ENABLE MISSISSIPPI RIVER TRANSMISSION, LLC — Notice of Probable Violation

party submissionOfficial PDF42023042NOPV_Operator Response to Notice_06212023_(22-235632).pdf#

case documentOfficial PDF42023042NOPV_PCO_05232023_(22-235632).pdf#

case documentOfficial PDF42023042NOPV_PCO_05232023_(22-235632)_text.pdf#

42023042NOPV_Final Order_07162025_(22-235632)_text.pdf, page 1Official PDFJuly 16, 2025 VIA ELECTRONIC MAIL TO: Eric.Amundsen@energytransfer Eric Amundsen Senior Vice President Operations Enable Mississippi River Transmission, LLC 1300 Main Street Houston, TX 77002 Re: CPF No. 4-2023-042-NOPV Dear Mr. Amundsen: Enclosed please find the Final Order issued in the above-referenced case. It withdraws the Notice issued May 23, 2023. Service of the Final Order by e-mail is effective upon the date of transmission and acknowledgement of receipt as provided under 49 CFR § 190.5. Thank you for your cooperation in this matter. Sincerely, Linda Daugherty Acting Associate Administrator for Pipeline Safety Enclosure cc: Bryan Jeffrey Lethcoe, Office of Pipeline Safety Susie Sjulin, Director – Regulatory Compliance, Enable Mississippi River Transmission, LLC, susie.sjulin@energytransfer.com CONFIRMATION OF RECEIPT REQUESTED#

42023042NOPV_Final Order_07162025_(22-235632)_text.pdf, page 2U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION OFFICE OF PIPELINE SAFETY WASHINGTON, D.C. 20590 ____________________________________ In the Matter of ) Enable Mississippi River ) CPF No. 4-2023-042-NOPV Transmission, LLC, ) ) ) ) Respondent. ) ____________________________________) FINAL ORDER From April 4 through November 2, 2022, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), inspected Enable Mississippi River Transmission, LLC’s (Enable or Respondent) natural gas pipeline systems in Arkansas, Illinois, Louisiana, Missouri, Oklahoma, and Texas. Enable is a subsidiary of Energy Transfer, and its natural gas pipeline system is approximately 1,600 miles in length.1 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Respondent, by letter dated May 23, 2023, a Notice of Probable Violation and Proposed Compliance Order (Notice). In accordance with 49 CFR § 190.207, the Notice proposed finding that Enable had committed one violation of 49 CFR Part 191 and proposed ordering Respondent to take certain measures to correct the alleged violation. Energy Transfer responded to the Notice on behalf of Enable by letter dated June 21, 2023 (Response). Enable contested the allegation, offered additional information in response to the Notice, and requested an informal discussion with the Region. Respondent did not request a hearing and therefore has waived its right to one. An informal discussion was held on June 30, 2023. Enable Midstream Partners submitted additional information, including its procedure Operations and Maintenance Procedure 250, Defect Evaluation (Ver. 3, Sep. 23, 2021) (OM-250 Defect Evaluation), on behalf of Enable on July 10, 2023. 1 Mississippi River Transmission Pipeline, ENABLE TRANSFER, https://www.energytransfer.com/operations-map/ (last accessed May 9, 2025).#

42023042NOPV_Final Order_07162025_(22-235632)_text.pdf, page 3WITHDRAWAL OF ALLEGATION The Notice alleged that Respondent violated 49 CFR Part 192, as follows: Item 1: The Notice alleged that Respondent violated 49 CFR § 191.23, which states: § 191.23 Reporting safety-related conditions. (a) Except as provided in paragraph (b) of this section, each operator shall report in accordance with § 191.25 the existence of any of the following safety-related conditions involving facilities in service: (1) …. (9) Any safety-related condition that could lead to an imminent hazard and causes (either directly or indirectly by remedial action of the operator), for purposes other than abandonment, a 20% or more reduction in operating pressure or shutdown of operation of a pipeline, UNGSF, or an LNG facility that contains or processes gas or LNG. Section 191.25(a) further states, in relevant part: § 191.25 Filing safety-related condition reports. (a) Each report of a safety-related condition under § 191.23(a)(1) through (9) must be filed (received by the Associate Administrator) in writing within 5 working days (not including Saturday, Sunday, or Federal holidays) after the day a representative of an operator first determines that the condition exists, but not later than 10 working days after the day a representative of an operator discovers the condition. . . . The Notice alleged that Respondent violated 49 CFR § 191.23(a)(9) by failing to file a safety- related condition (SRC) report within five working days of reducing the operating pressure on the Black River Pipeline by 20 percent in response to an SRC that could lead to an imminent hazard. Specifically, the Notice alleged that on July 6, 2021, Enable received a preliminary magnetic flux leakage axial (MFL-A) report for the Black River Pipeline, the results of which indicated the presence of a 79 percent metal wall loss anomaly within 220 yards of a dwelling. The Notice further alleged that on July 8, 2021, Enable reduced the operating pressure of the Black River Pipeline by 20 percent (i.e., from 619 pounds per square inch (psi) to 495 psi) in response to that anomaly, triggering the obligation to file an SRC report within five working days (i.e., by July 15, 2021) under § 191.23(a)(9). The Notice alleged that Enable did not file an SRC report within five working days; instead, Respondent filed an SRC report on August 2, 2021, for different anomalies (i.e., corrosion with a depth of 96.1 percent and 92.9 percent), the presence of which Respondent verified on July 24, 2021, while excavating certain portions of the Black River Pipeline based on the results of the preliminary in-line inspection (ILI) vendor report.#

42023042NOPV_Final Order_07162025_(22-235632)_text.pdf, page 4Enable contested the allegation in the Notice in its Response. Enable explained that its procedure, Enable Midstream Partners Analysis Reporting Criteria for Magnetic Flux Leakage, Geometry, and IMU, requires ILI vendors to report any metal loss greater than or equal to 70 percent of nominal wall thickness. That procedure also requires the ILI vendor to report any metal loss anomalies over 50 percent that are within fifty feet of any metal loss anomaly that satisfies the 70 percent wall-loss threshold. In addition, for the specific ILI run at issue, Enable asked the ILI vendor to report any metal loss anomalies over 50 percent in the joints immediately upstream and downstream of the 79 percent metal loss anomaly for purposes of including the former in the preliminary dig schedule. Per Enable’s procedures, preliminary anomalies are investigated and assessed in the ditch for calibration and confirmation of tool calls. Enable explained that the ILI vendor identified one metal loss anomaly with a calculated wall loss greater than or equal to 70 percent in its July 6, 2021 preliminary report. The anomaly detail in the preliminary report showed a depth of 79 percent and RSTRENG Pburst -0.85dL of 1726 psi. Based on that and other information from the report, Enable scheduled three preliminary digs (P01, P02, and P03) to allow for an in-the-ditch analysis of four anomalies. Respondent explained that it implemented the 20 percent pressure reduction on July 8, 2021, “to prepare for excavations and analysis of preliminary dig locations P01 and P02.” Enable completed excavations for dig locations P01 and P02, as well as the ML3 pipeline crossing in the dig area, on July 23, 2021. The direct examination technician who observed the P02 anomaly location requested that the pressure of the isolated section be further reduced to permit additional evaluation. After reducing the pressure to 90 psi, Respondent completed the anomaly analysis and determination for digs P01 and P02 on July 24, 2021. That analysis indicated that the dig P01 anomalies, which were initially called as 52 percent metal loss anomalies in the preliminary ILI report, were corrosion with a depth of 96.1 percent and 92.9 percent. Enable determined both anomalies to be SRCs based on that information. The dig P02 anomaly, which was initially called as a 79 percent metal loss anomaly in the preliminary ILI report, was corrosion with a depth of 71.2 percent, which according to Respondent, demonstrated the latter was not an SRC. Because July 24, 2021 was a Saturday, Enable marked the date of determination of the SRCs at P01 as Monday, July 26, 2021. Respondent filed the SRC report with PHMSA on August 2, 2021. Based on these facts, Respondent argued that it timely filed the SRC report within five business days after the date of field verification of the SRC at P01 and that no SRC report was required for the anomaly at P02. Analysis The primary question in this case is whether the P02 anomaly that the ILI vendor identified in its preliminary report as 79 percent wall loss, and Enable’s subsequent 20 percent reduction in the operating pressure of the Black River Pipeline, qualified as an SRC under § 191.23(a)(9). If so, Enable had an obligation to submit an SRC report within 5 working days of discovering that condition. If not, Enable had no obligation to file an SRC report.#

42023042NOPV_Final Order_07162025_(22-235632)_text.pdf, page 5The answer to this question begins with the text of the applicable regulation.2 Section 191.23(a)(9) states, in relevant part, that an operator must report any “safety-related condition that could lead to an imminent hazard and causes (either directly or indirectly by remedial action of the operator) . . . a 20% or more reduction in operating pressure . . . of a pipeline.” Id. The plain text of section 191.23(a)(9) thus prescribes two criteria that must be satisfied to require the submission of an SRC report: (1) the SRC must be a condition “that could lead to an imminent hazard” and (2) the SRC must “cause” the operator (either directly or indirectly) to reduce the operating pressure of the pipeline by 20 percent or more. The violation alleged in the Notice can be resolved solely on the basis of the first criterion. PHMSA has not defined the phrase “imminent hazard” for purposes of the SRC reporting requirements in 49 CFR Part 191, 3 but contemporaneous4 dictionaries defined the term “imminent” as “impending,”5 and “hazard” as “risk.”6,7 The term “could,” which is also used in § 191.23(a)(9), was defined as “should or would be able to,”8 and “lead” was defined as “result (in).”9 Taken together, these definitions suggest that the phrase “could lead to an imminent hazard” in § 191.23(a)(9) should be understood to mean the condition would result in an impending risk. The regulatory history supports that basic understanding. PHMSA adopted the SRC reporting requirements in response to a 1986 congressional mandate. 10 That mandate, as codified at 49 U.S.C. § 60102(h), directed PHMSA to: [P]rescribe regulations requiring each operator of a pipeline facility (except a master meter) to submit to [PHMSA] a written report on any— (A) condition that is a hazard to life, property, or the environment; and (B) safety-related condition that causes or has caused a significant change or restriction in the operation of a pipeline facility. 2 Kisor v. Wilkie, 588 U.S. 558, 573-579 (2019). 3 The phrase “imminent hazard” is defined in 49 CFR § 190.3 for purposes of the emergency order requirements in 49 CFR § 190.236. That definition parrots the text of 49 U.S.C. § 60117(p)(8) (2016), which states, “[i]mminent hazard means the existence of a condition relating to a gas or hazardous liquid pipeline facility that presents a substantial likelihood that death, serious illness, severe personal injury, or a substantial endangerment to health, property, or the environment may occur before the reasonably foreseeable completion date of a formal proceeding begun to lessen the risk of such death, illness, injury or endangerment.” 4 49 CFR 191.23 was promulgated on July 1, 1988. See 53 Fed. Reg. 24942. 5 Imminent, CHAMBERS ENGLISH DICTIONARY (1988), at 712, available at Archive.org. 6 Hazard, CHAMBERS NEW SCHOOL DICTIONARY (1990), at 443, available at Archive.org. 7 Perrin v. United States, 444 U.S. 37, 43 (1979) (“A fundamental cannon of statutory construction is that, unless otherwise defined, words will be interpreted as taking their ordinary, contemporary, common meaning.”). 8 Could, NEW CONCISE WEBSTER’S DICTIONARY (1988), at 72. 9 Lead, COLLINS REFERENCE ENGLISH DICTIONARY (1992), at 277, available at Archive.org. 10 Pipeline safety reauthorization act for fiscal year 1987, Pub. L. 99-516, 100 Stat. 2965 (Oct. 22, 1986).#

42023042NOPV_Final Order_07162025_(22-235632)_text.pdf, page 6As PHMSA explained in the subsequent rulemaking proceeding, Congress enacted § 60102(h) to ensure that operators would notify PHMSA of conditions that, if left unaddressed, might potentially cause a pipeline failure. Congress expected that such notifications would allow PHMSA to investigate the condition and ensure that the operator took appropriate remedial action. 11 In other words, one of Congress’s purposes in enacting § 60102(h) was to “incite government action in time to prevent unsafe conditions from turning into an ‘incident’ or ‘accident.’”12 That understanding of the SRC reporting requirements remains unchanged. 13 In addition, PHMSA published an interpretation and statement of policy concerning the discovery of safety-related conditions from the results of ILI tool runs shortly after adopting the original SRC reporting requirements. Because the time period for reporting begins to run when an operator “discovers” a potentially reportable condition, operators had asked PHMSA to explain when discovery occurs in connection with the use of ILI tools. In the statement of policy, PHMSA explained that: Discovery of a potentially reportable condition occurs when an operator’s representative has adequate information from which to conclude the probable existence of a reportable condition. An operator would have adequate information for each anomaly that is physically examined. Absent physical examination, discovery may occur after the data are calibrated if the “adequate information” test is met. However, the adequacy of the information that pig data provide about anomalous conditions is contingent on a concurrent indication from a number of factors which an operator could conclude the probable existence of a reportable condition. Among these are the sophistication of the pig being used, the reliability of the data, the accuracy of data interpretation, and any other factors known by the operator relative to the condition of the pipeline.14 Returning to the question presented, the issue here is whether the preliminary ILI report provided Enable with sufficient information to conclude that the P02 anomaly was an “imminent hazard” for purposes of the SRC reporting requirements in § 191.23(a)(9). As previously discussed, the preliminary ILI report indicated that the P02 anomaly was a 79 percent pipe wall loss anomaly located within 220 yards of a dwelling. 15 OPS did not allege in the Notice that the P02 anomaly 11 Reporting Unsafe Conditions on Gas and Hazardous Liquid Pipelines and Liquefied Natural Gas Facilities, Notice of Proposed Rulemaking, 52 Fed. Reg. 36068 (Sep. 25, 1987). 12 Reporting Unsafe Conditions on Gas and Hazardous Liquid Pipelines and Liquefied Natural Gas Facilities, Notice of Proposed Rulemaking, 52 Fed. Reg. 36068, 36069 (Sep. 25, 1987). 13 Reporting Unsafe Conditions on Gas and Hazardous Liquid Pipelines and Liquefied Natural Gas Facilities, 53 Fed. Reg. 24942 (Jul. 1, 1988). 14 Transportation of Gas and Hazardous Liquids by Pipeline; Reporting Safety-Related Conditions; Discovery of Conditions by Smart Pigs; Enforcement Rules, Final Rule, 54 Fed. Reg. 32,342, 32343 (Aug. 7, 1989); see also In the Matter of ANR Pipeline Company, CPF No. 3-2011-1011, Final Order (Dec. 31, 2012) (stating that ILI data alone can support a finding of a probable SRC, depending upon the sophistication of the pig being used, the reliability of the data, the accuracy of data interpretation, and any other factors known relative to the condition of the pipeline). 15 Region Recommendation, Enable Mississippi River Transmission, LLC, CPF 4-2023-042-NOPV, dated May 22, 2024, on file with PHMSA.#

42023042NOPV_Final Order_07162025_(22-235632)_text.pdf, page 7qualified as an immediate (or even a one-year) repair condition under the integrity management regulations at 49 CFR § 192.933(d), nor does the record suggest that Enable had any other evidence indicating that the P02 anomaly “could lead to an imminent hazard” or would result in an impending risk to the Black River Pipeline. Moreover, Enable’s subsequent excavation and in-the-ditch analysis revealed that the P02 anomaly was corrosion with a depth of 71.2 percent, a condition less severe than originally indicated in the preliminary ILI report.16 In these circumstances, Enable did not have sufficient information to conclude that the P02 anomaly satisfied the imminent hazard requirement in § 191.23(a)(9), either on the basis of the information provided in the preliminary ILI report or as a result of the information obtained during the subsequent excavation and in-the-ditch analysis.17 OPS has not met its burden of proof to sustain the violation alleged in the Notice. 18 Conclusion OPS has not presented a sufficient factual or legal basis to support the allegation that the July 6, 2021 preliminary ILI report provided Enable with sufficient information to conclude that the P02 anomaly was a condition that “could lead to an immediate hazard” within the meaning of § 191.23(a)(9). Accordingly, after considering all of the evidence, I find there is no basis for finding a violation of § 191.23(a)(9). Based upon the foregoing, I hereby order that the Notice be withdrawn. ___________________________________ __________________________ Linda Daugherty Date Issued Acting Associate Administrator for Pipeline Safety 16 The fact that Enable implemented a 20 percent pressure reduction to perform the excavation and in-the-ditch analysis does not mean that the P02 anomaly was an imminent hazard under § 191.23(a)(9). The imminent hazard and 20 percent pressure reduction criteria are separate and distinct requirements. Both must be satisfied to require the submission of an SRC report. 17 Enable did discover that the P01 anomalies had corrosion at depths of 96.1 percent and 92.9 percent. The P01 anomalies constituted conditions that “could lead to an imminent hazard” or would result in an impending risk, and Enable appropriately filed an SRC report within the required timeframe following that discovery. 18 49 U.S.C. § 60117(b)(1)(F).#