{"operation":"document","citation":"CPF 42022032NOPV","title":"FLORIDA GAS TRANSMISSION CO — Notice of Probable Violation","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":"2022-07-22","effective_on":null,"summary":"OPEN notice of probable violation citing 192.619(a)(3), 192.917(a)(1), 192.937(c)(1).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-42022032nopv.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-42022032nopv.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-42022032nopv","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/42022032NOPV","body":"Notice of Probable Violation involving FLORIDA GAS TRANSMISSION CO. PHMSA's enforcement data identifies the cited regulations as 192.619(a)(3),  192.917(a)(1),  192.937(c)(1). The case was opened on 2022-07-22 and is reported as open. Proposed civil penalty: $834,400. Assessed civil penalty: $0. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n42022032NOPV_Final Order_05212024_(20-190995).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_Final%20Order_05212024_(20-190995).pdf\n\n42022032NOPV_Final Order_05212024_(20-190995)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_Final%20Order_05212024_(20-190995)_text.pdf\n\n42022032NOPV_Florida Gas Transmission v PHMSA Petition for Review of an Order_05202026_(20-190995).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_Florida%20Gas%20Transmission%20v%20PHMSA%20Petition%20for%20Review%20of%20an%20Order_05202026_(20-190995).pdf\n\n42022032NOPV_Operator Post-Hearing Submission_04212023_(20-190995).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_Operator%20Post-Hearing%20Submission_04212023_(20-190995).pdf\n\n42022032NOPV_Operator Pre-Hearing Submission_03142023_(20-190995).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_Operator%20Pre-Hearing%20Submission_03142023_(20-190995).pdf\n\n42022032NOPV_Operator RfH and Statement of Issues_09302022_(20-190995).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_Operator%20RfH%20and%20Statement%20of%20Issues_09302022_(20-190995).pdf\n\n42022032NOPV_Operator RtN and Statement of Issues_09302022_(20-190995).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_Operator%20RtN%20and%20Statement%20of%20Issues_09302022_(20-190995).pdf\n\n42022032NOPV_Operator to PHC - External Petition for Review_08162024_(20-190995).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_Operator%20to%20PHC%20-%20External%20Petition%20for%20Review_08162024_(20-190995).pdf\n\n42022032NOPV_PCP_07222022_(20-190995).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_PCP_07222022_(20-190995).pdf\n\n42022032NOPV_PCP_07222022_(20-190995)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_PCP_07222022_(20-190995)_text.pdf\n\n42022032NOPV_PHC Hearing Scheduled_11012022_(20-190995).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_PHC%20Hearing%20Scheduled_11012022_(20-190995).pdf\n\n42022032NOPV_PHC Hearing Scheduled_11012022_(20-190995)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_PHC%20Hearing%20Scheduled_11012022_(20-190995)_text.pdf\n\n42022032NOPV_PHC Hearing Scheduled_11012022_(20-190995)_text.pdf\n\nNovember 1, 2022\nVIA ELECTRONIC MAIL TO: vince.murchison@pipelinelegal.com and\nbryan.lethcoe@dot.gov\nMr. Vince Murchison, Esq.\nCounsel for Florida Gas Transmission Company\nMurchison Law Firm, PLLC\n325 North St. Paul Street, Suite 2700\nDallas, Texas 75201\nMr. Bryan Lethcoe\nDirector, Southwest Region\nPipeline and Hazardous Materials Safety Administration\n8701 South Gessner Road, Suite 630\nHouston, Texas 77074\nRe: Notice of Hearing, Florida Gas Transmission Company\nCPF No. 4-2022-032-NOPV\nDear Mr. Murchison and Mr. Lethcoe:\nIn accordance with 49 C.F.R. § 190.211, an informal hearing will be held regarding the Notice of\nProbable Violation and Proposed Civil Penalty issued by the Pipeline and Hazardous Materials\nSafety Administration in the above-referenced case. The hearing will take place on March 22,\n2023, beginning at 8:30 a.m. Central Time.\nThe hearing will take place at the PHMSA Southwest Region office, 8701 South Gessner Road,\nSuite 630, Houston, TX 77074. Upon arrival at the building, attendees will be required to present\nphoto identification to security personnel. A contact phone number for the day of the hearing is\n(713) 272-2859.\nAt least 10 calendar days prior to the hearing (or by March 13, 2023), both parties must submit and\nexchange any additional written materials they intend to present at the hearing and the name and\nemail address of each attendee. This information should be provided electronically. Materials not\nsubmitted by this date may be excluded.\n\n\n\nIf you have any questions, please do not hesitate to contact me.\nSincerely,\nLarry White\nPresiding Official\ncc: Mr. Eric Amundsen, Senior Vice President, Operations, Florida Gas Transmission Co.,\neric.amundsen@energytransfer.com\nMs. Heidi Slinkard, Counsel, Florida Gas Transmission Co.,\nheidi.slinkard@energytransfer.com\nMr. Ian Curry, Esq., Counsel, Southwest Region, Office of Pipeline Safety,\nian.curry@dot.gov\n\n42022032NOPV_Final Order_05212024_(20-190995)_text.pdf\n\nMay 21, 2024\nVIA ELECTRONIC MAIL TO: tom.long@energytransfer.com\nThomas E. Long\nChief Executive Officer\nEnergy Transfer LP\n1300 Main Street\nHouston, Texas 77002\nRe: CPF No. 4-2022-032-NOPV\nDear Mr. Long:\nEnclosed please find the Final Order issued in the above-referenced case to Florida Gas\nTransmission Company, LLC, a subsidiary of Energy Transfer LP. It withdraws one of the\nallegations of violation, makes other findings of violation, and assesses a civil penalty of\n$409,400. The penalty payment terms are set forth in the Final Order. This enforcement action\ncloses automatically upon receipt of payment. Service of the Final Order by e-mail is effective\nupon the date of transmission and acknowledgement of receipt as provided under 49 C.F.R.\n§ 190.5.\nThank you for your cooperation in this matter.\nSincerely,\nAlan K. Mayberry\nAssociate Administrator\nfor Pipeline Safety\nEnclosure\ncc: Mr. Bryan Lethcoe, Director, Southwest Region, Office of Pipeline Safety, PHMSA\nMr. Greg McIlwain, Executive Vice President of Operations, Energy Transfer LP,\ngregory.mcilwain@energytransfer.com\n\n\n\nMr. Eric Amundsen, Senior Vice President of Operations, Energy Transfer LP,\neric.amundsen@energytransfer.com\nMr. Todd Stamm, Senior Vice President of Operations, Energy Transfer LP,\ntodd.stamm@energytransfer.com\nMs. Jennifer Street, Senior Vice President of Operations Services, Energy Transfer LP,\njennifer.street@energytransfer.com\nMs. Heidi Murchison, Chief Counsel, Energy Transfer LP,\nheidi.murchison@energytransfer.com\nMr. Leif Jensen, Vice President of Tech Services, Energy Transfer LP,\nleif.jensen@energytransfer.com\nMr. Todd Nardozzi, Director of Regulatory Compliance, Energy Transfer LP,\ntodd.nardozzi@energytransfer.com\nMs. Susie Sjulin, Director of Regulatory Compliance, Energy Transfer LP,\nsusie.sjulin@energytransfer.com\nMr. Vince Murchison, Esq., Outside Counsel for Florida Gas Transmission Co.,\nMurchison Law Firm, PLLC, vince.murchison@pipelinelegal.com\nCONFIRMATION OF 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 )\nFlorida Gas Transmission Company, LLC, ) CPF No. 4-2022-032-NOPV\na subsidiary of Energy Transfer LP, )\n)\n)\n)\nRespondent. )\n______________________________________)\nFINAL ORDER\nFrom September 13, 2020 through September 23, 2021, pursuant to 49 U.S.C. § 60117, a\nrepresentative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office\nof Pipeline Safety (OPS), conducted an on-site pipeline safety inspection and investigation of the\nfacilities and records of Florida Gas Transmission Company, LLC’s (FGT or Respondent) 12-\ninch diameter Sanford Lateral natural gas transmission pipeline following a rupture of the\nSanford Lateral that occurred on September 10, 2020, in Sanford, Florida.1\nThe escaping natural gas ignited and burned an area measuring approximately 515 by 100 feet.\nThe burn also damaged and knocked down three overhead powerlines owned by Duke Energy\nand about 32 homes and 93 businesses had to be evacuated. There were no reported injuries or\nfatalities. On September 18, 2020, PHMSA issued a Corrective Action Order (CAO) to FGT\n(CPF 4-2020-008-CAO) that required a shutdown of the pipeline segment and required a records\nreview and verification, a review of prior inline inspection results, a metallurgical laboratory\nexamination of the ruptured pipe, a root cause failure analysis, a pressure restriction upon restart,\nand a remedial work plan. With PHMSA’s Southwest Region oversight, FGT repaired the pipe\nat the rupture site and returned the Sanford Lateral to service on December 7, 2020, under the\nterms of the CAO.\nAs a result of the inspection and investigation, the Director, Southwest Region, OPS (Director),\nissued to Respondent, by letter dated July 22, 2022, a Notice of Probable Violation and Proposed\nCivil Penalty (Notice). In accordance with 49 C.F.R. § 190.207, the Notice proposed finding\nthat FGT committed three violations of 49 C.F.R. Part 192 and proposed assessing a total civil\npenalty of $834,400 for the alleged violations.\n1 FGT is a large interstate natural gas pipeline company that operates approximately 5,300 miles of gas transmission\nlines that originate in Galveston Bay and extend through various states including Florida. FGT is owned by Citrus\nCorporation, a joint venture between Energy Transfer LP and Kinder Morgan, Inc. Energy Transfer LP website,\nNatural Gas, available online at https://www.energytransfer.com/natural-gas (last accessed Jan. 30, 2024).\n\n\n\nFGT responded to the Notice by letter dated September 30, 2022 (Response), as supplemented\nby material submitted on March 13, 2023 (Pre-hearing Submission). FGT contested the\nallegations and requested an informal hearing. A hearing was subsequently held on March 22,\n2023, in Houston, Texas, before a Presiding Official from the Office of Chief Counsel, PHMSA.\nAt the hearing, Respondent was represented by counsel. After the hearing, Respondent provided\nadditional written material for the record by letter dated April 21, 2023 (Post-hearing\nsubmission). The Director provided a recommendation on May 22, 2023 (Recommendation) and\nFGT submitted a reply to the Recommendation on June 12, 2023 (Reply).\nFINDINGS OF VIOLATION\nThe Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows:\nItem 1: The Notice alleged that Respondent violated 49 C.F.R. § 192.619(a)(3), which states:\n§ 192.619 Maximum allowable operating pressure: Steel or plastic\npipelines.\n(a) No person may operate a segment of steel or plastic pipeline at a\npressure that exceeds a maximum allowable operating pressure (MAOP)\ndetermined under paragraph (c), (d), or (e) of this section, or the lowest of\nthe following:\n(1) …\n(3) The highest actual operating pressure to which the segment was\nsubjected during the 5 years preceding the applicable date in the second\ncolumn. This pressure restriction applies unless the segment was tested\naccording to the requirements in paragraph (a)(2) of this section after the\napplicable date in the third column or the segment was uprated according to\nthe requirements in subpart K of this part:\nPipeline segment Pressure date Test date\n(i) Onshore regulated\ngathering pipeline (Type A\nor Type B under § 192.9(d))\nthat first became subject to\nthis part (other than\n§192.612) after April 13,\n2006\nMarch 15, 2006, or\ndate pipeline\nbecomes subject to\nthis part, whichever\nis later\n5 years preceding\napplicable date in\nsecond column.\n(ii) Onshore regulated\ngathering pipeline (Type C\nunder § 192.9(d)) that first\nbecame subject to this part\n(other than § 192.612) on or\nafter May 16, 2022\nMay 16, 2023, or\ndate pipeline\nbecomes subject to\nthis part, whichever\nis later\n5 years preceding\napplicable date in\nsecond column.\n\n\n\n(iii) Onshore transmission\npipeline that was a\ngathering pipeline not\nsubject to this part before\nMarch 15, 2006\nMarch 15, 2006, or\ndate pipeline\nbecomes subject to\nthis part, whichever\nis later\n5 years preceding\napplicable date in\nsecond column.\n(iv) Offshore gathering\npipelines\nJuly 1, 1976 July 1, 1971.\n(v) All other pipelines July 1, 1970 July 1, 1965.\nThe Notice alleged that Respondent violated 49 C.F.R. § 192.619(a)(3) by failing to establish a\nmaximum allowable operating pressure (MAOP) for its Sanford Lateral in accordance with\n§ 192.619(a)(3). Specifically, the Notice alleged that FGT did not have records to substantiate\nthe highest actual operating pressure that the segment was subjected to during the five years prior\nto MAOP establishment.\nIn its Response and at the hearing, FGT contested the allegation and provided information\nconcerning the history of the pipeline going back to 1959 indicating that former owners and\noperators of the pipeline considered the MAOP in 1970 to be 713 psig. Respondent explained\nthat it maintained a one-page historical record from 1989 referred to by FGT as the “Gold Sheet”\nthat in its view substantiated the current MAOP for the Sanford Lateral,\n2 and argued that the\nregulations did not require it to have records to substantiate the MAOP indicated on the Gold\nSheet or otherwise substantiate the highest actual operating pressure that the segment was\nsubjected to during the five years prior to MAOP establishment. FGT further argued that the\nNotice should have alleged a violation under the MAOP Reconfirmation section in § 192.624\nwhich was added to Part 192 in 2019, and not establishment of MAOP under § 192.619.\nAt the hearing, OPS maintained that it was unable to verify or substantiate, based on FGT\nrecords, that the Sanford Lateral was subjected to 713 psig during the five-year period prior to\nJuly 1, 1970. FGT argued that “[n]o indication exists that Sanford Lateral was not subjected to a\nhighest pressure of 713 psig between 1965 and 1970.”3 OPS stated that Respondent did not\nprovide any records that would substantiate the establishment of an MAOP of 713 psig and that\nthe first pressure records provided to substantiate the MAOP were from the 2020 hydrostatic test\nconducted pursuant to the CAO.\nTo demonstrate compliance with § 192.619(a)(3), operators are required to have records that\nenable PHMSA to “verify that the entire pipeline was subjected to that pressure sometime during\nthe five-year period prior to July 1, 1970.”4 Consistent with this requirement, PHMSA issued\nenforcement guidance in 2017 reminding operators that a probable violation may be found if an\n2 PHMSA Violation Report, Exhibit A.\n3 Post-hearing Submission, at 18.\n4 West Texas Gas, Final Order, CPF No. 4-2004-1007, at 6 (Sept. 13, 2006).\n\n\n\noperator cannot provide records to “substantiate the established MAOP.”5\nWith regard to the 1989 Gold Sheet, FGT acknowledged that it did not have pressure logs or\nother such records of pressure readings associated with it, but suggested that Enron, the former\noperator of the Sanford Lateral, must have reviewed such records when creating the Gold Sheet.\nThat assertion, however, does not take the place of records necessary to verify MAOP.6\nRespondent also provided a declaration from a current FGT employee who had recently\nreviewed the specifications of various valves and other components of the pipeline.7 The\ndeclaration stated that “no component on the pipeline at the time of the September 10, 2020\nincident had, and no component on the pipeline currently has, a design pressure that is less than\n713 psig which is the established MAOP of the pipeline. However, this affidavit is insufficient\nto satisfy § 192.619(c) because it failed to include any operating pressure readings from July 1,\n1965 – July 1, 1970. In addition, OPS has advised operators that affidavits on their own are not\nverifiable records sufficient to meet the requirement to establish MAOP.8 Without actual\npressure logs or similar records demonstrating actual pressures experienced during this five-year\ntime period, OPS cannot verify that the MAOP was properly established.\nAt the hearing, FGT also contended that even though the Gold Sheet does not reflect any actual\nhistorical operating pressure readings, it is in some sense a record of the overall “limiting factor”\non the Sanford Lateral.9 Thus, it appears FGT accepts that 713 psig is not a reflection of the\nactual operating pressure from 1965 to 1970, but instead reflects MAOP established under\n§ 192.619(a)(1). The Gold Sheet, however, cannot be both. FGT also acknowledged that the\nGold Sheet may itself be inaccurate. FGT stated that “[i]t would not be unreasonable to\nconclude” that the MAOP Authorization Sheet “inadvertently chose ‘619(c).”10 Because FGT\nfailed to substantiate its MAOP with § 192.619(c), it cannot rely on § 192.619(c) as a defense to\nthe alleged violation of § 192.619(a)(3). For the same reasons that the records fail to\ndemonstrate compliance with § 192.619(c), FGT failed to provide records to substantiate its\nestablishment of MAOP in accordance with § 192.619(a)(3).11 If the Gold Sheet does in fact\n5 PHMSA, Operations & Maintenance Enforcement Guidance Part 192 Subparts L and M, at 81 (July 21, 2017),\navailable online at https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/regulatory-\ncompliance/pipeline/enforcement/5776/o-m-enforcement-guidance-part-192-7-21-2017.pdf.\n6 PHMSA’s enabling statute requires operators to “make” and “maintain records” to demonstrate compliance with\nthe pipeline safety laws and regulations. See 49 U.S.C. § 60117(c). The failure to maintain records, by itself, can be\na violation of the pipeline safety regulations. See 49 C.F.R. § 192.619(f).\n7 Post-hearing Submission, Exhibit 3.\n8 Pipeline Safety: Verification of Records: ADB-2012-06, 77 Fed. Reg. 26,822, 26,823 (May 7, 2012) (“In general,\nthe only acceptable use of an affidavit would be as a complementary document, prepared and signed at the time of\nthe test or inspection by an individual who would have reason to be familiar with the test or inspection.”).\n9 Post-hearing Submission, at 17.\n10 Post-hearing Submission, at 18.\n11 FGT suggested it established MAOP under other provisions of § 192.619(a) and that it is PHMSA’s burden to\ndemonstrate § 192.619(a)(3) is the lowest of the options in subparagraph (a). However, the absence of any one\ncalculation under § 192.619(a)(1)-(4) renders the whole analysis unsubstantiated. If the MAOP “established” under\n§ 192.619(a)(3) cannot be verified or substantiated it cannot form the basis for a valid MAOP.\n\n\n\nreflect uncertainty about whether it was intended to apply for purposes of subsection (a) or\nsubsection (c), that only reinforces the conclusion that it does not substantiate the establishment\nof MAOP.\nWith respect to the consistency of this case with PHMSA’s position in prior proceedings, in the\nabove-referenced West Texas Gas proceeding the agency found that, “PHMSA must be able to\nverify” that a pipeline was subjected to the pressure if MAOP was established under\n§ 192.619(c). In West Texas Gas, the Acting Associate Administrator found that two single\ndocuments, each with different MAOPs, were insufficient to establish MAOP because neither\nnumber could be corroborated with other records.12 Similarly in the present case, FGT has failed\nto provide any corroborating records (i.e., operating pressure records) that support the selection\nof 713 psig on the MAOP Authorization Sheet. In fact, FGT suggested that 713 psig was\nselected based on the design pressure, and not historical operating pressure.13 This uncertainty\nsupports finding this violation as PHMSA cannot verify how MAOP was established. This point\nis further emphasized by FGT’s efforts spent speculating on what the prior operator may or may\nnot have reviewed in creating the MAOP Authorization Sheet.14\nSimilarly, in the El Paso Natural Gas Company, LLC proceeding, OPS alleged that the operator\nfailed to establish MAOP in accordance with § 192.619(a)(3). In the final order, the Associate\nAdministrator for Pipeline Safety found the operator in violation of 192.619(a)(3) for failing to\nhave records in support of its (pre-1970) MAOP establishment. Thus, the final order found the\noperator in violation of § 192.619(a)(3) under the same charge as alleged here in this\nproceeding.15 In both the West Texas Gas and El Paso proceedings cases, the operators had\nestablished an MAOP using historical operating pressure, but could not provide any operating\npressure records to support that number. Thus, OPS is correct that its position in this case is\nconsistent with the outcome of both prior proceedings.\nFinally, FGT argued that any allegation of non-compliance should have cited the MAOP\nreconfirmation requirements in § 192.624 because it was a newer regulation and “obviated” the\nprovisions in § 192.619(c).16 FGT cited the above referenced El Paso proceeding as support for\nits position that MAOP reconfirmation obviated section 192.619.17 Section 192.624 was\npromulgated, in part, to address a congressional mandate in Section 23 of the 2011 Pipeline\nSafety Act that “requires the verification of records for pipe in Class 3 and Class 4 locations, and\nhigh consequence areas in Class 1 and Class 2 locations, to ensure they accurately reflect the\nphysical and operational characteristics of the pipelines and confirm the established MAOP of\n12 West Texas Gas, Final Order, CPF No. 4-2004-1007, at 6 (Sept. 13, 2006).\n13 Post-hearing Submission, at 18.\n14 Id., at 17-18.\n15 El Paso Natural Gas Company, LLC, Notice of Probable Violation, CPF No. 4-2019-1010, at 2 (Oct. 1, 2019).\n16 Post-hearing Submission at 25; see Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP\nReconfirmation, Expansion of Assessment Requirements, and Other Related Amendments, 84 Fed. Reg. 52,180\n(Oct. 1, 2019).\n17 See El Paso Natural Gas Company, LLC, Final Order, CPF No. 4-2019-1010 (July 22, 2020).\n\n\n\nthe pipelines.”18 Section 192.624, however, is complementary to, but does not replace,\n§ 192.619. MAOP reconfirmation instead reiterated the importance of verifiable documentation\nto support MAOP establishment. Operators are required to establish MAOP under § 192.619\nand then, if the criteria in § 192.624(a) are met, operators must reconfirm MAOP according to\nthat section. Nothing in the MAOP reconfirmation regulatory record suggests that this regulation\nreplaced the MAOP Establishment requirements.\n19\nAccordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.\n§ 192.619 by failing to establish a MAOP for its Sanford Lateral in accordance with\n§ 192.619(a)(3).\nItem 2: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(a)(1), which states:\n§ 192.917 How does an operator identify potential threats to pipeline\nintegrity and use the threat identification in its integrity program?\n(a) Threat identification. An operator must identify and evaluate all\npotential threats to each covered pipeline segment. Potential threats that an\noperator must consider include, but are not limited to, the threats listed in\nASME/ANSI B31.8S (incorporated by reference, see § 192.7), section 2,\nwhich are grouped under the following four categories:\n(1) Time dependent threats such as internal corrosion, external\ncorrosion, and stress corrosion cracking;\nThe Notice alleged that Respondent violated 49 C.F.R. § 192.917(a)(1) by failing to identify and\nevaluate all potential threats to each covered pipeline segment in its natural gas pipeline systems\nin accordance with § 192.917(a)(1). Specifically, the Notice alleged that FGT failed to include\nthe Sanford Lateral as part of its stress corrosion cracking (SCC) program prior to the September\n10, 2020 incident.\nIn its Response and at the hearing, FGT contested the allegation and explained that while it was\ngenerally aware of the potential of SCC to be an integrity threat, after appropriate application of\nthe relevant factors it had insufficient reason to include the Sanford Lateral in its SCC program.\nRespondent stated that the only indication of SCC on Sanford Lateral came after the September\n10, 2020 incident when the post-incident metallurgical report was received.\n20\nAs the basis for its allegation that the Sanford Lateral was required to have been included in\nFGT’s SCC program, OPS stated that Respondent has 30 pipelines and 13 laterals in its SCC\nprogram with pipe specifications it believed were similar to the Sanford Lateral, and that SCC\nhad been found on pipelines in the vicinity. Respondent strongly disagreed. Respondent’s\nDirector of Pipeline Integrity testified that the 30 pipelines and 13 laterals OPS mentioned are\nnot in fact the same as Sanford Lateral and that they have different seam type and coating,\n18 84 Fed. Reg., at 52,234.\n19 The MAOP Reconfirmation Rule made conforming changes to § 192.619 and revised the test pressure factors but\notherwise retained each provision. See id. Thus, FGT’s assertions that MAOP Reconfirmation replaced MAOP\nEstablishment is unsupported by the regulatory record.\n20 Id., at 29-30.\n\n\n\ndifferent grade steel, different vintage (age), different manufacturer, and different wall thickness\nand diameter. FGT correctly noted that just because one pipeline may have some of the same\ncharacteristics as another does not automatically mean that all of them will be susceptible to\nSCC. FGT argued that PHMSA’s inference that all of those pipelines are in the vicinity of the\nSanford Lateral was also incorrect and explained that some were hundreds of miles distant.21\nWith regard to OPS’ contention that, prior to the incident, the Sanford Lateral should have been\nincluded in Respondent’s SCC program, FGT argued that the Sanford Lateral simply did not\nmeet the applicable criteria to be subjected to the program. Respondent’s Director of Pipeline\nIntegrity testified that its pipelines are evaluated for SCC all the time, and, had SCC been found\nor had Sanford Lateral been determined to be susceptible to SCC, it would have been added to\nthe program, as occurred after the 2020 incident.22\nRespondent noted that section 192.917(a), Threat Identification, directs operators to identify and\nevaluate all potential threats to each covered pipeline segment, including but not limited to those\nidentified in ASME/ANSI B31.8S-2004 (B31.8S), section 2. Of the four categories established\nin Section 192.917(a)(1)-(4), OPS alleged a violation of only subsection (1), “time dependent\nthreats such as internal corrosion, external corrosion, and stress corrosion cracking.”23 Section\n2.3.3 of B31.8S, Risk Assessment, refers the reader to a prescriptive approach presented in\nAppendix A. Section A3.3 of Appendix A provides that each segment should be assessed for\nrisk for the possible threat of SCC if all of the following criteria are present:\nASME B31.8S-2004 - SCC Threat Susceptibility Review\n(a) Operating stress > 60% SMYS\n(b) Operating temperature > 100o Fahrenheit\n(c) Distance from compressor station ≤ 20 miles\n(d) Age ≥ 10 years\n(e) All corrosion coating systems other than fusion-bonded\nepoxy (FBE).24\nRespondent explained that the Sanford Lateral fails to meet three of those five criteria. The only\ntwo criteria met are (d) age ≥ 10 years given that Sanford Lateral was constructed in 1959, and\n(e) all corrosion coating systems other than fusion-bonded epoxy given that the greater\nproportion of Sanford Lateral is coated with Polyken tape coating.25 With regard to the first of\n21 Post-hearing Submission, at 30-31.\n22 Id., at 31.\n23 Id., at 27.\n24 Case File Exhibit 5, PSVR Ex. C, ASME B31.8S, at 43 (PDF p. 176).\n\n\n\nthe three criteria that the Sanford Lateral does not meet, criterion (a) operating stress > 60%\nSMYS, Respondent presented information showing that the Sanford Lateral operates at a\nmaximum stress level of 49% SMYS. Second, regarding criterion (b) operating temperature >\n100o Fahrenheit, Respondent’s Vice President of Operations for the Southeast Division testified\nthat Sanford Lateral over the last six years has operated between 61 and 84 degrees Fahrenheit\nand that this temperature range is typical for operating conditions on the Sanford Lateral.\nRegarding criterion (c) distance from compressor station ≤ 20 miles, Respondent presented\ninformation showing that the beginning of Sanford Lateral at the takeoff is approximately 39\nmiles from the upstream compressor station.26 Respondent is correct that B31.8S indicates that\nonly if “all” criteria of Section A3.3 of Appendix A are met is a segment “to be assessed for risk\nof the possible threat of SCC” but only two were met27\nWhile they are not mandatory criteria, B31.8S contains additional factors that an operator must\nconsider for determining whether a segment of pipeline is susceptible to the SCC threat. Those\nare: (a) one or more service incidents was caused by either high pH SCC or near neutral pH\nSCC; and (b) one or more hydrostatic test breaks or leaks was caused by one of the two types of\nSCC. Respondent’s witnesses testified that no service incident was caused by either type of SCC\nprior to the 2020 incident, and no hydrostatic test leaks or breaks were experienced on the\nSanford Lateral.28 B31.8S also requires an operator to consider previous SCC history.\nRespondent showed that the only indication of SCC on Sanford Lateral came after the incident,\nwhen the post-incident metallurgical report was received.29\nUnlike a component widely known to have manufacturing defects that can be identified by an\noperator in various ways, SCC is an issue that can take decades to develop and typically needs to\nbe confirmed by metallurgical analysis. As FGT correctly noted, many pipelines never\nexperience SCC at all. While OPS is correct that a pipeline operator is obligated to address the\npotential for SCC on its pipelines, the issue to be determined here is whether a violation of the\ncode as it currently exists has been proven. Under circumstances in which a pipeline segment\nhas no history of SCC ever being identified and does not have substantially the same material\nand operating characteristics as pipe that has been deemed susceptible to SCC,\n30 OPS has the\nburden of establishing that such a segment should have been treated as a SCC segment in a given\noperator’s SCC program.\n31 In this instance, the evidence presented by OPS fell short of meeting\n25 Post-hearing Submission, at 28.\n26 Id.\n27 Id., at 29.\n28 Id.\n29 Id., at 29-30.\n30 Respondent’s Director of Pipeline Integrity testified that the 30 pipelines and 13 laterals OPS mentioned are not\nin fact the same as Sanford Lateral and that they have different seam type and coating, different grade steel, different\nvintage (age), different manufacturer, and different wall thickness and diameter.\n31 Of course, now that near-neutral pH SCC has been identified in connection with FGT’s analysis of the September\n10, 2020 incident, Respondent is not disputing the need to include the Sanford Lateral in its SCC program going\nforward.\n\n\n\nthat burden.\nAccordingly, after considering all of the evidence, I find that OPS did not establish that\nRespondent was out of compliance with the cited regulation. Based upon the foregoing, I hereby\norder that Item 2 be withdrawn.\nItem 3: The Notice alleged that Respondent violated 49 C.F.R. § 192.937(c)(1), which states:\n§ 192.937 What is a continual process of evaluation and assessment to\nmaintain a pipeline’s integrity?\n(a) …\n(c) Assessment methods. In conducting the integrity reassessment, an\noperator must assess the integrity of the line pipe in the covered segment by\nany of the following methods as appropriate for the threats to which the\ncovered segment is susceptible (see § 192.917), or by confirmatory direct\nassessment under the conditions specified in § 192.931.\n(1) Internal inspection tool or tools capable of detecting corrosion, and\nany other threats to which the covered segment is susceptible. An operator\nmust follow ASME/ANSI B31.8S (ibr, see § 192.7), section 6.2 in selecting\nthe appropriate internal inspection tools for the covered segment.32\nThe Notice alleged that Respondent violated 49 C.F.R. § 192.937(c)(1) by failing to follow\nB31.8S, section 6.2 in selecting the appropriate internal inspection tools for each covered\nsegment. Specifically, the Notice alleged that although the Sanford Lateral consisted largely of\nlow-frequency electric-resistance welded (LF-ERW) pipe manufactured by Youngstown Sheet &\nTube of 1959 vintage known to be susceptible to axial seam defects, FGT used an in-line\ninspection (ILI) tool for its ILI runs in 2014 and 2019 that was designed primarily to evaluate\ncircumferential defects rather than axial defects.\nIn its Response and at the hearing, FGT contested the allegation and argued that although the\nSanford Lateral largely did consist of LF-ERW pipe, no assessment for this threat was prompted\nby 49 C.F.R. § 192.937(c)(1).\n33 FGT argued that the cited regulation should be read together\nwith § 192.917(e)(4).\n34 This provision states that if a covered pipeline segment contains LF-\nERW pipe, lap welded pipe, or other conditions specified in B31.8S, Appendices A4.3 and A4.4,\nany covered or noncovered segment in the pipeline system with such pipe must have experienced\na pressure increase over MAOP or a seam integrity failure during the preceding five years in\n32 Section 192.937(c) and (d) were amended on October 1, 2019, after FGT conducted its 2014 and 2019 ILIs.\n33 Post-hearing Submission, at 37-38.\n34 OPS disagreed, noting that § 192.917(a) outlines the process operators must follow to determine which threats\ntheir pipelines are susceptible to. However, section 192.917(e)(4) sets forth specific actions an operator must take to\naddress known issues with ERW pipe. Section 192.917(e)(4) does not prescribe an exclusive list of criteria for use\nin determining appropriate assessment tools. OPS maintained that the Notice alleged that FGT failed to use\nappropriate assessment methods, it did not allege that FGT failed to take one of the specific actions listed in\n§ 192.917(e)(4).\n\n\n\norder for an operator to be required to select an assessment technology capable of detecting and\nmeasuring longitudinal seam defects.\n35 Respondent argued that the Sanford Lateral had not\nexperienced such a pressure increase or a seam integrity failure prior to the 2019 tool run and as\na result, its LF-ERW pipe was not considered susceptible to failure and use of an ILI tool with\naxial capability in 2019 was not required. OPS disagreed and stated that there was a history of\nseam integrity failures on Respondent’s system including an actionable axial seam defect\nidentified in 2014 on the Sanford Lateral.\nThe axial seam failure threat posed by older LF-ERW pipe, has been a safety issue in the natural\ngas and hazardous liquid pipeline industry for decades due to the known occurrence of\nmanufacturing defects or inclusions in the weld seam. A widely-referenced report on the\nintegrity threat presented by LF-ERW pipe discusses the types of inclusions in older LF-ERW\npipe that make the material susceptible and states that “The likely causes of seam failures that\ncould necessitate a seam-integrity assessment are pressure cycle-induced fatigue and selective\n(grooving) corrosion of the bondline region of the seam.36 OPS has consistently identified LF-\nERW pipe as being subject to failures in the longitudinal seam because of manufacturing defects.\nPipeline accidents involving seam failures can be much more serious than failures involving\nsmaller leaks because a failed seam can propagate longitudinally for some distance along the\npipe and blow-out a large rupture of the pipeline resulting in a large volume of flammable\nproduct being released. OPS issued Alert Notices on January 28, 1988, and again on March 8,\n1989, to inform pipeline operators of the problem. Failures of the longitudinal seam of the pipe\nhave been caused by the growth over time of manufacturing defects in the LF-ERW seams. As\nsummarized in the CAO:\nPHMSA has issued Advisory Bulletins on the safety risks of Low-\nFrequency Welded ERW and Flash-welded Pipe manufactured prior to\n1970. It also issued Alert Notice, ALN-88-01, in January 1988, advising\nowners and operators of natural gas and hazardous liquids pipelines to\nconsider the threat from ERW pipe manufactured prior to 1970. The\noperators were advised to determine whether their pipelines were\nsusceptible to ERW seam failures and address the potential impact on\npipeline integrity.37\n35 Section 192.917(e)(4) states, in relevant part, “Electric Resistance Welded (ERW) pipe. If a covered pipeline\nsegment contains low frequency ERW pipe, lap welded pipe, pipe with longitudinal joint factor less than 1.0 as\ndefined in § 192.113, or other pipe that satisfies the conditions specified in ASME/ANSI B31.8S, Appendices A4.3\nand A4.4, and any covered or non-covered segment in the pipeline system with such pipe has experienced seam\nfailure (including seam cracking and selective seam weld corrosion), or operating pressure on the covered segment\nhas increased over the maximum operating pressure experienced during the preceding 5 years (including abnormal\noperation as defined in § 192.605(c)), or MAOP has been increased, an operator must select an assessment\ntechnology or technologies with a proven application capable of assessing seam integrity and seam corrosion\nanomalies.”\n36 See PHMSA, Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation (Apr. 2004), available online\nat https://www.phmsa.dot.gov/pipeline/gas-transmission-integrity-management/low-frequency-erw-and-lap-welded-\nlongitudinal-seam-evaluation, at page 1; Post-Hearing Brief, at 60.\n37 Florida Gas Transmission Company, Amended Corrective Action Order, CPF No. 4-2020-008-CAO, at 4 (Oct. 1,\n2020).\n\n\n\nIn determining susceptible threats, an operator is required to consider its prior history and\ninternal inspection records.38 Prior to the 2019 tool run, FGT has experienced axial seam issues\non the 15.9-mile length of the Sanford Lateral as well as on the larger 654-mile FGT pipeline\nunit of which the Sanford Lateral is a part. With respect to the Sanford Lateral, FGT’s 2014 ILI\nrun identified an anomaly that was found to be selective seam weld corrosion, a type of axial\ndefect.39 As stated in the CAO:\nThe operator reported that it performed ILI runs of the Sanford Lateral\nin 2014 and 2019. ILI correlation data from these runs show corrosion\ngrowth rates as high as 17 thousandths of an inch per year. The 2019 ILI\nrun had a large amount of corrosion indications in the vicinity of rupture,\nmany over forty percent (40%).\nMost of the pipeline ROW appears to be located in swamp areas with\nheavy vegetation along its borders, making the 12-inch line more\nsusceptible to active external corrosion than other locations.40\nMoreover, FGT remediated such defects in 2015.41 According to the Root Cause Failure\nAnalysis (RCFA):\n2015: Integrity digs are performed in response to the 2014 ILI run, none\nof these digs were within the Black Bear Wilderness Area. One as-found\nanomaly is classified as selective seam weld corrosion (SSWC), however\ncontrary to an understood practice at that time (but not procedurally or best-\npractice documented), no hydrostatic test was performed on the line. Instead\nthis anomaly was remediated with a Class B sleeve. (105, 109, interviews)\nThere were three anomaly digs in total with repairs made on all three.42\nThe 2014 ILI results and the 2015 sleeve installation to repair the identified failure of axial seam\nintegrity occurred within the five-year period preceding the 2019 ILI tool run and was sufficient\nto trigger the requirement to change the 2019 tool selection to one that reliably detects axial\ndefects such as selective seam corrosion. However, FGT did not change the tool selection.\nInstead, in 2019 FGT used a tool that, according to section 6.2 of B31.8S, is “not reliable” for\ndetecting the types of axial defects identified and addressed in 2014-2015.43\nWith regard to the larger 654-mile FGT pipeline unit of which the Sanford Lateral is a part, FGT\n38 49 C.F.R. § 192.917(b) (Apr. 6, 2004).\n39 Root Cause Failure","truncated":true,"body_characters":59276}