DAVID PORTER, CHAIRMAN CHRISTI CRADDICK. COMMISSIONER RYAN COMMISSIONER KARI FRENCH DIRECTOR OVERSIGHT AND SAFETY DIVISION PIPELINE SAFETY November 2, 2015 455-2] Mr. Ryan Coffey, Executive Vice President of Oper ENERGY TRANSFER COMPANY 800 E. Sonterra Blvd., Suite 400 San Antonio, TX 78258-3941 Re: Pipeline Safety Evaluation Inspection Package Number: II 1385 I GAS GATHERING (All correspondence must include the Inspection Package Number) Dear Mr. Ryan Coffey: Recently, an incident, complaint, or other condition required our staff to conduct an investigation of pipeline facilities operated by your company. The facilities and the subject of the investigation are identified in the attached Safety Evaluation Summary. Investigations are conducted in accordance with pipeline safety requirements of the Texas Utilities Code, Section .201 for natural and other gas pipeline facilities and TEX. NAT. RES. CODE, Sections I 17.00! and I 17.01] (Vernon Supp. 2002) for hazardous liquid pipeline facilities. During the investigation, selected physical conditions, written procedures, and records were reviewed. At the time ofthis investigation, no alleged violations ofthe applicable safety regulations were found in the areas reviewed. If you have any questions or need assistance, do not hesitate to contact James Mergist or Stephanie Weidman in Austin Headquarters at 512-463- 7058. Sincerely, 2 Kari French Director Enclosure: Safety Evaluation Summary 1701 NORTH CONGRESS AVENUE POST OFFICE BOX 12967 AUSTIN, TEXAS 78711-2957 PHONE (512) 463-7058 FAX (512) 463-7319 TDD (800) 735-2989 OR TDY (512) 463-7284 AN EQUAL OPPORTUNITY EMPLOYER Railroad Commission of Texas 11/2/15 8:37 AM . . . Safety DIVISION Page 1 of 1 Safety Evaluation Summary Inspection Package: 111385 Activity/Classification: Specialized/Accident Operator: Unit: 6770 ENERGY TRANSFER COMPANY 29918 1 GAS GATHERING Mr- Ryan CO?ey Inspection Package Performed Executive Vice President of Operations 800 E. Sonterra Blvd. Suite 400 San Antonio, TX 78258-3941 Start Date: 06/15/2015 End Date: 07/10/2015 Alleged Violations Eval No System ID and Name 53/5th Type Repeat Uncorrected Corrected Total 20152073 963843 REM. 42" Gas Transmission 0 0 0 0 lnspector(s) Regional Office Phone Number Alejandro Alcala Corpus Christi (361) 242-3117 Jonathan Sauceda Corpus Christi (361) 242-3117 Steven Rios Corpus Christi (361) 242-3117 important Note: The pipeline system(s) listed above are identi?ed by a number and name and represent the physical pipe. valves and other components operated by your company. Additionally. there may be a pipeline system listed that is named System of Company [0 Number where number is the identi?cation number of your company. This system is used to represent your company and does not represent any physical pipeline system. For internal purposes it allows the Commission to more properly record inspection work performed at the company level. Where de?ciencies are found in programs. plans. procedures. and records at the company level and are not with a speci?c physical system. alleged violations will be cited against the Sysiem of Company Number. Pipeline Failure Investigation Report Pipeline System: Rich Eagleford Mainline 42? Operator: Energy Transfer Company Operator ID: 32099 Unit Number: Activity Number: Location: Latitude 29.] 1467, Longitude -97.37442 Date of Occurrence: June 14, 20l5 Material Released: Natural Gas Quantity: 134,17] MCF PHMSA Arrival Time Date: Total Damages S: $500k (Property) (Gas) $1.4 million Investigation Responsibility: State PHMSA NTSB Other Company Reported Apparent Cause: Company Reported Sub-Cause (from PHMSA arm 7000-1/ 71 00.2): Corrosion Natural Force Damage Excavation Damage Other Outside Force Damage Material Failure (Pipe, Joint, Weld) Pipeline experienced excessive bending load Equipment Failure Incorrect Operation Other Accidanb?'ncident Resalted in (check all that apply): Comments: Rupture Rupture along girth weld Leak x. Fire Gas. ignitedupon release Explosion Evacuation Number of Persons: [6 Area: Immediate surrounding area Narrative Summary Short summary of the Incident/Accident scenario Energy Transfer Company (ETC), Operator I 32099, experienced a gas release and rupture on its REM 42" Class I Gathering Line on June I4, 2015. The area is rural farm land near Cuero, in Dewitt County TX and approximately 52 miles upstream from ETC's Jackson Gas Plant, near Edna, TX. There were no injuries or fatalities resulting from this incident. The incident was telephonically reported to the Texas Railroad Commission at 21:30 on 6/14/2015 under incident ID 1 l84. The line was isolated and permanent repairs completed. The failed sections of pipeline were sent in for metallurgical analysis to determine root cause. The metallurgical lab investigation concluded that the pipeline rupture on the REM, 42" pipeline system was due to a bending overload that placed the bottom of the pipeline in tension, causing a fracture to initiate and propagate along the weld ??om the bottom to the top. Region/State: Dewitt County Cuero, TX Reviewed by: Steven Rios Principal Investigator: Alejandro Alcala Title: Region 7 Manager Date: 9/4/15 Date: 10/23/2015 Page 1 of 17 Form -11 Pipeline Failure investigation Report (Rev. 03/17/2011 through Amdt. 192-116 195-95). Pipeline Failure Investigation Report Failure Location Response Location (City, Township, Range, County/Parish): (Acquire Map) Cuero Dewitt County Address or MP. on Pipeline: Type ofArea (Rural, City): ?l Milepost 71 74 Rural Cuero Coordinates of failure location (Latitude): 29.] I467 (Longitude): -97.37442 Date: June I4, 2015 Time ofFailure: 8:30 pm Time Detected: 8:30 pm Time Located: 8:30 pm How Located: Public Noti?cation NRC Report NA Time Reported to NRC: NA Reported by: NA Type of Pipeline: Gas Distribution Gas Transmission Hazardous Liquid LNG LP Interstate Gas Interstate Liquid Municipal Intrastate Gas Intrastate Liquid Public Utility Gas Gathering Offshore Liquid Master?Meter?~? ??:?OffshoreGas Offshore Gas - High HIS Low Stress Liquid HVL Pipeline Con?guration (Regulator Station, Pump Station, Pipeline, etc.): 1.2 miles upstream NW of rupture is Cuero compression station which includes which is remote actuated. Pipeline crosses under HWY 953 and continues south for approximately 52 miles into Jackson Plant in Edna, TX. OperatorXOWIIerInformation Owner: Energy Transfer Company Operator: Energy Transfer Company Address: 300 Sonterra Suite 400 Address: 595? US Hwy 87 Cuero,TX 77954 San Antonio TX 78258 Company Of?cial: Ryan Coffey Company Of?cial: Chris Kresta Phone No.: 210-403-7300 Fax No.: 210-403-7500 Phone No. 7l3-989-7077 Fax No. 7l3~989~l l88 Drug. and Alcohol Testing Proaram Contacts Drug Program Contact Phone: Alcohol Program Contact Phone: 1 Photo documentation Page 2 of 17 Form -11 Pipeline Failure investigation Report (Rev. 03I17I2011 through Amdt. 192-116 195-95). Pipeline Failure Investigation Report Damages Product/Gas Loss or Spill? Amount Recovered Estimated Amount 134,171 MCF 900,000 Associated Damages?) 5 Estimated Preperty Damage 350,000 150,000 Description of Property Damage: An area of about .3 miles by .2 miles upstream (North) of rupture was ignited and burned. Power lines and fences adjacent to pipeline rupture were also damaged and in need of replacement and repairs. Customers out of Service: Yes Number: Suppliers out of Service: Yes Number: Fatalities and Injuries Fatalities: Yes A No Company: Contractor: Public: Injuries - Hospitalization: Yes No Company: Contractor: Public: Injuries - Non-Hospitalization: Yes A No Company: Contractor: Public: Total Injuries (including Non-Hospitalization): None Company: Contractor: Public: Name Job Function EXP- Type of Injury Drug?ellcohol Testing 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? __No Results Job Function Test Date Time Location Type of Drug Pos Neg system Description 2 Initial volume lost or spilled 3 Including cleanup cost Page 3 of 17 Form -11 Pipeline Failure Investigation Report (Rev. 03l17l2011 through Amdt. 192-115 195-95). Pipeline Failure Investigation Report System Description Describe the Operator's System: REM 42? consists of FBE (fusion bonded epoxy) carbon steel model API 5L Grade X70 PSL-2 pipe manufactured by Berg Spiral Pipe Corporation and installed in 2012. MAOP of this system is set at 1300 PSI and equipped with automatic pump shutdown for over pressure protection. Pipeline is approximately 52.8 miles in length and lies in Class 1 location and is a gathering line which transports rich unprocessed gas ??om Eagle Ford Shale in Tilden area into REM 30? which supplies gas into REM 42? in Cuero Compression Station and to Jackson Plant in Edna, TX. Cathodic protection is maintained using induced current by way of rectifiers. Pg); Length of Failure (inches, feet, miles): 132 inches circumferentially Position (Top, Bottom, include position on pipe, 6 O'clock): Description of Failure (Corrosion Gouge, Seam Split): Top of pipe at 12 O?clock and continues along girth weld. Rupture occurred along girth weld due to bending Laboratory Analysis: A Yes 7 No Perfumed by: Bryan Laboratory, Inc Preservation of Failed Section or Component: Yes If Yes - Method: Preserved by Bryan Laboratories Tn Custody of: Bryan Laboratories Develop a sketch of the area including distances from roads, houses, stress inducing factors, pipe con?gurations, direction of ?ow, etc. Bar Hole Test Survey Plot, if included, should be outlined with concentrations at test points. . Component Failure Descrimiou Component Failed: REM 42? Pipeline Manufacturer: Berg Spiral Pipe Corporation Mode]; Apl 5L Grade X70 Pressure Rating: 1300 PSI Size; 42" Other (Breakout Tank, Underground Storage): Pipe Data NAA Material: Carbon Steel Wall Thickness/SDR: .550 in Diameter (DD): 42? Installation Date: 2012 SMYS: 70,000 psi Manufacturer: Berg Spiral Pipe Corporation Longitudinal Seam: Spiral Welded DSAW Type of Coating: FBE Pipe Speci?cations 5L, ASTM A53, etc.): API 5L Joining Type: .l/K Bevel Weld Procedure: Requirements of AWS A5.5 NDT Method: Inspected: Yes __No Pressure Time of Failure Failure Site NAA Pressure Failure Site: 82] psi I Elevation Failure Site: Page 4 of 17 Form -11 Pipeline Failure Investigation Report (Rev. 03/17/2011 through Amdt. 192-116 195-95). Pipeline Failure Investigation Report Pressure Time of Failure Failure Site Pressure Readings Various Locations: Direction from Failure Site Location/M.P./Station Pressure (psig) Elevation msl) Upstream MP 7] 74 82l Upstream Pinup Station Data NAA Type of Product: Rich Unprocessed Gas API Gravity: Speci?c Gravity: Flow Rate: Pressure Time of Failure (4) Distance to Failure Site: High Pressure Set Point: Low Pressure Set Point: Station Data Flow Rate: Distance to Failure Site: 1.3 miles Speci?c Gravity: Pressure Time of Failure (4) 82] psi OperatingPressyre Max. Allowable Operating Pressure: I300 DBtel?mmation 0f MAopi 192-519 (2) Actual Operating Pressure: 800 psi Method of Over Pressure Protection: Auto pump shutoff Relief Valve Set Point: Capacity Adequate? Yes A Integrity Test A?er Failure i Pressure test conducted in place? (Conducted on Failed Components or Associated Piping): Yes No if No, tested a?er removal? Yes No Method: Describe any failures during the test. Soil/water Failure Site Condition of and Type of Soil around Failure Site (Color, Wet, Dry, Frost Depth): Dry Type of Back?ll (Size and Description): dry natural soil 4 Obtain event logs and pressure recording charts Page 5 of 17 Form -11 Pipeline Failure investigation Report (Rev. 0311712011 through Amdl. 192-116 195-95). Pipeline Failure Investigation Report Soil/water Conditions-@Failure Site Type of Water (Salt, Brackish): NA Water Analysis yes No External Pipe or Component Examination External Corrosion? Yes No Good Coating Condition (Disbonded, Non-existent): (I) Description of Corrosion: Description of Failure Surface (Gouges, Arc Burns, Wrinkle Bends, Cracks, Stress Cracks, Chevrons, Fracture Mode, Point of Origin): Burns due to ignition. Fracture extended from toe of the weld on the outside surface to toe of the weld in the inside surface. Most of the fracture appears to be shear. Fracture surfaces were oxidized and covered with tenacious scale from the heat of the ?re Above Ground: Yes A No Buried: Yes No Stress Inducing Factors: Depth of Cover: 0? Cathodic Protection (Surface): Cathodically Protected PIS (Interface): Soil Resistivity: pH: Date of Installation: 5/24/2013 Method of Protection: Impressed Current Recti?ers Did the Operator have knowledge of Corrosion before the Incident? Yes No (No corrosion found) How Discovered? (Close Interval Survey, Pig, Annual Survey, Recti?er Readings, ECDA, etc): Internal Pipe or ComponentExamination (U Yes No ?an? Internal Corrosion: Injected Inhibitors: Yes Type of Inhibitors: Testing: it Yes __No loss. Results are lower than 2mm allowance by ETC. Results (Coupon Test, Corrosion Resistance Probe): 4 tests conducted from 5/ I 3 to 3/ 5 ranged between .Olmm to .03mm wall Description of Failure Surface (MIC, Fitting, Wall Thinning, Chevrons, Fracture Mode, Point of Origin): Fractured with crack propagation due to bending overload. Cleaning Pig Program: Yes No Gas and/or Liquid Analysis: Yes _No 5 Attach copy of water analysis report Page 6 of 17 Form -11 Pipeline Failure Investigation Report (Rev. 03I17l2011 through Amdt. 192-116 195-95). Pipeline Failure Investigation Report Internal Pipe or Component Examination Results of Gas and/or Liquid Analysis Non-Corrosive Internal Inspection Survey: Yes Results Did the Operator have knowledge of Corrosion before the Incident? Yes No (Corrosion not found) How Discovered? (Instrumented Pig, Coupon Testing, ICDA, etc.): Outside orce Damage 1: Responsible Party: Telephone No.: Address: Work Being Performed: Equipment Involved: Called One Call System? Yes No One Call Name: One Call Report Notice Date: Time: Response Date: Time: ?Detai15?of'Response: Was Location Marked According to Procedures? Yes No Pipeline Marking Type: Location: 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 de?ciency in the Public Awareness Program contribute to the accident? _Yes No ls OSHA Noti?cation Required? Yes No Nature! Forces _gL Description (Earthquake, Tornado, Flooding, Erosion): 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 Page 7 of 17 Form -11 Pipeline Failure investigation Report (Rev 03/17/2011 through Amdt. 192-115 195-95). Pipeline Failure Investigation Report Natural Fames Failurelsolation Squeeze Off/Stopple Location and Method: Loss of pressure detected upstream of failure at pump station, which triggered automatic pump shut down. Valve Closed - Upstream: MLV remote control Time: 8:35pm M.P.: Valve Closed - Jackson Plant Inlet Valve manual Time: 9:35pm M.P.: Pipeline Shutdown Method: Manual Automatic SCADA Controller ESD Failed Section Bypassed or Isolated: Isolated Performed By: ETC personnel Valve Spacing: adequate Odorization I NM Gas Odorized: Yes No Concentration of Odorant (Post Incident at Failure Site): Method of Determination: Yes No LEL: Yes No I 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: Type of Odorant: Model: Amount Injected: Monitoring Interval (Weekly): Odorization History (Leaks Complaints, Low Odorant Levels, Monitoring Locations, Distances from Failure Site): Weather Conditions Temperature: Between 85 and IOOF Wind (Direction Speed): Climate (Snow, Rain): Clear Humidity: Was Incident preceded by a rapid weather change? Yes No Weather Conditions Prior to Incident (Cloud Cover, Ceiling Heights, Snow, Rain, Fog): Page 8 of 17 Form -11 Pipeline Failure Investigation Report (Rev. 03/17/2011 through Amdt. 192-116 195-95). Pipeline Failure Investigation Report Gas Migration Survey Bar Hole Test of Area: Yes No Equipment Used: Method of Survey (Foundations, Curbs, Manholes, Driveways, Mains, Services) l? Environment Sensitivin Inmact Location (Nearest Rivers, Body of Water, Marshlands, Wildlife Refuge, City Water Supplies that could be or were affected by the medium loss): (I) OPA Contingency Plan Available? Yes _No Followed? Yes _No Class Location/High Consequence Area Class Location: 3 4_ HCA Area? Yes No NIA Determination: Determination: Odorization Required? Yes No Pressure Test History ?rpandbisr?asNeces-swy) - ?Reqid?b?ssessment ?Pressure- ?Duration? - Deadline Date Test Date Test Medium (psig) (ms) ,0 SMYS installation 3' Next Next Most Recent Describe any problems experienced during the pressure tests. Internal- Line Inspection/OtherAssessment History Expand List as Necessaggl Req?d Assessment Assessment Type of ILI Other Assessment Indicated Anomaly Deadline Date Date Tool Method If yes, describe below Initial Yes No Next Yes No Next Yes No Most Recent Yes No 9 Plot on site description page 10 As required of Pipeline Integrity Management regulations in 49CFR Parts 192 and 195 ll MFL, TFI, UT, Combination, Geometry, etc. l2 ECDA, ICDA, SCCDA, ?other technology,? etc. Page 9 of 17 Form -11 Pipeline Failure Investigation Report (Rev. 03/17/2011 through Amdt. 192-116 8. 195-95). Pipeline Failure Investigation Report Internal Line I aspection/Other Assessment History NIA @gpand List as Necessary) Describe any previously indicated anomalies at the failed pipe, and any subsequent pipe inspections (anomaly digs) and remedial actions. Pre-Failure Conditions and Actions Was there a known pre-failure condition requiring 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 evaluation and remediation schedule? Describe below or on attachment. Yes No Prior to the failure, had the operator performed the required actions to address the threats that are now known to be related to the cause of this failure? Yes No List below or on an attachment such operator-identi?ed 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. Maps &?ecords and'Rms?Curr'ent'riizi A Yes No Comments: Leo]: Survey History Leak Survey History (Trend Analysis, Leak Plots): Aerial patrol was conducted and no abnormal operating conditions were found Pipeline Operation Histon Description (Repair or Leak Reports, Exposed Pipe Reports): Pipeline is a relatively new line installed in 2012 with no history of leaks or abnormal operating conditions prior to incident Did a Safety Related Condition Exist Prior to Failure? Yes x_ No Reported? Yes Unaccounted For Gas: Over Short/Line Balance (24 hr., Weekly, [3 Obtain copies of maps and records Page 10 of 17 Form -11 Pipeline Failure Investigation Report (Rev. 03/17/2011 through Amdt. 192-116 195-95). Pipeline Failure Investigation Report Operator/Contractor Error AM 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? No Was quali?ed individual suspended from performing covered task Yes No 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 lnspection conducted on this portion of the job? Yes No 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: Years Hours on Duty Shi? Name Title . . . Experience Prior to Failure Alarm Parameters: High/Low Pressure Shutdown: Flow Rate: Procedures for Clearing Alarms: Type of Alarm: Company Response Procedures for Abnormal Operations: Page 11 of 17 Form -11 Pipeline Failure Investigation Report (Rev. 03/17/2011 through Amdt. 192-116 195-95). Pipeline Failure Investigation Report Operator/Contractor Error Over/Short Line Balance Procedures: Frequency of Over/Short Line Balance: Additional Actions: Page 12 of 17 Form -11 Pipeline Failure investigation Report (Rev. 03i17l2011 through Amdt. 192-116 8: 195-95). Pipeline Failure Investigation Report Additional Actions Taken by the Operator N114 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 Pumps): Photo Documentation Overall Area ??om best possible view. Pictures from the four points of the compass. Failed Component, Operator Action, Damages in Area, Address Markings, etc. Photo No. Descr' I Refer to PhotoiDescription attachment in PBS l5 Camera Type: Page 13 of 17 Form -11 Pipeline Failure Investigation Report (Rev. 03/17/2011 through Amdt. 192-116 8. 195-95). Pipeline Failure Investigation Report A dditional Information Sources Agency Name Title Phone Number Police: None available at time of arrival Fire Dept.: State Fire Marshal]: State Agency: NTSB: EPA: USCG: FBI: ATF: OSHA: Insurance Co.: FRA: MM S: Television: Other: Persons Interviewed Title Phone Number Chad lngalls Director of Operations 210-854-0428 Danny Nichols Director of Regulatory Compliance 7l3-823-3 795 Chris Kresta Regulatory Specialist 979?53 -9036 Page 14 of 17 Form -11 Pipeline Failure investigation Report (Rev. O3i17l2011 through Amdt. 192-116 195-95). Pipeline Failure Investigation Report Eveanog 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 Date Event 8:00 pm scada telemetry indicated drop in pressure 8:15 pm Jackson Plant in Edna. TX observed loss in suction pressure 8:30 pm Possible line blowout reported by Jerry Frausto 8:35 pm Remote closure of REM MLV #1 upstream of cuero 8:57 pm Jackson Plant advised they have the inlet valve shut on REM 42? to plant 9:23 pm Shane Steffek isolated MLV #2 on REM 42? 9:24 pm Ricky Bonewald reports that ?re is on REM 42? near FM 953 9:32 pm Corey Tolbert with Cuero Fire Department reports rupture occurred in field and evacuated residents and blocked off HWY 953. No injuries reported. 9:55 pm Kenny Morgan has personnel open up upstream vent at Cuero to begin blowdown process of gas away ?om the failure 10:00 pm Agency notifications were made to 0&0) 10: 13 pm Lee Putnam assigned to assist evacuated residents with temporary hotels. - 10:44 pm ?ame beginning to decrease 1:12 pm Fire is approximately 5? in height 1:34pm TRRC called and asked Bart Husky if ?re was still burning 1:54pm Chris Lason has assessed the incident and determined that parallel pipeline name Gateway 16? liquids line should be ?ne to continue normal operation 12:08 am TRRC inspector on scene Page 15 of 17 Form -11 Pipeline Failure lnvestigation Report (Rev. 0311712011 through Amdt. 192-115 195-95). Pipeline Failure Investigation Report Investigation Contact Log Name Description Refer to ?Persons Interviewed? section Failure Investigation Documentation Log I Appendix Date FOIA Documentation Description Number Received Yes No Refer to attachments section in PBS Page 16 of 17 Form -11 Pipeline Failure investigation Report (Rev. 03l17/2011 through Amdl. 192-116 195-95). Pipeline Failure Investigation Report Site Description Provide a sketch of the area including distances from roads, houses, stress inducing factors, pipe con?gurations, 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. Refer to pictures/description in attachment section in PES and failure location section for more details. Page 17 of 17 Form -11 Pipeline Failure investigation Report (Rev. 03/17/2011 through Amdt. 192-116 8: 195-95). Failure Investigation Report Template Railroad Commission of Texas Region: Corpus Christi Region 7 Principal Investigator: Alejandro Alcala Senior Accident Investigator: Steven Rios Region Director: Steven Rios Date of Report: September 11, 2015 Subject: Failure Investigation Report - Energy Transfer Company?s pipeline system identi?ed as REM, 42" Operator, Location, Conseguences Date of Failure: June 14,2015 Commodity Released: Natural Gas City/County: Cuero DeWitt Operator Operator Name: 32099 Energy Transfer Company RRC Unit ID RRC Unit Name: 29918 1 GATHERING Milepost Location: M.P 71+74 1.3 miles south east of Cuero Compression Station Type of Failure: Fracture occurred along girth weld due to bending overload Fatalities: None Injuries: None Description of area impacted: The pipeline rupture occurred in a rural farmland area in Cuero, Texas approximately 30? south of HWY 953. Blast radius extended north of HWY 953 and covered an area of approximately 0.3 miles by 0.2 miles. Collateral damage included power lines and private fence lines. Total Costs: Energy Transfer Company reported $150,000 in public and non-operator private property damages and $350,000 in operator property damages and repairs, which totaled $500,000 in property damage. In addition, $900,000 of gas was released unintentionally. Executive Summagy An explosion was reported by the public at approximately 8:30 pm on June 14,2015 in Cuero, TX along HWY 953 involving Energy Transfer Company's natural gas gathering pipeline system identi?ed as the REM, 42" (RRC System 963843). The REM, 42" pipeline system is located in a Class 1 location, within rural farmland in Dewitt County, approximately 52 miles upstream from Energy Transfer Company's Jackson Gas Plant near Edna, TX. There were no injuries or fatalities resulting from this incident. The incident was telephonically reported to the Texas Railroad Commission at 9:50 pm on June 14, 2015 and Pipeline Inspector Alejandro Alcala was notified by 10:23 pm. The REM, 42" pipeline system ruptured, and ignited, 30 feet south of HWY 953. Three homes, comprising of a total of 16 people, were evacuated from the surrounding area by Energy Transfer Company personnel and local ?re department. The REM, 42" pipeline system was shut in by remote closure of Maine Line Valve #1 at 8:35 pm, at the time the system had less than 100 psig of mainline pressure. At 9:23 pm, manual isolation was achieved at the inlet valve into the Jackson Plant. Energy Transfer Company commenced blow down activities at 9:55 pm. Energy Transfer Company reported to the Texas Railroad Commission that metallurgical analysis indicated the rupture of the REM, 42" pipeline system was the result of a bending load exerted on the pipeline. The total property damage 1 Failure Investigation Report Template cost (including cost of operator's property damage 8: repairs and cost of non-operators private property damage) is estimated at $500,000. The estimated volume of natural gas release was 134,171 MCF, which totaled an estimated loss of $900,000. This incident was assigned Incident ID: 1184 by The Texas Railroad Commission. System Details The REM, 42" pipeline system is constructed of42" OD spiral welded DSAW, API 5L pipe with a wall thickness of 0.550 inches and a standard minimum yield strength of 70,000 psig with fusion bonded epoxy (FBE) external coating. The system identi?ed as the REM, 30" supplies rich unprocessed gas from the Eagle Ford Shale to the REM 42" which begins at the Cuero Compression Station. The REM, 42" system continues from the Cuero Compression Station to the Jackson Gas Plant in Edna, Texas for approximately 52.8 miles. The portion of the system involved in the incident was below ground and crossed HWY 953 approximately 1.3 miles south of the Cuero Compression Station. The pipeline was constructed and installed in 2012 with Cathodic Protection maintained on it via induced current through rectifiers as of May 24, 2013. The maximum allowable operating pressure of the REM, 42" is established at 1300 psi and is protected via automatic pump shutdown upstream at the Cuero Compression Station. Events Leading up to the Failure On June 14, 2015 at 8:00pm, SCADA telemetry data scan indicated a drop in pressure. At 8:15pm Energy Transfer Company was advised of the fire and the incident involving the pipeline system identi?ed as REM, 42?. Emergency Response Upon con?rmation of the REM, 42" rupture, Energy Transfer Company began shut down operations while simultaneously informing the Cuero fire department. The REM, 42" Main Line Valve upstream of Cuero, was shut in via remote closure at 8:35 pm. REM, 42" Main Line Valve #2 was manually isolated at 9:23 pm. The Cuero Fire Department was responsible for initiating the evacuation of the residents along the pipeline while blocking HWY 953. Three homes, comprising ofa total of 16 people, were evacuated. No injuries were reported. Summary of Retu rn-to-Service On June 17, 2015, Energy Transfer Company personnel completed the welding of the pipe replacement for the REM, 42" at 4:00 pm. The system was then purged from the Jackson Gas Plant to the Cuero Compressor Station with low pressure natural gas. Purging activities were completed by 6:10 pm. Between the hours of 6:10 pm to 12:00 am, the pipeline was fully packed with natural gas and then the pipeline's main line valves were opened: the pipeline system was completely returned to service once equalized. Coating and sandblasting was resumed at the time of startup until they were completed. Investigation Details On Monday, June 14, 2015 at approximately 10:00 pm, Energy Transfer Company reported to the Texas Railroad Commission that a natural gas release occurred on their system identi?ed as REM, 42". The incident occurred in a rural farmland area in Cuero, Texas approximately 30 feet south of Highway 953 from where it crosses. Alejandro Alcala Texas Railroad Commission Pipeline Safety Inspector, was noti?ed of the incident at 10:23 pm. Alejandro Alcala and Jonathan Sauceda (Inspector in training observing) arrived at the incident site on June 15, 2015 at approximately 8:00 am. Mr. Alcala met with Energy Transfer Company's Operations Director and Regulatory Specialist, Chad Ingalls and Chris Kresta respectively, who verified that the pipeline involved was the REM, 42" system. Chris Kresta con?rmed that REM 42" was a class 1 gathering system however, pursuant to H8 2982, a field investigation was conducted. Mr. Ingalls stated that the system is a rich gas gathering system which transports 2 Failure Investigation Report Template unprocessed natural gas to the Jackson Gas Processing Plant in Jackson County.Mr. Ingalls also stated that according to SCADA telemetry, the system was operating at approximately 800 psig when the pipeline failed at 8:00 pm on June 14, 2015. The system was shut in by remote closure of the Main Line Valve #1 at 8:35 pm. At 9:23 pm the Main Line Valve #2 was manually closed. Blow down activities commenced at 9:55 pm. Mr. Alcala observed visually that property was damaged within a perimeter that measured approximately 0.3 miles by 0.2 miles. Fence lines were damaged, power lines were down, and there was evidence of grass ignition on private property. Upon Mr. Alcala's departure, as of 1:00 pm on June 15, 2015, residual gas and condensate continued burning from the pipeline and excavation activities were still being carried out in order to prepare for the necessary repairs of the leaking section of pipe. Mr. Alcala and Mr. Sauceda returned to the incident site on June 15, 2015 at 9:50 pm and met with Chris Kresta, Energy Transfer Company's Regulatory Specialist, and Mr. Ingalls. Mr. Kresta stated that the ruptured portion of pipe was cut out and removed by a third party contractor (Pump Co.) at approximately 8:29 pm and had a duration period of 45 minutes before being loaded on a truck to be sent for sampling at Bryan Laboratories in Houston, Texas. The sample portion measured approximately 10 feet in length and had been cut into 2 equal pieces along the girth weld. At 10:45 pm, Mr. Alcala veri?ed the pipeline speci?cations of the replacement pipe that was later installed after all measurements, ?tting, and excavation activities in the trench were complete. Mr. Alcala and Mr. Sauceda left the incident site at 11:45 pm on the evening ofJune 15, 2015. Mr. Alcala and Mr. Sauceda returned to the incident site once again at 10:45 am on Tuesday, June 16, 2015 and met with Mr. Kresta and Mr. Ingalls for an update on the repairs that were still in progress. At that time, excavation and welding activities were in place and installation of new pipe segment was scheduled for 10:00 pm on June 16, 2015. Mr. Alcala was noti?ed that purging and packing activities would be carried out while the replaced pipeline segment was being wrapped and coated. otos were ta en 0 pipeline samples sent for analysis along with all surrounding areas of incident. Findings and Contributing Factors A segment of pipe was removed, preserved, and sent to Bryan Laboratories for metallurgical analysis. The metallurgical lab investigation concluded that the rupture was due to a bending overload which placed the bottom of the pipeline in tension, causing a fracture to initiate and propagate along the weld from the bottom to the top. On July 9, 2015, Railroad Commission Inspectors, Alejandro Alcala, Jonathan Sauceda (Inspector in training/ observing), and Steven Rios, traveled to Energy Transfer Company's headquarters to conduct a construction investigation which included an investigation of the repairs that were made. All construction procedures were reviewed and found to be in accordance with PHMSA standards and Energy Transfer Company's Operations Maintenance 8: Operator Qualification procedures. Welding procedures were also reviewed to ensure that they were in accordance with Section 5 of API 1104 or Section IX of ASME. Mill Test Reports (MTR) was veri?ed for sections upstream and of the investigated pipeline rupture. SCADA operational history for the REM, 42" was reviewed. Based on SCADA information for the portion of the system which is located of the Jackson Plant, 30 days prior to June 14, 2015, operating pressures indicated a fluctuation between 700 psi and 850 psi. In addition, on April 29, 2015 at 6:00 pm, there was a spike in pressure of about 1030 psi. The REM, 42" pipeline system has an established maximum allowable operating pressure (MAOP) of 1300 psi. Rectifier records were also reviewed for the rectifier at Mile Post 26 from the time they were installed (on May 24, 2013) through the 2015 calendar year and no irregularities were found. Cathodic protection records were 3 Failure Investigation Report Template reviewed, including the annual survey data at the test point locations immediately upstream and of the pipeline segment involved in the June 14, 2015 release. The inspection data indicated that pipe-to-soil potentials exceeded an -850 mV (on) criteria, on the date of the surveys. Internal corrosion coupon monitoring records were reviewed from May of 2013 to March of 2015. Within this time, four internal corrosion coupons were obtained with results that ranged from 0.01 mm to 0.03 mm of metal loss. The metal loss does not exceed the 2 allowed by Energy Transfer Company. An aerial patrol record carried out for a system GATEWAY, 16", which runs parallel with the REM, 42", was reviewed and there was no indication of a leak in the area. Operator quali?cation records were reviewed for corrosion control technicians, control room personnel that were on duty at the time of the incident, and for pilots that conducted aerial patrols for Energy Transfer Company. No issues were identi?ed. The metallurgical lab investigation concluded that the pipeline rupture on the REM, 42" pipeline system was due to a bending overload that placed the bottom of the pipeline in tension, causing a fracture to initiate and propagate along the weld from the bottom to the top. Appendices A Investigation Template PHMSA Form 11 Pipeline Failure Investigation OpErator Accident/Incident Report to PHMSA (30 day Report) Ehoto Summaryjheet COMPANY NANIE: Energy Transfer Company EVAL 20152073 INSPECTOR: Alejandro Alcala DATE: 6-15-2015 DATE: 6-15-2015 PHOTOGRAPHER: Alejandro Alcala LOCATION: 1.3 miles of Cuero compression station on Hwy 953 DESCRIPTION: View of residual gas burning during excavation activities at pipeline REM 42". DATE: 6-15-2015 PHOTOGRAPHER: Alejandro Alcala LOCATION: 1.3 miles of Cuero compression station on Hwy 953 DESCRIPTION: Adjacent view of residual gas burning from ruptured pipeline REM 42". DATE: 6-15-2015 PHOTOGRAPHER: Alejandro Alcala LOCATION: 1.3 miles of Cuero compression station on Hwy 953 DESCRIPTION: View of residual gas burning from ruptured pipeline REM 42? with a visual of surrounding excavation pro?le. COMPANY NAME: Energy Transfer Company EVAL 20152073 INSPECTOR: Alejandro Alcala DATE: 6-15-2015 DATE: 6-15-2015 PHOTOGRAPHER: Alejandro Alcala LOCATION: 1.3 miles of Cuero compression station on Hwy 953 DESCRIPTION: View from Hwy 953 facing south direction of ?ow towards Jackson Plant. DATE: 6-16-2015 Alejandro Alcala LOCATION: 13 miles of Cuero compression station on Hwy 953 DESCRIPTION: View from Hwy 953 facing south direction of ?ow. Same ground segment as picture above but remaining pipeline was replaced to include 0 45 degree portion (green segment) which reduces bending/loading visible in upper picture. DATE: 6-16-2015 PHOTOGRAPHER: Alejandro Alcala LOCATION: 1.3 miles of Cuero compression station on Hwy 953 DESCRIPTION: View of 0-45 degree angle added to REM 42?. COMPANY NAME: Energy Transfer Company EVAL 20152073 INSPECTOR: Alejandro Alcala DATE: 6-15-15 DATE: 6-15-2015 PHOTOGRAPHER: Alejandro Alcala LOCATION: 1.3 miles of Cuero compression station on Hwy 953 DESCRIPTION: View of failed pipeline segment cut into 2 along the girth weld. Samples loaded and sent to Bryan Laboratories. Left segment of rupture) Right segment (Upstream of rupture closest to FM 953)) DATE: 6-15-2015 PHOTOGRAPHER: Alejandro Alcala LOCATION: 1.3 miles of Cuero compression station on Hwy 953 DESCRIPTION: View of rupture pro?le along girth weld, left segment of rupture) DATE: 6-15-2015 PHOTOGRAPHER: Alejandro Alcala LOCATION: 1.3 miles of Cuero compression station on Hwy 953 DESCRIPTION: View of rupture pro?le along girth weld, right segment (upstream of rupture) COMPANY NAME: Energy Transfer Company EVAL 20152073 INSPECTOR: Alejandro Alcala DATE: 6-15-15 DATE: 6-15-2015 PHOTOGRAPHER: Alejandro Alcala LOCATION: 1.3 miles of Cuero compression station on Hwy 953 DESCRIPTION: View of damaged power lines running perpendicular to pipeline REM 42?. DATE: 6-15-2015 LOCATION: 1.3 miles of Cuero compression station on Hwy 953 DESCRIPTION: View of surrounding homes North East of pipeline REM 42?. DATE: 6-15-2015 PHOTOGRAPHER: Alejandro Alcala LOCATION: 1.3 miles of Cuero compression station on Hwy 953 DESCRIPTION: View of damaged property upstream of pipeline rupture. NOTICE. This report is required by 49 CFR Part 191. Failure to report can result In a civil penalty not to exceed Form Approved 5100.000 for each violation for each day that such violation persists except that the maxlmum civil penalty shall not OMB No: 2137-0522 exceed 51.000900 as melded In 49 USC 6012?. Expires: 105112016 (3 s. Deparbnent ofTraneportelion INCIDENT REPORT - Report Date PIpeIineandI-Iezardous Materials NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS (007% only, 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 fallme to comply with a collection of Information subject to the requirements of the Papemork Reduction Act unless that de?ection of Information displays a current valid OMB Control Number. The OMB Control Nunber for this Information de?ection Is 213741522. Public reporting for this collection of Information is estimated to be approximately 10 hours per response. including the time tor reviewing instructions. gathering the data needed. and completing and reviewing the collection of lnfonnatlon. All responses to this collection of information are mandatory. Send comments regarding this burden esb'mate or any other aspect of this collection of Information. including suggestions for reducing this borden to: Information Collection Clearance Of?cer. PHMSA. Of?ce of Pipeline Safety (PHP-SD) 1200 New Jersey Avenue. SE. Washington. 0.0. 20580. msrnucnons Important: Please read the separate instructions for completing this form before you begin. They clarify the information requested and provide speci?c examples. It you do not have a copy of the instructions, you can obtain one from the PHMSA Pipeline Safety Community Web Page at ling/flmeEmiggliggr PART A- KEY REPORT INFORMATION Report Type: (select all that apply) Original CI Supplemental Final Last Revision Date 1. Operator's OPS-Issued Operator Identi?cation Number Name of Operator: Enemy Ign?tg 3. Address of Operator. 3.3 400 (Street Address) 31! mil (Girl 3.c State: ITIXI I I I I 4 Leeal time (244w clock) and date of the Incident: 8. National Response Center Report Number. . 2" 13%} deported to TRRC at 21.30 on 06l14 n15 Incident ID: 1184 5' Loumo? . em: 7 Lo (2441006? a EIBO teep ncreporitote Lamuue 2 National Response Center (If applicableIncident resulted from: Unintentional release of gas CI Intentional release cl gas CI Reasons other than release of gas 9. Gas released: (select only one. based on predominant volume released) Natural Gas CI Propane Gas CI Gas CI Hydrogen Gas LandlillGas CI Other Gas ED Name: 10. Estimated voitxno of gas released unintentionallyI'll 1 [Thousand Cubic FegleCF) 11. Estimated volune of Intentional and controlled releasetbtondown: I I I I I Thousand gigs 12. Estimated volume of accompanying llquld released: I II I I rr Form 7100.2 (rev 10-2014) Page 1 of 19 13. Were there 0 Yes No 14. Were there lngwies requiring Inpatient hospitalization? 0 Yes No If Yes. specify the number In each category: If Yes. specify the number in each category: 13.3 Operator employees I I I I 14.3 Operator employees I I I I I 13.b Contractor employees 14.b Contractor employees tor the Operator I I I I I workan for the Operator I I i I I 13.c Non-Operator 14.c Non-Operator emergency responders I I I I I emergency responders I I I I I 13.d Workers worlan on the 14.d Workers workan on the righl-oi?way. but NOT right-oI-way. but NOT associated this Opera-lat I I I I I associated with this Operator I I I I I 13.3 General public I I I I I 14.9 General public I I I I I 13.1 Total fatalities (sum of above) I I I I I 14.! Total Injuries (sum of above) I I I I I 15. Was the plpettnelfactlity shut dovm due to the Incident? {Ewes No as Explaln: I Irs If Yes. complete Quesllons 15.a and 1511: (use local time, 2443? clock) 15.3 Local time and date otshutdown I I I I L151 I1 MI I Momh Day Year 15.b I1I1I2IOI IOIBI I1I7I I1I5I How Month Day Year ('SuppIementaI Report requIred) 16. Old the gas Ignite? Yes 0 No 17. Old the gas explode? 0 Yes [it No 18. Numberot general publlc evacuated: I I I I1 lg! 19. Time sequence: (useIocaI time. 244mmcIocIr) 19.a IDISI I1I4I I1I5I Hour Month Day Year tlme operator resourceserriyed on site Hour Month Day Year Form PHMSA 7100.2 (rev 10-2014) Page 2 oI19 PARTS - ADDITIONAL LOCATION INFORMATION I 1. Was the origin at the Incident onshore? I21 Yes (Complete Questions 242) No (Complete Questions 13-15) II Onshore: II O?shore: 2. State: 13. Approximate waterdepth (FL) at the polnt ol the Incident 3. ZIpCodezl'll7l915I4IGuam 5 Damn." 14. Origin oltncident: Clty CountyorParIsh In Stale waters 5 . Stat I I I 6. Operawrdesignated location: (select onlyone) '3 penny a err WeposWaIveSlation {specifth shaded area below) Area: EISurvey SIatlonNO. (specifyin shadedarea below) Blockfl'ractr?NearestCoumylPa?sh: On the Outer Continental Shelf (OCS) 7. name: Rig ?gglgigrg 43 ED specify: 8. Segment namryID: ??cllm Irgm beginning MLV #1 9. Was Incident on Federal land, other than the Outer Continentat Ana: snarrocsp 0 Yes El No 10. Location of Incident: (select only one) Block II: 15. Area at Incident: (select onlyone) Pmpe'ty CI ShorellneIBank or shore approach Plpeilne right-of-way Cl Below water. plpe buried or jetted below seabed 11. Area of Incident (as found): (select only one) 3:31;: or above 533mm CI Bela round 5 re or abov round store vessel. lndu?ggm anach?gd gemudenages 9 Earshot riser outslde OI Splash Zone. Includan rlser bend IZI Underground I: Specify: Under sell 0 Under a bulldan 0 Under pavement 0 Exposed due to excavatlon In underground enclosed space vault) 0 Other Depth-oI-Cover Cl Abovegruund up Specify: 0 Typical aboveground lacll'rty piplng or appurtenance 0 Overhead Crossing In or an open tnsIde a 0 Inside other enclosed space 0 Other CI Transltion Area :3 Specify: Interface 0 Watt sleeve 0 Plpe support or other close contact area 0 Other 12. Did Incident occurln a 0 Yes El NO ll Yes. specify type below. CI Bridge crossing . Specify: 00353:! Uncased El Railroad crossing . (select all that apply) 0 Cased Uncased Boredldritted El Road . (sated allthal app?) 0 Cased Uncased 0 Boredldritled I: Specify: Cased Unoased Name of body of water. It commonly known: Apme water depth (ft) at the polnt ol the Incident: I II I I I (select only one o! the following) Shorelinelaank crossing Below water. pipe In Below water. plpe buried below bottom (NOT In boredldriled Crossing) Below water. pipe on or above bottom 0 :on'n PHMSA 7100.2 (rev 10-2014) Page 3 ol 19 PART - momoueL FACILITY INFORMATION 1. Is the pipeline or facility: Cl Interstate Intrastate 2. Part of system Involved In Incident (seIecl only one) Belouground Storage. Including Associated Equipment and Piping Cl Aboveground Storage. including Associated Equipment and Piping Onshore Compressor Station Equipment and Piping Onshore Regulatorllillelering Station Equipment and Piping l3] Onshore Pipeline, Including Valve Sites Cl Offshore Platform. Including Platform-mounted Equipment end Piping CI O?shore Pipeline. Including Riser and Riser Bend 3. Item involved In incident: {select only one) Pipe g, Specify: OPIpeBody [EPlpe Seam 3.a Nominal diameter of pipe 1512;; I I 3.b Wall thickness I 3.: SMYS (Speci?ed Minimum Yield Strength) of pipe (psi)? I 3.d Pipe speci?cation APISL 3.e Pipe Seam up Specify: 0 Longitudinal ERW - High Frequency 0 Single SAW 0 Flash Welded 0 Longitudinal ERW - Low Frequency 0 DSAW 0 Continuous Welded 0 Longitudinal ERW - Unknom Pregnancy 0 Fumace Butt Welded 0 Spiral Welded saw 0 Spiral Welded saw {21 Spiral Welded DSAW 0 Lap Welded Seamless Other 3.f Pipe manufacturer. Bern 3.9 Yearofmanufacture IQI 3.h Pipeline coating type at point of incident lea Specify: Fusion Bonded Epoxy 0 Coal Ter 0 Asphall Polyolelin Extruded Polyethylene 0 Field Applied Epoxy 0 Cold Applied Tape 0 Paint 0 Composite 0 None 0 Other --E If Pipe GIrlh Weld Is selected complete Home 3.8. through h. above. If the values on either side of the girth weld. enter one value in 3.a. through h. and list the value(s) In Part - Narrative Description of the IncidenL Cl Valve 0 Mainline g; Specify: 0 Butterfly 0 Check 0 Gate 0 Plug 0 Ball 0 Globe Other 3.I Mainline valve manufactuan 3.1 Year of manufactureRelief Valve 0 Auxiliary or Other Valve [3 Compressor [3 Meter CI ScraperIPIg Trap SeparatorISeparaior Filler El StrainerlFlIier DehydratorIDllerfl'reater Regulator/Control Valve dedep Collection Device Pulsalion Bottle Cooler [3 Repair Sleeve or Clamp HoITep Equipment El Sloppie Fitting Cl Flange Cl RellelUne El Auxiliary Piping drain lines) Tubing [3 Instrumentation [3 Underground Gas Storageor Cavem Pressure Vessel Cl Other 4. involved in Incidentwas Installed: [1 Form PHMSA 7100.2 (rev 10-2014) Page 4 ol19 5. Malerialtrwotved (select only one) til Carbon Steel [3 Plastic Cl Material other than Carbon Steel or Plastic co ?Specify. 6. Type of Incident Involved: (select only one) Cl Mechanical Puncture :9 Approx sizezl I I I II _Iin. (axial) by I I I I IJ_rrn. (circumferential) C1 Leak :5 Select Type: Pinhole 0 Crack 0 Connection Failure 0 Seal or Packing Other IZI Rupture as Setect Orlentatlon: OLonglludinal OOIher Approx. slze;l I I I in. (widest opening) by I I I1 (length ctrcumferentially or axially) Other :9 ?Describe: mm- ADDITIONAL INFORMATION I 1. Class Location of Incident: (select only one) [it Class 1 Location El Class 2 Location El Class 3 Location [3 Class 4 Location 2. Did this incident occur In a High Consequence Area No El Yes as 2.a Specify the Method used to identify the HCA: 0 Method 1 0 Method 2 3. What Is the FIR (Potential Impact Radius) for the location of this incident? I 11,1 1 I0 I 5 I feel 4. Were eny structures outside the FIR Impacted or otherwise damaged by heatI?re resulting from the Incident? 0 Yes El No 5. Were any structures outstde the FIR Impacted or omerwise damaged NOT by heat/lire resulting from the incident? 0 Yes No 6. Were any of the fatalities or Iriudes reported for persons [peeled outside the 0 Yes No 7. Estimated Property Damage: In? 1 15:01.1010101 7.1: Estimated cost of Operator's property damage repalrs 7.e EsIImated cost of Operator's emergency response 7.6 Estimated other costs Describe 7.e Total estimated property damage (sum of above) 5 I I I I 7.f Estimated cost of gas reieased unintentionally SI I I I.I9I0 I I) IJ 0 I DIOI 7.9 Estimated cost at gas released during intentional and controlled biowdown 7.h Total estimated cost of gas released (sum of 715 7.9 aboveForm PHMSA 7100.2 (rev 10-2014) Page 5 ol 19 PART 5 - ADDITIONAL OPERATING I 0 Other [Slide Specify Other: 3. Describe the pressure on the syslern or facility relating to the incident: (selecionfy one) El Pressure did not exceed MAOP [3 Pressure exceeded MAOP. but did not exceed 110% of MAOP 13 Pressure exceeded 110% of MAOP 4. Not including pressure reductions required by PHMSA regulations (such as for repairs and pipe movement). was the system or facility relating to the incident operating under an established pressure restriction with pressure limits below those normally allowed by the MADP 7 1. Estimated pressure at the point and time of the Incident (pstgMaximum Allowable Operating Pressure (MADP) at the point and time of the incident (pslg): I I 1 I IQI 2a. MAOP established by 49 CFR section: 19L61QIBKZI 0 0 9 0 9 192.619 0 192.619(d) Cl Yes :5 (Complete 4.a and 4c below) 4.8 Did the pressure exceed this established pressure restriction? 4.b Was this pressure restriction mandated by PHMSA or the State? 0 No 0 State 0 Yes 0 PHMSA 0 Not mandated DNO Ci Transmission System [It Type A Gathering [3 Storage Gathering 5.c Length of segment Isolated between valves 5. Was 'Onshore Pipeline, including Valve Sites? DR 'Ot?ishore Pipeline. Including Riser and Riser Bend? selected In PART C. Question 2? Yes :5 (Complete - 5.9 below) 5.3 Type of upstream valve used to Initially isolate release source: [a Manual 0 Automatic 0 Remoter Controlled 5.b Type of valve used to Initially isolate release source: Manual 0 Automch Remotely Controlled 0 Check Valve I I Ed Is the pipeline con?gured to accommodate internal Inspection tools? El Yes Cl No physical features toot accommodation? (select all that apply) 0 Changes In line pipe diameter Presence otmsutlabtematntine Iratv 0 Tight or mitered pipe bends Other passage restrictions (to. unbarred tee?s. protecting etc.) 0 Extra thick pipe wall (applicable only for magnetic flux leakage Internal Inspection tools) 0 Other oz: Describe: 5.e For this pipeline, are there operational factors which significantly complicate the execution of an tntemat inspection toot run? l3] No Cl Yes :9 Which operational factors compilcaie execution? {seiect apply) 0 Excessive debris or scale. wax. or other well build-up 0 Low Operating pressure(s) 0 Low ?ow or absence Of flow 0 Incompatible commodity Other up Deseribe: 5.f Function of pipeline system: (select only one) glass 1 Gas Gathering El Transmission Line of Distribution System Cl Type Gathering Cl Offshore Gathering Farm 7100.2 (rev 10-2014} Page of 19 6. Was a Supervisory Controi and Data Acquisition (SCADAi-based system in place on the pipeline or facility involved In the Incidentoperating at the time of the Incidentfully functional at the time of the incident? Yes 0 No 6.c Did SCADA?based information (such as atarm(s). aterits). eventis). andtor volmte or pack calculations) assist with the detection of the incident? 13] Yes 0 No 6.d Did SCADA-based information (such as atannis). atertis). evenl(s). and/or volume calculations) assist with the continuation of the incident? [El Yes 0 No 7. How was the Incident initially identi?ed for the Operator? (select only one) SCADA-based Inforrnalion {such as aiarm(s). alertts). event(s). andlor volume or pack calculations) [3 Static Shut-in Test or Other Pressure or Leak Test Ci Controller Local Operating Personnel. Including contractors Air Patrol Ci Ground Patrol by Operator or its mntractor El Noti?cation from Public Ci Noti?cation from Emergency Responder Ci Noti?cation from Third Party that caused the Incident Ci Other 7.a If ?Controller. 'Local Operating Fetsomel. Including contractors?. 'Air Patrol'. or 'Ground Patrol by Operator or lis contractor" is selected In Question 7. specify the foiiowing: (select only one) 0 Operator employee 0 Contractor workth for the Operator 8. Was an Investigation Initiated Into whether or not the conirollerts) or control room issues were the cause of ore contributing factor to the Incident? (select only one) Cl Yes. but the Investigation of the control room and/or controller actions has not yet been completed by the operator (Supplemental Report required) Ci No. the facility was not monitored by a controllerts) at the time of the Incident 12'] No. the operator did not ?nd that an investigation of the controiierts) actions or control room Issues was necossary due to: (provide an explanation for wh the operator did not thestigatoInvestigation reviewed work schedule rotations. continuous hours of service (Mills working for the Operator) and other factors associated with fatigue 0 Investigation did NOT review wont schedule rotations. continuous hours of service (while mrking for the Operator) and other factors associated with fatigue (provide an explanationIQr attempt) investigation Identified no control room Issues 0 investigation identi?ed no controller issues 0 investigation identi?ed Incorrect controller action or controller error 0 investigation identi?ed that fatigue may have affected the cuntrolieris) involved or impacted the Involved controllerts) response 0 Investigation Identi?ed incorrect procedures 0 Investigation identi?ed incorrect control room equipment operation 0 Investigation Identi?ed maintenance actiVities that affected control room operations. procedures. andlor controller response 0 Investigation Identi?ed areas other than those above I: Describe Form PH MSA 7100.2 (rev 10-2014) Page 7 at 19 PART - DRUG 8. ALCOHOL TESTING INFORMATION Drug 3. Alcohol Testing regdatlons? No Specify how many felled: DOTS Drug a. Alcohol Teslan regulations? No '2.b Specify how many falled: 1. As a resull of this Inddenl. were any Operator employees lesled under the post-accidenl drug and alcohol lasting requirements of DOT's :3 ?1.9 Spedl?yhowmanywerelesled: I I 2. As a result of this Incident. were any Opera [or contractor employees Iesled under the post-accldenl drug and alcohol testing requirements of OYes ?2.a 1 1 Form PHMSA 7100.2 (rev 10-2014) Page 8 0! 19 PART APPARENT CAUSE Select only one box from PART 6 In the shaded column on the loft representing the APPARENT Cause of the Inc/dent, and answer the questions on the right. Describe secondary, contributing, or root? causes of the Incident In the narrative H). G1 - Corrosion Failure - 'only one sub-cause be picked from shaded left-hand column El External Corrosion 1. Results of visual examination: 0 Localized Filling 0 General Corrosion Other 2. Type of corrosion: (seleclaiilhalappiy) Galvanic Atmospheric Stray Current 0 Microbiological Selective Seam Other 3. The typels) of corrosion selected In Question 2 is based on the following: (select all that apply) 0 Field examination 0 Determined by metallurgical analysis 0 Other 4. Was the failed item buried under the ground? 0 Yes as 4.3 Was tailed Item considered to be under cathodic protection at the lime of the incident? 0 Yes Is: Year protection started4.b Was shielding. or dish-ending of coating evident at the point of the incidentmore Cathodic Protection Survey been conducted at the point of the incident? 0 Yes. CF Annual Sorvey q: Most recent year concluded: I I I I 0 Yes, Close Interval Survey g, Most recent year conducted: I I I I 0 Yes. Other CP Survey a Most recent year conducted4.d Was the failed item externally coated or palnled? 0 Yes 0 No 5. Was there observable damage to the coating or paint in the oi the corrosion? 0 Yes 0 No Cl internal Corrosion B. Restits of visual examination: 0 Localized Filling 0 General Corrosion 0 Not cut Open 0 Other 7. Cause of corrosion: (select that apply} 0 Corrosive Commodity 0 Water Microbiological Erosion Other 8. The cause(s) of corrosion selected in Question 7 is based on the following: (select all that apply) 0 Field examination 0 Delennined by metallurgical analysis 0 Other 9. Location of corrosion: (select allihel apply} 0 Lowpolnt in pipe 0 Elbow Drop-out Other 10. Was the gasiltuld treated with corrosion inhibitors or blocides? 0 Yes 0 No 11. Was the interior coated or ?ned with protective coating? 0 Yes 0 No 12. Were cleaningidewaledng pigs (or other operations) routinely utilizad? 0 Not applicable - Not mainline pipe 0 Yes 0 No 13. Were corrosion coupons routinely utilized? 0 Not applicable - Not mainline pipe 0 Yes 0 No Form PHMSA 7100.2 (rev 10-2014) Page 9 M19 Complete the following If any Corrosion Failure sub-cause is selected AND the ?item Involved In incident" (from PART C. Ouestlon 3} ts Pipe or Weld. 14. Has one or more tntemal Inspection toot collected data at the point of the Incident? 0 Yes 0 ND 14.a. If Yes. for each tool used. select type of Internet Inspection tool and Indicate most recent year run: 0 Magnetic Flux Leakage Tool I I I I I Ultrasonic I I I I I 0 Geometry Caliper I I I I I 0 Crack I I I I I Herd Spot I I I I I 0 Combination Tool I I I I I 0 Transverse Ftetdfl'rtaadat I I I I I Other more hydrolest Or other pressure lest been conducted slnce original construction at the point of the 0 Yes :5 Moslrecenl year tested: I I I I I TestpressureIpsig16. Has one ormore Direct Assessment been conducted on this segment? 0 Yes, and an Investigative dig was concluded at the point of the Incident :5 Most recent year conductedYes. but the point DI the incident was not identi?ed as a :5 Most recent year conducted17. Has onset more non-destructive examination been conducted at the point of the incident since January 21. 2002? Yes 0 No 17.3 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: 0 Radiography I I I I I 0 Guided Wave Ultrasonic I I I I I 0 Handheld Ultrasonic Toot Dry Magnetic Particle Test Other I I I I I GZ Natural Force Damage - 'only one sub-cause ran be picked front shaded left-hand column [3 Earth Hovement, NOT due to 1. Specin 0 Earthquake Subsidence Landslide Heavy Rund?oods 0919, Heavy RatmIFloode 2. Specify: WashoulISoouring Flotation Mudslide Other [3 Lightning 3. Specify: 0 Direct hit 0 Secondary impact such as resulting nearby ?res [3 Temperature 4. Specify: ThermeISlress 0 Frost Heave 0 Frozen Components 0 Other Wind: [3 Other Natural Force Damage 5- Describe: Complete the following If any Natural Force Damage sub-cause ts selected. 6. Were the natural forces causing the Incident generated In conjunction with an extreme weather eventspeci?c (select all that apply) 0 Hurricane 0 Tropical Storm 0 Tornado 0 Other Form PHMSA 7100 2 (rev 10-2014) Page to of 19 Ga - Excavation Damage -?onty one sub-cause can be picked from shaded iei't-hand column Ci Excavation Damage by Operator (First Party) Ci Excavation Damage by Operator's Contractor (Second Party) Cl Excavation Damage by Third Party Ci Previous Damage due to Excavation Activity Complete Questions 1-5 ONLY IF the "Item Involved In incident? (from PART c, Question 3) Is Pipe or Weld. 1. Has one or more intemal inspection loot ootiected data at the point of the IncidentYes. for each tool used. seieci type of Internet Inspection tool and Indicate most recent year run: 0 Magnetic Flux Leakage I I I I Ultrasonic I I I I I 0 Geometry Caliper I I I I 0 Crack I I I I 0 Hard Spot 0 Combination Tool 0 Transverse Fieidfi'rtaxial Other I I 2. Do you have reason to believe that the Internal inspection was completed BEFORE the damage was sustainedmore hydrolest or other pressure test been conducted since ogg? ?nal construction ?K?s?h at the OYeSco Mostrecmlyeartested: I I I I I Test pressure (pslgmore Direct Assessment been conducted on the pipeline segment? 0 Yes. and an Investigative dig was conducted at the point of the Incident as Most recent year conductedYes. but the point of the Incident was not Identi?ed as a dig slle ab Moslrecenlyearconducted: I I I I I Ohio 5. Has one or more nan-destructive examination been conducted at the point of the Incident since January 1. 2002Yes. for each examination conducted since January 1. 2002. select type of non- destructive examination and indicate most recent year the examination was conducted 0 Radiography I I I I I 0 Guided Wave Ultrasonic I I I I I Handheid Ultrasonic Tool I I I I I 0 Wet Magnetic Particle Test I I I I I 0 Dry Magnetic Particle Test I I I I I Other I I I I I Complete the following Ii Excavation Damage by Third Party Is selected as the sub-cause. 6. Old the Operator get prior noti?cation of the excavation activityYes, Notii'ttation received from: (select at! that apply) 0 One-Cali System 0 Excavator Contractor Landowner :Orm PHMSA 7100.2 (rev 10-2014) Page 11 of19 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 OYes No B. Rtgmof-VVay where event occurred: (select atI that apply) Public :9 Specify: 0 City Street 0 State Highway 0 County Road 0 interstate Highway 0 Other [3 Private up Specify. 0 Private Landowner 0 Private Business 0 Private Easement Pipeline PropertylEasement Cl Powerfi'ransmission Line 13 Railroad [3 Dedicated Public Utility Easement Federal Land Data not collected Ci UnknovmtOther 9. Type oi excavator: (select only one) 0 Contractor 0 County 0 Developer 0 Farmer Municipality Occupant 0 Railroad 0 State 0 Utility 0 Data not collected 0 UnknowrlIOIher 10. Type of excavation equipment: (select only one) 0 Auger Backhoe/Trackhoe Boring Drilling Directional Dn'it'ng Explosives 0 Farm Equipment 0 GraderIScraper 0 Hand Tools 0 Milling Equipment 0 Probing Device Trencher 0 Vacuum Equipment 0 Data not collected 0 Unknowr?Other 11. Type of work periormed: (select only one) 0 Agriculture 0 Cable TV 0 CurbiSidewalk 0 Building Construction 0 Building Demolan Drainage 0 Driveway 0 Electric 0 EnglneedngISurveytng Fencing 0 Grading Irrigation 0 Landscaping 0 Liquid Pipeline Milling 0 Natural Gas 0 Pole 0 Public Transit Authority 0 Railroad Maintenance 0 Road Work 0 Sewer (SanitaryISlorm) 0 Site Development 0 Steam 0 Storm DrainICutvert OStreet OTrat?c Signet 0 Traf?c Sign 0 Water 0 Waterway improve ment 0 Data not collected 0 UnknownIOlher 12. Was the One-Call Center noti?ed'12.b If this is a State where more than a single One-Call Center exists. list the name at the One-Call Center notified. 1:3. Typeot Localor 0 Utility Owner 0 Contract Localor 0 Data not collected 0 UnknomIOther 14. Were facility locate marks visible in the area of excavation? No 0 Yes 0 Data not collected 0 15. Were facilities marked correctly? 0 No 0 Yes 0 Data not collected 0 UnknownIOther 16. Did the damage cause an interruption In service? 0 No 0 Yes 0 Data not collected 0 UnknovtnIOther 16.a ll Yes.specity duration of the interruption: I I I I Ihours (This GOA-DIRT section continued on next page with Question 17 Form PHMSA 7100.2 (rev 10-2014) Page 12 of 19 17. Description of the CGA-DIRT Root Cause (sales! only the one predoninanl ?rst level CGA-DIRT Ran! Cause and than. where avalfabte as a choice. the one predorrdnan! second lave! Roof Cause as [3 egg: NgU?grgn Pg?g (select anry one) 0 No noti?canon made to lhe One-Call Center 0 Noti?cation Io One-Call Center made. bul nol suf?cienl 0 Wrong lnfonnanon provided (sales! only one) 0 Faculty maid not he found?ocated Facilin marking or focalion not suf?cienl 0 Facility was not localed or marked 0 lnoorrecl (acuity Eg?vangn L191 gumggn? (select only one) 0 Excavalion practices nol suf?cient (other) 0 Fallure to malnlaln clearance 0 Failure In malnlaln the marks 0 Fallure to support exposed radnues 0 Failure Io use hand tools where required 0 Fallure to verify localion by lesl?hole (pol?holing) Improper Um DEW SW Hm DWI Form PHMSA 7100.2 (rev 10-2014) Page 13 GI 19 G4 - Other Outside Force Damage - 'oniy one sub-cause be picked fromshaded left-hand column Nearby industrial. Monmde, or Other FireIExpiosion a: Primary Cause of incident 93mm by Truck- am" 1. VehicieIEqulpment operated by: (select only one) Motorized Vehlciquulpment NOT Ewan? In Excavation Operator 0 Operator's Contractor 0 Third Party Damage by Boats, Barges, Drilling 2. Select one or more oi the following IF an extreme weather event was a factor: Ri?i- 0" 03?" ?Ilium. Equipm?mt 0' 0 Hurricane Troplrzi Storm 0 Tornado V?m" 5" Add? ?Wh'd? 0 Heavy RainsIFlood Other Otherwise Loci Their Mooring CI Routine or Normal Filhing or Other Maritime Activity NOT Engaged in Excavation Electrical Arcing from Other Equipment or Facility Complete Questions 3-7 ONLY iF the "item involved in incident" {from PART E, El Previous Mechanical Damage NOT Question 3) Is pipe arr/45M Related to Excavation 3. Has one or more internal lnspectim tool collected daia at the point of the lncidenl? 0 Yes 0 No 3.5! it Yes. for each tool used. select type of internal inspection tool and indicate most recent year run: 0 Magnetic Flux Leakage I I I I I Ultrasonic I I I I QGeomauy I Caliper I I I I I 0 Crack I I I I I 0 Hard Spot I I I I I 0 Combination Tool I I I I I 0 Transverse I I I I I Other you have reason to beileve that the lntemai inspection was oompieled BEFORE the damage was sustainedmore hydrotest or other pressure test been conducted since original construction at the point of the incident? OYes =9 Mostrecentyeartested: I I I I I Test pressure (pslgmore Direct been conducted on the pipeiine segment? 0 Yes. and an Investigative dig was cmducied at the point oi the incident :9 Most recent year conducted: 0 Yes, but the point of the Incident was not identi?ed as a dig site :9 Most recent year conducted{This Section continued on next page with Question Form PHMSA 7100.2 (rev 10-2014) Page 14 of 19 fnl. 'u I 7. Has one or more nondestructive examinaan been conducted al the point oi the Incident since January 1. 2002Yes. for each examination conducted since January 1. 2002. select type of non- destructive examination and indicate most recent year the examhation was conducted 0 Radiography I I I I I 0 Guided Wave Ultrasonlc I I I I I 0 Handheld Ultrasonic Tool I I I I I Wei Magnetic Particle Tesl I I I I I ODryMagnelicParticieTest I I I I I Other I I I I I intentional Damage 8. Specify: Vandailsm 0 Terrorism 0 Theft of transported 0 Theft of equipment 0 Other Other Outside Force Damage 9- Describe: Form 7100.2 (rev 10-2014) Page 15 at 19 - - Lise this section to report material failures ONLY iF the ?item involved in Only one sub-cause be picked from shaded left-hand column 1. The subcause selected below is based on the iotiowlng: (select all that apply) Ci Field Examination Determined by Metallurgical Analysis omerAnalysis {it Subcause is Tentative or Suspected; Still Under investigation (Supplemental Report required] Comm?, or 2. List contributing factors: (select all that apply) Fab?catlmmiaud Fatigue- Ot? Medianiceiianduced prior to installation (such as during iranspon of pipe) 0 Mechanical Vibration Original Manufacturing-related pressumrelaled (NOT girth weld or other welds 0 Thermal iormedi th field a Other CI Mechanical Stress Other [3 cracking.nmad 3. Speciiy: 0 Stress Corrosion Cracking Sul?de Stress Cracking 0 Hydrogen Stress Cracking Other Complete the following if any Material Failure of Pipe or Weld subacausa is selected. 4. Additional factors [select all that apply): 0 Deni Gouge 0 Pipe Bend 0 Art: Burn 0 Crack 0 Lack oi Fusion 0 Lamination Buckle Wrinkle Misaiignment 0 Burn] Steel 0 Other 5. Has one ormore internal inspection tool selected data at the point of the incidentYes. for each tool used. select type of internal inspection tool and indicate most recent year run: 0 Magnetic Flux Leakage Tool I I I I Ultrasonic I I I I I Geometry Caliper I I I I I 0 Crack I I I I I 0 Hard Spot I I I I I 0 Combination TDOI I I I I I 0 Transverse Fieidri'riaxiai I I I I I Other more hydrolest or other pressure iesl been conducted since original construction at the point at the incident? 0 Yes as 'Mostrecent year tested: I I I I I ?Tesi pressure (psigmore Direct Assessment been conducted on the pipeline segmeni? 0 Yes. and an investigative dig ms conducted at the point of the incident as Most recent year concludedYes. but the point oi the incident was not identi?ed as a dig siie as Most recent year conductedHas one ormore non-destructive eraminatlonts) been conducted at the point of the incident since January 1. 2002Yes. tor eadi examination conducted since January 1. 2002. select type of non-destructive examination and indicate most recent year the examination til-35 conducted: 0 Radiography I I I 0 Guided Wave Ultrasonic I I I I I 0 Handheld Ultrasonic TOOI I I I 0 Wet Magnetic Particle Test I I I I I 0 Dry Magnetic Particle Test I I I I I Other I I I I I Form PHMSA 7100.2 (rev 10-2014) Page 16 oi19 GS - Equipment Failure - ?onty one sub~cause can be picked from shaded Ian-hand ooitmn Ci Malfunction of ControUReiiaf 1. Specify: (56186181? thalamer Equipment 0 Control Valve 0 instrumentation SCADA 0 Communications 0 Block Valve 0 Check Valve 0 Relief Valve 0 Power Failure 0 StoppielControl Filling 0 Pressune Regulator 5513 System Failure 0 Other Ci Compressor or Compressor-related 2. Specify: Failure 0 Body Failure 0 Crack In Body Equipment 0 Apportenance Failure 0 Pressure Vessel Failure 0 Other [3 Threaded Connectiorthoupiing 3. Specify: 0 Pipe Nipple 0 Valve Threads 0 Mechanical Coupling Failure 0 Threaded Pipe Collar 0 Threaded Fitting Other CI Non-threaded Connection Failure 4. Specify: O-Rlng Gasket 0 Seal (NOT compressor seal) orPacking Other Ci Defective or Loon Tubing or Fitting Ci Failure of Equipment Body (exoapt Compressor), Vessel Plate, or other Material CI Other Equipment Failure 5 095mb? Complete the following it any Equipment Failure sub-cause is selected. 6. Additional factors that contributed to the equipment failure' (select all that apply} 0 Excessive vibration Overpressurizatlon No support or loss of support 0 Manufacturing defect 0 Loss of electricity 0 improper installation 0 Mlsmatched lterns (ditferent manufacturer for tubing and tubing ?ttings) 0 Dissimller metals 0 Breakdown of soft goods due to compatibility issues with transported gas/?uid 0 Valve vault or valve can contributed to the release 0 Alam'u'status failure 0 Miseligrrnent 0 Thermal stress 0 Other Form PHMSA 7100.2 (rev 10-2014) Page 17 at 19 67 - incorrect Operation - ?oniy one sub-cause can be picked from shaded left-hand column Ci Damage by Operator or Operator?s Contractor NOT Related to Exoavation and NOT due to Motorized VehlcietEquipment Damage [3 Underground Gas Storage, Pressure Vmel, or Cavern Allowed or Caused to Ovurpreseure Specify: 0 Valve Incorrect Reference DatalCalcuiallon Mlscommunication inadequate Monitoring 0 Other Ci Valve Left or Placed in Wrong Position, but NOT Resulting in an E3 Pipeline or Equipment Overpressured Ci Equipment Not installed Properly CI Wrong Equipment Speci?ed or installed Other incorrect Operation 2. Desoribe: Inadequate procedure pmcedurmtaotlehed 0 Failure to follow procedure 0 Other: Complete the following It any incorrect Operation sub-cause Is selected. 3. Was this Incident related to: (sated all that apply) 0 Construction 0 Commissioning Decommissioning Flight-oi-Way activities 0 Routine maintenance 0 Other maintenance 0 Normal operating conditions quali?ed Individual 4. What category type was the activity that caused the Incident: 0 Non-routine operating conditions (abnormal operations or emergencies) 5. Was the iask(s) that led to the Incident identi?ed as a covered task In your Operator Quali?cation ProgramYes, were the Individuals performing the task(s) quatilied tor the tesk(s)? 0 Yes. they were quali?ed for the lasir(s) No. bul they were performing the task(s) under the direction and observation of a quali?ed individual 0 No. they were not quali?ed for the taskts) nor were they performing the taslds) under the direction and observation of a GB - Other incident Cause - 'only one sub-cam can be picked from shaded left-hand column [3 Miscellaneous 1. Desoribe: [3 Unknown 2. Specify: 0 Investigation complele. causa of incident unknown 0 Still under investigation. came at Incident to be detennlned' (?Supplemantai Report required) Form PHMSA Page 18 ol19 PART - DESCRIPTION OF THE INCIDENT I (Attach sheets as necessary} am an ETC ratorID 32099 ex erienc da 3 as and rupture on its REM 42" (minty resulting from this incident. The Incident was telephonically reported to the Texas Railroad Commission at 21:30 on 06/14/2015 under Incident ID 1184. The line was isolated and permanent repairs completed. The root cause of the release is still under investigation with sections of the failed pipe submitted to metallurev for further analysis. PART I - simmer: AND muomzeo SIGNATURE I Preparer?: Name HYPE or prinl) Preparers Telephone Number Preparers True (type or print) Preparers Email Address Preparers Facsimile Number 2 3 a a Tamarind Nunber \m 5 z: Signer Ema! ss =orrn PHMSA 7100.2 (rev 10-2014) Page 19 0f 19