Gulf South Pipeline Company, LP.-8/26/15

Page 1Official PDFDOT U.S. Department of Transportation PHMSA Pipeline and Hazardous Materials Safety Administration OPS Office of Pipeline Safety Southwest Region Principal Investigator Gene Roberson Region Director R.M. Seeley Date of Report 11/3/2016 Subject Failure Investigation Report—Gulf South Pipeline Company, LP Sub-sea Fitting Failure—Eugene Island Block 95 Operator, Location, & Consequences Date of Failure 8/26/2015 Commodity Released Natural Gas City/County & State Gulf of Mexico, Louisiana, Eugene Island Block 95 OPID & Operator Name 31728 Gulf South Pipeline Company, LP Unit # & Unit Name 1534 Lafayette Offshore SMART Activity # 152248 Milepost/Location Eugene Island Block 95 Type of Failure Sub-sea connection failed, causing a pipeline system in the Gulf to separate. Estimated natural gas release was 2,631 thousand cubic feet (MCF). Fatalities None. Injuries Description of area impacted Three (3), none requiring hospitalization. Offshore in approximately 25-30 feet of water in the Gulf of Mexico. There was no structure in the vicinity that could be affected by the release. Property Damage $843,098#

Page 2Failure Investigation Report Gulf South Pipeline Company, LP—Sub-sea Connection Failure Failure Date: 8/26/2015 Executive Summary On Tuesday, August 25, 2015, C-Dive, a contractor for the Gulf South Pipeline Company, LP (Gulf South), began jetting procedures to facilitate a sub-sea pipeline abandonment project involving their 10-inch pipeline located on Eugene Island, Block 95, off the coast of Louisiana in the Gulf of Mexico. At approximately 8:45 p.m. CST on August 26, 2015, C-Dive was working to identify and validate the location for abandonment when the pipeline separated from the mechanical sub-sea fitting, releasing aprroximately 2,631 thousand cubic feet (MCF) of natural gas. This produced a surface fire on the Gulf of Mexico that burned for approximately 2 hours. All facilities in the area were shut-in, allowing the fire to burn out. At 9:40 p.m. CST on August 26, 2015, Gulf South made an initial notification to the National Response Center (NRC), NRC #1126790, regarding this incident. An update to the original report, NRC #1126839, was filed at 1:27 p.m. CST on August 27, 2015, to address the sheen associated with condesate from the pipeline (Appendix A). The release occurred approximately 40 miles offshore in approximately 25 feet of water, with no above- water structure that could be affected. The contractors’ dive boat was on the surface of the water at the time of the incident, resulting in minor injuries for three contract employees (incurred during the initial response) and negligible fire damage to the boat. After the Bureau of Safety and Environmental Enforcement (BSEE) approved Gulf South’s plan, the pipe and fitting was removed and transported to Houma, Louisiana, for initial evauluation. It was then sent to Stress Engineering Services in Houston, Texas, for further testing and evaluation. System Details Gulf South is owned by Boardwalk Pipeline Partners, LP. They operate a network of approximately 7,400 miles of gas transmission piplines located in the Gulf Coast States of Texas, Louisiana, Mississippi, Alabama, and Florida. The Lafayette Offshore Unit—the unit affected by this incident—is a system that consists of about 75 miles of pipeline in the Gulf Of Mexico in which natural gas is collected offshore and transported to systems onshore for distribution to end users. The offshore portion of this system begins in the Eugene Island Block 110 area and terminates onshore in Burns, Louisiana. The 10.75-inch-diameter, 3.33-mile segment (BSEE Segment Number 14162) from Block 110 to Block 95 was being prepared for abandonment under BSEE approval at the time of the incident. Page 2 of 6#

Page 3Failure Investigation Report Gulf South Pipeline Company, LP-Sub-sea Connection Failure Failure Date: 8/26/2015 The failure occurred at the sub-sea tie-in assembly area identified in the upper section of the area detail. Figure 1: Abandonment Area Pipeline Specifications The pipe was 10.750-inch-diameter, 0.500-inch wall thickness American Petroleum Institute (API) 5LX- 52. The sub-sea connection was an American National Standards Institute (ANSI) 900 compression-type fitting manufactured by HydroTech Systems, Inc., that was designed to connect 10.750-inch-diameter pipe in a subsea environment without welding. Page 3 of 6#

Page 4Failure Investigation Report Gulf South Pipeline Company, LP—Sub-sea Connection Failure Failure Date: 8/26/2015 Figure 2: Sub-sea Fitting The connector was installed in 2006 as an approved repair to damage from Hurricanes Katrina and Rita in 2005. Events Leading up to the Failure On August 25, 2015, Gulf South’s contractor mobilized on site in preparation for the abandonment of the pipeline system. A crew boat was supplied with diving and jetting equipment, then it and the requisite divers traveled to the appropriate location and anchored in preparation for the abandonment operations. Jetting was being performed to expose the sub-sea isolation valve and connection associated with the shut-in and abandonment. The average water depth on location is 21 feet, and the depth of cover was documented as 7 feet. On August 26, 2015, at 8:45 p.m. on the second day of this operation, when the pipe was exposed and the connection located the pipe dislodged from the mechanical fitting, allowing the pipelines to separate and the incident to occur. It was also noted during this process that an existing stand-off brace had been damaged and dislodged from the pipeline as a result of a previous sub-sea incident. The ensuing incident allowed the 10-inch pipelines to separate and release a full stream of natural gas onto the sea bed. The vapors bubbled to the surface where they ignited, burning until the gas source was isolated. The pipeline was immediately shut-in and the fire allowed to burn out. Gulf South initially reported the incident to the NRC (#1126790) at approximately 9:43 p.m. CST on August 26, 2015. An updated report was made to the NRC (#1126839) the following day at 2:27 p.m. CST to include the condensate sheen from the release (Appendix A). Emergency Response Gulf South responded by immediately isolating the affected systems and allowing the pressure to blow down to atmospheric pressure. The work boat moved off site during this process, and the fire was Page 4 of 6#

Page 5Failure Investigation Report Gulf South Pipeline Company, LP—Sub-sea Connection Failure Failure Date: 8/26/2015 allowed to burn out. No further actions were required, but the project was shut down pending investigation into the cause of the incident. The release was located offshore of Lousiana, affecting only a small surface area of the water and the crew boat performing the operation. No emergency response personel were required, and the volume of the gas loss was estimated to be 2.63 million cubic feet (MMCF). A slight sheen from condensate in the system was briefly observed, but quickly dispersed and dissipated. Summary of Return to Service Following the emergency response, the pipeline system was isolated and shut-in pendinginvestigation into the cause of the incident. A revised plan, including the removal of the failed mechanical fitting so it could be evaluated, was submitted to BSEE with a new scope for the pipeline system abandonment. Once the new plan was approved, Gulf South mobilized again and completed the removal and abandonment project. The other affected systems shut-in due to the incident were returned to service 11 days later on September 6, 2015. Investigation Details At approximately 9:43 p.m. CST on August 26, 2015, Gulf South reported to the NRC a release of natural gas due to an unknown cause at their Eugene Island Block 95 sub-sea connection in the Gulf of Mexico. The Southwest Region division of the Pipeline and Hazardous Materials Safety Administration (PHMSA) received the incident notification and began an investigation the following morning. No response to site was initiated, as the incident was sub-sea. Gulf South coordinated with PHMSA and BSEE regarding the removal of the fitting and its transport to Stress Engineering in Houston, Texas, for evaluation. Upon arrival at Stress, the Southwest Region performed a visual examination of the fitting and a scope for the investigation was established. The primary indication of the failure appeared to be mechanical, and did not indicate any material failure. Mechanical Analysis The sub-sea connector was sent to a Houston, Texas, metallurgical lab for analysis, where it was determined that the connector performed as designed and that all damage observed to the connector slips, seals, and pipe occurred during the incident. Conclusion Stress Engineering’s conclusion was: “the connector fitting likely failed due to a combination of external forces from the pipe being exposed and the lack of support from the damaged stand off found while exposing the pipe.” PHMSA concurs with this finding, since this incident occurred sub-sea and site evaluation was limited. Appendices A Telephonics Notice Report—NRC #1126839 Page 5 of 6#

Page 6Failure Investigation Report Gulf South Pipeline Company, LP—Sub-sea Connection Failure Failure Date: 8/26/2015 B Operator Accident Report—ODES #20150114 C Stress Engineering—Document No: 1461154-PL-RP-01 (Rev. 1) Page 6 of 6#

Page 7TeleDetail Page 1 of 2 •PHMSA Materials Safety Pipeline & Hazardous HMIS-> INCIDENTS->TELEPHONICS Administration (Version 4.0.0 PROD) Rules of Behavior Home Logout Menu NRC Number: [Return to Search] Call Date: 08/27/2015 1126839 Call Time: 14:27:00 Caller Information First Name: STEPHEN Last Name: BATUK Company Name: GULF SOUTH PIPELINE COMPANY Address: 2300 VEROT SCHOOL RD City: LAFAYETTE State: Country: |USA Zip: 70508 Phone 1: (8008500051 Phone 2: Confidential: Organization Type: PRIVA Is caller the spiller? • Yes • No • No Response • Yes •No • No Response First Name: STEPHEN Discharger Information Last Name: BATUK Company Name: GULF SOUTH PIPELINE COMPANY Address: 2300 VEROT SCHOOL RD City: LAFAYETTE State: LA Country: USA Zip: 70508 Phone 1: 8008500051 Phone 2: Organization Type: [PRIVAT State: Spill Information County: EUGENE ISLAND AREA Location Nearest City: Zip Code: Spill Date: [08/26/2015 (mm/dd/yyyy) Spill Time: 20:45:00 (24hh:mm:ss) DTG Type: Belect DTG P Incident Type Description Reported Incident Type PIPELINE ///NRC REPORT UPDATE TO REPORT NUMBER 1126790/// THE CALLER IS REPORTING A STATED THAT THERE IS A FIRE COMING FROM THE RELEASE SITE. NO RELEASE OF NATURAL GAS DUE A SMALL LEAK IN THE PIPELINE LINE. REPORTED INJURIES THE CALLER OR EVACUATIONS. WHICH WAS CREATED BY THE DISCHARGE OF CONDENSATE, THE IMPACT IS THE WATER DURING AN OVER FLIGHT A SHEEN WAS ALSO OBSERVED ON THE WATER ATMOSPHERE. THE DAMAGES AMOUNT IS UNKNOWN. Materials Involved NATURAL GAS Material / Chris Name ONG Chris Code [Total Qty. O UNKNOWN AMOUNT Water Qty. Medium Type: Additional Medium Information: Selett Médium i v GULE OF MEXICO http://hmis.phmsa.dot.gov/hmis/telephonics/Teledetail.aspx?showresult=Y&ReceivedDat.. 10/13/2016#

Page 8TeleDetail rage 4 vi ‹ Injuries: Evacuations: Damages: Other Agency Notified: Federal Agency Notified: © Yes © No @ Unknown © Yes • No @ Unknown State Agency Notified: • Yes © No ® Unknown Remedial Actions DIVE BOAT ON SITE. PIPELINE SHUT IN AND SHUT DOWN. Additional info / /UPDATE TO NRC REPORT 1126790 TO ADD A MATERIAL TO THE LIST OF MATERIAL RESPONDING COAST GUARD UNIT. ISCHARGED, AS WELL AS TO UPDATE THE INCIDENT SUMMARY AS REQUESTED BY TH Degrees: L Latitude Degrees: L Longitude Minutes: Seconds: Quadrant: L Distance from City: Minutes Seconds: Direction Quad Section: Township: Range: Milepost: # Rescindea Comments (max 250 characters) «c Previous 1.1 of 1 « Save >> http://hmis.phmsa.dot.gov/hmis/telephonics/Teledetail.aspx?showresult=Y&ReceivedDat... 10/13/2016#

Page 9EXPIRATION DATE: 10/31/2017 OMB NO: 2137-0522 penalty shall not exceed $1,000,000 as provided in 49 USC 60122. xceed 100,000 for each violation for each day that such violation persists except that the maximum civ IOTICE: This report is required by 49 CFR Part 191. Failure to report can result in a civil penalty not t Original Report Date: 09/18/2015 U.S Department of Transportation No. 20150114 - 17139 Pipeline and Hazardous Materials Safety Administration (DOT Use Only) INCIDENT REPORT - GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS with a collection of information subject to the requirements of the Paperwork Reduction Act unless that collection of information displays a current valid A federal agency may not conduct or sponsor, and a person is not required to respond to, nor shail a person be subject to a penalty for failure to comply mandatory. Send comments regarding the burden estimate or any other aspect of this collection of information, including suggestions for reducing the OMB Control Number. The OMB Control Number for this information collection is 2137-0522. All responses to this collection of information are INSTRUCTIONS burden to: Information Collection Clearance Officer, PHMSA, Office of Pipeline Safety (PHP.30) 1200 New Jersey Avenue, SE, Washington, D.C. 20590. examples. If you do not have a copy of the instructions, you can obtain one from the PHMSA Pipeline Safety Community Web Page at Important: Please read the separate instructions for completing this form before you begin. They clarify the information requested and provide specific http://www.phmsa.dot.gov/pipeline/library/forms. PART A - KEY REPORT INFORMATION Report Type: (select all that apply) Original: Supplemental: Last Revision Date: Yes Final: Yes 2. Name of Operator 1. Operator's OPS-issued Operator Identification Number (OPID): 31728 07/08/2016 3. Address of Operator: GULF SOUTH PIPELINE COMPANY, LP 3b. City Зa. Street Address 9 GREENWAY PLAZA SUITE 2800 3d. Zip Code: 3c. State 77046 Texas HOUSTON 5. Location of Incident: 4. Local time (24-hr clock) and date of the Incident: 08/26/2015 20:45 29.043056 6. National Response Center Report Number (if applicable): -91.69944 National Response Center (if applicable): 7. Local time (24-hr clock) and date of initial telephonic report to the 1126790 08/26/201521:40 8. Incident resulted from: released) 9. Gas released: (select only one, based on predominant volume Unintentional release of gas Natural Gas 10. Estimated volume of commodity released unintentionally - Thousand - Other Gas Released Name: 2,631.00 Thousand Cubic Feet (MCF) 11. Estimated volume of intentional and controlled release/blowdown - 12. Estimated volume of accompanying liquid release (Barrels): - If Yes, specify the number in each category: I NO 13a. Operator employees 13b. Contractor employees working for the Operator 13d. Workers working on the right-of-way, but NOT 13c. Non-Operator emergency responders 13e. General public associated with this Operator 14. Were there injuries requiring inpatient hospitalization? 13f. Total fatalities (sum of above) - If Yes, specify the number in each category: No 14a. Operator employees 14c. Non-Operator emergency responders 14b. Contractor employees working for the Operator 14d. Workers working on the right-of-way, but NOT 15. Was the pipeline/facility shut down due to the incident? 14f. Total injuries (sum of above) - If No, Explain: Yes Form PHMSA F 7100.2 Reproduction of this form is permitted Page 1 of 13#

Page 10- If Yes, complete Questions 15a and 15b: (use local time, 24-hr clock) 15b. Local time pipeline/facility restarted 15a. Local time and date of shutdown 08/26/2015 20:45 16. Did the gas ignite? - Still shut down? (* Supplemental Report Required) 09/06/2015 16:00 17. Did the gas explode? 19. Time sequence (use local time, 24-hour clock): 18. Number of general public evacuated: No 0 changed from "Incident" to "failure" 19a. Local time operator identified Incident- effective 10-2014, 08/26/2015 20:45 19b. Local time operator resources arrived on site 08/26/2015 23:50 PART B - ADDITIONAL LOCATION INFORMATION 1. Was the origin of the Incident onshore? No - No (Complete Questions 13-15) - Yes (Complete Questions 2-12) If Onshore: 2. State: 3. Zip Code: 4. City 6. Operator designated location 5. County or Parish 7. Pipeline/Facility name: Specify: 8. Segment name/ID: (OCS)? 9. Was Incident on Federal land, other than the Outer Continental Shelf 11. Area of Incident (as found) : 10. Location of incident: Other - Describe: Specify: 12. Did Incident occur in a crossing? Depth-of-Cover (in): - If Yes, specify type below: - If Bridge crossing - - If Railroad crossing - Cased/ Uncased: - If Road crossing - Cased/ Uncased/ Bored/drilled - If Water crossing - Cased/ Uncased/ Bored/drilled Cased/ Uncased Approx. water depth (ft) at the point of the Incident: Name of body of water (If commonly known): If Offshore: Select: 14. Origin of Incident: 13. Approx. water depth (ft) at the point of the Incident: On the Outer Continental Shei (OCS) - If "In State waters": - Area: - State: - Block/Tract #: - If "On the Outer Continental Shelf (OCS)": - Nearest County/Parish: - Block #: - Area: Eugene Island 15. Area of Incident: 95 Below water, pipe buried or jetted below seabed PART C - ADDITIONAL FACILITY INFORMATION 2. Part of system involved in Incident: 1. Is the pipeline or facility: - Interstate - Intrastate Interstate 3. Item involved in Incident: Offshore Pipeline, Including Riser and Riser Bend - If Pipe - Specify: Flange 3a. Nominal diameter of pipe (in): 3c. SMYS (Specified Minimum Yield Strength) of pipe (psi): 3b. Wall thickness (in): Form PHMSA F 7100.2 Reproduction of this form is permitted Page 2 of 13#

Page 113e. Pipe Seam - Specify: 3d. Pipe specification: 3f. Pipe manufacturer: - If Other, Describe: 3g. Year of manufacture: 3h. Pipeline coating type at point of Incideni - SpectOther, Describe: - If Weld, including heat-affected zone - Specify: - If Valve - Specify: - If Other, Describe: - If Mainline - Specify: 3i. Mainline valve manufacturer: - If Other, Describe: 3j. Year of manufacture: 4. Year item involved in Incident was installed: 5. Material involved in Incident: 2006 6. Type of incident involved: - If Material other than Carbon Steel or Plastic - Specify: Carbon Steel Leak - If Mechanical Puncture - Specify Approx. size: in. (circumferential) in. (axial) by - If Leak - Select Type: - If Rupture - Select Orientation: - If Other - Describe: Connection Failure Approx. size: in. (widest opening): - If Other - Describe: - If Other - Describe: by in. (length circumferentially or axially): PART D - ADDITIONAL CONSEQUENCE INFORMATION 1. Class Location of Incident: 2. Did this Incident occur in a High Consequence Area (HCA)? Class 1 Location - If Yes: No 3. What is the PIR (Potential Impact Radius) for the location of this 2a. Specify the Method used to identify the HCA: Incident? Feet: 382 due to heat/fire resulting from the Incident? 4. Were any structures outside the PIR impacted or otherwise damaged No 6. Were any of the fatalities or injuries reported for persons located NOT by heat/fire resulting from the Incident? 5. Were any structures outside the PIR impacted or otherwise damaged No No 7. Estimated Property Damage : 7a. Estimated cost of public and non-Operator private 2011, "paid/reimbursed by the Operator" removed property damage paid/reimbursed by the Operator - effective 6- $ moved to item 7f Estimated cost of gas released unintentionally - effective 6-2011, Estimated cost of gas released during intentional and controlled 7b. Estimated cost of Operator's property damage & repairs blowdown - effective 6-2011, moved to item 7g 7c. Estimated cost of Operator's emergency response 625,000 7d. Estimated other costs 10,000 7e. Property damage subtotal (sum of above) Describe: Investigation 200,000 $ 835,000 Cost of Gas Released 7g. Estimated cost of gas released during intentional and 7f. Estimated cost of gas released unintentionally 8,098 7h. Total estimated cost of gas released (sum of 7.f & 7.g above) controlled blowdown $ 0 $ 843,0,08 8,098 Form PHMSA F 7100.2 Reproduction of this form is permitted Page 3 of 13#

Page 12PART E - ADDITIONAL OPERATING INFORMATION 2. Maximum Allowable Operating Pressure (MAOP) at the point and . Estimated pressure at the point and time of the Incident (psig):- 925.00 time of the Incident (psig): 1,200.00 Added 10-2014 2a. MAOP established by 49 CFR section: 3. Describe the pressure on the system or facility relating to the If Other, specify: 192.619(a)(1) Pressure did not exceed MAOP 4. Not including pressure reductions required by PHMSA regulations relating to the Incident operating under an established pressure (such as for repairs and pipe movement), was the system or facility restriction with pressure limits below those normally allowed by the No MAOP? - If Yes - (Complete 4a and 4b below 4a. Did the pressure exceed this established pressure restriction? 4b. Was this pressure restriction mandated by PHMSA or the 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. - 5e. below): 5b. Type of downstream valve used to initially isolate release 5a. Type of upstream valve used to initially isolate release source: Automatic source: Automatic 5d. Is the pipeline configured to accommodate internal inspection 5c. Length of segment isolated between valves (ft): 174,240 tools? No - If No - Which physical features limit tool accommodation? (select all that apply) - Presence of unsuitable mainline valves - Changes in line pipe diameter - Other passage restrictions (i.e. unbarred tee's, projecting - Tight or mitered pipe bends instrumentation, etc.) Yes - Extra thick pipe wall (applicable only for magnetic flux leakage internal inspection tools) - If Other, Describe: Yes 5e. For this pipeline, are there operational factors which Sub-sea tie-in run? significantly complicate the execution of an internal inspection tool Yes - If Yes, which operational factors complicate execution? (select all that apply) - Low operating pressure(s) - Excessive debris or scale, wax, or other wall build-up - Incompatible commodity - Low flow or absence of flow 6. Was a Supervisory Control and Data Acquisition (SCADA)-based 5f. Function of pipeline system: Transmission System system in place on the pipeline or facility involved in the Incident? Yes 6b. Was it fully functional at the time of the Incident? 6a. Was it operating at the time of the Incident? Yes events), and/or volume or pack calculations) assist with the 6c. Did SCADA-based information (such as alarms), alerts), Yes Yes 6d. Did SCADA-based information (such as alarms), alert(s), event(s), and/or volume calculations) assist with the confirmation of No 7. How was the Incident initially identified for the Operator? 7a. If "Controller", "Local Operating Personnel, including - If Other - Describe: Notification From Public contractor" is selected in Question 7, specify: contractors", "Air Patrol", or "Ground Patrol by Operator or its control room issues were the cause of or a contributing factor to the 8. Was an investigation initiated into whether or not the controller(s) or No, the Operator did not find that an investigation of the controllers) actions or control room issues was necessar due to: (provide an explanation for why the Operator did not Form PHMSA F 7100.2 Reproduction of this form is permitted Page 4 of 13#

Page 13- If No, the operator did not find that an investigation of the (provide an explanation for why the operator did not investigate) controller(s) actions or control room issues was necessary due to: outage performed by area. Incident occurred while contractor was onsite for scheduled - If Yes, Describe investigation results) (select all that apply): - Investigation reviewed work schedule rotations, continuous factors associated with fatigue hours of service (while working for the operator), and other - Investigation did NOT review work schedule rotations and other factors associated with fatigue continuous hours of service (while working for the Operator) - Investigation identified no control room issues - Provide an explanation for why not: - Investigation identified incorrect controller action or - Investigation identified no controller issues - Investigation identified that fatigue may have affected the controller error response controllers) involved or impacted the involved controllers) - investigation identified incorrect procedures operation - Investigation identified incorrect control room equipment control room operations, procedures, and/or controller investigation identified maintenance activities that affected response - Investigation identified areas other than those above - Describe: PART F - DRUG & ALCOHOL TESTING INFORMATION 1. As a result of this Incident, were any Operator employees tested under the post-accident drug and alcohol testing requirements of DOT's Drug & Alcohol Testing regulations? Yes - If Yes: 1b. How many failed: 1a. How many were tested: 2. As a result of this Incident, were any Operator contractor employees tested under the post-accident drug and alcohol testing requirements of DOT's Drug & Alcohol Testing regulations? Yes 2a. 2b. How many failed: How many were tested: PART G - APPARENT CAUSE questions on the right. Describe secondary, contributing, or root causes of the Incident in the narrative (PART H). Select only one box from PART G in the shaded column on the left representing the APPARENT Cause of the Incident, and answer the Apparent Cause: G8 - Other Incident Cause G1 - Corrosion Failure - only one sub-cause can be picked from shaded left-hand column Corrosion Failure - Sub-cause: 1. Results of visual examination: • If External Corrosion: 2. Type of corrosion: (select all that apply) - If Other, Describe: - Galvanic - Atmospheric - Microbiological - Stray Current - Other - Selective Seam 3. The type(s) of corrosion selected in Question 2 is based on the following: (select all that apply) - If Other - Describe: - Field examination - Other - Determined by metallurgical analysis 4. Was the failed item buried under the ground? - If Other - Describe: Form PHMSA F 7100.2 Reproduction of this form is permitted Page 5 of 13#

Page 144a. Was failed item considered to be under cathodic protection at 4b. Was shielding, tenting, or disbonding of coating evident at the - If Yes, Year protection started: 4c. Has one or more Cathodic Protection Survey been conducted If "Yes, Close Interval Survey" - Most recent year conducted: If "Yes, CP Annual Survey" - Most recent year conducted: If "Yes, Other CP Survey" - Most recent year conducted: 5. Was there observable damage to the coating or paint in the vicinity of 4d. Was the failed item externally coated or painted? • If Internal Corrosion: the corrosion? 6. Results of visual examination: 7. Cause of corrosion (select all that apply): - If Other, Describe: - Water drop-out/Acid - Corrosive Commodity - Microbiological - Other - Erosion 8. The cause(s) of corrosion selected in Question 7 is based on the following (select all that apply): - If Other, Describe: - Field examination - Determined by metallurgical analysis 9. Location of corrosion (select all that apply): - If Other, Describe: - Elbow - Low point in pipe - Drop-out - Other 11. Was the interior coated or lined with protective coating? 10. Was the gas/fluid treated with corrosion inhibitors or biocides? 12. Were cleaning/dewatering pigs (or other operations) routinely 13. Were corrosion coupons routinely utilized? Complete the following if any Corrosion Failure sub-cause is selected AND the Item Involved in Incident" (from PART C, 14. Has one or more internal inspection tool collected data at the point Question 3) is Pipe or Weld. of the Incident? 14a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run: - Magnetic Flux Leakage Tool - Ultrasonic Most recent year run: - Geometry Most recent year run: - Caliper Most recent year run: - Crack Most recent year run: - Hard Spot Most recent year run: - Combination Tool Most recent year run: - Transverse Field/Triaxial Most recent year run: - Other Most recent year run: Most recent year run: 15. Has one or more hydrotest or other pressure test been conducted If Other, Describe: since original construction at the point of the Incident? - If Yes, Form PHMSA F 7100.2 Reproduction of this form is permitted Page 6 of 13#

Page 15Most recent year tested 16. Has one or more Direct Assessment been conducted on this Test pressure (psig): segment? - If Yes, and an investigative dig was conducted at the point of the Incident: - If Yes, but the point of the Incident was not identified as a dig site: Most recent year conducted: 17. Has one or more non-destructive examination been conducted at Most recent year conducted: the point of the Incident since January 1, 2002? recent year the examination was conducted: 17a. If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most - Radiography - Guided Wave Ultrasonic Most recent year examined: - Handheld Ultrasonic Tool Most recent year examined: - Wet Magnetic Particle Test Most recent year examined: - Dry Magnetic Particle Test Most recent year examined: - Other Most recent year examined: Most recent year examined If Other, Describe: 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 Heavy Rains/Floods: - If Other, Describe: 2. Specify: • If Lightning: - If Other, Describe: 3. Specify: 4. Specify: - If Temperature: • If Other Natural Force Damage: - If Other, Describe 5. Describe: 6. Were the natural forces causing the Incident generated in conjunction Complete the following if any Natural Force Damage sub-cause is selected. with an extreme weather event? 6a. If yes, specify: (select all that apply): - Tornado - Tropical Storm - Other - If Other, Describe: G3 - Excavation Damage only one sub-cause can be picked from shaded left-hand column Excavation Damage - Sub-Cause: - If Previous Damage Due to Excavation Activity: Complete Questions 1-5 ONLY IF the "Item Involved in Incident" (From Part C, 1. Has one or more internal inspection tool collected data at the point of 1a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run: - Magnetic Flux Leakage - Ultrasonic Year: - Geometry Year: - Caliper Year: Form PHMSA F 7100.2 Reproduction of this form is permitted Page 7 of 13#

Page 16- Crack Year: - Hard Spot Year: - Combination Tool Year: - Transverse Field/Triaxial Year: - Other: Year: 2. Do you have reason to believe that the internal inspection was Describe! completed BEFORE the damage was sustained? since original construction at the point of the Incident? 3. Has one or more hydrotest or other pressure test been conducted - If Yes: Most recent year tested: 4. Has one or more Direct Assessment been conducted on the pipeline Test pressure (psig): - If Yes, and an investigative dig was conducted at the point of the Incident: - If Yes, but the point of the Incident was not identified as a dig site: Most recent year conducted: 5. Has one or more non-destructive examination been conducted at the Most recent year conducted: point of the Incident since January 1, 2002? recent year the examination was conducted: 5a. If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most - Radiography - Guided Wave Ultrasonic Year: - Handheid Ultrasonic Tool Year: - Wet Magnetic Particle Test Year: - Dry Magnetic Particle Test Year: - Other Year: Describe: Year: 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 - Contractor - Excavator Complete the following mandatory CGA-DIRT Program questions if any Excavation Damage sub-cause is selected. - Landowner DIRT (www.cqa-dirt.com)? 7. Do you want PHMSA to upload the following information to CGA- 8. Right-of-Way where event occurred (select all that apply): - Private - If Public, Specify: - Pipeline Property/Easement - If Private, Specify: - Power/Transmission Line - Railroad - Dedicated Public Utility Easement - Federal Land - Data not collected 9. Type of excavator : - Unknown/Other 10. Type of excavation equipment : 12. Was the One-Call Center notified? - Yes - No 11. Type of work performed Form PHMSA F 7100.2 Reproduction of this form is permitted Page 8 of 13#

Page 1712a. If Yes, specify ticket number: exists, list the name of the One-Call Center notified: 12b. If this is a State where more than a single One-Call Center 14. Were facility locate marks visible in the area of excavation? 16. Did the damage cause an interruption in service? Were facilities marked correctly? 17. Description of the CGA-DIRT Root Cause (se/ect only the one predominant first leve/ CGA-DIRT Root Cause and then, where 16a. If Yes, specify duration of the interruption: (hours) - Predominant first level CGA-DIRT Root Cause: available as a choice, then one predominant second level CGA-DIRT Root Cause as well: - If One-Call Notification Practices Not Sufficient, Specify: - If Locating Practices Not Sufficient, Specify: - If Other/None of the Above, Explain: - If Excavation Practices Not Sufficient, Specify: G4 - Other Outside Force Damage - only one sub-cause can be selected from the shaded left-hand column Other Outside Force Damage - Sub-Cause: - If Damage by Car, Truck, or Other Motorized Vehicle/Equipment NOT Engaged in Excavation: 1. Vehicle/Equipment operated by: Their Mooring: - If Damage by Boats, Barges, Drilling Rigs, or Other Maritime Equipment or Vessels Set Adrift or Which Have Otherwise Lost 2. Select one or more of the following IF an extreme weather event was a factor: - Hurricane - Tropical Storm - Heavy Rains/Flood - Tornado - Other - If Previous Mechanical Damage NOT Related to Excavation: Complete Questions 3-7 ONLY IF the "Item Involved in Incident" - If Other, Describe: Зa. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run: - Magnetic Flux Leakage - Ultrasonic Most recent year run: - Geometry Most recent year run: - Caliper Most recent year run: - Crack Most recent year run: - Hard Spot Most recent year run: - Combination Tool Most recent year run: - Transverse Field/Triaxial Most recent year run: - Other: Most recent year run: Most recent year run: 4. Do you have reason to believe that the internal inspection was Describe: 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 Incident? Most recent year tested: 6. Has one or more Direct Assessment been conducted on the pipeline Test pressure (psig): segment? - If Yes, and an investigative dig was conducted at the point of the Incident: Form PHMSA F 7100.2 Reproduction of this form is permitted Page 9 of 13#

Page 18- If Yes, but the point of the Incident was not identified as a dig site: Most recent year conducted: 7. Has one or more non-destructive examination been conducted at the Most recent year conducted: point of the Incident since January 1, 2002? recent year the examination was conducted: Ta. If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most - Radiography - 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: Most recent year conducted: Describe: | - If Intentional Damage: 8. Specify: - If Other Outside Force Damage: - If Other, Describe: 9. Describe: Use this section to report material failures ONLY IF the Item Involved in G5 - Pipe, Weld, or Joint Failure Incident" (from PART C, Question 3) is "Pipe" or "Weld." Only one sub-cause can be selected from the shaded left-hand column Pipe, Weld or Join Failure - Sub-Cause: 1. The sub-cause shown above is based on the following (select all that apply): - Determined by Metallurgical Analysis - Field Examination - Other Analysis - Sub-cause is Tentative or Suspected; Still Under Investigation - If "Other Analysis", Describe - If Construction-, Installation- or Fabrication (Supplemental Report required) - Fatigue or Vibration related: 2. List contributing factors: (select all that apply) - If Other, Describe: Specify: - Mechanical Stress - Other - If Environmental Cracking-related: - If Other, Describe: 3. Specify: - If Other, Describe: Complete the following if any Material Failure of Pipe or Weld sub-cause is selected. 4. Additional Factors (select all that apply): - Gouge - Dent - Arc Burn - Pipe Bend - Crack - Lamination - Lack of Fusion - Buckle - Misalignment - Wrinkle - Burnt Steel - Other 5. Has one or more internal inspection tool collected data at the point of - If Other, Describe: Form PHMSA F 7100.2 Reproduction of this form is permitted Page 10 of 13#

Page 19the Incident? 5a. If Yes, for each tool used, select type of internal inspection tool and indicate most recent year run: - Magnetic Flux Leakage - Ultrasonic Most recent year run: Most recent year run: - Geometry - Caliper Most recent year run: - Crack Most recent year run: - Hard Spot Most recent year run: - Combination Tool Most recent year run: - Transverse Field/Triaxia Most recent year run: - Other Most recent year run: Most recent year run: Describe: Most recent year tested: 7. Has one or more Direct Assessment been conducted on the pipeline Test pressure (psig): segment? - If Yes, and an investigative dig was conducted at the point of the Incident: - If Yes, but the point of the Incident was not identified as a dig site: Most recent year conducted: 8. Has one or more non-destructive examination(s) been conducted at Most recent year conducted: the point of the Incident since January 1,2002? recent year the examination was conducted: 8a. If Yes, for each examination conducted since January 1, 2002, select type of non-destructive examination and indicate most - 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: 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: - Control Valve - SCADA - Instrumentation - Block Valve - Communications - Check Valve - Relief Valve - Power Failure Form PHMSA F 7100.2 Reproduction of this form is permitted Page 11 of 13#

Page 20- Stopple/Control Fitting - ESD System Failure - Pressure Regulator - Other - If Compressor or Compressor-related Equipment: - If Other, Describe: 2. Specify: - If Threaded Connection/Coupling Failure: - If Other, Describe: 3. Specify: • If Non-threaded Connection Failure: - If Other, Describe: 4. Specify: - If Other, Describe - If Other Equipment Failure: 5. Describe: Complete the following if any Equipment Failure sub-cause is selected. 6. Additional factors that contributed to the equipment failure (select all that appiy) - Excessive vibration - Overpressurization - No support or loss of support - Manufacturing defect - Improper installation - Loss of electricity fittings - Mismatched items (different manufacturer for tubing and tubing - Dissimilar metals - Breakdown of soft goods due to compatibility issues with - Valve vault or valve can contributed to the release transported gas/fluid - Misalignment - Alarm/status failure - Other - Thermal stress - If Other, Describe: G7 - Incorrect Operation - only one sub-cause can be selected from the shaded left-hand column Incorrect Operation - Sub-Cause: 1. Specify: - If Underground Gas Storage, Pressure Vessel, or Cavern Allowed or Caused to Overpressure: - If Other Incorrect Operation: - If Other, Describe: 2. Describe: Complete the following if any Incorrect Operation sub-cause is selected. 3. Was this Incident related to: (select all that apply) - No procedure established - Inadequate procedure - Failure to follow procedure - Other: 4. What category type was the activity that caused the Incident: - If Other, Describe: your Operator Qualification Program? 5. Was the tasks) that led to the Incident identified as a covered task in the task(s)? 5a. If Yes, were the individuals performing the tasks) qualified for G8 - Other Incident Cause - only one sub-cause can be selected from the shaded left-hand column Other Incident Cause - Sub-Cause: Miscellaneous - If Miscellaneous: 1. Describe: assembly for pipeline abandonment. Sub-sea connector Dive company was jetting to expose sub-sea tie-in valve Form PHMSA F 7100.2 Reproduction of this form is permitted Page 12 of 13#

Page 21Appendix C Stress Engineering—Document No: 1461154-PL-RP-01 (Rev. 1) This document is on file at PHMSA#