# FLORIDA GAS TRANSMISSION CO — Notice of Probable Violation - **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:** Not available - **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. Official case documents: 42022032NOPV_Final Order_05212024_(20-190995).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_Final%20Order_05212024_(20-190995).pdf 42022032NOPV_Final Order_05212024_(20-190995)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_Final%20Order_05212024_(20-190995)_text.pdf 42022032NOPV_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 42022032NOPV_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 42022032NOPV_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 42022032NOPV_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 42022032NOPV_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 42022032NOPV_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 42022032NOPV_PCP_07222022_(20-190995).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_PCP_07222022_(20-190995).pdf 42022032NOPV_PCP_07222022_(20-190995)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_PCP_07222022_(20-190995)_text.pdf 42022032NOPV_PHC Hearing Scheduled_11012022_(20-190995).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42022032NOPV/42022032NOPV_PHC%20Hearing%20Scheduled_11012022_(20-190995).pdf 42022032NOPV_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 42022032NOPV_PHC Hearing Scheduled_11012022_(20-190995)_text.pdf November 1, 2022 VIA ELECTRONIC MAIL TO: vince.murchison@pipelinelegal.com and bryan.lethcoe@dot.gov Mr. Vince Murchison, Esq. Counsel for Florida Gas Transmission Company Murchison Law Firm, PLLC 325 North St. Paul Street, Suite 2700 Dallas, Texas 75201 Mr. Bryan Lethcoe Director, Southwest Region Pipeline and Hazardous Materials Safety Administration 8701 South Gessner Road, Suite 630 Houston, Texas 77074 Re: Notice of Hearing, Florida Gas Transmission Company CPF No. 4-2022-032-NOPV Dear Mr. Murchison and Mr. Lethcoe: In accordance with 49 C.F.R. § 190.211, an informal hearing will be held regarding the Notice of Probable Violation and Proposed Civil Penalty issued by the Pipeline and Hazardous Materials Safety Administration in the above-referenced case. The hearing will take place on March 22, 2023, beginning at 8:30 a.m. Central Time. The hearing will take place at the PHMSA Southwest Region office, 8701 South Gessner Road, Suite 630, Houston, TX 77074. Upon arrival at the building, attendees will be required to present photo identification to security personnel. A contact phone number for the day of the hearing is (713) 272-2859. At least 10 calendar days prior to the hearing (or by March 13, 2023), both parties must submit and exchange any additional written materials they intend to present at the hearing and the name and email address of each attendee. This information should be provided electronically. Materials not submitted by this date may be excluded. If you have any questions, please do not hesitate to contact me. Sincerely, Larry White Presiding Official cc: Mr. Eric Amundsen, Senior Vice President, Operations, Florida Gas Transmission Co., eric.amundsen@energytransfer.com Ms. Heidi Slinkard, Counsel, Florida Gas Transmission Co., heidi.slinkard@energytransfer.com Mr. Ian Curry, Esq., Counsel, Southwest Region, Office of Pipeline Safety, ian.curry@dot.gov 42022032NOPV_Final Order_05212024_(20-190995)_text.pdf May 21, 2024 VIA ELECTRONIC MAIL TO: tom.long@energytransfer.com Thomas E. Long Chief Executive Officer Energy Transfer LP 1300 Main Street Houston, Texas 77002 Re: CPF No. 4-2022-032-NOPV Dear Mr. Long: Enclosed please find the Final Order issued in the above-referenced case to Florida Gas Transmission Company, LLC, a subsidiary of Energy Transfer LP. It withdraws one of the allegations of violation, makes other findings of violation, and assesses a civil penalty of $409,400. The penalty payment terms are set forth in the Final Order. This enforcement action closes automatically upon receipt of payment. Service of the Final Order by e-mail is effective upon the date of transmission and acknowledgement of receipt 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: Mr. Bryan Lethcoe, Director, Southwest Region, Office of Pipeline Safety, PHMSA Mr. Greg McIlwain, Executive Vice President of Operations, Energy Transfer LP, gregory.mcilwain@energytransfer.com Mr. Eric Amundsen, Senior Vice President of Operations, Energy Transfer LP, eric.amundsen@energytransfer.com Mr. Todd Stamm, Senior Vice President of Operations, Energy Transfer LP, todd.stamm@energytransfer.com Ms. Jennifer Street, Senior Vice President of Operations Services, Energy Transfer LP, jennifer.street@energytransfer.com Ms. Heidi Murchison, Chief Counsel, Energy Transfer LP, heidi.murchison@energytransfer.com Mr. Leif Jensen, Vice President of Tech Services, Energy Transfer LP, leif.jensen@energytransfer.com Mr. Todd Nardozzi, Director of Regulatory Compliance, Energy Transfer LP, todd.nardozzi@energytransfer.com Ms. Susie Sjulin, Director of Regulatory Compliance, Energy Transfer LP, susie.sjulin@energytransfer.com Mr. Vince Murchison, Esq., Outside Counsel for Florida Gas Transmission Co., Murchison Law Firm, PLLC, vince.murchison@pipelinelegal.com CONFIRMATION OF RECEIPT REQUESTED U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION OFFICE OF PIPELINE SAFETY WASHINGTON, D.C. 20590 ______________________________________ In the Matter of ) Florida Gas Transmission Company, LLC, ) CPF No. 4-2022-032-NOPV a subsidiary of Energy Transfer LP, ) ) ) ) Respondent. ) ______________________________________) FINAL ORDER From September 13, 2020 through September 23, 2021, 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 and investigation of the facilities and records of Florida Gas Transmission Company, LLC’s (FGT or Respondent) 12- inch diameter Sanford Lateral natural gas transmission pipeline following a rupture of the Sanford Lateral that occurred on September 10, 2020, in Sanford, Florida.1 The escaping natural gas ignited and burned an area measuring approximately 515 by 100 feet. The burn also damaged and knocked down three overhead powerlines owned by Duke Energy and about 32 homes and 93 businesses had to be evacuated. There were no reported injuries or fatalities. On September 18, 2020, PHMSA issued a Corrective Action Order (CAO) to FGT (CPF 4-2020-008-CAO) that required a shutdown of the pipeline segment and required a records review and verification, a review of prior inline inspection results, a metallurgical laboratory examination of the ruptured pipe, a root cause failure analysis, a pressure restriction upon restart, and a remedial work plan. With PHMSA’s Southwest Region oversight, FGT repaired the pipe at the rupture site and returned the Sanford Lateral to service on December 7, 2020, under the terms of the CAO. As a result of the inspection and investigation, the Director, Southwest Region, OPS (Director), issued to Respondent, by letter dated July 22, 2022, a Notice of Probable Violation and Proposed Civil Penalty (Notice). In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that FGT committed three violations of 49 C.F.R. Part 192 and proposed assessing a total civil penalty of $834,400 for the alleged violations. 1 FGT is a large interstate natural gas pipeline company that operates approximately 5,300 miles of gas transmission lines that originate in Galveston Bay and extend through various states including Florida. FGT is owned by Citrus Corporation, a joint venture between Energy Transfer LP and Kinder Morgan, Inc. Energy Transfer LP website, Natural Gas, available online at https://www.energytransfer.com/natural-gas (last accessed Jan. 30, 2024). FGT responded to the Notice by letter dated September 30, 2022 (Response), as supplemented by material submitted on March 13, 2023 (Pre-hearing Submission). FGT contested the allegations and requested an informal hearing. A hearing was subsequently held on March 22, 2023, in Houston, Texas, before a Presiding Official from the Office of Chief Counsel, PHMSA. At the hearing, Respondent was represented by counsel. After the hearing, Respondent provided additional written material for the record by letter dated April 21, 2023 (Post-hearing submission). The Director provided a recommendation on May 22, 2023 (Recommendation) and FGT submitted a reply to the Recommendation on June 12, 2023 (Reply). FINDINGS OF VIOLATION The Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows: Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 192.619(a)(3), which states: § 192.619 Maximum allowable operating pressure: Steel or plastic pipelines. (a) No person may operate a segment of steel or plastic pipeline at a pressure that exceeds a maximum allowable operating pressure (MAOP) determined under paragraph (c), (d), or (e) of this section, or the lowest of the following: (1) … (3) The highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column. This pressure restriction applies unless the segment was tested according to the requirements in paragraph (a)(2) of this section after the applicable date in the third column or the segment was uprated according to the requirements in subpart K of this part: Pipeline segment Pressure date Test date (i) Onshore regulated gathering pipeline (Type A or Type B under § 192.9(d)) that first became subject to this part (other than §192.612) after April 13, 2006 March 15, 2006, or date pipeline becomes subject to this part, whichever is later 5 years preceding applicable date in second column. (ii) Onshore regulated gathering pipeline (Type C under § 192.9(d)) that first became subject to this part (other than § 192.612) on or after May 16, 2022 May 16, 2023, or date pipeline becomes subject to this part, whichever is later 5 years preceding applicable date in second column. (iii) Onshore transmission pipeline that was a gathering pipeline not subject to this part before March 15, 2006 March 15, 2006, or date pipeline becomes subject to this part, whichever is later 5 years preceding applicable date in second column. (iv) Offshore gathering pipelines July 1, 1976 July 1, 1971. (v) All other pipelines July 1, 1970 July 1, 1965. The Notice alleged that Respondent violated 49 C.F.R. § 192.619(a)(3) by failing to establish a maximum allowable operating pressure (MAOP) for its Sanford Lateral in accordance with § 192.619(a)(3). Specifically, the Notice alleged that FGT did not have records to substantiate the highest actual operating pressure that the segment was subjected to during the five years prior to MAOP establishment. In its Response and at the hearing, FGT contested the allegation and provided information concerning the history of the pipeline going back to 1959 indicating that former owners and operators of the pipeline considered the MAOP in 1970 to be 713 psig. Respondent explained that it maintained a one-page historical record from 1989 referred to by FGT as the “Gold Sheet” that in its view substantiated the current MAOP for the Sanford Lateral, 2 and argued that the regulations did not require it to have records to substantiate the MAOP indicated on the Gold Sheet or otherwise substantiate the highest actual operating pressure that the segment was subjected to during the five years prior to MAOP establishment. FGT further argued that the Notice should have alleged a violation under the MAOP Reconfirmation section in § 192.624 which was added to Part 192 in 2019, and not establishment of MAOP under § 192.619. At the hearing, OPS maintained that it was unable to verify or substantiate, based on FGT records, that the Sanford Lateral was subjected to 713 psig during the five-year period prior to July 1, 1970. FGT argued that “[n]o indication exists that Sanford Lateral was not subjected to a highest pressure of 713 psig between 1965 and 1970.”3 OPS stated that Respondent did not provide any records that would substantiate the establishment of an MAOP of 713 psig and that the first pressure records provided to substantiate the MAOP were from the 2020 hydrostatic test conducted pursuant to the CAO. To demonstrate compliance with § 192.619(a)(3), operators are required to have records that enable PHMSA to “verify that the entire pipeline was subjected to that pressure sometime during the five-year period prior to July 1, 1970.”4 Consistent with this requirement, PHMSA issued enforcement guidance in 2017 reminding operators that a probable violation may be found if an 2 PHMSA Violation Report, Exhibit A. 3 Post-hearing Submission, at 18. 4 West Texas Gas, Final Order, CPF No. 4-2004-1007, at 6 (Sept. 13, 2006). operator cannot provide records to “substantiate the established MAOP.”5 With regard to the 1989 Gold Sheet, FGT acknowledged that it did not have pressure logs or other such records of pressure readings associated with it, but suggested that Enron, the former operator of the Sanford Lateral, must have reviewed such records when creating the Gold Sheet. That assertion, however, does not take the place of records necessary to verify MAOP.6 Respondent also provided a declaration from a current FGT employee who had recently reviewed the specifications of various valves and other components of the pipeline.7 The declaration stated that “no component on the pipeline at the time of the September 10, 2020 incident had, and no component on the pipeline currently has, a design pressure that is less than 713 psig which is the established MAOP of the pipeline. However, this affidavit is insufficient to satisfy § 192.619(c) because it failed to include any operating pressure readings from July 1, 1965 – July 1, 1970. In addition, OPS has advised operators that affidavits on their own are not verifiable records sufficient to meet the requirement to establish MAOP.8 Without actual pressure logs or similar records demonstrating actual pressures experienced during this five-year time period, OPS cannot verify that the MAOP was properly established. At the hearing, FGT also contended that even though the Gold Sheet does not reflect any actual historical operating pressure readings, it is in some sense a record of the overall “limiting factor” on the Sanford Lateral.9 Thus, it appears FGT accepts that 713 psig is not a reflection of the actual operating pressure from 1965 to 1970, but instead reflects MAOP established under § 192.619(a)(1). The Gold Sheet, however, cannot be both. FGT also acknowledged that the Gold Sheet may itself be inaccurate. FGT stated that “[i]t would not be unreasonable to conclude” that the MAOP Authorization Sheet “inadvertently chose ‘619(c).”10 Because FGT failed to substantiate its MAOP with § 192.619(c), it cannot rely on § 192.619(c) as a defense to the alleged violation of § 192.619(a)(3). For the same reasons that the records fail to demonstrate compliance with § 192.619(c), FGT failed to provide records to substantiate its establishment of MAOP in accordance with § 192.619(a)(3).11 If the Gold Sheet does in fact 5 PHMSA, Operations & Maintenance Enforcement Guidance Part 192 Subparts L and M, at 81 (July 21, 2017), available online at https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/regulatory- compliance/pipeline/enforcement/5776/o-m-enforcement-guidance-part-192-7-21-2017.pdf. 6 PHMSA’s enabling statute requires operators to “make” and “maintain records” to demonstrate compliance with the pipeline safety laws and regulations. See 49 U.S.C. § 60117(c). The failure to maintain records, by itself, can be a violation of the pipeline safety regulations. See 49 C.F.R. § 192.619(f). 7 Post-hearing Submission, Exhibit 3. 8 Pipeline Safety: Verification of Records: ADB-2012-06, 77 Fed. Reg. 26,822, 26,823 (May 7, 2012) (“In general, the only acceptable use of an affidavit would be as a complementary document, prepared and signed at the time of the test or inspection by an individual who would have reason to be familiar with the test or inspection.”). 9 Post-hearing Submission, at 17. 10 Post-hearing Submission, at 18. 11 FGT suggested it established MAOP under other provisions of § 192.619(a) and that it is PHMSA’s burden to demonstrate § 192.619(a)(3) is the lowest of the options in subparagraph (a). However, the absence of any one calculation under § 192.619(a)(1)-(4) renders the whole analysis unsubstantiated. If the MAOP “established” under § 192.619(a)(3) cannot be verified or substantiated it cannot form the basis for a valid MAOP. reflect uncertainty about whether it was intended to apply for purposes of subsection (a) or subsection (c), that only reinforces the conclusion that it does not substantiate the establishment of MAOP. With respect to the consistency of this case with PHMSA’s position in prior proceedings, in the above-referenced West Texas Gas proceeding the agency found that, “PHMSA must be able to verify” that a pipeline was subjected to the pressure if MAOP was established under § 192.619(c). In West Texas Gas, the Acting Associate Administrator found that two single documents, each with different MAOPs, were insufficient to establish MAOP because neither number could be corroborated with other records.12 Similarly in the present case, FGT has failed to provide any corroborating records (i.e., operating pressure records) that support the selection of 713 psig on the MAOP Authorization Sheet. In fact, FGT suggested that 713 psig was selected based on the design pressure, and not historical operating pressure.13 This uncertainty supports finding this violation as PHMSA cannot verify how MAOP was established. This point is further emphasized by FGT’s efforts spent speculating on what the prior operator may or may not have reviewed in creating the MAOP Authorization Sheet.14 Similarly, in the El Paso Natural Gas Company, LLC proceeding, OPS alleged that the operator failed to establish MAOP in accordance with § 192.619(a)(3). In the final order, the Associate Administrator for Pipeline Safety found the operator in violation of 192.619(a)(3) for failing to have records in support of its (pre-1970) MAOP establishment. Thus, the final order found the operator in violation of § 192.619(a)(3) under the same charge as alleged here in this proceeding.15 In both the West Texas Gas and El Paso proceedings cases, the operators had established an MAOP using historical operating pressure, but could not provide any operating pressure records to support that number. Thus, OPS is correct that its position in this case is consistent with the outcome of both prior proceedings. Finally, FGT argued that any allegation of non-compliance should have cited the MAOP reconfirmation requirements in § 192.624 because it was a newer regulation and “obviated” the provisions in § 192.619(c).16 FGT cited the above referenced El Paso proceeding as support for its position that MAOP reconfirmation obviated section 192.619.17 Section 192.624 was promulgated, in part, to address a congressional mandate in Section 23 of the 2011 Pipeline Safety Act that “requires the verification of records for pipe in Class 3 and Class 4 locations, and high consequence areas in Class 1 and Class 2 locations, to ensure they accurately reflect the physical and operational characteristics of the pipelines and confirm the established MAOP of 12 West Texas Gas, Final Order, CPF No. 4-2004-1007, at 6 (Sept. 13, 2006). 13 Post-hearing Submission, at 18. 14 Id., at 17-18. 15 El Paso Natural Gas Company, LLC, Notice of Probable Violation, CPF No. 4-2019-1010, at 2 (Oct. 1, 2019). 16 Post-hearing Submission at 25; see Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments, 84 Fed. Reg. 52,180 (Oct. 1, 2019). 17 See El Paso Natural Gas Company, LLC, Final Order, CPF No. 4-2019-1010 (July 22, 2020). the pipelines.”18 Section 192.624, however, is complementary to, but does not replace, § 192.619. MAOP reconfirmation instead reiterated the importance of verifiable documentation to support MAOP establishment. Operators are required to establish MAOP under § 192.619 and then, if the criteria in § 192.624(a) are met, operators must reconfirm MAOP according to that section. Nothing in the MAOP reconfirmation regulatory record suggests that this regulation replaced the MAOP Establishment requirements. 19 Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 192.619 by failing to establish a MAOP for its Sanford Lateral in accordance with § 192.619(a)(3). Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(a)(1), which states: § 192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (a) Threat identification. An operator must identify and evaluate all potential threats to each covered pipeline segment. Potential threats that an operator must consider include, but are not limited to, the threats listed in ASME/ANSI B31.8S (incorporated by reference, see § 192.7), section 2, which are grouped under the following four categories: (1) Time dependent threats such as internal corrosion, external corrosion, and stress corrosion cracking; The Notice alleged that Respondent violated 49 C.F.R. § 192.917(a)(1) by failing to identify and evaluate all potential threats to each covered pipeline segment in its natural gas pipeline systems in accordance with § 192.917(a)(1). Specifically, the Notice alleged that FGT failed to include the Sanford Lateral as part of its stress corrosion cracking (SCC) program prior to the September 10, 2020 incident. In its Response and at the hearing, FGT contested the allegation and explained that while it was generally aware of the potential of SCC to be an integrity threat, after appropriate application of the relevant factors it had insufficient reason to include the Sanford Lateral in its SCC program. Respondent stated that the only indication of SCC on Sanford Lateral came after the September 10, 2020 incident when the post-incident metallurgical report was received. 20 As the basis for its allegation that the Sanford Lateral was required to have been included in FGT’s SCC program, OPS stated that Respondent has 30 pipelines and 13 laterals in its SCC program with pipe specifications it believed were similar to the Sanford Lateral, and that SCC had been found on pipelines in the vicinity. Respondent strongly disagreed. Respondent’s Director of Pipeline Integrity testified that the 30 pipelines and 13 laterals OPS mentioned are not in fact the same as Sanford Lateral and that they have different seam type and coating, 18 84 Fed. Reg., at 52,234. 19 The MAOP Reconfirmation Rule made conforming changes to § 192.619 and revised the test pressure factors but otherwise retained each provision. See id. Thus, FGT’s assertions that MAOP Reconfirmation replaced MAOP Establishment is unsupported by the regulatory record. 20 Id., at 29-30. different grade steel, different vintage (age), different manufacturer, and different wall thickness and diameter. FGT correctly noted that just because one pipeline may have some of the same characteristics as another does not automatically mean that all of them will be susceptible to SCC. FGT argued that PHMSA’s inference that all of those pipelines are in the vicinity of the Sanford Lateral was also incorrect and explained that some were hundreds of miles distant.21 With regard to OPS’ contention that, prior to the incident, the Sanford Lateral should have been included in Respondent’s SCC program, FGT argued that the Sanford Lateral simply did not meet the applicable criteria to be subjected to the program. Respondent’s Director of Pipeline Integrity testified that its pipelines are evaluated for SCC all the time, and, had SCC been found or had Sanford Lateral been determined to be susceptible to SCC, it would have been added to the program, as occurred after the 2020 incident.22 Respondent noted that section 192.917(a), Threat Identification, directs operators to identify and evaluate all potential threats to each covered pipeline segment, including but not limited to those identified in ASME/ANSI B31.8S-2004 (B31.8S), section 2. Of the four categories established in Section 192.917(a)(1)-(4), OPS alleged a violation of only subsection (1), “time dependent threats such as internal corrosion, external corrosion, and stress corrosion cracking.”23 Section 2.3.3 of B31.8S, Risk Assessment, refers the reader to a prescriptive approach presented in Appendix A. Section A3.3 of Appendix A provides that each segment should be assessed for risk for the possible threat of SCC if all of the following criteria are present: ASME B31.8S-2004 - SCC Threat Susceptibility Review (a) Operating stress > 60% SMYS (b) Operating temperature > 100o Fahrenheit (c) Distance from compressor station ≤ 20 miles (d) Age ≥ 10 years (e) All corrosion coating systems other than fusion-bonded epoxy (FBE).24 Respondent explained that the Sanford Lateral fails to meet three of those five criteria. The only two criteria met are (d) age ≥ 10 years given that Sanford Lateral was constructed in 1959, and (e) all corrosion coating systems other than fusion-bonded epoxy given that the greater proportion of Sanford Lateral is coated with Polyken tape coating.25 With regard to the first of 21 Post-hearing Submission, at 30-31. 22 Id., at 31. 23 Id., at 27. 24 Case File Exhibit 5, PSVR Ex. C, ASME B31.8S, at 43 (PDF p. 176). the three criteria that the Sanford Lateral does not meet, criterion (a) operating stress > 60% SMYS, Respondent presented information showing that the Sanford Lateral operates at a maximum stress level of 49% SMYS. Second, regarding criterion (b) operating temperature > 100o Fahrenheit, Respondent’s Vice President of Operations for the Southeast Division testified that Sanford Lateral over the last six years has operated between 61 and 84 degrees Fahrenheit and that this temperature range is typical for operating conditions on the Sanford Lateral. Regarding criterion (c) distance from compressor station ≤ 20 miles, Respondent presented information showing that the beginning of Sanford Lateral at the takeoff is approximately 39 miles from the upstream compressor station.26 Respondent is correct that B31.8S indicates that only if “all” criteria of Section A3.3 of Appendix A are met is a segment “to be assessed for risk of the possible threat of SCC” but only two were met27 While they are not mandatory criteria, B31.8S contains additional factors that an operator must consider for determining whether a segment of pipeline is susceptible to the SCC threat. Those are: (a) one or more service incidents was caused by either high pH SCC or near neutral pH SCC; and (b) one or more hydrostatic test breaks or leaks was caused by one of the two types of SCC. Respondent’s witnesses testified that no service incident was caused by either type of SCC prior to the 2020 incident, and no hydrostatic test leaks or breaks were experienced on the Sanford Lateral.28 B31.8S also requires an operator to consider previous SCC history. Respondent showed that the only indication of SCC on Sanford Lateral came after the incident, when the post-incident metallurgical report was received.29 Unlike a component widely known to have manufacturing defects that can be identified by an operator in various ways, SCC is an issue that can take decades to develop and typically needs to be confirmed by metallurgical analysis. As FGT correctly noted, many pipelines never experience SCC at all. While OPS is correct that a pipeline operator is obligated to address the potential for SCC on its pipelines, the issue to be determined here is whether a violation of the code as it currently exists has been proven. Under circumstances in which a pipeline segment has no history of SCC ever being identified and does not have substantially the same material and operating characteristics as pipe that has been deemed susceptible to SCC, 30 OPS has the burden of establishing that such a segment should have been treated as a SCC segment in a given operator’s SCC program. 31 In this instance, the evidence presented by OPS fell short of meeting 25 Post-hearing Submission, at 28. 26 Id. 27 Id., at 29. 28 Id. 29 Id., at 29-30. 30 Respondent’s Director of Pipeline Integrity testified that the 30 pipelines and 13 laterals OPS mentioned are not in fact the same as Sanford Lateral and that they have different seam type and coating, different grade steel, different vintage (age), different manufacturer, and different wall thickness and diameter. 31 Of course, now that near-neutral pH SCC has been identified in connection with FGT’s analysis of the September 10, 2020 incident, Respondent is not disputing the need to include the Sanford Lateral in its SCC program going forward. that burden. Accordingly, after considering all of the evidence, I find that OPS did not establish that Respondent was out of compliance with the cited regulation. Based upon the foregoing, I hereby order that Item 2 be withdrawn. Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 192.937(c)(1), which states: § 192.937 What is a continual process of evaluation and assessment to maintain a pipeline’s integrity? (a) … (c) Assessment methods. In conducting the integrity reassessment, an operator must assess the integrity of the line pipe in the covered segment by any of the following methods as appropriate for the threats to which the covered segment is susceptible (see § 192.917), or by confirmatory direct assessment under the conditions specified in § 192.931. (1) Internal inspection tool or tools capable of detecting corrosion, and any other threats to which the covered segment is susceptible. An operator must follow ASME/ANSI B31.8S (ibr, see § 192.7), section 6.2 in selecting the appropriate internal inspection tools for the covered segment.32 The Notice alleged that Respondent violated 49 C.F.R. § 192.937(c)(1) by failing to follow B31.8S, section 6.2 in selecting the appropriate internal inspection tools for each covered segment. Specifically, the Notice alleged that although the Sanford Lateral consisted largely of low-frequency electric-resistance welded (LF-ERW) pipe manufactured by Youngstown Sheet & Tube of 1959 vintage known to be susceptible to axial seam defects, FGT used an in-line inspection (ILI) tool for its ILI runs in 2014 and 2019 that was designed primarily to evaluate circumferential defects rather than axial defects. In its Response and at the hearing, FGT contested the allegation and argued that although the Sanford Lateral largely did consist of LF-ERW pipe, no assessment for this threat was prompted by 49 C.F.R. § 192.937(c)(1). 33 FGT argued that the cited regulation should be read together with § 192.917(e)(4). 34 This provision states that if a covered pipeline segment contains LF- ERW pipe, lap welded pipe, or other conditions specified in B31.8S, Appendices A4.3 and A4.4, any covered or noncovered segment in the pipeline system with such pipe must have experienced a pressure increase over MAOP or a seam integrity failure during the preceding five years in 32 Section 192.937(c) and (d) were amended on October 1, 2019, after FGT conducted its 2014 and 2019 ILIs. 33 Post-hearing Submission, at 37-38. 34 OPS disagreed, noting that § 192.917(a) outlines the process operators must follow to determine which threats their pipelines are susceptible to. However, section 192.917(e)(4) sets forth specific actions an operator must take to address known issues with ERW pipe. Section 192.917(e)(4) does not prescribe an exclusive list of criteria for use in determining appropriate assessment tools. OPS maintained that the Notice alleged that FGT failed to use appropriate assessment methods, it did not allege that FGT failed to take one of the specific actions listed in § 192.917(e)(4). order for an operator to be required to select an assessment technology capable of detecting and measuring longitudinal seam defects. 35 Respondent argued that the Sanford Lateral had not experienced such a pressure increase or a seam integrity failure prior to the 2019 tool run and as a result, its LF-ERW pipe was not considered susceptible to failure and use of an ILI tool with axial capability in 2019 was not required. OPS disagreed and stated that there was a history of seam integrity failures on Respondent’s system including an actionable axial seam defect identified in 2014 on the Sanford Lateral. The axial seam failure threat posed by older LF-ERW pipe, has been a safety issue in the natural gas and hazardous liquid pipeline industry for decades due to the known occurrence of manufacturing defects or inclusions in the weld seam. A widely-referenced report on the integrity threat presented by LF-ERW pipe discusses the types of inclusions in older LF-ERW pipe that make the material susceptible and states that “The likely causes of seam failures that could necessitate a seam-integrity assessment are pressure cycle-induced fatigue and selective (grooving) corrosion of the bondline region of the seam.36 OPS has consistently identified LF- ERW pipe as being subject to failures in the longitudinal seam because of manufacturing defects. Pipeline accidents involving seam failures can be much more serious than failures involving smaller leaks because a failed seam can propagate longitudinally for some distance along the pipe and blow-out a large rupture of the pipeline resulting in a large volume of flammable product being released. OPS issued Alert Notices on January 28, 1988, and again on March 8, 1989, to inform pipeline operators of the problem. Failures of the longitudinal seam of the pipe have been caused by the growth over time of manufacturing defects in the LF-ERW seams. As summarized in the CAO: PHMSA has issued Advisory Bulletins on the safety risks of Low- Frequency Welded ERW and Flash-welded Pipe manufactured prior to 1970. It also issued Alert Notice, ALN-88-01, in January 1988, advising owners and operators of natural gas and hazardous liquids pipelines to consider the threat from ERW pipe manufactured prior to 1970. The operators were advised to determine whether their pipelines were susceptible to ERW seam failures and address the potential impact on pipeline integrity.37 35 Section 192.917(e)(4) states, in relevant part, “Electric Resistance Welded (ERW) pipe. If a covered pipeline segment contains low frequency ERW pipe, lap welded pipe, pipe with longitudinal joint factor less than 1.0 as defined in § 192.113, or other pipe that satisfies the conditions specified in ASME/ANSI B31.8S, Appendices A4.3 and A4.4, and any covered or non-covered segment in the pipeline system with such pipe has experienced seam failure (including seam cracking and selective seam weld corrosion), or operating pressure on the covered segment has increased over the maximum operating pressure experienced during the preceding 5 years (including abnormal operation as defined in § 192.605(c)), or MAOP has been increased, an operator must select an assessment technology or technologies with a proven application capable of assessing seam integrity and seam corrosion anomalies.” 36 See PHMSA, Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation (Apr. 2004), available online at https://www.phmsa.dot.gov/pipeline/gas-transmission-integrity-management/low-frequency-erw-and-lap-welded- longitudinal-seam-evaluation, at page 1; Post-Hearing Brief, at 60. 37 Florida Gas Transmission Company, Amended Corrective Action Order, CPF No. 4-2020-008-CAO, at 4 (Oct. 1, 2020). In determining susceptible threats, an operator is required to consider its prior history and internal inspection records.38 Prior to the 2019 tool run, FGT has experienced axial seam issues on the 15.9-mile length of the Sanford Lateral as well as on the larger 654-mile FGT pipeline unit of which the Sanford Lateral is a part. With respect to the Sanford Lateral, FGT’s 2014 ILI run identified an anomaly that was found to be selective seam weld corrosion, a type of axial defect.39 As stated in the CAO: The operator reported that it performed ILI runs of the Sanford Lateral in 2014 and 2019. ILI correlation data from these runs show corrosion growth rates as high as 17 thousandths of an inch per year. The 2019 ILI run had a large amount of corrosion indications in the vicinity of rupture, many over forty percent (40%). Most of the pipeline ROW appears to be located in swamp areas with heavy vegetation along its borders, making the 12-inch line more susceptible to active external corrosion than other locations.40 Moreover, FGT remediated such defects in 2015.41 According to the Root Cause Failure Analysis (RCFA): 2015: Integrity digs are performed in response to the 2014 ILI run, none of these digs were within the Black Bear Wilderness Area. One as-found anomaly is classified as selective seam weld corrosion (SSWC), however contrary to an understood practice at that time (but not procedurally or best- practice documented), no hydrostatic test was performed on the line. Instead this anomaly was remediated with a Class B sleeve. (105, 109, interviews) There were three anomaly digs in total with repairs made on all three.42 The 2014 ILI results and the 2015 sleeve installation to repair the identified failure of axial seam integrity occurred within the five-year period preceding the 2019 ILI tool run and was sufficient to trigger the requirement to change the 2019 tool selection to one that reliably detects axial defects such as selective seam corrosion. However, FGT did not change the tool selection. Instead, in 2019 FGT used a tool that, according to section 6.2 of B31.8S, is “not reliable” for detecting the types of axial defects identified and addressed in 2014-2015.43 With regard to the larger 654-mile FGT pipeline unit of which the Sanford Lateral is a part, FGT 38 49 C.F.R. § 192.917(b) (Apr. 6, 2004). 39 Root Cause Failure - **truncated:** true - **body characters:** 59276