LAKE CHARLES LNG COMPANY, LLC — Notice of Probable Violation

party submissionOfficial PDF420173002_Operator Petition for Reconsideration and Request for Stay_12232019.pdf#

case documentOfficial PDF420173002_Operator Pre-Hearing Submittal_09222017.pdf#

party submissionOfficial PDF420173002_Operator Response to Notice and Request for Hearing_03222017.pdf#

party submissionOfficial PDF420173002_Operator_Post-Hearing_Brief_11032017.pdf#

420173002_Closure Letter_11092020_text.pdf, page 1Official PDFVia ELECTRONIC MAIL November 9, 2020 Matthew Ramsey Chief Operating Officer Energy Transfer Partners, LP 8111 Westchester Drive Dallas, Texas 75225 CPF 4-2017-3002 Dear Mr. Warren: On March 7, 2018, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to Lake Charles LNG Company, LLC a Final Order in the above-referenced case. This Final Order included a Compliance Order that required the respondent to complete all items and to submit documentation to the Southwest Region Director demonstrating the completion within 180 days of receiving the Final Order and a civil penalty. On June 1, 2020, Lake Charles LNG provided documentation addressing completion of all items referenced in the Compliance Order. Based on our review of the information provided, it has been determined that you have complied with the terms the Compliance Order and made payment of the penalty, therefore, this case is now considered closed. Thank you for your cooperation in this matter. Sincerely, Mary L. McDaniel, P.E. Director, Southwest Region Pipeline and Hazardous Materials Safety Administration cc: Todd Nardozzi, Director Regulatory Compliance, Energy Transfer#

420173002_NOPV PCP PCO_02212017_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED February 21, 2017 Mr. Dennis Odum VP, Operations of the South and LNG Divisions Lake Charles LNG Company, LLC 800 E. Sonterra Blvd San Antonio, TX 78258 CPF 4-2017-3002 Dear Mr. Odum: On September 15 - 16, 2015, 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 inspected your records and procedures in Lake Charles, Louisiana. As a result of the inspection, it appears that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violation(s) are: 1. §193.2629 External corrosion control, buried or submerged components (a) Each buried or submerged component that is subject to external corrosive attack must be protected from external corrosion by:#

420173002_NOPV PCP PCO_02212017_text.pdf, page 2(2) The following means: (ii) A cathodic protection system designed to protect components in their entirety in accordance with the requirements of §192.463 of this chapter and placed in operation before October 23, 1981, or within 1 year after the component is constructed or installed whichever is later. §192.463 External corrosion control: Cathodic protection. (a) Each cathodic protection system required by this subpart must provide a level of cathodic protection that complies with one or more of the applicable criteria contained in Appendix D of this part. If none of these criteria is applicable, the cathodic protection system must provide a level of cathodic protection at least equal to that provided by compliance with one or more of these criteria. Appendix D - Criteria for Cathodic Protection and Determination of Measurements I. Criteria for cathodic protection (1) A negative (cathodic) voltage of at least 0.85 volt, with reference to a saturated copper-copper sulfate half cell. Determination of this voltage must be made with the protective current applied, and in accordance with sections II and IV of this appendix. II. Interpretation of voltage measurement. Voltage (IR) drops other than those across the structure electrolyte boundary must be considered for valid interpretation of the voltage measurement in paragraphs A(1) and (2) and paragraph B(1) of section I of the appendix. Lake Charles LNG failed to consider IR drop when interpreting cathodic protection readings from their annual survey to determine if the cathodic protection was adequate as required by §193.2629 and §192.463, Appendix D. During the inspection, the Operator stated that they were using the - 0.85 volt criterion with current applied. This criterion requires that voltage (IR) drops other than those across the structure to electrolyte boundary be considered for valid interpretation of the voltage measurements. PHMSA requested information on how the Operator had considered IR drops in determining the adequacy of the readings, but the operator was unable to explain or provide additional information in the form of surveys, studies, or measurements to show how this requirement had been satisfied. 2#

420173002_NOPV PCP PCO_02212017_text.pdf, page 3The -0.85 volt criterion at a minimum requires this potential at the pipe-to-soil interface. Readings taken on the surface of the ground above the pipe incorporate a voltage drop that if not considered, could result in the required cathodic protection potential at the pipe-to-soil interface being inadequate. Lake Charles LNG’s records show only structure to soil readings with the cathodic protection current applied and the Operator did not account for the voltage (IR) drops in the cathodic protection circuit, particularly IR drop in the soil between the point of measurement on the surface of the ground and the pipe. 2. §193.2635 Monitoring corrosion control Corrosion protection provided as required by this subpart must be periodically monitored to give early recognition of ineffective corrosion protection including the following, as applicable: (d) Each component that is protected from atmospheric corrosion must be inspected at intervals not exceeding 3 years. Lake Charles LNG failed to periodically inspect a portion of their aboveground piping to monitor for ineffective corrosion protection from atmospheric corrosion as required by §193.2635. During the PHMSA inspection, the Operator was asked to provide atmospheric corrosion inspection records for their aboveground piping, specifically the insulated stainless steel piping used to transport chilled or liquefied natural gas within the facility. Lake Charles LNG responded by stating that the stainless steel piping will not corrode and consequently did not require inspection for atmospheric corrosion. This assumption is also documented in the Lake Charles LNG’s Technical Procedures Manual, Section 8.1 Component Identification, which shows that the Operator did not require atmospheric corrosion inspections of the stainless steel piping. The Lake Charles LNG facility has a significant quantity of aboveground insulated stainless steel piping that has not been periodically inspected for atmospheric corrosion. The insulation generally consists of a fibrous material wrapped around the circumference of the pipe covered by aluminum sheathing held onto the piping by metal straps (Exhibit B, Photos 1 – 5). This covering, while necessary to help preserve the temperature of the chilled or liquefied natural gas, makes it difficult to visually inspect the piping for atmospheric corrosion. However, insulated piping is susceptible to a specific type of atmospheric corrosion called Corrosion Under Insulation (CUI) and must be periodically inspected for corrosion just as with other aboveground piping. CUI is recognized by industry as a serious damage mechanism that results from the presence of moisture trapped under insulation and can adversely affect the integrity of piping by providing an environment conducive to corrosion, particularly environments that contain chlorides or sulfides. The location of the Lake Charles LNG facility is in an environment that includes high humidity (making it likely that condensation will form on the pipe) and potential sources of chlorides (the nearby brackish or salt water in Calcasieu Lake and the Gulf of Mexico). 3#

420173002_NOPV PCP PCO_02212017_text.pdf, page 4The justification provided by the Operator for concluding that the stainless steel piping will not corrode was primarily based on the argument that the operating temperature at the Lake Charles LNG facility is not within the range where stainless steel piping is susceptible to corrosion. The source referenced by the Operator for this conclusion was a study by the Norwegian University of Science and Technology titled “Pitting and Crevice Corrosion of Stainless Steel under Offshore Conditions”1 authored by a graduate student at the Norwegian University of Science and Technology as a Master’s thesis (see Exhibit B, Pitting and Crevice Corrosion of Stainless Steel under Offshore Conditions, Norwegian University of Science and Technology, Trondheim 2012). The Operator refers to Figure 2.5 in the document that shows the Critical Pitting Temperature (CPT) and the Crevice Corrosion Temperature (CCT) for various grades of un-welded stainless steel. Lake Charles argues that their operating temperatures range from -255 degrees F (-159 degrees C) to -50 degrees F (-46 degrees C) but the CPT and CCT for 304 Stainless Steel from Figure 2.5 are 4 degrees C and -16 degrees C, respectively, making their operating temperatures too low for corrosion to occur. When the PHMSA inspection was performed, the Lake Charles LNG facility was not operating and the piping was at atmospheric temperature, showing that the surface temperatures of the piping are not always within the range stated by the operator. The conclusions of the thesis referenced by the Operator do not support the argument that corrosion of stainless steel can be predicted solely on the basis of operating temperature. In fact, the referenced research was initiated because offshore operators were experiencing corrosion of stainless steel piping under temperatures where existing charts and graphs indicated it wouldn’t occur. The author states, “This study has shown that in order to be able to assess the possibility of pitting and crevice corrosion and probability of failure with respect to time due to pitting corrosion and coating degradation it is not enough to only consider temperature. It is shown that other parameters are probably as important as temperature.” (Wika 73). The Operator also failed to consider the stated limitations of the study. Specifically, the document states, “Only the bulk of the pipe is considered, so welds, flanges and other places where localized corrosion is likely to occur are out of scope for this study” (Wika 3). It is apparent that the Operator selected excerpts from the referenced thesis to try and support their decision to not inspect the insulated stainless steel piping, but failed to use the findings in a manner consistent with the complete results of the research. 3. §193.2707 Operations and maintenance. (a) Each operator shall utilize for operation or maintenance of components only those personnel who have demonstrated their capability to perform their assigned functions by- (1) Successful completion of the training required by §§193.2713 and 193.2717; (2) Experience related to the assigned operation or maintenance function; and, (3) Acceptable performance on a proficiency test relevant to the assigned function. 1 Wika, Sandra Finsås (2012). Pitting and Crevice Corrosion of Stainless Steel under Offshore Conditions (Master’s Thesis) Norwegian University of Science and Technology. Trondheim, 2012 4#

420173002_NOPV PCP PCO_02212017_text.pdf, page 5§193.2713 Training, operations and maintenance. (a) Each operator shall provide and implement a written plan of initial training to instruct- (1) All permanent maintenance, operating, and supervisory personnel- (i) About the characteristics and hazards of LNG and other flammable fluids used or handled at the facility, including, with regard to LNG, low temperatures, flammability of mixtures with air, odorless vapor, boiloff characteristics, and reaction to water and water spray; (ii) About the potential hazards involved in operating and maintenance activities; and, (iii) To carry out aspects of the operating and maintenance procedures under §§193.2503 and 193.2605 that relate to their assigned functions; and (2) All personnel- (i) To carry out the emergency procedures under §193.2509 that relate to their assigned functions; and (ii) To give first-aid; and, (3) All operating and appropriate supervisory personnel- (i) To understand detailed instructions on the facility operations, including controls, functions, and operating procedures; and (ii) To understand the LNG transfer procedures provided under §193.2513. (b) A written plan of continuing instruction must be conducted at intervals of not more than 2 years to keep all personnel current on the knowledge and skills they gained in the program of initial instruction. §193.2717 Training, fire protection. (a) All personnel involved in maintenance and operations of an LNG plant, including their immediate supervisors, must be trained according to a written plan of initial instruction, including plant fire drills, to: (1) Know the potential causes and areas of fire; (2) Know the types, sizes, and predictable consequences of fire; and (3) Know and be able to perform their assigned fire control duties according to the procedures established under § 193.2509 and by proper use of equipment provided under § 193.2801. (b) A written plan of continuing instruction, including plant fire drills, must be conducted at intervals of not more than 2 years to keep personnel current on the knowledge and skills they gained in the instruction under paragraph (a) of this section. (c) Plant fire drills must provide personnel hands-on experience in carrying out their duties under the fire emergency procedures required by § 193.2509. Lake Charles LNG failed meet the training requirements required by the regulations. Lake Charles LNG failed to provide records demonstrating that they had met all required initial and/or refresher training according to §193.2707 and the Operator’s procedures as required by §193.2713 and §193.2717. In addition, the Operator failed to require refresher training on detailed operations for supervisors and the required training for security personnel was not in accordance with §193.2713. 5#

420173002_NOPV PCP PCO_02212017_text.pdf, page 6Training records presented by Lake Charles LNG during the inspection did not show that personnel had completed the required training as required by §193.2707 and defined by the facility’s training matrix, Lake Charles LNG Company, Table 1.1, Master Training Matrix, Initial and Refresher Training, Revised 02/01/2010. In addition, the Operator’s records did not show that supervisors completed refresher training on detailed operations. Contract security personnel also have assigned duties as part of the facility’s emergency response but there were no records showing that security personnel received training on the Operator’s emergency procedures. 4. §193.2801 Fire Protection Each operator must provide and maintain fire protection at LNG plants according to sections 9.1 of NFPA 59A (incorporated by reference, see §193.2013). However, LNG plans existing on March 31, 2000 need not comply with provisions on emergency shutdown systems, water delivery systems, detection systems, and personnel qualification and training until September 12, 2005. §193.2605 Maintenance procedures. (a) Each operator shall determine and perform, consistent with generally accepted engineering practice, the periodic inspections or tests needed to meet the applicable requirements of this subpart and to verify that components meet the maintenance standards prescribed by this subpart. (b) Each operator shall follow one or more manuals of written procedures for the maintenance of each component, including any required corrosion control. The procedure must include: (1) The details of the inspections or tests determined under paragraph (a) of this section and their frequency of performance; and (2) A description of other actions necessary to maintain the LNG plant according to the requirements of this subpart. (c) Each operator shall include in the manual required by paragraph (b) of this section instructions enabling personnel who perform operation and maintenance activities to recognize conditions that potentially may be safety-related conditions that are subject to the reporting requirements of §191.23 of this subchapter. Lake Charles LNG failed to follow their procedures in performing and documenting verification of the annual inspection of their emergency shutdown system. The Operator has a comprehensive procedure for performing the annual inspection of their emergency shutdown system titled “ESS II Shutdown System Procedure, Annual Inspection PM #860-74.” This procedure includes sections for documenting the tests of the various components throughout the facility. Documentation of the annual inspection performed on June 17, 2015 contained many blank fields that were intended to be initialed by testing personnel to confirm proper operation and there were no notes of explanation included with the documentation. Consequently, it cannot be determined from the documentation whether the un-initialed components failed the testing, were skipped during the testing, or could not be tested based on operating circumstances at the facility. The Operator must have complete documentation according to their procedures and should include6#

420173002_NOPV PCP PCO_02212017_text.pdf, page 7explanatory notes indicating any repairs or follow-up actions needed, why components weren’t tested, and when they will be tested to comply with §193.2801 and their inspection procedures. 5. §193.2911 Security lighting. Where security warning systems are not provided for security monitoring under §193.2913, the area around the facilities listed under §193.2905(a) and each protective enclosure must be illuminated with a minimum in service lighting intensity of not less than 2.2 lux (0.2 ftc) between sunset and sunrise. The Lake Charles LNG inspection records for security lighting failed to show that the Operator was in compliance with the requirements of §193.2911. When PHMSA requested records for security inspections, Lake Charles LNG presented an inspection report performed by Project Technical Liaison Technical Associates, Inc. (PTL) dated 04/15/2005. The inspection document stated that PTL completed a review of the existing Trunkline LNG facility for compliance to the amended sections of code. The only reference to the inspection of security lighting is in the inspection section referring to NFPA 59A, 9.8.4 that states “LNG facilities shall be illuminated in the vicinity of protective enclosures and in other areas as necessary to promote security of the facility.” The comment in the PTL inspection states “Light posts on the entire perimeter fencing are provided to identify suspected intrusion.” There was nothing in the inspection record presented by Lake Charles LNG to confirm the presence of a security warning system or lighting with a minimum intensity of 2.2 lux. Proposed Civil Penalty Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $200,000 per violation per day the violation persists up to a maximum of $2,000,000 for a related series of violations. For violations occurring prior to January 4, 2012, the maximum penalty may not exceed $100,000 per violation per day, with a maximum penalty not to exceed $1,000,000 for a related series of violations Also, for LNG facilities, an additional penalty of not more than $50,000 for each violation may be imposed. The Compliance Officer has reviewed the circumstances and supporting documentation involved in the above probable violation(s) and has recommended that you be preliminarily assessed a civil penalty of $32,400 as follows for item 1. Item number PENALTY 1 $32,400 Warning Items With respect to items 4 and 5, 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 promptly correct these item(s). Failure to do so may result in additional enforcement action. 7#

420173002_NOPV PCP PCO_02212017_text.pdf, page 8Proposed Compliance Order With respect to items 1, 2, and 3 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Lake Charles LNG. 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 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 4-2017-3002 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, R. M. Seeley Director, Southwest Pipeline and Hazardous Materials Safety Administration Enclosures: Proposed Compliance Order Response Options for Pipeline Operators in Compliance Proceedings 8#

420173002_NOPV PCP PCO_02212017_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 Lake Charles LNG a Compliance Order incorporating the following remedial requirements to ensure the compliance of Lake Charles LNG with the pipeline safety regulations: 1. 2. 3. 3. 4. In regard to Item Number 1 of the Notice pertaining to Lake Charles LNG’s failure to consider IR drop when conducting an annual CP survey: Survey the facility so that IR drop is considered in the readings and remediate any areas not meeting the criterion. Implement provisions to consider IR drop in determining the adequacy of all future readings in the form of procedures and interrupted surveys or other accepted means of consideration. In regard to Item Number 2 of the Notice pertaining to Lake Charles LNG’s failure to provide procedures demonstrating that atmospheric corrosion inspections are performed on a regular basis on above ground stain less steel insulated piping: Develop procedures to inspect insulated above ground insulated stainless steel pipe for atmospheric corrosion at set intervals not to exceed every 3 years. Using the procedures, perform an atmospheric corrosion inspection of the insulated stainless steel piping. In regard to Item Number 3 of the Notice pertaining to Lake Charles LNG’s training records: Review training records for all personnel and confirm that the required initial training and refresher training has been completed according to the requirements of §193.2707, §193.2713, §193.2717, and the Operator’s training matrix. Ensure that supervisors complete refresher training on detailed operations and that contract Security personnel who have defined roles in the facility emergency response plan have received training in the emergency response plan and their roles. Develop records that clearly identify the employee’s job title, the specific training required for that employee’s job, and the dates the initial and refresher training was completed by each employee. Lake Charles LNG must demonstrate within 180 days of receipt of this order that the requirements of this Compliance Order have been completed for Item Numbers 1, 2 and 3. It is requested (not mandated) that Lake Charles LNG maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to R. M. Seeley, Director, Southwest, 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#

420173002_Final Order_12022019_text.pdf, page 1Official PDFDecember 2, 2019 Mr. Kelcy L. Warren Chief Executive Officer Energy Transfer, LP 8111 Westchester Drive Dallas, Texas 75225 Re: CPF No. 4-2017-3002 Dear Mr. Warren: Enclosed please find the Final Order issued in the above-referenced case. It withdraws one allegation of violation, makes findings of violation, assesses a civil penalty of $32,400, and specifies actions that need to be taken by your subsidiary, Lake Charles LNG Company, LLC, to comply with the pipeline safety regulations. The penalty payment terms are set forth in the Final Order. When the civil penalty has been paid and the terms of the compliance order 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: Ms. Mary McDaniel, Director, Southwest Region, Office of Pipeline Safety, PHMSA Mr. Jeff Brightwell, Vice President, LNG Operations, Lake Charles LNG Company, LLC, 8100 Big Lake Road, Lake Charles, Louisiana 70605 Ms. Catherine D. Little, Esq., Troutman Sanders, LLP, 600 Peachtree Street, NE, Suite 5200, Atlanta, Georgia 30308 CERTIFIED MAIL - RETURN RECEIPT REQUESTED#

420173002_Final Order_12022019_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 ) Lake Charles LNG Company, LLC, ) CPF No. 4-2017-3002 a subsidiary of Energy Transfer, LP, ) ) ) ) Respondent. ) ____________________________________) FINAL ORDER On September 15-16, 2015, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the facilities and records of Lake Charles LNG Company, LLC (Lake Charles LNG or Respondent), in Lake Charles, Louisiana. At the time of the inspection, the Lake Charles LNG facility encompassed a 400-acre site and consisted of four insulated liquefied natural gas (LNG) tanks, two vaporizers, and associated equipment with export facilities under development. Lake Charles LNG is a wholly-owned subsidiary of Energy Transfer, LP, which owns and operates approximately 71,000 miles of natural gas, natural gas liquids, refined petroleum, and crude oil pipelines.1 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Respondent, by letter dated February 21, 2017, a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice), which also included a warning pursuant to 49 C.F.R. § 190.205. In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that Lake Charles LNG had committed three violations of 49 C.F.R. Part 193 and proposed assessing a civil penalty of $32,400 for one of the alleged violations. The Notice also proposed ordering Respondent to take certain measures to correct the alleged violations. The Notice also included two warning items that required no further action, but warned the operator to correct the probable violations or face possible future enforcement action. Lake Charles LNG responded to the Notice by letter dated March 22, 2017 (Response). Respondent contested the allegations and requested a hearing. A hearing was subsequently held on October 3, 2017, in Houston, Texas before a PHMSA Presiding Official. At the hearing, Respondent was represented by counsel. Respondent submitted additional written materials prior to the hearing on September 22, 2017 (Pre-hearing submittal), and following the hearing on 1 Pipeline Safety Violation Report (Violation Report), (Feb. 21, 2017) (on file with PHMSA), at 1; Energy Transfer, LP website, available at https://www.energytransferlng.com/who we are html (last accessed November 12, 2019).#

420173002_Final Order_12022019_text.pdf, page 3CPF No. 4-2017-3002 Page 2 November 3, 2017 (Post-hearing submittal). The Director submitted a region recommendation on May 22, 2019 (Region recommendation), and Lake Charles LNG submitted a reply to the region recommendation on May 31, 2019 (Reply). FINDINGS OF VIOLATION The Notice alleged that Respondent violated 49 C.F.R. Part 193, as follows: Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 193.2629(a), which states: § 193.2629 External corrosion control: buried or submerged components. (a) Each buried or submerged component that is subject to external corrosive attack must be protected from external corrosion by— (1) Material that has been designed and selected to resist the corrosive environment involved; or (2) The following means: (i) An external protective coating designed and installed to prevent corrosion attack and to meet the requirements of §192.461 of this chapter; and (ii) A cathodic protection system designed to protect components in their entirety in accordance with the requirements of §192.463 of this chapter and placed in operation before October 23, 1981, or within 1 year after the component is constructed or installed, whichever is later. The Notice alleged that Respondent violated 49 C.F.R. § 193.2629(a) by failing to protect its pipeline from external corrosion by means of a cathodic protection system that met the requirements of § 192.463. Specifically, the Notice referenced Appendix D of Part 192 and alleged that Lake Charles LNG failed to consider IR drop when interpreting cathodic protection readings from its annual surveys. IR drop represents the voltage difference between the pipe-to- soil readings taken at the surface and the readings that one would actually obtain at the pipe-to- soil interface due to the resistance of the soil. In the absence of considering IR drop, an operator may erroneously conclude that the cathodic protection level meets the -850 mV criterion when it does not, resulting in a failure to provide adequate cathodic protection to the pipe.2 In its Response and at the hearing, Lake Charles LNG stated that it began its 2015 annual cathodic protection survey the day before the scheduled OPS compliance inspection began. Respondent did not argue that it was not required to consider IR drop. Rather, Respondent explained that it contracted with the firm Corrpro to install interrupters on its rectifiers during the 2015 inspection which would allow it to be able to measure IR drop. Respondent did not provide the OPS inspector with any records, documents, studies, prior surveys, or explanations for how it considered the effect of IR drop in interpreting the cathodic protection pipe-to-soil voltage measurements, nor were any such documents provided in connection with the hearing. During 2 Region recommendation, at 3.#

420173002_Final Order_12022019_text.pdf, page 4CPF No. 4-2017-3002 Page 3 the hearing, Respondent did not argue that its annual surveys conducted in years prior to 2015 accounted for IR drop. The requirement to consider IR drop on an annual basis has been in place since before the facility was commissioned in 1981. In Lake Charles LNG's case, its own records and statements establish that it had never performed an interrupted survey in the history of the facility until 2015. Accordingly, after considering all of the evidence and the legal issues presented, I find that Respondent violated 49 C.F.R. § 193.2629(a) by failing to protect its pipeline from external corrosion by means of a cathodic protection system that met the requirements of § 192.463 prior to the 2015 inspection and survey. Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 193.2635(d), which states: § 193.2635 Monitoring corrosion control. Corrosion protection provided as required by this subpart must be periodically monitored to give early recognition of ineffective corrosion protection, including the following, as applicable: (a)… (d) Each component that is protected from atmospheric corrosion must be inspected at intervals not exceeding 3 years. The Notice alleged that Respondent violated 49 C.F.R. § 193.2635(d) by failing to periodically inspect a portion of its aboveground piping to monitor for ineffective protection from atmospheric protection. Specifically, the Notice alleged that Lake Charles LNG did not inspect certain insulated piping used to transport liquefied natural gas at intervals not exceeding three years. In its Response and at the hearing, Lake Charles LNG contested the allegation, contending that the aboveground pipe used to transport LNG at its Lake Charles facility was not required to be periodically inspected for atmospheric corrosion. Respondent explained that it believed the three year inspection requirement did not apply to stainless-steel pipe and that austenitic stainless steel “contains a high percentage of nickel and chromium, and is thus extremely resistant to corrosion.”3 Respondent cited a research paper entitled "Pitting and Crevice Corrosion of Stainless Steel Under Offshore Conditions."4 This paper included a diagram in Figure 2.5 showing the temperatures that different grades of stainless steel were previously thought to be susceptible to corrosion.5 For 304 stainless steel, the critical pitting temperature ranges from 5 degrees to -20 degrees C. Respondent explained that the operating temperature of its piping during LNG operations is -46 degrees C to -159 degrees C, and argued that its piping was 3 Post-hearing submission, at 5. It is notable, however, that § 193.2635(d) does not include an express exemption from the atmospheric corrosion inspection requirement for stainless steel pipe. If the drafters of this regulation had intended to exempt stainless steel pipe from atmospheric corrosion inspections, they could have easily done so then and there but they chose not to. 4 Violation Report, Exhibit B. 5 Id., at 18-19.#

420173002_Final Order_12022019_text.pdf, page 5CPF No. 4-2017-3002 Page 4 operated outside the temperature range for corrosion to occur. OPS acknowledged that cryogenic temperatures were a factor in preventing external pipe corrosion, but pointed out that the Lake Charles facility had not operated at cryogenic temperatures since 2012, making it approximately six years since the piping has been within the temperature range that Respondent maintains would prevent corrosion. OPS went on to point out that the research paper also states: “This study has shown that in order to be able to assess the possibility of pitting and crevice corrosion and probability of failure with respect to time due to pitting corrosion and coating degradation it is not enough to only consider temperature. It is shown that other parameters are probably as important as temperature.”6 OPS then pointed to a section of the paper explaining that the other mechanisms that can cause the protective chromium oxide layer on stainless-steel piping to be compromised and lead to corrosion include: (1) chemical attack, particularly from environments containing chlorides and sulfides; (2) mechanical damage such as scratches or gouges on the surface of the pipe; and (3) heat such as that from welding. The critical factors listed include, “Design of insulation system, insulation type, temperature, environment (humidity, rainfall and chlorides from marine environment, industrial environments containing high SO2) are critical factors.”7 This leads to the issue of whether the temperature, humidity, and marine environment factors present at the site of the Lake Charles facility implicate a potentially corrosive atmospheric environment. Respondent argued that the Lake Charles facility was not subject to a corrosive atmospheric environment. Respondent submitted a report entitled “Evaluation of the Susceptibility to Corrosion of Stainless Steel LNG Pipe Under All Operating Conditions at the lake Charles Liquefied Natural Gas Facility. 8 The report stated: “The LC LNG Facility is approximately 26 miles (42 km) from the Gulf of Mexico, as shown in Figure 1.”9 The report goes on to state, “The corrosion rate of carbon steel diminishes by more than 97% when it is only 0.62 miles (1 km) from the water. Thus, the effects of seawater on LC LNG Facility Type 304 SS piping should be insignificant at 26 miles (42 km) from the Gulf of Mexico.”10 With regard to the potential for a corrosive atmospheric environment to be present, OPS stated: The Lake Charles facility is located in a hot, humid environment immediately adjacent to bodies of saltwater. The piping is covered by metallic sheathed insulation that is not water tight and can trap moisture against the surface of the pipe. The chlorides present in the salt water along with the environment could clearly create an environment that would chemically degrade the thin protective chromium oxide layer on the stainless-steel piping and result in a damage mechanism defined by API 6 Id., at 73. 7 Id., at 170-171. 8 Post-hearing submittal, Exhibit 4. 9 Post-hearing submittal, Exhibit 4, at 6. 10 Id.#

420173002_Final Order_12022019_text.pdf, page 6CPF No. 4-2017-3002 Page 5 Recommended Practice 571, "Damage Mechanisms Affecting Fixed Equipment in the Refining Industry" as Corrosion Under Insulation (CUI) (Violation Report, Ex. B, at 170-71). This industry standard clearly identifies Series 300 stainless steel piping as susceptible to this damage mechanism.11 I find that OPS was persuasive on this point. The Lake Charles facility was constructed as an LNG import terminal and is serviced by oceangoing LNG tankers traversing the ship channel from the Gulf of Mexico. Consequently, the Lake Charles facility is immediately adjacent to the Calcasieu Ship Channel, which is continuous with Calcasieu Lake, both of which are saline bodies of water in direct contact with the Gulf of Mexico. Thus, the Lake Charles LNG facility is not 26 miles from seawater, but sits immediately adjacent to a chloride rich saline bodies of water.12 In determining the applicability of the three-year atmospheric corrosion inspection requirement, the three sections in Part 193 that speak to atmospheric corrosion, §§ 193.2625, 193.2627, and 193.2635(a), must be read in a cohesive manner in order to arrive at a logical application of the inspection requirement that is consistent with the purpose and intent of the corrosion control regulations. First, § 193.2625 requires operators to determine the need for corrosion protection with regard to all metallic components which could have their integrity adversely affected by uncontrolled corrosion during their intended service life. Second, § 193.2627 requires operators to protect each component that is subject to atmospheric corrosive attack from corrosion by: (1) using a material that has been designed and selected to resist the corrosive atmosphere involved; or (2) using suitable coating or jacketing. Finally, § 193.2635(d), the cited regulation, requires that each component subject to the atmospheric corrosion protection requirements be inspected at intervals not exceeding three years. In this case, Respondent met its obligations under §§ 193.2625 and 193.2627 to determine the need for and a select a material that would resist a corrosive atmosphere when it selected stainless-steel pipe for the Lake Charles facility. Stainless steel pipe is more expensive to use than carbon-steel pipe and presumably the designers of the facility decided to incur that expense to ensure that the Lake Charles facility would have greater protection from corrosion resulting in a longer life span than would be the case if a lower cost material not as resistant to corrosion such as carbon steel had been selected. Respondent’s own submissions in this case tout its decision to use stainless steel piping to protect against atmospheric corrosion. It appears, however, that Respondent has confused its ability to determine which material it would use to use to resist the corrosive atmosphere with the applicability of the ensuing periodic inspection requirement. The three-year inspection requirement in § 193.2635(d) applies to all components subject to the atmospheric corrosion protection requirements. It does not allow an operator to determine that a three-year inspection of such components is not needed. In other 11 Region recommendation, at 10. 12 OPS noted that surface corrosion was already beginning on the metallic pipe cladding.#

420173002_Final Order_12022019_text.pdf, page 7CPF No. 4-2017-3002 Page 6 words, rather than justifying the failure to conduct periodic inspections, the fact that Respondent selected stainless-steel pipe as the protective material needed to resist the corrosive atmosphere implicated the three-year inspection requirement just as assuredly as selecting a coated material other than stainless steel as a means of resisting atmospheric corrosion would have, perhaps in a different (i.e., non-marine) location. It may turn out that Respondent’s choice of stainless steel piping will successfully resist atmospheric corrosion over the entire life span of the Lake Charles facility, but that does not negate the requirement in § 193.2635(d) to conduct an inspection every three years to confirm the absence of atmospheric corrosion. It should be emphasized that an LNG facility operator has wide latitude in developing the procedures by which its atmospheric corrosion inspections will be conducted. Nothing in this decision prohibits an operator from determining the appropriate manner of inspection for its particular facility so long as the procedures account for the presence of piping that is not visually accessible such as insulated piping. For example, operators that have insulated pipes can establish procedures for visually inspecting these pipes by removing select portions of the insulation or clamps or developing a program whereby visual inspections occur in predetermined critical inspection locations by creating inspection ports. Accordingly, after considering all of the evidence and the legal issues presented, I find that Respondent violated 49 C.F.R. § 193.2635(d) by failing to periodically inspect a portion of its aboveground piping to monitor for ineffective protection from atmospheric protection. Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 193.2707(a), which states: § 193.2707 Operations and maintenance. (a) Each operator shall utilize for operation or maintenance of components only those personnel who have demonstrated their capability to perform their assigned functions by— (1) Successful completion of the training required by §§193.2713 and 193.2717; and (2) Experience related to the assigned operation or maintenance function; and (3) Acceptable performance on a proficiency test relevant to the assigned function. The Notice alleged that Respondent violated 49 C.F.R. § 193.2707(a) by utilizing personnel for operations and maintenance who had not demonstrated their capability to perform the assigned functions. Specifically, the Notice referenced §§ 193.2713 and 193.2717 and alleged that Respondent utilized personnel who had not completed the applicable training requirements. In its Response and at the hearing, Lake Charles LNG disputed the allegation that it ever used personnel for operations and maintenance who had not completed the applicable training requirements. Respondent explained that some of its initial training records were misplaced and acknowledged that improvement in its training record retention practices was in order. Respondent further stated that it was making its initial and refresher training records for personnel and appropriate supervisory personnel available to OPS. In connection with the#

420173002_Final Order_12022019_text.pdf, page 8CPF No. 4-2017-3002 Page 7 hearing, Respondent submitted copies of these training records and stated that these records were created contemporaneously at the time the training was conducted. These records included Lake Charles Master Training Matrix, Initial and Refresher Training (Rev. Feb. 1, 2010); Lake Charles LNG Training Status (as of Sept. 14-16, 2015); and Lake Charles LNG Refresher Training Records (as of Sept. 15, 2015).13 For its part, OPS pointed out that Respondent is required to “maintain” training records and emphasized that Lake Charles LNG did not produce these training records at the time of the inspection. OPS maintained that Respondent should be found in violation as alleged in the Notice due to this failure to produce the training records at the time of the inspection. OPS is correct that a LNG facility operator is required to maintain records of satisfactory completion of the applicable facility training requirements and produce them upon request during an OPS inspection. These records must be maintained while personnel are performing duties such as operations and maintenance, security, and fire protection, and maintained for an additional one-year period after they are no longer assigned such duties. This requirement is found in § 193.2719. Respondent’s failure to maintain and produce these records at the time of the inspection suggests that it likely ran afoul of this requirement. In its Notice, however, OPS did not cite § 193.2719 for a failure of Respondent to maintain records. Instead the Notice cited Lake Charles LNG for an alleged violation of § 193.2707(a) which would equate to an alleged failure to actually conduct the training. Respondent subsequently located the relevant records showing that it did conduct the training and provided these records in connection with the hearing. Thus, Respondent was able to refute the allegation of violating the particular code section that was charged in the Notice. Accordingly, after considering all of the evidence and the legal issues presented, I find that a violation of 49 C.F.R. § 193.2707(a) has not been proven. Based upon the foregoing, I hereby order that Item 3 be withdrawn. 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 related series of violations.14 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; 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 13 Post-hearing submission Exhibits 9, 10, and 11. 14 These amounts are adjusted annually for inflation. See 49 C.F.R. § 190.223.#

420173002_Final Order_12022019_text.pdf, page 9CPF No. 4-2017-3002 Page 8 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 $32,400 for the first violation cited above. Item 1: The Notice proposed a civil penalty of $32,400 for Respondent’s violation of 49 C.F.R. § 193.2629(a), for failing to failing to protect its pipeline from external corrosion by means of a cathodic protection system that met the requirements of § 192.463. With respect to the nature and circumstances of the violation, ensuring that cathodic protection readings are accurate and account for IR drop is a basic code requirement. Respondent argued that the penalty should be eliminated because it believed this was a “records only” violation in that it was taking steps to account for IR drop during the 2015 OPS inspection.15 With respect to the gravity of the violation, preventing corrosion is a serious safety matter. Respondent argued that there was no impact on pipeline safety or integrity because the annual survey was being conducted during the PHMSA inspection. With respect to culpability, Respondent should have known from a plain reading of the code that IR drop had to be considered, but again argued that Respondent took significant steps to comply. Similarly, Respondent argued that it made a good faith effort to comply by arranging for the interrupted testing to be conducted concurrently with the OPS inspection.16 All of these arguments, however, are premised on the incorrect notion that the OPS allegation was limited to the 2015 annual survey. The violation, however, was for failure to account for IR drop for many years up until the 2015 OPS inspection. Respondent presented no arguments that would warrant a reduction in the civil penalty amount proposed in the Notice for this violation. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $32,400 for violation of 49 C.F.R. § 193.2629(a).17 Payment of the civil penalty must be made within 20 days of service. Federal regulations (49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed instructions are contained in the enclosure. Questions concerning wire transfers should be directed to: Financial Operations Division (AMK-325), Federal Aviation Administration, Mike Monroney Aeronautical Center, 6500 S MacArthur Blvd, Oklahoma City, Oklahoma 79169. The Financial Operations Division telephone number is (405) 954-8845. Failure to pay the $32,400 civil penalty will result in accrual of interest at the current annual rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to 15 Post-hearing submission, at 4. 16 Id. 17 In its Reply to the region recommendation, Respondent argued that the region recommendation contained new information and pointed out that it was not submitted by the Director until over a year after the hearing. Having considered these arguments, I find that the region recommendation did not raise new evidence that Respondent did not have the opportunity to contest (and in any event, it is not binding in any way). With respect to the timing, 49 C.F.R. § 190.209((b)(7) does not set a deadline for submission of the region recommendation by the Director and I do not find that this delay impacted Respondent’s ability to contest the case.#

420173002_Final Order_12022019_text.pdf, page 10CPF No. 4-2017-3002 Page 9 those same authorities, a late penalty charge of six percent (6%) per annum will be charged if payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty may result in referral of the matter to the Attorney General for appropriate action in a district court of the United States. COMPLIANCE ORDER The Notice proposed a compliance order with respect to Items 1, 2, and 3 in the Notice for violations of 49 C.F.R. §§ 193.2629(a), 193.2635(d), and 193.2707(a), respectively. Under 49 U.S.C. § 60118(a), each person who engages in the transportation of gas or who owns or operates a pipeline facility is required to comply with the applicable safety standards established under chapter 601. As discussed above, Item 3 has been withdrawn. Therefore, no compliance terms for that Item are included. 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 § 193.2629(a) (Item 1), Respondent must survey its pipeline facilities so that IR drop is considered in the readings and remediate any areas not meeting the applicable criterion. Respondent must implement measures to consider IR drop in determining the adequacy of all future cathodic protection readings in the form of developing and following procedures for interrupted surveys or other accepted means of IR drop consideration. 2. With respect to the violation of § 193.2635(d) (Item 2), Respondent must develop procedures for inspecting above ground insulated stainless steel pipe for atmospheric corrosion at set intervals not to exceed every 3 years. Using the procedures, Respondent must perform an atmospheric corrosion inspection of the insulated stainless steel piping. 3. Respondent must submit documentation to the Director within 180 days of receipt of this Compliance Order showing that Items 1 and 2 of this order have been completed. 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. It is requested (not mandated) that Respondent 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.#

420173002_Final Order_12022019_text.pdf, page 11CPF No. 4-2017-3002 Page 10 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. WARNING ITEMS With respect to Items 4 and 5, the Notice alleged probable violations of Part 193 but did not propose a civil penalty or compliance order for these items. Therefore, these are considered to be warning items. The warnings were for: 49 C.F.R. § 193.2801 (Item 4) ─ Respondent’s alleged failure to ensure that all aspects of an annual inspection of the emergency shutdown system in 2015 were carried out in accordance with § 193.2605 procedures; and 49 C.F.R. § 193.2911 (Item 5) ─ Respondent’s alleged failure to ensure that its LNG facility security lighting met the applicable illumination intensity standard of 2.2 lux. Lake Charles LNG presented information in its Response showing that it had taken certain actions to address the cited items. If OPS finds a violation of any of these items in a subsequent inspection, Respondent may be subject to future enforcement action. 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. December 2, 2019 ___________________________________ __________________________ Alan K. Mayberry Date Issued Associate Administrator for Pipeline Safety#

420173002_Decision on Petition for Reconsideration_04272020_text.pdf, page 1Official PDFApril 27, 2020 VIA ELECTRONIC MAIL TO: kelcy.warren@energytransfer.com Mr. Kelcy L. Warren President and Chief Executive Officer Energy Transfer, LP 8111 Westchester Drive Dallas, Texas 75225 Re: CPF No. 4-2017-3002 Dear Mr. Warren: Enclosed please find the Decision on the Petition for Reconsideration issued in the above- referenced case to your subsidiary, Lake Charles LNG Company, LLC. It grants the relief sought in your Petition and withdraws the finding of violation in Item 2 of the December 2, 2019 Final Order issued in this case. When the terms of the Compliance Order issued with respect to Item 1 of the Final Order are completed, as determined by the Director, Southwest Region, this enforcement action will be closed. Service of the Decision on Reconsideration by electronic mail is effective upon the date of transmission, 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: Ms. Mary McDaniel, Director, Southwest Region, Office of Pipeline Safety, PHMSA Mr. Jeff Brightwell, Vice President - LNG Operations, Lake Charles LNG Company, LLC, jeffrey.brightwell@energytransfer.com Ms. Catherine D. Little, Esq., Troutman Sanders, LLP, catherine.little@troutman.com CONFIRMATION OF RECEIPT REQUESTED#

420173002_Decision on Petition for Reconsideration_04272020_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 ) Lake Charles LNG Company, LLC, ) CPF No. 4-2017-3002 a subsidiary of Energy Transfer, LP, ) ) ) ) Respondent. ) ____________________________________) DECISION ON PETITION FOR RECONSIDERATION In a December 2, 2019 Final Order, the Pipeline and Hazardous Materials Safety Administration (PHMSA) determined that Lake Charles LNG Company, LLC (Lake Charles LNG or Petitioner) committed two violations of 49 C.F.R. Part 193 following an inspection by the Office of Pipeline Safety (OPS) of a liquefied natural gas (LNG) facility operated by Petitioner.1 PHMSA assessed a civil penalty of $32,400 for one of the violations and ordered Lake Charles LNG to undertake certain measures to correct the violations. PHMSA also withdrew an allegation that Petitioner had committed a third violation.2 On December 23, 2019, Lake Charles LNG submitted a Petition for Reconsideration of the Final Order (Petition). The Petition requested that PHMSA reconsider its finding in Item 2 of the Final Order that Petitioner had violated 49 C.F.R. § 193.2635(d) by failing to inspect certain piping at its Lake Charles facility to ensure protection from atmospheric corrosion was being achieved. Given the particular circumstances of this case, I have determined that OPS should have used means other than an enforcement action alleging a code violation to notify Petitioner how the regulations apply to 300 Series stainless steel piping. Accordingly, I am granting the relief sought in the Petition. Background On September 15-16, 2015, pursuant to 49 U.S.C. § 60117, a representative of OPS conducted an on-site pipeline safety inspection of Petitioner’s facilities and records in Lake Charles, Louisiana. As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Petitioner, by letter dated February 21, 2017, a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice). The Notice proposed finding that Lake 1 Lake Charles LNG Company, LLC, Final Order, CPF No. 4-2017-3002 (Dec. 2, 2019) (Final Order). 2 Id.#

420173002_Decision on Petition for Reconsideration_04272020_text.pdf, page 3CPF No. 4-2017-3002 Page 2 Charles LNG had committed three violations of 49 C.F.R. Part 193 and proposed assessing a civil penalty of $32,400 for one of the alleged violations. The Notice also proposed ordering Lake Charles LNG to take certain measures to correct the alleged violations. Lake Charles LNG contested the allegations in the Notice and requested a hearing which was held in Houston, Texas before a Presiding Official from the Office of Chief Counsel. Following the hearing, on December 2, 2019, PHMSA issued a Final Order that, with respect to Notice Item 2, found that Petitioner violated 49 C.F.R. § 193.2635(d) by failing to periodically inspect a portion of the aboveground piping at its Lake Charles facility to ensure the piping is adequately protected from atmospheric corrosion.3 Specifically, I found that Petitioner’s selection and use of stainless steel as the material to resist corrosion did not exempt it from the cited regulation that required atmospheric corrosion inspections every three years.4 On December 23, 2019, Lake Charles LNG filed a Petition requesting that PHMSA reconsider its finding in Item 2 of the Final Order that Petitioner violated 49 C.F.R. § 193.2635(d). Standard of Review Under 49 C.F.R. § 190.243, a respondent is afforded the right to petition the Associate Administrator for reconsideration of a final order. However, that right is not an appeal or an opportunity to seek a de novo review of the record.5 It is a venue for presenting the Associate Administrator with information that was not previously available or requesting that any errors in the final order be corrected. Requests for consideration of additional facts or arguments must be supported by a statement of reasons as to why those facts or arguments were not presented prior to the issuance of the final order. Repetitious information or arguments will not be considered. Analysis The Final Order determined that while the regulations allow an operator to determine which material it would use to resist and protect against atmospheric corrosion, I found that the ensuing three-year inspection requirement in § 193.2635(d) applied to all pipe and components subject to the atmospheric corrosion protection requirements, including 300 Series stainless steel pipe chosen by Petitioner.6 In making this determination, I found that the three sections in Part 193 that speak to atmospheric corrosion, §§ 193.2625, 193.2627, and 193.2635(a), needed to be read in a cohesive manner that remains consistent with the purpose and intent of the corrosion control regulations. I also emphasized that an LNG facility operator has wide latitude in developing the procedures by which its atmospheric corrosion inspections will be conducted. Nothing in the Final Order prohibited Petitioner from determining the appropriate manner of inspection for its particular 3 Final Order, at 3-6. The Final Order also found that Petitioner violated 49 C.F.R. § 193.2629(a) and assessed a $32,400 civil penalty for this violation which has been paid. 4 Final Order, at 6. 5 49 C.F.R. § 190.243(a)-(d). 6 Final Order, at 5-6.#

420173002_Decision on Petition for Reconsideration_04272020_text.pdf, page 4CPF No. 4-2017-3002 Page 3 facility so long as the procedures account for the presence of piping that is not visually accessible, such as insulated piping. For example, operators that have insulated pipes can establish procedures for visually inspecting these pipes by removing select portions of the insulation or clamps; developing a program whereby visual inspections occur in predetermined critical inspection locations by creating inspection ports; or supplementing the visual inspections with non-destructive methods such as radiographic or ultrasonic testing.7 Lake Charles LNG argues in its Petition and throughout this proceeding that it did not believe it was possible that the aboveground piping at its Lake Charles facility could experience any external corrosion because it was composed of stainless steel, not carbon steel. Petitioner asserts that under the code language, it was free to decide for itself whether or not to conduct three-year atmospheric corrosion inspections.8 The arguments made in the Petition in this area, however, are largely repetitious. The type of stainless steel used by Petitioner at its Lake Charles facility is Type 304 stainless steel. This austenitic chromium-nickel alloy is the most common grade of the 300 Series stainless steel generally used for piping. As more fully explained in the Final Order, OPS disagreed with Petitioner, citing widely accepted industry practices on the subject of Corrosion Under Insulation (CUI), including section 4.3.3.2 of API Recommended Practice 571 (April 2011) (API RP 571), which establishes that 300 Series stainless steel was not immune from corrosion.9 OPS noted that this would particularly be true where the operating temperatures fall outside of cryogenic temperatures for certain periods of time, as was documented to have occurred at the Lake Charles facility located in the vicinity of the Gulf of Mexico. There is no dispute that carbon steel and stainless steel have different risk profiles. Stainless steel has a much greater resistance to corrosion than carbon steel. An operator’s selection of stainless steel as a corrosion resistant pipe material is certainly a significant factor that would appropriately influence the development of procedures for the type and extent of atmospheric corrosion inspections that are needed for a given facility or set of operating conditions.10 Nevertheless, I am not persuaded that the Final Order was erroneous in concluding that OPS met its burden of establishing that the 300 Series stainless steel material selected by Petitioner to protect against corrosion at its Lake Charles facility, while corrosion resistant, was at least potentially susceptible to CUI. In its Petition, Lake Charles LNG also objected to the Final Order on the grounds that this case was the first instance in which OPS had ever cited an LNG facility operator having stainless steel 7 Final Order, at 6. 8 Petition, at 4. 9 API Recommended Practice 571 (April 2011) (API RP 571), Section 4.3.3.5(b)-(f). This publication is not incorporated by reference in Part 193 and not subject to enforcement, but is referenced here as indicative of industry consensus standards. 10 While relatively minimal inspections of stainless steel pipe may be justified under the circumstances, in this case Respondent did not provide any indication that even minimal atmospheric corrosion inspections of any kind were conducted.#

420173002_Decision on Petition for Reconsideration_04272020_text.pdf, page 5CPF No. 4-2017-3002 Page 4 pipe for failure to conduct a three-year atmospheric corrosion inspection on that pipe.11 Petitioner pointed out that OPS had never issued authoritative guidance notifying operators that the atmospheric corrosion inspection requirement applied to stainless steel piping just as it did to carbon steel piping. Petitioner argued that the use of an enforcement action by OPS to do so for the first time was a new interpretation that amounted to an unfair surprise. Having considered these arguments, I agree that in this instance, given the risk profile variance with stainless steel as compared to conventional carbon steels, OPS could have used means other than an enforcement action alleging a code violation to notify Petitioner regarding how the regulations apply to 300 Series stainless steel piping, such as the use of a Notice of Amendment or Warning Letter, or alternatively, through the issuance of guidance to the industry at large.12 Accordingly, I find that the relief sought by Petitioner is appropriate in this case. It should be emphasized that this determination is based on the particular circumstances of this case and should not be construed to broadly prohibit OPS from pursuing enforcement actions in other instances in which there is no prior history of enforcement in a given application of a regulation, particularly where public safety concerns indicate a need for enforcement. RELIEF GRANTED Based on the information provided in the Petition, a review of the record, and for the reasons stated above, the relief sought in the Petition is granted and the finding of violation in Item 2 of the December 2, 2019 Final Order is withdrawn. The Request to Stay Item 2 of the Compliance Order is dismissed as moot. This Decision is the final administrative action in this proceeding. April 27, 2020 _____________________________ __________________________ Alan K. Mayberry Date Issued Associate Administrator for Pipeline Safety 11 Petition, at 9. 12 For example, OPS could incorporate API RP 571, Section 4.3.3 into Part 193.#