Natural Gas Pipeline Co. of America — Pipeline Special Permit

LOD-SPAF 2025-0011-1 NGPL Extension, page 1Official PDFÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ ÿ#

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SPAF 2025-0011 NGPL 07.28.25, page 1Official PDFU.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION Special Permit Analysis and Findings Class 1 to Class 3 Location Change Special Permit Information: Docket Number: PHMSA-2025-0011 Requested By: Natural Gas Pipeline Company of America, LLC Operator ID#: 13120 Original Date Requested: August 29, 2024 Original Issuance Date: July 28, 2025 Code Section(s): 49 CFR §§ 192.611(a) and 192.619(a) Purpose: The Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), 1 prepared this document to provide information related to the special permit application submitted by Natural Gas Pipeline Company of America, LLC (NGPL) in the above-captioned proceeding.2 The document discusses the relevant public comments received with respect to the application, presents the engineering and safety analysis of the special permit application, and makes findings regarding whether the requested special permit should be granted and, if so, under what conditions. Pipeline System Affected and Need for Special Permit: On August 29, 2024, NGPL applied for a special permit waiving the requirements in 49 Code of Federal Regulations (CFR) §§ 192.611(a) and 192.619(a) for approximately 10.37 miles of the 30-inch diameter Louisiana Line #2 natural gas transmission pipeline located in Liberty, Harris, and Montgomery counties, Texas. NGPL’s special permit application specifically requested a waiver of 49 CFR § 192.611(a) as applicable to 10.37 miles of pipe, comprising 16 pipeline special permit segments (SPSs), where the class location changed from Class 1 to Class 3. Without a special permit, 49 CFR § 192.611(a) requires NGPL to replace the SPSs experiencing a Class 1 to Class 3 location change with higher yield strength or thicker walled pipe or continue to operate at a reduced pipeline maximum allowable 1 Throughout this special permit the usage of “PHMSA” or “PHMSA OPS” means the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration Office of Pipeline Safety. 2 Natural Gas Pipeline Company of America, LLC is owned by Kinder Morgan, Inc. 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 1 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 2operating pressure (MAOP).3 As part of its request for a special permit, NGPL sought to restore an earlier MAOP and implement enhanced integrity management (IM) practices for the pipeline. A description and definition of the SPSs and the pipeline specifications are detailed in Attachment A – NGPL Special Permit Segments in Docket No. PHMSA-2025-0011 in the Federal Docket Management System (FDMS) located at Regulations.gov. The special permit inspection area (SPIA) extends over the entire segment length between the upstream launcher and downstream receiver of the in-line inspection (ILI) tool, contains all the SPSs, and extends 220 yards on each side of the centerline of the Louisiana Line #2 pipeline subject to this document. Public Notice: On April 21, 2025, PHMSA posted a notice of this special permit request in the Federal Register with a closing date of May 21, 2025.4 The NGPL special permit application letter, Federal Register notice, Final Environmental Assessment (FEA), Finding of No Significant Impact, and all other pertinent documents are available for review in Docket No. PHMSA-2025-0011 in the Federal Docket Management System (FDMS) located at www.regulations.gov. PHMSA reviewed all public comments received for Docket Number PHMSA-2025-0011 through May 21, 2025. PHMSA received 17 public comments concerning this special permit request. Specific citations from the Federal pipeline safety regulations, 49 CFR Parts 190 and 192, are referenced throughout PHMSA’s responses to the public comments and are accessible online at eCFR: 49 CFR Chapter I Subchapter D – Pipeline Safety. Anonymous commenters submitted 15 public comment responses, many of which contain dozens of questions and comments. Anonymous commenters frequently asked the same or similar questions. The Pipeline Safety Trust (PST) and the operator, NGPL, also submitted comments. Summary of Public Comments and PHMSA Response Comments fell into the following general topic areas: whether NGPL provided adequate justification for the waiver; public awareness; applying IM principles in lieu of class location design factor requirements; adequacy of the safety analysis and proficiency of staff conducting the analysis; valve automation, emergency response and leak detection methodology; corrosion control; material toughness and hydrostatic pressure testing; public transparency and environmental assessment; incident and enforcement history; regulatory coordination and related approvals; and repair methods and adequacy of documentation. NGPL’s submission addressed many of the questions and concerns raised by commenters and reiterated NGPL’s IM approach to safely operating the pipeline. Based on PHMSA’s expertise, consideration of the public comments, and technical information provided by NGPL including in response to the public comments, PHMSA is granting the permit. 3 Under 49 CFR § 192.611(a), when a pipeline operator determines that a class location increase has occurred, it is required to replace those segments of pipe with higher strength or thick walled pipe, reduce the operating pressure using the design factors for new pipe under 49 CFR § 192.111 commensurate with the new class location, or use a previous pressure test or conduct a new pressure test to revise the MAOP using the criteria in 49 CFR §192.611(a) which allows design factors higher than 49 CFR § 192.111 to be used when revising MAOP due to a class location increase. NGPL used the pressure test option when it derated the MAOP from 1,100 psig to 936 psig and is unable to use the pressure test option to restore the MAOP to 1,100 psig because it exceeds the limiting criteria for determining MAOP under 49 CFR § 192.611(a) and 49 CFR § 192.111. 4 See “Pipeline Safety: Request for Special Permit; Natural Gas Pipeline Company of America (NGPL),” 90 FR 16766 (Apr. 21, 2025). 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 2 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 3Each of the general topic areas from the public comments is described further below. Waiver Justification PST and several anonymous commenters questioned whether the applicant met the requirement of 49 CFR § 190.341(c)(4) to explain unique circumstances that justify a waiver of the specified regulation. PHMSA Response: PHMSA may grant a waiver from compliance with class location change requirements to applicants who demonstrate that their request is not inconsistent with pipeline safety. 5 PHMSA issued a policy statement identifying the threshold criteria it considers when granting class location special permits. 6 PHMSA has reviewed the documentation submitted by NGPL and determined the facility meets the threshold criteria for a class location special permit. Public Awareness. Many anonymous commenters and PST asserted that the special permit process does not provide adequate transparency and asked why the proposed special permit did not require NGPL to notify affected members of the public of this special permit request. In its comments, NGPL noted that its routine public awareness activities include mailing brochures to the affected public within 1,000 feet of the pipeline and to excavators in Liberty and Montgomery Counties in Texas. Several public commenters also asserted that raising the MAOP increases the risk associated with an incident by increasing the potential impact radius (PIR) for the pipeline and incorporating additional dwellings. NGPL’s comments clarified that restoring the MAOP from the current 936 psig to 1,100 psig results in an increase of the PIR from 633 feet to 687 feet, with 79 dwellings being newly incorporated into the PIR due the MAOP restoration. In total there will be 889 homes, four businesses, and one church located within the 687-foot PIR calculated using the restored MAOP of 1,100 psig. PHMSA Response: To ensure public transparency this Federal Register Notice notified the public of the proposed special permit by publishing the application, Draft Environmental Assessment (DEA), and draft special permit conditions in the Federal Register. 7 PIR calculates “the radius of a circle within which a potential pipeline failure could have significant impact on people or property.”8 NGPL calculated a PIR of 687 feet using the formula provided in 49 CFR § 192.903, using an MAOP of 1,100 psig and the pipeline diameter of 30 inches. The increase in MAOP will extend the PIR an additional 54 feet and incorporate an additional 79 dwellings. Adhering to the IM requirements in 49 CFR Part 192, Subpart O ensures that the dwellings within the PIR are adequately protected from the risks associated with the operation of the pipeline. 49 CFR § 192.616 requires NGPL to administer a Public Awareness program, and to follow American Petroleum Institute (API) Recommended Practice (RP) 1162. Operators must notify the public that a gas transmission pipeline is operated in the vicinity, educate the public on: the use of a one-call notification system for damage prevention; possible hazards associated with unintended releases from a gas pipeline facility; physical indications that such a release may have occurred; steps that should be 5 See 49 U.S.C. § 60118(c)(1). 6 See “Pipeline Safety: Development of Class Location Change Waiver Criteria,” 69 FR 38948 (June 29, 2004). 7 See generally FEDERAL REGISTER 101, OFFICE OF THE FEDERAL REGISTER (2010), https://uploads.federalregister.gov/uploads/2011/01/fr_101.pdf (“Publishing a document in the Federal Register provides the public official notice of a document’s existence, specifies the legal authority of the agency to issue the document, and gives the document evidentiary status.”). 8 49 CFR § 192.903. 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 3 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 4taken for public safety in the event of a gas pipeline release; and procedures for reporting such an event.9 NGPL previously operated the pipeline at an MAOP of 1,100 psig, and portions of the pipeline outside the SPIA operate at an MAOP of 1,100 psig. The operator therefore has valuable experience operating the pipeline at that pressure and complying with the applicable regulatory requirements of such a pressure. Integrity Management Principles in Lieu of Class Location Design Factor Requirements. PST stated the draft special permit appears to only require that NGPL incorporate the SPSs into its Integrity Management Plan (IMP) as Class 1 pipe without incorporating the tougher repair standards necessary for Class 3 locations. PST and several public commenters questioned whether IM adequately compensates for the waiver of critical design factors established for Class 3 locations and allows operation at MAOP based on Class 1 design factor. They sought assurances that IM evaluation and repair criteria appropriately reflect the higher risk and consequence of failure in populated areas and stated that allowing for increased pressure on outdated infrastructure introduces higher likelihood of failure, gas leaks, explosions, and long-term environmental contamination. Some also questioned if the repair criteria in Subpart O are appropriate for understrength pipe in Class 3 locations. In its comments, NGPL conveyed the applicability of 49 CFR Part 192, Subpart O to the entire 44.9- mile SPIA will result in a higher level of safety due to regulatory requirements for identification of threats, assessment of all applicable threats, minimum reassessment intervals, remediation criteria, and management of manufacturing and construction threats. NGPL also provided additional information about integrity threats and assessments on the pipeline subject to the special permit. Threats identified by NGPL within the SPIA include external corrosion and internal corrosion. The internal and external corrosion threats were comprehensively assessed in 2023 and 2024. In 2023, NGPL completed in-line inspection (ILI) of the entire SPIA using high-resolution caliper, inertial measurement unit, and magnetic flux leakage-axial (MFL-A) tools. In 2024, the entire SPIA underwent a hydrostatic pressure test at or above 1.39 times the MAOP. The next integrity assessment is planned for no later than the end of 2030. PHMSA Response: The requirement in 49 CFR § 192.611 to confirm or revise the MAOP of a pipeline that experiences a change in class location has been in effect since 1970. 10 Historically, Part 192 has required operators to reduce the MAOP of the pipeline when population density increases, applying a design factor that varies based on the class location in 49 CFR §§ 192.111 or 192.611(a). These design factors provide a safety margin in more populated areas, but are greater than the design factors applied to new pipe and may be used if an adequate pressure test has been conducted. Alternatively, operators may replace the pipe with a higher yield strength or thicker walled pipe to ensure the hoop stress corresponding to the desired MAOP is commensurate with the new class location. PHMSA’s intent in creating the IM program requirements in Subpart O was to realize a greater safety margin than what was historically provided by 49 CFR § 192.611. Section 192.611 requires the use of safety factors that vary based on population density, but which predate the advent of ILI technology 9 See 49 CFR § 192.616(d). 10 See “Transportation of Natural and Other Gas by Pipeline; Minimum Safety Standards,” 35 FR 13248 (Aug. 19, 1970). 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 4 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 5and requirements to use other assessment methods periodically in high and moderate consequence areas. The IM requirements in Part 192 require gas transmission line operators to conduct periodic integrity assessments and stringent evaluation, investigation, and repair based on assessment findings. As described in the documentation, NGPL uses high-resolution caliper, inertial measurement unit, and MFL-A tools when conducting ILI, already conducted a hydrostatic pressure test at or above 1.39 times MAOP, and will conduct other activities to comprehensively assesses threats like internal and external corrosion. To ensure the pipeline is operated at an equivalent level of safety, special permit Condition 1(b) requires the entire SPIA to be considered a covered segment subject to IM practices. This will increase the pipeline mileage subject to IM requirements from 8.5 miles to 44.9 miles. The pipeline was manufactured and constructed pursuant to the Federal pipeline safety regulations. All records and documentation provided with the application indicate that the pipeline was manufactured and constructed soundly. PHMSA has determined that the more rigorous practices required by the special permit conditions ensure an equivalent level of safety which addresses the elevated risk associated with operating the pipeline at a higher pressure in a more populous area. Proficiency of Safety Analysis. Several public commenters asked about the competency and training of PHMSA personnel who process special permits and conduct analyses to ensure public safety standards are maintained by the conditions in this proposed special permit. Public commenters asked similar questions about whether the competency of NGPL personnel overseeing IM practices and the operator’s incident history were considered in PHMSA’s decision. Commenters also asked why PHMSA did not require special permit conditions like previously issued special permits, why the special permit conditions did not require the pipeline to have the same requirements as new pipelines, and why special permit conditions did not require NGPL to complete their proposed measures to undertake as an alternative to compliance in Attachment B. Commenters further questioned what factor of safety was required by Subpart O and whether the proposed special permit alters allowable pipeline repair methods. In its comments, NGPL stated that ILI technology and robust IM practices render pipe replacement solely due to population growth near a pipeline unnecessary and inefficient. NGPL further stated that its IMP is specifically designed to proactively identify and mitigate potential threats to pipeline integrity. NGPL explained that the proposed special permit results in an additional 34.5 miles of pipeline treated as a high consequence area (HCA) in accordance with 49 CFR Part 192, Subpart O, which provides a higher level of safety across a greater length of pipeline as compared to the alternative of pipeline replacement. PHMSA Response: PHMSA engineers review and verify the special permit application packages to ensure the documentation meets the requirements of 49 CFR § 190.341. The engineers engage with region personnel who have additional experience with the operator and the segments under consideration, and who ultimately inspect and enforce special permit conditions. PHMSA engineers also provide their analysis and recommendations, including any recommended special permit conditions, to the Associate Administrator for Pipeline Safety, who is authorized to grant or deny the special permit application. The records reviewed by PHMSA in processing a special permit application substantiate the material characteristics and integrity of the facility subject to the special permit application. 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 5 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 6The shorter and more simplified format of the special permit document is attributable to PHMSA’s efforts to increase the comprehensibility and legibility of regulatory documents by eliminating redundant requirements and referencing code citations rather than restating already existing regulatory requirements. Some previously issued special permits listed conditions that were already required by the regulations. To meet the requirements of 49 CFR § 190.341(c)(5), NGPL provided descriptions of proposed measures to undertake as an alternative to compliance in Attachment B.11 PHMSA evaluates proposed measures, but ultimately determines which conditions will ensure an equivalent level of safety. PHMSA considered whether inclusion of additional conditions may be warranted based on the information provided, but determined only those conditions included are necessary to ensure that the special permit achieves the level of safety required by law. The absence of additive requirements in this special permit compared to previously issued class location special permits is also consistent with PHMSA’s efforts to reduce regulatory burdens on the use of domestic energy resources, as directed by Executive Order 14154, 12 and PHMSA’s commitment13 to modernize how pipeline risk is addressed through use of IM principles and technologically advanced tools to assess pipeline integrity and maintain pipeline safety standards. The Federal pipeline safety regulations require operators to maintain detailed compliance records, including identification of the employees responsible for conducting the test or assessment, training and qualifications of employees and contractors who conduct, not only assessments, but all activities performed on a pipeline facility that affect the operation or integrity of the pipeline. See 49 CFR 192.807. PHMSA believes it is paramount to pipeline safety to ensure properly qualified and experienced individuals with appropriate knowledge of pipeline facilities are entrusted to complete inspections, assessments, and evaluations of integrity to ensure pipelines are operated safely. Stringent recordkeeping requirements ensure PHMSA is able to perform detailed inspections and investigations as detailed in 49 CFR § 190.203. Valve Automation, Emergency Response, and Leak Detection. Commenters requested mandatory remotely controlled valves (RCV) with 30-minute or less shut-in times, enhanced rupture detection standards, continuous leak detection with additional measures to ensure public transparency, and community evacuation drills within the PIR. PST advocated for explicit permit conditions ensuring that RCVs shut in pipeline segments within 30 minutes, referencing prior special permits and National Transportation Safety Board recommendations that resulted from incident investigations. They stressed that such requirements reduce risk significantly in populated areas. PHMSA Response: Although requirements for rupture-mitigation valve (RMV) installation and reduced valve spacing required by PHMSA’s recently issued Final Rule14 are primarily applicable to pipelines constructed after the rule’s effective date, NGPL indicated to PHMSA that all the mainline and lateral isolation valves on the system meet the valve automation methodology15 required by the Final Rule and which PHMSA has historically required as a condition in similar special permits. In addition, the Final Rule incorporated more stringent requirements that are applicable to all regulated 11 See NGPL, “Attachment B,” Docket ID PHMSA-2025-0011-0001 (Apr. 21, 2025). 12 See “Unleashing American Energy,” 90 FR 8353 (Jan. 29, 2025). 13 See “Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines),” 68 FR 69778 (Dec. 15, 2003); “Pipeline Safety: Development of Class Location Change Waiver Criteria,” 69 FR 38948 (June 29, 2004). 14 See “Pipeline Safety: Requirement of Valve Installation and Minimum Rupture Detection Standards,” 87 FR 20940 (Apr. 8, 2022) 15 See PHMSA, “Draft Special Permit—Appendix A,” Docket ID PHMSA-2025-0011-0004 at tbl. A3 (Apr. 21, 2025). 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 6 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 7gas transmission facilities. 49 CFR §§ 192.615 and 192.635 require enhanced emergency response plans to ensure quicker responses to indications of emergency and more rapid identification and notification of potential ruptures. 16 The requirements from that rule within 49 CFR §§ 192.615, 192.617, and 192.635 are applicable to all natural gas transmission pipelines, and the requirements from 49 CFR §§ 192.745 and 192.935 are applicable to all RMVs. PHMSA appreciates the assertion that leak detection reduces risk. The Federal pipeline safety regulations include many provisions for leak detection including through IM requirements of Subpart O. NGPL is required to comply with leak detection requirements for the entirety of its pipeline system—including the SPSs. Corrosion Control. Public comments questioned the effectiveness of fusion bonded epoxy (FBE) external coating dating from the early phases of its use in the 1970s and the adequacy of cathodic protection (CP) test stations given the age and vintage coating practices on large-diameter pipe. Commenters raised concerns about coating disbondment, chloride contamination, and their potential connection to pipe failures. Suggestions were made to require additional CP test sites, enhanced corrosion inspection, and defined remediation timeframes. PST challenged the claim that affected pipeline segments have FBE coatings, noting limited commercial adoption of FBE in the 1970s and potential degradation over 50 years. PST recommended mandatory inspection and remediation of coating defects to ensure external corrosion control is consistent with current safety standards. NGPL reported routine inspections including close interval surveys (CIS) that demonstrate the pipeline’s coating system effectiveness, with corrosion control practices that do not rely solely on linear anodes or the 100 mV polarization criterion. They highlighted recent pipeline examination reports confirming bond integrity and coating condition. PHMSA Response: PHMSA reviewed pipeline examination reports and CIS data confirming that the pipeline generally possesses solidly bonded FBE coatings supplemented by coal tar coatings on girth welds, consistent with then-current industry practices. Proper coating installation practices are paramount to ensure pipeline coating will be effective in protecting pipelines from corrosion. Section 192.461, which requires sufficient coating installation practices, including adequate surface preparation and protection from coating damage during construction or maintenance activities, was codified at the time of the subject pipeline’s construction between 1974 and 1978. NGPL’s corrosion control program complies with Part 192 Subpart I requirements mandating adequate cathodic protection (CP) levels, frequent testing, and prompt remediation of deficiencies. NGPL has also performed CISs on the pipeline subject to this special permit. These measures, in addition to external corrosion data collected from ILI, contribute to the operator’s knowledge about the condition of the coating on the pipeline. The operator’s established practices provide ongoing surveillance of coating integrity and corrosion threats at an enhanced scope and frequency. PHMSA found existing CP test site locations and monitoring frequency satisfactory to support integrity assurance for this pipeline segment. Additional conditions were not included in the special permit because Part 192 Subpart I already requires operators to verify through frequent inspection and testing that CP is adequate. For example, CP power sources and protective bonds are required to be inspected every 2½ months. Section 192.469 requires pipelines to have sufficient test stations to determine the adequacy of cathodic protection. Annual testing is required to ensure CP meets specified criteria. When an annual CP survey indicates inadequate systemic CP, the operator must conduct an interrupted current CIS as required by 49 CFR 16 See Valve Rule Fact Sheet, PHMSA (Aug. 12, 2024), https://www.phmsa.dot.gov/rulemaking-implementation/valve-rule/valve-rule-fact-sheet. 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 7 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 8§ 192.465(f) and complete remedial action within 15 months of discovery. The implementation of IM for the entire SPIA will incorporate additional robust requirements to maintain integrity and pipeline safety. Material Toughness, and Hydrostatic Pressure Testing. PST and anonymous public commenters expressed concerns with the absence of Charpy impact toughness data from construction records, given pipe manufacture occurred between 1974 and 1978. Several commenters requested details about pressure test failures linked to seam weld toe cracks and how those defects and pipe toughness are addressed. Commenters asked why the final pressure test was 1.39 times MAOP rather than the 1.5 times MAOP generally required for Class 3 pipelines, and whether the special permit requires periodic reassessment using crack-detection ILIs. PST urged PHMSA to require verification of toughness and comprehensive evaluations of crack related defects on non-failed areas, and questioned NGPL’s manufacturing defect rejection rates and ILI assessment for cracking threats. In its comments, NGPL clarified that the two 2024 pressure test failures occurred near 100-percent of specified minimum yield strength (SMYS), leading to removal and replacement of defective pipe seams. Metallurgical analysis confirmed these were longstanding manufacturing imperfections that had remained stable for approximately 50 years, and that the successful 2024 pressure test reached 1.39 times MAOP, or around 1,539 psig. NGPL stated the test pressure exceeding 1.25 times MAOP stabilizes any latent manufacturing imperfections in accordance with § 192.917(e)(3). NGPL cited an adjacent vintage and manufacturer pipeline operating safely at 1,100 psig as evidence of defect stabilization. PHMSA Response: NGPL submitted records documenting material characteristics for pipe from the original pipeline construction. Those records did not include test results documenting Charpy impact toughness properties or repair and rejection rates from the manufacturer. In the absence of known pipe material toughness, the Federal pipeline safety regulations require operators to use conservative minimum values or obtain the data during pipeline cutouts or using nondestructive testing, to ensure accurate or conservative toughness values are used when calculating predicted failure pressure and critical strain level. The pipeline subject to this special permit was manufactured using the double submerged arc welding (DSAW) process to form its longitudinal seams. PHMSA reviewed metallurgical analysis reports from the 2024 pressure test failures which ascertained the toughness of the pipe body, heat affected zone, and longitudinal seam weld and determined that the subject pipe does not have a similar risk profile to vintage pipe. Those test results demonstrated the pipe has adequate Charpy toughness values by modern standards in all but one case, which still demonstrated toughness that far exceeds the conservative minimum values provided in the Federal pipeline safety regulations. Those values, along with other known pipe characteristics, material testing records, positive material identification reports, consideration of the operating and maintenance history, and results of both the pressure test and ILI assessments indicated the pipeline’s integrity and safety in operating at the restored MAOP of 1,100 psig. The operator submitted documentation that demonstrated traceable, verifiable, and complete material records for all SPSs subject to the special permit, including material test reports for all the pipe which confirms the pipe attributes, the chemical properties, and strength test results. 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 8 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 9Pressure tests are a reliable integrity assessment method for manufacturing defect threats, including defective pipe seams. 17 Testing a pipeline above the operating pressure eliminates any defect that threatens a pipeline’s integrity, through failure, and when successful, demonstrates the absence of defects which might cause it to fail in service. The adequacy of pressure tests to ensure safe pipeline operations is demonstrated by decades of empirical evidence as well as a multitude of studies. PHMSA FAQs18 detail the reliability of Subpart J pressure tests as an assessment method for manufacturing defects, including seam and construction defects, caused by mechanical damage. Section 192.917(e)(3) allows an operator to consider manufacturing defects stable if the pipeline has been subjected to a pressure test at least 1.25 times MAOP. The successful pressure test up to 1.39 times MAOP on this pipeline in 2024 following repairs at failure locations, among several other factors, demonstrated the pipe’s integrity and ability to operate safely at its restored MAOP. Condition 1(b) of the special permit requires the operator to apply IM to the entire pipeline subject to the SPSs—this includes a requirement to identify and evaluate all potential threats, including cracking threats, as 49 CFR § 192.917(e)(6) requires the operator to address cracks or crack-like defects. Subpart O requires pipeline operators to evaluate all threats on a pipeline, including threats considered stable. Moreover, 49 CFR § 192.712(d)(3) requires operators that do not have ILI data to assess cracks by analyzing potential crack defects that could have survived a pressure test. Public Transparency and Environmental Assessment. PST and anonymous public commenters criticized the absence of pipeline location maps and detailed demographic information in the Environmental Assessment (EA), asserting these omissions limit stakeholders’ ability to evaluate risks adequately. PST also questioned the EA’s portrayal of the affected area as largely undeveloped forest, minimizing the extent of nearby population and development. Some anonymous commenters thought independent third-party verification of pipeline safety analyses and public release of inspection data in searchable databases would improve public transparency. PHMSA Response: In addition to posting notices of proposed special permits in the Federal Register for public review and comment, PHMSA also lists information about noticed proposed special permits on its website. 19 Section 190.341(c)(2)(i) requires special permit applications to include a detailed description of the pipeline facilities, including the beginning and ending points of the pipeline mileage to be covered and the counties and States in which it is located. Section 191.29 requires each operator of a gas transmission pipeline to provide geospatial data to PHMSA annually to be displayed on a public website, the National Pipeline Mapping System (NPMS). 20 The online map resource and coordinates21 were also provided to ensure the public could access pipeline maps in their preferred level of detail. PHMSA’s former practice of attaching maps required significant effort to ensure adequate scaling, proofreading, redrafting, document consolidation, and transfer of large file sizes. While PHMSA 17 Section 192.937(c)(2) states that pressure testing is an appropriate assessment method for the following threats: Internal corrosion; external corrosion and other environmentally assisted corrosion mechanisms; manufacturing and related defects threats, including defective pipe and pipe seams; stress corrosion cracking; selective seam weld corrosion; dents; and other forms of mechanical damage. 18 See PHMSA, “Gas Transmission Integrity Management FAQs, ” FAQ-219 and FAQ-220 (Jan. 15, 2021), https://www.phmsa.dot.gov/pipeline/gas- transmission-integrity-management/gas-transmission-integrity-management-faqs. 19 See Pipeline Special Permits and State Waivers Overview, PHMSA (June 30, 2025), https://www.phmsa.dot.gov/pipeline/special-permits-state- waivers/special-permits-and-state-waivers-overview. 20 See NAT’L PIPELINE MAPPING SYS., https://www.npms.phmsa.dot.gov (last visited July 25, 2025). 21 See NGPL, “Attachment A,” Docket ID PHMSA-2025-0011-0002 (Apr. 21, 2025). 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 9 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 10believes substantial effort is worthwhile to provide transparency to the public regarding pipeline safety topics, PHMSA also believes the public is best served when the Agency allocates its finite resources to the review and analysis tasks associated with special permit applications. NPMS is an informative and useful tool that can provide a more detailed understanding of the subject facility, as well as the national pipeline network. The NPMS has many helpful resources to aid the public in learning to use the NPMS. The Public Map Viewer22 contains an instructional video located under the Help menu which demonstrates the viewer’s functionality and should answer most user questions about how to use the viewer. The instructional video is also accessible on YouTube.23 Contact information for pipeline operators may be found via the Find Who’s Operating in Your Area tool. This tool displays the contact information for all pipeline operators in the NPMS data for the user’s selected State, county, or zip code. Dwelling count per each SPS is provided in Attachment A – NGPL Special Permit Segments, and acknowledgement of the increased population density within class 3 areas and discussion of the pipeline safety impacts on the population were discussed and carefully considered. In addition to consideration of public safety, the EA acknowledged the terrain to ensure adequate assessment of potential environmental impacts. Incident and Enforcement History. Several commenters requested insight into NGPL’s incident history over the past five years and any enforcement actions taken by PHMSA. They questioned whether enforcement and past incidents informed the permit approval and requested disclosure of NGPL’s recent significant incident history and PHMSA enforcement actions to assess pipeline safety and reliability. Public commenters also asked several questions about how PHMSA can ensure accountability of pipeline operators through enforcement of Federal pipeline safety regulations and special permit conditions. PHMSA Response: The operator’s incident and enforcement histories were reviewed by PHMSA and considered in evaluation of this special permit application. In the special permit process, consideration of whether an operator’s procedures are adequate is made through a review of the operator’s enforcement history. Previous findings of inadequate procedures are indicated by formerly issued Notices of Amendment and enforcement history is considered by PHMSA in making a determination on issuance of special permits. An overview of reported incidents and enforcement actions are discussed within the Analysis section of this special permit and includes references to online viewing of PHMSA’s incident and enforcement history for NGPL. Additionally, PHMSA’s website24 is a comprehensive resource for members of the public to learn more about enforcement activity. Any member of the public may request additional information from PHMSA under the Freedom of Information Act. 25 Pipeline operators are responsible for compliance with the pipeline safety regulations and the orders issued by PHMSA, including special permits. The enforcement actions that PHMSA can take if an operator is found to be in violation of the Federal pipeline safety regulations or the conditions of this 22 See Learn About the Public Map Viewer, NAT’L PIPELINE MAPPING SYS., https://www.npms.phmsa.dot.gov/AboutPublicViewer.aspx. 23 See PHMSA, How to Locate Pipelines in Your Area with the National Pipeline Mapping System (NPMS), YOUTUBE (Jan. 5, 2017), https://youtu.be/OnZFGVwae4I 24 See Enforcement Data, PHMSA, https://primis.phmsa.dot.gov/enforcement-data/ (last visited July 25, 2025). 25 See FOIA Overview, PHMSA (Oct. 6, 2023), https://www.phmsa.dot.gov/foia. 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 10 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 11special permit are conveyed in 49 CFR Part 190. Pursuant to 49 U.S.C. § 60122, any civil penalty assessed by PHMSA is owed to the United States Government. Regulatory Coordination and Related Approvals. Anonymous public commenters inquired about coordination between PHMSA and the Federal Energy Regulatory Commission (FERC), including whether FERC conducted public hearings and notice for the pressure increase, and whether PHMSA aligned its permit process with FERC’s authority. Comments submitted by PST discussed similarities between this special permit and one NGPL previously applied for under PHMSA-2022-0075. PHMSA Response: NGPL previously applied for a special permit for this pipeline to waive the same regulations cited in this special permit, requesting to return the pipeline’s MAOP to 1,100 psig. NGPL voluntarily withdrew its application and PHMSA did not issue a special permit at that time. In 2024, the operator conducted successful Subpart J hydrostatic pressure tests to 1.39 times the MAOP of 1,100 psig, which demonstrated the integrity of the pipeline and indicated to PHMSA it can be operated safely at 1,100 psig. PHMSA’s process for issuing special permits is set forth in 49 CFR § 190.341 and includes public notice regarding consideration of special permit applications, including drafts of the special permit conditions and environmental assessment, with a Federal Register Notice and documentation specific to the subject facility. FERC utilizes a separate process under its own authority by which it issued approval of NGPL’s project associated with the subject pipeline’s MAOP increase under Docket No. CP24-8-000. PHMSA’s grant of the special permit would not displace, alter, or modify any other Federal, State, or local government oversight over the subject pipeline. Repair Methods and Adequacy of Documentation. Several public comments addressed allowable pipe repair methods, including Type A sleeves, questioning their appropriateness given new findings on hard spots and effectiveness. Additionally, commenters requested formal third-party risk assessments incorporating extreme weather and climate impacts and queried the periodicity and methods of integrity assessments for manufacturing and construction-related defects. PST indicated the application documentation submitted by NGPL stated that it has no records available relating to radiographic inspection of girth welds either during or after construction which are required under 49 CFR § 192.243(f). PST commented that if NGPL has no documentation, it may be out of compliance, and a poor choice for receiving a special permit. PST further postulated that pipelines with girth-weld cracking are ineligible from participating in the integrity management option under the proposed class location rule. PHMSA Response: This special permit does not modify what repair methods are allowed. Section 192.713 requires repairs to be made by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe. Industry standards, such as American Society of Mechanical Engineers (ASME)/American National Standards Institute (ANSI) B31.8S-2004, “Supplement to B31.8 on Managing System Integrity of Gas Pipelines,” and Gas Piping Technology Committee (GPTC) guidance material offer considerations of acceptable repair methods depending on the causal threat and other characteristics of a failure or anomalous condition. Some repair criteria in Subpart O use factors times the MAOP based on class location to calculate the limit of predicted failure pressure. The MAOP used in those calculations already incorporate a design factor that serves as a measure of safety between the operating pressure and the strength of the pipe, as required by 49 CFR § 192.111. 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 11 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 12Section 192.243(d)(1) requires during a pipeline’s construction that at least 10 percent of each day’s completed field girth welds are nondestructively tested, and 49 CFR § 192.243(f) requires record retention for the life of the pipeline documenting how many girth welds were made, nondestructively tested, and rejected, and the disposition of rejected welds. NGPL was unable to produce records of construction girth weld nondestructive testing for the subject pipeline. NGPL had a record from a 1978 test which demonstrated the girth welds were made using a stick metal arc welding process, and certified that the pipeline has never experienced a girth weld leak or failure, nor has ever required a repair on a girth weld. PHMSA considers enforcement and compliance history when reviewing special permit applications, but this does not prevent special permits for any operator with an outstanding compliance issue. PHMSA has determined that these records sufficiently address integrity risk concerns with these welds, and, together with the conditions implemented, lead to the decision that granting the special permit is not inconsistent with pipeline safety. PHMSA issued an Advisory Bulletin26 to remind pipeline operators of the requirements of 49 CFR § 192.317(a) to protect pipelines from the hazards associated with extreme weather. PHMSA considered the suggestion to have a third-party risk assessment completed, but determined it was not necessary to include in the special permit. Analysis: Background: On June 29, 2004, PHMSA published the criteria it uses for the consideration of applications for class location change waivers, now being granted or denied through a special permit.27 First, certain threshold requirements should be met on a pipeline SPS for a class location change special permit to be granted. Second, the age and manufacturing process of the pipe; system design, and construction; environmental, operating and maintenance histories; and IMP elements are evaluated as significant criteria. These significant criteria are presented in matrix form and can be reviewed in the FDMS, Docket No. PHMSA–RSPA-2004-17401. Third, special permits will only be granted when pipe conditions and active IM provide a level of safety greater than or equal to a pipe replacement or pressure reduction. The operator’s Federal pipeline safety regulation compliance history is also evaluated as part of the criteria matrix for acceptability prior to issuance of a special permit. Threshold Requirements: Each of the threshold requirements published by PHMSA in the June 29, 2004 Federal Register notice is discussed below regarding the NGPL special permit request. • No pipeline segments in a class location changing to Class 4 location will be considered. NGPL’s special permit request for 16 SPSs where a change has occurred from a Class 1 to a Class 3 location meets this requirement. • No bare pipe will be considered. NGPL’s SPSs are externally coated with fusion bonded epoxy and meets this requirement. • No pipe containing wrinkle bends will be considered. There are no reported wrinkle bends in the SPSs. NGPL meets this requirement. 26 See “Pipeline Safety: Potential for Damage to Pipeline Facilities Caused by Earth Movement and Other Geological Hazards,” 87 FR 33576 (June 2, 2022). 27 See “Pipeline Safety: Development of Class Location Change Waiver Criteria,” 69 FR 38948 (June 29, 2004). 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 12 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 13• No pipe segments operating above 72 percent of the SMYS will be considered for a Class 3 special permit. NGPL’s SPSs operate at or below 72 percent SMYS and meet this requirement. • Records must be produced that show a hydrostatic test to at least 1.25 time the MAOP. The records should include test pressure, year of the test, test duration, and pressure test percent of MAOP for each pipeline. NGPL submitted documentation which demonstrated that all SPSs have been tested to at least 1.25 times the MAOP that meets this requirement. • ILI must have been performed with no significant anomalies identified that indicate systemic problems, such as SCC. NGPL ran an MFL-A ILI for corrosion and deformation ILI for denting in 2023 which did not discover any significant anomalies. NGPL meets this requirement. • Criteria for consideration of a class location change waiver, being considered through the special permit, published by PHMSA in the Federal Register (69 FR 38948), define a waiver inspection area (SPIA) as up to 25 miles of pipe on either side of the waiver segment (SPS). NGPL has identified the segments surrounding each SPS as the SPIA. These segments have been extended to the entire segment length between the upstream launcher and downstream receiver on the ILI segment that contains all SPSs. Criteria Matrix: The data submitted by NGPL for the SPSs have been compared to the class location change special permit criteria matrix. • The SPSs fall in the probable acceptance column of the criteria matrix for the following criteria: o Pipe material, design stress, pipe coating, test pressure, local geology, pressure fluctuations, safety related condition reports, IMP, ILI time frame, ILI type, coating assessment, and damage prevention program. • The SPSs fall in the possible acceptance column of the criteria matrix for the following criteria: o Class location change, pipe manufacturer, test failures, depth of cover, leaks and failures, service, CP, and inspection findings. • The SPSs fall in the required substantial justification column of the criteria matrix for pipe girth welds criteria, and the direct assessment criteria was not applicable. Enforcement History: In the last five years, PHMSA has taken six enforcement actions against NGPL.28 In the last five years, PHMSA has also taken two enforcement actions against the Colorado Interstate Gas Company, which is a Kinder Morgan gas transmission company with a reported Safety Program Relationship with NGPL.29 PHMSA’s review of the enforcement history for both NGPL and 28 See Federal Enforcement Data: Natural Gas Pipeline Co. of Am. (KMI), PHMSA (July 1, 2025), https://primis.phmsa.dot.gov/enforcement- data/operator/13120. 29 See Federal Enforcement Data: Colorado Interstate Gas Co., PHMSA (July 1, 2025), https://primis.phmsa.dot.gov/enforcement-data/operator/2564. 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 13 of 14#

SPAF 2025-0011 NGPL 07.28.25, page 14the Colorado Interstate Gas Company does not indicate that granting the special permit would be inconsistent with pipeline safety. The enforcement data and reports used in the course of PHMSA’s review are publicly available on PHMSA’s Enforcement Transparency website. The review included the enforcement history for NGPL’s parent company Kinder Morgan for the preceding 10-year period, which is also publicly available on PHMSA’s website. Incident History: In the last five years, NGPL reported 12 incidents, six of which meet the threshold of significant incident30 due to total property damage, and none of those incidents reported any fatalities or injuries. 31 In the last five years, the Colorado Interstate Gas Company has reported four incidents, all four of which meet the threshold of significant incident due to total property damage, and none of those incidents reported any fatalities or injuries.32 PHMSA’s review of the incident history for both NGPL and the Colorado Interstate Gas Company does not indicate that the granting of the special permit would be inconsistent with pipeline safety. The incident data used in the course of PHMSA’s review are publicly available on PHMSA’s Data Mart website. Findings: Based on the information submitted by NGPL and PHMSA’s review of the documentation, PHMSA finds that granting this special permit with conditions that waives the requirements of 49 CFR §§ 192.611(a) and 192.619(a) for NGPL’s Louisiana Line #2 pipeline SPSs subject to the special permit as described in Attachment A – NGPL Special Permit Segments is not inconsistent with pipeline safety. This special permit requires NGPL to implement the special permit conditions that include applying IM practices to the SPSs and the SPIA. NGPL will be required to implement the special permit conditions along the SPSs and SPIA in pipeline segments that are not HCAs and would not normally be required by 49 CFR Part 192 to be assessed on a periodic interval for threats. Completed in Washington D.C. on: July 28, 2025 Prepared by: PHMSA – Engineering and Research Division 30 “Significant Incidents” are those including any of the following conditions: (1) Fatality or injury requiring in-patient hospitalization; (2) $50,000 or more in total costs, measured in 1984 dollars; (3) Highly volatile liquid releases of 5 barrels or more or other liquid releases of 50 barrels or more; and (4) Liquid releases resulting in an unintentional fire or explosion. Gas distribution incidents caused by a nearby fire or explosion that impacted the pipeline system are excluded from this definition. 31 To view this data, go to https://www.phmsa.dot.gov/data-and-statistics/pipeline/operator-information click on Operator Search link to search for 13120 NATURAL GAS PIPELINE CO OF AMERICA (KMI)” and click on the “Incidents” tab. 32 To view this data, go to https://www.phmsa.dot.gov/data-and-statistics/pipeline/operator-information click on Operator Search link to search for 2564 COLORADO INTERSTATE GAS CO.” and click on the “Incidents” tab. 2025-0011 – Natural Gas Pipeline Company of America, LLC Special Permit Analysis and Findings – TX Page 14 of 14#

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