WILLIAMS OLEFINS FEEDSTOCK PIPELINES, LLC — Notice of Probable Violation

party submissionOfficial PDF420175001_Operator Response to Notice_03012017.pdf#

420175001_Final Order_07242017_text.pdf, page 1Official PDFJuly 24, 2017 Mr. Alan Armstrong President & Chief Executive Officer Williams Olefins Feedstock Pipelines, LLC One Williams Center Tulsa, Oklahoma 74172 Re: CPF No. 4-2017-5001 Dear Mr. Armstrong: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation, assesses a civil penalty of $253,900, and specifies actions that need to be taken by Williams Olefins Feedstock Pipelines, LLC to comply with pipeline safety regulations. This is to acknowledge receipt of payment of the full penalty amount, by wire transfer, dated March 21, 2017. When the terms of the compliance order are completed, as determined by the Director, Southwest Region, this enforcement action will be closed. Service of the Final Order by certified mail is effective upon the date of mailing as provided under 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Alan K. Mayberry Associate Administrator for Pipeline Safety Enclosure cc: Director, Southwest Region, Office of Pipeline Safety, PHMSA Mr. Larry D. Legendre, Manager, Pipeline Safety – Atlantic-Gulf, 2800 Post Oak Blvd., Houston TX 77056 CERTIFIED MAIL - RETURN RECEIPT REQUESTED#

420175001_Final Order_07242017_text.pdf, page 2U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION OFFICE OF PIPELINE SAFETY WASHINGTON, D.C. 20590 ____________________________________ ) In the Matter of ) ) Williams Olefins Feedstock Pipelines, ) CPF No. 4-2017-5001 LLC, ) ) Respondent. ) ____________________________________) FINAL ORDER On several occasions from August 31, 2015 to December 10, 2015, pursuant to 49 U.S.C. § 60117, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the records for operations and maintenance of Williams Olefins Feedstock Pipelines, LLC (Williams or Respondent), a subsidiary of Williams Partners, LP, in Houston, Texas. PHMSA also conducted field inspections of Williams’ Bayou Ethane System and Iowa to Port Neches 6- inch pipeline system. Williams’ interstate gas pipeline and gathering operations span the United States, including pipelines in the Gulf of Mexico, the Rockies, the Pacific Northwest and the Eastern Seaboard.1 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Respondent, by letter dated January 25, 2017, a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that Williams had committed five violations of 49 C.F.R. Part 195 and proposed assessing a civil penalty of $253,900 for the alleged violations. The Notice also proposed ordering Respondent to take certain measures to correct the alleged violations. Williams responded to the Notice by letter dated March 1, 2017 (Response). The company did not contest the allegations of violation and paid the proposed civil penalty of $253,900. In accordance with 49 C.F.R. § 190.208(a)(1), such payment authorizes the Associate Administrator to make findings of violation and to issue this final order. 1 Williams’ website, available at http://co.williams.com/ (last accessed July 20, 2017). On April 17, 2017, Williams Partners, LP, announced that it had agreed to sell 100 percent of its interest in Williams Olefins, LLC, the parent of Respondent, to NOVA Chemicals.#

420175001_Final Order_07242017_text.pdf, page 3CPF No. 4-2017-5001 Page 2 FINDINGS OF VIOLATION In its Response, Williams did not contest the allegations in the Notice that it violated 49 C.F.R. Part 195, as follows: Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.49, which states: § 195.49 Annual report. Each operator must annually complete and submit DOT Form PHMSA F 7000-1.1 for each type of hazardous liquid pipeline facility operated at the end of the previous year. An operator must submit the annual report by June 15 each year, except that for the 2010 reporting year the report must be submitted by August 15, 2011. A separate report is required for crude oil, HVL (including anhydrous ammonia), petroleum products, carbon dioxide pipelines, and fuel grade ethanol pipelines. For each state a pipeline traverses, an operator must separately complete those sections on the form requiring information to be reported for each state. The Notice alleged that Respondent violated 49 C.F.R. § 195.49 by failing to submit to PHMSA an annual report that included information on all its pipeline assets. Specifically, the Notice alleged that Williams did not submit a 2014 annual report that included information on the BASF Connection pipeline, which was constructed in 2013. Respondent did not contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.49 by failing to submit a complete 2014 annual report. Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.222, 2 which states: § 195.222 Welders and welding operators: Qualification of welders and welding operators. (a) Each welder or welding operator must be qualified in accordance with section 6, section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see § 195.3), or section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC), (incorporated by reference, see § 195.3) except that a welder or welding operator qualified under an earlier edition than listed in § 195.3, may weld but may not requalify under that earlier edition. The Notice alleged that Respondent violated 49 C.F.R. § 195.222(a) by failing to ensure that its welders were qualified in accordance with section 6 of API 1104 or section IX of the ASME Boiler and Pressure Vessel Code. Specifically, the Notice alleged that, in response to a Request for Specific Information, Williams could not produce records sufficient to demonstrate that its welders who worked on the Bayou Ethane Pipeline Rehabilitation Project were qualified to weld 2 This regulation was amended after issuance of the Notice. Amdt. 195-101, 82 FR 7999 (Jan. 23, 2017).#

420175001_Final Order_07242017_text.pdf, page 4CPF No. 4-2017-5001 Page 3 in accordance with § 195.222(a).3 Respondent did not contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.222(a) by failing to qualify its welders in accordance with section 6 of API 1104 or section IX of the ASME Boiler and Pressure Vessel Code. Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.569, which states: § 195.569 Do I have to examine exposed portions of buried pipelines? Whenever you have knowledge that any portion of a buried pipeline is exposed, you must examine the exposed portion for evidence of external corrosion if the pipe is bare, or if the coating is deteriorated. If you find external corrosion requiring corrective action under § 195.585, you must investigate circumferentially and longitudinally beyond the exposed portion (by visual examination, indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the exposed portion. The Notice alleged that Respondent violated 49 C.F.R. § 195.569 by failing to examine portions of exposed pipelines for evidence of external corrosion.4 Specifically, the Notice alleged that during the construction of new pipelines and pipeline facilities for the Bayou Ethane Pipeline Rehabilitation Project in 2013 and 2014, Williams failed to examine portions of exposed pipelines for evidence of external corrosion for six segments of pipe. Respondent did not contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.569 by failing to examine portions of exposed pipeline segments for evidence of external corrosion during the Bayou Ethane Pipeline Rehabilitation Project in 2013 and 2014. Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.579, which states: § 195.579 What must I do to mitigate internal corrosion? (a) . . . (c) Removing pipe. Whenever you remove pipe from a pipeline, you must inspect the internal surface of the pipe for evidence of corrosion. If you find internal corrosion requiring corrective action under § 195.585, you must investigate circumferentially and longitudinally beyond the exposed portion (by visual examination, indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the exposed portion. 3 See, generally, Request for Specific Information (August 29, 2016) (requesting information from Williams regarding its welding qualification procedures and records, to which Williams responded by providing limited, incomplete information) (on file with PHMSA). 4 See, Violation Report at Exhibit B, Williams Procedure No. 7.04-ADM-005, Section 1.2 (requiring that “each time a buried pipeline or related underground facility is exposed for any reason (intentionally or unintentionally), it must be thoroughly inspected (end-to-end) and the conditions documented on the appropriate form(s).” The procedures also require personnel to perform an inspection of the pipe coating and pipe conditions and to document the findings on Form 02-OPR-1581-Maintenance Report or 02-LEG-1035-Encroachment Agreement (on file with PHMSA).#

420175001_Final Order_07242017_text.pdf, page 5CPF No. 4-2017-5001 Page 4 The Notice alleged that Respondent violated 49 C.F.R. § 195.579(c) by failing to examine portions of exposed pipelines for evidence of internal corrosion.5 Specifically, the Notice alleged that during the construction of new pipelines and pipeline facilities for the Bayou Ethane Pipeline Rehabilitation Project in 2013 and 2014, Williams failed to examine portions of exposed pipelines for evidence of internal corrosion for 10 segments of pipe. Respondent did not contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.579(c) by failing to examine portions of exposed pipelines for evidence of internal corrosion. Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.583, which states, in pertinent part: § 195.583 What must I do to monitor atmospheric corrosion control? (a) . . . (c) If you find atmospheric corrosion during an inspection, you must provide protection against corrosion as required by § 195.581. The Notice alleged that Respondent violated 49 C.F.R. § 195.583(c) by failing to provide protection against corrosion after atmospheric corrosion was identified during inspections of Williams’ Iowa to Orange 6-inch pipeline system. Specifically, the Notice alleged that Williams conducted valve inspections in April 2014, May 2015, and October 2015 that resulted in atmospheric corrosion being observed at several valve sites. Williams failed, however, to correct all the deficiencies noted from these inspections and to provide protection against corrosion pursuant to § 195.581.6 Respondent did not contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.583(c) by failing to provide protection against corrosion as required by § 195.581 upon discovering evidence of atmospheric corrosion during several valve inspections. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed $200,000 per violation for each day of the violation, up to a maximum of $2,000,000 for any 5 See also, Williams Procedure No. 7.04-ADM-005, Section 2 (requiring that “[i]f the internal portion of the pipe is exposed from being cut, coupon extracted, or other reasons, include the internal surface in the Corrosion examination.” The procedures also state to perform an inspection of the internal pipe conditions and to document the findings on 02- 0PR-1581-Maintenance Report or 02-LEG-1035-Encroachment Agreement (Short Form)). 6 Respondent noted that its Iowa Extension, which was experiencing atmospheric corrosion, was idled and a “complete and total inspection and rehabilitation of the pipeline, including valve replacement, atmospheric corrosion remediation, and in-line inspection” would be completed prior to putting the line back into service. Id. at 7. PHMSA regulations, however, do not recognize idle status, and consider pipelines to be either active and fully subject to all relevant parts of the safety regulations or abandoned. See, PHMSA Advisory Bulletin 2016-0075 (August 11, 2016).#

420175001_Final Order_07242017_text.pdf, page 6CPF No. 4-2017-5001 Page 5 related series of violations.7 In determining the amount of a civil penalty under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature, circumstances, and gravity of the violation, including adverse impact on the environment; the degree of Respondent’s culpability; the history of Respondent’s prior offenses; and any effect that the penalty may have on its ability to continue doing business; and the good faith of Respondent in attempting to comply with the pipeline safety regulations. In addition, I may consider the economic benefit gained from the violation without any reduction because of subsequent damages, and such other matters as justice may require. The Notice proposed a total civil penalty of $253,900 for violations of Items 1-4. Item 1: The Notice proposed a civil penalty of $57,000 for Respondent’s violation of 49 C.F.R. § 195.49, for failing to submit a full and complete 2014 annual report to PHMSA. Williams neither contested the allegation nor presented any evidence or argument justifying a reduction in the proposed penalty. Although pipeline safety was minimally affected and Williams took steps to comply with the requirement, Williams did not achieve compliance and the violation was discovered by PHMSA. This is a repeat violation.8 Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $57,000 for violation of 49 C.F.R. § 195.49. Item 2: The Notice proposed a civil penalty of $46,600 for Respondent’s violation of 49 C.F.R. § 195.222(a), for failing to qualify its welders working on the Bayou Ethane Pipeline Rehabilitation Project, in accordance with Section 6 of API 1104 or Section IX of the ASME Boiler and Pressure Vessel Code. Williams neither contested the allegation nor presented any evidence or argument justifying a reduction in the proposed penalty. Williams failed to take appropriate action to comply with a requirement that was clearly applicable, and as a result, pipeline integrity was compromised in areas other than an HCA or HCA “could affect” segment. This violation was discovered by PHMSA. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $46,600 for violation of 49 C.F.R. § 195.222(a). Item 3: The Notice proposed a civil penalty of $69,100 for Respondent’s violation of 49 C.F.R. § 195.569, for failing to examine portions of exposed pipeline for evidence of external corrosion if the pipe is bare or if the coating is deteriorated. Williams neither contested the allegation nor presented any evidence or argument justifying a reduction in the proposed penalty. Williams failed to take appropriate action to comply with a requirement that was clearly applicable, and as a result, pipeline integrity was compromised in areas other than an HCA or HCA “could affect” segment. Further, PHMSA discovered the violation. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $69,100 for violation of 49 C.F.R. § 195.569. Item 4: The Notice proposed a civil penalty of $81,200 for Respondent’s violation of 49 C.F.R. § 195.579(c), for failing to examine portions of exposed pipeline for evidence of internal 7 These amounts are adjusted annually for inflation. See, e.g., Pipeline Safety: Inflation Adjustment of Maximum Civil Penalties, 82 Fed. Reg. 19325 (April 27, 2017). 8 In the Matter of Williams Olefins Feedstock Pipelines, LLC, Final Order, CPF. No. 4-2013-5016 (March 20, 2014).#

420175001_Final Order_07242017_text.pdf, page 7CPF No. 4-2017-5001 Page 6 corrosion. Williams neither contested the allegation nor presented any evidence or argument justifying a reduction in the proposed penalty. Williams failed to take appropriate action to comply with a requirement that was clearly applicable, and as a result, pipeline integrity was compromised in areas other than an HCA or HCA “could affect” segment. Further, Williams did not have a credible justification for its actions. PHMSA discovered the violation. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $81,200 for violation of 49 C.F.R. § 195.579(c). In summary, having reviewed the record and considered the assessment criteria for each of the Items cited above, I assess Respondent a total civil penalty of $253,900, which amount has already been paid by Respondent. COMPLIANCE ORDER The Notice proposed a compliance order with respect to Items 1 and 5 in the Notice for violations of 49 C.F.R. §§ 195.49 and 195.583(c), respectively. Under 49 U.S.C. § 60118(a), each person who engages in the transportation of hazardous liquids or who owns or operates a pipeline facility is required to comply with the applicable safety standards established under chapter 601. Pursuant to the authority of 49 U.S.C. § 60118(b) and 49 C.F.R. § 190.217, Respondent is ordered to take the following actions to ensure compliance with the pipeline safety regulations applicable to its operations: 1. With respect to the violation of § 195.49 (Item 1), Respondent must submit a supplemental annual report to PHMSA to include the BASF Connection pipeline information. This must be completed within 30 days of after receipt of the Final Order. 2. With respect to the violation of § 195.583(c) (Item 5), Respondent must correct all deficiencies identified in its atmospheric corrosion inspections of the Iowa Extension. Williams must provide a monthly update regarding all deficiencies that have been corrected, beginning 30 days after receipt of the Final Order. All work is to be completed within 365 days after receipt of the Final Order. It is requested (not mandated) that Williams maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to the Director. It is requested that these costs be reported in two categories: 1) total cost associated with preparation/ revision of plans, procedures, studies and analyses; and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. The Director may grant an extension of time to comply with any of the required items upon a written request timely submitted by the Respondent and demonstrating good cause for an extension. Failure to comply with this Order may result in the administrative assessment of civil penalties not to exceed $200,000, as adjusted for inflation (49 C.F.R. § 190.223), for each violation for each day the violation continues or in referral to the Attorney General for appropriate relief in a district court of the United States.#

420175001_Final Order_07242017_text.pdf, page 8CPF No. 4-2017-5001 Page 7 Under 49 C.F.R. § 190.243, Respondent may submit a Petition for Reconsideration of this Final Order to the Associate Administrator, Office of Pipeline Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC 20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address, no later than 20 days after receipt of service of this Final Order by Respondent. Any petition submitted must contain a statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.243. The filing of a petition automatically stays the payment of any civil penalty assessed. The other terms of the order, including corrective action, remain in effect unless the Associate Administrator, upon request, grants a stay. The terms and conditions of this Final Order are effective upon service in accordance with 49 C.F.R. § 190.5. July 24, 2017 ___________________________________ __________________________ Alan K. Mayberry Date Issued Associate Administrator for Pipeline Safety#

420175001_NOPV PCP PCO_01252017_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION, PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED January 25, 2017 Mr. Alan Armstrong President, Chief Executive Officer Williams Olefins Feedstock Pipelines, LLC One Williams Center Tulsa, Oklahoma 74172 CPF 4-2017-5001 Dear Mr. Armstrong: On multiple occasions between August 31 and December 10, 2015, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected Williams Olefins Feedstock Pipelines, LLC’s (Williams) plans and records for operations and maintenance in Houston, Texas, and conducted field evaluation of its Bayou Ethane System and Iowa to Port Neches 6-inch pipeline system. As a result of the inspection, it is alleged that you have committed probable violations of the Pipeline Safety Regulations, Title 49 Code of Federal Regulations. The items inspected and the probable violations are: 1. § 195.49 Annual report. Each operator must annually complete and submit DOT Form PHMSA F 7000-1.1 for each type of hazardous liquid pipeline facility operated at the end of the previous year. An operator must submit the annual report by June 15 each year, except that for the 2010 reporting year the report must be submitted by August 15, 2011. A separate report is required for crude oil, HVL (including anhydrous ammonia), petroleum products, carbon dioxide pipelines, and fuel grade ethanol pipelines. For#

420175001_NOPV PCP PCO_01252017_text.pdf, page 2each state a pipeline traverses, an operator must separately complete those sections on the form requiring information to be reported for each state. Williams did not include the new 10-inch, 0.37 mile BASF Connection pipeline in their 2014 annual report submittal. Williams had constructed new pipelines and pipeline facilities in 2013 and 2014 as part of the Bayou Ethane Pipeline Rehabilitation Project, which includes the construction of 0.37 miles of 10-inch pipeline (BASF Connection) which was completed in 2013. At the time of inspection, Williams stated that the BASF Connection was sold to another company in 2014, but Williams retained operatorship. Williams’ 2014 Annual Report submitted to PHMSA did not include data information on BASF Connections. This is a repeat violation of CPF 4-2013-5016, Items #1, 2, and 3. 2. § 195.222 Welders: Qualification of welders. (a) Each welder must be qualified in accordance with section 6 of API 1104 (incorporated by reference, see § 195.3) or section IX of the ASME Boiler and Pressure Vessel Code, (incorporated by reference, see § 195.3) except that a welder qualified under an earlier edition than listed in § 195.3 may weld but may not re- qualify under that earlier edition. Williams could not demonstrate that welders were qualified in accordance with section 6 of API 1104 or section IX of the ASME Boiler and Pressure Vessel Code on the Bayou Ethane Pipeline Rehabilitation Project that was completed in December 2014. Williams constructed new pipelines and pipeline facilities in 2013 and 2014 as part of the Bayou Ethane Pipeline Rehabilitation Project which included the following activities: (1) 3.24 miles of 12-inch steel pipeline (Ethane BASF South). (2) 0.49 mile of 12-inch steel pipeline (Ethane BASF North). (3) 0.48 mile of 12-inch steel pipeline (Korbe Junction to Explorer Line). A Request for Specific Information (RSFI) was sent to Williams on August 29, 2016. The RSFI specifically requested a list of all welders that welded on the projects listed above. The RSFI also specifically requested the welder qualification records to demonstrate that the welders were qualified in accordance with section 6 of API or section IX of the ASME Boiler and Pressure Vessel Code. On September 28, 2016, Williams provided the welding procedure and the procedure qualification record for Welding Procedure Specification Sunland-004. Williams provided another welder record which was for a different contractor and company, and it could not be determined what procedure that the individual was qualified under and if that was approved by Williams, dated November 16, 2012. Williams also provided a procedure qualification record TRB1-1, and no welding procedure. It is unclear that these individuals actually welded on the projects and what procedures were utilized. The RSFI also requested the non-destructive test records for the construction projects listed 2#

420175001_NOPV PCP PCO_01252017_text.pdf, page 3above. On September 28, 2016, Williams provided non-destructive test records for the projects. The records provided did identify the welds being tested and the results of the non-destructive tests, but the records did not identify the welders. Williams stated that they were unable to locate and provide a weld map or other record that specifically confirms which welders performed each weld and the results of the non-destructive tests for those welds. Williams’ Procedure WE-ADM-005, ‘Specification 102 – Welder Performance Qualification’, Section 3.1.3, states that “Prior to welding on pipelines, all welders are required to be qualified in accordance with one or more of the following: ASME Section IX and/or API 1104 (latest DOT-accepted editions).” The information provided by Williams did not confirm how many welders were utilized and if the welders were qualified to weld on activities #1, #2, and #3 above. Williams did not demonstrate that the person(s) who welded on activities #1, #2, and #3 above, were qualified in accordance with section 6 of API 1104 or section IX of the ASME Boiler and Pressure Vessel Code. 3. § 195.569 Do I have to examine exposed portions of buried pipelines? Whenever you have knowledge that any portion of a buried pipeline is exposed, you must examine the exposed portion for evidence of external corrosion if the pipe is bare, or if the coating is deteriorated. If you find external corrosion requiring corrective action under § 195.585, you must investigate circumferentially and longitudinally beyond the exposed portion (by visual examination, indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the exposed portion. Williams did not examine exposed portions of buried pipe for evidence of external corrosion at the time when Williams had constructed new pipelines and pipeline facilities in 2013 and 2014 as part of the Bayou Ethane Pipeline Rehabilitation Project. Williams Procedure No. 7.04-ADM-005, ‘Examining and Documenting the Condition of an Underground Pipeline or Related Facility When Exposed for Any Reason’, Section 1, states that each time a buried pipeline or related underground facility is exposed for any reason (intentionally or unintentionally), it must be thoroughly inspected (end-to-end) and the conditions documented on the appropriate form(s).” The procedures also state, to perform an inspection of the pipe coating and pipe conditions and to document the findings on Form 02- OPR-1581-Maintenance Report or 02-LEG-1035-Encroachment Agreement (Short Form). At the time of inspection, Williams was unable to provide documentation to demonstrate that the pipelines that were exposed during the following construction activities had been examined for evidence of external corrosion: 1. Replacement of existing valves on the “12-inch Explorer pipeline” segment’s main line valve between Korbe Junction in Port Neches, Texas, and the Lake Charles Pump Station in Sulphur, Louisiana. Nine valves were converted to above ground valves and six valves remained underground. Williams was unable to provide documentation to demonstrate that they had examined buried sections of the “12-inch Explorer pipeline” segment that were exposed during the valve replacement for evidence of external corrosion.3#

420175001_NOPV PCP PCO_01252017_text.pdf, page 42. Replacement of above ground spans at two locations on the “12-inch, Explorer pipeline” segments. One span, approximately 800 feet in length, was replaced with underground pipe via Horizontal Directional Drilling; and the other span, approximately 75 feet in length was replaced by open cut technique. Williams was unable to provide documentation to demonstrate they had examined buried sections of existing “12-inch Explorer pipeline” segment that were exposed during the pipeline span replacement for evidence of external corrosion. 3. A 12-inch, 2.5 miles of pipeline was constructed to connect the Lake Charles Pump Station to the existing 8-inch pipeline near Sulphur, Louisiana. A new 12-inch pig trap was also installed at the Lake Charles Pump Station Williams was unable to provide documentation to demonstrate that they had examined the buried section of the existing 8-inch pipeline for evidence of external corrosion. 4. A new 12-inch, 0.49 mile pipeline (Ethane BASF North) was constructed and connected to the existing “12-inch Explorer pipeline” segment. Williams was unable to provide documentation to demonstrate that they had examined the buried sections of the existing “12-inch Explorer pipeline” segment that were exposed during the construction for evidence of external corrosion. 5. A new 12-inch, 3.24 miles pipeline (Ethane BASF South) was constructed between existing “8-inch, 840 pipeline” segment and the existing “12-inch Explorer pipeline” segment. Williams was unable to provide documentation to demonstrate that they had examined the buried sections of existing “8-inch, 840 pipeline” segment and buried sections of existing “12-inch Explorer pipeline” segment that were exposed during the construction for evidence of external corrosion. 6. A new 12-inch, 0.48 mile pipeline (Korbe Junction to Explorer) was constructed and connected to the existing “12-inch Explorer pipeline” segment. Williams was unable to provide documentation to demonstrate that they had examined buried sections of existing “12-inch Explorer pipeline” segment that were exposed during construction for evidence of external corrosion. 4. § 195.579 What must I do to mitigate internal corrosion? (c) Removing pipe. Whenever you remove pipe from a pipeline, you must inspect the internal surface of the pipe for evidence of corrosion. If you find internal corrosion requiring corrective action under § 195.585, you must investigate circumferentially and longitudinally beyond the removed pipe (by visual examination, indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the removed pipe. Williams did not inspect the internal surface of the removed pipe at the time when Williams had constructed new pipelines and pipeline facilities in 2013 and 2014 as part of the Bayou Ethane Pipeline Rehabilitation Project. Williams Procedure No. 7.04-ADM-005, ‘Examining and Documenting the Condition of an Underground Pipeline or Related Facility When Exposed for Any Reason’, Section 2, states that4#

420175001_NOPV PCP PCO_01252017_text.pdf, page 5“If the internal portion of the pipe is exposed from being cut, coupon extracted, or other reasons, include the internal surface in the Corrosion examination.” The procedures also state, to perform an inspection of the internal pipe conditions and to document the findings on 02-OPR-1581 – Maintenance Report or 02-LEG-1035-Encroachment Agreement (Short Form). At the time of inspection, Williams did not provide documentation to demonstrate that pipelines that were exposed internally from being cut during the following construction activities had been examined for evidence of internal corrosion: 1. A new pump station was constructed near Hankamer, Texas, and connected to the existing “8-inch, 840 pipeline” segment. Williams did not provide documentation to demonstrate they had internally examined sections of the “840 pipeline” segment for evidence of internal corrosion. 2. 3. 4. New pump station construction near Port Arthur, Texas, and connected to the existing “12-inch Explorer pipeline” segment. Williams did not provide documentation to demonstrate they had internally examined sections of the “12-inch Explorer pipeline” segment for evidence of internal corrosion. Valve replacement was conducted on the existing “12-inch Explorer pipeline” segment’s main line valve between Korbe Junction in Port Neches, Texas, and the Lake Charles Pump Station in Sulphur, Louisiana. Nine valves were converted to above ground valves and six valves remain underground. Williams did not provide documentation to demonstrate they had internally examined sections of “12-inch Explorer pipeline” segment for evidence of internal corrosion. Replacement of above ground spans at two locations on the “12-inch Explorer pipeline” segments. One span, approximately 800 feet in length, was replaced with underground pipe via Horizontal Directional Drilling; and the other span, approximately 75 feet in length was replaced by open cut technique. Williams did not provide documentation to demonstrate they had internally examined sections of the existing “12-inch Explorer pipeline” segment that was exposed and cut during the pipeline span replacement for evidence of external corrosion. 5. Replacement of an ethane liquid meter was installed at the Lake Charles Pump Station. Williams did not provide documentation to demonstrate they had internally examined the section of existing above ground pipe connected to the new ethane liquid meter for evidence of internal corrosion. 6. A 12-inch, 2.5 miles of pipeline was constructed to connect Lake Charles Pump Station to the existing 8-inch pipeline near Sulphur, Louisiana. A new 12-inch pig trap was also installed at the Lake Charles Pump Station. Williams did not provide documentation to 5#

420175001_NOPV PCP PCO_01252017_text.pdf, page 6demonstrate they had internally examined the section of the existing 8-inch pipeline for evidence of internal corrosion. 7. A new pump station was constructed near Bruly, Louisiana, and connected to an existing 10-inch pipeline. Williams did not provide documentation to demonstrate they had internally examined the section of the existing 10-inch pipeline for evidence of internal corrosion. 8. 9. A new 12-inch, 0.49 mile pipeline (Ethane BASF North) was constructed and connected to existing the “12-inch Explorer pipeline” segment. Williams did not provide documentation to demonstrate they had internally examined sections of the existing “12- inch Explorer pipeline” segment that was exposed for evidence of internal corrosion. A new 12-inch, 3.24 miles pipeline (Ethane BASF South) was constructed between an existing “8-inch, 840 pipeline” segment and the existing “12-inch Explorer pipeline” segments. Williams did not provide documentation to demonstrate they had internally examined sections of the existing “8-inch, 840 pipeline” segment and sections of the existing “12-inch Explorer pipeline” segments that were exposed for evidence of internal corrosion. 10. A new 12-inch, 0.48 mile pipeline (Korbe Junction to Explorer) was constructed and connected to the existing “12-inch Explorer pipeline” segment. Williams did not provide documentation to demonstrate they had internally examined sections of the existing “12- inch Explorer pipeline” segment that was exposed for evidence of internal corrosion. 5. § 195.583 What must I do to monitor atmospheric corrosion control? (c) If you find atmospheric corrosion during an inspection, you must provide protection against the corrosion as required by §195.581. Williams did not provide protection against atmosphere corrosion, after atmospheric corrosion was identified during inspections. During the inspection of the Williams Iowa to Orange 6-inch pipeline system, the inspector reviewed the inspection of valves and the documentation indicated that there was atmospheric corrosion with repairs, identified at the following locations: 1) Valve Site #10 Old Ferry Road 2) Valve Site #9 South Pig Trap. 3) Valve Site #8 North Pig Trap 4) Valve Site #6 Global Dr. 5) 6” Riser off 6” Main Line Targa Valve Site Greywood Parkway. 6) Valve Site #5 Tank Farm Rd. 7) Valve Site #4 Ham Reid Rd. Inspections of the valves noted above were conducted in April 2014; October 2015 and in May 2015. The Valve Inspection Reports, 02-OPR-1035, indicate ‘Corrosion’ was observed on their inspection forms. Under the ‘List Post-Inspection Repairs Needed’ column, comments state that6#

420175001_NOPV PCP PCO_01252017_text.pdf, page 7various repairs are needed. The deficiencies and repair recommendations noted were the same for all valve inspections. Williams’ Procedure No 9.01-ADM-037 Valve Inspection and Maintenance, states ‘Using 02- OPR-1035 – Valve Inspection Report, document any repairs or corrections made and any deficiencies observed which require follow-up.’ A review of records indicated that in 2014 and 2015, several valves had atmospheric corrosion deficiencies, specifically Valve Site #4 and #10. During the PHMSA field inspection during the week of December 8-10, 2015, it was discovered that these valve sites had not been maintained. The PHMSA field inspection revealed that several pipeline and pipeline components showed severe atmospheric corrosion; and pipe supports and valve handles were missing and corroded. Moreover, Valve Sites #1, #7 and #11 were physically visited and inspected. Pipeline and pipeline components at these locations also showed severe atmospheric corrosion. The 2014 and 2015 annual valve inspection forms did not have any notes on the observations regarding atmospheric corrosion for these valves. Also, Valve Site #11 was not listed on 2014 and 2015 annual valve inspection. Williams’ Procedure No. 7.04-ADM-002 - Atmospheric Corrosion Inspection, states that they are to visually ‘inspect all surfaces and assign a visual coating condition code on the Atmospheric Corrosion Inspection data gather form, generated from the American Innovations Pipeline Compliance System (PCS) or in the data logger as either “Adequate” or “Inadequate.” Also, the procedures state that they are to visually ‘inspect all surfaces and assign a visual corrosion condition code on the Atmospheric Corrosion Inspection data gather form (generated from the American Innovations Pipeline compliance System (PCS) or in the data logger as either “Rust”, “Pitting”, or “None”.’ Williams provided the records of the atmospheric inspections for the Iowa Extension. These records show, the valves were inspected for atmospheric corrosion in April of 2014, and in May of 2016. The coating conditions were identified as “Coating Not Adequate” and the Inspection Remarks vary from ‘Transition needs to be rewrapped and needs paint’ to ‘’hand wheel rusted off, transition needs repair, pipe supports missing’. During and after the inspection, Williams stated that, “the line is idled and has been idled for some time prior to our purchase. A complete and total inspection and rehabilitation of the pipeline, including valve replacement, atmospheric corrosion remediation, and in-line inspection will be completed before the pipeline is place back in service.” On August 11, 2016, PHMSA issued an Advisory Bulletin (PHMSA-2016-0075), PHMSA regulations do not recognize an “idle” status for hazardous liquid and gas pipelines. The regulations consider pipeline to be either active and fully subject to all relevant parts of the safety regulations or abandoned. Proposed Civil Penalty Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $205,638 per violation per day the violation persists up to a maximum of $2,056,380 for a related series of violations. For violations occurring between January 4, 2012, to August 1, 2016, the 7#

420175001_NOPV PCP PCO_01252017_text.pdf, page 8maximum penalty may not exceed $200,000 per violation per day, with a maximum penalty not to exceed $2,000,000 for a related series of violations. For violations occurring prior to January 4, 2012, the maximum penalty man not exceed $100,000 per violations per day, with a maximum penalty not to exceed $1,000,000 for related series of violations. The Compliance Officer has reviewed the circumstances and supporting documentation involved in the above probable violations and has recommended that you be preliminarily assessed a civil penalty of $253,900 as follows: Item number PENALTY 1 $57,000 2 $46,600 3 $69,100 4 $81,200 Proposed Compliance Order With respect to Items 1 and 5 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Williams Olefins Feedstock Pipelines, LLC. Please refer to the Proposed Compliance Order, which is enclosed and made a part of this Notice. Response to this Notice Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in Compliance Proceedings. Please refer to this document and note the response options. All material you submit in response to this enforcement action may be made publicly available. If you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order. In your correspondence on this matter, please refer to CPF 4-2017-5001 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, R. M. Seeley Director, Southwest Region Pipeline and Hazardous Materials Safety Administration Enclosures: Proposed Compliance Order Response Options for Pipeline Operators in Compliance Proceedings 8#

420175001_NOPV PCP PCO_01252017_text.pdf, page 9PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Williams Olefins Feedstock Pipelines, LLC a Compliance Order incorporating the following remedial requirements to ensure the compliance of Williams Olefins Feedstock Pipelines, LLC with the pipeline safety regulations: 1. In regard to Item Number 1 of the Notice, pertaining to the failure to submit an accurate 2014 annual report to PHMSA, Williams Olefins Feedstock Pipelines, LLC, must submit a supplemental annual report to PHMSA to include the BASF Connection pipeline information. This must be completed within 30 days of after receipt of the Final Order. 2. 3. In regards to Item Number 5 of the Notice pertaining to the failure provide protection against atmospheric corrosion, Williams Olefins Feedstock Pipelines, LLC, must correct all deficiencies identified in their atmospheric inspections of the Iowa Extension. Williams must provide a monthly update regarding all deficiencies that have been corrected. All work is to be completed within 365 days after receipt of the Final Order. It is requested (not mandated) that Williams maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to R. M. Seeley, Director, Southwest Region, Pipeline and Hazardous Materials Safety Administration. It is requested that these costs be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses, and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. 9#

420175001_Closure Letter_10302018_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED October 30, 2018 Alan Armstrong President, Chief Executive Officer Williams Olefins Feedstock Pipelines, LLC One Williams Center Tulsa, Oklahoma 74172 CPF 4-2017-5001 Dear Mr. Armstrong: On July 24, 2017, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to Williams Olefin Feedstock Pipeline LLC a Final Order in the above-referenced case. This Order included a Compliance Order and Civil Penalty assessment. Based on our review of the documentation you provided and confirmation of payment of the civil penalty, it has been determined that you have complied with the terms of this Order. Accordingly, this case is now closed and no further action is contemplated with respect to the matters involved in this case. Thank you for your cooperation in this matter. Sincerely, Mary L. McDaniel, P. E. Director, Southwest Region Pipeline and Hazardous Materials Safety Administration cc: Mark Cluff Vice President Safety & Operational Discipline Williams Olefins Feedstock Pipeline, LLC#