# Gulf South Pipeline Company, LLC — Pipeline Special Permit **Citation:** PHMSA-2023-0126 **Type / status:** permit / current **Agency:** Pipeline and Hazardous Materials Safety Administration **Effective:** 2025-09-02 **Published:** 2025-09-02 PHMSA-2023-0126, issued 2025-09-02 for Gulf South Pipeline Company, LLC's gas transmission system. ## Document text PHMSA pipeline special permit PHMSA-2023-0126. Operator: Gulf South Pipeline Company, LLC. System: Gas Transmission. Issue date: 2025-09-02. <<>> U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration 1200 New Jersey Avenue, SE Washington, D.C. 20590 September 2, 2025 Mr. Tony Rizk Vice President, Technical Services Gulf South Pipeline Company, LLC 9 Greenway Plaza, Suite 2800 Houston, TX 77046 Re: Docket No. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC – Grayson County, Texas, Special Permit from September 2, 2025 to September 2, 2035 Dear Mr. Rizk: On November 15, 2023, pursuant to 49 Code of Federal Regulations (CFR) § 190.341, Gulf South Pipeline Company, LLC (GSPC)1 applied to the Pipeline and Hazardous Materials Safety Administration (PHMSA) for a special permit. GSPC requested a special permit to waive compliance with 49 CFR §§ 192.611(a) and (d) and 192.619(a) for Class 1 to Class 3 location changes on two pipeline segments. Both segments consist of approximately 2.283 miles of 16- inch diameter gas transmission pipeline and are located in Grayson County, Texas. A gas transmission pipeline operator is required by 49 CFR § 192.611 to confirm or revise the maximum allowable operating pressure of a pipeline segment or reduce it according to the limits required by 49 CFR § 192.619(a), where the class location has changed as defined in 49 CFR § 192.5. On September 4, 2024, PHMSA published a Federal Register notice (89 FR 72152) announcing the Special Permit Request. The Special Permit Request letter, Final Environmental Assessment (FEA) and Finding of No Significant Impact (FONSI), Special Permit Analysis and Findings (SPAF), and all other pertinent documents for this special permit are available in Docket No. PHMSA- 2023-0126 in the Federal Docket Management System located at www.regulations.gov. 2 Subject to the stated terms and conditions, PHMSA grants this special permit (enclosed) based on the information provided by GSPC and the findings set forth in the SPAF, FEA, and FONSI. This special permit provides relief from certain regulations and requires GSPC to comply with conditions and limitations designed to maintain pipeline safety as defined in the special permit. 1 Gulf South Pipeline Company, LLC is owned by owned by Boardwalk Pipelines, LP. 2 https://www.regulations.gov/docket?D=PHMSA-2023-0126 Special Permit: PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Letter of Decision – Class 1 to Class 3 Location – Texas Page 1 of 2 <<>> In accordance with 49 CFR § 190.341(j), PHMSA reserves the right to revoke, suspend, or modify this special permit if circumstances occur in which its continuance would be inconsistent with pipeline safety. If GSPC elects not to implement the special permit conditions, GSPC must notify PHMSA within 60 days and comply with 49 CFR § 192.611 within 18 months of the date of this letter. PHMSA notes that the conditions imposed by this special permit are consistent with those originally noticed. However, PHMSA is in the process of reforming its process for reviewing and issuing special permits in order to streamline conditions imposed and reduce unnecessary regulatory burden on use of domestic energy resources in accordance with EO 14154, Unleashing American Energy. 3 PHMSA has offered operators of special permits previously noticed the opportunity to seek reconsideration of their special permits and resubmit their applications for notice and comment in line with the new process. GSPC declined to do so at this time and elected to maintain its current application, but this decision does not preclude GSPC from reapplying in the future. My staff is available to discuss this special permit or any other regulatory matter with you. Max Kieba, Director, Engineering and Research Division, Office of Pipeline Safety, may be contacted at PipelineSPEngineeringDirector@dot.gov or 202-420-9169 on technical matters; and Dave Barrett, Acting Director, Central Region, Office of Pipeline Safety, may be contacted at 816- 329-3817 for operational matters specific to this special permit. Sincerely, Linda Daugherty Acting Associate Administrator for Pipeline Safety Enclosure: Special Permit – PHMSA-2023-0126 3 Exec. Order. No. 14,154, 90 Fed. Reg. 8353 (Jan. 29, 2025). For further information on PHMSA’s efforts to reform special permits, see Pipeline Safety: Rationalize Special Permit Conditions, 90 Fed. Reg. 28590 (July 1, 2025). Special Permit: PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Letter of Decision – Class 1 to Class 3 Location – Texas Page 2 of 2 <<>> U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION SPECIAL PERMIT – Class 1 to Class 3 Location Special Permit Information: Docket Number: PHMSA-2023-0126 Requested By: Gulf South Pipeline Company, LLC Operator ID#: 31728 Original Date Requested: November 15, 2023 Original Issuance Date: September 2, 2025 Effective Dates: September 2, 2025 to September 2, 2035 Code Section(s): 49 CFR §§ 192.611(a) and (d) and 192.619(a) Grant of Special Permit: By this order, subject to the terms and conditions set forth below, the Pipeline and Hazardous Materials Safety Administration’s (PHMSA) Office of Pipeline Safety (OPS)1 grants this special permit to Gulf South Pipeline Company, LLC (GSPC)2 for two special permit segments consisting of approximately 2.28 miles of 16-inch diameter gas transmission pipeline located in Grayson County, Texas. This special permit waives compliance from 49 Code of Federal Regulations (CFR) §§ 192.611(a) and (d) and 192.619(a) for the two special permit segments which have undergone changes from Class 1 to Class 3. 3 Federal pipeline safety regulations in 49 CFR § 192.611(a) require natural gas pipeline operators to confirm or revise the maximum allowable operating pressure (MAOP) of a pipeline segment or reduce it according to the limits required by 49 CFR § 192.619(a) after a change in class location. To avoid confusion, PHMSA has clarified the conditions applicable to GSPC by removing conditions that were either duplicative with existing 49 CFR Subpart D requirements or are not applicable to the Index 819-10 pipeline based on its characteristics and history as documented in GSPC records and verified by PHMSA. PHMSA reviewed material and pressure test records and 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 Gulf South Pipeline Company, LLC is owned by Boardwalk Pipelines, LP. 3 GSPC anticipates that Special Permit Segment 1 will be within a Class 3 location after completion of a planned development by Austin College. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 1 of 33 <<>> verified the Index 819-10 pipeline does not contain electric frequency welded or vintage seam types. The pipeline was installed in 2013 and 2014 and has only high-frequency electric resistance welded and seamless seam types. Both the pipe material data and pressure test documentation have been evaluated and determined by PHMSA to be adequate. I. Purpose and Need GSPC sought this special permit for Class 1 to Class 3 location changes occurring on the 16-inch diameter Index 819-10 pipeline. Provided GSPC complies with the terms and conditions set forth below, the special permit waives compliance from 49 CFR §§ 192.611(a)4 and (d) and 192.619(a) for approximately 2.28 miles of natural gas transmission pipeline. This special permit allows GSPC to maintain the current MAOP as shown in Table 1 – Special Permit Segments. II. Special Permit Segments and Special Permit Inspection Area This permit pertains to the specified special permit segments and corresponding special permit inspection area defined in this section. Special Permit Segments: This special permit applies to the special permit segments in Table 1 – Special Permit Segments and locations are identified using the GSPC survey station (SS) references. Table 1 – Special Permit Segments Special Start End Outside Permit Line Diameter Name Length (feet) Survey Station Survey Station County or Parish, No. Year Seam MAOP Segment Number Dwellings Installed Type (psig)5 (inches) State (SS) (SS) 1 16 Index 819-10 4580 585+22 631+32 Grayson, TX 06 2014 HF– ERW, 1350 2 16 Index 819-10 7472 728+40 803+12 TX Grayson, 240 2013, 2014 HF– ERW, SMLS 1350 Note: HF-ERW is a high frequency electric resistance welded pipe longitudinal seam. SMLS is a seamless longitudinal seam. 4 PHMSA is granting this special permit for Class 1 to Class 3 location changes where the pipeline has been pressure tested to 1.25 times MAOP or greater for eight hours to meet 49 CFR §§ 192.619(a)(2), 192.611(a), and 192.517. Each special permit segment must meet the documentation requirements in Condition 16 – Documentation. 5 Pressure tests were conducted after July 1, 1965; see 49 CFR § 192.619(a)(3) for applicability. 6 As of the Original Issuance Date of this Special Permit, Special Permit Segment 1 is within a Class 1 location. GSPC applied for Special Permit Segment 1 in anticipation of a future development project of Austin College. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 2 of 33 <<>> Special Permit Inspection Area: The special permit inspection area is defined as the area that extends 220 yards on each side of the centerline as listed in Table 2 – Special Permit Inspection Area. Table 2 – Special Permit Inspection Area Special Special Permit Outside Permit Inspection Diameter Line Name Start SS End SS Length (miles) Area Number Segments Included (inches) 1 1, 2 16 Index 819-10 0+00 871+73 16.53 Extended Special Permit Segments: The extended special permit segments are defined as the special permit segments and the five contiguous miles past each endpoint. Appendix B contains general maps that include the pipeline route map showing the special permit segments and special permit inspection area and more detailed maps showing the area near the special permit segments. PHMSA grants this special permit based on the findings set forth in the “Special Permit Analysis and Findings” and “Final Environmental Assessment and Finding of No Significant Impact” documents, which can be read in their entirety in Docket No. PHMSA-2023-0126 in the Federal Docket Management System located at www.regulations.gov. III. Conditions PHMSA grants this special permit subject to GSPC implementing the following conditions on the special permit segments and special permit inspection area. Each condition detailed in this section applies to the special permit inspection area and the corresponding special permit segments unless otherwise noted in the condition: 1) Condition 1 – Maximum Allowable Operating Pressure a) Maximum Allowable Operating Pressure: GSPC must continue to operate each special permit segment and special permit inspection area at or below the existing MAOP of 1350 pounds per square inch gauge (psig) (Index 819-10). b) Pressure Test: GSPC has furnished pressure test records to PHMSA for each special permit segment, which meet 49 CFR § 192.517(a) and have been determined to be adequate. 2) Condition 2 – Procedure Updates Within 90 days of the grant of the special permit, GSPC must develop and maintain procedures in accordance with 49 CFR §§ 192.603 and 192.605 that incorporate the special permit condition requirements as follows: PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 3 of 33 <<>> a) Operations and Maintenance Manual: GSPC must amend the applicable sections of its operations and maintenance (O&M) manuals and procedures to incorporate the special permit conditions. b) Integrity Management Program: i) GSPC must incorporate each special permit segment into its written integrity management program (IMP) as if the special permit segments are “covered segments” as defined in 49 CFR § 192.903, except for the reporting requirements contained in 49 CFR § 192.945.7 The portions of the special permit inspection area that fall outside of the special permit segments are not required to be included as a “covered segment” in accordance with 49 CFR § 192.903. ii) The special permit inspection area and special permit segments must have integrity threats identified, assessed, and remediated in accordance with these special permit conditions and 49 CFR Part 192, Subpart O. iii) Any high consequence area (HCA) in either a special permit segment or the special permit inspection area must be assessed and remediated for threats in accordance with these special permit conditions and 49 CFR Part 192, Subpart O. iv) All permit conditions that are applicable to special permit segments or to the special permit inspection area are applicable to HCAs where the HCA overlaps a special permit segment or the special permit inspection area. v) All special permit conditions that are applicable to the special permit inspection area are also applicable to the special permit segments. The special permit segments must meet the requirements of 49 CFR Part 192, Subpart O, if Subpart O is more stringent than the special permit conditions. vi) The special permit inspection area must be able to be assessed using in-line inspection (ILI) tools, including tethered or remotely controlled tools, in accordance with 49 CFR §§ 192.150 and 192.493. c) Damage Prevention Program: GSPC must incorporate within the special permit inspection area the applicable best practices of the Common Ground Alliance8 in its damage prevention (DP) program. 3) Condition 3 – Corrosion Control a) Cathodic Protection Test Station Spacing: At least one cathodic protection (CP) pipe- to-soil test station must be located within each special permit segment, with a spacing not to exceed ½ mile between CP pipe-to-soil test stations. In cases where obstructions or restricted areas prevent such test station placement, the test station must be placed in 7 GSPC must follow the reporting requirements in Condition 15 – Annual Report, as well as those noted throughout the conditions contained herein. 8 Common Ground Alliance. (March 2020). Best Practices Guide. Retrieved from: https://commongroundalliance.com/BPguide. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 4 of 33 <<>> the closest practical location, not to exceed a 3,000-foot spacing. CP pipe-to-soil test stations must be installed within 12 months of the grant of this special permit. b) Annual Monitoring of Test Station Potential Measurements: At least once every calendar year, not to exceed 15 months, GSPC must monitor CP pipe-to-soil test stations to meet 49 CFR §§ 192.463 and 192.465 for each special permit segment and must include “on and off” potential measurements. Pipe-to-soil potential measurements must comply with Appendix D – Section I.A. (1) of 49 CFR Part 192 or remediation detailed in paragraph (c) of this condition is required. If hard spots are identified with a Brinell Hardness (HB) of 300 HB or greater, CP voltage levels must be maintained more electro-positive than minus 1.2 volts direct current (DC). c) Inadequate Cathodic Protection Level Determination: i) In instances where inadequate potentials are a result of an electrical short to an adjacent foreign structure, a rectifier malfunction, an interruption of power source, or an interruption of CP current due to other non-systemic or location-specific causes, GSPC must document and repair these instances. A close interval survey (CIS) will not be required. ii) All other instances must be assessed as detailed in Condition 4 – Close Interval Surveys. d) Remedial Action Plans: i) Within six months of identifying a deficiency, GSPC must develop a remedial action plan to restore CP to meet 49 CFR § 192.463. Within two months of the finding, GSPC must apply for any necessary environmental permits (Federal or State). ii) GSPC must complete the remediation and confirm restoration of adequate CP over the entire area where inadequate CP levels were detected within 12 months of the deficiency finding or as soon as practicable after obtaining the necessary permits. 4) Condition 4 – Close Interval Surveys a) Survey Methodology and Boundaries: i) GSPC must perform an “on and off” current CIS at a maximum five-foot spacing along the entire length of each special permit segment. ii) GSPC must evaluate each special permit segment in accordance with 49 CFR § 192.463. iii) For inadequate CP level determination described in Condition 3(c)(ii), GSPC must conduct a CIS in both directions from the test station with an inadequate CP reading with the CIS ending at the adjacent test stations. b) Survey Intervals: GSPC must perform the CIS within the following timeframes: PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 5 of 33 <<>> i) Initial assessment must be completed for each newly incorporated and extensions of special permit segments within 12 months after the grant of the special permit. For a special permit segment renewal, the CIS may be conducted at the next reassessment interval.9 ii) Reassessments must be conducted every five years not to exceed 66 months. CIS assessments within the reassessment interval are not required to be performed in the same year as ILI reassessments. c) Survey Remediation and Remedial Action Plans: i) If a special permit segment requires the use of 100 millivolt shift criteria10 or the installation of linear anodes along the special permit segment to meet the CP requirements of 49 CFR § 192.463, it is not eligible to operate with a Class 1 pipe in a Class 3 location. GSPC must either: (1) replace the pipe in the special permit segment with Class 3 location standard (design factor) pipe (see 49 CFR § 192.111(a)); (2) recoat the pipe with non-shielding external coating within 12 months of the finding; or (3) lower the MAOP to meet 49 CFR § 192.611. ii) Within four months of identifying a deficiency, GSPC must develop a remedial action plan to restore CP to meet 49 CFR § 192.463. Within two months of the remedial action plan being developed, GSPC must apply for any necessary environmental permits (Federal or State). iii) GSPC must complete remediation of each special permit segment and confirm restoration of adequate CP over the entire area where inadequate CP levels were detected within 12 months of the survey or as soon as practicable after obtaining the necessary permits.11 5) Condition 5 – In-Line Inspection a) Threat Identification: GSPC must implement data integration and identify integrity threats in the special permit inspection area at least once each calendar year, with intervals not to exceed 15 months, in accordance with 49 CFR § 192.917 and Condition 13(c) – Data Integration. The stress corrosion cracking (SCC) threat assessment for the special permit segments must be conducted using the current incorporated by reference (IBR) edition of the American Society of Mechanical Engineers (ASME) Standard B31.8S, “Managing System Integrity of Gas Pipelines” (ASME B31.8S) Appendix A3 9 A CIS survey conducted in 2020 for a special permit segment that is permit condition compliant would not need to be resurveyed in 2021 but could wait until the next CIS survey reassessment time. 10 A.W. Peabody, “Peabody’s Control of Pipeline Corrosion,” second edition, “Criteria for Cathodic Protection.” “The 100mV polarization criterion should not be used in areas subject to stray current because 100 mV of polarization may not be sufficient to mitigate corrosion in these areas. This criterion also should not be used in areas where the intergranular form of external SCC, also referred to as high-pH or classical SCC, is suspected. The potential range for cracking lies between the native potential and -850 mV (CSE) such that application of the 100mV polarization criterion may place the potential of the structure in the range for cracking.” 11 If remediation based upon the findings of the CIS is not practicable within 12 months of the CIS survey, GSPC must submit a schedule and justify the delay 60 days prior to the 12-month completion requirement to the Director, PHMSA Central Region. GSPC must receive a “no objection” letter from the Director, PHMSA Central Region, prior to a pipe coating remediation schedule extension. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 6 of 33 <<>> and National Association of Corrosion Engineers (NACE) Standard Practice 0204-2008, “Stress Corrosion Cracking Direct Assessment Methodology,” Sections 1.2.1.1 and 1.2.2. b) Inline Inspection Methodology: GSPC must conduct instrumented ILI integrity assessments in accordance with 49 CFR § 192.493, for the special permit inspection area for all threats identified in accordance with 49 CFR §§ 192.919 and 192.921. i) At a minimum, GSPC must conduct ILI assessments for corrosion and denting with high-resolution (HR) magnetic flux leakage (HR-MFL) and HR deformation tools with deformation-extended sensor arms not limited by pig cups. ii) For near-neutral or high-pH SCC (cracking threat), GSPC must use an ILI tool12 that will identify tight cracks.13 iii) In the special permit inspection area that has experienced pipe or girth weld leaks or ruptures due to soil movement, or the threat has been identified, GSPC must run inertial measurement unit (IMU) and HR-deformation ILI tools for detection and remediation of strains and denting of the pipe body and girth welds from soil or pipe movements that impair pipeline integrity. Remediation must be conducted as determined by Condition 13(j) – Pipe and Soil Movement. c) Inline Inspection Assessment Intervals: GSPC must conduct initial assessments and reassessments for the special permit inspection area in accordance with the following: i) Initial ILI assessments must be conducted as follows: (1) If cracking has been identified as a threat for the extended special permit segment, it must be assessed within 18 months of the special permit grant date. 14 (2) All identified threats must be assessed within two years of the special permit grant date. (3) For newly identified threats, assessments must be completed within two years of identification. (4) Previous ILI assessments may be applied if Condition 8 – Anomaly Evaluation and Remediation is completed, and the Condition 5(c)(ii) reassessment interval is maintained. ii) Reassessments must be completed in accordance with the shortest interval of the following: 12 The crack ILI tool must be comparable to an electro-magnetic acoustic transducer (EMAT) ILI tool. 13 GSPC may propose an alternative assessment method for SCC (such as spike hydrostatic testing in accordance with 49 CFR § 192.506) to the Director, PHMSA Central Region, with a copy of the proposal to the Director, PHMSA Engineering and Research Division. GSPC must receive a “no objection” letter from the Director, PHMSA Central Region, prior to implementing any alternative assessment methods for SCC. 14 GSPC identified special permit segments 1 and 2 as having FBE coating. Special permit segments 1 and 2 will only require a cracking assessment to be completed within 18 months of special permit issuance, should cracking be identified as a threat. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 7 of 33 <<>> (1) 49 CFR § 192.939(a); (2) Intervals of five calendar years not to exceed 66 months, if the special permit segment contains any of the following: (a) hard spots (b) shorted carrier pipe to the casing (c) susceptible to SCC (d) pipe or soil movement After conducting two assessments of a threat, one of which must be after the grant of this special permit, GSPC may request reassessment intervals up to seven years for that threat assessment. GSPC must submit for and receive a “no objection” letter from the Director, PHMSA Central Region, prior to implementing this change. (3) The engineering critical assessment (ECA) determined interval, if applicable. iii) If factors beyond GSPC’s control prevent the completion of an assessment within the required timeframe or reassessment interval, GSPC must perform the assessment as soon as practicable, and GSPC must submit a letter justifying the delay and provide the anticipated date of completion to the Director, PHMSA Central Region, no later than two months prior to the end the timeframe or interval. GSPC must receive a “no objection” letter from the Director, PHMSA Central Region, for the delay or must lower the MAOP of the special permit segment in accordance with 49 CFR § 192.611. d) Remediation: Anomaly assessments must be evaluated and remediated in accordance with Condition 8 – Anomaly Evaluation and Remediation. 6) Condition 6 – Girth Welds Construction Girth Weld Non-Destructive Test Records: GSPC provided records to PHMSA that demonstrate the girth welds in the special permit inspection area were non- destructively tested at the time of construction in accordance with Federal pipeline safety regulations at the time the pipelines were constructed in 2013 and 2014. Records review demonstrated that girth welds defects were properly repaired. 7) Condition 7 – Stress Corrosion Cracking Threat GSPC must evaluate the entire length of each special permit inspection area15 for SCC as follows: 15 GSPC has documented no occurrences of SCC or cracking in the special permit inspection area. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 8 of 33 <<>> a) Threat Assessments: GSPC must complete the SCC threat assessment as detailed in Condition 5(a) – Threat Identification. b) SCC Integrity Assessment: If the threat assessment required under Condition 7(a) indicates an extended special permit segment is susceptible to either near-neutral or high- pH SCC, GSPC must perform an SCC assessment on the extended special permit segment in accordance with Condition 5 – In-Line Inspection. 16 c) Examination of Pipe: If the threat of SCC exists in an extended special permit segment as determined in Condition 7(a), GSPC must examine the pipe directly for SCC when the coating has been identified as poor during the pipeline examination. The examination must be conducted using an accepted crack detection practice in accordance with 49 CFR § 192.710(c)(4) and (d) when the extended special permit segment is uncovered for any reason to comply with the special permit and integrity management activities, not including One Call activities (49 CFR § 192.614). d) Discovery of SCC: If GSPC discovers SCC17 activity by any means within an extended special permit segment in similar pipe vintage (manufacturer, manufacturing time or age, diameter, wall thickness, grade, and seam type) and pipe coating vintage (in accordance with 49 CFR § 192.917(e)), or an extended special permit segment has had an in-service or hydrostatic test SCC failure or leak,18 the special permit segment must be further assessed and mitigated, within 18 months of finding SCC and reassessed every five calendar years or less19 based upon the evaluated growth of the SCC, using one of the following methods: i) Spike Hydrostatic Test Program:20 (1) GSPC must perform its SCC spike hydrostatic test program in the extended special permit segment in accordance with 49 CFR § 192.506 and include an ECA of the results that includes a determination of the reassessment interval; and (2) If a joint of pipe in an extended special permit segment leaks or ruptures during a hydrostatic test due to SCC, GSPC must replace the pipe joint that does not meet 49 CFR § 192.611 in the extended special permit segment with new pipe. GSPC 16 GSPC may propose an alternative assessment method for SCC (such as spike hydrostatic testing in accordance with 49 CFR § 192.506) to the Director, PHMSA Central Region, with a copy of the proposal to the Director, PHMSA Engineering and Research Division. GSPC must receive a “no objection” letter from the Director, PHMSA Central Region, prior to implementing any alternative assessment methods for SCC. 17 “SCC” activity shall be defined as greater than 20 percent wall thickness depth and two inches in length. 18 For all in-service and pressure test failures, GSPC must perform a root cause analysis, including the metallurgical examination of the failed pipe, to determine if the failure is caused by a systemic or non-systemic issue. GSPC must provide the written results of this root cause analysis to the Director, PHMSA Central Region, within 90 days of the failure and must submit a copy of the root cause analysis to the Director, PHMSA Engineering and Research Division. 19 GSPC has the option to submit a written request to the Director, PHMSA Central Region, with a copy to the Director, PHMSA Engineering and Research Division, for extension of the crack assessment interval to seven years, as defined in 49 CFR § 192.939(a), if the ECA shows that five-calendar-year assessments are not required. GSPC must receive a “no objection” letter from the Director, PHMSA Central Region, prior to extending the assessment interval to seven calendar years. 20 GSPC may propose an alternative assessment method for SCC (such as spike hydrostatic testing in accordance with 49 CFR § 192.506) to the Director, PHMSA Central Region, with a copy of the proposal to the Director, PHMSA Engineering and Research Division. GSPC must receive a “no objection” letter from the Director, PHMSA Central Region, prior to implementing any alternative assessment methods for SCC. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 9 of 33 <<>> must complete a successful SCC hydrostatic test prior to returning the extended special permit segment to operational service. ii) Crack Detection Tool Assessment: GSPC must run an electro-magnetic acoustic transducer (EMAT) ILI tool or other equivalent crack detection ILI tool in the extended special permit segment; iii) MAOP Lowered: GSPC must lower the MAOP of the special permit segment to 60 percent specified minimum yield strength (SMYS); iv) Pipe Replacement: GSPC must replace all pipe and comply with 49 CFR § 192.611 and § 192.619 in the special permit segment; or v) Operating Pressure Lowered: GSPC must lower the operating pressure of the special permit segment to 20 percent below the maximum pressure during the preceding 90-day operating interval until GSPC conducts an ECA and remediates the special permit segment. e) SCC Remediation Plan: If GSPC discovers any SCC activity in the extended special permit segment, GSPC must submit an SCC remediation plan to the Director, PHMSA Central Region, and send a copy to the Director, PHMSA Engineering and Research Division, no later than 90 days after the finding of SCC.21 The plan must: i) Meet Condition 7(d) and include an SCC remediation/repair plan with SCC characterization and timing; or ii) Include a technical justification that shows that GSPC is addressing the threat for SCC in the special permit segment. 8) Condition 8 – Anomaly Evaluation and Remediation a) General: GSPC must use the procedures specified in the special permit conditions, 49 CFR § 192.712 and 192.933, and Table 3 – Dent Criteria when evaluating anomalies. GSPC must account for ILI tool tolerance and corrosion growth rates in determining scheduled response times and repairs and must document and justify the values used. i) ILI Tool Accuracy: GSPC must demonstrate ILI tool tolerance accuracy for each ILI tool run by using calibration excavations and unity plots that demonstrate ILI tool accuracy to meet the tool accuracy specification provided by the vendor (typical for depth within +10 percent accuracy for 80 percent of the time). GSPC must incorporate ILI tool accuracy by ensuring that each ILI tool service provider determines the tolerance of each tool and includes that tolerance in determining the size of each anomaly feature reported to GSPC. GSPC must compare previous indications to current indications that are significantly different. If a trend is identified 21 For GSPC to go forward with the technical justification for addressing the SCC threat, GSPC must receive a “no objection” letter from the Director, PHMSA Central Region. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 10 of 33 <<>> where the tool has been consistently overcalling or undercalling, the remaining ILI features must be re-graded accordingly. ILI tools used must be calibrated as follows: (1) General ILI Tool Calibration: ILI tool calibrations must use ILI tool run results and anomaly calibrations from the special permit inspection area. ILI calibration excavations may include previously excavated anomalies or recent anomaly excavations with known dimensions that were field measured for length, depth, and width, externally re-coated, CP maintained, and documented for ILI calibrations prior to the ILI tool run. A minimum of four calibration excavations must be used for unity plots.22 (2) EMAT ILI Tool Calibration: (a) ILI calibration for EMAT ILI tools must be based upon excavation results of a minimum of the two most severe anomalies from a combined review of crack depth and length. If the EMAT tool identifies only one anomaly, the anomaly must be excavated and assessed. GSPC can propose alternative EMAT ILI tool evaluation procedures to the Director, PHMSA Central Region, but must receive a “no objection” letter prior to usage of these procedures. (b) If the EMAT ILI tool does not identify any cracking anomalies above the minimum length and depth criteria for 90 percent probability of detection, GSPC must provide the following to the Director, PHMSA Central Region: (1) EMAT ILI service provider report with any GSPC provided reporting thresholds for cracking; (2) Calibration data showing the ILI tool meets API Standard 1163 IBR – Section 6 – Qualification of Performance Specifications, Section 7 – System Operational Verification, and Section 8 – System Results Validation, as applicable; and (3) Previous in-ditch non-destructive examination records showing no SCC findings. Once the above information has been submitted, GSPC must receive a “no objection” letter from the Director, PHMSA Central Region, that no excavation is required for the EMAT ILI tool calibration. ii) Unity Plots: The unity plots must show actual anomaly depth versus predicted depth. 22 Other known and documented pipeline features that are appropriate for the type of ILI tool used may be used as calibration excavations for ILI tool calibration with technical documentation of their validity. To use other known and documented pipeline features as calibration excavations for ILI tool calibration, GSPC must complete the following: (1) submit a plan for using known and documented pipeline features such as calibration excavation data, to the Director, PHMSA Central Region, with a copy to the Director, PHMSA Engineering and Research Division. The plan must include at least the following information: a) reason that known and documented pipeline features will be used in place of anomalies on the pipelines; b) the pipeline features that will be used for the ILI tool calibration; and c) the technical justification for using the pipeline features for ILI tool calibration; (2) receive a “no objection” letter from the Director, PHMSA Central Region, prior to performing the ILI tool calibration using pipeline features; (3) submit a report to the Director, PHMSA Central Region, with a copy to the Director, PHMSA Engineering and Research Division, and with the results of the use of pipeline features for the ILI tool calibration that includes technical documentation establishing the validity of using the pipeline features for the ILI tool calibration. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 11 of 33 <<>> iii) ILI Tool Evaluations: ILI tool evaluations for metal loss must use “6t x 6t”23 interaction criteria for determining anomaly failure pressures and response timing. iv) Discovery Date: The discovery date24 must be within 180 days of any ILI tool run for each type of ILI tool (e.g., HR-geometry, HR-deformation, HR-MFL, EMAT, IMU, or other equivalent ILI tools). b) Remediation schedule for special permit inspection area: GSPC must remediate conditions in the special permit inspection area as required by the criteria in 49 CFR § 192.933(d), and additionally GSPC must schedule the following conditions for remediation as described: i) GSPC must immediately repair metal loss preferentially affecting a detected pipe weld seam, and the predicted failure pressure determined in accordance with 49 CFR § 192.712(d) is less than 1.25 times the MAOP or the metal loss is greater than 50 percent of pipe wall thickness.25 ii) GSPC must remediate any crack or crack-like anomaly that has a crack depth greater than 40 percent of the pipe wall thickness within two years of discovery that are in the special permit inspection area and area outside of the special permit segments. iii) GSPC must monitor any crack with depth less than 40 percent of the pipe wall thickness during subsequent risk assessments and integrity assessments for any change that may require remediation. Appendix A – Table 3 – Dent Criteria summarizes when ECA may be used to evaluate a critical dent. When required to conduct ECA performed in accordance with 49 CFR § 192.712(c): 1) The ECA process must be repeated following each assessment to ensure conformance to the original ECA conclusions. 2) ECA use for dents with a depth greater than six percent up to 10 percent of the outside diameter (OD) requires a “no objection” letter from the Director, PHMSA Central Region. 3) GSPC must remediate dents and mechanical damage that do not pass the criteria defined in Table 3 – Dent Criteria. 4) GSPC must submit the dent ECA procedure to the Director, PHMSA Central Region, for a “no objection” letter prior to conducting the anomaly evaluation.26 The Director, PHMSA Central Region, must respond to GSPC’s submittal letter within 23 6t” means pipe wall thickness times six. 24 Discovery date is the day, month, and year that GSPC receives the ILI tool run results from the ILI tool service provider. 25 ASME/ANSI B31G and R-STRENG are not acceptable evaluation methodologies for corrosion in pipe weld seams. Pipe weld seams must be evaluated using ECA methodology for cracking anomalies in accordance with 49 CFR § 192.712(d). 26 A copy of the dent ECA procedure must be sent to the Director, PHMSA Engineering and Research Division. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 12 of 33 <<>> 90 days. The Director, PHMSA Central Region, may provide a decision, request for additional information, or notify GSPC of PHMSA’s need for additional time to provide a decision. c) Remediation schedule for special permit segments: In addition to the requirements in paragraphs (a) and (b) of Condition 8 for the special permit inspection area, GSPC must remediate conditions in special permit segments as follows:27 i) One-year conditions for special permit segments: GSPC must repair the following conditions within one year of discovery in special permit segments: (1) Pipe Wall: Pipe wall thickness metal loss greater than 40 percent. (2) Weld Metal: Girth weld metal loss greater than 30 percent of pipe wall thickness or pipe weld seam metal loss greater than 15 percent of pipe wall thickness. 28 (3) Class 1 pipe: Any anomaly with a predicted failure pressure less than 1.39 times the MAOP. (4) Class 2 pipe: Any anomaly with a predicted failure pressure less than 1.67 times the MAOP. (5) Class 3 pipe: Any anomaly with a predicted failure pressure less than 2.0 times the MAOP. ii) One-year crack repair conditions for special permit segments: GSPC must repair all anomalies with a predicted failure pressure determined in accordance with 49 CFR § 192.712(d) that is less than 1.39 times the MAOP, or a crack depth that is greater than 40 percent of the pipe wall thickness. iii) Un-cleared shorted casing for special permit segments: GSPC must repair within 12 months of discovery any identified corrosion, cracking or other anomaly that is shorted to a casing that is greater than 30 percent of the pipe wall thickness. iv) Monitored conditions for special permit segments: GSPC does not have to schedule the following conditions for remediation but must record and monitor the conditions during subsequent risk assessments and integrity assessments for any change that may require remediation in a special permit segment. Monitored conditions are the least severe and will not require examination and evaluation until the next scheduled integrity assessment. 27 The special permit inspection area includes the special permit segments, so any anomalies found in a special permit segment must be remediated to meet the requirements for a special permit inspection area in addition to the requirements in this condition. The special permit segments must also be remediated to meet all additional remediation requirements specifically for the special permit segments as required in the special permit conditions. 28 ASME/ANSI B31G and R-STRENG are not acceptable evaluation methodologies for corrosion in pipe weld seams. Pipe weld seams must be evaluated using ECA methodology for cracking anomalies in accordance with 49 CFR § 192.712(d). PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 13 of 33 <<>> (1) Class 1 pipe: Any anomaly with a predicted failure pressure greater than or equal to 1.39 times the MAOP and an anomaly depth less than or equal to 40 percent wall thickness loss. (2) Class 2 pipe: Any anomaly with a predicted failure pressure greater than or equal to 1.67 times the MAOP and an anomaly depth less than or equal to 40 percent wall thickness loss. (3) Class 3 pipe: Any anomaly with a predicted failure pressure greater than or equal to 2.0 times the MAOP and an anomaly depth less than or equal to 40 percent of pipe wall thickness. 9) Condition 9 – Pipe Casings GSPC must identify all shorted casings within special permit segments no later than six months after the grant of this special permit and classify any shorted casings as either having a “metallic short” (the carrier pipe and the casing are in metallic contact) or an “electrolytic short” (the casing is filled with an electrolyte) using a commonly accepted method, such as the Panhandle Eastern, Pearson, DC voltage gradient, AC voltage gradient, or AC Attenuation.29 a) Clear Shorted Casings: Where practical, GSPC must clear shorted casings identified within special permit segments no later than 12 months after the grant of this special permit as follows: i) Metallic Shorts: GSPC must clear any metallic short on a casing in a special permit segment no later than 12 months after the short is identified. ii) Electrolytic Shorts: GSPC must remove the electrolyte from the casing/pipe annular space on any casing in a special permit segment that has an electrolytic short within 12 months of identifying the short. If GSPC identifies any shorts after uprating, they must be cleared no later than 12 months after identification. iii) All Shorted Casings: GSPC must install external corrosion control test leads on both the carrier pipe and the casing in accordance with 49 CFR § 192.471 to facilitate the future monitoring for shorted conditions. GSPC may then choose to fill the casing pipe annular space with a high dielectric casing filler or other material that provides a corrosion-inhibiting environment provided GSPC completed an assessment and all necessary repairs. b) Remediation of Un-cleared Casing Shorts: If it is impractical for GSPC to clear a shorted casing within a special permit segment, GSPC must document the actions taken to remediate the shorted casing and must receive a “no objection” letter from the 29 As of the date of the grant (issuance date) of this special permit, GSPC reported they identified zero shorted casings within special permit segments. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 14 of 33 <<>> Director, PHMSA Central Region, to use ILI assessments instead of clearing the short.30, 31 In addition to the notification, GSPC must conduct the following: i) A special permit segment with shorted casings must be assessed with the appropriate ILI tools (a minimum of HR-MFL and HR-Deformation ILI and with EMAT ILI when a special permit segment is susceptible to SCC) on a five-calendar-year assessment schedule, not to exceed 66 months. ii) GSPC must remediate any identified corrosion, cracking, or other anomalies in accordance with Condition 8 – Anomaly Evaluation and Remediation. 10) Condition 10 – Pipe – Seam Evaluations GSPC must conduct engineering integrity assessments to identify any pipe in extended special permit segments that may be susceptible to pipe seam leak, rupture, or other failure issues because of the vintage of the pipe, the manufacturer of the pipe, other physical or operational characteristics, or unknown pipe characteristics as follows: a) Identify and Test Pipe Seam Issues: i) Within 12 months of the special permit grant, GSPC must perform an engineering integrity analysis to determine if the pipe seam is susceptible to seam threats located in the extended special permit segments. This engineering integrity analysis must follow and document the processes listed herein along with other relevant materials: (1) “M Charts” in “Evaluating the Stability of Manufacturing and Construction Defects in Natural Gas Pipelines,” by Kiefner and Associates (updated April 26, 2007), under PHMSA Contract DTFAA-COSP02120; and (2) Figure 4.2, “Framework for Evaluation with Path for the Segment Analyzed Highlighted” from TTO-5, “Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation,” by Michael Baker Jr. and Kiefner and Associates, et. al. under PHMSA Contract DTRS56-02-D-70036. ii) If the engineering integrity analysis identifies pipe seam issues in extended special permit segments that are a threat to the integrity of the pipeline, GSPC must confirm there are no systemic issues with the weld seam or pipe. Within 12 months of analysis completion, GSPC must complete a hydrostatic test to a minimum of 1.39 times the MAOP for any identified special permit segment. b) Seam Leak or Failure: GSPC’s Index 819-10 pipeline has not experienced a seam leak or failure. 30 The Director, PHMSA Central Region, must respond to GSPC’s submittal letter within 90 days. The Director, PHMSA Central Region, may provide a decision, request for additional information, or notify GSPC of PHMSA’s need for additional time to provide a decision. 31 GSPC must send a copy of the actions taken to clear the shorted casing to the Director, PHMSA Engineering and Research Division. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 15 of 33 <<>> c) Pipe Replacement: The special permit segments must be replaced if any unresolved manufacturing or construction issues are discovered after the grant of this special permit, such as concentrated hard spots, hard heat-affected weld zones, selective seam corrosion, pipe movement that has led to buckling, past leak and rupture issues, or any other systemic issues. d) Girth Weld or Seam Weld Repairs: Within the special permit segments, GSPC must remove and replace, in accordance with 49 CFR Part 192 requirements, all weld seam or girth weld repairs that have been made by the usage of fittings, such as weldolets, threadolets, repair clamps, and pipe sleeves (steel or composite). This remediation must be completed within six months of the grant of this special permit or within six months of the identification. e) Remediation Plan: GSPC must remediate all weld seam leaks, failures, or ruptures32 discovered in the special permit segments. GSPC must submit a seam remediation plan for the special permit segment to the Director, PHMSA Central Region, no later than 30 days after finding a seam leak, seam failure, or seam rupture in the special permit segment containing one of the following: i) A longitudinal weld seam remediation/repair plan that meets Condition 10 and includes replacement, hydrostatic testing, or ILI, with completion of the remediation/repair plan within six months of discovery, or ii) A technical justification that shows that the special permit segment is not at risk for future longitudinal seam leaks or failures. 11) Condition 11 – Control of Interference Currents GSPC must address induced alternating current (AC) from parallel electric transmission lines and other interference issues, such as DC, that may affect the pipeline in a special permit segment. GSPC must have an induced AC or DC survey and analysis program and remediation plan, as required by 49 CFR § 192.473, to protect the pipeline from corrosion caused by stray currents within 12 months of the grant of this special permit. If GSPC faces delays initiating remedial actions as described by 49 CFR § 192.473(c)(4), GSPC must complete remediation as soon as practicable and submit a letter justifying the delay and providing the anticipated date of completion to the Director, PHMSA Central Region, no later than one month prior to the end of the six--month completion date. Any extended evaluation and remediation schedules submitted to PHMSA from GSPC must receive a “no objection” letter from the Director, PHMSA Central Region. 32 For all in-service and pressure test failures, GSPC must perform a root cause analysis, including the metallurgical examination of the failed pipe, to determine if the failure is caused by a systemic or non-systemic issue. GSPC must provide the written results of this root cause analysis to the Director, PHMSA Central Region, within 90 days of the failure and must submit a copy of the root cause analysis to the Director, PHMSA Engineering and Research Division. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 16 of 33 <<>> 12) Condition 12 – Mainline Valve – Monitoring and Remote Control for Ruptures GSPC must automate mainline valves33 for closure or demonstrate capability to manually close mainline valves in accordance with the requirements of this Condition 12. The special permit segments must have upstream and downstream remote-control valves (RCVs) so that the distance between the valves is no greater than 20 miles.34 GSPC must automate mainline valves to close in accordance with the requirements in Condition 12 within 12 months of the grant of this special permit. The special permit segments must have procedures for rupture isolation as follows: a) Valve Locations: RCVs must be installed as shown in Table 4 – Valves and Lateral Locations with Isolations Methods. b) Automatic Shutoff Valve Requirements: This special permit does not allow the use of automatic shutoff valves (ASVs). c) Remote Monitoring and Control: Each special permit segment must have telemetry connections to the GSPC supervisory control and data acquisition (SCADA) system, remote monitoring and control of valves by SCADA system, and constant monitoring of valve status (open, closed, or partial closed/open), upstream pressure, and downstream pressure. d) Crossover or Lateral Pipe Connection Isolation: If any crossover or lateral pipe35 connects to the isolated segment between the upstream and downstream mainline valves, the nearest valve on crossover connections or laterals must be isolated such that, when all valves are closed, there is no flow path for gas to flow to the leak or rupture site (except for residual gas already in the shut-off segment). If the nearest valve for a gas receipt or delivery line to the special permit inspection area is not isolated, isolation valves must be installed within 12 months of the grant of this special permit. 36 Valves that are in the GSPC O&M procedures as locked closed and that are only opened when manned by GSPC operating personnel do not require RCVs for closure. e) Mainline Valve Closure: Closure of the appropriate valves following a pipeline leak or rupture must occur “as soon as practicable” and must not exceed 30 minutes from the “notification of potential rupture” as defined in 49 CFR § 192.635. 37 GSPC must 33 A mainline valve is a sectionalizing valve used to isolate or stop gas flow upstream or downstream along the pipeline. 34 If the distance between mainline isolation valves exceeds 20 miles, additional mainline valve(s) must be added. 35 Table 4 – Valves and Lateral Locations with Isolations Methods has a listing of all applicable valves. 36 Gas delivery or receipt pipelines must have a shutoff valve (gate or ball valve) either at the connection between the isolation valves for a special permit segment or at the delivery or receipt meter station. Any gas delivery or receipt station over five miles in length that is connected between the isolation valves for a special permit segment must have a RCV or ASV within five miles of the pipeline tie-in. For gas delivery or receipt pipelines manual shutoff valves can be used for isolation but must be closed within 30 minutes of the pipeline leak or rupture confirmation. Check valves cannot be used for pipelines over eight-inch diameter. 37 The pipeline valve section location to be closed and isolated (if there should be a rupture) must be confirmed by GSPC through Gas Control or other field operations personnel monitoring of the appropriate pipeline pressures, pressure changes, or flow rate changes through a compressor discharge section or by location confirmation from responsible persons. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 17 of 33 <<>> evaluate and identify a rupture38 as being either an actual leak event, rupture event, or non-rupture event in accordance with operating procedures and 49 CFR § 192.615. f) Gas Control Center Monitoring: The GSPC Gas Control Center must monitor the special permit inspection area 24 hours a day, seven days a week, and must confirm the existence of a leak or rupture as soon as practicable in accordance with GSPC pipeline operating procedures. g) Remote Monitoring: GSPC must maintain remote monitoring and automatic control equipment, mainline valves, mainline valve operators, and pressure sensors in accordance with 49 CFR §§ 192.631 and 192.745. All remote monitoring and automatic control equipment, including pressure sensors, must have backup power to maintain communications and control to the GSPC Gas Control Center during power outages. h) Inoperable Valves: GSPC must take remedial measures to correct any valve used to isolate a leak or rupture that is found to be inoperable or unable to maintain shutoff, as follows: i) Repair or replace the valve as soon as practicable but no later than six months after the finding; ii) Designate an alternative valve within 14 calendar days of the finding while repairs are being made. Repairs must be completed within six months; and iii) If valve repair or replacement cannot be met due to circumstances beyond GSPC’s control, GSPC must notify, in writing, the Director, PHMSA Central Region, of the reasons the schedule cannot be met and obtain a letter of “no objection” from PHMSA prior to implementing the schedule change. i) Emergency Communications: GSPC must immediately and directly notify the appropriate public safety access point (911 emergency call center) or other emergency management coordinating agency for the communities and jurisdictions in which the pipeline is located when a release is indicated. 39 13) Condition 13 - Special Permit Specific Conditions GSPC must comply with the following requirements: a) Line-of-Sight Markers: GSPC must install and maintain line-of-sight markers on the pipeline in each special permit segment, except in agricultural areas or large water crossings, such as lakes, where line-of-sight signage is not practical. Line-of-sight markers must be installed within six months of the grant of this special permit and 38 For all in-service and pressure test failures, GSPC must perform a root cause analysis, including the metallurgical examination of the failed pipe, to determine if the failure is caused by a systemic or non-systemic issue. GSPC must provide the written results of this root cause analysis to the Director, PHMSA Central Region, within 90 days of the failure and must submit a copy of the root cause analysis to the Director, PHMSA Engineering and Research Division. 39 GSPC must designate the pipeline controller or the appropriate operator emergency response coordinator in its operating procedures and train the designated individual for coordinating with emergency responders. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 18 of 33 <<>> replaced as necessary by GSPC within 30 days after identification of line-of-sight marker removal. b) Depth of Cover Survey: i) GSPC must complete, within six months of the grant of this special permit, a depth of cover survey for each special permit segment. ii) GSPC must implement additional safety measures for any pipe in a special permit segment that does not meet depth of cover requirements from 49 CFR § 192.327(a) for a Class 1 location. A special permit segment with depth of cover less than 24 inches must be either lowered, have additional soil cover added, or have a concrete pad installed unless it is in consolidated rock. iii) For GSPC to use other remedial measures for depth of cover requirements that are based upon the threat, such as increased pipeline patrols or additional line markers, GSPC must submit these procedures to the Director, PHMSA Central Region, for a “no objection” letter prior to usage. The Director, PHMSA Central Region, must respond to GSPC’s submittal letter within 90 days. The Director, PHMSA Central Region, may provide a decision, request for additional information, or notify GSPC of PHMSA’s need for additional time to provide a decision. c) Data Integration: GSPC must develop and maintain data integration40 in accordance with 49 CFR § 192.917, of all special permit condition findings and remediation in special permit segments and special permit inspection area. Data integration must be completed at least once each calendar year, with intervals not to exceed 15 months. i) Data integration must include but is not limited to the data listed in 49 CFR § 192.917(b)(1).41 Structures must be validated each calendar year by obtaining new aerial imagery or by ground patrol in accordance with Condition 13(h). ii) If requested by PHMSA, GSPC must complete and submit data integration documentation and drawings, with four years of prior data, beginning with the second annual report of this modified special permit. iii) GSPC must maintain data integration as a composite of all applicable data elements in a comparable data viewer. d) Pipe Properties Testing: Material records supplied by GSPC demonstrated documentation of the mechanical and chemical properties of pipe in the special permit segments meets the wall thickness, yield strength, tensile strength, and chemical 40 Data integration is defined as the gathering of relevant pipeline attributes, operational, maintenance, environmental, and integrity information and integrating this information together to assess threats to the pipeline and to use this information to conduct assessments and remediation for those threats. 41 Hydrostatic test failures, in-service ruptures, rectifier readings, CP test point survey readings, AC/DC interference surveys, pipe coating surveys, pipe coating and anomaly evaluations from pipe excavations, SCC excavations and findings, and pipe exposures from encroachments must be maintained for data integration into a comparable data viewer. These data elements may not be on a drawing. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 19 of 33 <<>> composition requirements of API Standard 5L incorporated by reference into 49 CFR Part 192. e) Pipeline System Flow Reversals: For pipeline system flow reversals lasting longer than 90 days and where the MAOP for class location changes are exceeded under either 49 CFR §§ 192.619(a)(1) or 192.61142 in a special permit segment, GSPC must prepare a written plan that corresponds to the applicable criteria identified in the PHMSA Advisory Bulletin, ADB-2014-04, “Guidance for Pipeline Flow Reversals, Product Changes and Conversion of Service” (79 FR 56121; Sept. 18, 2014). GSPC must submit the written flow reversal procedure to the Director, PHMSA Central Region, and submit a copy of the plan to the Federal Docket for this special permit at www.regulations.gov. 43 GSPC must receive a “no objection” letter from the Director, PHMSA Central Region, prior to implementing the pipeline system flow reversal through a special permit segment. f) Environmental Assessments and Permits: GSPC must evaluate the potential environmental consequences and affected resources of any land disturbances and water body crossings, and pipeline natural gas emissions from implementation of the special permit conditions for a special permit segment or special permit inspection area prior to the disturbance or activity. If a land disturbance, water body crossing, or pipeline natural gas emission is required, GSPC must obtain and adhere to all applicable Federal, State, and local environmental permit requirements when conducting the special permit conditions activity. g) Gas Quality: GSPC must transport gas through the special permit segment whose composition quality is suitable for sale to gas distribution customers, including no free- flow water or hydrocarbons, no water vapor content that exceeds acceptable limits for gas distribution customer delivery, hydrogen sulfide not to exceed one grain per 100 cubic feet, or carbon dioxide not to exceed three percent by volume. h) Annual Class Location Study: GSPC must conduct a class location study on the special permit inspection area at least once each calendar year, with intervals not to exceed 15 months, in accordance with 49 CFR § 192.609. i) Notifications: For any special permit condition that requires GSPC to provide a notice for a “no objection” response from PHMSA, other notice, annual report, or documentation to the Director, PHMSA Central Region, GSPC must also send a copy to the State Agency that has interstate agent agreements with PHMSA and to the Director, PHMSA State Programs j) Pipe and Soil Movement: Girth weld strain from soil movement exerted onto the pipeline in the special permit segment must not exceed 0.5 percent and must account for girth weld misalignment. GSPC must develop procedures on how to evaluate and remediate soil stresses and strains on the pipeline including IMU intervals. GSPC must 42 An example of exceedance of 49 CFR § 192.619(a)(1) is a Grandfathered MAOP which has a design factor above 0.72. An example of exceedance of 49 CFR § 192.611 is a Class 1 to Class 3 location change. 43 GSPC must send a copy of the flow reversal procedure to the Director, PHMSA Engineering and Research Division. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 20 of 33 <<>> submit soil stress and strain evaluation and remediation procedures to the Director, PHMSA Central Region, within three months of identification and must receive a “no objection” letter prior to implementation. k) Gas Leakage Surveys and Remediation: i) GSPC must conduct gas leakage surveys using instrumented gas leakage detection equipment along each special permit segment and at all valves, flanges, pipeline tie- ins, ILI launcher and ILI receiver facilities in the special permit inspection area at least twice each calendar year, not to exceed 7½ months. GSPC must document the type of equipment used, survey findings, and remediation of all instrumented gas leakage surveys. ii) A gas transmission pipeline leak is a gas leak that can be seen, heard, felt, or detected by instrumented gas leakage detection equipment, or is an existing, probable, or future hazard to the public, operating personnel, property, or the environment. GSPC must grade and remediate all gas transmission pipeline leaks in the special permit segment and at all valves, flanges, pipeline tie-ins, ILI launcher, and ILI receiver facilities in each special permit inspection area, as follows: (1) A Grade 1 leak requires immediate or continuous remediation efforts to stop the leak. A Grade 1 leak is defined as any of the following: (a) Any leak which, in the judgment of the operating personnel at the scene, is regarded as an immediate hazard; (b) Escaping gas that has ignited; (c) Any indication of gas which has migrated into or under a building, or into a tunnel; (d) Any reading at the outside wall of a building, or any reading where gas would likely migrate to an outside wall of a building; (e) Any reading of 80 percent lower explosive limit (LEL), or greater, in a confined space; (f) Any reading of 80 percent LEL, or greater in small substructures (other than gas associated substructures) from which gas would likely migrate to the outside wall of a building; or (g) Any leak that can be seen, heard, or felt, and which is in a location that may endanger the public, property, or environment. (2) A Grade 2 leak requires remediation activity to be completed within 30 days or must have continuous remediation efforts to stop the leak. A Grade 2 leak is defined as any of the following: PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 21 of 33 <<>> (a) Any leak which, under frozen or other adverse soil conditions, would likely migrate to the outside wall of a building; (b) Any reading of 40 percent LEL, or greater, under a sidewalk in a wall-to-wall paved area that does not qualify as a Grade 1 leak; (c) Any reading of 100 percent LEL, or greater, under a street in a wall-to-wall paved area that has significant gas migration and does not qualify as a Grade 1 leak; (d) Any reading less than 80 percent LEL in small substructures (other than gas associated substructures) from which gas would likely migrate creating a probable future hazard; (e) Any reading between 20 percent LEL and 80 percent LEL in a confined space; (f) Any reading on a pipeline operating at 30 percent SMYS or greater, in a Class 3 or Class 4 location, which does not qualify as a Grade 1 leak; (g) Any reading of 80 percent LEL, or greater, in gas associated substructures; or (h) Any leak which, in the judgement of operating personnel at the scene, is of sufficient magnitude to justify schedule repair. (3) A Grade 3 leak must be reevaluated at the next scheduled survey, or within 7½ months of the date discovered, whichever occurs first, until the leak is cleared, re-graded, or remediated. Remediation of Grade 3 leaks must be completed within 24 months of discovery of the leak. A Grade 3 leak is defined as any of the following: (a) Any reading of less than 80 percent LEL in small gas associated structures; (b) Any reading in areas without wall-to-wall paving where it is unlikely the gas could migrate to the outside wall of a building; or (c) Any reading of less than 20 percent LEL in a confined space. iii) When a pressure limiting device or relief valve allows a gas release to the atmosphere that is located along the special permit inspection area, GSPC must conduct an O&M procedure assessment of the pilot, springs, pressure gauges, and other pressure limiting equipment to ensure that these items are properly functioning, sensing, and retaining set pressures. If a pressure limiting device or relief valve deficiency cannot be remediated, the pressure limiting device or relief valve must be replaced or continuously monitored until remediated. GSPC cannot extend or change any remediation timing or continuous monitoring requirements in this paragraph without a “no objection” letter received by GSPC from the Director, PHMSA Central Region. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 22 of 33 <<>> iv) GSPC may request an extension of the remediation time interval requirements by sending a request to the Director, PHMSA Central Region, but must receive a “no objection” letter from the Director, PHMSA Central Region, prior to extending the leak remediation timing or continuous monitoring requirements in Condition 13(k). 44 l) Right-of-Way Patrols: In addition to the requirements of 49 CFR § 192.705, GSPC must perform right-of-way patrols as follows: i) Aerial flyover patrols or ground patrols by walking or driving of a special permit segment right-of-way once each month, not to exceed 45 days, contingent on weather conditions. Should mechanical availability of the patrol aircraft or weather conditions become an extended issue, the special permit segment pipeline aerial flyover patrol must be completed within 60 days of the last patrol by other methods such as walking or driving the pipeline route, as feasible. ii) If the schedule for either ground patrols or aerial flyover patrols cannot be met due to circumstances beyond GSPC’s control, GSPC must notify the Director, PHMSA Central Region, in writing of the reasons the schedule cannot be met and obtain a letter of “no objection” within three business days of the exceedance. m) Minimization of Gas Released: i) GSPC must reduce the release of gas when replacing any pipe between the mainline isolating valves for a special permit segment. GSPC must use one or more of following methods that will reduce the safety risks of methane (gas) being released. GSPC must calculate the volume of natural gas that will be released by each method or combination of methods and proceed with minimal release of gas consistent with pipeline safety. 45 1) Isolate a smaller pipeline segment length by use of valves and/or the installation of control fittings near the pipe being replaced; 2) Flaring the gas released from the pipeline from the nearest isolation valves or control fittings from the pipe being replaced; 3) Pressure reduction in the pipeline segment by use of inline compression; 4) Pressure reduction by use of mobile compression from the nearest isolation valves from the pipe being replaced; 5) Transfer the gas to a lower pressure pipeline system or segment from the nearest isolation valves nearest to the pipe being replaced such as through a lateral delivering gas to another pipeline facility; or 44 Any GSPC request for a time interval extension for a 24-month remediation interval must be 90 days prior to the end of the 24-month remediation interval. 45 Condition 13(m) would not be required for a blowdown due to an immediate repair, as detailed in Condition 8 – Anomaly Evaluation and Remediation, or where immediate action is required to ensure public safety. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 23 of 33 <<>> 6) An alternative method demonstrated to minimize the release of gas to the environment similar to the other methods listed in the methods (1) through (5) above. ii) GSPC must document the determination and justification for the reduction method(s) implemented and how the method(s) used minimized the release of natural gas to the environment and was consistent with pipeline safety. GSPC must also document and justify, any substantial difference (over 10 percent additional release) between the actual amount of natural gas released and the estimated volume calculated before the replacement. iii) GSPC must report all mainline blowdowns between the mainline isolating valves for a special permit segment due to pipe replacement as detailed in the Condition 15 – Annual Report. 14) Condition 14 – Field Activity Notices to PHMSA GSPC must give a minimum 14-day notice to the Director, PHMSA Central Region, to enable PHMSA to observe the excavations relating to Condition 8 – Anomaly Evaluation and Remediation and Condition 13(d) – Pipe Properties Testing of field activities in the special permit inspection area. Immediate response conditions do not require 14-day notice, but GSPC should notify the Director, PHMSA Central Region, no later than two business days after the immediate condition is discovered. The Director, PHMSA Central Region, may elect not to require a notification for some activities. 15) Condition 15 – Annual Report Annually, 46 after the grant of this special permit, GSPC must report the following to the Director, PHMSA Central Region, with copies to the Director, PHMSA Engineering and Research Division:47 a) The number of new residences, other structures intended for human occupancy, and public gathering areas built within each special permit segment during the previous year. GSPC must include a summary of the results of the study conducted to meet Condition 13(h) – Annual Class Location Study in the annual report. b) Any new integrity threats identified during the previous year and the results of any ILI or direct assessments performed (including any un-remediated anomalies over 30 percent wall loss; cracking found in the pipe body, weld seam, or girth welds; and dents with metal loss, cracking, or stress riser) and any soil movement (lateral or subsidence) that affects pipeline integrity48 during the previous year in the special permit inspection area, 46 PHMSA must receive the annual report by the last day of the month in which the special permit is dated. For example, the annual report for a special permit dated January 21, 2020 must be received by PHMSA no later than January 31 each year beginning in 2021. 47 GSPC must post the annual report to the special permit docket PHMSA-2023-0126 at www.regulations.gov. 48 GSPC must develop and implement an O&M procedure to review soil movements that could damage the special permit segment on a periodic interval so the lateral stresses will not exceed 100 percent of SMYS (0.5 percent strain) on girth welds. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 24 of 33 <<>> including their survey station, predicted failure pressure, anomaly depth and length, class location, and whether these threats are in an HCA. c) Any reportable incident, any leak normally indicated on the DOT Annual Report, and all repairs on the pipeline that occurred during the previous year in a special permit inspection area. GSPC must include the location by mile post, County/parish, and State, the date of discovery, date of repair, and estimated gas loss (cubic feet) per day and in total for any Grade 1, 2, or 3 gas leaks as described in Condition 13(k) – Gas Leakage Surveys and Remediation. d) Any ongoing damage prevention initiatives affecting the special permit inspection area and a discussion of the success of the initiatives, including findings and remediation actions. e) GSPC must submit annual data integration information, as required in Condition 13(c) – Data Integration, beginning with the second annual report, which must include an annual overview of any new threats. If requested by PHMSA, GSPC must submit a full information package of the requested pipeline attribute and integrity items outlined in the condition. f) Any emergency events that cause closure of mainline valves, including the location (County, State, and mile post) of valves and closure times. g) GSPC must report the diameter and location of the lateral, if any lateral or crossover piping is not included in Table 4 – Valves and Lateral Locations with Isolation Methods or installed between isolation valves for a special permit segment. h) GSPC must report all mainline blowdowns between the mainline isolating valves for a special permit segment due to pipe replacement which includes the date of blowdown, location (milepost/stationing), and the amount of gas released to comply with Condition 13(m) – Minimization of Gas Released to the Environment. i) Any mergers, acquisitions, transfer of assets, or other events affecting the regulatory responsibility of the company operating the pipeline. j) A senior executive officer, vice president, or higher executive of GSPC must review for accuracy, date, and sign the annual report prior to posting it to the Federal Docket (PHMSA-2023-0126) at www.regulations.gov and submitting a copy to the Director, PHMSA Central Region, and the Director, PHMSA Engineering and Research Division. k) GSPC must schedule a review meeting regarding Condition 15 – Annual Report with the Director, PHMSA Central Region, prior to or within one month of the filing of each year.49 During the annual review meeting, GSPC must review the status of implementing the special permit conditions with the Director, PHMSA Central Region. 49 The Director, PHMSA Central Region, has the authority to waive this meeting. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 25 of 33 <<>> 16) Condition 16 – Documentation GSPC must maintain the following records for the special permit segments as follows: a) GSPC must keep documentation of compliance with all conditions of this special permit for the life of the pipe. b) Documentation of the mechanical and chemical properties (e.g., mill test reports) that show the pipe in a special permit segment meets the wall thickness, yield strength, tensile strength, and chemical composition requirements of API Standard 5L, 5LX or 5LS, “Specification for Line Pipe” (API 5L) incorporated by reference into the 49 CFR Part 192 code at the time of manufacturing, or, if the pipe was manufactured and placed in- service prior to the inception of 49 CFR Part 192, the API 5L standard in use at that time. 17) Condition 17 – Extension of the Special Permit Segment PHMSA may extend a special permit segment to include contiguous segments up to the limits of the special permit inspection area pursuant to GSPC implementing the following conditions: a) Within six months after the Class 1 to Class 3 location change, GSPC must provide notice to the Director, PHMSA Central Region, and Director, PHMSA Engineering and Research Division, of the request for a special permit segment extension. i) The notice must include the special permit segment extension survey stations, mile posts, additional pipeline footage, pipe attributes (wall thickness, grade, seam type, external coating, and latest pressure test), predicted failure pressure of any anomalies over 30 percent wall loss, schedule of inspections, and of any anticipated remedial actions. ii) GSPC must update the final environmental assessment (FEA) to reflect the special permit segment extension and the FEA section titled, “Affected Resources and Environmental Consequences” as necessary. GSPC must submit the updated FEA with its request for an extension to PHMSA for review and consideration. iii) Any request for a special permit segment extension does not become effective until GSPC receives a “no objection” response from the Director, PHMSA Engineering and Research Division. b) Any proposed special permit segment extension must meet the following requirements prior to the class location change or within 12 months of the class location change: i) GSPC must remediate all anomalies in accordance with Condition 8 – Anomaly Evaluation and Remediation; PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 26 of 33 <<>> ii) GSPC must have hydrostatically tested50 the special permit segment and extension in accordance with Condition 1 – Maximum Allowable Operating Pressure, as applicable; and iii) GSPC must complete all required special permit conditions, except Condition 17(b) above, for each special permit segment extension within two years of the Class 1 to Class 3 location change, unless specified otherwise. c) GSPC must apply all the special permit conditions and limitations included herein to all future special permit segment extensions. 18) Condition 18 – Certification GSPC must meet the following conditions for certification: a) A senior executive officer, vice president, or higher executive of GSPC must certify in writing the following: i) Each special permit inspection area and special permit segment meet the conditions described in this special permit; ii) GSPC has updated its O&M, IMP, and DP procedures required by Condition 2 – Procedure Updates to require the implementation of the special permit conditions for each special permit segment and special permit inspection area; and iii) GSPC has implemented all conditions as required by this special permit. b) GSPC must send the certifications required in Condition 18(a), with special permit condition status, completion date, compliance documentation summary, and the required senior executive signature and date of signature to the PHMSA Associate Administrator for Pipeline Safety with copies to the Director, PHMSA Central Region; the Director, PHMSA Engineering and Research Division; and the Federal Register Docket (PHMSA- 2023-0126) at www.regulations.gov within one year of the issuance date of this special permit. IV. Limitations This special permit is subject to the limitations set forth in 49 CFR § 190.341, as well as the following limitations: 50 For all in-service and pressure test failures, GSPC must perform a root cause analysis, including the metallurgical examination of the failed pipe, to determine if the failure is caused by a systemic or non-systemic issue. GSPC must provide the written results of this root cause analysis to the Director, PHMSA Central Region, within 90 days of the failure and must submit a copy of the root cause analysis to the Director, PHMSA Engineering and Research Division. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 27 of 33 <<>> 1) PHMSA has the sole authority to make all determinations on whether GSPC has complied with the specified conditions of this special permit. Failure to comply with any condition of this special permit may result in revocation of the permit. 2) Any work plans and associated schedules for a special permit segment and special permit inspection area are automatically incorporated into this special permit and are enforceable in the same manner. 3) Failure by GSPC to submit the certifications required by Condition 18 – Certification within the time frames specified may result in revocation of this special permit. 4) As provided in 49 CFR § 190.341, PHMSA may issue an enforcement action for failure to comply with this special permit. The terms and conditions of any corrective action order, compliance order, or other order applicable to a pipeline facility covered by this special permit will take precedence over the terms of this special permit. 5) If GSPC sells, merges, transfers, or otherwise disposes of all or part of the assets known as a special permit segment or special permit inspection area, GSPC must provide PHMSA with written notice of the change within 30 days of the consummation date. 6) PHMSA reserves the right to revoke, suspend, or modify the special permit if a material change occurs in conditions or circumstances underlying the permit. 7) PHMSA grants this special permit limited to a term of no more than 10 years from the date of issuance. If GSPC elects to seek renewal of this special permit, GSPC must submit its renewal request at least 180 days prior to expiration of the 10-year period to the PHMSA Associate Administrator for Pipeline Safety with copies to the Director, PHMSA Central Region, and to the Director, PHMSA Engineering and Research Division. All requests for a renewal must include a summary report in accordance with the requirements in Condition 15 – Annual Report above and must demonstrate that the special permit is still consistent with pipeline safety. PHMSA may seek additional information from GSPC prior to granting any request for special permit renewal. AUTHORITY: 49 U.S.C. § 60118 (c)(1) and 49 CFR § 1.97. Issued in Washington, D.C. on September 2, 2025. Linda Daugherty Acting Associate Administrator for Pipeline Safety PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 28 of 33 <<>> Appendix A – Tables Table 3 – Dent Criteria Dent type Critical Dents that Require Action ECA an Option Plain Dent Dent of depth > 6 percent outside diameter (OD) or dent strain level exceeding: i. Dent with strain > 6 percent limit (ASME B31.8, 2018 Edition) or ii. Strain limit damage (SLD) or ductile failure damage indicator (DFDI) > 0.6 (per API RP 1183, 1st Edition, 2020) YES Dent Associated with Corrosion** i. Dent depth of > 6 percent OD with corrosion of any depth or ii. Dent of depth ≤ 6 percent OD with corrosion depth that is more than 15 percent of the pipe wall thickness YES Dent Associated with Metal Loss other than Corrosion** Dent associated with metal loss other than corrosion: gouge, axial or circumferential groove, SCC, fatigue cracks, and/or other cracks YES Dent Affecting Weld (Girth Weld, Longitudinal Seam Weld) Dent of depth > 2 percent OD affecting other types of weld seams, see above, or girth welds with strain level exceeding 4 percent (ASME B31.8, 2018 Edition) YES Skewed and/or Multiple Dent Peaks Any complex dent geometry identified by GSPC or ILI vendor, such as skewed dent, two or multi-peak deformations YES ** Corrosion failure pressure with safety factor must meet the MAOP requirements in Condition 7 – Anomaly Evaluation and Remediation. Note: GSPC may use 49 CFR Part 192 compliant dent remediation procedures for the evaluation and remediation of a dent ≤ 6 percent OD, with a corrosion depth < 15 percent of the pipe wall, and corrosion failure pressure with safety factor that meets the MAOP requirements in Condition 7 – Anomaly Evaluation and Remediation. PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 29 of 33 <<>> Table 4 – Valves and Lateral Locations with Isolations Methods Required Valve Valve/ Nominal Special Permit Segment Nos. Valve Automation Automation Stationing Type Lateral Name Diameter Methodology (if applicable) (inches) Methodology for Special Permit51 0+00 Valve 298734 12 OPEN RCV Upstream 0+00 Valve to pig launcher 298733 16 CLOSED CLOSED 461+03 Upstream mainline valve 298737 16 OPEN RCV 1, 2 (starts at 728+40) 778+98 Downstream mainline valve of 1 Mid segment valve of 2 291086 16 OPEN RCV 779+36 Receipt 291089 12 CLOSED CLOSED 2 (ends at 803+12) 871+73 Valve to pig receiver 291091 16 CLOSED CLOSED 871+73 Downstream mainline valve 291096 12 OPEN RCV 51 Any isolation valve that is not an RCV or check valve must be blinded or closed. Isolation valve(s) shown as CLOSED, when opened, must be manned by GSPC personnel. Condition 12 – Mainline Valve – Monitoring and Remote Control for Ruptures is applicable to all crossover valves, valve spacing, and lateral tie-ins.PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Page 30 of 33 Special Permit – Class 1 to Class 3 Location – Grayson County, Texas <<>> Appendix B – Special Permit Segments and Inspection Area Route Maps Appendix B-1 Special Permit Inspection Area PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 31 of 33 <<>> Appendix B-2 – Special Permit Segments PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 32 of 33 <<>> Final Page of the Special Permit with Conditions PHMSA-2023-0126 – Gulf South Pipeline Company, LLC Special Permit – Class 1 to Class 3 Location – Grayson County, Texas Page 33 of 33 <<>> U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION Special Permit Analysis and Findings Class 1 to Class 3 Location Special Permit Information: Docket Number: PHMSA-2023-0126 Requested By: Gulf South Pipeline Company, LLC Operator ID#: 31728 Date Requested: November 15, 2023 Issuance Date: September 2, 2025 Code Sections: 49 CFR §§ 192.611(a) and (d) and 192.619(a) Purpose: The Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS),1 prepared this document to support the decision on the special permit application submitted by Gulf South Pipeline Company, LLC (GSPC)2 in the above-captioned proceeding. It 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. GSPC requested that PHMSA waive compliance from the 49 Code of Federal Regulations (CFR) §§ 192.611(a) and (d) and 192.619(a) for two natural gas transmission pipeline segments that experienced a change in class location from Class 1 to Class 3 due to an increase in population density. 3 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 Gulf South Pipeline Company, LLC is owned by Boardwalk Pipelines, LP. 3 As of the Issuance Date Special Permit Segment 1 is in a Class 1 location. GSPC applied to have Special Permit Segment 1 included in this special permit in anticipation of a class location change to Class 3 upon completion of Austin College’s planned development. PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 1 of 13 <<>> Pipeline System Affected: GSPC requested a waiver from the class location change requirements in 49 CFR §§ 192.611(a) and (d) and 192.619(a) for approximately 2.28 miles of the 16-inch diameter Index 819-10 Pipeline located in Greyson County, Texas. Pipe specifications, including outside diameter, year installed, seam type, coating type, pipe grade, wall thickness, maximum allowable operating pressure (MAOP), minimum pressure test pressure, and ratio of minimum test pressure to MAOP, are detailed in Table 1 – Pipe Specifications by Line Name. Table 1 – Pipe Specifications by Line Name Ratio of Outside Wall Min. Test Line Year Diameter Name Installed Seam Type MAOP Test Coating Type Grade Thickness Pressure (psig) Pressure to (inches) (inches) (psig) MAOP Index 819-10 16 2014 HF- ERW, SMLS Fusion Bonded Epoxy X60 0.25 1350 1897 1.41 Note: HF-ERW is a high-frequency electric resistance welded pipe longitudinal seam. SMLS is a seamless longitudinal seam. Without this special permit, 49 CFR § 192.611(a) would require GSPC to replace the special permit segments with stronger pipe or reduce the pipeline MAOP for a Class 1 to Class 3 location change. Special Permit Request: On November 15, 2023, GSPC applied to PHMSA for a special permit seeking relief from 49 CFR §§ 192.611(a) and (d) and 192.619(a) for the below-listed special permit segments. These segments experienced a class location change from the original Class 1 to a Class 3 on the 16-inch diameter Index 819-10 Pipeline located in Greyson County, Texas. GSPC’s special permit applies to the special permit segments and special permit inspection area as described and defined below using the GSPC mile post (MP) and survey station (SS) references: PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 2 of 13 <<>> Special Permit Segment: This special permit applies to the special permit segments in Table 2 – Special Permit Segments. Table 2 – Special Permit Segments Special Start End Pressure Material Outside Permit Line Diameter Name Length (feet) Survey Station Survey Station County or Parish, No. Year Seam MAOP Test Properties Segment Number Dwellings Installed Type (psig)4 Condition Condition (inches) State (SS) (SS) 1(b) Met 13(d) Met 1 16 Index 819-10 4580 585+22 631+32 Grayson 0 2014 HF – ERW, 1350 Yes Yes 2 16 Index 819-10 7472 728+40 803+12 Grayson 240 2013, 2014 HF – ERW, SMLS 1350 Yes Yes Special Permit Inspection Area: The special permit inspection area is defined as the area that extends 220 yards on each side of the centerline as listed in Table 3 – Special Permit Inspection Area. Table 3 – Special Permit Inspection Area Special Special Permit Outside Permit Inspection Diameter Line Name Start Survey Station End Survey Station Length (miles) Area Number Segment(s) Included (inches) (SS) (SS) 1 1, 2 16 Index 819-10 0+00 871+73 16.53 Public Notice: PHMSA published the special permit request in the Federal Register (89 FR 72152) for a 30-day public comment period from September 4, 2024, through October 4, 2024. The special permit application from GSPC, draft environmental assessment, and draft special permit conditions were available in Docket No. PHMSA-2023-0126 at www.regulations.gov for public review. PHMSA received three public comments. The Pipeline Safety Trust (PST) asked PHMSA to examine the two topics in its comments. The two anonymous commenters asked PHMSA to examine several additional topics. PHMSA addresses each of these comments below: • PST Topic One: PST expressed concern with the level of detail in the maps provided from GSPC and encouraged PHMSA to include an additional condition explicitly requiring that GSPC notify the public of the change in operation as outlined in 49 CFR § 192.616(e). PHMSA Response: The maps showed the pipeline right of way at a scale of one inch equal to 2,000 feet, allowing adequate depiction of buildings located near the pipeline right-of-way. Dwelling count included in special permit documents reflects the dwelling count at the time 4 Pressure tests were conducted after July 1, 1965; see 49 CFR § 192.619(a)(3) for applicability. PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 3 of 13 <<>> the application was processed, however GSPC anticipated future construction that will increase population density in the special permit segments to Class 3. Much of the projected construction is not yet built and therefore is not depicted on the map or current Google Map satellite images. The special permit as granted will not change the operation of the Index 819-10 pipeline but does include increased patrolling and emergency communications to protect public safety. The special permit does not excuse GSPC from full compliance with 49 CFR § 192.616, but subsection (e) does not require the operator to notify the public of the continuing use of current MAOP. • PST Topic Two: PST stated that GSPC did not provide an adequate justification or describe the unique operational circumstance that would make a special permit appropriate. PHMSA Response: Through the issuance of Federal Register Notice, “Pipeline Safety: Development of Class Location Change Waiver Criteria” (69 FR 38948; June 29, 2004), PHMSA described the unique circumstances under which it would allow special permit submittals to be considered for class changes. The Federal Register Notice has criteria that PHMSA uses to determine the suitability of a special permit segment to be considered (Attachment A – Segment Integrity Information and Attachment B – Special Permit Criteria). GSPC submitted these attachments for this special permit request, which have been posted to Docket No. PHMSA-2023-0126. PHMSA reviewed the attachments and used the information provided in determining the special permit conditions. In addition, two anonymous comments asked PHMSA to examine several topics: • Anonymous Topic One: The anonymous commenter stated the draft environmental assessment (DEA) did not evaluate the measures in-place and to be implemented for pipeline failure or rupture situations to protect the public in areas: 1) where there will be more than 46 people; 2) where emergency responders are housed; and 3) where emergency communications are located. PHMSA Response: PHMSA requires operators to have a public awareness plan that follows the general program recommendations of American Petroleum Institute (API) RP 1162 and assesses the unique attributes and characteristics of the operator’s pipeline and facilities. 49 CFR § 192.616(b). PHMSA also requires gas transmission line operators to have detailed plans for handling abnormal operations and responding to emergencies. 49 CFR §§ 192.605(c), (e), 192.615. This special permit does not waive or modify GSPC’s obligation to satisfy these requirements, which provide adequate protection for the areas identified by the anonymous commenter. • Anonymous Topic Two: The anonymous commenter stated that the DEA did not evaluate the consequences of the requested special permit segments effect on structures, emergency management, and occupancy by people for the “Globitech Semi-Conductor Factory” (1,500 employees), apartments (240 dwellings), Sherman Police Headquarters (has overall safety communications and may have prisoners), and Sherman Fire Station No. 4. PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 4 of 13 <<>> PHMSA Response: As part of its public awareness program, GSPC works with local, State, and Federal agencies in the event of an emergency to ensure the safety of the public, affected stakeholders, and the environment. Public awareness mailers are sent to all populations living or working near the pipeline, as well as emergency responders. A map included in the Final Environment Assessment (Attachment B-2 – Anticipated Class Changes) shows the Globitech Semi-Conductor Factory, and a 240-unit apartment complex were accounted for in the GSPC’s class location study. This special permit does not waive or modify GSPC’s obligation to implement its public awareness program, which provides adequate protection for the areas identified by the anonymous commenter. • Anonymous Topic Three: The anonymous commenter asked how evacuation activities will be handled should the pipeline leak or rupture and noted the potential impact radius (PIR) is 406 feet based upon 49 CFR § 192.903. The commenter further inquired whether the PIR is based upon giving people 30 seconds to identify and leave the PIR, and whether that is enough time to evacuate the area. PHMSA Response: Condition 12 of the special permit requires remotely monitored and operable valves to shut in pipeline segments quickly and minimize the volume of product released in the event of an emergency. PIR calculates the distance a potential pipeline failure could have significant impact on people or property and is not associated with any evacuation time. The National Transportation Safety Board (NTSB) Pipeline Incident Report NTSB/PIR-22/02 stated that “PHMSA’s PIR model assumes a 1 percent chance of mortality for a person with 30 seconds of exposure to find shelter.” The conditions of this special permit are designed to safeguard against a release occurring and reduce any risks to structures within the PIR. • Anonymous Topic Four: The anonymous commenter stated the NTSB has questioned the usage and effectiveness of the PIR calculation in 49 CFR § 192.903. The anonymous commenter also asked whether PHMSA has reviewed and updated the PIR definition or calculations to better communicate its meaning to the public and emergency responders. PHMSA Response: NTSB Safety Recommendation P-22-001 recommended revision of the PIR calculation methodology. In response to NTSB’s recommendation, PHMSA established a team to review the current calculation methodology. PHMSA also held a public meeting in Houston, Texas in December 2022, during which PHMSA presented an overview of NTSB’s report and discussed NTSB Recommendation P-22-001..5 The status of P-22-001 is open, and NTSB has rated PHMSA’s response as acceptable.6 Gas transmission line operators are required to comply with the provisions in 49 CFR § 192.903 in determining the PIR of covered segments. • Anonymous Topic Five: The anonymous commenter pointed out that the pipeline special permit segment may parallel a high voltage power line. If so, the commenter inquired what has been implemented to maintain pipeline safety. 5 PHMSA public meeting information is archived on PHMSA’s web site, https://primis-meetings-stage.phmsa.dot.gov. 6 https://data.ntsb.gov/carol-main-public/sr-details/P-22-001 PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 5 of 13 <<>> PHMSA Response: Condition 11 of the special permit requires monitoring and mitigating the effects of interference currents from electric transmission lines. • Anonymous Topic Six: The anonymous commenter stated that as of September 30, 2024, there were no public or local government responses to this special permit request. The commenter went on to inquire whether this public notification process was working as intended; and whether PHMSA is requiring GSPC to send out notices of the process to the public and local government agencies within the pipeline PIR, and if not, why. PHMSA Response: PHMSA published a notice in the Federal Register advising the public of the availability and opportunity to comment on the special permit application, DEA, and draft special permit conditions. • Anonymous Topic Seven: The anonymous commenter stated that Part 192 requires pipelines in a Class 3 location to be over 40 percent stronger (thicker wall pipe and/or high steel grade). The commenter asked how usage of a special permit can be as safe as modern pipe, which is stronger that the older pipe, and modern Class 3 construction techniques. PHMSA Response: The Index 819-10 Pipeline is a modern pipeline constructed in 2013 and 2014, and the enhanced integrity management (IM) practices to be implemented in the special permit segments are designed to provide an equivalent level of safety. The conditions of the special permit require the operator to apply IM to the entire pipeline and require additional conditions to be applied to the special permit segments that are more stringent than the requirements of the Federal pipeline safety regulations. • Anonymous Topic Eight – The anonymous commenter stated that PHMSA’s enforcement database indicates that GSPC has a history of past IM and corrosion control violations. The commenter provided the following examples of enforcement against GSPC: 1) Part 192, Subpart O, Integrity Management; 2) corrosion control; and 3) installation of Type A and B sleeves in Mississippi, Louisiana, and Texas, on Line Index 129 (717 sleeves were evaluated/remediated for improper installation) and Line 130 (686 sleeves were evaluated/remediated for improper installation). See CPF No. 2-2025-1001S dated July 23, 2015, on the PHMSA enforcement web site. PHMSA Response: PHMSA reviews the past performance of pipeline operators when evaluating whether to grant a special permit. PHMSA completed the review of past enforcement history with a summary of data considered included in this Special Permit Analysis and Findings document under Past Enforcement History – January 1, 2014, through October 31, 2024. PHMSA has determined that GSPC’s enforcement history does not provide a basis for denying this special permit. • Anonymous Topic Nine: The anonymous commenter asked why dents in “Attachment A – Dent Anomalies – Engineering Critical Assessment” of the proposed special permit conditions are allowed to be remediated. The commenter pointed to 49 CFR § 192.309(b), which the commenter stated requires dents over two percent of the pipe nominal diameter to be repaired or remediated during pipeline construction. The PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 6 of 13 <<>> commenter then asked when this pipeline was constructed and whether it followed the Code. PHMSA Response: The special permit conditions do not waive the repair criteria required by the code in 49 CFR §§ 192.309(a). The table shown in Attachment A – Dent Anomalies – Engineering Critical Assessment applies additional remediation criteria for dents above what is already required by the code. In-line inspection (ILI) data from a 2024 tool run using axial magnetic flux leakage, inertial mapping unit, and deformation tools indicated the pipeline does not have any dents greater than two percent of the pipe nominal diameter. The pipeline was originally constructed in 2013 and 2014, in accordance with applicable Code requirements. Dents can occur during construction but also as a result of third-party damage after construction. This special permit will require GSPC to inspect the line for metal loss and dents using ILI tools. • Anonymous Topic Ten: The anonymous commenter asked whether the proposed special permit – “Attachment A – Dent Anomalies – Engineering Critical Assessment” – allows the usage of API RP 1183 – (industry dent review document), which the commenter characterized as “a flawed (not reliable) technical document developed by the pipeline industry.” The commenter also asked whether API RP 1183 is being rewritten. If so, the commenter further inquired why “Attachment A – Dent Anomalies – Engineering Critical Assessment” is being allowed in the proposed special permit, whether 49 CFR § 192.309(b) requires dents over two percent of the pipe diameter to be removed or remediated for a pipeline constructed in the 2000s, and—if so—why a dent procedure is required in the special permit. PHMSA Response: Dents can be a result of third-party damage and can occur after construction. The special permit requires anomalies, including dents, to be analyzed and remediated as required by 49 CFR §§ 192.712 and 192.933, the requirements of Condition 8, and Appendix A – Table 3 – Dent Criteria. Table 3 requires action on plain dents if their strain limit damage or ductile failure damage indicator, calculated as defined in API RP 1183, are greater than 0.6. The API RP 1183 standard is not incorporated by reference into the Federal pipeline safety regulations. • Anonymous Topic Eleven: The anonymous commenter asked whether the maps for the proposed special permit PHMSA-2023-0126 are correct. The commenter stated that the maps seem to lack identification of highways, interstates, office buildings, police buildings, fire station, and apartments around this pipeline. Therefore, the commenter asked why all affected structures were not shown on the maps. PHMSA Response: The maps provided are correct and were only intended to show a high- level view of the pipeline route. Further information may be obtained from publicly available maps, including PHMSA’s National Pipeline Mapping System (NPMS). • Anonymous Topic Twelve: The anonymous commenter asked whether landowners and local public officials (within the potential impact area) were notified by a GSPC mail-out of this special permit request. If so, the commenter further inquired whether the local PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 7 of 13 <<>> landowners and public officials had any concerns. If a public mail-out was not conducted, the commenter wanted to know why. PHMSA Response: PHMSA published a notice in the Federal Register advising the public of the availability and opportunity to comment on the special permit application, DEA, and draft special permit conditions.. • Anonymous Topic Thirteen: The anonymous commenter pointed to 49 CFR § 192.616(e) – Public Awareness – which requires the public to be advised of pipeline operations. The commenter asked whether GSPC would need to notify the public about the special permit and send out this notice to the public through a mail-out program similar to requirements of 49 CFR § 192.616. PHMSA Response: No new facilities would be constructed as part of the special permit. Mailings are already conducted in accordance with 49 CFR § 192.616, and no additional mailings are required because of the special permit application. • Anonymous Topic Fourteen: The anonymous commenter noted that GSPC information documents to meet 49 CFR § 190.341(c) - (2)(iv), (4), (5), and (6) are not listed for public review at www.regulations.gov. The commenter stated that these Code sections require information or a listing/description/remediation of: 1) any anomalies, dents, corrosion, or inadequate soil cover; 2) how a factory, government building, police building, fire station, business, or apartment complex can be evacuated; (3) how people have been and will be notified and educated to recognize a gas leak or rupture and what to do for personnel safety. The commenter also stated that not all of this information was provided for public review. PHMSA Response: The information required by the referenced citations were, in some cases, inconsistent with the commenter’s descriptions; however, GSPC provided all required information required by 49 CFR § 192.341(c) in its special permit application. PHMSA is required by 49 CFR § 190.341(d)(1) to publish documents relating to the special permit application for public inspection, to the extent that such documents do not include information exempt from public disclosure, such as confidential commercial information. Therefore, not all the material PHMSA receives from an operator is required to be uploaded to the Federal Register. Analysis: Background: On June 29, 2004, PHMSA published in the Federal Register (89 FR 72152) the criteria it uses for the consideration of applications for class location change waivers, now being granted or denied through a special permit. First, certain threshold requirements should be met on a pipeline special permit segment 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 IM program elements are evaluated as significant criteria. These significant criteria are presented in matrix form and can be reviewed in the Federal Docket Management System, Docket No. PHMSA-RSPA-2004-17401. Third, special permits will only be granted when pipe conditions and active IM provide a level of safety PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 8 of 13 <<>> 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 GSPC special permit request. 1) No pipeline segments in a class location changing to Class 4 location will be considered. • This special permit request is for two special permit segments where a change has occurred, or is anticipated to occur, from a Class 1 location to a Class 3 location. • GSPC meets this requirement. 2) No bare pipe will be considered. • The special permit segments are externally coated with fusion bonded epoxy. • GSPC meets this requirement. 3) No pipe containing wrinkle bends will be considered. • There are no reported wrinkle bends in the special permit segments. • GSPC meets this requirement. 4) No pipe segments operating above 72 percent of the specified minimum yield strength (SMYS) will be considered for a Class 3 special permit: • The special permit segments operate at or below 72 percent SMYS. • GSPC meets this requirement. 5) 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. • GSPC has provided records that demonstrate the special permits segments have been tested to at least 1.25 times the MAOP. • GSPC meets this requirement. 6) ILI must have been performed with no significant anomalies identified that indicate systemic problems. • A high-resolution magnetic flux leakage (HR-MFL) ILI tool for corrosion and deformation ILI tool for denting was run in 2024 in the special permit segments with no significant anomalies discovered. PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 9 of 13 <<>> • GSPC meets this requirement. 7) 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 (special permit inspection area) as up to 25 miles of pipe on either side of the waiver segments (special permit segments). • GSPC has identified longer segments surrounding the special permit segments as the special permit inspection area. The special permit inspection area has been extended to the entire segment length between the upstream launcher and downstream receiver on each ILI segment that contains the special permit segments. Criteria Matrix: The data submitted by GSPC Attachment B – Special Permit Criteria for the special permit segments has been compared to the class location change special permit criteria matrix. • The following qualified for probable acceptance based on the criteria matrix: o Pipe manufactured in 2013, pipe material, design stress, pipe girth welds, fusion bonded epoxy pipeline coating, test pressure, test failures, local geology, type of service, pressure fluctuations, safety related conditions, IM program, ILI time frame, ILI type, direct assessment, coating assessment, damage prevention program, and leaks and failures, and cathodic protection. • The following qualified for possible acceptance based on the criteria matrix: o Class location change and enforcement history. • None of the special permit segments information qualified for required substantial justification based the criteria matrix. Operational Integrity Compliance: To inform PHMSA’s decision about whether a special permit could provide a level of safety greater than or equal to a pipe replacement or pressure reduction and is consistent with pipeline safety, PHMSA reviewed this special permit request to understand the integrity threats that are in the special permit segments and special permit inspection area. This integrity information informed the special permit conditions to ensure the operator follows a systematic program to analyze and remediate the pipeline for safety concerns through its operation. Additional operational integrity review and remediation requirements are required by this special permit to ensure that the operator has an ongoing program to locate and remediate safety threats. These threats to integrity and safety include any issues with the pipe coating quality, cathodic protection effectiveness, operations, damage prevention program, depth of soil cover over the pipeline, weld seam integrity, anomalies evaluation and remediation, and protection from cathodic protection interference. PHMSA has carefully designed a comprehensive set of conditions that GSPC must implement to comply with this special permit. PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 10 of 13 <<>> Past Enforcement History—January 1, 2014 through October 31, 2024: From January 1, 2014 through October 31, 2024, GSPC was cited in 17 enforcement actions with a total of $322,500 in assessed civil penalties. PHMSA issued one notice of amendment, four notices of probable violation, one safety order, and 11 warning letters to GSPC. Table 4 and Table 5 show PHMSA’s enforcement actions and civil penalties for GSPC. Table 4 – GSPC Enforcement Matters: January 1, 2014 - October 31, 2024 Notice of Status Corrective Action Order Notice of Probable Amendment Safety Order Warning Letter Total Violation Closed 0 1 4 1 11 17 Open 0 0 0 0 0 0 Total 0 1 4 1 11 17 Table 5 – GSPC Enforcement Civil Penalty Status January 1, 2014 - October 31, 2024 Proposed Awaiting Order Assessed Withdrawn/Reduced Collected $322,500 $0 $322,500 $0 $322,500 Summary of Enforcement Findings for GSPC includes: • Construction: Compliance with standards; Corrosion Control: Corrosion Control Records, External Corrosion Control Monitoring; Integrity Management: Elements and Implementation and Record Keeping; OME Procedural Manual: General and Maintenance and Normal Operations; Operations and Maintenance: Pressure limiting and Regulating Relief Devices, Transmission lines leak surveys, Emergency Plans, MAOP, and General; Operator Qualification: Qualification Program Reporting: National Registry of Pipeline Operators, and Immediate Reporting Incident; Transportation of Gas: Underground Natural Gas Storage Facilities; Design: Supports and Anchors, Transmission Line Valve, and Required Capacity of Pressure Relieving and Limiting Stations. • 49 CFR §§ 191.5, 191.22, 191.23, 192.12, 192.161, 192.179, 192.201, 192.303, 192.461, 192.465, 192, 491, 192.605, 192.615, 192.619, 192.706, 192.743, 192.805, 192.907, and 192.947. Summary of Enforcement Findings for the Boardwalk Gas Pipelines Companies—Texas Gas Transmission and GSPC: From January 1, 2014 through October 31, 2024, Boardwalk Pipelines LP (Boardwalk), the owner of GSPC, was cited in 64 enforcement actions with a total of $597,400 in assessed civil penalties on its Texas Gas Transmission, LLC (TGT) and GSPC pipeline systems. PHMSA issued six notices of amendment, one notice of probable violation, one safety order and 17 warning letters to Boardwalk. PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 11 of 13 <<>> Table 6 and Table 7, below, below show PHMSA’s enforcement actions and civil penalties Boardwalk on the TGT and GSPC pipeline systems with operator identification numbers 19270 and 31728, respectively. Table 6 – Boardwalk Enforcement Matters January 1, 2014 - October 31, 2024 Notice of Status Corrective Action Order Notice of Probable Amendment Safety Order Warning Letter Total Violation Closed 0 5 9 1 17 32 Open 0 1 2 0 0 3 Total 0 6 11 1 17 35 Table 7 – Boardwalk Enforcement Civil Penalty Status January 1, 2014 - October 31, 2024 Proposed Awaiting Order Assessed Withdrawn/Reduced Collected $1,064,000 $119,00 $597,400 $236,500 $597,400 The type of 49 CFR Part 192 enforcement violations against Boardwalk on these two pipeline systems from January 1, 2014 through October 31, 2024, were as follows: Summary of Enforcement Findings for GSPC and TGT: • Construction: Compliance with standards; Control Room Management; Alarm Management, Training Procedures, Operating Experience, Training, and Roles and Responsibilities; Corrosion Control: Atmospheric Corrosion Control, Corrosion Control Records, and Monitoring; Integrity Management: Elements and Implementation and Record Keeping; OME Procedural Manual: General and Maintenance and Normal Operations; Operations and Maintenance: Transmission lines leak surveys, Continuing Surveillance, Emergency Plans, MAOP, Pressure Limiting and Regulating Devices, and General; Operator Qualification; Qualification Program Reporting: National Registry of Pipeline Operators, Immediate Reporting Incident, Underground Natural Gas Storage Facilities, and Class Locations; Transportation of Gas: Compressor Station Design and Construction, Design of Pressure Relief and Limiting Devices, Compressor Stations Emergency Shutdown, and Longitudinal Joint Factor for Steel Pipe; Design: Supports and Anchors, Transmission Line Valve, and Required Capacity of Pressure Relieving and Limiting Stations. • 49 CFR §§ 191.5, 191.22, 191.23, 192.5, 192.12, 192.14, 192.113, 192.161, 192.163, 192.167, 192.179, 192.199, 192.201, 192.303, 192.461, 192.465,192.479. 192.481, 192.491, 192.555, 192.603, 192.605, 192.607, 192.615, 192.619, 192.631, 192.705, 192.706, 192.712, 192.743, 192.805, 192.907, and 192.947. PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 12 of 13 <<>> Findings: Based on the information submitted by GSPC and PHMSA’s analysis of the technical, operational, and safety issues, PHMSA finds that granting this special permit with conditions that require GSPC to operate the special permit segments on the 16-inch diameter Index 819-10 Pipeline located in Greyson County, Texas, at the current MAOP for a Class 1 to Class 3 location change segments are consistent with pipeline safety. PHMSA has designed the special permit conditions to assess any threats to the special permit segments and special permit inspection area effectively. To ensure that GSPC properly implements the special permit conditions, GSPC will be required to give PHMSA an annual review of their compliance with the special permit. PHMSA finds the issuance and full implementation of this special permit that waives the requirements of 49 CFR §§ 192.611(a) and (d) and 192.619(a) for a class location change to a Class 3 location is consistent with pipeline safety. This special permit requires GSPC to implement the special permit conditions that include safety requirements on the operations, maintenance, and integrity management of the special permit segments and the special permit inspection area. GSPC will be required to implement the special permit conditions along the special permit segments and special permit inspection area. Completed in Washington D.C. on: Month Day, 2025 Prepared By: PHMSA – Engineering and Research Division PHMSA-2023-0126 – Gulf South Pipeline Company LLC Special Permit Analysis and Findings Page 13 of 13 ## Provenance - Official: Yes - Source: - Source ID: `phmsa-special-permits` - SHA-256: `34dd99e01d25249412cad0a038d00d6976fb7a7bf0ed069e3fd810028867202d` - Retrieved: 2026-08-20T01:06:17.853Z - Exported: 2026-08-24T22:19:49.249Z - Document slug: `phmsa-special-permit-phmsa-2023-0126` ### Source metadata ```json { "materialSubtype": "pipeline_special_permit", "operator": "Gulf South Pipeline Company, LLC", "system": "Gas Transmission", "issuedOn": "2025-09-02", "issuanceStatus": "issued", "renewal": null, "indexUrl": "https://www.phmsa.dot.gov/pipeline/special-permits-state-waivers/special-permits-issued", "docketUrl": "https://www.regulations.gov/docket/PHMSA-2023-0126", "docketDocumentCount": 15, "decisionDocumentCount": 3, "decisions": [ { "id": "PHMSA-2023-0126-0013-09000064b8f3534a", "regulationsGovDocumentId": "PHMSA-2023-0126-0013", "title": "Gulf South Letter of Determination (LOD)", "postedDate": "2025-09-02", "documentUrl": "https://www.regulations.gov/document/PHMSA-2023-0126-0013", "pdfUrl": "https://downloads.regulations.gov/PHMSA-2023-0126-0013/attachment_1.pdf", "pdfArtifactPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2023-0126/phmsa-2023-0126-0013.pdf", "pdfArtifactSha256": "282e77ebab92e2c4b01a20728eb96cd0ffbb72fe77487904d9ffa3bc59667b64", "extractedTextPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2023-0126/phmsa-2023-0126-0013.txt", "extractedTextSha256": "bccc0d5689a45e1ec4055f654171ecab23d748061c28a6f8fa66cbe1d25e337c", "pageCount": 2, "extractionVersion": 2 }, { "id": "PHMSA-2023-0126-0014-09000064b8f35351", "regulationsGovDocumentId": "PHMSA-2023-0126-0014", "title": "Gulf South Special Permit Conditions", "postedDate": "2025-09-02", "documentUrl": "https://www.regulations.gov/document/PHMSA-2023-0126-0014", "pdfUrl": "https://downloads.regulations.gov/PHMSA-2023-0126-0014/attachment_1.pdf", "pdfArtifactPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2023-0126/phmsa-2023-0126-0014.pdf", "pdfArtifactSha256": "22578ee2222ff672a1787a0d9992bd53a37f100d6b47b7ae62816167a860804a", "extractedTextPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2023-0126/phmsa-2023-0126-0014.txt", "extractedTextSha256": "03614a89fff98d20c5536ee89d633ec882cc74af4bfc2a3927635df7b4418849", "pageCount": 33, "extractionVersion": 2 }, { "id": "PHMSA-2023-0126-0018-09000064b8f8b7e3", "regulationsGovDocumentId": "PHMSA-2023-0126-0018", "title": "PHMSA-250714-003_-_Outgoing_-_Final_8.29.25_SPAF 2023-0126 Gulf South", "postedDate": "2025-09-15", "documentUrl": "https://www.regulations.gov/document/PHMSA-2023-0126-0018", "pdfUrl": "https://downloads.regulations.gov/PHMSA-2023-0126-0018/attachment_1.pdf", "pdfArtifactPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2023-0126/phmsa-2023-0126-0018.pdf", "pdfArtifactSha256": "3ee1534c85567e72fc8ef695fe7c1bc70424c62456429fa237ad444bc51ed982", "extractedTextPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2023-0126/phmsa-2023-0126-0018.txt", "extractedTextSha256": "bd8a0c26ffa7f9abd4057d723901372aebf64270f6a1e491b7ab3f1174d06374", "pageCount": 13, "extractionVersion": 2 } ], "citedSections": [ "190.341", "192.611", "192.619", "192.5", "192.517", "192.603", "192.605", "192.903", "192.150", "192.493", "192.463", "192.465", "192.111", "192.917", "192.919", "192.921", "192.506", "192.939", "192.710", "192.614", "192.712", "192.933", "192.471", "192.473", "192.635", "192.615", "192.631", "192.745", "192.327", "192.61142", "192.609", "192.705", "192.616", "192.309", "192.341", "191.5", "191.22", "191.23", "192.12", "192.161", "192.179", "192.201", "192.303", "192.461", "192.706", "192.743", "192.805", "192.907", "192.947", "192.14", "192.113", "192.163", "192.167", "192.199", "192.479", "192.481", "192.491", "192.555", "192.607" ], "caveat": "The issued-permit index establishes issuance, not current validity or applicability to facilities beyond those covered by the permit. 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