# Florida Gas Transmission — Pipeline Special Permit **Citation:** PHMSA-2023-0020 **Type / status:** permit / current **Agency:** Pipeline and Hazardous Materials Safety Administration **Effective:** 2023-08-22 **Published:** 2023-08-22 PHMSA-2023-0020, issued 2023-08-22 for Florida Gas Transmission's gas transmission system. ## Document text PHMSA pipeline special permit PHMSA-2023-0020. Operator: Florida Gas Transmission. System: Gas Transmission. Issue date: 2023-08-22. <<>> U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION Special Permit Analysis and Findings Class 1 to Class 3 Locations Special Permit Information: Docket Number: PHMSA-2020-0001 and PHMSA 2023-00201 Requested By: Florida Gas Transmission Company, LLC Operator ID#: 5304 Original Date Requested: December 18, 2019 Original Issuance Date: March 31, 2022 New Segments Request Date:2 March 24, 2023 Effective Dates:3 June 24, 2022, to March 31, 2032 Code Section(s): 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), 4 provides this information to describe the facts of the subject special permit 1 Special permits PHMSA-2020-0001 and PHMSA-2023-0020 are being combined into special permit PHMSA- 2020-0001. The new special permit segments 189579, 202967, 187434, 187440, and 202974 and special permit segment 165857 extension are added in Table 1 and are in the same special permit inspection areas that existed in the original special permit PHMSA-2020-0001. 2 On March 24, 2023, FGT requested the addition of five (5) special permit segments 189579, 202967, 187434, 187440, and 202974. These special permit segments were Federal Register noticed in Docket PHMSA-2023- 0020 and going forward will be addressed under special permit Docket PHMSA-2020-0001. A 455-foot extension to special permit segment 165857 was Federal Register noticed in Docket PHMSA-2020-0001 and added to this special permit Docket PHMSA-2020-0001. 3 The effective date for the implementation of the special permit conditions for special permit segments 189579, 202967, 187434, 187440, and 202974 and the 455-foot extension to special permit segment 165857 is grant date for the special permit that includes the five (5) new special permit segments and one (1) special permit segment extension. 4 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. PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 1 of 16 <<>> application submitted by Florida Gas Transmission Company, LLC (FGT), 5 to discuss any relevant public comments received with respect to the application, to present the engineering and safety analysis of the special permit application, and to make findings regarding whether the requested special permit should be granted and, if so, under what conditions. FGT requested that PHMSA waive compliance from the 49 Code of Federal Regulations (CFR) 192.611(a) and (d) and 192.619(a) for natural gas transmission pipeline segments, where the class location has changed from Class 1 to a Class 3 locations and from Class 2 to Class 3 locations. Pipeline System Affected: This existing special permit applies to the FGT request for a waiver of the class location change requirements in 49 CFR 192.611(a) and (d) and 192.619(a) for approximately 3.761 miles of gas transmission pipelines located in Brevard, Lake, Orange, and Osceola Counties, Florida. Special permit application (2023-0020) for five (5) new special permit segments and one (1) special permit segment extension increases the special permit mileage in the existing permit from approximately 3.761 miles to 4.406 miles (23,266 feet) of gas transmission pipelines located in Lake, Orange, and Osceola Counties, Florida. These special permit segments are in red in Table 2 – Special Permit Segments. 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 pressure test factor based on the minimum test pressure are detailed in Table 1 – Pipe Specifications by Line Name. Table 1 – Pipe Specifications by Line Name Outside Wall Min. Test Pressure Year Line Name Diameter Installed Seam Type MAOP Coating Type Grade Thickness Pressure Test (psig) (inches) (inches) (psig) Factor Mainline Loop CMPR STA 17-18 26 1968/1969 DSAW Coal Tar Enamel / Fusion Bonded Epoxy X60 0.294 977 1,347 1.38 Mainline Loop STA18-STA19 26 1968 DSAW MLV 18-1 to C/S 19 30 1995 DSAW Coal Tar Enamel / Copolymer Fusion Bonded Epoxy X60 X70 0.294 0.291 974 / 977 975 1,347 1,305 1.38 1.34 Note: DSAW is double submerged arc welded seam pipe. 5 FGT is owned by Energy Transfer and Kinder Morgan, Inc. Energy Transfer operates FGT. PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 2 of 16 <<>> Without this special permit, 49 CFR 192.611(a) would require FGT 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 December 18, 2019, FGT 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, where a class location change occurred from the original Class 1 to a Class 3 location and from a Class 2 to Class 3 location on the 26-inch diameter Mainline Loop STA18-STA19, 26-inch diameter Mainline Loop CMPR STA 17-18, and 30-inch diameter MLV 18-1 to C/S 19 Pipelines in Brevard, Lake, Orange, and Osceola Counties, Florida. On March 24, 2023, FGT applied to PHMSA for five (5) new special permit segments and one (1) special permit segment extension on the pipeline special permit inspection areas identified in Table 3 – Special Permit Inspection Areas. This special permit applies to the special permit segments and special permit inspection areas described and defined as follows, using the FGT survey station references: Special Permit Segments: This special permit applies to the special permit segments and is identified using the FGT survey station (SS) references as detailed in Table 2 – Special Permit Segments. PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 3 of 16 <<>> Table 2 – Special Permit Segments Special Permit Start End Outside MAO Diameter Line Name Length (feet) Survey Station Survey Station County, State Class Year Segment Number Summary Installed Seam Type/ Coating Type P (inches) (psig) (SS) (SS) 165856 26 Mainline Loop CMPR STA 17-18 2,368 1835+77 1859+45 Lake, FL 2 to 3 1969 DSAW/CTE 977 165857 26 Mainline Loop CMPR STA 17-18 216 2075+20 2077+36 Lake, FL 2 to 3 1968 DSAW/CTE 977 165857 extension6 26 Mainline Loop CMPR STA 17-18 455 2077+36 2081+91 Lake, FL 2 to 3 1968 DSAW/CTE 977 165858 26 Mainline Loop CMPR STA 17-18 724 2081+91 2089+15 Lake, FL 2 to 3 1969 DSAW/CTE 977 165859 26 Mainline Loop CMPR STA 17-18 587 2089+15 2095+01 Lake, FL 2 to 3 1969 DSAW/CTE 977 165860 26 643 165897 26 Mainline Loop STA18-STA19 169426 26 169427 26 169428 26 Mainline Loop CMPR STA 17-18 3,191 2195+14 2201+57 2 to 3 1969 2967+96 2978+65 1 to 3 Orange, FL DSAW/CTE DSAW/CTE 1968 977 977 189579 26 165900 26 Orange, FL Brevard, FL 1968 Mainline Loop STA18-STA19 614 1100+68 1106+82 Orange, FL 1 to 3 1968 DSAW/ Copolymer7 974 Mainline Loop STA18-STA19 4,618 1106+82 1153+00 Orange, FL 1 to 3 1968 DSAW/ Copolymer 974 1184+91 1 to 3 DSAW/ Copolymer 974 DSAW / Copolymer 974 DSAW/CTE 977 1,069 Mainline Loop STA18-STA19 Mainline Loop STA18-STA19 1153+00 60 1213+93 1214+53 Orange, FL 1 to 3 1968 Mainline Loop STA18-STA19 291 3435+06 3437+97 Brevard, FL 2 to 3 1968 165909 26 Mainline Loop STA18-STA19 1,588 3859+58 3875+46 Brevard, FL 2 to 3 1968 DSAW/CTE 977 170717 30 MLV 18-1 to C/S 19 3,668 24+758 61+43 Osceola, FL 1 to 3 1995 DSAW/FBE 975 165997 30 MLV 18-1 to C/S 19 282 61+43 64+25 Osceola, FL 1 to 3 1995 DSAW/FBE 975 202967 30 MLV 18-1 to C/S 19 159 620+94 622+53 Osceola, FL 1 to 3 1995 DSAW/FBE 975 187434 30 MLV 18-1 to C/S 19 4,869 807+18 855+87 Osceola, FL 1 to 3 1995 DSAW/FBE 975 187440 30 MLV 18-1 to C/S 19 285 1223+57 1226+42 Osceola, FL 1 to 3 1995 DSAW/FBE 975 202974 30 MLV 18-1 to C/S 19 4,451 1056+52 1101+03 Osceola, FL 1 to 3 1995 DSAW/FBE 975 Note: DSAW is a double submerged arc welded pipe longitudinal seam. FBE is fusion bonded epoxy external pipe coating. CTE is coal tar enamel external pipe coating. Special Permit Inspection Areas: The special permit inspection areas are defined as the area that extends 220 yards on each side of the centerline along approximately 185.7 miles of 26-inch diameter Mainline Loop CMPR 6 On March 24, 2023, FGT notified PHMSA that the existing special permit segment 16857 had been extended 455 feet through the implementation of Condition 17. 7 This special permit segment is coated with a butadiene-styrene copolymer external pipe coating. It is a high temperature resistant coating by Esso in the 1960’s. This coating system resembles green FBE however it does not contain any epoxy. It was used on portions of the FGT system just downstream of compressor stations and has proven to be a very effective coating system. 8 Previously, Special Permit Segment 170717 was corrected from Survey Station 60+17 to 24+75 due to a typo error in Table 1. PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 4 of 16 <<>> STA 17-18, 26-inch diameter Mainline Loop STA18-STA19, and 30-inch diameter MLV 18-1 to C/S 19 Pipelines as shown in Table 3 – Special Permit Inspection Areas. Table 3 – Special Permit Inspection Areas Special End Outside Start Survey Permit Special Permit Segment Number(s) Diameter Line Name Station Survey Station Length9 (miles) Inspection Area Name (inches) (MP) (MP) FLMEB-17 165856, 165857 and 165857 extension, 165858, 165859, 165860 26 Mainline Loop CMPR STA 17-18 608.00 668.8 60.8 FLMEB-18 165897, 165900, 165909, 169426, 169427, 169428, 189579 26 Mainline Loop STA18-STA19 668.8 742.5 73.7 FLMED1819 170717, 165997, 202967, 187434, 187440, 202974 30 MLV 18-1 to C/S 19 683.3 734.5 51.2 The special permit inspection areas are in Brevard, Lake, Marion, Orange, and Osceola Counties, Florida. 10 Figures 1 through 3 are maps showing the 26-inch diameter Mainline Loop CMPR STA 17-18, 26-inch diameter Mainline Loop STA18-STA19, and 30-inch diameter MLV 18-1 To C/S 19 Pipelines special permit segments and special permit inspection areas. Public Notice: On March 26, 2020, PHMSA posted a notice of this special permit request in the Federal Register (85 FR 17176) with a closing date of April 27, 2020. PHMSA received no comments on this special permit application during the comment period. PHMSA received the same comment repeated three (3) times several months after the close of the comment period. The comment criticized special permit application processing delay, but the comment did not provide an opinion on the safety or merit of this specific proposed special permit. PHMSA published the special permit request for the extension of special permit segment 165857 in the Federal Register (88 FR 34927) for a 30-day public comment period from May 31, 2023, through June 30, 2023. The special permit application from FGT, draft environmental assessment, and draft special permit conditions are available in Docket No. PHMSA-2020-0001 on the Federal Docket Management System (FDMS) located on the internet at 9 If the special permit inspection area footage does not extent from launcher to receiver, then the special permit inspection area would need to be extended. 10 The special permit inspection areas include the special permit segments. PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 5 of 16 <<>> www.Regulations.gov. PHMSA received no comments on this special permit application during the comment period. PHMSA published the special permit request for the five (5) new special permit segments in the Federal Register (88 FR 24464) for a 30-day public comment period from April 20, 2023, through May 22, 2023, with public comments to be posted on Docket PHMSA-2023-0020. PHMSA sought comments on any potential environmental impacts that could result from the selection of either alternative, including the special permit conditions. PHMSA received one (1) public comment for the five (5) new special permit segments on Docket PHMSA-2023-0020 in the FDMS located on the internet at www.Regulations.gov. • The Anonymous Comment recommended the special permit to not be issued to protect the environment and speed up the transition to renewable energy. PHMSA has conducted a review of the special permit request and has determined that implementation of the special permit conditions by FGT will not harm the environment. The request to speed up the transition to renewable energy is beyond the scope of this notice. PHMSA has reviewed this special permit application to ensure the special permit conditions address pipeline safety and integrity threats to the pipeline in the special permit segments and special permit inspection areas. The special permit will require FGT’s Operations and Maintenance (O&M) Manual and Procedures to provide a systematic program to review and remediate the pipeline for safety concerns. Additional operational integrity reviews and remediation requirements will be required by this special permit for these special permit segments for Class 1 to 3 location changes or Class 2 to 3 location changes. The FGT special permit application letter, Federal Register notice, FEA and FONSI, special permit with conditions, special permit analysis and findings document, and all other pertinent documents are available for review in Docket Nos. PHMSA-2020-0001 and PHMSA-2023-0020 in the FDMS located on the internet at www.Regulations.gov. Analysis: Background: On June 29, 2004, PHMSA published in the Federal Register (69 FR 38948) the criteria it uses for the consideration of applications for class location change waivers, now being PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 6 of 16 <<>> 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 integrity management program elements are evaluated as significant criteria. These significant criteria are presented in matrix form and can be reviewed in the FDMS, Docket No. PHMSA–RSPA-2004-17401. Third, special permits will only be granted when pipe conditions and active integrity management provides a level of safety greater than or equal to a pipe replacement or pressure reduction. The operator’s Federal pipeline safety regulation compliance history is also evaluated as part of the criteria matrix for acceptability prior to issuance of a special permit. Threshold Requirements: Each of the threshold requirements published by PHMSA in the June 29, 2004, Federal Register notice is discussed below regarding the FGT 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 the special permit segments on the FGT 26-inch diameter Mainline Loop CMPR STA 17-18, 26-inch diameter Mainline Loop STA18- STA19, and 30-inch diameter MLV 18-1 To C/S 19 Pipelines, where a change has occurred from a Class 1 location to a Class 3 location or a Class 2 location to a Class 3 location. • FGT has met this requirement. 2) No bare pipe will be considered. • The special permit segments are externally coated with coal tar epoxy or fusion bonded epoxy. FGT has met this requirement of no bare pipe. • FGT has not reported any coating issues such as disbonded coating. • FGT has met this requirement. 3) No pipe containing wrinkle bends will be considered. • There are no wrinkle bends in the special permit segments. • FGT has met this requirement. 4) No pipe segments operating above 72% 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% SMYS. PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 7 of 16 <<>> • The pipe for the special permit segments on the Mainline Loop CMPR STA 17-18 Pipeline is 26-inch diameter, 0.294-inch wall thickness, pipe strength of 60,000 psig. The pipe seam is a double submerged, arc-welded seam and was manufactured by Kaiser Steel in 1968. • The pipe for the special permit segments on the Mainline Loop STA18-STA19 Pipeline are 26-inch diameter, 0.294-inch wall thickness, pipe strength of 60,000 psig. The pipe seam is a double submerged, arc-welded seam and was manufactured by Kaiser Steel in 1968. • The pipe for the special permit segments on the MLV 18-1 To C/S 19 Pipeline are 30- inch diameter, 0.291-inch wall thickness, pipe strength of 70,000 psig. The pipe seam is a double submerged, arc-welded seam and was manufactured by Napa Pipe Corporation in 1993. • FGT has met this requirement. 5) Records must be produced that show a hydrostatic test to at least 1.25 x MAOP and 90% of SMYS. • The special permit segments on the Mainline Loop CMPR STA 17-18 Pipeline were pressure tested in 1968 at 1,349 psig for 24 hours. • The special permit segments on the Mainline Loop STA18-STA19 Pipeline were pressure tested in 1968 at 1,347 psig for 24 hours. • The special permit segments on the MLV 18-1 To C/S 19 Pipeline were pressure tested in 1994 at 1305 psig for eight (8) hours. • FGT has met this pressure requirement, but pressure test records must meet 49 CFR 192.517(a). 6) In-line inspection (ILI) must have been performed with no significant anomalies identified that indicate systemic problems such as stress corrosion cracking (SCC). • FGT ran ILI tools on the Mainline Loop CMPR STA 17-18 Pipeline in 2006, 2013, and 2020. • FGT ran ILI tools on the Mainline Loop STA18-STA19 Pipeline in 2004, 2011, and 2018. • FGT ran ILI tools on the MLV 18-1 To C/S 19 Pipeline in 2009 and 2015. PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 8 of 16 <<>> • FGT has had no SCC findings or failures on these segments. Due to the coating type and operational and environmental conditions of the pipeline, FGT has evaluated the special permit segments and special permit inspection areas as being not susceptible to SCC in accordance with ASME B31.8S. 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 segment (special permit segment). • A special permit would be contingent upon FGT’s incorporation of the special permit segments in its written integrity management program as covered segments in a high consequence area in accordance with 49 CFR 192.903 and to assess and remediate threats to the special permit inspection areas. Criteria Matrix: The data submitted by FGT for the special permit segments have been compared to the class location change special permit criteria matrix. The data fall within the probable acceptance or the possible acceptance column of the criteria matrix, except for PHMSA enforcement findings which fall under the requires substantial justification. • The special permit segments fall in the probable acceptance column of the criteria matrix for: o Class 2 to 3 location, pipe manufacturer (MLV 18-1 To C/S 19 Pipeline), pipe material, design stress, coating type (MLV 18-1 To C/S 19 Pipeline), girth welds (Mainline Loop STA18-STA19 and MLV 18-1 To C/S 19 Pipelines), depth of pipe cover, test pressure, test failures, local geology, type service, pressure fluctuations, safety related conditions, direct assessment, ILI type, and damage prevention program. • The special permit segments fall in the possible acceptance column of the criteria matrix for: o Class 1 to 3 location, pipe manufacturer (Mainline Loop CMPR STA 17-18 and Mainline Loop STA18-STA19 Pipelines), pipe coating type (may shield cathodic protection (CP) Mainline Loop CMPR STA 17-18 and Mainline Loop STA18- STA19 Pipelines), leaks and failures, CP, HCA program, and ILI program. PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 9 of 16 <<>> • The special permit segments fall in the requires substantial justification column of the criteria matrix for: o Pipe girth weld records are not available for the Mainline Loop CMPR STA 17- 18 Pipeline. o Energy Transfer and Kinder Morgan, Inc. are co-owners of FGT. Energy Transfers overall enforcement findings fall in the requires substantial justification category. FGT enforcement findings do not fall within this category. 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 known type of integrity threats that are in the special permit segments and special permit inspection areas. This integrity information was used to design special permit conditions to provide a systematic program to review and remediate the pipeline for safety concerns. 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, pipe depth of soil cover, weld seam and girth weld integrity, anomalies in the pipe steel and welds, and material and structures either along or near the pipeline that could cause the cathodic protection system to be ineffective. PHMSA has carefully designed a comprehensive set of conditions that FGT must implement to comply with this special permit. Past Enforcement History – January 1, 2013, through June 30, 2023: During January 1, 2013, through June 30, 2023, FGT was cited in eight (8) enforcement actions with a total of $1,050,900 in assessed civil penalties. PHMSA issued two (2) Corrective Action Orders, three (3) Notice of Probable Violation, two (2) Notices of Amendments, and one (1) Warning Letter to FGT. Tables 4 and 5 below show PHMSA enforcement actions and civil penalties for FGT: PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 10 of 16 <<>> Table 4 - FGT Enforcement Matters from January 1, 2013, through June 30, 2023 Notice of Status Corrective Action Order Notice of Safety Probable Amendment Order Warning Letter Total Violation CLOSED 1 2 1 0 1 5 OPEN 1 0 2 0 0 3 Total 2 2 3 0 1 8 Table 5 - FGT Enforcement Matters from January 1, 2013, through June 30, 2023 Proposed Awaiting Order Assessed Withdrawn/Reduced Collected $1,050,900 $834,400 $216,500 $216,500 $0 From January 1, 2013, through June 30, 2023, Energy Transfer, the operator of FGT, was cited in 35 enforcement actions with a total of $4,064,612 in assessed civil penalties on their Energy Transfer Company (ETC), Florida Gas Transmission Company (FGT), Panhandle Eastern Company (PEPL), Transwestern Pipeline Company (Transwestern), and Trunkline Gas Company (Trunkline) pipeline systems. PHMSA issued two (2) Corrective Action Orders, ten (10) Notice of Amendments, thirteen (13) Notices of Probable Violations, one (1) Safety Order, and nine (9) Warning Letters to Energy Transfer. Tables 6 and 7 below show PHMSA’s enforcement actions and civil penalties for Energy Transfer Partners on these pipeline systems – ETC, FGT, PEPL, Transwestern, and Trunkline with operator identification numbers (OPID#) 32099, 5304, 15105, 19610, and 19730. Table 6 - Summary of Enforcement Findings for ETC, FGT, PEPL, Transwestern, and Trunkline from January 1, 2013, through June 30, 2023 Notice of Status Corrective Action Order Notice of Safety Probable Amendment Order Warning Letter Total Violation CLOSED 1 9 10 1 9 30 OPEN 1 1 3 0 0 5 Total 2 10 13 1 9 35 PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 11 of 16 <<>> Table 7 - ETC, FGT, PEPL, Transwestern, and Trunkline Civil Penalty Status January 1, 2013, through June 30, 2023 Proposed Awaiting Order Assessed Withdrawn/Reduced Collected $4,064,612 $3,308,312 $756,300 $0 $756,300 Summary of enforcement findings for the ETC, FGT, PELP, Transwestern, and Trunkline systems include: construction, corrosion control, integrity management, procedural manual, operations and maintenance procedures, qualification of operating personnel, public awareness, reporting, welding, design, transportation of underground natural gas storage, and transportation of hazard liquids. These 49 CFR Part 192 code violations are in the following code sections: • 49 CFR 191.5, 191.23, 192.12, 192.167, 192.225, 192.402, 192.452, 192.463, 192.465, 192.467, 192.469, 192.471, 192.479, 192.481, 192.605, 192.615, 192.616, 192.619, 192.709, 192.739, 192.745, 192.805, 192.905, 192.907, 192.917, 192.919, 192.927, 192.933, 192.935, and 192.937. Table 8 below gives a complete summary of the findings and the specific 49 CFR Part 191 and 192 violations: Table 8 - Summary of Enforcement Findings for ETC, FGT, PEPL, Transwestern, and Trunkline January 1, 2013, through June 30, 2023 Construction 1 Corrosion Control 13 Integrity Management 29 OME Procedural Manual 17 Operation and/or Maintenance 14 Operator Qualification 2 Public Awareness 3 Reporting 4 Welding 1 Transportation of Design 1 Underground 2 Transportation of HL 2 Natural Gas Storage Grand Total: 89 PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 12 of 16 <<>> Findings: Based on the information submitted by FGT and PHMSA’s analysis of the technical, operational, and safety issues, PHMSA finds that granting this special permit to FGT to operate the special permit segments including five (5) new special permit segment and the extension of one (1) special permit segment on the 26-inch diameter Mainline Loop STA18-STA19, 26-inch diameter Mainline Loop CMPR STA 17-18, and 30-inch diameter MLV 18-1 to C/S 19 Pipelines in Brevard, Lake, Orange, and Osceola Counties, Florida, for approximately 4.406 miles (previous mileage was 3.761 miles) of Class 1 or Class 2 location pipe in a Class 3 location is consistent with pipeline safety. FGT’s enforcement record does not reflect sustained and substantial noncompliance with 49 CFR Part 192. PHMSA has designed special permit conditions to effectively assess and remediate threats to the special permit segments and special permit inspection areas, including assessments to evaluate pipe girth welds that have not been non-destructively tested, and any pipe with inadequate pressure test or material records. To ensure FGT properly implements the special permit conditions, FGT will be required to give PHMSA an annual review of their compliance with the special permit. PHMSA finds that no significant negative impact to human safety and the environment will result from the issuance and full implementation of a special permit that waives the requirements of 49 CFR 192.611(a) and (d) and 192.619(a) for class location changes to a Class 3 location. This permit requires FGT to implement the special permit conditions which include safety requirements on the operations, maintenance, and integrity management of the special permit segments and the special permit inspection areas. Completed in Washington DC on: August 22, 2023 Prepared by: PHMSA - Engineering and Research Division PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 13 of 16 <<>> Figure 1 – FGT Special Permit Segments and Inspection Areas PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 14 of 16 <<>> Figure 2 – FGT Special Permit Segments and Inspection Area PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 15 of 16 <<>> Figure 3 – FGT Special Permit Segments and Inspection Area Final Page of the Special Permit Analysis and Findings PHMSA-2020-0001 – Florida Gas Transmission Company Special Permit Analysis and Findings – Class 1 and 2 to Class 3 Locations - FL Page 16 of 16 <<>> U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration August 22, 2023 1200 New Jersey Avenue, SE Washington, DC 20590 Dave W. Shellhouse Vice President of Operations Florida Gas Transmission Company, LLC 2405 Lucien Way, Suite 200 Maitland, Florida 32751 Re: Docket Nos. PHMSA-2020-0001 and PHMSA-2023-0020 Special Permit from June 24, 2022, to March 31, 2032 Dear Mr. Shellhouse: On March 24, 2023, pursuant to 49 Code of Federal Regulations (CFR) § 190.341, Florida Gas Transmission Company, LLC (FGT) 1 applied to the Pipeline and Hazardous Materials Safety Administration (PHMSA) for a special permit (PHMSA 2023-0020) and a special permit segment extension for an existing special permit (PHMSA-2020-0001). FGT requested the 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 and an extension of an existing special permit segment. The class location changes includes six (6) pipeline segments consisting of approximately 0.098 miles (515 feet) of 26-inch diameter and approximately 1.849 miles (9,764 feet) of 30-inch diameter gas transmission pipeline (Pipeline) located in Lake, Orange, and Osceola Counties, Florida.2 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 where the class location has changed as defined in 49 CFR § 192.5. On April 20, 2023, and May 31, 2023, PHMSA published Federal Register notices (88 FR 24464 for Docket PHMSA-2023-0020 and 88 FR 34927 for Docket PHMSA-2020-0001) announcing the Special Permit Request for the five (5) special permit segments and one (1) special permit segment extension. The special permit conditions for Dockets PHMSA-2023-0020 and PHMSA-2020-0001 are being combined going forward into a single docket at Docket PHMSA- 1 Florida Gas Transmission Company, LLC is owned by Energy Transfer and Kinder Morgan, Inc. 2 The new pipeline segments are special permit segments 189579, 202967, 187434, 187440, and 202974 and total 9,824 feet in length. The extended special permit segment is special permit segment 16857 extension and total 455 feet in length. <<>> 2020-0001. The combination of the dockets is due to the special permit requests being in the same pipeline special permit inspection areas along the Pipeline. 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 both Docket Nos. PHMSA-2020- 0001 and PHMSA-2023-0020 in the Federal Docket Management System located at www.regulations.gov.3 Subject to the stated terms and conditions, PHMSA grants this special permit (enclosed) based on the information provided by FGT and the findings set forth in the SPAF, FEA, and FONSI. This special permit provides relief from certain provisions of the Federal pipeline safety regulations for the Pipeline and requires FGT to comply with conditions and limitations designed to maintain pipeline safety as defined in the special permit. Note that 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 FGT elects not to implement the special permit conditions, FGT must notify PHMSA within 60 days and comply with 49 CFR § 192.611(a) within 18 months of the date of this letter. My staff would be pleased to discuss this special permit or any other regulatory matter with you. Mary McDaniel, Acting Director of PHMSA Engineering and Research Division, may be contacted at (713) 272-2847, on technical matters; and Bryan Lethcoe, Director, Office of Pipeline Safety, Southwest Region, may be contacted at (713) 773-7215, for operational matters specific to this special permit. Sincerely, Alan K. Mayberry Associate Administrator for Pipeline Safety Enclosures: Special Permit – PHMSA-2020-0001 – Combined w/PHMSA-2023-0020 3 https://www.regulations.gov/docket?D=PHMSA-2020-0001. https://www.regulations.gov/docket?D=PHMSA-2023-0020.PHMSA-2020-0001 – Combined w/Docket PHMSA-2023-0020 Page 2 of 2 Letter of Decision – Florida Gas Transmission Company, LLC - Class Location – Florida <<>> U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION DRAFT SPECIAL PERMIT - Class 1 to 3 Location Special Permit Information: Docket Number: PHMSA-2023-0020 Requested By: Florida Gas Transmission Company, LLC Operator ID#: 5304 Original Date Requested: March 24, 2023 Original Issuance Date: Month Day, 20XX Effective Dates: Month Day, 20XX to Month Day, 20XX Code Section(s): 49 CFR 192.611(a) and (d) and 192.619(a) Proposed Grant of Special Permit: By this order, subject to the terms and conditions set forth below, the Pipeline and Hazardous Materials Safety Administration (PHMSA) Office of Pipeline Safety (OPS)1 proposes to grant this special permit to Florida Gas Transmission (FGT)2 for five (5) special permit segments consisting of approximately 0.1 miles of 26-inch diameter gas transmission pipelines and 1.85 miles of 30-inch gas transmission pipelines located in Orange and Osceola Counties, Florida. This special permit waives compliance from 49 Code of Federal Regulations (CFR) 192.611(a) and (d) and 192.619(a) for five (5) special permit segment(s) that have undergone changes from Class 1 to Class 3. The 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 after a change in class location. I. Purpose and Need FGT sought this special permit for Class 1 to Class 3 location changes occurring on the 26-inch diameter Mainline Loop CMPR STA 18-19 and 30-inch diameter MLV 18-1 to C/S 19 Pipelines. On 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 FGT is owned by Energy Transfer and Kinder Morgan. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 1 of 52 <<>> Special Permit Segment Number 189579 202967 187434 187440 202974 the condition that FGT complies with the terms and conditions set forth below, the proposed special permit would waive compliance from 49 CFR 192.611(a)3 and (d) and 192.619(a) for approximately 1.86 miles (9,824 feet) of natural gas transmission pipeline. This proposed special permit would allow FGT to maintain the current MAOP as shown in Table 1 – Special Permit Segments. II. Special Permit Segments and Special Permit Inspection Areas This proposed special permit pertains to the specified special permit segment(s) and corresponding special permit inspection areas defined in this section. Special Permit Segments: This proposed special permit applies to the special permit segments in Table 1 – Special Permit Segments and are identified using the FGT survey station (SS) references. Table 1 – Special Permit Segments Pressure Material - Start End Outside Line Name Seam Type/ External Test - Condition Diameter Length (feet) Survey Station Survey Station County or Parish, State No. Year MAOP Condition Dwellings Installed (inches) (SS) (SS) Coating Type (psig)4 13(d) Required (Yes) 26 1213+93 1214+53 Orange 974 30 30 30 30 1(b) Required (Yes) Mainline Loop CMPR 1 1968 DSAW/ Copolymer5 1346 Steel STA 18-19 MLV 18-1 to C/S 19 159 620+94 622+53 Osceola 18 1995 DSAW/ FBE 975 1305 Steel MLV 18-1 to C/S 19 4869 807+18 855+87 Osceola 76 1995 DSAW/ FBE 975 1305 Steel 285 1223+57 1226+42 1 1995 DSAW/ FBE 975 1305 Steel 1056+52 1101+03 178 1995 1305 Steel 60 MLV 18-1 to C/S 19 MLV 18-1 to C/S 19 Osceola 4451 Osceola DSAW/ FBE 975 Note: DSAW is a double submerged arc welded pipe longitudinal seam. FBE is fusion bonded epoxy external pipe coating. 3 PHMSA proposes to grant 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 (8) hours to meet 49 CFR 192.619(a)(2), 192.611(a), 192.517, and Condition 1(b). Each special permit segment must meet the documentation requirements in Condition 16 - Documentation. 4 Pressure tests were conducted after July 1, 1965, see 49 CFR 192.619(a)(3) for applicability. 5 This special permit segment is coated with a butadiene-styrene copolymer external pipe coating. It is a high temperature resistant coating by Esso in the 1960’s. This coating system resembles green FBE however it does not contain any epoxy. It was used on portions of the FGT system just downstream of compressor stations and has proven to be a very effective coating system. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 2 of 52 <<>> Special Permit Inspection Areas: The special permit inspection areas are defined as the area that extends 220 yards on each side of the centerline as listed in Table 2 – Special Permit Inspection Areas. Table 2 – Special Permit Inspection Areas Special Permit Special Permit Outside Start Survey End Survey Length6 Inspection Segment(s) Diameter Line Name Station Station (miles) Area Number Included (inches) (SS) (SS) 1 189579 26 FLMEB-18 1+90 3890+62 73.7 2 202967, 187434, 187440, 202974 30 FLMED1819 0+00 2738+66 51.2 Extended Special Permit Segments: The extended special permit segment is defined as the special permit segment and the five (5) contiguous miles past each endpoint. Attachment B contains general maps that include the pipeline route map showing the special permit segments and special permit inspection areas and more detailed maps showing the area near the special permit segments. PHMSA proposes to grant this special permit based on the findings set forth in the “Special Permit Analysis and Findings” and “Draft Environmental Assessment and Finding of No Significant Impact” documents, which can be read in their entirety in Docket No. PHMSA-2023-0020 in the Federal Docket Management System located on the internet at www.regulations.gov. III. Conditions PHMSA proposes to grant this special permit subject to FGT implementing the following conditions on the special permit segments and special permit inspection areas. Each condition detailed in this section applies to the special permit inspection areas and the corresponding special permit segments unless otherwise noted in the condition: 1) Condition 1 - Maximum Allowable Operating Pressure a) Maximum Allowable Operating Pressure: FGT must continue to operate each special permit segment and special permit inspection area at or below the existing MAOP of 974 6 If a special permit inspection area footage does not extent from launcher to receiver then the special permit inspection area would need to be extended. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 3 of 52 <<>> pounds per square inch gauge (psig) (Mainline Loop CMPR STA 18-19) and 975 psig (MLV 18-1 to C/S 19). b) Pressure Test: FGT must identify previous pressure tests for each special permit segment. Pressure test records for each special permit segment must meet 49 CFR 192.517(a) and be traceable, verifiable, and complete (TVC)7 as required in 49 CFR 192.624(a)(1).8 i) FGT must furnish TVC pressure test records to the Director, PHMSA Engineering and Research Division, and to the Director, PHMSA Southwest Region, within 60 days of the grant of the special permit. The pressure test records must be compliant with Condition 1(b). 9 FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, that the TVC pressure test records are compliant with 49 CFR 192.517(a), 192.624(a)(1), and 192.619(a)(1) through (a)(4) for a Class 1 location, or FGT must pressure test each special permit segment in accordance with Condition 1(b)(ii). ii) If FGT does not have a TVC record of a 1.25 times the MAOP hydrotest in accordance with Subpart J, or the special permit segment requires an updated pressure test, the special permit segment must be hydrostatically tested10 to a minimum of 1.39 times the MAOP for eight (8) continuous hours in accordance with 49 CFR Part 192, Subpart J, within 18 months of the grant of this special permit.11 c) MAOP Restoration or Uprating of Previously De-rated Pipe: MAOP restoration or uprating is not approved for this special permit. 7 TVC procedures and records must follow the following: 1) “Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements and Other Related Amendments”; 84 FR 52218 to 52219; October 1, 2019; and 2) PHMSA Advisory Bulletin: Pipeline Safety: Verification of Records; 77 FR 26822; May 7, 2012; https://www.gpo.gov/fdsys/pkg/FR-2012-05-07/pdf/2012-10866.pdf. 8 If PHMSA determines that the pressure test records supplied by FGT do not meet the requirements of TVC, the completion of Condition 1(b) will be required for each special permit segment. 9 The pressure test records must cover the entire length of the special permit segment, regardless of when the pipeline, single or multiple pipe joints, or other pipeline components were installed. Affidavits for a pressure test are not acceptable TVC pressure test records. 10 For all in-service and pressure test failures, FGT 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. FGT must provide the written results of this root cause analysis to the Director, PHMSA Southwest 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. 11 The grant of this special permit, as used throughout, is the signed issuance date of the special permit. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 4 of 52 <<>> 2) Condition 2 - Procedure Updates Within 90 days of the grant of the special permit, FGT must develop and maintain procedures in accordance with 49 CFR 192.603 and 192.605 that incorporate the special permit condition requirements as follows: a) Operations and Maintenance Manual: FGT must amend the applicable sections of its Operations and Maintenance (O&M) manual(s) and procedures to incorporate the special permit conditions. b) Integrity Management Program: i) FGT must incorporate each special permit segment into its written integrity management program (IMP) procedures as if the special permit segment is a “covered segment” as defined in 49 CFR 192.903, except for the reporting requirements contained in 49 CFR 192.945.12 A special permit inspection area outside of a special permit segment is 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 segment must have integrity threats identified, assessed, and remediated in accordance with these special permit conditions, 49 CFR 192.917, and 49 CFR Part 192, Subpart O. iii) Any high consequence area (HCA) in either a special permit segment or a 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 a special permit segment or to a special permit inspection area are applicable to HCAs where the HCA overlaps a special permit segment or a special permit inspection area. v) All special permit conditions that are applicable to a special permit inspection area are also applicable to the special permit segment. A special permit segment must meet the requirements of 49 CFR 192, Subpart O, if Subpart O is more stringent than the special permit conditions. 12 FGT must follow the reporting requirements in Condition 15 – Annual Report as well as those noted throughout the conditions contained herein. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 5 of 52 <<>> vi) The special permit inspection area must be able to be assessed using inline inspection (ILI) tools, including tethered or remotely controlled tools, in accordance with 49 CFR 192.150 and 192.493. c) Damage Prevention Program: FGT must incorporate within a special permit inspection area the applicable best practices of the Common Ground Alliance (CGA)13 in its damage prevention (DP) program. 3) Condition 3 – Corrosion Control FGT must promptly address any corrosion control deficiencies in a special permit segment that are indicated by the inspection and testing programs required under 49 CFR 192.463 and 192.465. a) Cathodic Protection Test Station Spacing: At least one (1) 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 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, FGT must monitor CP pipe-to-soil test stations to meet 49 CFR 192.463 and 192.465 for the special permit segment and must include “on and off” potential measurements. Test station readings (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. For hard spots 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, FGT 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. 13 Common Ground Alliance. (March 2020). Best Practices Guide. Retrieved from: https://commongroundalliance.com/BPguide. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 6 of 52 <<>> d) Remedial Action Plans: i) Within six (6) months of identifying a deficiency, FGT must develop a remedial action plan to restore CP to meet 49 CFR 192.463. Within two (2) months of the finding, FGT must apply for any necessary environmental permits (Federal or state). ii) FGT 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) FGT must perform an “on and off” current CIS at a maximum 5-foot spacing along the entire length of each special permit segment. 14 ii) FGT 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), FGT 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: FGT must perform the CIS within the following timeframes: i) Initial assessment must be completed for each newly incorporated and extended special permit segment 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.15 ii) Reassessments must be conducted every five (5) 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. 14 Each condition in this special permit that requires FGT to perform an action with respect to the special permit inspection area also requires FGT to perform that action on each special permit segment within the area. 15 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. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 7 of 52 <<>> c) Survey Remediation and Remedial Action Plans: i) If a special permit segment requires the use of 100 millivolt shift criteria16 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. FGT 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 (4) months of identifying a deficiency, FGT must develop a remedial action plan to restore CP to meet 49 CFR 192.463. Within two (2) months of the remedial action plan being developed, FGT must apply for any necessary environmental permits (Federal or state). iii) FGT 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.17 5) Condition 5 – Inline Inspection a) Threat Identification: FGT 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 extended special permit segment, 18 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 and National Association of 16 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.” 17 If remediation based upon the findings of the CIS is not practicable within 12 months of the CIS survey, FGT must submit a schedule and justify the delay 60 days prior to the 12-month completion requirement to the Director, PHMSA Southwest Region. FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to a pipe coating remediation schedule extension. 18 The extended special permit segment is defined as the special permit segment and the five (5) contiguous miles past each endpoint. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 8 of 52 <<>> Corrosion Engineers (NACE) Standard Practice (SP) 0204-2008, "Stress Corrosion Cracking Direct Assessment Methodology," Sections 1.2.1.1 and 1.2.2. b) Inline Inspection Methodology: FGT must conduct instrumented ILI integrity assessments in accordance with 49 CFR 192.493, for each special permit inspection area for all threats identified in accordance with 49 CFR 192.919 and 192.921. i) At a minimum, FGT 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), FGT must use an ILI tool19 that will identify tight cracks. 20 iii) A special permit segment with electric flash-welded (EFW) pipe must have an ILI tool assessment run for hard spots and cracking from hard spots. iv) In a special permit inspection area that has experienced pipe or girth weld leaks or ruptures due to soil movement or the threat has been identified, FGT 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: FGT must conduct initial assessments and reassessments for the special permit inspection areas in accordance with the following: i) Initial ILI assessments must be conducted as follows: (1) If a special permit segment has EFW pipe, it must be assessed for hard spots within 18 months of the special permit grant date. (2) If cracking has been identified as a threat for an extended special permit segment, it must be assessed within 18 months of the special permit grant date. (3) All other identified threats must be assessed within two (2) years of the special permit grant date. 19 The crack ILI tool must be comparable to an electro-magnetic acoustic transducer (EMAT) ILI tool. 20 FGT may propose an alternative assessment method for SCC (such as spike hydrostatic testing in accordance with 49 CFR 192.506) to the Director, PHMSA Southwest Region, with a copy of the proposal to the Director, PHMSA Engineering and Research Division. FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to implementing any alternative assessment methods for SCC. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 9 of 52 <<>> (4) For newly identified threats, assessments must be completed within two (2) years of identification. (5) 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: (1) 49 CFR 192.939(a); (2) Intervals of five (5) calendar years not to exceed 66 months, if a special permit segment contains any of the following: (a) low-frequency electric resistance welded (LF-ERW) or EFW pipe, (b) hard spots, (c) shorted carrier pipe to the casing, (d) susceptible to SCC, or (e) pipe or soil movement; or (3) The engineering critical assessment (ECA) determined interval, if applicable. iii) After conducting two (2) assessments of a threat, one (1) of which must be after the grant of this special permit, FGT may request reassessment intervals up to seven (7) years for that threat assessment. FGT must submit for and receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to implementing this change. iv) If factors beyond FGT’s control prevent the completion of an assessment within the required timeframe or reassessment interval, FGT must perform the assessment as soon as practicable, and FGT must submit a letter justifying the delay and provide the anticipated date of completion to the Director, PHMSA Southwest Region, no later than two (2) months prior to the end the timeframe or interval. FGT must receive a “no objection” letter from the Director, PHMSA Southwest 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. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 10 of 52 <<>> 6) Condition 6 - Girth Welds a) Construction Girth Weld Non-Destructive Test Records: FGT must provide records to PHMSA that demonstrate the girth welds in the special permit inspection area were either21: i) Non-destructively tested (NDT) at the time of construction in accordance with the Federal pipeline safety regulations at the time the pipelines were constructed, or ii) At least 1% of the girth welds and a minimum of two (2) girth welds in each special permit segment were NDT after initial construction and prior to the special permit application. FGT must demonstrate these welds were excavated, NDT, and repaired, if the welds do not meet Federal pipeline safety regulations at the time the pipelines were constructed. b) Missing Records: If FGT cannot provide girth weld records to PHMSA to demonstrate compliance with Condition 6(a), FGT must complete either Condition 6(b)(i) or both Conditions 6(b)(ii) and (iii) within 12 months of the grant of this special permit as follows: i) Certify to PHMSA, in writing, that there have been no in-service leaks or breaks in the girth welds in the special permit inspection area for the life of the pipeline; or ii) Evaluate the terrain along each special permit segment for threats to girth weld integrity from soil or settlement stresses, perform NDT, and remediate all such integrity threats;22 and iii) Excavate,23 visually inspect, and perform NDT on at least two (2) girth welds on each special permit segment in accordance with the applicable American Petroleum Institute Standard 1104, “Welding of Pipelines and Related Facilities” (API 1104) as follows: (1) Using the edition of API 1104 current at the time the pipeline was constructed; (2) Using the edition of API 1104 IBR in the Federal pipeline safety regulations at the time the pipeline was constructed; or (3) Using the edition of API 1104 currently IBR in 49 CFR 192.7. 21 FGT has not provided girth weld NDT records to PHMSA for the special permit segments and must meet Condition 6 – Girth Welds. 22 If a special permit segment has not had girth weld NDT to meet Condition 6 – Girth Welds and has experienced pipe or girth weld leaks or ruptures due to soil movement or the threat has been identified, then Condition 5(b)(iv) must be conducted within 12 months of the finding. 23 FGT must evaluate the pipe for SCC any time the special permit inspection area is uncovered or excavated in accordance with Condition 8(b) or (c) of this special permit. Pipe with fusion bonded epoxy coating does not require SCC evaluation when excavated unless SCC has been identified as a threat in the special permit inspection area. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 11 of 52 <<>> c) Defective Girth Welds: If any girth weld in a special permit segment is found unacceptable in accordance with the API 1104 IBR Edition at the time of pipeline construction, FGT must repair the girth weld immediately and then prepare an inspection and remediation plan for all remaining girth welds in the special permit segment based upon the repair findings and the threat to the special permit segment. FGT must submit the inspection and remediation plan for girth welds to the Director, PHMSA Southwest Region, and must receive a “no objection” letter for the girth weld remediation plan prior to its implementation.24 FGT must remediate girth welds in the special permit segment in accordance with the inspection and remediation plan within 90 days of the “no objection” letter receipt.25 7) Condition 7 - Stress Corrosion Cracking Threat FGT must evaluate the entire length of each special permit inspection area26 for SCC as follows: a) Threat Assessments: FGT must complete the SCC threat assessment as detailed in Condition 5(a) – Threat Assessment. b) SCC Integrity Assessment: If the threat assessment required under Condition 7(a) indicates the extended special permit segment27 is susceptible to either near-neutral or high-pH SCC, FGT must perform an SCC assessment on the extended special permit segment in accordance with Condition 5 – Inline Inspection. SCC integrity assessment using spike pressure testing is not approved for this special permit.28 c) Examination of Pipe: If the threat of SCC exists in the extended special permit segment as determined in Condition 7(a), FGT must directly examine the pipe 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), (d), and Condition 7(d) when the extended special permit segment is 24 The Director, PHMSA Southwest Region, must respond to FGT's submittal letter within 90 days of receipt with a decision letter, or either give FGT a request for additional information or a need of additional time for PHMSA to review the request. 25 FGT must include any plan requirements or comments received from the Director, PHMSA Southwest Region, into the remediation plan. 26 FGT has documented 0 occurrences of SCC or cracking in the [special permit segment/special permit inspection area]. 27 The extended special permit segment is defined as the special permit segment and the five (5) contiguous miles past each endpoint. 28 FGT may propose an alternative assessment method for SCC (such as spike hydrostatic testing in accordance with 49 CFR 192.506) to the Director, PHMSA Southwest Region, with a copy of the proposal to the Director, PHMSA Engineering and Research Division. FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to implementing any alternative assessment methods for SCC. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 12 of 52 <<>> uncovered for any reason to comply with the special permit and integrity management activities, not including One Call activities (49 CFR 192.614). d) Inspection of Pipe at Excavations: Except for pipe coated with non-shielding coatings (fusion-bonded or liquid-applied epoxy coatings) and excavations performed in accordance with 49 CFR 192.614(c), FGT must directly examine the pipe for SCC using non-destructive examination methods appropriate for the type of pipe and integrity threat conditions in the ditch. FGT must use appropriate methods for crack detection, such as phased array ultrasonic testing (PAUT), inverse wavefield extrapolation (IWEX), or magnetic particle inspection (MPI), 29 when an extended special permit segment is uncovered, and the coating has been identified as poor during the pipeline examination. Visual inspection is not sufficient to determine “poor coating.” FGT must “jeep” the excavated segment to determine the coating condition. Examples of “poor coating” include, but are not limited to, a coating that has become damaged and is losing adhesion to the pipe which is shown by falling off the pipe and/or shields the CP. FGT must keep coating records30 at all excavation locations in the special permit inspection area to demonstrate the coating condition. e) Discovery of SCC: If FGT discovers SCC31 activity by any means within the 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 the extended special permit segment has had an in-service or hydrostatic test SCC failure or leak, 32 the special permit segment must be further assessed and mitigated, within 18 months of finding SCC and reassessed every five (5) calendar years or less33 based upon the evaluated growth of the SCC, using one (1) of the following methods: 29 When MPI finds cracking, another method must be used to size the crack unless the crack can be completely ground out and still meet the pipeline MAOP. 30 The records must include, at a minimum, a description of FGT’s detection procedures, records of finding, and mitigation procedures implemented for the excavation. 31 “SCC” activity shall be defined as greater than 20 percent wall thickness depth and 2-inches in length. 32 For all in-service and pressure test failures, FGT 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. FGT must provide the written results of this root cause analysis to the Director, PHMSA Southwest 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. 33 FGT has the option to submit a written request to the Director, PHMSA Southwest Region, with a copy to the Director, PHMSA Engineering and Research Division, for extension of the crack assessment interval to seven (7) years, as defined in 49 CFR 192.939(a), if the ECA shows that five (5) calendar year assessments are not required. FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to extending the assessment interval to seven (7) calendar years. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 13 of 52 <<>> i) Spike Hydrostatic Test Program:34 (1) FGT must perform its SCC spike hydrostatic test program in an 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, FGT must replace the pipe joint that does not meet 49 CFR 192.611 in the extended special permit segment with new pipe. FGT must complete a successful SCC hydrostatic test prior to returning the extended special permit segment to operational service; ii) Crack Detection Tool Assessment: FGT 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: FGT must lower the MAOP of the special permit segment to 60% specified minimum yield strength (SMYS). iv) Pipe Replacement: FGT must replace all pipe and comply with 49 CFR 192.611 and 192.619 in the special permit segment; or v) Operating Pressure Lowered: FGT must lower the operating pressure of the special permit segment to 20% below the maximum pressure during the preceding 90-day operating interval until FGT conducts an ECA and remediates the special permit segment. f) SCC Remediation Plan: If FGT discovers any SCC activity in the extended special permit segment, FGT must submit an SCC remediation plan to the Director, PHMSA Southwest Region, and send a copy to the Director, PHMSA Engineering and Research Division, no later than 90 days after the finding of SCC.35 The plan must: i) Meet Condition 7(e) and include an SCC remediation/repair plan with SCC characterization and timing; or 34 FGT may propose an alternative assessment method for SCC (such as spike hydrostatic testing in accordance with 49 CFR 192.506) to the Director, PHMSA Southwest Region, with a copy of the proposal to the Director, PHMSA Engineering and Research Division. FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to implementing any alternative assessment methods for SCC. 35 For FGT to go forward with the technical justification for addressing the SCC threat, FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 14 of 52 <<>> ii) Include a technical justification that shows that FGT is addressing the threat for SCC in the special permit segment. 8) Condition 8 - Anomaly Evaluation and Remediation a) General: FGT must use the procedures specified in the special permit conditions, 49 CFR 192.712, and Attachment A when evaluating anomalies. FGT 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: FGT 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% accuracy for 80% of the time). FGT 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 FGT. FGT must compare previous indications to current indications that are significantly different. If a trend is identified where the tool has been consistently overcalling or under-calling, 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 either the special permit inspection area or from the complete ILI tool run segment if the continuous ILI segment is longer than 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 PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 15 of 52 <<>> documented for ILI calibrations prior to the ILI tool run. A minimum of four (4) calibration excavations must be used for unity plots.36 (2) EMAT ILI Tool Calibration: (a) ILI calibration for EMAT ILI Tools must be based upon excavation results of a minimum of the two (2) most severe anomalies from a combined review of crack depth and length. If the EMAT tool identifies only one (1) anomaly, the anomaly must be excavated and assessed. FGT can propose alternative EMAT ILI Tool evaluation procedures to the Director, PHMSA Southwest 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% probability of detection, FGT must provide the following to the Director, PHMSA Southwest Region: (1) EMAT ILI service provider report with any FGT provided reporting thresholds for cracking; (2) Calibration data showing the ILI tool meets API Standard 1163 IBR - Sections 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. (4) FGT must receive a “no objection” letter from the Director, PHMSA Southwest 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. 36 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, FGT must complete the following: (1) submit a plan for using known and documented pipeline features such as calibration excavation data, to the Director, PHMSA Southwest 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 Southwest Region, prior to performing the ILI tool calibration using pipeline features; (3) submit a report to the Director, PHMSA Southwest 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-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 16 of 52 <<>> iii) ILI Tool Evaluations: ILI tool evaluations for metal loss must use “6t x 6t”37 interaction criteria for determining anomaly failure pressures and response timing. iv) Discovery Date: The discovery date38 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”: FGT must remediate the special permit inspection area39 as follows: i) Immediate repair conditions for a “special permit inspection area”: FGT must repair the following conditions immediately upon discovery in a special permit inspection area: (1) Metal loss anomaly where the calculation of the remaining strength of the pipe shows a predicted failure pressure determined in accordance with 49 CFR 192.712(b) less than or equal to 1.1 times the MAOP at the location of the anomaly. (2) Metal loss greater than 80% of nominal wall, regardless of dimensions. (3) 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% of pipe wall thickness.40 (4) A dent located between the 8 o'clock and 4 o'clock positions (upper 2/3 of the pipe) that has metal loss, cracking, or a stress riser, unless an engineering analysis conducted in accordance with 49 CFR 192.712 and Attachment A demonstrates the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment. (5) A crack or crack-like anomaly meeting any of the following criteria: (a) Crack depth plus any metal loss is greater than 50% of pipe wall thickness; (b) Crack depth plus any metal loss is greater than the inspection tool’s maximum measurable depth; or 37 “6t” means pipe wall thickness times six (6). 38 Discovery date is the day, month, and year that FGT receives the ILI tool run results from the ILI tool service provider. 39 Throughout this special permit, the special permit inspection area includes the special permit segment, 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 of this condition for a special permit segment. The special permit segment has additional remediation criteria in later sections of this special permit condition. 40 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-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 17 of 52 <<>> (c) The crack or crack-like anomaly has a predicted failure pressure, determined in accordance with 49 CFR 192.712(d), that is less than 1.25 times the MAOP. (6) An indication or anomaly that, in the judgment of FGT, requires immediate action. ii) One-year conditions – Hard Spots for a “special permit inspection area”: FGT must repair by installation of a Type B sleeve or cut-out and recoat within 12 months of discovery, any hard spots found in the pipe body of EFW pipe discovered after the grant of the special permit with a hardness on the HB scale of either (1) 300 HB or greater and 2- inches in length or width; (2) 300 HB or greater with any cracking or metal loss over 10% of wall thickness; or (3) a single reading of 320 HB or greater at any location. iii) One-year conditions – dents, metal loss, and cracks for a “special permit inspection area”: FGT must repair the following conditions within 12 months of discovery in a special permit inspection area: (1) A smooth dent located between the 8 o'clock and 4 o'clock positions (upper 2/3 of the pipe) with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than nominal pipe size (NPS) 12), unless an engineering analysis conducted in accordance with 49 CFR 192.712 and Attachment A demonstrates the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment. (2) A dent with a depth greater than 2% of the pipeline diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or at a longitudinal or helical (spiral) seam weld, unless an engineering analysis conducted in accordance with 49 CFR 192.712 and Attachment A demonstrates the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment. (3) A dent located between the 4 o'clock and 8 o'clock positions (lower 1/3 of the pipe) that has metal loss, cracking, or a stress riser, unless an engineering analysis conducted in accordance with 49 CFR 192.712 and Attachment A demonstrates the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment. (4) Metal loss anomalies where a calculation of the remaining strength of the pipe shows a predicted failure pressure, determined in accordance with 49 CFR 192.712(b), at the location of the anomaly less than or equal to 1.39 times the MAOP for Class 2 locations, and 1.50 times the MAOP for Class 3 and 4 locations. For metal loss PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 18 of 52 <<>> anomalies in Class 1 locations outside of the special permit segment with a predicted failure pressure greater than 1.1 times the MAOP, FGT must follow the remediation schedule specified in ASME/ANSI B31.8S, Section 7, Figure 4. (5) Metal loss that is located at a crossing of another pipeline, is in an area with widespread circumferential corrosion, or could affect a girth weld, with a predicted failure pressure determined in accordance with 49 CFR 192.712 less than 1.39 times the MAOP for Class 1 locations or where Class 2 locations contain Class 1 pipe, or 1.50 times the MAOP for all other Class 2 locations and Class 3 and Class 4 locations. (6) Metal loss preferentially affecting a detected pipe weld seam, if that seam was formed by direct current, low-frequency or high-frequency electric resistance welding, electric flash welding, or that has a longitudinal joint factor less than 1.0 (49 CFR 192.113), and where the predicted failure pressure determined in accordance with 49 CFR 192.712(d) is less than 1.39 times the MAOP for Class 1 locations or where Class 2 locations contain Class 1 pipe, or 1.50 times the MAOP for all other Class 2 locations and Class 3 and Class 4 locations. 41 (7) A crack or crack-like anomaly that has a predicted failure pressure determined in accordance with 49 CFR 192.712(d) that is less than 1.39 times the MAOP for Class 1 locations or where Class 2 locations contain Class 1 pipe, and 1.50 times the MAOP for all other Class 2 locations and Class 3 and Class 4 locations. iv) Two-year condition for crack repairs for a “special permit inspection area”: FGT must remediate any crack or crack-like anomaly that has a crack depth greater than 40% of the pipe wall thickness within two (2) years of discovery that are in the special permit inspection area and area outside of the special permit segment. (v) Monitored conditions for a “special permit inspection area”: FGT 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. Monitored conditions are the least severe and will not require examination and evaluation until the next scheduled integrity assessment. 41 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-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 19 of 52 <<>> (1) A dent with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than NPS 12) located between the 4 o'clock position and the 8 o'clock position (bottom 1/3 of the pipe), and engineering analyses of the dent conducted in accordance with 49 CFR 192.712 and Attachment A demonstrates the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment. (2) A dent located between the 8 o'clock and 4 o'clock positions (upper 2/3 of the pipe) with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than NPS 12), and engineering analyses of the dent conducted in accordance with 49 CFR 192.712 and Attachment A demonstrates the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment. (3) A dent with a depth greater than 2% of the pipeline diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or longitudinal or helical (spiral) seam weld, and engineering analyses conducted in accordance with 49 CFR 192.712 and Attachment A to demonstrate the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment. (4) A dent that has metal loss, cracking, or a stress riser, and an engineering analysis conducted in accordance with 49 CFR 192.712 and Attachment A to demonstrate the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment. (5) Metal loss preferentially affecting a detected pipe weld seam and where the predicted failure pressure determined in accordance with 49 CFR 192.712(d) is greater than or equal to 1.39 times the MAOP for Class 1 locations or where Class 2 locations contain Class 1 pipe, or 1.50 times the MAOP for all other Class 2 locations and Class 3 and Class 4 locations.42 (6) A crack or crack-like anomaly for which the predicted failure pressure, determined in accordance with 49 CFR 192.712(d), is greater than or equal to 1.39 times the MAOP for Class 1 locations or where Class 2 locations contain Class 1 pipe, or 1.50 times the 42 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-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 20 of 52 <<>> MAOP for all other Class 2 locations and Class 3 and Class 4 locations.43 The crack depth is less than 40% of the pipe wall thickness. c) Remediation schedule for a “special permit segment”: In addition to the requirements in paragraphs (a) and (b) of Condition 8 for a special permit inspection area, FGT must remediate conditions in a special permit segment as follows:44 i) One-year conditions for a “special permit segment”: FGT must repair the following conditions within one (1) year of discovery in a special permit segment: (1) Pipe Wall: Pipe wall thickness metal loss greater than 40%. (2) Weld Metal: Girth weld metal loss greater than 30% of pipe wall thickness or pipe weld seam metal loss greater than 15% of pipe wall thickness.45 (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 a “special permit segment”: FGT 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% of the pipe wall thickness. 43 Failure stress pressure and crack growth analysis of cracks and crack-like defects must be determined using a technically proven fracture mechanics model appropriate to the failure mode (ductile, brittle or both) and boundary condition used (pressure test, ILI, or other). Examples of technically proven models include but are not limited to: for the brittle failure mode, the Raju/Newman Model; for the ductile failure mode, Modified LnSec, API RP 579-1/ASME FFS-1, June 15, 2007, (API 579-1, Second Edition) – Level II or Level III, CorLas™, PAFFC, and PipeAccessTM. All crack fracture mechanic evaluation models must be used within the assessment limits of the model. 44 The special permit inspection area includes the special permit segment, 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 segment must also be remediated to meet all additional remediation requirements specifically for the special permit segment as required in the special permit conditions. 45 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-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 21 of 52 <<>> iii) Un-cleared shorted casing for a “special permit segment”: FGT 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% of the pipe wall thickness. iv) Monitored conditions for a “special permit segment”: FGT 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. (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% 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% 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% of pipe wall thickness. 9) Condition 9 - Pipe Casings FGT must identify all shorted casings within a special permit segment no later than six (6) 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, Direct Current Voltage Gradient (DCVG), Alternating Current Voltage Gradient (ACVG), or AC Attenuation.46 a) Clear Shorted Casings: Where practical, FGT must clear shorted casings identified within a special permit segment no later than 12 months after the grant of this special permit as follows: i) Metallic Shorts: FGT must clear any metallic short on a casing in a special permit segment no later than 12 months after the short is identified. 46 As of the date of the grant (issuance date) of this special permit, FGT reported they identified zero (0) shorted casings within a special permit segment. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 22 of 52 <<>> ii) Electrolytic Shorts: FGT 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 FGT identifies any shorts after uprating, they must be cleared no later than 12 months after identification. iii) All Shorted Casings: FGT 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. FGT 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 FGT completed an assessment and all necessary repairs. b) Remediation of Un-cleared Casing Shorts: If it is impractical for FGT to clear a shorted casing within a special permit segment, FGT must document the actions taken to remediate the shorted casing and must receive a “no objection” letter from the Director, PHMSA Southwest Region, to use ILI assessments instead of clearing the short.47, 48 In addition to the notification, FGT 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 (5) calendar year assessment schedule, not to exceed 66 months. ii) FGT must remediate any identified corrosion, cracking, or other anomalies in accordance with Condition 8 – Anomaly Evaluation and Remediation. 10) Condition 10 - Pipe - Seam Evaluations FGT must conduct engineering integrity assessments to identify any pipe in the extended special permit segment 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: 47 The Director, PHMSA Southwest Region, must respond to FGT’s submittal letter within 90 days. The Director, PHMSA Southwest Region, may provide a decision, request for additional information, or notify FGT of PHMSA’s need for additional time to provide a decision. 48 FGT must send a copy of the actions taken to clear the shorted casing to the Director, PHMSA Engineering and Research Division. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 23 of 52 <<>> a) Identify and Test Pipe Seam Issues: i) Within 12 months of the special permit grant, FGT must perform an engineering integrity analysis to determine if the pipe seam is susceptible to seam threats located in the extended special permit segment. 49 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 the extended special permit segment that are a threat to the integrity of the pipeline, FGT must confirm there are no systemic issues with the weld seam or pipe. Within 12 months of analysis completion, FGT 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: i) If the pipeline experienced a seam leak or failure in the last five (5) years and FGT did not perform a hydrostatic test meeting Condition 1(b) after the seam leak or failure in the special permit segment of the same weld seam and manufacturer, then FGT must complete a hydrostatic test to a minimum of 1.39 times the MAOP within 18 months after the grant of this special permit in the special permit segment. ii) FGT must determine from the hydrostatic test whether there are systemic issues with the weld seam or pipe. FGT 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. FGT must provide the written results of this root cause analysis to the Director, PHMSA Southwest Region, within 90 days of the failure.50 49 The extended special permit segment is defined as the special permit segment and the five (5) contiguous miles past each endpoint. 50 FGT must send a copy of the root cause analysis to the Director, PHMSA Engineering and Research Division. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 24 of 52 <<>> c) Pipe Replacement: The special permit segment must be replaced if any of the following conditions exist or are discovered after the grant of this special permit: i) The special permit segment has any direct current-electric resistance welded (DC-ERW) seam or pipe with a longitudinal joint factor below 1.0 as defined in 49 CFR 192.113; ii) The special permit segment pipe has any LF-ERW or EFW seam pipe joints that had pipe seam leaks or ruptures and the pipe has not been replaced with new pipe;51 iii) Pipe in the extended special permit segment was constructed or manufactured prior to 1954 and had pipe seam leaks or ruptures;52 iv) The special permit segment pipe has unknown manufacturing processes (i.e., unknown seam type, yield strength, or wall thickness); or v) The special permit segment pipe has known manufacturing or construction issues that are unresolved, 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 a special permit segment, FGT 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 (6) months of the grant of this special permit or within six (6) months of the identification. e) Remediation Plan: FGT must remediate all weld seam leaks, failures, or ruptures53 discovered in the special permit segment. FGT must submit a seam remediation plan for the special permit segment to the Director, PHMSA Southwest Region, no later than 30 days after finding a seam leak, seam failure, or seam rupture in the special permit segment containing one (1) of the following: 51 As of the date of the grant of this special permit, FGT reported no LF-ERW or EFW seam pipe in a special permit segment. 52 As of the date of the grant of this special permit, FGT reported no pipe manufactured prior to 1954 with seam integrity issues in a special permit segment. 53 For all in-service and pressure test failures, FGT 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. FGT must provide the written results of this root cause analysis to the Director, PHMSA Southwest 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-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 25 of 52 <<>> 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 (6) 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 FGT must address induced alternating current (AC) from parallel electric transmission lines and other interference issues, such as direct current (DC), that may affect the pipeline in a special permit segment. FGT must have an induced AC or DC program and remediation plan to protect the pipeline from corrosion caused by stray currents within 12 months of the grant of this special permit. a) Surveys: FGT must perform periodic interference surveys to detect the presence and level of any electrical stray current, including when there are current flow increases over the special permit segment grounding design from any co-located pipelines, structures, or high voltage alternating current (HVAC) powerlines, including from additional generation, a voltage up rating, additional lines, new or enlarged power substations, new pipelines or other structures. b) Analysis of Results: FGT must analyze the results of the survey to determine the cause of the interference and whether the level could cause significant corrosion (defined as 100 amps per meter squared for AC-induced corrosion), or if the interference impedes the safe operation of the pipeline, or that may cause a condition that would adversely impact the environment or the public. c) Remediation: Remedial action is required when the interference in the special permit segment is at a level that could cause significant corrosion (defined as 100 amps per meter squared for AC-induced corrosion), or if it impedes the safe operation of a pipeline, or may cause a condition that would adversely impact the environment or the public. Within six (6) months after completing the interference survey, FGT must develop a remediation procedure and apply for any necessary permits to conduct remediation. FGT must complete all remediation within six (6) months, or as soon as practicable, after obtaining the necessary permits for the remediation. d) Completion Schedules: If environmental permitting or right-of-way factors beyond FGT’s control prevent the completion of any remediation within six (6) months of completing the PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 26 of 52 <<>> interference engineering analysis of the survey results, FGT 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 Southwest Region, no later than one (1) month prior to the end of the six (6) month completion date. Any extended evaluation and remediation schedules submitted to PHMSA from FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region. 12) Condition 12 - Mainline Valve – Monitoring and Remote Control for Ruptures FGT must automate mainline valves54 for closure or demonstrate capability to manually close mainline valves in accordance with the requirements of this Condition 12. A special permit segment must have upstream and downstream automatic shutoff valves (ASVs) or remote- controlled valves (RCVs) so that the distance between the valves is no greater than 20 miles.55 FGT 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 segment must have procedures for rupture isolation as follows: a) Valve Locations: ASVs or RCVs must be installed as shown in Table 4 - Valves and Lateral Locations with Isolations Methods. Each special permit segment must have telemetry connections to the FGT supervisory control and data acquisition (SCADA) system installed. b) Automatic Shutoff Valve Requirements: i) If an ASV is used, FGT must confirm the 30-minute ASV shut-in pressure for a special permit segment after “notification of potential rupture” by flow modeling of the special permit inspection area and any looped pipelines or gas receipt tie-ins between the ASVs or RCVs. Flow modeling must include anticipated maximum, normal, or any other flow volumes, pressures, or any other operating conditions that may be encountered during the calendar year. The flow model detection for a rupture must be based upon 0.500 times the pipe diameter area or smaller pipe area (partial pipe opening) for rupture sizing to account for pressure drop. If operating conditions change that could affect the ASV set pressures and the 30-minute isolation time after “notification of potential rupture,” a new flow model must be conducted and ASV set pressures must be reset prior to the next review for ASV set pressures. If the special permit segment cannot be isolated within 30 minutes of a 54 A mainline valve is a sectionalizing valve used to isolate or stop gas flow upstream or downstream along the pipeline. 55 If the distance between mainline isolation valves exceed 20 miles, additional mainline valve(s) must be added. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 27 of 52 <<>> “notification of potential rupture” by usage of ASVs, then RCVs must be installed. Table 4 - Valves and Lateral Locations with Isolations Methods has the ASV shutoff pressures and shutoff times for isolation of the special permit segment after “notification of potential rupture.” ii) ASVs must be equipped with rupture sensing equipment to detect the special permit segment “rate of pressure drop” with a set-point of [SET_POINT-20-40] psig/minute or less unless FGT submits a request for a “rate of pressure drop” set-point change and receives a “no objection” letter from the Director, PHMSA Southwest Region, for any revised shut-in pressures prior to their implementation. iii) ASV shut-in pressures must be confirmed and reset on a calendar year basis not to exceed 15 months. FGT must submit initial and annual ASV shut-in pressures to the Director, PHMSA Southwest Region, as detailed in Condition 15 – Annual Report, and receive a “no objection” letter from the Director, PHMSA Southwest Region, for any revised shut-in pressures prior to their implementation. The Director, PHMSA Southwest Region, must respond to FGT’s submittal letter within 90 days with a decision letter, or either give FGT a request for additional information or additional time for PHMSA to review the request. iv) If the pipeline is impacted by extreme weather or other emergency conditions that reduce pipeline operating pressures in the special permit segment to operating pressures where the ASV shut-in pressures require emergency resetting, FGT may reset ASV shut-in pressures below the operating pressure requirements for a maximum period of seven (7) days, but must notify the Director, PHMSA Southwest Region, within two (2) days of the pressure reset. c) Remote Monitoring and Control: Each special permit segment must be controlled by a SCADA system and must be equipped for remote monitoring and control, or remote monitoring and automatic control, in accordance with 49 CFR 192.620(d)(3)(iii) and the below requirements in this Condition 12. d) Crossover or Lateral Pipe Connection Isolation: If any crossover or lateral pipe56 connects to the isolated segment between the upstream and downstream mainline valves, the nearest valve on the crossover connection(s) or lateral(s) must be isolated such that, when all valves 56 Table 4 - Valves and Lateral Locations with Isolations Methods has a listing of all lateral valves. FGT must update Table 4 if a mainline, lateral, or crossover valve was mis-identified, added, or modified after the grant of the special permit and submit this update in accordance with Condition 15. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 28 of 52 <<>> 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. 57 Valves that are in the FGT O&M procedures as locked closed and that are only opened when manned by FGT operating personnel do not require RCVs or ASVs for closure. e) Remote-Control and Automatic-Shutoff Valve Status: i) RCVs must be constantly monitored for valve status (open, closed, or partial closed/open), upstream pressure, and downstream pressure. ii) A special permit segment with ASVs must have a minimum of one (1) pressure monitoring point within the segment when the mainline valve locations do not have pressure monitoring. If an ASV is used, FGT must determine the set pressure used in Condition 12(b) on a calendar year basis not to exceed 15 months and must report the set pressure to PHMSA each year in the Condition 15 - Annual Report. ASV pressure settings must be determined by flow modeling of the special permit segment, special permit inspection area, and all looped, delivery, or receipt pipelines tied into the special permit inspection area that could affect pressures in the special permit segment. If the ASV pressure settings cannot be accurately determined, RCVs must be installed for the special permit segment. The shutdown time for ASVs must be within 30 minutes of the “notification of potential rupture.” f) 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 below:58 57 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 5-miles in length that is connected between the isolation valves for a special permit segment must have a RCV or ASV within 5-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 8-inch diameter. 58 The pipeline valve section location to be closed and isolated (if there should be a rupture) must be confirmed by FGT 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-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 29 of 52 <<>> i) “Notification of Potential Rupture” means any of the following events that involve an unintentional or uncontrolled release of a large volume of gas from a transmission pipeline: (1) A release of gas observed by or reported to FGT (e.g., by its controller(s) in a control room, field operations personnel, nearby pipeline or utility personnel, the public, local responders, or public authorities) that may be representative of an unintentional or uncontrolled release event meeting paragraphs (2) or (3) of this definition; (2) FGT observes an unanticipated or unplanned pressure loss outside of the pipeline’s normal operating pressures, as defined in FGT’s written procedures. If FGT establishes an unanticipated or unplanned pressure loss threshold that is greater than a 10% pressure loss, occurring within a time interval of 15 minutes or less, FGT must document in its written procedures the need for a greater pressure-change threshold due to pipeline flow dynamics (including the pipeline operating pressure, gas flow rate or volume), that are caused by fluctuations in gas demand, gas receipts, or gas deliveries; or (3) FGT observes an unexplained flow rate change, pressure change, equipment function, or other pipeline instrumentation indication that may be representative of an event meeting paragraph (2) of this definition. Note: Notification of potential rupture occurs when an event, as defined in this section/paragraphs (2) or (3) above, is first observed by or reported to FGT. ii) FGT must evaluate and identify a rupture,59 as defined above, as being either an actual leak event, rupture event, or non-rupture event in accordance with operating procedures and 49 CFR 192.615. g) Gas Control Center Monitoring: The FGT Gas Control Center must monitor the special permit inspection area 24 hours a day, seven (7) days a week, and must confirm the existence of a leak or rupture as soon as practicable in accordance with FGT pipeline operating procedures. h) Remote Monitoring: FGT must maintain remote monitoring and automatic control equipment, mainline valves, mainline valve operators, and pressure sensors in accordance with 59 For all in-service and pressure test failures, FGT 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. FGT must provide the written results of this root cause analysis to the Director, PHMSA Southwest 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-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 30 of 52 <<>> 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 FGT Gas Control Center during power outages. i) Point-to-Point Verification: FGT must conduct a point-to-point verification between SCADA displays and the mainline valve, sensors, and communications equipment in accordance with 49 CFR 192.631(c) and (e). j) Valve Maintenance: FGT must maintain all valves used to isolate a leak or rupture in accordance with this special permit and 49 CFR 192.745. k) Inoperable Valves: FGT 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 (6) 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 (6) months; and iii) If valve repair or replacement cannot be met due to circumstances beyond FGT’s control, FGT must notify, in writing, the Director, PHMSA Southwest Region, of the reasons the schedule cannot be met and obtain a letter of “no objection” from PHMSA prior to implementing the schedule change. l) Emergency Communications: i) FGT must establish and maintain adequate means of communication with the appropriate public safety access point (9-1-1 emergency call center) or emergency management coordinating agency and must notify them, as well other emergency responders, if there is a leak or rupture, as required in 49 CFR 192.615; ii) FGT must immediately and directly notify the appropriate public safety access point (9-1-1 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;60 and iii) In accordance with these special permit conditions and as required in 49 CFR 192.615 and 192.631, FGT must establish actions required to be taken by a pipeline controller or the 60 FGT 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-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 31 of 52 <<>> appropriate emergency response coordinator when an emergency occurs in the special permit inspection area. 13) Condition 13 - Special Permit Specific Conditions FGT must comply with the following requirements: a) Line-of-Sight Markers: FGT must install and maintain line-of-sight markings 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 (6) months of the grant of this special permit and replaced as necessary by FGT within 30 days after identification of line-of-sight marker removal. b) Depth of Cover Survey: i) FGT must complete, within six (6) months of the grant of this special permit, a depth of cover survey for each special permit segment. ii) FGT must implement additional safety measures for any pipe in a special permit segment that does not meet 49 CFR 192.327(a) for a Class 1 location where there is a reduced depth of cover. 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 FGT 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, FGT must submit these procedures to the Director, PHMSA Southwest Region, for a “no objection” letter prior to usage. The Director, PHMSA Southwest Region, must respond to FGT’s submittal letter within 90 days. The Director, PHMSA Southwest Region, may provide a decision, request for additional information, or notify FGT of PHMSA’s need for additional time to provide a decision. c) Data Integration: FGT must develop and maintain data integration61 in accordance with 49 CFR 192.917, of all special permit condition findings and remediation in a special permit segment and special permit inspection area. Data integration must be completed at least once each calendar year, with intervals not to exceed 15 months. 61 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. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 32 of 52 <<>> i) Data integration must include the following information: (1) Pipe diameter, wall thickness, grade, and seam type; (2) pipe coating; (3) MAOP; (4) class location, including boundaries on aerial photography; (5) HCAs, including boundaries on aerial photography; (6) hydrostatic test pressure, including any known test failures; (7) casings; (8) any in-service ruptures or leaks; (9) ILI survey results, including HR-MFL, HR-geometry/caliper, or deformation tools; (10) the most recent CIS results; (11) depth-of-cover surveys; (12) rectifier readings for the past five (5) years; (13) CP test point survey readings for the past five (5) years; (14) AC/DC interference surveys; (15) pipe coating surveys; (16) pipe coating and anomaly evaluations from pipe excavations; (17) SCC excavations and findings; and (18) pipe exposures from encroachments.62 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, FGT must complete and submit data integration documentation and drawings, with four (4) years of prior data, beginning with the 2nd annual report of this modified special permit. iii) FGT must maintain data integration as a composite of all applicable data elements in a comparable data viewer. d) Pipe Properties Testing: If the pipe does not meet Condition 16(b), FGT must test the pipe in a special permit segment as follows: 63 i) Develop and implement procedures for conducting non-destructive or destructive tests, examinations, and assessments for any special permit segment, without TVC64, 65 pipe material properties records, in accordance with this condition and either 49 CFR 192.607 62 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. 63 If PHMSA determines that the material records supplied by FGT do not meet the requirements of TVC, the completion of Condition 13(d) will be required for each special permit segment. 64 TVC procedures and records must follow the following: 1) “Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements and Other Related Amendments”; 84 FR 52218 to 52219; October 1, 2019; and 2) PHMSA Advisory Bulletin: Pipeline Safety: Verification of Records; 77 FR 26822; May 7, 2012; https://www.gpo.gov/fdsys/pkg/FR-2012-05-07/pdf/2012-10866.pdf. 65 Material records must cover the entire length of the special permit segment, regardless of when the pipeline, single or multiple pipe joints, or other pipeline components were installed. Affidavits for a material record are not acceptable TVC material records. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 33 of 52 <<>> or 192.105 for determining MAOP. Non-destructive or destructive tests, examinations, and assessments must be completed within 18 months of the grant of this special permit. ii) FGT must test pipe in each special permit segment without TVC material properties and of different vintages as defined in Condition 13(d)(iv). Material tests must be conducted at two (2) excavation sites per mile with excavations spaced between 1,320 to 3,960 feet in each mile segment. If the special permit segment is less than ½ mile, only one (1) excavation site is required. iii) FGT must perform a minimum of two (2) destructive or NDT methods at an excavation site. FGT must conduct NDT assessments using test procedures, calibration pipe of similar confirmed properties for equipment testing, and ball indention methodology, or an equivalent method.66 If NDT of pipe material properties show that the pipe wall thickness is not within API 5L specification tolerances, and the pipe grade is under the strength requirements of API 5L by 1,000 pounds per square inch (psi) or more, then FGT will confirm the yield strength of that individual pipe using destructive test methods or remove the special permit segment pipe. If ILI tools are used to verify the pipeline materials, FGT must submit an assessment procedure to the Director, PHMSA Southwest Region, for a “no objection” letter prior to its usage.67 The Director, PHMSA Southwest Region, must respond to FGT’s submittal letter within 90 days. The Director, PHMSA Southwest Region, may provide a decision, request for additional information, or notify FGT of PHMSA’s need for additional time to provide a decision. iv) FGT must assess pipe in a special permit segment with missing mill test reports (MTRs) or missing mill inspection reports (i.e., Moody Engineering Reports) for each unique combination of the following attributes: wall thicknesses (within 10 percent of the smallest wall thickness in the population), grade, manufacturing process, pipe manufacturing dates (within a 2-year interval), and construction dates (within a 2-year interval). 66 FGT must submit the non-destructive assessment method and procedures to the Director, PHMSA Southwest Region, and the Director, PHMSA Engineering and Research Division. The Director, PHMSA Southwest Region, must respond to FGT’s submittal letter within 90 days. The Director, PHMSA Southwest Region, may provide a decision, request for additional information, or notify FGT of PHMSA’s need for additional time to provide a decision. 67 FGT must send a copy of the assessment procedure to the Director, PHMSA Engineering and Research Division. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 34 of 52 <<>> v) FGT cannot use the material properties determined from either destructive or NDT required by this condition to raise the original grade or specification of the pipeline material. FGT must use the applicable standard referenced in 49 CFR 192.7. vi) For a future special permit segment with missing mill inspection reports for mechanical and chemical properties, FGT must use the above methodology, or FGT may elect to remove pipe joints for destructive testing.68 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 192.61169 in a special permit segment, FGT 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). FGT must submit the written flow reversal procedure to the Director, PHMSA Southwest Region, and submit a copy of the plan to the Federal Docket for this special permit at www.regulations.gov. 70 FGT must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to implementing the pipeline system flow reversal through a special permit segment. f) Environmental Assessments and Permits: FGT 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, FGT must obtain and adhere to all applicable Federal, state, and local environmental permit requirements when conducting the special permit conditions activity. g) Gas Quality: FGT 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 68 FGT must prepare a procedure in accordance with Condition 13(d) – Pipe Properties Testing, for material documentation and submit to the Director, PHMSA Southwest Region, and receive a “no objection” letter prior to usage of the procedure. The Director, PHMSA Southwest Region, must respond to FGT’s submittal letter within 90 days. The Director, PHMSA Southwest Region, may provide a decision, request for additional information, or notify FGT of PHMSA’s need for additional time to provide a decision. A copy of the procedure must be sent to the Director, PHMSA Engineering and Research Division. 69 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 3 location change. 70 FGT must send a copy of the flow reversal procedure to the Director, PHMSA Engineering and Research Division. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 35 of 52 <<>> hydrocarbons, no water vapor content that exceeds acceptable limits for gas distribution customer delivery, hydrogen sulfide (H2S) not to exceed one (1) grain per 100 cubic feet, or carbon dioxide (CO2) not to exceed three (3) percent by volume. h) Annual Class Location Study: FGT 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 FGT to provide a notice for a “no objection” response from PHMSA, other notice, annual report, or documentation to the Director, PHMSA Southwest Region, FGT 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. FGT must develop procedures on how to evaluate and remediate soil stresses and strains on the pipeline including IMU intervals. FGT must submit soil stress and strain evaluation and remediation procedures to the Director, PHMSA Southwest Region, within three (3) months of identification and must receive a “no objection” letter prior to implementation. k) Gas Leakage Surveys and Remediation: i) FGT 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 each special permit inspection area at least twice each calendar year, not to exceed 7½ months. FGT 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. FGT 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: PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 36 of 52 <<>> (1) A Grade 1 leak requires immediate and/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% lower explosive limit (LEL), or greater, in a confined space; (f) Any reading of 80% 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: (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% 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% 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% 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% LEL and 80% LEL in a confined space; (f) Any reading on a pipeline operating at 30% SMYS or greater, in a Class 3 or 4 location, which does not qualify as a Grade 1 leak; (g) Any reading of 80% LEL, or greater, in gas associated substructures; or PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 37 of 52 <<>> (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% 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% 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, FGT must conduct an O&M procedure assessment of the pilot, springs, pressure gauges, and other pressure limiting equipment to ensure 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. FGT cannot extend or change any remediation timing or continuous monitoring requirements in this paragraph without a "no objection" letter received by FGT from the Director, PHMSA Southwest Region. iv) FGT may request an extension of the remediation time interval requirements by sending a request to the Director, PHMSA Southwest Region, but must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to extending the leak remediation timing or continuous monitoring requirements in Condition 13(k). 71 l) Right-of-Way Patrols: In addition to the requirements of 49 CFR 192.705, FGT 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 71 Any FGT 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. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 38 of 52 <<>> 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 FGT’s control, FGT must notify the Director, PHMSA Southwest Region, in writing of the reasons the schedule cannot be met and obtain a letter of “no objection” within three (3) business days of the exceedance. m) Minimization of Gas Released to the Environment: i) FGT must reduce the release of gas to the environment when replacing any pipe between the mainline isolating valves for a special permit segment. FGT must use one (1) or more of following methods that will reduce the environmental effects of methane (gas) being released. FGT must calculate the volume of natural gas that will be released by each method or combination of methods and select an option(s) that minimizes the release of gas to the environment and is consistent with pipeline safety. 72 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 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) FGT 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. FGT must also document and justify, 72 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-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 39 of 52 <<>> 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) FGT 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(i) - Annual Report. 14) Condition 14 - Field Activity Notices to PHMSA FGT must give a minimum 14-day notice to the Director, PHMSA Southwest 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 FGT should notify the Director, PHMSA Southwest Region, no later than two (2) business days after the immediate condition is discovered. The Director, PHMSA Southwest Region, may elect not to require a notification for some activities. 15) Condition 15 - Annual Report Annually73 after the grant of this special permit, FGT must report the following to the Director, PHMSA Southwest Region, with copies to the Director, PHMSA Engineering and Research Division:74 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. FGT 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% 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 integrity75 during the previous year in the special permit inspection area, including their 73 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. 74 FGT must post the annual report to the special permit docket [DOCKET_NUMBER] at www.regulations.gov. 75 FGT 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% of SMYS (0.5% strain) on girth welds. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 40 of 52 <<>> survey station, predicted failure pressure, anomaly depth and length, class location, and whether these threats are in an HCA. c) In the 1st, 2nd, and 3rd annual reports FGT must report each special permit segment that does not have the following complaint TVC records: i) A pressure test that meets Condition 1(b). FGT must report the planned or actual completion dates for the special permit segment pressure test including test pressure. ii) Material pipe properties tests that meet Condition 13(d) – Pipe Properties Testing. FGT must report the planned or actual completion dates for the special permit segment material pipe property tests. d) 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. FGT 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 leak as described in Condition 13(k) - Gas Leakage Surveys and Remediation. e) Any ongoing DP initiatives affecting a special permit inspection area and a discussion of the success of the initiatives, including findings and remediation actions. f) FGT must submit annual data integration information, as required in Condition 13(c) - Data Integration, beginning with the 2nd annual report, which must include an annual overview of any new threats. If requested by PHMSA, FGT must submit a full information package of the requested pipeline attribute and integrity items outlined in the condition. g) If FGT uses ASVs for Condition 12 – Mainline Valve, FGT must report the set pressure and how it was determined for each year to meet “as soon as practicable but 30 minutes or less.” h) Any emergency events that cause closure of mainline valves, including the location (County, State and MP) of valves and closure times. i) FGT 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. j) FGT 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. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 41 of 52 <<>> k) Any mergers, acquisitions, transfer of assets, or other events affecting the regulatory responsibility of the company operating the pipeline. l) A senior executive officer, vice president, or higher executive of FGT must review for correctness, date, and sign the annual report prior to posting it to the Federal Docket (PHMSA- 2023-0020) at www.regulations.gov and submitting a copy to the Director, PHMSA Southwest Region, and the Director, PHMSA Engineering and Research Division. m) FGT must schedule a review meeting regarding Condition 15 - Annual Report with the Director, PHMSA Southwest Region, prior to or within one (1) month of the filing of each year.76 During the annual review meeting, FGT must review the status of implementing the special permit conditions with the Director, PHMSA Southwest Region. 16) Condition 16 – Documentation FGT must maintain the following records for a special permit segment as follows: a) FGT 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. Any pipe in a special permit segment that does not have TVC mill test reports or does not meet Condition 13(d) – Pipe Properties Testing and 49 CFR 192.607 cannot be authorized per this special permit. 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 FGT implementing the following conditions: a) Within six (6) months after the Class 1 to Class 3 location change, FGT must provide notice to the Director, PHMSA Southwest Region, and Director, PHMSA Engineering and Research Division, of the request for a special permit segment extension. 76 The Director, PHMSA Southwest Region, has the authority to waive this meeting. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 42 of 52 <<>> 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% wall loss, schedule of inspections, and of any anticipated remedial actions. ii) FGT 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. FGT 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 FGT 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) FGT must remediate all anomalies in accordance with Condition 8 – Anomaly Evaluation and Remediation; ii) FGT must have hydrostatically tested77 a special permit segment and extension in accordance with Condition 1 – Maximum Allowable Operating Pressure, as applicable; and iii) FGT must complete all required special permit conditions, except Condition 17(b) above, for each special permit segment extension within two (2) years of the Class 1 to Class 3 location change, unless specified otherwise. c) FGT must apply all the special permit conditions and limitations included herein to all future special permit segment extensions. 18) Condition 18 – Certification FGT must meet the following conditions for certification: a) A senior executive officer, vice president, or higher executive of FGT must certify in writing the following: 77 For all in-service and pressure test failures, FGT 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. FGT must provide the written results of this root cause analysis to the Director, PHMSA Southwest 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-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 43 of 52 <<>> i) Each special permit inspection area and special permit segment meet the conditions described in this special permit; ii) FGT 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; iii) FGT has prepared an uprating plan in accordance with Condition 1(c), if applicable; and iv) FGT has implemented all conditions as required by this special permit. b) FGT 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 Southwest Region; the Director, PHMSA Engineering and Research Division; and the Federal Register Docket (PHMSA-2023-0020) at www.regulations.gov within one (1) 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: 1) PHMSA has the sole authority to make all determinations on whether FGT 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 FGT 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 FGT sells, merges, transfers, or otherwise disposes of all or part of the assets known as a special permit segment or special permit inspection area, FGT must provide PHMSA with written notice of the change within 30 days of the consummation date. In the event of such PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 44 of 52 <<>> transfer, PHMSA reserves the right to revoke, suspend, or modify the special permit if the transfer constitutes a material change in conditions or circumstances underlying the permit. 6) PHMSA grants this special permit limited to a term of no more than 5-10 years78 from the date of issuance. If FGT elects to seek renewal of this special permit, FGT must submit its renewal request at least 180 days prior to expiration of the 5-10-year period to the PHMSA Associate Administrator for Pipeline Safety with copies to the Director, PHMSA Southwest 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 FGT 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, DC on Month Day, 2023. DRAFT Alan K. Mayberry, Associate Administrator for Pipeline Safety 78 To be determined by PHMSA. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 45 of 52 <<>> Attachment A - Dent Anomalies – Engineering Critical Assessment To evaluate dents and other mechanical damage anomalies that conform to the conditions described in Table 3 – Dent Criteria below, FGT must perform an engineering critical assessment (ECA) as follows: 1) Identify and assess all threats for the pipe segment such as ground movement, other external loading, cracking and corrosion that may be impacting the dent and mechanical damage. 2) Review all available high-resolution magnetic flux leakage (HR-MFL), high-resolution deformation, inertial mapping tool, and crack detection ILI data for damage in the dent area and any associated weld region. 3) If multiple ILI runs over time are available, the dent profile between the most recent and previous inline inspections should be compared to identify changes or significant changes in dent depth and shape and its possible impact to the integrity of the pipeline. 4) Perform pipeline curvature-based strain analysis using recent HR-Deformation inspection data. 5) Identify and quantify all significant loads acting on the dent. 6) FGT must use finite element analysis to quantify the dent strain, and then estimate the damage using either Strain Limit Damage (SLD) or Ductile Failure Damage Indicator (DFDI) at the dent. Finite element analysis modeling of the dent must include all associated anomalies, defects, and welds. Other methodologies and approaches that are supported by peer reviewed publications will also be considered as part of the ECA but will require a “no objection” letter from the Director, PHMSA Southwest Region. 7) The analyses performed must account for material property uncertainties and model inaccuracies and ILI tool sizing tolerances. 8) Using operational pressure data, appropriate fatigue models, and assuming the appropriate safety factor, FGT must estimate the fatigue life of the dent in accordance with API 1156 (1997 Edition), API RP 1183 (1st Edition, 2020, or IBR Edition) or other published literature that is technically appropriate for dent assessment. Multiple dent or other fatigue models must be evaluated as part of the ECA. 9) If the dent is suspected to have cracks, then a crack growth rate assessment is required (or the dent needs to be remediated) to ensure adequate life for the dent with crack(s) and the crack(s) in the dent must be evaluated and remediated in accordance with the criteria in Condition 8 – Anomaly Evaluation and Remediation. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 46 of 52 <<>> 10) If FGT uses other technologies or techniques to comply with failure pressure determinations, FGT must submit advance notification to Director, PHMSA Southwest Region, and must receive a “no objection” letter from the Director, PHMSA Southwest Region, prior to usage. 11) The ECA process must be repeated following each assessment to ensure conformance to the original ECA conclusions. 12) To use ECA for dents with a depth greater than 6% up to 10% of the outside diameter (OD) requires a “no objection” letter from the Director, PHMSA Southwest Region. 13) FGT must remediate dents and mechanical damage that do not pass the criteria defined in Table 3 – Dent Criteria, or FGT must conduct an acceptable ECA as described in this Attachment A, Items 1 through 12. 14) FGT must submit the dent ECA procedure to the Director, PHMSA Southwest Region, for a “no objection” letter prior to conducting the anomaly evaluation.79 The Director, PHMSA Southwest Region, must respond to FGT’s submittal letter within 90 days. The Director, PHMSA Southwest Region, may provide a decision, request for additional information, or notify FGT of PHMSA’s need for additional time to provide a decision. 79 A copy of the dent ECA procedure must be sent to the Director, PHMSA Engineering and Research Division. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 47 of 52 <<>> Table 3 – Dent Criteria Dent type Critical Dents that Require Action ECA an Option Plain Dent Dent of depth > 6% Outside Diameter (OD) or dent strain level exceeding: i. Dent with strain > 6% limit (ASME B31.8, 2018 Edition) or ii. Strain Limit Damage (SLD) or Ductile Failure Damage Indicator (DFDI) > 0.6 (per API RP 1183, IBR Edition or 1st Edition, 2020, if not IBR) YES Dent Associated with Corrosion** i. Dent depth of > 6% OD with corrosion of any depth or ii. Dent of depth ≤ 6% OD with corrosion depth that is more than 15% 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 or Spiral Seam Weld) Dent of any depth affecting pipe with: Low Frequency Electric Resistance Welded (LF-ERW), Electric Flash Welded (EFW), Lap Welded, or Longitudinal Joint Factor < 1.0 YES* Dent of depth > 2% OD affecting other types of weld seams, see above, or girth welds with strain level exceeding 4% (ASME B31.8, 2018 Edition) YES Skewed and/or Multiple Dent Peaks Any complex dent geometry identified by FGT or ILI vendor such as skewed dent, two or multi-peak deformations YES * Lack of ductility must be integrated into the ECA. ** Corrosion failure pressure with safety factor must meet the MAOP requirements in Condition 8 - Anomaly Evaluation and Remediation. Note: FGT may use 49 CFR Part 192 compliant dent remediation procedures for the evaluation and remediation of a dent ≤ 6% OD, with a corrosion depth < 15% of the pipe wall, and corrosion failure pressure with safety factor that meets the MAOP requirements in Condition 8 - Anomaly Evaluation and Remediation. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 48 of 52 <<>> Attachment B-1 – 26-inch Mainline Loop C/S 18-19 Special Permit Segment and Inspection Area Route Maps PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 49 of 52 <<>> Attachment B-2 – 30-inch MLV 18-1 to C/S 19 Special Permit Segments and Inspection Area Route Maps PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 50 of 52 <<>> Table 4 – Valves and Lateral Locations with Isolations Methods For ASVs – Complete this Section Special Valve / Nominal Valve Permit Segment Mile Post / Stationing ASV Low Rate of Type Lateral Name Diameter Automation Rate of Pressure Low Pressure Pressure (if Applicable) (inches) Methodology80 Nos. Set-point (psig) Drop Set-point (psig/minute) Change Timing (minutes) Timing (minutes) 691.7 Upstream Isolation Valve 32-0A 26 RCV N/A N/A N/A N/A 693.3 Lateral 18-1A2 6 Check Valve N/A N/A N/A N/A 189579 693.4 Lateral 18-1A1 12 ASV or RCV N/A N/A N/A N/A 705.9 Downstream Isolation Valve 18-2A 26 RCV N/A N/A N/A N/A 690.3 Upstream Isolation Valve 18-10B 30 ASV N/A -20 1 N/A 694.7 Lateral/Crossover 18-12C 4 Closed N/A N/A N/A N/A 202967 697.4 Crossover 18-100BU 12 Closed N/A N/A N/A N/A 697.4 Downstream Isolation Valve 18-100B 30 RCV N/A N/A N/A N/A 697.4 Upstream Isolation Valve 18-100B 30 RCV N/A N/A N/A N/A 187434 697.4 Crossover 18-100BD 12 Closed N/A N/A N/A N/A 701.8 Downstream Isolation Valve 18-2B 30 RCV N/A N/A N/A N/A 701.8 Upstream Isolation valve 18-2B 30 RCV N/A N/A N/A N/A 202974, 187440 710.3 Lateral 18-22C 12 ASV or RCV N/A N/A N/A N/A 719.2 Downstream Isolation Valve 18-3B 30 RCV N/A N/A N/A N/A 80 Any isolation valve that is not an RCV, ASV, or check must be blinded or closed. Isolation valve(s) shown as CLOSED (Normally Closed), when opened, must be manned by FGT personnel. Condition 12 - Mainline Valve – Monitoring and Remote Control for Ruptures is applicable to all blowdown/ mainline valve bypass valves, crossover valves, valve spacing, and lateral tie-ins. PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 51 of 52 <<>> Table 4 – Valves and Lateral Locations with Isolations Methods For ASVs – Complete this Section Special Valve / Nominal Valve Permit Segment Mile Post / Stationing ASV Low Rate of Type Lateral Name Diameter Automation Rate of Pressure Low Pressure Pressure (if Applicable) (inches) Methodology80 Nos. Set-point (psig) Drop Set-point (psig/minute) Change Timing (minutes) Timing (minutes) Software Package – Greg Engineering Winflow and Wintran Pipeline Simulation Florida Gas utilizes a copyrighted program (Gregg Engineering) and has prepared the pressure graphs included in the Special Permit Conditions. This computer program simulates the operation of the FGT system. It models a pipe segment by the simultaneous solution of the mass, momentum, and energy balance equations. FGT uses the Colebrook-White and API 520 equations. FGT believes the Colebrook-White equation fairly typifies the steady state and transient conditions regularly experienced on the FGT pipeline system. As part of developing the Special Permit Conditions, FGT believes the API 520 equation is sufficient to estimate the rupture pattern and thereby accurately computes the reaction times simulated for these pipeline ruptures on the FGT pipeline system. Final Page of the Special Permit with Conditions PHMSA-2023-0020 – Florida Gas Transmission Company, LLC Draft Special Permit – Class 1 to Class 3 Location – Florida Page 52 of 52 ## Provenance - Official: Yes - Source: - Source ID: `phmsa-special-permits` - SHA-256: `efaa41959f73052974e33bb69df80ef956d35d4dae6e7a2a0c0dad824056cafb` - Retrieved: 2026-08-20T01:06:17.853Z - Exported: 2026-08-24T06:42:14.702Z - Document slug: `phmsa-special-permit-phmsa-2023-0020` ### Source metadata ```json { "materialSubtype": "pipeline_special_permit", "operator": "Florida Gas Transmission", "system": "Gas Transmission", "issuedOn": "2023-08-22", "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-2023-0020", "docketDocumentCount": 12, "decisionDocumentCount": 3, "decisions": [ { "id": "PHMSA-2023-0020-0010-0900006485f4bf56", "regulationsGovDocumentId": "PHMSA-2023-0020-0010", "title": "2020-0001 - FGT - Class 1 to 3 SP - FL - Segment Extension and 5 new Segments - SPAF - 08-22-2023", "postedDate": "2023-09-07", "documentUrl": "https://www.regulations.gov/document/PHMSA-2023-0020-0010", "pdfUrl": "https://downloads.regulations.gov/PHMSA-2023-0020-0010/attachment_1.pdf", "pdfArtifactPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2023-0020/phmsa-2023-0020-0010.pdf", "pdfArtifactSha256": "094affbb4fd6f819a7150be3d58a3da58227718e0bd9d2038e293160ff0fed98", "extractedTextPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2023-0020/phmsa-2023-0020-0010.txt", "extractedTextSha256": "f1959d8d72b0de16fe0985174f51618a0fb04bf44ffc5c5ca7cdcfc05e86c073", "pageCount": 16, "extractionVersion": 2 }, { "id": "PHMSA-2023-0020-0012-0900006485f4bf5a", "regulationsGovDocumentId": "PHMSA-2023-0020-0012", "title": "2020-0001 - FGT - Class 1 to 3 SP - Segment Ext and 5 new Segments - LOD - 08-22-2023", "postedDate": "2023-09-07", "documentUrl": "https://www.regulations.gov/document/PHMSA-2023-0020-0012", "pdfUrl": "https://downloads.regulations.gov/PHMSA-2023-0020-0012/attachment_1.pdf", "pdfArtifactPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2023-0020/phmsa-2023-0020-0012.pdf", "pdfArtifactSha256": "26c793c3cc1e72912270741dbbc002032faadd95fbf0e17d0010fbf5a0f05f90", "extractedTextPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2023-0020/phmsa-2023-0020-0012.txt", "extractedTextSha256": "5f61b60b8eb0ddbd1bc97a6d27a4a2cdea02c9695da387df950b07cee5b63cc4", "pageCount": 2, "extractionVersion": 2 }, { "id": "PHMSA-2023-0020-0005-090000648594b3b6", "regulationsGovDocumentId": "PHMSA-2023-0020-0005", "title": "Florida Gas Transmission - Class 1 to 3 SP - Special Permit Conditions - 04-06-2023", "postedDate": "2023-04-17", "documentUrl": "https://www.regulations.gov/document/PHMSA-2023-0020-0005", "pdfUrl": "https://downloads.regulations.gov/PHMSA-2023-0020-0005/attachment_1.pdf", "pdfArtifactPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2023-0020/phmsa-2023-0020-0005.pdf", "pdfArtifactSha256": "35fd0078555e9aac7b91e1680aa45d700f064d148e1139df43d194e68cfcd7a3", "extractedTextPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2023-0020/phmsa-2023-0020-0005.txt", "extractedTextSha256": "25727c9489048a29ab405850f090c90d61c6c874079b18cd20ba9e644e5e70da", "pageCount": 52, "extractionVersion": 2 } ], "citedSections": [ "192.611", "192.619", "192.517", "192.903", "191.5", "191.23", "192.12", "192.167", "192.225", "192.402", "192.452", "192.463", "192.465", "192.467", "192.469", "192.471", "192.479", "192.481", "192.605", "192.615", "192.616", "192.709", "192.739", "192.745", "192.805", "192.905", "192.907", "192.917", "192.919", "192.927", "192.933", "192.935", "192.937", "190.341", "192.5", "192.624", "192.603", "192.150", "192.493", "192.111", "192.921", "192.506", "192.939", "192.7", "192.710", "192.614", "192.712", "192.113", "192.620", "192.631", "192.327", "192.607", "192.105", "192.61169", "192.609", "192.705" ], "caveat": "The issued-permit index establishes issuance, not current validity or applicability to facilities beyond those covered by the permit. 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