{"operation":"document","citation":"CPF 420173002","title":"LAKE CHARLES LNG COMPANY, LLC — Notice of Probable Violation","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2017-02-21","effective_on":null,"summary":"CLOSED notice of probable violation citing 192.463(a), 193.2605, 193.2629(a)(2)(ii), 193.2635(d), 193.2707(a), 193.2713, 193.2717, 193.2801, 193.2911.","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-420173002.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-420173002.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-420173002","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/420173002","body":"Notice of Probable Violation involving LAKE CHARLES LNG COMPANY, LLC. PHMSA's enforcement data identifies the cited regulations as 192.463(a),  193.2605,  193.2629(a)(2)(ii),  193.2635(d),  193.2707(a),  193.2713,  193.2717,  193.2801,  193.2911. The case was opened on 2017-02-21 and is reported as closed as of 2020-11-09. Proposed civil penalty: $32,400. Assessed civil penalty: $32,400. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n420173002_Closure Letter_11092020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Closure%20Letter_11092020.pdf\n\n420173002_Closure Letter_11092020_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Closure%20Letter_11092020_text.pdf\n\n420173002_Decision on Petition for Reconsideration_04272020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Decision%20on%20Petition%20for%20Reconsideration_04272020.pdf\n\n420173002_Decision on Petition for Reconsideration_04272020_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Decision%20on%20Petition%20for%20Reconsideration_04272020_text.pdf\n\n420173002_Final Order_12022019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Final%20Order_12022019.pdf\n\n420173002_Final Order_12022019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Final%20Order_12022019_text.pdf\n\n420173002_NOPV PCP PCO_02212017.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_NOPV%20PCP%20PCO_02212017.pdf\n\n420173002_NOPV PCP PCO_02212017_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_NOPV%20PCP%20PCO_02212017_text.pdf\n\n420173002_Operator Petition for Reconsideration and Request for Stay_12232019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Operator%20Petition%20for%20Reconsideration%20and%20Request%20for%20Stay_12232019.pdf\n\n420173002_Operator Pre-Hearing Submittal_09222017.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Operator%20Pre-Hearing%20Submittal_09222017.pdf\n\n420173002_Operator Response to Notice and Request for Hearing_03222017.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Operator%20Response%20to%20Notice%20and%20Request%20for%20Hearing_03222017.pdf\n\n420173002_Operator_Post-Hearing_Brief_11032017.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420173002/420173002_Operator_Post-Hearing_Brief_11032017.pdf\n\n420173002_Closure Letter_11092020_text.pdf\n\nVia ELECTRONIC MAIL\nNovember 9, 2020\nMatthew Ramsey\nChief Operating Officer\nEnergy Transfer Partners, LP\n8111 Westchester Drive\nDallas, Texas 75225\nCPF 4-2017-3002\nDear Mr. Warren:\nOn March 7, 2018, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued\nto Lake Charles LNG Company, LLC a Final Order in the above-referenced case. This Final Order\nincluded a Compliance Order that required the respondent to complete all items and to submit\ndocumentation to the Southwest Region Director demonstrating the completion within 180 days\nof receiving the Final Order and a civil penalty.\nOn June 1, 2020, Lake Charles LNG provided documentation addressing completion of all items\nreferenced in the Compliance Order. Based on our review of the information provided, it has been\ndetermined that you have complied with the terms the Compliance Order and made payment of\nthe penalty, therefore, this case is now considered closed.\nThank you for your cooperation in this matter.\nSincerely,\nMary L. McDaniel, P.E.\nDirector, Southwest Region\nPipeline and Hazardous Materials Safety Administration\ncc: Todd Nardozzi, Director Regulatory Compliance, Energy Transfer\n\n420173002_NOPV PCP PCO_02212017_text.pdf\n\nNOTICE OF PROBABLE VIOLATION\nPROPOSED CIVIL PENALTY\nand\nPROPOSED COMPLIANCE ORDER\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nFebruary 21, 2017\nMr. Dennis Odum\nVP, Operations of the South and LNG Divisions\nLake Charles LNG Company, LLC\n800 E. Sonterra Blvd\nSan Antonio, TX 78258\nCPF 4-2017-3002\nDear Mr. Odum:\nOn September 15 - 16, 2015, a representative of the Pipeline and Hazardous Materials Safety\nAdministration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49 United\nStates Code inspected your records and procedures in Lake Charles, Louisiana.\nAs a result of the inspection, it appears that you have committed probable violations of the Pipeline\nSafety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable\nviolation(s) are:\n1. §193.2629 External corrosion control, buried or submerged components\n(a) Each buried or submerged component that is subject to external corrosive attack\nmust be protected from external corrosion by:\n\n\n\n(2) The following means:\n(ii) A cathodic protection system designed to protect components in their entirety in\naccordance with the requirements of §192.463 of this chapter and placed in operation\nbefore October 23, 1981, or within 1 year after the component is constructed or installed\nwhichever is later.\n§192.463 External corrosion control: Cathodic protection.\n(a) Each cathodic protection system required by this subpart must provide a level of\ncathodic protection that complies with one or more of the applicable criteria\ncontained in Appendix D of this part. If none of these criteria is applicable, the\ncathodic protection system must provide a level of cathodic protection at least equal\nto that provided by compliance with one or more of these criteria.\nAppendix D - Criteria for Cathodic Protection and Determination of Measurements\nI. Criteria for cathodic protection\n(1) A negative (cathodic) voltage of at least 0.85 volt, with reference to a saturated\ncopper-copper sulfate half cell. Determination of this voltage must be made with the\nprotective current applied, and in accordance with sections II and IV of this appendix.\nII. Interpretation of voltage measurement.\nVoltage (IR) drops other than those across the structure electrolyte boundary must be\nconsidered for valid interpretation of the voltage measurement in paragraphs A(1) and\n(2) and paragraph B(1) of section I of the appendix.\nLake Charles LNG failed to consider IR drop when interpreting cathodic protection readings from\ntheir annual survey to determine if the cathodic protection was adequate as required by §193.2629\nand §192.463, Appendix D. During the inspection, the Operator stated that they were using the -\n0.85 volt criterion with current applied. This criterion requires that voltage (IR) drops other than\nthose across the structure to electrolyte boundary be considered for valid interpretation of the\nvoltage measurements. PHMSA requested information on how the Operator had considered IR\ndrops in determining the adequacy of the readings, but the operator was unable to explain or\nprovide additional information in the form of surveys, studies, or measurements to show how this\nrequirement had been satisfied.\n2\n\n\n\nThe -0.85 volt criterion at a minimum requires this potential at the pipe-to-soil interface. Readings\ntaken on the surface of the ground above the pipe incorporate a voltage drop that if not considered,\ncould result in the required cathodic protection potential at the pipe-to-soil interface being\ninadequate. Lake Charles LNG’s records show only structure to soil readings with the cathodic\nprotection current applied and the Operator did not account for the voltage (IR) drops in the\ncathodic protection circuit, particularly IR drop in the soil between the point of measurement on\nthe surface of the ground and the pipe.\n2. §193.2635 Monitoring corrosion control\nCorrosion protection provided as required by this subpart must be periodically\nmonitored to give early recognition of ineffective corrosion protection including the\nfollowing, as applicable:\n(d) Each component that is protected from atmospheric corrosion must be inspected at\nintervals not exceeding 3 years.\nLake Charles LNG failed to periodically inspect a portion of their aboveground piping to monitor\nfor ineffective corrosion protection from atmospheric corrosion as required by §193.2635. During\nthe PHMSA inspection, the Operator was asked to provide atmospheric corrosion inspection\nrecords for their aboveground piping, specifically the insulated stainless steel piping used to\ntransport chilled or liquefied natural gas within the facility. Lake Charles LNG responded by\nstating that the stainless steel piping will not corrode and consequently did not require inspection\nfor atmospheric corrosion. This assumption is also documented in the Lake Charles LNG’s\nTechnical Procedures Manual, Section 8.1 Component Identification, which shows that the\nOperator did not require atmospheric corrosion inspections of the stainless steel piping.\nThe Lake Charles LNG facility has a significant quantity of aboveground insulated stainless steel\npiping that has not been periodically inspected for atmospheric corrosion. The insulation generally\nconsists of a fibrous material wrapped around the circumference of the pipe covered by aluminum\nsheathing held onto the piping by metal straps (Exhibit B, Photos 1 – 5). This covering, while\nnecessary to help preserve the temperature of the chilled or liquefied natural gas, makes it difficult\nto visually inspect the piping for atmospheric corrosion. However, insulated piping is susceptible\nto a specific type of atmospheric corrosion called Corrosion Under Insulation (CUI) and must be\nperiodically inspected for corrosion just as with other aboveground piping. CUI is recognized by\nindustry as a serious damage mechanism that results from the presence of moisture trapped under\ninsulation and can adversely affect the integrity of piping by providing an environment conducive\nto corrosion, particularly environments that contain chlorides or sulfides. The location of the Lake\nCharles LNG facility is in an environment that includes high humidity (making it likely that\ncondensation will form on the pipe) and potential sources of chlorides (the nearby brackish or salt\nwater in Calcasieu Lake and the Gulf of Mexico).\n3\n\n\n\nThe justification provided by the Operator for concluding that the stainless steel piping will not\ncorrode was primarily based on the argument that the operating temperature at the Lake Charles\nLNG facility is not within the range where stainless steel piping is susceptible to corrosion. The\nsource referenced by the Operator for this conclusion was a study by the Norwegian University of\nScience and Technology titled “Pitting and Crevice Corrosion of Stainless Steel under Offshore\nConditions”1 authored by a graduate student at the Norwegian University of Science and\nTechnology as a Master’s thesis (see Exhibit B, Pitting and Crevice Corrosion of Stainless Steel\nunder Offshore Conditions, Norwegian University of Science and Technology, Trondheim 2012).\nThe Operator refers to Figure 2.5 in the document that shows the Critical Pitting Temperature\n(CPT) and the Crevice Corrosion Temperature (CCT) for various grades of un-welded stainless\nsteel. Lake Charles argues that their operating temperatures range from -255 degrees F (-159\ndegrees C) to -50 degrees F (-46 degrees C) but the CPT and CCT for 304 Stainless Steel from\nFigure 2.5 are 4 degrees C and -16 degrees C, respectively, making their operating temperatures\ntoo low for corrosion to occur. When the PHMSA inspection was performed, the Lake Charles\nLNG facility was not operating and the piping was at atmospheric\ntemperature, showing that the surface temperatures of the piping are not always within the range\nstated by the operator.\nThe conclusions of the thesis referenced by the Operator do not support the argument that corrosion\nof stainless steel can be predicted solely on the basis of operating temperature. In fact, the\nreferenced research was initiated because offshore operators were experiencing corrosion of\nstainless steel piping under temperatures where existing charts and graphs indicated it wouldn’t\noccur. The author states, “This study has shown that in order to be able to assess the possibility of\npitting and crevice corrosion and probability of failure with respect to time due to pitting corrosion\nand coating degradation it is not enough to only consider temperature. It is shown that other\nparameters are probably as important as temperature.” (Wika 73). The Operator also failed to\nconsider the stated limitations of the study. Specifically, the document states, “Only the bulk of\nthe pipe is considered, so welds, flanges and other places where localized corrosion is likely to\noccur are out of scope for this study” (Wika 3). It is apparent that the Operator selected excerpts\nfrom the referenced thesis to try and support their decision to not inspect the insulated stainless\nsteel piping, but failed to use the findings in a manner consistent with the complete results of the\nresearch.\n3. §193.2707 Operations and maintenance.\n(a) Each operator shall utilize for operation or maintenance of components only those\npersonnel who have demonstrated their capability to perform their assigned functions\nby-\n(1) Successful completion of the training required by §§193.2713 and 193.2717;\n(2) Experience related to the assigned operation or maintenance function; and,\n(3) Acceptable performance on a proficiency test relevant to the assigned function.\n1 Wika, Sandra Finsås (2012). Pitting and Crevice Corrosion of Stainless Steel under Offshore Conditions (Master’s Thesis) Norwegian University of Science and Technology.\nTrondheim, 2012\n4\n\n\n\n§193.2713 Training, operations and maintenance.\n(a) Each operator shall provide and implement a written plan of initial training to\ninstruct-\n(1) All permanent maintenance, operating, and supervisory personnel-\n(i) About the characteristics and hazards of LNG and other flammable fluids used or\nhandled at the facility, including, with regard to LNG, low temperatures, flammability\nof mixtures with air, odorless vapor, boiloff characteristics, and reaction to water and\nwater spray;\n(ii) About the potential hazards involved in operating and maintenance activities; and,\n(iii) To carry out aspects of the operating and maintenance procedures under\n§§193.2503 and 193.2605 that relate to their assigned functions; and\n(2) All personnel-\n(i) To carry out the emergency procedures under §193.2509 that relate to their assigned\nfunctions; and\n(ii) To give first-aid; and,\n(3) All operating and appropriate supervisory personnel-\n(i) To understand detailed instructions on the facility operations, including controls,\nfunctions, and operating procedures; and\n(ii) To understand the LNG transfer procedures provided under §193.2513.\n(b) A written plan of continuing instruction must be conducted at intervals of not more\nthan 2 years to keep all personnel current on the knowledge and skills they gained in the\nprogram of initial instruction.\n§193.2717 Training, fire protection.\n(a) All personnel involved in maintenance and operations of an LNG plant, including\ntheir immediate supervisors, must be trained according to a written plan of initial\ninstruction, including plant fire drills, to:\n(1) Know the potential causes and areas of fire;\n(2) Know the types, sizes, and predictable consequences of fire; and\n(3) Know and be able to perform their assigned fire control duties according to the\nprocedures established under § 193.2509 and by proper use of equipment provided\nunder § 193.2801.\n(b) A written plan of continuing instruction, including plant fire drills, must be\nconducted at intervals of not more than 2 years to keep personnel current on the\nknowledge and skills they gained in the instruction under paragraph (a) of this section.\n(c) Plant fire drills must provide personnel hands-on experience in carrying out their\nduties under the fire emergency procedures required by § 193.2509.\nLake Charles LNG failed meet the training requirements required by the regulations. Lake Charles\nLNG failed to provide records demonstrating that they had met all required initial and/or refresher\ntraining according to §193.2707 and the Operator’s procedures as required by §193.2713 and\n§193.2717. In addition, the Operator failed to require refresher training on detailed operations for\nsupervisors and the required training for security personnel was not in accordance with §193.2713.\n5\n\n\n\nTraining records presented by Lake Charles LNG during the inspection did not show that personnel\nhad completed the required training as required by §193.2707 and defined by the facility’s training\nmatrix, Lake Charles LNG Company, Table 1.1, Master Training Matrix, Initial and Refresher\nTraining, Revised 02/01/2010. In addition, the Operator’s records did not show that supervisors\ncompleted refresher training on detailed operations. Contract security personnel also have\nassigned duties as part of the facility’s emergency response but there were no records showing that\nsecurity personnel received training on the Operator’s emergency procedures.\n4. §193.2801 Fire Protection\nEach operator must provide and maintain fire protection at LNG plants according to\nsections 9.1 of NFPA 59A (incorporated by reference, see §193.2013). However, LNG\nplans existing on March 31, 2000 need not comply with provisions on emergency\nshutdown systems, water delivery systems, detection systems, and personnel\nqualification and training until September 12, 2005.\n§193.2605 Maintenance procedures.\n(a) Each operator shall determine and perform, consistent with generally accepted\nengineering practice, the periodic inspections or tests needed to meet the applicable\nrequirements of this subpart and to verify that components meet the maintenance\nstandards prescribed by this subpart.\n(b) Each operator shall follow one or more manuals of written procedures for the\nmaintenance of each component, including any required corrosion control. The\nprocedure must include:\n(1) The details of the inspections or tests determined under paragraph (a) of this section\nand their frequency of performance; and\n(2) A description of other actions necessary to maintain the LNG plant according to the\nrequirements of this subpart.\n(c) Each operator shall include in the manual required by paragraph (b) of this section\ninstructions enabling personnel who perform operation and maintenance activities to\nrecognize conditions that potentially may be safety-related conditions that are subject to\nthe reporting requirements of §191.23 of this subchapter.\nLake Charles LNG failed to follow their procedures in performing and documenting verification\nof the annual inspection of their emergency shutdown system. The Operator has a comprehensive\nprocedure for performing the annual inspection of their emergency shutdown system titled “ESS\nII Shutdown System Procedure, Annual Inspection PM #860-74.” This procedure includes\nsections for documenting the tests of the various components throughout the facility.\nDocumentation of the annual inspection performed on June 17, 2015 contained many blank fields\nthat were intended to be initialed by testing personnel to confirm proper operation and there were\nno notes of explanation included with the documentation. Consequently, it cannot be determined\nfrom the documentation whether the un-initialed components failed the testing, were skipped\nduring the testing, or could not be tested based on operating circumstances at the facility. The\nOperator must have complete documentation according to their procedures and should include6\n\n\n\nexplanatory notes indicating any repairs or follow-up actions needed, why components weren’t\ntested, and when they will be tested to comply with §193.2801 and their inspection procedures.\n5. §193.2911 Security lighting.\nWhere security warning systems are not provided for security monitoring under\n§193.2913, the area around the facilities listed under §193.2905(a) and each protective\nenclosure must be illuminated with a minimum in service lighting intensity of not less\nthan 2.2 lux (0.2 ftc) between sunset and sunrise.\nThe Lake Charles LNG inspection records for security lighting failed to show that the\nOperator was in compliance with the requirements of §193.2911. When PHMSA requested\nrecords for security inspections, Lake Charles LNG presented an inspection report performed\nby Project Technical Liaison Technical Associates, Inc. (PTL) dated 04/15/2005. The\ninspection document stated that PTL completed a review of the existing Trunkline LNG\nfacility for compliance to the amended sections of code. The only reference to the inspection\nof security lighting is in the inspection section referring to NFPA 59A, 9.8.4 that states “LNG\nfacilities shall be illuminated in the vicinity of protective enclosures and in other areas as\nnecessary to promote security of the facility.” The comment in the PTL inspection states\n“Light posts on the entire perimeter fencing are provided to identify suspected intrusion.”\nThere was nothing in the inspection record presented by Lake Charles LNG to confirm the\npresence of a security warning system or lighting with a minimum intensity of 2.2 lux.\nProposed Civil Penalty\nUnder 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $200,000\nper violation per day the violation persists up to a maximum of $2,000,000 for a related series of\nviolations. For violations occurring prior to January 4, 2012, the maximum penalty may not exceed\n$100,000 per violation per day, with a maximum penalty not to exceed $1,000,000 for a related\nseries of violations Also, for LNG facilities, an additional penalty of not more than $50,000 for\neach violation may be imposed. The Compliance Officer has reviewed the circumstances and\nsupporting documentation involved in the above probable violation(s) and has recommended that\nyou be preliminarily assessed a civil penalty of $32,400 as follows for item 1.\nItem number PENALTY\n1 $32,400\nWarning Items\nWith respect to items 4 and 5, we have reviewed the circumstances and supporting documents\ninvolved in this case and have decided not to conduct additional enforcement action or penalty\nassessment proceedings at this time. We advise you to promptly correct these item(s). Failure to\ndo so may result in additional enforcement action.\n7\n\n\n\nProposed Compliance Order\nWith respect to items 1, 2, and 3 pursuant to 49 United States Code § 60118, the Pipeline and\nHazardous Materials Safety Administration proposes to issue a Compliance Order to Lake Charles\nLNG. Please refer to the Proposed Compliance Order, which is enclosed and made a part of this\nNotice.\nResponse to this Notice\nEnclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in\nCompliance Proceedings. Please refer to this document and note the response options. All\nmaterial submit in response to this enforcement action may be made publicly available. If you\nbelieve that any portion of your responsive material qualifies for confidential treatment under 5\nU.S.C. 552(b), along with the complete original document you must provide a second copy of the\ndocument with the portions you believe qualify for confidential treatment redacted and an\nexplanation of why you believe the redacted information qualifies for confidential treatment under\n5 U.S.C. 552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a\nwaiver of your right to contest the allegations in this Notice and authorizes the Associate\nAdministrator for Pipeline Safety to find facts as alleged in this Notice without further notice to\nyou and to issue a Final Order.\nIn your correspondence on this matter, please refer to CPF 4-2017-3002 and for each document\nyou submit, please provide a copy in electronic format whenever possible.\nSincerely,\nR. M. Seeley\nDirector, Southwest\nPipeline and Hazardous Materials Safety Administration\nEnclosures: Proposed Compliance Order\nResponse Options for Pipeline Operators in Compliance Proceedings\n8\n\n\n\nPROPOSED COMPLIANCE ORDER\nPursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety\nAdministration (PHMSA) proposes to issue to Lake Charles LNG a Compliance Order\nincorporating the following remedial requirements to ensure the compliance of Lake Charles LNG\nwith the pipeline safety regulations:\n1. 2. 3. 3. 4. In regard to Item Number 1 of the Notice pertaining to Lake Charles LNG’s failure\nto consider IR drop when conducting an annual CP survey:\nSurvey the facility so that IR drop is considered in the readings and remediate any\nareas not meeting the criterion. Implement provisions to consider IR drop in\ndetermining the adequacy of all future readings in the form of procedures and\ninterrupted surveys or other accepted means of consideration.\nIn regard to Item Number 2 of the Notice pertaining to Lake Charles LNG’s failure\nto provide procedures demonstrating that atmospheric corrosion inspections are\nperformed on a regular basis on above ground stain less steel insulated piping:\nDevelop procedures to inspect insulated above ground insulated stainless steel pipe\nfor atmospheric corrosion at set intervals not to exceed every 3 years. Using the\nprocedures, perform an atmospheric corrosion inspection of the insulated stainless\nsteel piping.\nIn regard to Item Number 3 of the Notice pertaining to Lake Charles LNG’s training\nrecords:\nReview training records for all personnel and confirm that the required initial\ntraining and refresher training has been completed according to the requirements of\n§193.2707, §193.2713, §193.2717, and the Operator’s training matrix. Ensure that\nsupervisors complete refresher training on detailed operations and that contract\nSecurity personnel who have defined roles in the facility emergency response plan\nhave received training in the emergency response plan and their roles. Develop\nrecords that clearly identify the employee’s job title, the specific training required\nfor that employee’s job, and the dates the initial and refresher training was\ncompleted by each employee.\nLake Charles LNG must demonstrate within 180 days of receipt of this order that\nthe requirements of this Compliance Order have been completed for Item Numbers\n1, 2 and 3.\nIt is requested (not mandated) that Lake Charles LNG maintain documentation of\nthe safety improvement costs associated with fulfilling this Compliance Order and\nsubmit the total to R. M. Seeley, Director, Southwest, Pipeline and Hazardous\nMaterials Safety Administration. It is requested that these costs be reported in two\ncategories: 1) total cost associated with preparation/revision of plans, procedures,\nstudies and analyses, and 2) total cost associated with replacements, additions and\nother changes to pipeline infrastructure.9\n\n420173002_Final Order_12022019_text.pdf\n\nDecember 2, 2019\nMr. Kelcy L. Warren\nChief Executive Officer\nEnergy Transfer, LP\n8111 Westchester Drive\nDallas, Texas 75225\nRe: CPF No. 4-2017-3002\nDear Mr. Warren:\nEnclosed please find the Final Order issued in the above-referenced case. It withdraws one\nallegation of violation, makes findings of violation, assesses a civil penalty of $32,400, and\nspecifies actions that need to be taken by your subsidiary, Lake Charles LNG Company, LLC, to\ncomply with the pipeline safety regulations. The penalty payment terms are set forth in the Final\nOrder. When the civil penalty has been paid and the terms of the compliance order completed,\nas determined by the Director, Southwest Region, this enforcement action will be closed.\nService of the Final Order by certified mail is effective upon the date of mailing as provided\nunder 49 C.F.R. § 190.5.\nThank you for your cooperation in this matter.\nSincerely,\nAlan K. Mayberry\nAssociate Administrator\nfor Pipeline Safety\nEnclosure\ncc: Ms. Mary McDaniel, Director, Southwest Region, Office of Pipeline Safety, PHMSA\nMr. Jeff Brightwell, Vice President, LNG Operations, Lake Charles LNG Company,\nLLC, 8100 Big Lake Road, Lake Charles, Louisiana 70605\nMs. Catherine D. Little, Esq., Troutman Sanders, LLP, 600 Peachtree Street, NE,\nSuite 5200, Atlanta, Georgia 30308\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\n\n\n\nU.S. DEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION\nOFFICE OF PIPELINE SAFETY\nWASHINGTON, D.C. 20590\n____________________________________\nIn the Matter of )\nLake Charles LNG Company, LLC, ) CPF No. 4-2017-3002\na subsidiary of Energy Transfer, LP, )\n)\n)\n)\nRespondent. )\n____________________________________)\nFINAL ORDER\nOn September 15-16, 2015, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and\nHazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS),\nconducted an on-site pipeline safety inspection of the facilities and records of Lake Charles LNG\nCompany, LLC (Lake Charles LNG or Respondent), in Lake Charles, Louisiana. At the time of\nthe inspection, the Lake Charles LNG facility encompassed a 400-acre site and consisted of four\ninsulated liquefied natural gas (LNG) tanks, two vaporizers, and associated equipment with\nexport facilities under development. Lake Charles LNG is a wholly-owned subsidiary of Energy\nTransfer, LP, which owns and operates approximately 71,000 miles of natural gas, natural gas\nliquids, refined petroleum, and crude oil pipelines.1\nAs a result of the inspection, the Director, Southwest Region, OPS (Director), issued to\nRespondent, by letter dated February 21, 2017, a Notice of Probable Violation, Proposed Civil\nPenalty, and Proposed Compliance Order (Notice), which also included a warning pursuant to 49\nC.F.R. § 190.205. In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that\nLake Charles LNG had committed three violations of 49 C.F.R. Part 193 and proposed assessing\na civil penalty of $32,400 for one of the alleged violations. The Notice also proposed ordering\nRespondent to take certain measures to correct the alleged violations. The Notice also included\ntwo warning items that required no further action, but warned the operator to correct the probable\nviolations or face possible future enforcement action.\nLake Charles LNG responded to the Notice by letter dated March 22, 2017 (Response).\nRespondent contested the allegations and requested a hearing. A hearing was subsequently held\non October 3, 2017, in Houston, Texas before a PHMSA Presiding Official. At the hearing,\nRespondent was represented by counsel. Respondent submitted additional written materials\nprior to the hearing on September 22, 2017 (Pre-hearing submittal), and following the hearing on\n1 Pipeline Safety Violation Report (Violation Report), (Feb. 21, 2017) (on file with PHMSA), at 1; Energy Transfer,\nLP website, available at https://www.energytransferlng.com/who we are html (last accessed November 12, 2019).\n\n\n\nCPF No. 4-2017-3002\nPage 2\nNovember 3, 2017 (Post-hearing submittal). The Director submitted a region recommendation\non May 22, 2019 (Region recommendation), and Lake Charles LNG submitted a reply to the\nregion recommendation on May 31, 2019 (Reply).\nFINDINGS OF VIOLATION\nThe Notice alleged that Respondent violated 49 C.F.R. Part 193, as follows:\nItem 1: The Notice alleged that Respondent violated 49 C.F.R. § 193.2629(a), which states:\n§ 193.2629 External corrosion control: buried or submerged\ncomponents.\n(a) Each buried or submerged component that is subject to external\ncorrosive attack must be protected from external corrosion by—\n(1) Material that has been designed and selected to resist the corrosive\nenvironment involved; or\n(2) The following means:\n(i) An external protective coating designed and installed to prevent\ncorrosion attack and to meet the requirements of §192.461 of this chapter;\nand\n(ii) A cathodic protection system designed to protect components in\ntheir entirety in accordance with the requirements of §192.463 of this\nchapter and placed in operation before October 23, 1981, or within 1 year\nafter the component is constructed or installed, whichever is later.\nThe Notice alleged that Respondent violated 49 C.F.R. § 193.2629(a) by failing to protect its\npipeline from external corrosion by means of a cathodic protection system that met the\nrequirements of § 192.463. Specifically, the Notice referenced Appendix D of Part 192 and\nalleged that Lake Charles LNG failed to consider IR drop when interpreting cathodic protection\nreadings from its annual surveys. IR drop represents the voltage difference between the pipe-to-\nsoil readings taken at the surface and the readings that one would actually obtain at the pipe-to-\nsoil interface due to the resistance of the soil. In the absence of considering IR drop, an operator\nmay erroneously conclude that the cathodic protection level meets the -850 mV criterion when it\ndoes not, resulting in a failure to provide adequate cathodic protection to the pipe.2\nIn its Response and at the hearing, Lake Charles LNG stated that it began its 2015 annual\ncathodic protection survey the day before the scheduled OPS compliance inspection began.\nRespondent did not argue that it was not required to consider IR drop. Rather, Respondent\nexplained that it contracted with the firm Corrpro to install interrupters on its rectifiers during the\n2015 inspection which would allow it to be able to measure IR drop. Respondent did not provide\nthe OPS inspector with any records, documents, studies, prior surveys, or explanations for how it\nconsidered the effect of IR drop in interpreting the cathodic protection pipe-to-soil voltage\nmeasurements, nor were any such documents provided in connection with the hearing. During\n2 Region recommendation, at 3.\n\n\n\nCPF No. 4-2017-3002\nPage 3\nthe hearing, Respondent did not argue that its annual surveys conducted in years prior to 2015\naccounted for IR drop.\nThe requirement to consider IR drop on an annual basis has been in place since before the\nfacility was commissioned in 1981. In Lake Charles LNG's case, its own records and statements\nestablish that it had never performed an interrupted survey in the history of the facility until\n2015. Accordingly, after considering all of the evidence and the legal issues presented, I find\nthat Respondent violated 49 C.F.R. § 193.2629(a) by failing to protect its pipeline from external\ncorrosion by means of a cathodic protection system that met the requirements of § 192.463 prior\nto the 2015 inspection and survey.\nItem 2: The Notice alleged that Respondent violated 49 C.F.R. § 193.2635(d), which states:\n§ 193.2635 Monitoring corrosion control.\nCorrosion protection provided as required by this subpart must be\nperiodically monitored to give early recognition of ineffective corrosion\nprotection, including the following, as applicable:\n(a)…\n(d) Each component that is protected from atmospheric corrosion must\nbe inspected at intervals not exceeding 3 years.\nThe Notice alleged that Respondent violated 49 C.F.R. § 193.2635(d) by failing to periodically\ninspect a portion of its aboveground piping to monitor for ineffective protection from\natmospheric protection. Specifically, the Notice alleged that Lake Charles LNG did not inspect\ncertain insulated piping used to transport liquefied natural gas at intervals not exceeding three\nyears.\nIn its Response and at the hearing, Lake Charles LNG contested the allegation, contending that\nthe aboveground pipe used to transport LNG at its Lake Charles facility was not required to be\nperiodically inspected for atmospheric corrosion. Respondent explained that it believed the three\nyear inspection requirement did not apply to stainless-steel pipe and that austenitic stainless steel\n“contains a high percentage of nickel and chromium, and is thus extremely resistant to\ncorrosion.”3 Respondent cited a research paper entitled \"Pitting and Crevice Corrosion of\nStainless Steel Under Offshore Conditions.\"4 This paper included a diagram in Figure 2.5\nshowing the temperatures that different grades of stainless steel were previously thought to be\nsusceptible to corrosion.5 For 304 stainless steel, the critical pitting temperature ranges from 5\ndegrees to -20 degrees C. Respondent explained that the operating temperature of its piping\nduring LNG operations is -46 degrees C to -159 degrees C, and argued that its piping was\n3 Post-hearing submission, at 5. It is notable, however, that § 193.2635(d) does not include an express exemption\nfrom the atmospheric corrosion inspection requirement for stainless steel pipe. If the drafters of this regulation had\nintended to exempt stainless steel pipe from atmospheric corrosion inspections, they could have easily done so then\nand there but they chose not to.\n4 Violation Report, Exhibit B.\n5 Id., at 18-19.\n\n\n\nCPF No. 4-2017-3002\nPage 4\noperated outside the temperature range for corrosion to occur.\nOPS acknowledged that cryogenic temperatures were a factor in preventing external pipe\ncorrosion, but pointed out that the Lake Charles facility had not operated at cryogenic\ntemperatures since 2012, making it approximately six years since the piping has been within the\ntemperature range that Respondent maintains would prevent corrosion. OPS went on to point\nout that the research paper also states: “This study has shown that in order to be able to assess the\npossibility of pitting and crevice corrosion and probability of failure with respect to time due to\npitting corrosion and coating degradation it is not enough to only consider temperature. It is\nshown that other parameters are probably as important as temperature.”6 OPS then pointed to a\nsection of the paper explaining that the other mechanisms that can cause the protective chromium\noxide layer on stainless-steel piping to be compromised and lead to corrosion include: (1)\nchemical attack, particularly from environments containing chlorides and sulfides; (2)\nmechanical damage such as scratches or gouges on the surface of the pipe; and (3) heat such as\nthat from welding. The critical factors listed include, “Design of insulation system, insulation\ntype, temperature, environment (humidity, rainfall and chlorides from marine environment,\nindustrial environments containing high SO2) are critical factors.”7\nThis leads to the issue of whether the temperature, humidity, and marine environment factors\npresent at the site of the Lake Charles facility implicate a potentially corrosive atmospheric\nenvironment. Respondent argued that the Lake Charles facility was not subject to a corrosive\natmospheric environment. Respondent submitted a report entitled “Evaluation of the\nSusceptibility to Corrosion of Stainless Steel LNG Pipe Under All Operating Conditions at the\nlake Charles Liquefied Natural Gas Facility.\n8 The report stated: “The LC LNG Facility is\napproximately 26 miles (42 km) from the Gulf of Mexico, as shown in Figure 1.”9 The report\ngoes on to state, “The corrosion rate of carbon steel diminishes by more than 97% when it is only\n0.62 miles (1 km) from the water. Thus, the effects of seawater on LC LNG Facility Type 304\nSS piping should be insignificant at 26 miles (42 km) from the Gulf of Mexico.”10\nWith regard to the potential for a corrosive atmospheric environment to be present, OPS stated:\nThe Lake Charles facility is located in a hot, humid environment\nimmediately adjacent to bodies of saltwater. The piping is covered by\nmetallic sheathed insulation that is not water tight and can trap moisture\nagainst the surface of the pipe. The chlorides present in the salt water along\nwith the environment could clearly create an environment that would\nchemically degrade the thin protective chromium oxide layer on the\nstainless-steel piping and result in a damage mechanism defined by API\n6 Id., at 73.\n7 Id., at 170-171.\n8 Post-hearing submittal, Exhibit 4.\n9 Post-hearing submittal, Exhibit 4, at 6.\n10 Id.\n\n\n\nCPF No. 4-2017-3002\nPage 5\nRecommended Practice 571, \"Damage Mechanisms Affecting Fixed\nEquipment in the Refining Industry\" as Corrosion Under Insulation (CUI)\n(Violation Report, Ex. B, at 170-71). This industry standard clearly\nid","truncated":true,"body_characters":70300}