested: Test pressure (psig): 6. Has one or more Direct Assessment been conducted on the pipeline segment? - If Yes, and an investigative dig was conducted at the point of the Accident: Most recent year conducted: - If Yes, but the point of the Accident was not identified as a dig site: Most recent year conducted: 7. Has one or more non-destructive examination been conducted at the point of the Accident since January 1, 2002? 7a. If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most recent year the examination was conducted: - Radiography Most recent year conducted: - Guided Wave Ultrasonic Most recent year conducted: - Handheld Ultrasonic Tool Most recent year conducted: - Wet Magnetic Particle Test Most recent year conducted: - Dry Magnetic Particle Test Most recent year conducted: Page 10 of 14 Reproduction of this form is permitted#

Page 25- Other Most recent year conducted: Describe: - If Intentional Damage: 8. Specify: - If Other, Describe: - If Other Outside Force Damage: 9. Describe: G5 - Material Failure of Pipe or Weld - only one sub-cause can be selected from the shaded left-hand column Use this section to report material failures ONLY IF the "Item Involved in Accident" (from PART C, Question 3) is "Pipe" or "Weld." Material Failure of Pipe or Weld – Sub-Cause: Construction-, Installation-, or Fabrication-related 1. The sub-cause selected below is based on the following: (select all that apply) - Field Examination Yes - Determined by Metallurgical Analysis - Other Analysis - If "Other Analysis", Describe: - Sub-cause is Tentative or Suspected; Still Under Investigation (Supplemental Report required) - If Construction, Installation, or Fabrication-related: 2. List contributing factors: (select all that apply) - Fatigue or Vibration-related Specify: - If Other, Describe: - Mechanical Stress: Yes - Other - If Other, Describe: - If Original Manufacturing-related (NOT girth weld or other welds formed in the field): 2. List contributing factors: (select all that apply) - Fatigue or Vibration-related: Specify: - If Other, Describe: - Mechanical Stress: - Other - If Other, Describe: - If Environmental Cracking-related: 3. Specify: - Other - Describe: Complete the following if any Material Failure of Pipe or Weld sub-cause is selected. 4. Additional factors: (select all that apply): - Dent - Gouge - Pipe Bend - Arc Burn - Crack Yes - Lack of Fusion - Lamination - Buckle - Wrinkle - Misalignment - Burnt Steel - Other: - If Other, Describe: 5. Has one or more internal inspection tool collected data at the point of the Accident? Yes 5a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run: - Magnetic Flux Leakage Yes Most recent year run: 2007 - Ultrasonic Most recent year run: - Geometry Most recent year run: - Caliper Most recent year run: - Crack Most recent year run: Page 11 of 14 Reproduction of this form is permitted#

Page 26- Hard Spot Most recent year run: - Combination Tool Most recent year run: - Transverse Field/Triaxial Most recent year run: - Other Most recent year run: Describe: 6. Has one or more hydrotest or other pressure test been conducted since original construction at the point of the Accident? Yes - If Yes: Most recent year tested: 1967 Test pressure (psig): 1,300.00 7. Has one or more Direct Assessment been conducted on the pipeline segment? No - If Yes, and an investigative dig was conducted at the point of the Accident Most recent year conducted: - If Yes, but the point of the Accident was not identified as a dig site Most recent year conducted: 8. Has one or more non-destructive examination(s) been conducted at the point of the Accident since January 1, 2002? No 8a. If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most recent year the examination was conducted: - Radiography Most recent year conducted: - Guided Wave Ultrasonic Most recent year conducted: - Handheld Ultrasonic Tool Most recent year conducted: - Wet Magnetic Particle Test Most recent year conducted: - Dry Magnetic Particle Test Most recent year conducted: - Other Most recent year conducted: Describe: G6 – Equipment Failure - only one sub-cause can be selected from the shaded left-hand column Equipment Failure – Sub-Cause: - If Malfunction of Control/Relief Equipment: 1. Specify: (select all that apply) - Control Valve - Instrumentation - SCADA - Communications - Block Valve - Check Valve - Relief Valve - Power Failure - Stopple/Control Fitting - ESD System Failure - Other - If Other – Describe: - If Pump or Pump-related Equipment: 2. Specify: - If Other – Describe: - If Threaded Connection/Coupling Failure: 3. Specify: - If Other – Describe: - If Non-threaded Connection Failure: 4. Specify: - If Other – Describe: - If Defective or Loose Tubing or Fitting: - If Failure of Equipment Body (except Pump), Tank Plate, or other Material: - If Other Equipment Failure: Page 12 of 14 Reproduction of this form is permitted#

Page 275. Describe: Complete the following if any Equipment Failure sub-cause is selected. 6. Additional factors that contributed to the equipment failure: (select all that apply) - Excessive vibration - Overpressurization - No support or loss of support - Manufacturing defect - Loss of electricity - Improper installation - Mismatched items (different manufacturer for tubing and tubing fittings) - Dissimilar metals - Breakdown of soft goods due to compatibility issues with transported commodity - Valve vault or valve can contributed to the release - Alarm/status failure - Misalignment - Thermal stress - Other - If Other, Describe: G7 - Incorrect Operation - only one sub-cause can be selected from the shaded left-hand column Incorrect Operation – Sub-Cause: Damage by Operator or Operator's Contractor NOT Related to Excavation and NOT due to Motorized Vehicle/Equipment Damage No Tank, Vessel, or Sump/Separator Allowed or Caused to Overfill or Overflow No 1. Specify: - If Other, Describe: Valve Left or Placed in Wrong Position, but NOT Resulting in a Tank, Vessel, or Sump/Separator Overflow or Facility Overpressure No Pipeline or Equipment Overpressured No Equipment Not Installed Properly No Wrong Equipment Specified or Installed No Other Incorrect Operation No 2. Describe: Complete the following if any Incorrect Operation sub-cause is selected. 3. Was this Accident related to (select all that apply): - Inadequate procedure - No procedure established - Failure to follow procedure - Other: - If Other, Describe: 4. What category type was the activity that caused the Accident? 5. Was the task(s) that led to the Accident identified as a covered task in your Operator Qualification Program? 5a. If Yes, were the individuals performing the task(s) qualified for the task(s)? G8 - Other Accident Cause - only one sub-cause can be selected from the shaded left-hand column Other Accident Cause – Sub-Cause: - If Miscellaneous: 1. Describe: Page 13 of 14 Reproduction of this form is permitted#

Page 28- If Unknown: 2. Specify: PART H - NARRATIVE DESCRIPTION OF THE ACCIDENT CPL¿s Houston Control Center (investigating a potential leak, due to system imbalace) had shut down the two 10¿ sections of the LPG System for a stand up test (blocked @MP 158 & MP 139). One of the 10¿ lines was blocked in @ 06:47 & the other @ 06:58. The control center received a phone call @ 07:52 reporting a vapor cloud in the vacinity of our pipelines. The control center then received another phone call a few minutes later reporting that the vapor cloud had ignited. Chevron personnel & local VFD¿s arrived & began spraying water around the perimeter to extinguish any grass fires. Both 10¿ lines have been excavated & examined for heat damage. All block valves at the MP 148.8 swab trap area were dismantled & inspected for any heat related damage and all seals replaced on 9-11-11. The pipe near the leak site was examined by metallurgists and determined to be undamaged on 9/11/11. The damaged pipe was replaced with new tested pipe and the 10¿ Loop Line was put back in service on 9/15/11. SEE ATTACHED LAB ANALYSIS_CONCLUSIONS File Full Name 20120327230001_Lab Analysis_Conclusions.pdf PART I - PREPARER AND AUTHORIZED SIGNATURE Preparer's Name J. R. Burke Preparer's Title DOT Specialist Preparer's Telephone Number 713-432-3206 Preparer's E-mail Address rburke@chevron.com Preparer's Facsimile Number 713-432-3477 Authorized Signature's Name J. R. Burke Authorized Signature Title DOT Specialist Authorized Signature Telephone Number 713-432-3206 Authorized Signature Email rburke@chevron.com Date 03/27/2012 Page 14 of 14 Reproduction of this form is permitted#

Page 29INTRODUCTION A section of 10-inch diameter pipe from the Coahoma LPG Pipeline in West Texas was received trom Chevron Pipe Line Company. The pipe sample contained an external sleeve. which was cracked at the upstream pipe-to-sleeve weld. The pape was been bolted to a concrete anchor block with a clamp that extended across the estemal sleeve. The cylindrical sleeve was attached to the outside of the pipe with fillet welds on the upstream and downstream ends of the sleeve. The upstream fillet weld between the pipe and sleeve exhibited a visible crack at the pipe-side weld toe that extended approximately one third of the circumference across the top of the pipe. The received section of pipe consisted of three short pup pieces connected by two butt welds: a short pup containing the cracked filler weld with the sleeve, clamp and anchor: and two short pup pieces, one upstream and one downstream of cracked pipe segment. The pipe, which has been in liquid petroleum gas service, was reportedly installed in 1967 and was manufactured from API 5L, Orade X52, Stress Engincering Services, Inc. was asked by to perform a metallurgical analysis on the cracked pipe-to-sleeve weld to determine the cause of the crack. CONCLUSIONS • The crack in the 10-inch diameter pipe occurred at the upstream fillet weld of the external sleeve was a result of a combination of bending loads and excessive hardness in the weld heat affected zone (HAZ): • The as-received pipe sample exhibited an upward bow with a measured deflection of approximately ½ inch over the ten foot span of the pipe sample; • The maximum deflection of the bow occured adjacent to the crack at the upstream pipe-to-sleeve fillet weld The crack at the upstream pipe-to-sleeve fillet weld occurred on the top half of the pipe extending from approsimately 9:00 across the top to 2:00 on the tensile side of the pipe bow: The ID suaface of the pipe was necked or reduced in thickness at the throngh-wall crack:#

Page 30Appendix D Metallurgical Report This document is on file at PHMSA#