# Gulf South Pipeline Company, LLC — Pipeline Special Permit - **operation:** document - **citation:** PHMSA-2023-0126 - **title:** Gulf South Pipeline Company, LLC — Pipeline Special Permit - **source type:** permit - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** current - **official:** true - **published on:** 2025-09-02 - **effective on:** 2025-09-02 - **summary:** PHMSA-2023-0126, issued 2025-09-02 for Gulf South Pipeline Company, LLC's gas transmission system. - **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2023-0126.json - **markdown:** https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2023-0126.md - **app url:** https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2023-0126 - **source url:** https://www.regulations.gov/docket/PHMSA-2023-0126 **body:** 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 permi - **truncated:** true - **body characters:** 123262