{"operation":"document","citation":"CPF 42021020NOA","title":"ENERGY TRANSFER COMPANY — Notice of Amendment","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2021-12-01","effective_on":null,"summary":"CLOSED notice of amendment citing 192.907(a), 192.915(a), 192.927(c)(5)(ii), 192.929(a), 192.929(b), 192.933(a), 192.933(b), 192.935(a), 192.935(c), 192.937(a), 192.937(b), 192.941(a), 192.941(b)(1), 192.941(b)(2)(ii), 192.941(c).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-42021020noa.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-42021020noa.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-42021020noa","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/42021020NOA","body":"Notice of Amendment involving ENERGY TRANSFER COMPANY. PHMSA's enforcement data identifies the cited regulations as 192.907(a),  192.915(a),  192.927(c)(5)(ii),  192.929(a),  192.929(b),  192.933(a),  192.933(b),  192.935(a),  192.935(c),  192.937(a),  192.937(b),  192.941(a),  192.941(b)(1),  192.941(b)(2)(ii),  192.941(c). The case was opened on 2021-12-01 and is reported as closed as of 2022-03-04. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n42021020NOA_Closure Letter_03042022_(21-207373).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42021020NOA/42021020NOA_Closure%20Letter_03042022_(21-207373).pdf\n\n42021020NOA_Closure Letter_03042022_(21-207373)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/42021020NOA/42021020NOA_Closure%20Letter_03042022_(21-207373)_text.pdf\n\n42021020NOA_Notice of Amendment_12012021_(21-207373).pdf: https://primis.phmsa.dot.gov/enforcement-documents/42021020NOA/42021020NOA_Notice%20of%20Amendment_12012021_(21-207373).pdf\n\n42021020NOA_Notice of Amendment_12012021_(21-207373)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/42021020NOA/42021020NOA_Notice%20of%20Amendment_12012021_(21-207373)_text.pdf\n\n42021020NOA_Closure Letter_03042022_(21-207373)_text.pdf\n\nELECTRONIC MAIL - RETURN RECEIPT REQUESTED\nMarch 4, 2022\nMatthew Ramsey\nPresident & Chief Executive Officer\nEnergy Transfer Company\n1300 Main Street\nHouston, Texas 77002\nCPF 4-2021-020-NOA\nDear Mr. Ramsey:\nFrom May 10, 2021 through May 13, 2021, representatives of the Pipeline and Hazardous\nMaterials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code\n(U.S.C.), inspected Energy Transfer Company’s (ETC) Integrity Management Plan (IMP)\nprocedures for its gas facilities. As a result of the inspection, Energy Transfer was issued a Notice\nof Amendment (Notice) on December 1, 2021, which proposed amendments to its procedures.\nAfter being granted a time extension for its response to the Notice, ETC submitted its amended\nprocedures on February 14, 2022. PHMSA staff reviewed the amended procedures, and it appears\nthat the inadequacies outlined in the Notice have been corrected.\nThis letter is to inform you no further action is necessary and this case is now closed. Thank you\nfor your cooperation.\nSincerely,\nMary L. McDaniel, P.E.\nDirector, Southwest Region\nPipeline and Hazardous Materials Safety Administration\ncc: Eric Amundsen, Sr. VP, Energy Transfer, eric.amundsen@energytransfer.com\nTodd Nardozzi, Director Regulatory Compliance, Energy Transfer,\ntodd.nardozzi@energytransfer.com\n\n42021020NOA_Notice of Amendment_12012021_(21-207373)_text.pdf\n\nNOTICE OF AMENDMENT\nELECTRONIC MAIL - RETURN RECEIPT REQUESTED\nDecember 1, 2021\nMatthew Ramsey\nPresident & Chief Executive Officer\nEnergy Transfer Company\n1300 Main Street\nHouston, Texas 77002\nCPF 4-2021-020-NOA\nDear Mr. Ramsey:\nFrom May 10, 2021 through May 13, 2021, representatives of the Pipeline and Hazardous\nMaterials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code\n(U.S.C.), inspected Energy Transfer Company’s (ETC) Integrity Management Plan (IMP)\nprocedures for its gas facilities via video teleconference.\nBased on the inspection, PHMSA identified the apparent inadequacies found within ETC’s plans\nor procedures, as described below:\n1. § 192.907 What must an operator do to implement this subpart?\n(a) General. No later than December 17, 2004, an operator of a covered pipeline\nsegment must develop and follow a written integrity management program that\ncontains all the elements described in § 192.911 and that addresses the risks on each\ncovered transmission pipeline segment. The initial integrity management program\nmust consist, at a minimum, of a framework that describes the process for\nimplementing each program element, how relevant decisions will be made and by\nwhom, a time line for completing the work to implement the program element, and\nhow information gained from experience will be continuously incorporated into the\nprogram. The framework will evolve into a more detailed and comprehensive\nprogram. An operator must make continual improvements to the program.\n\n\n\n§ 192.915 - What knowledge and training must personnel have to carry out an\nintegrity management program?\n(a) Supervisory personnel. The integrity management program must provide that each\nsupervisor whose responsibilities relate to the integrity management program\npossesses and maintains a thorough knowledge of the integrity management program\nand of the elements for which the supervisor is responsible. The program must\nprovide that any person who qualifies as a supervisor for the integrity management\nprogram has appropriate training or experience in the area for which the person is\nresponsible.\nETC’s written IMP procedures are inadequate because they do not include a requirement that\nsupervisory personnel must possess and maintain a thorough knowledge of the integrity\nmanagement program procedures in accordance with §§ 192.907 and 192.915(a). Specifically,\nETC’s Pipeline Integrity Management Plan, ETC GAS IMP_Rev013 04012021, Section 11:\nQualification and Training (Revision Date: April 1, 2021) states: “The integrity management\nprocess must be executed, and the results reviewed by qualified personnel.”\nETC must amend its procedures to include a requirement that supervisory personnel will\nmaintain and possess a thorough knowledge of the integrity management program procedures\nin accordance with §§ 192.907 and 192.915(a).\n2. § 192.907 What must an operator do to implement this subpart?\n(a) General. No later than December 17, 2004, an operator of a covered pipeline\nsegment must develop and follow a written integrity management program that\ncontains all the elements described in § 192.911 and that addresses the risks on each\ncovered transmission pipeline segment. The initial integrity management program\nmust consist, at a minimum, of a framework that describes the process for\nimplementing each program element, how relevant decisions will be made and by\nwhom, a time line for completing the work to implement the program element, and\nhow information gained from experience will be continuously incorporated into the\nprogram. The framework will evolve into a more detailed and comprehensive\nprogram. An operator must make continual improvements to the program.\n§ 192.933 - What actions must be taken to address integrity issues?\n(a) General requirements. An operator must take prompt action to address all\nanomalous conditions the operator discovers through the integrity assessment. In\naddressing all conditions, an operator must evaluate all anomalous conditions and\nremediate those that could reduce a pipeline's integrity. An operator must be able to\ndemonstrate that the remediation of the condition will ensure the condition is unlikely\nto pose a threat to the integrity of the pipeline until the next reassessment of the\ncovered segment.\n\n\n\n(b) Discovery of condition. Discovery of a condition occurs when an operator has\nadequate information about a condition to determine that the condition presents a\npotential threat to the integrity of the pipeline. A condition that presents a potential\nthreat includes, but is not limited to, those conditions that require remediation or\nmonitoring listed under paragraphs (d)(1) through (d)(3) of this section. An operator\nmust promptly, but no later than 180 days after conducting an integrity assessment,\nobtain sufficient information about a condition to make that determination, unless\nthe operator demonstrates that the 180-day period is impracticable.\nETC’s written IMP procedures are inadequate because they do not define or clarify the “Date\nof Discovery” in the context of pressure testing, which may involve re-tests and multiple\ndiscovery dates, in accordance with §§ 192.907 and 192.933.\nSpecifically, ETC’s Pipeline Integrity Management Plan, ETC GAS IMP_Rev013 04012021,\nSection 7.1 Discovery of a Condition (Revision Date: April 1, 2021) is inadequate because it\ndoes not explain that there may be several dates of discoveries, each for different findings. A\ncondition can only be discovered once per finding/test, and a \"Pass\" is not necessarily a new\ndate of discovery, especially when remediation is already occurring. There should only be one\ndate of discovery for each finding or test, and then the subsequent remediation acceptance\ndate. Additionally, regarding ILI Assessments and the “Date of Discovery,” PHMSA noted\nduring the inspection that ETC’s procedures state that the “Date of Discovery” is equivalent to\nthe data Acceptance Date after the ILI data has been received and loaded into the integrity\ndatabase. However, the input of data into a database is not relevant to having adequate\ninformation and should not be a factor in determining “Date of Discovery.”\nETC must revise its procedures to define/clarify the “Date of Discovery” in accordance with\n§§ 192.907 and 192.933(b).\n3. § 192.907 What must an operator do to implement this subpart?\n(a) General. No later than December 17, 2004, an operator of a covered pipeline\nsegment must develop and follow a written integrity management program that\ncontains all the elements described in § 192.911 and that addresses the risks on each\ncovered transmission pipeline segment. The initial integrity management program\nmust consist, at a minimum, of a framework that describes the process for\nimplementing each program element, how relevant decisions will be made and by\nwhom, a time line for completing the work to implement the program element, and\nhow information gained from experience will be continuously incorporated into the\nprogram. The framework will evolve into a more detailed and comprehensive\nprogram. An operator must make continual improvements to the program.\n§ 192.935 - What additional preventive and mitigative measures must an operator\ntake?\n\n\n\n(a) General requirements. An operator must take additional measures beyond those\nalready required by Part 192 to prevent a pipeline failure and to mitigate the\nconsequences of a pipeline failure in a high consequence area. An operator must base\nthe additional measures on the threats the operator has identified to each pipeline\nsegment. (See § 192.917) An operator must conduct, in accordance with one of the\nrisk assessment approaches in ASME/ANSI B31.8S (incorporated by reference, see §\n192.7), section 5, a risk analysis of its pipeline to identify additional measures to\nprotect the high consequence area and enhance public safety. Such additional\nmeasures include, but are not limited to, installing Automatic Shut-off Valves or\nRemote-Control Valves, installing computerized monitoring and leak detection\nsystems, replacing pipe segments with pipe of heavier wall thickness, providing\nadditional training to personnel on response procedures, conducting drills with local\nemergency responders and implementing additional inspection and maintenance\nprograms.\n(b) …\n(c) Automatic shut-off valves (ASV) or Remote-control valves (RCV). If an operator\ndetermines, based on a risk analysis, that an ASV or RCV would be an efficient means\nof adding protection to a high consequence area in the event of a gas release, an\noperator must install the ASV or RCV. In making that determination, an operator\nmust, at least, consider the following factors—swiftness of leak detection and pipe\nshutdown capabilities, the type of gas being transported, operating pressure, the rate\nof potential release, pipeline profile, the potential for ignition, and location of nearest\nresponse personnel.\nETC’s written IMP procedures for Preventive and Mitigative Measures are inadequate because\nthey permit ETC to review certain factors or refer to a 1995 Southwest Institute Study, when\ndetermining the need for installation of ASV or RCV as outlined in accordance with §§ 192.907\nand 192.935.\nSpecifically, ETC’s Pipeline Integrity Management Plan, ETC GAS IMP_Rev013\n04012021(Revision Date: April 1, 2021), Section 9.2: Mitigative Actions Determination\nProcess, states:\nIn determining the need for installation of an ASV or RCV, the Operations Manager will\nreview the following or refer to Southwest Institute Study:\n The swiftness of leak detection and pipeline shutdown capabilities,\no System detection times\no Operator response times\no Remotely controlled valve response characteristics, and\no System isolation time, if applicable.\n Location and capabilities of existing ASV or RCV,\n ASV response to releases in transient conditions,\n Potential effects of additional ASV on conducting proper valve sequencing during\nintended ASV activations,\n Potential effects of additional ASV on personnel to promptly detect and react to\ninadvertent AS activations,\n\n\n\n Relevant operating modes beyond full flow conditions,\n Consideration of risk results,\n Rate of leakage,\n The volume that can be released,\n Potential for ignition,\n Proximity to power sources,\n Location of the nearest response personnel, and\n Benefits expected by reducing the release size.\nSection 5 of ASME/ANSI B31.8S (incorporated by reference, see § 192.7), requires that an\noperator must conduct, in accordance with one of the risk assessment approaches, a risk\nanalysis of its pipeline to identify additional measures to protect the high consequence area\nand enhance public safety. Such additional measures include, but are not limited to, installing\nAutomatic Shut-off Valves or Remote-Control Valves. ETC’s procedures provide the\nOperations Manager with the option of choosing to use current operational capabilities of the\npipeline or a study that is twenty-six years old.\nOn July 30, 2021, ETC submitted a letter to PHMSA and included the 1995 Southwest Institute\nStudy. The report states: “The findings of this report statistically show that it is unlikely that\na ROV or ASV will mitigate the consequences of a pipeline failure. However, case-by-case\nreviews are performed in both HCA and Non-HCA segments to determine the addition of ASV\nor RSV would be useful in reducing response time or gas loss. Additionally, will perform a\nreview on the Stingray Pipeline system to determine the adequacy of response time to the\noffshore platform from the onshore point.”\nETC must revise its procedures to state that current operational capabilities will be utilized as\nrequired by § 192.935.\n4. § 192.907 What must an operator do to implement this subpart?\n(a) General. No later than December 17, 2004, an operator of a covered pipeline\nsegment must develop and follow a written integrity management program that\ncontains all the elements described in § 192.911 and that addresses the risks on each\ncovered transmission pipeline segment. The initial integrity management program\nmust consist, at a minimum, of a framework that describes the process for\nimplementing each program element, how relevant decisions will be made and by\nwhom, a time line for completing the work to implement the program element, and\nhow information gained from experience will be continuously incorporated into the\nprogram. The framework will evolve into a more detailed and comprehensive\nprogram. An operator must make continual improvements to the program.\n\n\n\n§ 192.937 - What is a continual process of evaluation and assessment to maintain a\npipeline’s integrity?\n(a) General. After completing the baseline integrity assessment of a covered segment,\nan operator must continue to assess the line pipe of that segment at the intervals\nspecified in § 192.939 and periodically evaluate the integrity of each covered pipeline\nsegment as provided in paragraph (b) of this section. An operator must reassess a\ncovered segment on which a prior assessment is credited as a baseline under §\n192.921(e) by no later than December 17, 2009. An operator must reassess a covered\nsegment on which a baseline assessment is conducted during the baseline period\nspecified in § 192.921(d) by no later than seven years after the baseline assessment of\nthat covered segment unless the evaluation under paragraph (b) of this section\nindicates earlier reassessment.\n(b) Evaluation. An operator must conduct a periodic evaluation as frequently as\nneeded to assure the integrity of each covered segment. The periodic evaluation must\nbe based on a data integration and risk assessment of the entire pipeline as specified\nin § 192.917. For plastic transmission pipelines, the periodic evaluation is based on\nthe threat analysis specified in 192.917(d). For all other transmission pipelines, the\nevaluation must consider the past and present integrity assessment results, data\nintegration and risk assessment information (§ 192.917), and decisions about\nremediation (§ 192.933) and additional preventive and mitigative actions (§ 192.935).\nAn operator must use the results from this evaluation to identify the threats specific\nto each covered segment and the risk represented by these threats.\nETC’s written IMP procedures for performance of evaluations and continuous evaluation\nprocedures are inadequate because they do not define or specify when the periodic evaluation\nwill be conducted, as required by § 192.937(b).\nSpecifically, ETC’s Pipeline Integrity Management Plan, ETC GAS IMP_Rev013 04012021,\n8 Continual Re-Evaluation & Reassessment (Revision Date: April 1, 2021) and Pipeline\nIntegrity Management Plan, ETC GAS IMP_Rev013 04012021, 8.2 Re-Evaluation (Revision\nDate: April 1, 2021) states, “The Company will conduct a re-evaluation as frequently as\nnecessary to assure the integrity of each covered segment.” This does not contain enough\nspecificity for the record keeping requirements of the \"re-evaluation\" and needs clarification\nas to what the minimum required frequency is to ensure that periodic re-evaluations do actually\noccur. Procedural language should require the meeting agenda and minutes/commentary as a\npart of the \"official record.\" ETC should consider conducting the re-evaluation during the\nsame interval as the risk assessment discussed in Pipeline Integrity Management Plan, ETC\nGAS IMP_Rev013 04012021, 5 Risk Assessment (Revision Date: April 1, 2021) and Pipeline\nIntegrity Management Plan, ETC GAS IMP_Rev013 04012021, 5.1 Risk Assessment Models\n(Revision Date: April 1, 2021).\n\n\n\nETC must revise its procedures to define and specify when the periodic evaluation will be\nconducted in accordance with §§ 192.907 and 192.937.\n5. § 192.907 What must an operator do to implement this subpart?\n(a) General. No later than December 17, 2004, an operator of a covered pipeline\nsegment must develop and follow a written integrity management program that\ncontains all the elements described in § 192.911 and that addresses the risks on each\ncovered transmission pipeline segment. The initial integrity management program\nmust consist, at a minimum, of a framework that describes the process for\nimplementing each program element, how relevant decisions will be made and by\nwhom, a time line for completing the work to implement the program element, and\nhow information gained from experience will be continuously incorporated into the\nprogram. The framework will evolve into a more detailed and comprehensive\nprogram. An operator must make continual improvements to the program.\n§ 192.941 - What is a low stress reassessment?\n(a) General. An operator of a transmission line that operates below 30% SMYS may\nuse the following method to reassess a covered segment in accordance with § 192.939.\nThis method of reassessment addresses the threats of external and internal corrosion.\nThe operator must have conducted a baseline assessment of the covered segment in\naccordance with the requirements of §§ 192.919 and 192.921.\n(b) External corrosion. An operator must take one of the following actions to address\nexternal corrosion on the low stress covered segment.\n(1) Cathodically protected pipe. To address the threat of external corrosion on\ncathodically protected pipe in a covered segment, an operator must perform an\nelectrical survey (i.e. indirect examination tool/method) at least every 7 years on the\ncovered segment. An operator must use the results of each survey as part of an overall\nevaluation of the cathodic protection and corrosion threat for the covered segment.\nThis evaluation must consider, at minimum, the leak repair and inspection records,\ncorrosion monitoring records, exposed pipe inspection records, and the pipeline\nenvironment.\n(2) Unprotected pipe or cathodically protected pipe where electrical surveys are\nimpractical. If an electrical survey is impractical on the covered segment an operator\nmust— (i) Conduct leakage surveys as required by § 192.706 at 4-month intervals;\nand\n(i) …\n(ii) Every 18 months, identify and remediate areas of active corrosion by evaluating\nleak repair and inspection records, corrosion monitoring records, exposed pipe\ninspection records, and the pipeline environment.\n(c) Internal corrosion. To address the threat of internal corrosion on a covered\nsegment, an operator must—\n(1) Conduct a gas analysis for corrosive agents at least once each calendar year;\n\n\n\n(2) Conduct periodic testing of fluids removed from the segment. At least once each\ncalendar year test the fluids removed from each storage field that may affect a\ncovered segment; and\n(3) At least every seven (7) years, integrate data from the analysis and testing required\nby paragraphs (c)(1)-(c)(2) with applicable internal corrosion leak records, incident\nreports, safety-related condition reports, repair records, patrol records, exposed pipe\nreports, and test records, and define and implement appropriate remediation actions.\nETC’s written IMP procedures for low stress assessments are inadequate because they do not\ninclude specific record keeping requirements for these assessments as required by § 192.941.\nSpecifically, ETC’s Pipeline Integrity Management Plan, ETC GAS IMP_Rev013 04012021\n(Revision Date: April 1, 2021), Section 8.5: Low Stress Reassessment and Appendix D-6 Low\nStress Reassessment Plan (Effective Date: March 1, 2016) should provide more specificity for\nthe record keeping requirements of the 7-year \"assessment.\" This includes, but is not limited\nto, what that record is to specifically include, what format, and guidelines for remedial actions,\netc.\nETC must revise its procedures to include specific record keeping requirements for low stress\nassessments in accordance with §§ 192.907 and 192.941.\n6. § 192.927 - What are the requirements for using Internal Corrosion Direct\nAssessment (ICDA)?\n(a) . . .\n(c) The ICDA plan. An operator must develop and follow an ICDA plan that provides\nfor preassessment, identification of ICDA regions and excavation locations, detailed\nexamination of pipe at excavation locations, and post-assessment evaluation and\nmonitoring.\n(1) …\n(5) Other requirements. The ICDA plan must also include –\n(i) …\n(ii) Provisions for applying more restrictive criteria when conducting ICDA for\nthe first time on a covered segment and that become less stringent as the\noperator gains experience;\nETC’s written procedures for Internal Corrosion Direct Assessment (ICDA) are inadequate\nbecause they do not contain provisions for applying more restrictive criteria when conducting\nICDA for the first time on a covered segment and that becomes less stringent as the operator\ngains experience in accordance with § 192.927(c)(5)(ii).\n\n\n\nSpecifically, ETC’s Pipeline Integrity Management Plan, ETC GAS IMP_Rev013 04012021,\n7 Provisions for Remedial Action (Repair/Mitigation) (Revision Date: April 1, 2021), Pipeline\nIntegrity Management Plan, ETC GAS IMP_Rev013 04012021, 7.5 Internal Corrosion Direct\nAssessment (ICDA) (Revision Date: April 1, 2021), and Appendix D-2 Internal Corrosion\nDirect Assessment (ICDA) Plan (Effective Date: March 1, 2016) do not contain provisions as\nrequired by § 192.927(c)(5)(ii). The ICDA plan does not document when the more restrictive\ncriteria are applied when conducting ICDA for the first time on a covered segment.\nThese more restrictive criteria are for pre-assessment, indirect inspection, direct examination,\nand post assessment steps of the ICDA process. ETC needs to document for each specific\nassessment how the more restrictive criteria were applied.\nETC must revise the ICDA procedures to include provisions for applying more restrictive\ncriteria in accordance with § 192.927(c)(5)(ii).\n7. § 192.929 - What are the requirements for using Direct Assessment for Stress\nCorrosion Cracking (SCCDA)?\n(a) Definition. Stress Corrosion Cracking Direct Assessment (SCCDA) is a process to\nassess a covered pipe segment for the presence of SCC primarily by systematically\ngathering and analyzing excavation data for pipe having similar operational\ncharacteristics and residing in a similar physical environment.\n(b) General requirements. An operator using direct assessment as an integrity\nassessment method to address stress corrosion cracking in a covered pipeline segment\nmust have a plan that provides, at minimum, for—\n(1) Data gathering and integration. An operator's plan must provide for a\nsystematic process to collect and evaluate data for all covered segments to identify\nwhether the conditions for SCC are present and to prioritize the covered segments\nfor assessment. This process must include gathering and evaluating data related\nto SCC at all sites an operator excavates during the conduct of its pipeline\noperations where the criteria in ASME/ANSI B31.8S (incorporated by\nreference, see § 192.7), appendix A3.3 indicate the potential for SCC. This data\nincludes at minimum, the data specified in ASME/ANSI B31.8S, appendix A3.\n(2) Assessment method. The plan must provide that if conditions for SCC are\nidentified in a covered segment, an operator must assess the covered segment\nusing an integrity assessment method specified in ASME/ANSI B31.8S, appendix\nA3, and remediate the threat in accordance with ASME/ANSI B31.8S, appendix\nA3, section A3.4.\nETC’s written procedures for ICDA are inadequate because they do not clarify the SCC threat\nsusceptibility criteria in accordance with § 192.929. Specifically, ETC’s Pipeline Integrity\nManagement Plan, ETC GAS IMP_Rev013 04012021, Section 4: Identification of Threats\n(Revision Date: April 1, 2021) and ETC’s Pipeline Integrity Management Plan, ETC GAS\nIMP Rev013 04012021, 4.1.3 Stress Corrosion Cracking (SCC) do not reflect the current\nindustry SCC susceptibility criteria (SCC is a threat if the MAOP is > 60% SMYS and has a\n\n\n\ncoating other than FBE). Section 4.1.3 defines the susceptibility criteria for high-pH SCC,\nincluding the stress factor, temperature, coating, and distance from a compressor\nstation. ETC’s current definition fails to account for the threat of near-neutral-pH SCC, which\nonly has a stress factor and coating factor. This concern was discussed during the inspection\nand ETC stated that it currently has a procedural revision pending to differentiate between\nhigh-pH and near-neutral-pH SCC resulting from an incident on the Florida Gas system (this\nsame recommendation was made by the Michigan Public Service Commission Staff in 2019\nduring the Panhandle Eastern Inspection and appears to have been unaddressed.\nETC must revise its procedures to clarify the SCC threat susceptibility criteria in accordance\nwith § 192.929.\nResponse to this Notice\nThis Notice is provided pursuant to 49 U.S.C. § 60108(a) and 49 C.F.R. § 190.206. Enclosed as\npart of this Notice is a document entitled Response Options for Pipeline Operators in Compliance\nProceedings.\nPlease refer to this document and note the response options. Be advised that all material you\nsubmit in response to this enforcement action is subject to being made publicly available. If you\nbelieve that any portion of your responsive material qualifies for confidential treatment under 5\nU.S.C. 552(b), along with the complete original document, you must provide a second copy of the\ndocument with the portions you believe qualify for confidential treatment redacted and an\nexplanation of why you believe the redacted information qualifies for confidential treatment under\n5 U.S.C. 552(b).\nFollowing the receipt of this Notice, you have 30 days to submit written comments, revised\nprocedures, or a request for a hearing under § 190.211. If you do not respond within 30 days of\nreceipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice\nand authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice\nwithout further notice to you and to issue an Order Directing Amendment. If your plans or\nprocedures are found inadequate as alleged in this Notice, you may be ordered to amend your plans\nor procedures to correct the inadequacies (49 C.F.R. § 190.206). If you are not contesting this\nNotice, we propose that you submit your amended procedures to my office within 30 days of\nreceipt of this Notice. This period may be extended by written request for good cause. Once the\ninadequacies identified herein have been addressed in your amended procedures, this enforcement\naction will be closed.\nIt is requested (not mandated) that Energy Transfer Company maintain documentation of the safety\nimprovement costs associated with fulfilling this Notice of Amendment (preparation/revision of\nplans, procedures) and submit the total to Mary L. McDaniel, P.E., Director, Southwest Region,\nPipeline and Hazardous Materials Safety Administration.\n\n\n\nIn correspondence concerning this matter, please refer to CPF 4-2021-020-NOA and, for each\ndocument you submit, please provide a copy in electronic format whenever possible.\nSincerely,\nMary L. McDaniel, P.E.\nDirector, Southwest Region\nPipeline and Hazardous Materials Safety Administration\nEnclosure: Response Options for Pipeline Operators in Enforcement Proceedings\ncc: Eric Amundsen, Sr. VP, Energy Transfer, eric.amundsen@energytransfer.com\nTodd Nardozzi, Director Regulatory Compliance, Energy Transfer,\ntodd.nardozzi@energytransfer.com","truncated":false,"body_characters":29978}