EAGLE US 2 LLC — Warning Letter

420191002W_Warning Letter_02132019_text.pdf, page 1Official PDFWARNING LETTER CERTIFIED MAIL - RETURN RECEIPT REQUESTED February 13, 2019 Andrew Kenner Vice President of Manufacturing Eagle US 2 LLC 2801 Post Oak Blvd. Houston, Texas 77056 CPF 4-2019-1002W Dear Mr. Kenner: On August 14 – 18, 2017; December 4 – 8, 2017; and January 30 – February 2, 2018, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49 United States Code (U.S.C.) inspected your Eagle US 2 LLC (Eagle), LA-TX Ethylene Pipeline in Lake Charles, Louisiana and Orange, Texas. 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 (CFR). The items inspected and the probable violations are: 1. §191.29 National Pipeline Mapping System. (a) Each operator of a gas transmission pipeline or liquefied natural gas facility must provide the following geospatial data to PHMSA for that pipeline or facility: (b) The information required in paragraph (a) of this section must be submitted each year, on or before March 15, representing assets as of December 31 of the previous year. If no changes have occurred since the previous year's submission, the operator must comply with the guidance provided in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or contact the PHMSA Geographic Information Systems Manager at (202) 366-4595.#

420191002W_Warning Letter_02132019_text.pdf, page 2Eagle failed to submit the NPMS information required by §191.29(a) on or before March 15 representing its assets as of December 31 of the previous year. Specifically, in 2016 Eagle failed to submit geospatial data, attributes, metadata and a transmittal letter appropriate for use in the National Pipeline Mapping System NPMS in a timely manner. Eagle submitted their NPMS update on September 21, 2016, which was 191 days after the deadline. 2. §192.605 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least once each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. Eagle failed to ensure their maps and manual of written procedures for conducting operations and maintenance activities and for emergency response are readily available to appropriate operating, maintenance, and emergency response personnel. At the time of inspection, the PHMSA inspector observed one of the two field technicians for LA- TX Ethylene pipeline struggling to retrieve the Operations, Maintenance, and Emergency (OME) Response Manual (dated 2015) from his work laptop without coaching from his supervisor. The field tech stated he relied on the hard copy located in his company truck (dated 2014). The current OME manual used during this inspection had a revision date of November 9, 2017. 3. §192.909 How can an operator change its integrity management program? (a) General. An operator must document any change to its program and the reasons for the change before implementing the change. (b) Notification. An operator must notify OPS, in accordance with §192.949, of any change to the program that may substantially affect the program's implementation or may significantly modify the program or schedule for carrying out the program elements. An operator must also notify a State or local pipeline safety authority when either a covered segment is located in a State where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by that State. An operator must provide the notification within 30 days after adopting this type of change into its program. 2#

420191002W_Warning Letter_02132019_text.pdf, page 3Eagle failed to follow procedure #2305-IM-1000, revision date 1/15/18 Section 43.0 – 45.0 regarding Management of Change, notifications, and significant changes which requires Eagle to define a “significant change”, document the reason for changes along with management authority for approving changes, as well as notifying PHMSA and appropriate state agencies as necessary. Eagle failed to notify PHMSA within 30 days of adopting changes to their IMP that substantially affected the program's implementation or significantly modify the program or schedule for carrying out the program elements. Eagle revamped their risk model and switched from method 1 HCA determination to method 2 in 2015. Subsequently, as a result of this inspection, on December 8, 2017 Eagle submitted a notification of change to PHMSA and initiated the MOC process. 4. §192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (b) Data gathering and integration. To identify and evaluate the potential threats to a covered pipeline segment, an operator must gather and integrate existing data and information on the entire pipeline that could be relevant to the covered segment. In performing this data gathering and integration, an operator must follow the requirements in ASME/ANSI B31.8S, section 4. At a minimum, an operator must gather and evaluate the set of data specified in Appendix A to ASME/ANSI B31.8S, and consider both on the covered segment and similar non-covered segments, past incident history, corrosion control records, continuing surveillance records, patrolling records, maintenance history, internal inspection records and all other conditions specific to each pipeline. Eagle failed to develop a process to gather data and integrate existing data to identify and evaluate potential threats on covered segments and similar non-covered segments. Eagle’s Integrity Management Program (IMP), document #2305-IM-1000, revision date 1/15/18, Section 18 Threat Identification and Risk Evaluation refers to procedure 2305-IM-C201, Gathering Data for Threats and Risk however at the time of inspection this procedure was not provided. Eagle does not have a process describing the requirements of data gathering and integrating information for LA-TX Ethylene pipeline. 5. §192.935 What additional preventive and mitigative measures must an operator take? (c) Automatic shut-off valves (ASV) or Remote-control valves (RCV). If an operator determines, based on a risk analysis, that an ASV or RCV would be an efficient means 3#

420191002W_Warning Letter_02132019_text.pdf, page 4of adding protection to a high consequence area in the event of a gas release, an operator must install the ASV or RCV. In making that determination, an operator must, at least, consider the following factors--swiftness of leak detection and pipe shutdown capabilities, the type of gas being transported, operating pressure, the rate of potential release, pipeline profile, the potential for ignition, and location of nearest response personnel. During the inspection, the PHMSA inspector found that Eagle did not conduct an analysis which considers the swiftness of leak detection and pipe shutdown capabilities, the type of gas being transported, operating pressure, the rate of potential release, pipeline profile, the potential for ignition, and location of nearest response personnel. Eagle’s IMP manual, document #2305-IM-1000, revision date 1/15/18, Section 33.4 ASV’s / RCV’s states: “33.4.1 Westlake’s currently uses Remote Control Valves (RCVs) where they have been determined to be needed. Pipelines can be isolated at the supply in cases of leak or over-pressure. The need for additional RCV’s is considered along with other P&M’s during the P&M Annual Review. 33.4.2 Westlake considered the following factors if it is determined that installing an Automatic Shutoff Valve (ASV) or RCV would be an effective way to protect a high consequence area against a gas release: • Swiftness of leak detection • Pipe shutdown capabilities • Type of gas being transported • Operating pressure • Rate of potential release • Pipeline profile • Potential for ignition • Location of nearest response personnel” At the time of inspection Eagle could not provide the analysis where they considered the need for ASV or RCV to determine if additional ASV or RCV would add protection to potentially affected high consequence areas. 6. §192.945 What methods must an operator use to measure program effectiveness? (a) General. An operator must include in its integrity management program methods to measure whether the program is effective in assessing and evaluating the integrity of each covered pipeline segment and in protecting the high consequence areas. These measures must include the four overall performance measures specified in 4#

420191002W_Warning Letter_02132019_text.pdf, page 5ASME/ANSI B31.8S (incorporated by reference, see §192.7 of this part), section 9.4, and the specific measures for each identified threat specified in ASME/ANSI B31.8S, Appendix A. An operator must submit the four overall performance measures as part of the annual report required by §191.17 of this subchapter. Eagle has failed to adequately demonstrate the effectiveness of their integrity management program. In assessing and evaluating the integrity of its LA-TX Ethylene pipeline and in protecting HCAs, Eagle did not demonstrate that periodic self-assessments, internal and/or external audits, management reviews, or other evaluations to measure program effectiveness were performed. Eagle did not demonstrate that its IMP effectiveness performance measures were trended over time or an analysis of these trends. Under 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil penalty not to exceed $213,268 per violation per day the violation persists, up to a maximum of $2,132,679 for a related series of violations. For violation occurring on or after November 2, 2015 and before November 27, 2018, the maximum penalty may not exceed $209,002 per violation per day, with a maximum penalty not to exceed $2,090,022. For violations occurring prior to November 2, 2015, the maximum 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. We have reviewed the circumstances and supporting documents involved in this case, and have decided not to conduct additional enforcement action or penalty assessment proceedings at this time. We advise you to correct the items identified in this letter. Failure to do so will result in Eagle US 2, LLC being subject to additional enforcement action. No reply to this letter is required. If you choose to reply, in your correspondence please refer to CPF 4-2019-1002W. Be advised that all material you submit in response to this enforcement action is subject to being 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). Sincerely, Mary L. McDaniel, P.E. Director, Southwest Region Pipeline and Hazardous Materials Safety Administration 5#