# Alaska Gas Development Corporation – AGDC — Pipeline Special Permit **Citation:** PHMSA-2017-0045 **Type / status:** permit / current **Agency:** Pipeline and Hazardous Materials Safety Administration **Effective:** 2019-09-09 **Published:** 2019-09-09 PHMSA-2017-0045, issued 2019-09-09 for Alaska Gas Development Corporation – AGDC's gas transmission system. ## Document text PHMSA pipeline special permit PHMSA-2017-0045. Operator: Alaska Gas Development Corporation – AGDC. System: Gas Transmission. Issue date: 2019-09-09. <<>> C U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration Mr. Frank T. Richards, P.E. Senior Vice President, Program Management Alaska Gasline Development Corporation 3201 C Street, Suite 200 Anchorage, Alaska 99503 SEP 9 2Q19 1200 New Jersey Avenue, SE Washington, D.C. 20590 Docket No. PHMSA-2017-0045 Dear Mr. Richards: On April 14, 2017, Alaska Gasline Development Corporation (AGDC) requested the Pipeline and Hazardous Materials Safety Administration (PHMSA) to issue a special permit to waive compliance from 49 Code of Federal Regulations (CFR) 192.197(a)(4) for the Alaska LNG Pipeline. The Alaska LNG Pipeline is an 807-mile 42-inch diameter natural gas transmission pipeline that AGDC has proposed to build extending from the AGDC's proposed Gas Treatment Plant (GTP) on the North Slope of Alaska to the Liquefaction Facility on the shore of the Cook Inlet near Nikiski, Alaska, including an offshore pipeline section crossing the Cook Inlet. PHMSA is granting this special permit (enclosed) for the 42-inch diameter Alaska LNG Pipeline. This special permit provides relief from the Federal Pipeline Safety Regulations for the AGDC special permit segments and requires ADGC to comply with certain conditions and limitations designed to maintain pipeline safety. AGDC is authorized to design, construct, and operate the Alaska LNG pipeline with mainline block valve spacing of up to 50 miles in the very sparsely populated region north of Fairbanks borough in Alaska, and up to 30 miles spacing south of Fairbanks in Class 1 locations. Section 192.179(a)(4) requires a maximum Class 1 location valve spacing of 20-miles. PHMSA grants this special permit based on the findings set forth in the "Special Permit Analysis and Findings" and the "Final Environmental Assessment and Finding ofNo Significant Impact" documents, which can be read in their entirety in Docket No. PHMSA- 20 17-0045 in the Federal Docket Management System (FDMS) located at www.regulations.gov. <<>> My staff would be pleased to discuss this matter or any other regulatory matter with you. John Gale, Director of Standards and Rulemaking Division may be contacted at 202-366-0434, on regulatory matters, and Sentho White, Director of Engineering and Research Division, may be contacted at 202-493-2415, on technical matters specific to this special permit grant. Sincerely, A.bL' Associate Administrator for Pipeline Safety Enclosure: Special Permit- PHMSA-2017-0045 SEP- 9 201t9 PHMSA-2017-0045-Alaska LNG Pipeline- MLBV Spacing- LOD Page 2 of 2 <<>> U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION SPECIAL PERMIT- Mainline Valve Spacing Special Permit Information: Docket Number: Requested By: Operator ID#: Original Date Requested: Original Issuance Date: Effective Date: Code Sections: PHMSA-2017-0045 Alaska Gasline Development Corporation 40015 April 14, 2017 September 9, 2019 September 9, 2019 49 CFR 192.179(a)(4) Grant of Special Permit: By this order, subject to the terms and conditions set forth below, the United States Department of Transportation, Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS),1 grants this special permit to Alaska Gasline Development Corporation (AGDC), owner and operator of the Alaska LNG Pipeline.2 This special permit waives compliance from 49 Code of Federal Regulations (CFR) 192.179(a)(4) for sectionalizing mainline valve spacing in Class 1 locations. This special permit requires the use of remote controlled valves (RCV) or automatic shut-off valves (ASV) for the Alaska LNG Pipeline and mandates specific design, construction, operations, and maintenance procedures in accordance with the special permit conditions. 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 As used in these draft conditions, the term Alaska LNG Pipeline refers to the approximately 807 miles of 42-inch natural gas transmission pipeline and not to any potential owners, operators or entities associated with the Alaska LNG Pipeline. The special permit owner, operator, and applicant/permittee names is Alaska Gasline Development Corporation. Please note that this pipeline does not transport liquefied natural gas (LNG). It will supply natural gas to a liquified natural gas (LNG) facility for further transportation as LNG PHMSA-2017-0045: Alaska Gasline Development Corporation Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing Page 1 of 16 <<>> I. Purpose and Need: The Alaska LNG Pipeline will be approximately 807 miles of 42-inch-diameter steel pipe for transporting natural gas from AGDC's gas treatment plant (GTP) on Alaska's North Slope to the liquefaction facility on the eastern shore ofthe Cook Inlet near Nikiski, Alaska. The pipeline will be mostly onshore, with a segment of offshore pipeline crossing the Cook Irdet. The onshore portion of the pipeline will be a buried pipeline except for short, above-ground special design segments, such as aerial water crossings and aboveground fault crossings. The Alaska LNG Pipeline's design has a maximum allowable operating pressure (MAOP) of 2,075 pounds per square inch gauge (psig). AGDC is requesting a waiver of compliance with 49 CFR 192.179(a)(4) for remote, sparsely populated segments along the 42-inch pipeline route. AGDC's special permit request is specifically for the Class 1 location segments.3 Federal pipeline safety regulations require natural gas transmission pipeline operators to have sectionalizing block valves within 10 miles of each point on the pipeline (or no more than 20 miles between sectionalizing mainline valves) in a Class 1 location. AGDC' s request allows for a valve spacing greater than 20 miles in Class 1 locations but requires all ofthe mainline valves to be either RCVs or ASVs. II. Special Permit Segment: State of Alaska The Alaska LNG Pipeline specialpermit segment is defined as: approximately 807 miles of 42- inch diameter pipeline originating in the North Slope Borough, traversing the Yukon-Koyukuk Census Area, the Fairbanks North Star Borough, the Denali Borough, the Matanuska-Susitua Borough, and the Kenai Peninsula Borough. The specialpermit segment terminates at the liquefaction facility on the shore of the Cook Inlet near Nikiski, Alaska. The special permit allows alternative mainline valve placement in Class 1 locations on the 42- inch specialpermit segment with the implementation ofthe special permit conditions. 49 CFR 192.5 defines Class location units and class 1, 2, 3, and 4 locations. PHMSA-2017-0045: Alaska Gasline Development Corporation Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing Page 2 of 16 <<>> PHMSA hereby grants this special permit for the specialpermit segment based on the findings set forth in the "Final Environmental Assessment and Findings ofNo Sign ficant Impact" documents, which both can be read in their entirety in Docket No. PHMSA-2017-0045 in the Federal Docket Management System (FDMS) located on the internet at www.regulations.gov. III. Conditions: PHMSA grants this special permit to AGDC for alternative mainline valve spacing subject to AGDC implementing the following conditions on the specialpermit segment as detailed below: 1. Applicable Regulations: The specialpermit segment must be designed, constructed, operated, and maintained in accordance with 49 CFR Part 192, including but not limited to, those requirements that are stated as pertaining to alternative MAOP (49 CFR 192.112, 192.328, and 192.620), but with exception of the mainline valve spacing requirement 49 CFR 192.179(a)(4). In addition to 49 CFR Part 192 conformance, the specialpermit segment must also be designed, constructed, operated and maintained in accordance with the special permit conditions. 2. Maximum Allowable Operating Pressure (MAOP): AGDC must operate the special permit segment at or below a maximum allowable operating pressure (MAOP) of 2,075 pounds per square inch gauge (psig). The specialpermit segment may be designed for operation up to 80% of specified minimum yield strength, allowing for pressure build-up and overpressure protection in accordance with 49 CFR 192.620(e). Mainline Valve Spacin2, Control. Closure, Operations & Maintenance: 3. Transmission Line Valves: Sectionalizing block valves along the specialpermit segment must be spaced as shown in Table i4 and as follows for class location segments:5 a) Class 1 locations north of Fairbanks from Mile Post 0.00 to Mile Post 422 must have a 50-mile maximum sectionalizing block valve spacing between block valves (each point on the pipeline must be within 25 miles of a sectionalizing block valve). "IfAGDC determines that the sectionalizing block valve spacing or operational controls (RCV or ASV), as shown in Table 1 need to be modified, AGDC must submit proposed changes to the conditions and Table ito PHMSA's Western Region Director or PWv1SA Project Designee for review and a "no objection" letter must be received prior to the change by AGDC. Transmission line class locations are defined in 49 CFR 192.5. PHMSA-2017-0045: Alaska Gasline Development Corporation Page 3 of 16 Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing <<>> 4. b) Class 1 locations south of Fairbanks from Mile Post 422 to Mile Post 807 must have a 30-mile maximum sectionalizing block valve spacing between block valves (each point on the pipeline must be within 15 miles of a sectionalizing block valve). c) Class 2, 3, and 4 locations between Mile Post 0.00 to Mile Post 807 must comply with the requirements of 49 CFR 192.179.6 d) High consequence areas (as defined in 49 CFR 192.903 and 192.905) located in Class 1 and 2 locations, must comply with the requirements of 49 CFR 192.179. Valve Monitoring, Control and Closure: All mainline valves7 within the specialpermit segment must be controlled by a supervisory control and data acquisition (SCADA) system and must be equipped for remote monitoring and control, or remote monitoring and automatic control, in accordance 49 CFR 192.620(d)(3)(iii), and the below requirements: a. b. c. d. If any crossover or lateral pipe for gas receipts or deliveries 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 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); All interconnect and/or meter and regulator stations must be monitored and capable of remote operation for isolating from the pipeline such that, when all valves are closed, there is no flow path for gas to flow to the leak or rupture site (except for residual gas already in the shut-off segment); Mainline valves must be continuously monitored for valve status (open, closed, or partial closed/open), upstream pressure, and downstream pressure; Closure of the appropriate valves following a pipeline leak or rupture meeting the criteria of Condition 4 must occur as soon as practicable from the time the 6 Mile Post 0.00 to Mile Post 807 is the starting and ending mile posts ofthe specialpermit segment. Ifthe length ofthe pipeline length should change due to routing or survey changes, these mile posts must be adjusted based upon these changes. Both RCV and ASV are permissible at sectionalizing mainline valves locations. RCV's must be installed at all powered and teleconnnunications-equipped locations, that are: compressor, heater and metering locations. PHMSA-2017-0045: Alaska Gasline Development Corporation Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing Page 4 of 16 <<>> pipeline leak or rupture location is confirmed, not to exceed 30 minutes from such confirmation;8 i. "Rupture" means a significant breach of a pipeline that results in a large- volume, uncontrolled release of gas, over a short period oftime as defined below. For purposes ofthis special permit, AGDC must treat all the following as ruptures: 1. Specialpermit segment pressure drops to 75% of the operating pressure at the sectionalizing mainline valve based upon maximum flow model gradients for the upstream compressor station discharge at MOP (2050 psig). In addition, ASV set-points must not be less than that required to actuate the valve before a downstream RCV actuates;9 2. A release of gas observed or reported to the operator by its field personnel, nearby pipeline or utility personnel, the public, local responders, or public authorities, and that may be representative of an unintentional and uncontrolled release event defined in 3. 4. paragraphs (3) or (4) ofthis definition; An unanticipated or unplanned pressure loss of 10 percent or greater, occurring within a time interval of 15 minutes or less, unless the operator has documented in advance of the pressure loss the need for a higher pressure-change threshold due to pipeline flow dynamics that cause fluctuations in gas demand that are typically higher than a pressure loss of 10 percent in a time interval of 15 minutes or less; or An unexplained flow rate change, pressure change, instrumentation indication, or equipment function that may be representative of an event defined in paragraph (2) of this definition. 8 The pipeline valve section location to be closed and isolated (ifthere should be a leak or rupture) must be confirmed by AGDC through Gas Control or other field operations personnel monitoring ofthe appropriate pipeline pressures, pressure changes, or flow rate changes through a compressor discharge section, meter stations, or by location confirmation from responsible persons. 9AGDC must notify the PHMSA Western Region Director in writing ofthe reasons the pressure drop cannot be met and obtain a letter of"no objection" from PHMSA prior to implementing any pressure drop below 75% of maximum operating pressure based upon pressure loss through flow gradient. PHMSA-2017-0045: Alaska Gasline Development Corporation Page 5 of 16 Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing <<>> e. f. Note: Rupture identification occurs when a rupture, as defined in this section, is observed by or reported to pipeline operating personnel or a controller. ii. Within five (5) minutes ofthe initial notification to AGDC, AGDC must evaluate and identify a rupture, 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. Once a rupture is verified, closure of the appropriate valves must comply with the timing requirements of Condition 4(d). The Alaska LNG PipelineGas Control Center must monitor the pipeline 24 hours a day, 7 days a week, and must confirm the existence of a leak or rupture as soon as practicable in accordance with Condition 4(d); AGDC must maintain remote monitoring and automatic control equipment, mainline valves, mainline valve operators, and pressure sensors in accordance with 49 CFR 192.63 1 and 192.745. All remote monitoring and automatic control equipment including pressure sensors must have backup power to maintain communications and control to the AGDC Gas Control Center during power outages; g. AGDC must conduct a point-to-point verification between SCADA displays and the mainline valve, sensors, and communications equipment in accordance with 49 CFR 192.63 1(c) and (e); h. All valves used to isolate a leak or rupture must be maintained in accordance with this special permit and 49 CFR 192.745; i. AGDC 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 shut-off, 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 seven (7) calendar days of the finding while repairs are being made; and iii. If valve repair or replacement cannot be met due to circumstances beyond AGDC's control, AGDC must notify the PHMSA Western Region Director or Project Designee in writing of the reasons the PHMSA-2017-0045: Alaska Gasline Development Corporation Page 6 of 16 Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing <<>> schedule cannot be met and obtain a letter of "no objection" from PHMSA prior to implementing the schedule change. 5. Mainline Valve Locations: Mainline valves will be sited per Table 1: Table 1: Mainline Valve Locations for Alaska LNG_Pipeline'0 MLBV # MP A MJ Location Description Valve Type Class Location(s) HCA Yes/No 1 0.00 GTP Meter Station RCV 1 No 2 36.74 36.74 Stand-alone MLBV- Potential Station ASV 1 No 3 75.97 39.23 Compressor Station- Sagwon RCV 1 No 4 112.04 36.07 Stand-alone MLBV- Potential Station ASV 1 No 5 148.51 36.47 Compressor Station- Galbriath Lake RCV 1 No 6 194.09 45.58 Stand-alone MLBV- Potential Station ASV 1 No 6 194.09 45.58 Stand-alone MLBV- Potential Station ASV 1 No 7 240.10 46.01 Compressor Station- Coldfoot RCV 1 No 8 286.05 45.95 Stand-alone MLBV- Potential Station ASV 1 No 9 332.64 46.59 Compressor Station- Ray River RCV I No 9A 356.22 23.58 Added for potential "Hotspot Café" HCA ASV I No 10 377.95 21.78 Stand-alone MLBV- Potential Station ASV 1 No 11 421.56 43.61 Compressor Station- Minto RCV 1 No 12 444.90 23.34 Stand-alone MLBV ASV 1 No 13 467.10 22.20 Stand-a1oneMLBV-PotentialStation ASV 1 No 14 492.96 25.86 Stand-alone MLBV ASV 1 No 15 517.62 24.66 CompressorStation -Healy RCV 1 No 16 534.79 17.17 Upstream of Class 3 Location- Nenana Canyon ASV 1 No 17 538.79 4.00 Downstream of Class 3 Location- Nenana Canyon ASV 1 No 18 546.50 7.71 Stand-alone MLBV- Potential Station ASV 1 No 19 572.23 25.73 Stand-alone MLBV ASV 1 No 20 597.35 25.12 Compressor Station- Honolulu Creek RCV I No 21 625.83 28.48 Stand-alone MLBV ASV I No 22 648.16 22.33 Stand-alone MLBV- Potential Station ASV I No 23 675.24 27.08 Compressor Station- Rabideux Creek RCV I No 24 703.67 28.43 Stand-alone MLBV- Potential Station ASV I No 25 725.93 22.26 Stand-alone MLBV- Potential Station ASV I No 26 749.11 23.18 Heater Station- Theodore River RCV 1 No ° Sectionalizing mainline valve siting is based upon the latest route revision C2 and may be subject to change with future route alternatives. The final siting will follow the requirements and limitations ofthe special permit conditions. PHMSA-2017-0045: Alaska Gasline Development Corporation Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing Page 7 of 16 <<>> Table 1: Mainline Valve Locations for Alaska LNG_Pipeline10 MLBV # MP A MP Location Description Valve Type Class Locajons3 HCA Yes/No 27 766.01 16.90 UpstreamofCooklnletcrossing ASV 1 No 28 793.34 27.33 Downstream of Cook Inlet crossing RCV 1 No 29 799.85 6.51 Stand-alone MLBV- Potential Class 2 Location RCV 2 No 30 806.57 6.72 LNG Meter Station RCV 1 No 6. Emergency Operations: a) Alaska LNG Pipeline control center operators must continually monitor position and operational status of all RCVs affected by a leak/rupture event until positive isolation ofthe effected segment is confirmed. b) AGDC must immediately and directly notify the appropriate public safety access point (9-1-1 emergency call center) or other coordinating agency for the communities and jurisdictions in which the pipeline is located when a release is indicated. c) AGDC must establish actions required to be taken by a pipeline controller, or the appropriate emergency response coordinator, during an emergency in accordance with these special permit conditions and as required in 49 CFR 192.615 and 192.631. d) Emergency closure drills simulating shutting down a randomly selected section of transmission line must be performed at least once in a calendar year, but within an interval not to exceed 15 months. AGDC may conduct a table-top emergency closure drill to meet this requirement for no more than two out of each three calendar years. The operator will conduct a site-specific emergency closure drill at a field site at least once every three calendar years. 7. Emergency Training and Planning: AGDC must develop and implement emergency response plans and procedures for the specialpermit segment in accordance with 49 CFR 192.6 15 and the following requirements: a. Identify the appropriate public safety access point (911 emergency call center), fire, police, and other public officials to be notified; AGDC must designate the pipeline controller or the appropriate operator emergency response coordinator in its operating procedures and train the pipeline controller or the appropriate operator emergency response coordinator for coordinating with emergency responders. PHMSA-2017-0045: Alaska Gasline Development Corporation Page 8 of 16 Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing <<>> b. c. Identify responsibility, resources, jurisdictional area, and emergency contact telephone numbers for both local and out-of-area calls of each government organization that may respond to a pipeline emergency; and Inform emergency officials (911 emergency call centers, fire, police, and other public officials) about the operator's ability to respond to the pipeline emergency and means of communication. d. Emergency response plans must be reviewed, updated and communicated, as required in this Condition 7 and 49 CFR 192.615(b) and (c), on a calendar year basis, not to exceed 15 months. Reportin2 and Certification: 8. Annual Reports: Within twelve (12) months following pipeline start-up'2 and annually13 thereafter, AGDC must report the following to the PHMSA Western Region Director or Project Designee, with copies to the Director, PHMSA Engineering and Research Division, and Director, PHMSA Standards and Rulemaking Division:'4' 15 a) The number of new residences, identified sites, or other structures intended for human occupancy and public gathering areas built within a potential impact radius (PIR) of the specialpermit segment, as defined in 49 CFR 192.903; b) Any reportable incidents associated with the specialpermit segment that occurred during the previous year; c) Any emergency events that cause closure of mainline valves as described in Condition 4, including the location (mile post) of valves and closure times; d) Any emergency drills performed in accordance with Condition 6(d). Submit a brief description of the emergency drill and date of the drill; and 12 Pipeline start-up is defined as an interval during which the pipeline system begins operations, and throughput (product flow through the pipeline) is ramped to commercial capacity. 13 Annual reports must be received by PHMSA by the last day ofthe month of pipeline start-up. For example, the annual report for pipeline start-up beginning March 7, 2021, must be received by PHMSA no later than March 3 1S each year beginning in 2022. 14 Upon notice to the AGDC, PHMSA may update reporting contacts for Condition 7. ' AGDC must place a copy of each Alaska LNG Pipeline annual report on the PHMSA docket, PRMSA-20 17- 0045, at www.regulations.gov. PHMSA-2017-0045: Alaska Gasline Development Corporation Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing Page 9 of 16 <<>> e) Any company mergers, acquisitions, transfers of assets, or other events affecting the regulatory responsibility of the company operating the pipeline to which this special permit applies. 9. Notifications: AGDC must notify the PHMSA UPS Western Region Director or Project Designee, at least 14 days prior to conducting field activities associated with the special permit segment to meet Conditions 6(d). 10. Certification: a) A senior executive officer of AGDC, vice president or higher, must certify in writing that: b) c) i. The specialpermit segment meets the conditions described in this special permit (including applicable sections 49 CFR 192.112, 192.328, and 192.620 for alternative MAOP) and other applicable sections of 49 CFR Part 192; and ii. The written manual of O&M procedures required by 49 CFR 192.605 for the Alaska LNG Pipeline includes all additional operating and maintenance requirements of this special permit and 49 CFR Part 192; The certification must be sent to PHMSA within three (3) months ofplacing the Alaska LNG Pipeline into natural gas service. AGDC must send a copy of the certifications required in this condition, with completion dates, 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 Deputy Associate Administrator for Pipeline Safety, PHMSA Field Operations; Deputy Associate Administrator, PHMSA Policy and Programs; PHMSA Western Region Director; Director, PHMSA Standards and Rulemaking Division; Director, PUMSA Engineering and Research Division; and to the Federal Register Docket (PHMSA-2017-0045) at www.regulations.gov. 11. AGDC may propose changes to these special permit conditions by making a request to PHMSA in writing. Any proposed changes to the conditions by AGDC must maintain equivalent levels of safety, as determined by PHMSA. PHMSA will determine whether substantive changes to the conditions require a modification or public notice ofthis special permit. PHMSA will provide AGDC with notice of its decision and an opportunity to PHMSA-2017-0045: Alaska Gasline Development Corporation Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing Page 10 of 16 <<>> respond to any PHMSA-proposed changes to AGDC's request in accordance with 49 CFR 190.341. Any submittal timing, review timing, or completion timing in these conditions can be modified by PHMSA upon request by AGDC and with a "no objection" letter from PHMSA'6 to AGDC. IV. Limitations: This special permit is subject to the limitations set forth in 49 CFR 190.34 1 as well as the following limitations: 1) PHMSA has the sole authority to make all determinations on whether AGDC has complied with the specified conditions of this special permit for the Alaska LNG Pipeline. Failure to comply with any condition ofthis special permit may result in revocation ofthe permit. 2) Any work plans and associated schedules for the Alaska LNG Pipeline supporting this special permit are automatically incorporated into this special permit and are enforceable in the same manner. 3) Failure by AGDC to submit the certifications required by Condition 10 (Certification) within the time frames specified may result in revocation ofthis special permit. 4) As provided in 49 CFR 190.341, PHMSA may issue an enforcement action for failure to comply with this special permit for the Alaska LNG Pipeline. 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 ofthis special permit. 5) If AGDC sells, merges, transfers, or otherwise disposes of all or part of the assets known as the Alaska LNG Pipeline, AGDC must provide PHMSA with written notice of the change within 30 days of the consummation date. In the event of such transfer, PHMSA reserves the right to revoke, suspend, or modify the special permit ifthe transfer constitutes a material change in conditions or circumstances underlying the permit. 16 AGDC must submit any proposed changes to the conditions to PHMSA Western Region Director or PHIMSA project designee for review and a letter of "no objection" prior to usage. PHMSA-2017-0045: Alaska Gasline Development Corporation Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing Page 11 of 16 <<>> AUTHORITY: 49 U.S.C. 60118 and 49 CFR 1.97. SEP 9 2019 Issued in Washington, DC on AIbJJ Associate Administrator for Pipeline Safety Figure 1: Alaska LNG Pipeline Route PHMSA-2017-0045: Alaska Gasline Development Corporation Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing Page 12 of 16 <<>> 0 t L)eaLitofL ea up o SL -4EM / - MP MP200 3 - J '1 /uioo\ /14\ .1 uc /IIW4j7 LAP5OO ,/ 1' / /-_ ( 7 r- ;p kDth _&!_) (I 'z_ / A ( 3¯ftf¯ m. P8OG Gulf of Alaska Wkk PHMSA-2017-0045: Alaska Gasline Development Corporation Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing Page 13 of 16 <<>> Table 2: Mainline Valve Locations for Alaska LNG Pipeline with High Consequence Areas, Bridges, and Railroad Locations MLBV MP. A MP, miles. . . Location Description Valve Class HCA Type Location(s) Yes/No 1 0.00 GTP Meter Station RCV 1 No 2 36.74 36.74 Stand-alone MLBV- Potential Station ASV 1 No 3 75.97 39.23 Compressor Station- Sagwon RV No 4 112.04 36.07 Stand-alone MLBV- Potential Station ASV No 5 148.51 36.47 Compressor Station- Gaibriath Lake RCV 1 No 6 194.09 45.58 Stand-alone MLBV- Potential Station ASV 1 No 6 194.09 45.58 Stand-alone MLBV- Potential Station ASV 1 No 236.08 to 1.25 HCA -Marion Campground- 1.25 miles 1 Yes 7 240.10 46.01 Compressor Station- Coldfoot RCV 1 No 8 286.05 45.95 Stand-alone MLBV- Potential Station ASV No 9 332.64 46.59 Compressor Station- Ray River RCV No 352.21 to 1.14 HCA-Hotspot Café 1 Yes 9a 356.22 23.58 Added for potential "Hotspot Café" HCA ASV 1 No 10 377.95 21.73 Stand-alone MLBV- Potential Station ASV 1 No 11 421.56 43.61 Compressor Station- Minto RCV 1 No 12 444.90 23.34 Stand-alone MLBV ASV 1 No 13 467.10 22.20 Stand-alone MLBV- Potential Station ASV 1 No 14 492.96 25.86 Stand-alone MLBV ASV 1 No 15 517.62 24.66 COmpressorStation -Healy RCV 1 No 529.21 to 1.23 HCA-RV Park and Hotel- 1.23 miles 1 Yes 532.07 Alaska Railroad Crossing No 532.13 Nenana River Bridge Crossing No 16 534.79 17.17 Upstream of Class 3 Location- Nenana Canyon ASV 1 No HCA- Denali Riverside RV Park, McKinley Chalet Resort, Denali Rainbow Village and RV, Denali 535 54 0.45 Princess Wilderness Lodge, Denali Crows Nest 1 Yes 990 Cabins, Grarid Denali Lodge, and Denali Bluffs Hotel -2.20 miles HCA- Denali Riverside RV Park, McKinley Chalet 535 99 Resort, Denali Rainbow Village and RV, Denali 536 49 0.50 Princess Wilderness Lodge, Denali Crows Nest 3 Yes Cabins, Grand Denali Lodge, and Denali Bluffs Hotel -2.20 miles HCA- Denali Riverside RV Park, McKinley Chalet 536 49 Resort, Denali Rainbow Village and RV, Denali 537 1.25 Princess Wilderness Lodge, Denali Crows Nest 1 Yes Cabins, Grand Denali Lodge, and Denali Bluffs Hotel -2.20 miles PHMSA-2017-0045: Alaska Gasline Development Corporation Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing Page 14 of 16 <<>> Table 2: Mainline Valve Locations for Alaska LNG Pipeline with High Consequence Areas, Bridges, and Railroad Locations MLBV Valve Class HCA # MP A MP, miles. . Location Description Type Location(s) Yes/No 537.79 Lynx Creek Bridge Crossing 1 Yes 17 538.79 4.00 Downstream of Class 3 Location- Nenana Canyon ASV 1 No 18 546.50 7.71 Stand-alone MLBV- Potential Station ASV 1 No 551.34 to 0.93 HCA- Denali Perch Resort- 0.93 miles 1 Yes 565.77 to 1.46 HCA- DOT/PF Cantwell Station- 1.46 miles 1 Yes 19 572.23 25.73 Stand-alone MLBV ASV No 572.79 Alaska Railroad Crossing 1 No 588.07 Alaska Railroad Crossing 1 No 20 597.35 25.12 Compressor Station- Honolulu Creek RCV 1 No 609.02 Alaska Railroad Crossing 1 No 21 625.83 28.48 Stand-alone MLBV ASV 1 No 629.75 to 1 60 HCA-Byers Lake Campground (73 units)- 1.60 1 Yes 631.35 miles 633.75 to 0.75 HCA- Trappers Creek Pizza Club -0.75 miles 1 Yes 22 648.16 22.33 Stand-alone MLBV- Potential Station ASV 1 No 23 675.24 27.08 Compressor Station- Rabideux Creek RCV 1 No 24 703.67 28.43 Stand-alone MLBV- Potential Station ASV 1 No 25 725.93 22.26 Stand-alone MLBV- Potential Station ASV 1 No 26 749.11 23.18 Heater Station- Theodore River RCV 1 No 27 766.01 16.90 UpstreamofCooklnletcrossing ASV 1 No 28 793.34 27.33 Downstream of Cook Inlet crossing RCV 1 No HCA-Nikiski Middle/High School, Kenai Heliport, 797 71 0.94 Commercial Buildings, and Industrial Sites- 1.57 1 Yes 798 65 miles HCA-Nikiski Middle/High School, Kenai Heliport, 798 65 0.63 Commercial Buildings, and Industrial Sites- 1.57 2 Yes 799 28° miles 799.28 to 1.99 2 No 801.27 29 799.85 6.51 Stand-alone MLBV- Potential Class 2 Location RCV 2 No 803.39 to HCA- Conoco Phillips Property and Tesoro Kenai 803.78 0 39 Refinery -2.66 miles I Yes 803.78 to HCA- Conoco Phillips Property and Tesoro Kenai 2 806.05 2 27 Refinery -2.66 miles Yes 806.05 to 0.20 2 No 806.25 PHMSA-2017-0045: Alaska Gasline Development Corporation Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing Page 15 of 16 <<>> Table 2: Mainline Valve Locations for Alaska LNG Pipeline with High Consequence Areas, Bridges, and Railroad Locations MLBV I Valve I Class HCA # MP I A MP, miles i Location Description I Type Location(s) Yes/No 30 806.57 6.72 LNG Meter Station RCV 1 No PHMSA-2017-0045: Alaska Gasline Development Corporation Alaska LNG Pipeline- Special Permit for Mainline Valve Spacing Page 16 of 16 <<>> U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION Mainline Block Valve Spacing Special Permit Analysis and Findings Special Permit Information: Docket Number: PHMSA-2017-0045 Requested By: Alaska Gasline Development Corporation Operator ID#: 40015 Original Date Requested: April 14, 2017 Original Issuance Date: September 9, 2019 Effective Dates: September 9, 2029 Code Section(s): 49 CFR 192.179(a)(4) Purpose: The Pipeline and Hazardous Materials Safety Administration (PHMSA)1 provides information to describe the facts of the subject special permit application submitted by the Alaska Gasline Development Corporation (AGDC), owner and operator of the Alaska LNG Pipeline, 2 to discuss any relevant public comments received with respect to the application for a special permit, to present the engineering/safety analysis, and to make public the findings regarding whether the requested special permit should be granted and if so under what conditions. AGDC requested a special permit for the Alaska LNG Pipeline to waive compliance from 49 Code of Federal Regulations (CFR) 192.179(a)(4) for sectionalizing mainline block valve spacing in Class 1 locations in Alaska. 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 Alaska LNG Pipeline refers to the approximately 807 miles of 42-inch natural gas transmission pipeline and not to any potential owners, operators, or entities associated with the Alaska LNG Pipeline. The special permit owner, operator, and applicant/permittee is Alaska Gasline Development Corporation. Please note that this pipeline does not transport liquefied natural gas (LNG). It will supply natural gas to a LNG facility for further transportation as LNG. PHMSA-2017-0045 - - Alaska Gasline Development Corporation Alaska LNG Pipeline – Special Permit Analysis & Findings Page 1 of 11 <<>> Pipeline System Affected: The Alaska LNG Pipeline will be approximately 807 miles of 42-inch-diameter steel pipe for transporting natural gas from AGDC’s gas treatment plant (GTP) on Alaska’s North Slope to the liquefaction facility on the eastern shore of the Cook Inlet near Nikiski, Alaska. The pipeline will be mostly onshore, with a segment of offshore pipeline crossing the Cook Inlet. The onshore portion of the pipeline will be a buried pipeline except for short, above-ground special design segments, such as aerial water crossings and aboveground fault crossings. The Alaska LNG Pipeline’s design has a maximum allowable operating pressure (MAOP) of 2,075 pounds per square inch gauge (psig). AGDC is requesting a waiver of compliance of 49 CFR 192.179(a)(4) for remote, sparsely populated segments along the 42-inch pipeline route. AGDC’s special permit request is specifically for the Class 1 location segments.3 Federal pipeline safety regulations require natural gas transmission pipeline operators to have sectionalizing block valves within 10 miles of each point on the pipeline (or no more than 20 miles between sectionalizing mainline valves) in a Class 1 location. AGDC’s request allows for a valve spacing greater than 20 miles in Class 1 locations but requires all mainline block valves to be either remote controlled valves (RCVs) or automatic shut-off valves (ASVs). Special Permit Request: AGDC requested increased spacing of sectionalizing mainline block valves along the special permit segment as follows: Transmission Line Valves: Sectionalizing block valves along the special permit segment must be spaced as shown in Tables 1 and 24 and as follows for class location segments: a) Class 1 locations north of Fairbanks from Mile Post 0.00 to Mile Post 422 must have a 50- mile maximum sectionalizing block valve spacing between block valves (each point on the pipeline must be within 25 miles of a sectionalizing block valve). 3 49 CFR 192.5 defines Class location units and class 1, 2, 3, and 4 locations. 4 If AGDC determines that the sectionalizing block valve spacing or operational controls (RCV or ASV) as shown in Table 1 need to be modified, AGDC must submit proposed changes to the conditions and Table 1 to PHMSA’s Western Region Director or PHMSA Project Designee for review, and a “no objection” letter must be received prior to the change by AGDC. PHMSA-2017-0045 - - Alaska Gasline Development Corporation Alaska LNG Pipeline – Special Permit Analysis & Findings Page 2 of 11 <<>> b) Class 1 locations south of Fairbanks from Mile Post 422 to Mile Post 807 must have a 30- mile maximum sectionalizing block valve spacing between block valves (each point on the pipeline must be within 15 miles of a sectionalizing block valve). c) Class 2, 3, and 4 locations between Mile Post 0.00 to Mile Post 807 must comply with the requirements of 49 CFR 192.179. d) High consequence areas (as defined in 49 CFR 192.903 and 192.905) located in Class 1 and 2 locations, must comply with the requirements of 49 CFR 192.179. PHMSA designed a comprehensive set of special permit conditions that AGDC is required to implement in order to operate the 42-inch diameter pipeline with an increased mainline block valve spacing. An overview of the special permit condition topics is in the Operational Integrity Compliance section of this document. The special permit conditions were based upon pipeline safety considerations for the 49 CFR Part 192 sections that AGDC was seeking relief for an alternative mainline block valve spacing. The usage of remote controlled valves (RCVs) and automatic shut-off valves (ACVs) will reduce the time to isolate a pipeline segment should there be a rupture on the pipeline. In remote locations where it could take over 1 hour to isolate a pipeline segment, the Alaska LNG Pipeline will be able to isolate a pipeline segment in less than 35 minutes. The time to isolate a mainline block valve (MLBV) along the special permit segment is shown in Table 2 - MLBV Locations with Approximate Valve Closure Time and Gas Released. Special Permit Segment: State of Alaska The Alaska LNG Pipeline special permit segment is defined as: approximately 807 miles of 42-inch diameter pipeline originating in the North Slope Borough, traversing the Yukon-Koyukuk Census Area, the Fairbanks North Star Borough, the Denali Borough, the Matanuska-Susitna Borough, and the Kenai Peninsula Borough. The special permit segment terminates at the liquefaction facility on the shore of the Cook Inlet near Nikiski, Alaska. The special permit allows alternative mainline valve placement in Class 1 locations on the 42-inch special permit segment with the implementation of the special permit conditions. PHMSA-2017-0045 - - Alaska Gasline Development Corporation Alaska LNG Pipeline – Special Permit Analysis & Findings Page 3 of 11 <<>> Public Notice: On May 28, 2019, PHMSA published a special permit request in the Federal Register (84 FR 24594) for public comment. The public comment period ended on July 29, 2019, and PHMSA reviewed and considered all comments received through July 29, 2019. The special permit application from AGDC, pipeline route maps, public comments, final environmental assessment and finding of no significant impact, and special permit conditions are available in Docket No. PHMSA-2017-0045 at: www.regulations.gov. PHMSA Overall Response and Considerations of Public Safety Concerns: PHMSA published a Notice of Availability in the Federal Register on May 28, 2019, for four (4) special permit requests for the line pipe of the Alaska LNG Pipeline. (84 FR 24594, Docket Nos.: PHMSA-2017-0046, Usage of 3LPE Coating; PHMSA-2017-0044, Usage of Strain Based Design; PHMSA-2017-0045, Alternative Mainline Block Valve Spacing; and PHMSA-2017-0047, Usage of Crack Arrestor Spacing at www.Regulations.gov.) PHMSA requested comment on the special permit applications, the draft permit conditions, and the draft environmental analyses. The public notice comment period ended on July 29, 2019, and PHMSA reviewed and considered all comments received through July 29, 2019. PHMSA received a public comment concerning usage of fossil fuels, the building of the Alaska LNG Pipeline, and the building of a liquified natural gas (LNG) facility. PHMSA does not have siting authority over pipeline facilities. The public comment received did not submit concerns directed towards the special permit, the environmental assessment, or the special permit conditions, which were the issues within PHMSA’s decision making authority and the intent of the public notice. Operational Integrity Compliance: PHMSA has reviewed this special permit request to ensure that integrity threats to the pipeline in the special permit segment are addressed in the operator’s operations and management plan (O&M Procedures and specifications). PHMSA carefully designed a comprehensive set of conditions that AGDC is required to implement in order to operate the Alaska LNG Pipeline with increased mainline block valve spacing in Class 1 locations. PHMSA-2017-0045 - - Alaska Gasline Development Corporation Alaska LNG Pipeline – Special Permit Analysis & Findings Page 4 of 11 <<>> The special permit conditions are summarized by topic in the below list. The full conditions can be reviewed in their entirety in the special permit, which can be reviewed on Docket PHMSA-2017- 0045 at www.regulations.gov. 1) Applicable Regulations 2) Maximum Allowable Operating Pressure 3) Transmission Line Valves 4) Valve Monitoring, Control and Closure 5) Mainline Valve Locations 6) Emergency Operations 7) Emergency Training and Planning 8) Annual Reports 9) Notifications 10) Certification 11) Changes to Special Permit Conditions 12) Limitations Past Enforcement History: AGDC has no gas transmission pipeline operating history or enforcement history with PHMSA. Findings: Based on the information submitted by AGDC and PHMSA’s analysis of technical, operational, and safety issues, and given the conditions that will be imposed in the special permit, PHMSA finds that granting this special permit to AGDC to operate the Alaska LNG Pipeline special permit segment at increased mainline block valve spacing intervals and with either RCVs or ASVs will not be inconsistent with pipeline safety. Completed in Washington DC on: September 9, 2019 Prepared By: PHMSA – Engineering and Research Division PHMSA-2017-0045 - - Alaska Gasline Development Corporation Alaska LNG Pipeline – Special Permit Analysis & Findings Page 5 of 11 <<>> Figure 1: ALASKA LNG Pipeline Route PHMSA-2017-0045 - - Alaska Gasline Development Corporation Alaska LNG Pipeline – Special Permit Analysis & Findings Page 6 of 11 <<>> Table 1: Mainline Valve Locations for Alaska LNG Pipeline with High Consequence Areas (HCAs), Bridges, and Railroad Locations MLBV # MP  MP, miles Location Description Valve Type Class Location(s) HCA Yes/No 1 0.00 GTP Meter Station RCV 1 No 2 36.74 36.74 Stand-alone MLBV - Potential Station ASV 1 No 3 75.97 39.23 Compressor Station - Sagwon RCV 1 No 4 112.04 36.07 Stand-alone MLBV - Potential Station ASV 1 No 5 148.51 36.47 Compressor Station - Galbriath Lake RCV 1 No 6 194.09 45.58 Stand-alone MLBV - Potential Station ASV 1 No 6 194.09 45.58 Stand-alone MLBV - Potential Station ASV 1 No 236.08 to 237.33 1.25 HCA – Marion Campground – 1.25 miles 1 Yes 7 240.10 46.01 Compressor Station - Coldfoot RCV 1 No 8 286.05 45.95 Stand-alone MLBV - Potential Station ASV 1 No 9 332.64 46.59 Compressor Station - Ray River RCV 1 No 352.21 to 353.35 1.14 HCA - Hotspot Café 1 Yes 9a 356.22 23.58 Added for potential “Hotspot Café” HCA ASV 1 No 10 377.95 21.73 Stand-alone MLBV - Potential Station ASV 1 No 11 421.56 43.61 Compressor Station - Minto RCV 1 No 12 444.90 23.34 Stand-alone MLBV ASV 1 No 13 467.10 22.20 Stand-alone MLBV - Potential Station ASV 1 No 14 492.96 25.86 Stand-alone MLBV ASV 1 No 15 517.62 24.66 Compressor Station - Healy RCV 1 No 529.21 to 530.44 1.23 HCA – RV Park and Hotel – 1.23 miles 1 Yes 532.07 Alaska Railroad Crossing 1 No 532.13 Nenana River Bridge Crossing 1 No 16 534.79 17.17 Upstream of Class 3 Location - Nenana Canyon ASV 1 No 535.54 to 535.99 0.45 HCA - Denali Riverside RV Park, McKinley Chalet Resort, Denali Rainbow Village and RV, Denali Princess Wilderness Lodge, Denali Crows Nest Cabins, Grand Denali Lodge, and Denali Bluffs Hotel – 2.20 miles 1 Yes 535.99 to 536.49 0.50 HCA - Denali Riverside RV Park, McKinley Chalet Resort, Denali Rainbow Village and RV, Denali Princess Wilderness Lodge, Denali Crows Nest Cabins, Grand Denali Lodge, and Denali Bluffs Hotel – 2.20 miles 3 Yes PHMSA-2017-0045 - - Alaska Gasline Development Corporation Alaska LNG Pipeline – Special Permit Analysis & Findings Page 7 of 11 <<>> Table 1: Mainline Valve Locations for Alaska LNG Pipeline with High Consequence Areas (HCAs), Bridges, and Railroad Locations MLBV # MP  MP, miles Location Description Valve Type Class Location(s) HCA Yes/No 536.49 to 537.74 1.25 HCA - Denali Riverside RV Park, McKinley Chalet Resort, Denali Rainbow Village and RV, Denali Princess Wilderness Lodge, Denali Crows Nest Cabins, Grand Denali Lodge, and Denali Bluffs Hotel – 2.20 miles 1 Yes 537.79 Lynx Creek Bridge Crossing 1 Yes 17 538.79 4.00 Downstream of Class 3 Location - Nenana Canyon ASV 1 No 18 546.50 7.71 Stand-alone MLBV - Potential Station ASV 1 No 551.34 to 552.27 0.93 HCA – Denali Perch Resort – 0.93 miles 1 Yes 565.77 to 567.23 1.46 HCA – DOT/PF Cantwell Station – 1.46 miles 1 Yes 19 572.23 25.73 Stand-alone MLBV ASV 1 No 572.79 Alaska Railroad Crossing 1 No 588.07 Alaska Railroad Crossing 1 No 20 597.35 25.12 Compressor Station - Honolulu Creek RCV 1 No 609.02 Alaska Railroad Crossing 1 No 21 625.83 28.48 Stand-alone MLBV ASV 1 No 629.75 to 631.35 1.60 HCA – Byers Lake Campground (73 units) – 1.60 miles 1 Yes 633.75 to 634.50 0.75 HCA – Trappers Creek Pizza Club – 0.75 miles 1 Yes 22 648.16 22.33 Stand-alone MLBV - Potential Station ASV 1 No 23 675.24 27.08 Compressor Station - Rabideux Creek RCV 1 No 24 703.67 28.43 Stand-alone MLBV - Potential Station ASV 1 No 25 725.93 22.26 Stand-alone MLBV - Potential Station ASV 1 No 26 749.11 23.18 Heater Station - Theodore River RCV 1 No 27 766.01 16.90 Upstream of Cook Inlet crossing ASV 1 No 28 793.34 27.33 Downstream of Cook Inlet crossing RCV 1 No 797.71 to 798.65 0.94 HCA – Nikiski Middle/High School, Kenai Heliport, Commercial Buildings, and Industrial Sites – 1.57 miles 1 Yes 798.65 to 799.28 0.63 HCA – Nikiski Middle/High School, Kenai Heliport, Commercial Buildings, and Industrial Sites – 1.57 miles 2 Yes 799.28 to 801.27 1.99 2 No 29 799.85 6.51 Stand-alone MLBV - Potential Class 2 Location RCV 2 No 803.39 to 803.78 0.39 HCA – Conoco Phillips Property and Tesoro Kenai Refinery – 2.66 miles 1 Yes PHMSA-2017-0045 - - Alaska Gasline Development Corporation Alaska LNG Pipeline – Special Permit Analysis & Findings Page 8 of 11 <<>> Table 1: Mainline Valve Locations for Alaska LNG Pipeline with High Consequence Areas (HCAs), Bridges, and Railroad Locations MLBV # MP  MP, miles Location Description Valve Type Class Location(s) HCA Yes/No 803.78 to 806.05 2.27 HCA – Conoco Phillips Property and Tesoro Kenai Refinery – 2.66 miles 2 Yes 806.05 to 806.25 0.20 2 No 30 806.57 6.72 LNG Meter Station RCV 1 No Table 2 - MLBV Locations with Approximate Valve Closure Time and Gas Released MLBV # MP MP Location Description Valve Type Approximate Closure Time (minutes)5 Approximate Mass of Gas Released (tons)6 1 0.00 GTP Meter Station RCV 10.7 14,600 2 36.74 36.74 Stand-alone MLBV - Potential Station 28.6 14,600 ASV 29.9 15,300 10.7 15,300 3 75.97 39.23 Compressor Station - Sagwon RCV 10.7 14,400 4 112.04 36.07 Stand-alone MLBV - Potential Station 28.3 14,400 ASV 28.5 14,500 5 148.51 36.47 Compressor Station - Galbriath Lake RCV 10.7 14,500 10.7 17,000 6 194.09 45.58 Stand-alone MLBV - Potential Station 33.1 17,000 ASV 33.3 14,600 7 240.10 46.01 Compressor Station - Coldfoot 10.7 14,600 RCV 10.7 17,100 8 286.05 45.95 Stand-alone MLBV - Potential Station ASV 33.3 17,100 33.6 17,200 9 332.64 46.59 Compressor Station - Ray River RCV 10.7 17,200 10.7 16,900 9A 356.22 23.58 Added for potential “Hotspot Café” HCA ASV 20.5 11,300 23.7 11,500 10 377.95 21.78 Stand-alone MLBV - Potential Station ASV 32.9 16,900 32.1 16,500 5 Closure time is the total time measured from leak detection to complete valve closure and full interruption of flow. 6 The mass of gas released is based on a rupture occurring between the adjacent valves using the closure times of the upstream and downstream valves. Based on the Alaska LNG Pipeline gas composition, there are 45,148 cubic feet per ton. PHMSA-2017-0045 - - Alaska Gasline Development Corporation Alaska LNG Pipeline – Special Permit Analysis & Findings Page 9 of 11 <<>> Table 2 - MLBV Locations with Approximate Valve Closure Time and Gas Released MLBV # MP MP Location Description Valve Type Approximate Closure Time (minutes)5 Approximate Mass of Gas Released (tons)6 10.7 16,500 11 421.56 43.61 Compressor Station - Minto RCV 10.7 10,200 21.8 10,200 12 444.90 23.34 Stand-alone MLBV ASV 20.4 11,200 13 467.10 22.20 Stand-alone MLBV - Potential Station 20.4 11,200 ASV 22.7 12,700 22.7 12,700 14 492.96 25.86 Stand-alone MLBV ASV 22.5 10,700 10.7 10,700 15 517.62 24.66 Compressor Station - Healy RCV 10.7 7,800 16 534.79 17.17 Upstream of Class 3 Location - Nenana Canyon 18.7 7,800 ASV 9.3 2,300 17 538.79 4.00 Downstream of Class 3 Location - Nenana Canyon ASV 9.3 2,300 11.6 4,400 18 546.50 7.71 Stand-alone MLBV - Potential Station 11.6 4,400 ASV 22.6 12,700 22.6 12,700 19 572.23 25.73 Stand-alone MLBV ASV 22.7 10,800 20 597.35 25.12 Compressor Station - Honolulu Creek RCV 10.7 10,800 10.7 12,000 24.4 12,000 21 625.83 28.48 Stand-alone MLBV ASV 20.5 11,300 22 648.16 22.33 Stand-alone MLBV - Potential Station 20.5 11,300 ASV 23.7 11,500 23 675.24 27.08 Compressor Station - Rabideux Creek RCV 10.7 11,500 10.7 12,000 24 703.67 28.43 Stand-alone MLBV - Potential Station ASV 24.4 12,000 20.5 11,300 25 725.93 22.26 Stand-alone MLBV - Potential Station 20.5 11,300 ASV 21.8 10,100 26 749.11 23.18 Heater Station - Theodore River 10.7 10,100 RCV 10.7 7,700 27 766.01 16.90 Upstream of Cook Inlet crossing ASV 18.6 7,700 23.6 13,300 28 793.34 27.33 Downstream of Cook Inlet crossing RCV 23.6 13,300 10.9 3,700 29 799.85 6.51 RCV 10.9 3,700 PHMSA-2017-0045 - - Alaska Gasline Development Corporation Alaska LNG Pipeline – Special Permit Analysis & Findings Page 10 of 11 <<>> Table 2 - MLBV Locations with Approximate Valve Closure Time and Gas Released MLBV # MP MP Location Description Valve Type Approximate Closure Time (minutes)5 Approximate Mass of Gas Released (tons)6 Stand-alone MLBV - Potential Class 2 Location 13.4 3,300 30 806.57 6.72 LNG Meter Station RCV 10.7 3,300 PHMSA-2017-0045 - - Alaska Gasline Development Corporation Alaska LNG Pipeline – Special Permit Analysis & Findings Page 11 of 11 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION Final Environmental Assessment and Finding of No Significant Impact Mainline Block Valve Spacing Special Permit Special Permit Information: Docket Number: PHMSA-2017-0045 Requested By: Alaska Gasline Development Corporation Operator ID#: 40015 Original Date Requested: April 14, 2017 Original Issuance Date: September 9, 2019 Effective Date: September 9, 2019 Code Sections: 49 CFR 192.179(a)(4) Page 1 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Mainline Block Valve Final Environmental Assessment This Final Environmental Assessment (FEA) analyzes the Alaska LNG Pipeline for a special permit to waive the requirements of Title 49 of the Code of Federal Regulations (CFR) 192.179(a)(4). The special permit request described herein is related to, but distinct from the Federal Energy Regulatory Commission (FERC) decision making process for siting and permitting Alaska LNG’s 42-inch pipeline (Mainline) to transport natural gas to a facility on Alaska’s North Slope. The Pipeline and Hazardous Material Safety Administration (PHMSA) does not have pipeline siting or construction approval authority, but PHMSA’s pipeline safety regulations impose certain safety requirements that will apply to the Alaska LNG Pipeline. The requirements for special permit applications to PHMSA to request waiver from one or more safety regulations are described at 49 CFR 190.341. This FEA references the Alaska Gasline Development Corporation’s (AGDC) FERC Resource Reports for the Alaska LNG Pipeline to avoid duplication. Furthermore, this FEA accompanies AGDC’s special permit request on crack arrestor spacing. This information can also be found in Appendix C, Environmental Information for Mainline Block Valve and Crack Arrestor Spacing Special Permit of the Alaska LNG Pipeline FERC Resource Report No. 11, Reliability and Safety found on the FERC docket CP17- 178, Accession Number 20170417-5342 which can be accessed through https://elibrary.ferc.gov/IDMWS/common/OpenNat.asp?fileID=14562356. I. Purpose and Need AGDC is proposing to construct a 42-inch diameter pipeline as part of an integrated liquefied natural gas (LNG) project (Project) with interdependent facilities for the purpose of liquefying supplies of natural gas from Alaska, in particular from the Point Thomson Unit (PTU) and Prudhoe Bay Unit (PBU) production fields on the Alaska North Slope (North Slope), for export in foreign commerce and for in-state deliveries of natural gas. FERC is the lead Federal agency. Pursuant to 49 U.S.C. 60101, et seq and 49 CFR 192, PHMSA has authority over design, construction, operation, and maintenance of natural gas pipelines to maintain safety. As noted above, PHMSA does not have pipeline siting authority or construction approval authority. If required, special permits can be granted under 49 CFR 190.341 for deviations from the regulatory requirements. PHMSA imposes conditions on the grant of special permits to assure safety and environmental protection in accordance with 49 CFR 190.341. PHMSA complies with the National Environmental Policy Act (NEPA) in deciding whether to issue the special permit. AGDC is requesting a special permit from PHMSA to waive compliance with 49 CFR 192.179 only in Class 1 locations. AGDC is proposing a mainline block valve (MLBV) Page 2 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 spacing of 50 miles north of Fairbanks, Alaska, and 30 miles south of Fairbanks. 1 The purpose of MLBVs is to isolate a segment of pipeline in the event of a pipeline failure in order to stop product flow to the failure site. The spacing of MLBV is defined in 49 CFR 192.179(a) as stated below: Each transmission line, other than offshore segments, must have sectionalizing block valves spaced as follows, unless in a particular case the Administrator finds that alternative spacing would provide an equivalent level of safety: (4) Each point on the pipeline in a Class 1 location must be within 10 miles (16 kilometers) of a valve. II. Background and Site Description The Alaska LNG Pipeline route from the proposed gas treatment plant (GTP) located at Prudhoe Bay to the proposed LNG Plant site located on the Kenai Peninsula is shown in Figure 1. The Alaska LNG Pipeline will be a 42-inch-diameter natural gas pipeline, approximately 807 miles in length, extending from the Alaska LNG’s GTP on the North Slope, flowing south to the Liquefaction Facility on the shore of the Cook Inlet near Nikiski, including an offshore pipeline section crossing Cook Inlet. The onshore pipeline will be a buried pipeline except for short aboveground special design segments, such as aerial water crossings and aboveground fault crossings. As presented in Table 1.3.2-1 of FERC Resource Report 1 (inserted below), the Alaska LNG Pipeline will originate in the North Slope Borough, traverse south to the Yukon-Koyukuk Census Area, the Fairbanks North Star Borough, the Denali Borough, the Matanuska-Susitna Borough, and the Kenai Peninsula Borough, and terminate at the Liquefaction Facility. The Alaska LNG Pipeline’s design has a maximum allowable operating pressure (MAOP) of 2,075 pounds per square inch gauge (psig). 1 The average Class 1 MLBV spacing north of Fairbanks is about 42 miles, while the average spacing south of Fairbanks is about 24 miles. Page 3 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Figure 1: Alaska LNG Pipeline Route Map Page 4 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 TABLE 1.3.2-1 (From FERC Resource Report 1) Mainline Route Summary for a 42-inch Pipeline Segment or Facility Name Boroughs or Census Areas Approximate Length (miles) North Slope Borough 184.4 Yukon-Koyukuk Census Areas 303.8 Fairbanks North Star Borough 2.4 Mainline Denali Borough 86.8 Matanuska-Susitna Borough 179.9 Kenai Peninsula Borough 51.3 Total 806.6 The Alaska LNG Pipeline will include several types of aboveground pipeline facilities. The design includes eight (8) compressor stations, four meter stations, multiple pig launching/receiving stations, multiple MLBVs, and five potential gas interconnection points (Figure 2 and Figure 3 to this FEA, and FERC Resource Report No. 1, Appendix A). A list of compressor stations, heater station, and meter stations is provided in Table 1.3.2-6 of FERC Resource Report 1. Approximately 36 percent of the Alaska LNG Pipeline route is collocated within 500 feet of: an existing right-of-way (ROW) that includes the Trans Alaska Pipeline System (TAPS) and other pipelines; highways or major roads; utilities; and railroads. Table 1.3.2-2 of FERC Resource Report No. 1 (inserted below) identifies these areas along the pipeline. The Alaska LNG Pipeline crosses TAPS twelve times and its associated Fuel Gas Line five times, respectively, along with four railroad crossings. Design of the road and railroad crossings will determine the minimum wall thickness requirements for service loads in accordance with American Petroleum Institute (API) Recommended Practice (RP) 1102, and in compliance with 49 CFR 192.111. The minimum depth of cover will be four (4) feet for road crossings as specified by the Alaska Administrative Code 17.AAC 15.211 “Underground Facilities”, and ten feet for railroad crossings as specified in Alaska Railroad Corporation (ARRC) standards. These values exceed the 49 CFR 192.327 requirement of a minimum of three feet at drainage ditches of public roads and railroads. Site-specific designs for major highway and railroad crossings are provided in Appendix H of FERC Resource Report No. 1, General Project Description, and in the table below: Bridge and Railroad Crossings Milepost (MP) Crossing Type Description 532.13 Bridge Nenana River at Moody 537.90 Bridge Lynx Creek 532.07 Railroad Alaska Railroad Mainline Page 5 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 572.79 Railroad Alaska Railroad Mainline 588.07 Railroad Alaska Railroad Mainline 609.02 Railroad Alaska Railroad Mainline Additional details on roads, railroads, pipelines, utilities, and power line crossings can be found in FERC Resource Report No. 8, Land Use, Recreation, and Aesthetics. TABLE 1.3.2-2 (From FERC Resource Report No. 1) Collocated ROWs with the Mainline (within 500 feet) Borough/Census Area Category Length (Miles) Length (Feet) North Slope Borough Trans-Alaska Pipeline System (TAPS) 24.39 128,768 Other Pipelinesa 34.83 183,904 Highways or Major Roadsb 59.97 316,630 Utilities 108.65 573,692 Railroads – – Yukon-Koyukuk Census Area TAPS 64.14 338,653 Other Pipelinesa – – Highways or Major Roadsb 94.13 496.985 Utilities 106.42 561.898 Railroads 0.83 4,405 Denali Borough TAPS – – Other Pipelinesa 0.09 453 Highways or Major Roadsb 13.25 69,984 Utilities 46.21 243,983 Railroads 1.00 5,283 Matanuska-Susitna Borough TAPS – – Other Pipelinesa 2.31 12,206 Highways or Major Roadsb 26.76 141,289 Utilities 29.76 157,157 Railroads 2.30 12,123 Kenai Peninsula Boroughc TAPS – – Other Pipelinesa 3.37 17,810 Highways or Major Roadsb 1.58 8,342 Utilities 0.02 130 Railroads – – Total Collocation Opportunities 289.58 1,528,971 Page 6 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Aerial crossings on pipeline specific bridges (i.e. bridges that carry only a pipeline) are located at Nenana River at Moody and Lynx Creek. The design factor for the pipeline at aerial crossings will comply with 49 CFR § 192.111 (i.e., the design factor in Class 1 Locations will be 0.60). Pipeline design standards in 49 CFR 192.5(a)(1) are based on “class location units,” which classify locations based on population density in the vicinity of an existing or proposed pipeline system. The lower the class location (1-4), the higher the design factor used to find the minimum required wall thickness for pressure containment, i.e. the required minimum thickness of the pipe increases as the Class location and population density increases. Ninety-nine percent of the Alaska LNG Pipeline route is in Class 1, which is defined as having 10 or fewer buildings intended for human occupancy located within 220 yards on either side of any continuous 1-mile length of pipeline. On the Kenai Peninsula, near Nikiski, there is a Class 2 location that is about 2.6 miles long, and a potential Class 3 location as the Mainline nears the LNG Plant. In the Nenana Canyon region of Denali National Park (~milepost [MP] 536) there is approximately 0.5 mile of Class 3. Additional details on class locations for the Mainline can be found in FERC Resource Report No. 11, Reliability and Safety, Section 11.7. Resource Report No. 11 and Table 11.7.2-1 identifying class locations for the pipeline route is reproduced below. TABLE 11.7.2-1 (From FERC Resource Report No. 11) Class Locations for the Mainline Milepost (MP) Start (MP) End (MP) Class Location 0.00 535.99 1 535.99 536.49 3 536.49 798.65 1 798.65 801.27 2 801.27 803.78 1 803.78 806.25 2 806.25 806.57 1 There are 10 potential high consequence areas (HCA), as defined under 49 CFR 192.903, along the Alaska LNG Pipeline route. Details of HCA locations can be found in FERC Resource Report No. 11, Section 11.7, Table 11.7.4-1 (shown below with insertions for mainline valve Page 7 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 locations and valve type), Table 1, Table 2, and Attachment D - Main Line Block Valve Spacing Technical Support document2 of the MLBV spacing special permit application. TABLE 11.7.4-1 (From FERC Resource Report No. 11) – with insertions for mainline valve locations and type Potential HCA Takeoff for Proposed Route From MP To MP Length (mi.) Description 0.00 MLBV 1, GTP Meter Station 36.74 MLBV 2, Automatic Shut-off Valve (ASV) 75.97 MLBV 3, Remote Controlled Valve (RCV) 112.04 MLBV 4, ASV 148.51 MLBV 5, RCV 194.09 MLBV 6, ASV 236.08 237.33 1.25 Marion Creek Campground 240.1 MLBV 7, RCV 286.05 MLBV 8, RCV 332.64 MLBV 9, RCV 352.21 353.35 1.14 Hotspot Cafe 356.22 MLBV 9A, ASV 377.95 MLBV 10, ASV 421.56 MLBV 11, RCV 444.90 MLBV 12, ASV 467.10 MLBV 13, ASV 492.96 MLBV 14, ASV 517.62 MLBV 15, RCV 529.21 530.44 1.23 RV Park and Motel 534.79 MLBV 16, ASV 535.54 537.74 2.20 Denali Riverside RV Park, McKinley Chalet Resort, Denali Rainbow Village and RV, Denali Princess Wilderness Lodge, Denali Crow’s Nest Cabins, Grand Denali Lodge, Denali Bluffs Hotel 538.79 MLBV 17, ASV 546.50 MLBV 18, ASV 551.34 552.27 0.93 Denali Perch Resort 565.77 567.23 1.46 DOT/PF Cantwell Station 572.23 MLBV 19, ASV 597.35 MLBV 20, RCV 2 Attachment D can be found in www.regulations.gov in Docket PHMSA-2017-0045. Page 8 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 625.83 MLBV 21, ASV 629.75 631.35 1.60 Byers Lake Campground (73 units) 633.75 634.50 0.75 Trappers Creek Pizza Pub 648.16 MLBV 22, RCV 675.24 MLBV 23, ASV 703.67 MLBV 24, ASV 725.93 MLBV 25, RCV 749.11 MLBV 26, ASV 766.01 MLBV 27, ASV 793.34 MLBV 28, RCV 797.71 799.28 1.57 Nikiski Middle/High School, Kenai Heliport, Commercial Buildings, Industrial Sites 799.85 MLBV 29, RCV 803.39 806.05 2.66 Conoco Phillips Property and Tesoro Kenai Refinery 806.57 MLBV 30, LNG Meter Station HCA Total Length 14.79 In addition, the pipeline route special permit segments addressed in the special permit for Strain Based Design (SBD) segments, will be incorporated into the integrity management program (IMP), and treated as covered segments in HCA, in accordance with 49 CFR Part 192, Subpart O, and the associated special permit conditions, if the special permit for Strain Based Design is granted by PHMSA. The construction ROW width will vary depending on the type of terrain, the season of construction, and the ease of access from nearby roads. The ROW width will be 50 feet plus the diameter of the pipeline, i.e. 53.5 feet. At MLBV locations the ROW width will expand to approximately 85 feet over lengths of approximately 100 feet. If a helipad associated with any MLBV location is deemed necessary, an additional section of expanded ROW (approximately 115 feet wide by approximately 115 feet long) will be required. See FERC Resource Report No. 1, General Project Description, Appendix E, drawing E-102 for further details of the overall arrangement. Greater details on the construction ROW can be found in FERC Resource Report No. 1, General Project Description. The Mainline will be sited on land composed of more than 85 percent Federal, State of Alaska, and borough land of various holdings, with the remainder on privately owned land (see FERC Resource Report No. 8, Land Use, Recreation and Aesthetics). Page 9 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Environmental Setting The corridor for the Alaska LNG Pipeline spans nine ecoregions including the Beaufort Coastal Plain, Brooks Foothills, Brooks Range, Kobuk Ridges and Valleys, Ray Mountains, Yukon-Tanana Uplands, Tanana-Kuskokwim Lowlands, Alaska Range, and Cook Inlet Basin. These regions host a variety of ecosystems including muskeg bogs, spruce upland forest, alpine and Arctic tundra, high brush, and bottomland spruce and poplar forests. The associated ecosystems support a variety of species which include grizzly and black bears, Arctic foxes, seals, caribou, moose, small terrestrial mammals, birds, and anadromous fish. A variety of marine mammals inhabit the coastal waters along the pipeline ROW, including the bowhead whale, polar bear, beluga whale, ringed seal, bearded seal, Stellar sea lion, harbor seal, ribbon seal and spotted seal. Some of these species are critical subsistence resources for Alaska Native peoples. For additional information see FERC Resource Report No.3, Fish, Wildlife and Vegetation Resources. A detailed description of the Alaska LNG Pipeline ROW is included in Section 1.3.2.1 of FERC Resource Report No. 1, General Project Description. Supporting facilities are described in Section 1.3.2.1.3 and temporary construction infrastructure is described in Section 1.3.2.4 of FERC Resource Report No. 1, General Project Description. Baseline environmental conditions and the analysis of environmental effects resulting from construction and operation of the Alaska LNG Pipeline are addressed in the individual FERC Resource Reports which can be accessed by entering the FERC Docket Number “CP17-178” at https://elibrary.ferc.gov/IDMWS/common/OpenNat.asp?fileID=14562356 and then opening the Accession Number of the FERC filing for that Resource Report. Direct links to the Accession File for each Resource Report are given below: a) Resource Report No. 1 (General Project Description) 20170417-5337. https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14561634 b) Resource Report No. 2 (Water Use and Quality) 20170417-5341. https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14561641 c) Resource Report No. 3 (Fish, Wildlife and Vegetation) 20170417-5351. https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14561657 d) Resource Report No. 4 (Cultural Resources) 20170417-5336. https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14561631 e) Resource Report No. 5 (Socioeconomics) 20170417-5338. https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14561635 f) Resource Report No. 6 (Geological Resources) 201704167-5338. https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14561635 Page 10 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 g) Resource Report No. 7 (Soils) 20170417-5345. https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14561645 h) Resource Report No. 8 (Land Use, Recreation and Aesthetics) 20170417-5345. https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14561645 i) Resource Report No. 9 (Air and Noise Quality) 20170417-5345. https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14561645 j) Resource Report No. 10 (Alternatives) 20170417-5340 https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14561638 k) Resource Report No. 11, (Reliability and Safety) 20170417-5342. https://elibrary.ferc.gov/idmws/file_list.asp?document_id=14561642 Description of Special Permit Needs As stated above, the Applicant is seeking exemption from the requirements for MLBV spacing requirements in 49 CFR 192.179 in Class 1 locations. Additional details on class locations for the Alaska LNG Pipeline can be found in FERC Resource Report No. 11, Reliability and Safety, Section 11.7. The Alaska LNG Pipeline will traverse areas of high environmental value commonly used for outdoor recreation, sporting, and subsistence activities. It is possible that individuals could be in the vicinity of the pipeline even if there are 10 or fewer buildings intended for human occupancy located within 220 yards on either side of any continuous 1-mile length of pipeline. However, as the engineering analysis has shown, the proposed alternative to MLBV spacing will not expose these individuals or infrastructure to any risk greater than a 49 CFR Part 192 compliant design, as a result of additional mitigation measures designed to reduce risk to the public and nearby infrastructure. III. Alternatives An applicant requesting a special permit from PHMSA has the option of building a pipeline that will not require PHMSA to issue a special permit. This will require the design, construction, and operation of a pipeline in compliance with all requirements of 49 CFR Part 192. Therefore, PHMSA’s NEPA assessment is slightly different form other agencies in that the “No Action” alternative is not a “no build” alternative. Rather, the No Action alternative reflects a pipeline design that will not require issuance of a special permit. The “Proposed Action” alternative reflects the Applicant’s increase of MLBV spacing for which a special permit with specific conditions will be issued. The two alternatives are described below. Page 11 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 No Action Alternative – Design, construct, operate and maintain the pipeline in compliance with 49 CFR Part 192. This will require MLBVs to be placed at intervals defined by 49 CFR 192.179(a)(4). A 20-mile maximum spacing is required in Class 1 locations. Proposed Action Alternative – Design, construct, operate, and maintain the pipeline with MBLV spacing at longer intervals than allowed by 49 CFR 192.179(a)(4), and design, construct, operate, and maintain the pipeline in compliance with the MLBV spacing special permit conditions. AGDC is requesting a special permit from PHMSA to allow for increased MLBV spacing, in low risk, Class 1 locations. This special permit contains conditions that will require enhanced monitoring of MLBVs with shorter valve activation times as compared to a design that is compliant to 49 CFR 192. The valves will include a combination of Remote Controlled Valves (RCV) and Automatic Shut-off Valves (ASV), both with pressure set points that will initiate automatic closure. In addition, the RCVs will be capable of remote operation (closure and opening) along with pressure monitoring, both upstream and downstream of the valve that is reported to a pipeline control center. Due to the faster response and the valves, any failure will result in equivalent gas release for the first 17.5 minutes following the failure. Thereafter, the shorter valve closure times required in the special permit will result in less gas released and lower thermal radiation factors. The below Figure 1A shows RCV and ASV closure times versus manual valve closure times. Page 12 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Figure 1A – Gas Outflow as a Function of Time The special permit conditions are designed to provide for equal or greater pipeline safety than a pipeline constructed in accordance with 49 CFR Part 192. a. Explain what the special permit application asks for. The special permit will increase MLBV spacing up to 50 miles north of Fairbanks and 30 miles South of Fairbanks from the requirement in 49 CFR 192.179(a)(4), which requires MLB spacing of up to 20 miles in Class 1 locations. i. Cite regulation(s) for which special permit is sought in accordance with 49 CFR 190.341: 49 CFR 192.179(a)(4). ii. Explain/summarize how the design/operation/maintenance of the pipeline operating under the special permit would differ from the pipeline in the no action alternative. There will be two (2) types of MLBVs utilized for line break detection and sectionalization: RCVs will be installed at all powered locations (i.e. compressor and heater stations), and ASVs will be installed at other locations. The ASVs willPage 13 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 automatically close based on either a pressure set point of 75% of the operating pressure at the valve location based upon maximum flow model gradients, or a decrease in operating pressure over a fifteen (15) minute period that is greater than approximately 10%, as these conditions will likely indicate a line break. Functionality will be added to the RCVs to allow the pipelines gas control center to remotely close these valves in an emergency when deemed safe to do so. The ASVs will close based on the 75% of maximum operating pressure (MOP) at the valve location based upon maximum flow model gradients. In addition, ASV set points shall not be less than that required to actuate the valve before a downstream RCV. Once activated, both types of valves will close in less than one (1) minute. Approximate closure times and gas release volumes for each valve-to-valve section are presented in Table 1 – MLBV Locations. These requirements are intended to result in a reduction of valve closure actuation times as compared to a 49 CFR Part 192 compliant design. Real time monitoring of the RCVs via the Supervisory Control and Data Acquisition (SCADA) system will be performed at the Alaska LNG Pipeline Control Center. Additional detail on the requirements for design, construction, and operation is provided in Section VII of this document and the special permit conditions. iii. Applicant should include the pipeline stationing and mile posts (MP) for the location or locations of the applicable special permit segment(s) Details of the MLBV locations are presented in Table 1 – MLBV Locations. Maps showing the MLBV locations and other information are presented in Figure 2 and Figure 3. 3 Table 1 MLBV Locations MLBV # MP MP Location Description Valve Type Approximate Closure Time (minutes)4 Approximate Mass of Gas Released (tons)5 1 0.00 GTP Meter Station RCV 10.7 14,600 2 36.74 36.74 Stand-alone MLBV - Potential Station 28.6 14,600 ASV 29.9 15,300 3 Estimated time to begin activation of a manual mainline valve, if the “No Action Alternative” is selected, is two hours with another 30 minutes to close the valve. 4 Closure time is the total time measured from leak detection to complete valve closure and full interruption of flow. 5 The mass of gas released is based on a rupture occurring between the adjacent valves using the closure times of the upstream and downstream valves. Based on the Alaska LNG Pipeline gas composition, there are 45,148 cubic feet per ton. Page 14 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Table 1 MLBV Locations MLBV # MP MP Location Description Valve Type Approximate Closure Time (minutes)4 Approximate Mass of Gas Released (tons)5 10.7 15,300 3 75.97 39.23 Compressor Station - Sagwon RCV 10.7 14,400 4 112.04 36.07 Stand-alone MLBV - Potential Station 28.3 14,400 ASV 28.5 14,500 5 148.51 36.47 Compressor Station - Galbriath Lake RCV 10.7 14,500 10.7 17,000 6 194.09 45.58 Stand-alone MLBV - Potential Station 33.1 17,000 ASV 33.3 14,600 7 240.10 46.01 Compressor Station - Coldfoot RCV 10.7 14,600 10.7 17,100 8 286.05 45.95 Stand-alone MLBV - Potential Station 33.3 17,100 ASV 33.6 17,200 9 332.64 46.59 Compressor Station - Ray River 10.7 17,200 RCV 10.7 16,900 9A 356.22 23.58 Added for potential “Hotspot Café” HCA ASV 20.5 23.7 11,300 11,500 10 377.95 21.78 Stand-alone MLBV - Potential Station 32.9 16,900 ASV 32.1 16,500 10.7 16,500 11 421.56 43.61 Compressor Station - Minto RCV 10.7 10,200 21.8 10,200 12 444.90 23.34 Stand-alone MLBV ASV 20.4 11,200 13 467.10 22.20 Stand-alone MLBV - Potential Station 20.4 11,200 ASV 22.7 12,700 22.7 12,700 14 492.96 25.86 Stand-alone MLBV ASV 22.5 10,700 10.7 10,700 15 517.62 24.66 Compressor Station - Healy RCV 10.7 7,800 16 534.79 17.17 Upstream of Class 3 Location - Nenana Canyon ASV 18.7 7,800 9.3 2,300 17 538.79 4.00 Downstream of Class 3 Location - Nenana Canyon 9.3 2,300 ASV 11.6 4,400 18 546.50 7.71 Stand-alone MLBV - Potential Station ASV 11.6 4,400 22.6 12,700 19 572.23 25.73 Stand-alone MLBV ASV 22.6 12,700 Page 15 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Table 1 MLBV Locations MLBV # MP MP Location Description Valve Type Approximate Closure Time (minutes)4 Approximate Mass of Gas Released (tons)5 22.7 10,800 20 597.35 25.12 Compressor Station - Honolulu Creek 10.7 10,800 RCV 10.7 12,000 24.4 12,000 21 625.83 28.48 Stand-alone MLBV ASV 20.5 11,300 22 648.16 22.33 Stand-alone MLBV - Potential Station ASV 20.5 11,300 23.7 11,500 23 675.24 27.08 Compressor Station - Rabideux Creek RCV 10.7 11,500 10.7 12,000 24 703.67 28.43 Stand-alone MLBV - Potential Station 24.4 12,000 ASV 20.5 11,300 25 725.93 22.26 Stand-alone MLBV - Potential Station 20.5 11,300 ASV 21.8 10,100 26 749.11 23.18 Heater Station - Theodore River RCV 10.7 10,100 10.7 7,700 27 766.01 16.90 Upstream of Cook Inlet crossing 18.6 7,700 ASV 23.6 13,300 28 793.34 27.33 Downstream of Cook Inlet crossing RCV 23.6 13,300 10.9 3,700 29 799.85 6.51 Stand-alone MLBV - Potential Class 2 Location 10.9 3,700 RCV 13.4 3,300 30 806.57 6.72 LNG Meter Station RCV 10.7 3,300 Page 16 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Figure 2: Valve Location Map Page 17 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Figure 3: Valve Location Map (Nenana Canyon) Page 18 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 i. Mitigation Measures Additional mitigation measures are addressed in Section VIII of this document and the special permit conditions. RCVs and ASVs to be used on the Alaska LNG Pipeline are identical in material and construction but differ with respect to the logic systems within the valve actuators connected to the valves. In both cases, the RCVs and ASVs will be large diameter ball valves meeting API 6D requirements and will be controlled by valve actuators. The valve actuators are gas-hydraulic powered, using line gas pressure to open/close the valves. The ASV’s will be configured to close automatically, utilizing energy stored in the valve actuator, when the gas pressure in the pipeline is below the valve close set point. An auxiliary device, such as a hand pump, may be required to reopen a valve after a closure event. RCV’s will be shut-in from the gas control center. The ASVs use mechanical systems to constantly compare the line pressure on either side of the valve to a pre-set value (75% MOP for the Alaska LNG Pipeline) and should the line pressure drop below this set point the valve will close. The use of purely mechanical and hydraulic systems for ASVs means they can operate without the need for electrical power in the event of a line break. Actuators on RCVs will include the same internal mechanical/hydraulic logic systems as the ASVs but will additionally incorporate power-controlled solenoids (switches) to signal the valve to close when a computer-controlled system sends an alternate signal to the valve based on other criteria. AGDC will implement procedures that a decrease in operating pressure over a fifteen (15) minute period of greater than approximately 10% MOP will cause mainline valves to be closed to isolate the applicable pipeline segment. RCVs can also be closed by a signal from the pipeline control center should the need arise, such as when an observation of a leak or rupture6 is reported. IV. Environmental Impacts of Proposed Action and Alternatives a. Describe how a small and large leak/rupture to the pipeline could impact safety and the environment/human health. 6 Definitions for “leak” or “rupture” vary. However, the project defines a “leak” as a release from a stable through- wall defect, and “rupture” as a release where the defect expands under the influence of the applied stress after become through-wall. Page 19 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Potential impacts of small and large pipeline leaks/ruptures to the environment/human health apply equally to the Proposed Action and No Action alternatives because: i. Any discussion of the consequence of a leak or rupture must be put into the context of its probability. It is highly unlikely a leak or rupture occurring over the Alaska LNG Pipeline Class 1 locations will impact the environment or human health for the following reasons: a) Remoteness of the pipeline route: more than 99% of the Alaska LNG Pipeline route is in Class 1 location (801 miles of 806.6 miles). The frequency of incidents is significantly less for pipelines in Class 1 locations than in Class 2, 3 or 4. Specifically, the number of incidents per 1,000 mile-years in Class 1 locations was 0.15 as compared with 0.24 and 0.65 for Class 2 and Class 3 and 4 locations, respectively. 7 The lower incident rate in Class 1 locations is attributed to fewer incidences of outside force damage in these lesser populated areas. b) Resilience to third party mechanical damage: given the planned thickness of the pipe wall, there is very low risk of mechanical damage. Fracture mechanics calculations based on the mechanical properties of the pipe material and operating conditions of the pipe have shown the pipe is very resistant to puncture and fracture, capable of withstanding a through wall thickness flaw of greater than 4 inches in length without rupturing. c) Very low probability of corrosion damage: The Alaska LNG Pipeline will be transporting a dry, LNG specification gas, which will contain no significant quantities of the microbial species required to cause corrosion: water (< 0.1 lbs./MMSCF), CO2 (<50 ppmv) and H2S (≤4 ppmv). With these low impurity contents, a corrosive liquid water phase will not form inside the pipeline. Therefore, the probability of internal corrosion is minimal. To ensure the integrity of the pipeline, the in-line inspection program will comply with the robust requirements of 49 CFR 192.620(d)(9) and (10). External corrosion will be mitigated by using a high-integrity coating with a cathodic protection system.8 d) Compliance with Alternative MAOP requirements: the entire Alaska LNG Pipeline will be operated and maintained per 49 CFR 192.620, which 7 Eiber, R., and Kiefner, J. 2010. Review of Safety Considerations for Natural Gas Pipeline Block Valve Spacing. ASME Standards Technology, LLC. Columbus. July. 8 See Alaska LNG Pipeline FEA for special permit request for use of 3LPE Coating. [Docket PHMSA-2017-0046 at www.regulations.gov] Page 20 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 establishes robust operational requirements. Additionally, more than 615 miles of the total Mainline length, to include Alternative MAOP and SBD segments, will also comply with 49 CFR 192.112 and 192.328, which, respectively, establish robust design and construction requirements. e) AGDC performed an engineering study that considered requirements from ASME B31.8 § 846.1 for block valve spacing, including consideration of “the amount of gas released due to repair and maintenance blowdowns, leaks, or ruptures.” The analysis results, summarized in Attachment D - Main Line Block Valve Spacing Technical Support document, suggest “that increased valve spacing could be implemented in remote, low population density areas without affecting safety” because, as the thermal radiation analysis demonstrated, there is a negligible difference in the potential consequence to people in Class 1 locations, where there is an extremely low density of buildings intended for human occupancy. Incident prevention (decreasing probability of rupture) is better controlled through other practices, such as design for fracture resistance and control, and robust integrity management practices that include in-line inspections.9 ii. A small leak from a buried pipeline would result in a much slower release of gas than a full-bore rupture, with the total amount of gas released being dependent on the time it takes for the leak to be detected and fixed. Small leaks would be identified through a variety of techniques, such as routine surveillance, pipeline inspection programs, and mass balance systems incorporated in gas pipeline control. These identification techniques are not impacted by mainline block valve spacing. Gas from a small leak would permeate up through the pipeline backfill material (soil) before dissipating into the air. An individual small leak is not a significant source of methane emissions, although such leaks in the aggregate can be. Also, small gas pipeline leaks may result in some impacts to, or loss of, surrounding vegetation. This localized browning of vegetation can facilitate identification of small underground leaks during ROW inspection, which will be performed at intervals not exceeding 45 days but a least 12 times each calendar year per 49 CFR 192.620(d)(4). The rate at which gas is lost, and total volume of gas lost from a small leak is independent of valve spacing and is more contingent on identification timelines. The environmental impacts caused from a small leak are the same in both the Proposed Action and No Action alternatives. 9 See Alaska LNG Pipeline FEA for special permit request for Crack Arrestor Spacing. [Docket PHMSA-2017-0047 at www.regulations.gov]. Page 21 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 iii. A pipeline rupture would result in the rapid release of a large volume of natural gas, resulting in significant damage to the pipeline and creating a trench or crater in the immediate vicinity of the rupture. If an ignition source is present, an intense fire or explosion would result. Damage from a fire resulting from a pipeline rupture would depend on the extent of the combustible materials in the vicinity (infrastructure, vegetation) and local environmental conditions (e.g., rain, snow cover, etc.). A thermal radiation intensity of approximately 4,750 Btu/hr-ft2 (15 kW/m2) will result in piloted ignition of nearby wooden structures. The calculated distance to this isotherm from an ignited rupture is approximately 1,700 feet after 30 seconds, and quickly diminishes. This distance is roughly equivalent to the calculated potential impact radius (PIR) of the pipeline. Thus, wooden structures within this distance (PIR) may ignite. Structures constructed of other materials (e.g. steel) would not be seriously affected within this distance. Human exposure to a fire within the PIR could result in serious injury or death; however, the probability for human injury or fatality, and property damage, is relatively small due to the remoteness of the pipeline. The risk to people and environmental resources decreases as distance from the rupture increases. The pipeline will be sectionalized with MLBVs and the gas released during a rupture scenario would be, limited to the gas volume between valves, once the valves have fully closed. This amount of gas volumes and pressures would determine the duration of the fire. For more information, see Table 1, Table 2, and Attachment D - of the special permit application. The spacing between the block valves is the subject of this special permit. Large ruptures would be detectable through monitoring of pressure and flow conditions at pipeline facilities and the MLBVs via the SCADA system. b. Submit an explanation of delta/difference in safety and possible effects to the environment between the 49 CFR Part 192 baseline (Code baseline) and usage of the proposed special permit conditions for MLBV spacing mitigation measures. i. The anticipated differences in effects for individual resources between the No Action alternative and the Proposed Action alternative are discussed below. References are made to FERC Resource Reports, where applicable, for further detailed information and analysis of impacted resources. The basis for the FERC Resource Reports is the Proposed Action alternative; however, the associated environmental impact analysis is also applicable to the No Action alternative, given both alternatives are based on below ground design and installation, and both follow an identical route. Page 22 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 1. Human Health and Safety The impacts to human health and safety, and related infrastructure, due to the rupture and ignition event are similar with respect to the Proposed Action and No Action alternatives since, assuming ignition occurs, the thermal radiation released is identical between the 20 and 50 miles spacing cases for approximately 17.5 minutes because of the identical gas flow rate from the pipeline. As stated previously, it is within the initial period (seconds to minutes) immediately following pipeline rupture when most injuries and fatalities occur, as this is when the thermal radius is at its largest, but quickly dropping after the initial rupture. With this initial period being equal in both the Proposed Action and No Action alternatives, there are no differential safety risks. However, the installation and operation of RCVs and ASVs in accordance with the special permit conditions will reduce the total duration and quantity of gas release when compared with a design in compliance with 49 CFR 192.179 or 192.620 (see Tables 5 and 6 in Attachment D - Main Line Block Valve Spacing Technical Support). With respect to the impacts of the total rupture event (including the timeline beyond the initial 17.5 -minute window discussed above), the published rupture analysis report evaluating the impact of increased sectionalizing valve spacing further outlines that the total threshold thermal dosage (accumulated amount of damaging heat) is equivalent in all sectionalizing valve spacing cases examined. 2. Air Quality There will be no significant difference during construction or operation in emissions between the No Action and Proposed Action alternatives. Most of the heavy equipment required for construction in either alternative will be the same, including equipment such as brushers and bulldozers for the clearing and leveling of the ROW, trucks for transporting pipe, and side booms and welding trucks for pipe placement and welding. In the unlikely event of a pipeline rupture or leak, fewer MLBVs could result in more gas outflow because the pipeline mileage between valves will be greater and contain more gas. On the other hand, for a rupture or leak large enough to depressurize the pipeline and trigger valve closure, as shown in the supporting documentation and due to the special permit conditions related to use of RCVs and ASVs, the Proposed Action alternative will result in 31% less average gas outflow for the system per segment than the No Action alternative. This Page 23 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 highlights the importance of more responsive valve functionality (RCV and ASV) defined in the special permit conditions, which positively offsets larger pipeline segments due to longer MLBV spacing. The lower gas outflow also results in shorter duration of an ignited rupture and less total thermal radiation over the entire period of the rupture event than a system designed in compliance with 49 CFR Part 192. Should there be an operational requirement to evacuate a pipeline section, (i.e. for maintenance reasons), there will be an incremental increase of greenhouse gas emissions based on the Proposed Action alternative design if the gas were directly vented, due to the increased volume between MLBVs that sectionalize the line. However, for operational events, if the special permit is granted, AGDC will employ several emissions reduction strategies, such as the following examples: gas drawdown strategies, voiding the pipeline of as much gas as possible before blowdown is initiated, and use of passive blocks (e.g. stopples) to significantly limit the volume of gas released to atmosphere. AGDC’s commitment to utilize these emissions reduction strategies will mitigate or eliminate any increase in greenhouse gas or pollution emissions between the Proposed Action and No Action alternatives. Pipeline maintenance activities for both the No Action and Proposed Action alternatives will require similar equipment and personnel. This comparison will apply equally to pollutant and greenhouse emissions. A reduced number of MLBVs for the Project Action alternative will reduce the fugitive emissions sources of greenhouse gases. A detailed description of air emissions, including greenhouse gas emissions, from pipeline construction and operations are contained in FERC Resource Report 9 (Air and Noise Quality). 3. Aesthetics There will likely be a reduced aesthetics impact with the Proposed Action alternative as increased MLBV spacing will result in fewer valves and thus fewer overall pipeline facilities. 4. Biological Resources (including vegetation, wetlands, and wildlife) There will be no significant difference in impacts to vegetation, wetlands and wildlife between the between the No Action and Proposed Action alternatives. Page 24 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Based on calculations of accumulated thermal radiation dosage (function of thermal radiation intensity and time, see Attachment D - Main Line Block Valve Spacing Technical Support for more detail), MLBV spacing has no effect on piloted ignition of wooden structures for over an hour. This should correlate to similar effects on vegetation. Both of the Alaska LNG Pipeline alternatives for the consideration of this special permit application will be below ground and follow the same route. Fewer valves, under the Proposed Action alternative, may result in slightly less disturbance of or impact to biological resources on the right of way. FERC Resource Report 3 (Fish, Wildlife and Vegetation) contains descriptions of vegetation and wildlife resources, and potential impacts associated with the Alaska LNG Pipeline route. FERC Resource Report 2 contains a detailed analysis of wetlands affected by the Alaska LNG Pipeline route and mitigation of the impacts. The extent of impacts to biological resources will be similar or identical under the No Action and Proposed Action alternatives. 5. Resilience and Adaptation The potential effects of a changing climate on the Alaska LNG Pipeline design, construction, and operation are not expected to differ between the No Action and Proposed Action alternatives. Project design criteria incorporated consideration of a range of variable site conditions that could occur based upon historic information and future conditions. Mitigations are integrated into the design where appropriate or required for facility integrity and safe operations. Opportunities for resilience and adaptation to potential weather effects will be considered in the design of the Alaska LNG Pipeline. For example, geothermal modeling will be used to assess potential changes in ground temperatures that could be caused by longer-term geothermal impacts of pipeline construction, operations, and changes in climate. Other resilience and adaptation design considerations for the Alaska LNG Pipeline are addressed in FERC Resource Report No. 1. FERC Resource Report 9 (Air and Noise Quality) discusses greenhouse gas emissions from the pipeline. 6. Cultural Resources There will be no difference in the effect on Cultural Resources between the No Action and Proposed Action alternatives. Construction activities have the potential to affect cultural resources. Ground-clearing activities under both Page 25 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 alternatives will be similar. FERC is conducting the Section 106 consultation process with stakeholders that will lead to the development of a Programmatic Agreement to address management and recovery of known cultural resources and any discovered during construction. The Programmatic Agreement will apply to both the No Action and Proposed Action alternatives to mitigate effects on those resources. FERC Resource Report 6 (Cultural Resources) addresses cultural resources affected and associated mitigations. 7. Environmental Justice Since both pipeline designs will be sited in the same footprint, there will be no difference in effects on environmental justice resulting from construction or operation of the pipeline between the No Action and Proposed Action alternatives. 8. Geology, Soils and Mineral Resources There will be minimal differences in the effects on geology, soils and mineral resources between the No Action and Proposed Action alternatives. Construction activities have the potential to affect soils in a localized manner with minimal effect on regional geology or mineral resources. Construction activities that could contribute to erosion include clearing and grading, excavation trenching, stockpile management, backfilling, and the development of gravel pads. AGDC manages erosion impacts with the use of erosion and sediment control measures, including: a) The use of winter construction in areas of inundated and frozen ground conditions; b) Use of settlement basins, silt fences, and other Best Management Practices (BMP) for storm water control; c) Use of engineered flow diversions and slope breakers to control water flow on slopes and around water courses; and d) Installation of trench breakers to address storm and groundwater flow through the trench backfill or during construction. Construction, operations, and maintenance activities along the pipeline right-of- way will be similar for the No Action and Proposed Action alternatives. All excavations will be conducted as authorized under the applicable ROW authorization. As the land management agencies responsible for lands along the pipeline route, ROW permits will be issued by the Bureau of Land Management Page 26 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 and/or the Alaska Department of Natural Resources. All excavations and other applicable activities will be permitted through the appropriate Federal and state agencies for both alternatives. Both alternatives will have similar impacts on soil resources. FERC Resource Report 7 (Soils), contains a more detailed discussion of impacts to soils and erosion resulting from the pipeline construction and the potential mitigation measures to address those impacts. FERC also has a standard Upland Erosion Control, Revegetation and Maintenance Plan, to which AGDC has proposed alternative measures that will be subject to FERC approval. 9. Indian Trust Assets No Indian Trust Assets or Native allotments are located within the pipeline route. 10. Land Use, Subsistence, and Recreation There will be minimal difference in the effect on land use, subsistence, and recreation between the No Action and Proposed Action alternatives. During construction, land use in the form of subsistence activities and recreation for both alternatives could be altered in the immediate vicinity of the construction ROW. The pipeline’s remote location combined with the relatively small width of the ROW will generally limit the extent of displacement by users to the active construction zones. Construction activities will be timed to avoid potential use conflicts with portions of the trail used during the annual Iditarod sled-dog race. After construction, the ROW will be graded and revegetated to a stable condition in accordance with the FERC approved Alaska LNG Upland Erosion Control, Revegetation and Maintenance Plan; Alaska LNG Wetland & Waterbody Construction & Mitigation Procedures; and the associated Alaska LNG Project Restoration Plan. No long-term linear access along the pipeline alignment is proposed. Crossing of the ROW perpendicular to the pipeline is expected but use of the ROW itself as any type of access road is not proposed and in fact will be discouraged. However, under either alternative, PHMSA regulations will require that the pipeline ROW is brushed to prevent the growth of large vegetation over and around the pipeline to maintain a clearly defined ROW. As shown in the supporting documentation in Attachment D - Main Line Block Valve Spacing Technical Support, in the unlikely event of a rupture, the special permit conditions require use of RCVs and ASVs, which will result in 31% less average gas outflow from the system per segment than strict compliance with 49 Page 27 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 CFR Part 192. More responsive valve functionality (RCV and ASV) defined in the special permit conditions will positively offset larger pipeline segments due to longer MLBV spacing. The lower gas outflow resulting from more responsive valve functionality will result in shorter duration of an ignited rupture and less total thermal radiation than a system designed in full compliance with 49 CFR Part 192. FERC Resource Report 8 (Land Use, Recreation and Aesthetics) considers potential effects to land use and recreation activities. FERC Resource Report 5 (Socioeconomics) considers potential impacts to subsistence. 11. Noise During normal operations, there will be no difference in noise impacts between the two alternatives. The difference in noise impacts during pipeline blow down events should also be minimal. 12. Water Resources There will be no difference in impacts to water resources between the No Action and the Proposed Action alternatives. For both alternatives, stabilization techniques, including gravel blankets, riprap, gabions, or geosynthetics, will be used to stabilize the channel bed and stream banks at stream crossings. Watercourse crossing methods for each watercourse crossing are the same for both alternatives. Most rivers and streams along the pipeline route will be crossed by an open-cut method during winter months. During these months, the flows of rivers and streams are lowest, and disturbance of the channel and stream bank can be minimized. Burial depths for crossings have been based on site specific calculations to avoid the potential for scour. FERC Resource Report 2 (Water Use and Quality) contains a detailed discussion regarding the management of water during construction and operation of the pipeline, as well as impacts to ground, surface water flow and quality resulting from the construction and operation of the pipeline. c. Describe safety protections provided by the proposed special permit conditions. Several factors were taken into consideration. First, the Alaska LNG Pipeline route has been characterized for location of dwellings and structures in accordance with 49 CFR 192.5. Ninety-nine percent of the pipeline route is in Class 1 location, which is defined as having 10 or fewer buildings intended for human occupancy located within 220 yards on either side of any continuous 1-Page 28 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 mile length of pipeline. Route characterization has also determined that there are more than 700 miles of pipeline route crossing areas with no inhabited dwellings. Table 2 – Identified Sites and Structures within the Mainline PIR adjacent to Class 1 locations contains a list of mile posts where there are identified sites and structures that potentially could have human occupancy within 220 yards of the ROW. Given the geographic remoteness, robust size and grade of line pipe, unlikelihood of internal corrosion, and monitoring conditions imposed by the special permit, there is an extremely low probability that the pipeline will rupture. The proposed special permit conditions, which are summarized in Section VII, result in less time between rupture and valve actuation, improved valve monitoring, and a resulting smaller quantity of natural gas released in the event of failure, and require more robust pipe to be placed in proximity to key infrastructure (e.g. key bridges identified by Alaska Department of Transportation & Public Facilities (ADOT&PF)). d. Explain the basis for the particular set of alternative mitigation measures used in the proposed special permit conditions. Explain whether the measures will ensure that a level of safety and environmental protection equivalent to compliance with existing regulations is maintained. The basis for the mitigation measures is the Alaska LNG Pipeline engineering analysis, combined with consultation with PHMSA and ADOT&PF. More details on these measures is provided in Section VIII. These measures help ensure that no significant environmental or human safety impact will result from increasing the MLBV spacing. The use of RCVs and ASVs allow for faster valve closure than will be achieved with valves meeting the minimum standard for strict 49 CFR Part 192 compliance. The use of more responsive valves mitigates the longer distances between valves proposed by the special permit. e. Discuss how the special permit would affect the risk or consequences of a pipeline leak, rupture or failure (positive, negative, or none). This would include how the special permits preventative and mitigation measures (conditions) would affect the consequences and socioeconomic impacts of a pipeline leak, rupture or failure. As highlighted in the Project’s engineering and analysis as summarized in Attachment D - Main Line Block Valve Spacing Technical Support document, injuries and fatalities on gas transmission pipelines generally occur during the first 30 seconds after gas has been released from a pipeline. 11 In the event of an Alaska LNG Pipeline failure, there will be no difference in the volume of product released or in the likelihood of ignition in the first 17.5 minutes. The ASVs and RCVs will decrease the total product released and, therefore, the total thermal radiation. Page 29 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 f. Discuss any effects on pipeline longevity and reliability such as life-cycle and periodic maintenance including integrity management. Discuss any technical innovations as well. The Proposed Alternative will result in reduced MLBV maintenance, with no overall impacts on pipeline longevity and reliability. Implementation of the special permit conditions will require enhanced monitoring of RCVs, ASVs, and more stringent valve actuation criteria than is normally required by 49 CFR Part 192. g. Discuss how the special permit would impact human safety. There will be no additional impact on human safety resulting from granting of the special permit. h. Discuss whether the special permit would affect land use planning. The special permit will not change land use planning processes. The ROW authorization requirements, and other land use planning notification processes will be the same with either the No Action or Proposed Action alternative. The Proposed Action alternative will require fewer valves along the ROW. i. Discuss any pipeline facility, public infrastructure, safety impacts and/or environmental impacts associated with implementing the special permit. Discuss how any environmentally sensitive areas could be impacted. Implementation of the special permit will reduce the number of MLBVs and associated valve station footprints by about half. The footprint at remote MLBVs (ASVs or RCVs) extends beyond the normal permanent ROW, affecting approximately 0.07 acres. The special permit will reduce the number of MLBVs by 22, resulting in approximately 1.6 acres less disturbance. The special permit will require a more robust pipeline design within proximity of key bridges resulting in a positive impact to public infrastructure. There is no impact to environmentally sensitive areas. V. Response to Public Comments Placed on Docket PHMSA-2017-0045 PHMSA published a Notice of Availability in the Federal Register on May 28, 2019 for four (4) special permit requests for the line pipe of the Alaska LNG Pipeline. (84 FR 24594, Docket Nos.: PHMSA-2017-0046, Usage of 3LPE Coating; PHMSA-2017-0044, Usage of Strain Based Design; PHMSA-2017-0045, Alternative Mainline Block Valve Spacing; and PHMSA-2017-0047, Usage of Crack Arrestor Spacing at www.Regulations.gov). PHMSA requested comment on the special permit applications, the draft permit conditions, and the draft environmental analyses. The public notice comment period ended on July 29, 2019, with all comments received through July 29, 2019, being reviewed and considered. PHMSA Page 30 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 received a public comment concerning usage of fossil fuels, the building of the Alaska LNG Pipeline, and the building of a liquified natural gas (LNG) facility. PHMSA does not have siting authority over pipeline facilities. The public comment received did not submit concerns directed towards the special permit, the environmental assessment, or the special permit conditions, which were the issues within PHMSA’s decision making authority and the intent of the public notice. VI. Finding of No Significant Impact Although technically distinct, PHMSA considered the combined impacts and safety risks associated with the issuance and implementation of the special permits, including the special permit conditions, for usage of three-layer polyethylene (3LPE) coating, usage of strain based design, alternative spacing of mainline block valves, and alternative spacing of crack arrestors. PHMSA finds that special permits and associated special permit conditions will not impose a significant impact on the human environment. The special permit conditions are designed to be consistent with pipeline safety and to ensure the same or a greater level of safety as will be achieved if the pipeline were designed, constructed, operated, and maintained in full compliance with 49 CFR Part 192. VII. Consultation and Coordination a. Please list the name, title and company of any person involved in the preparation of this document. • PHMSA –Amelia Samaras (Senior Attorney), Steve Nanney (Engineer), Joshua Johnson (Engineer) • Alaska Gasline Development Corporation – Frank Richards (Senior Vice President) • Alaska LNG LLC – Rick Noecker (PHMSA Filing Coordinator), Mario Macia (Pipeline Technology Lead), Norm Scott (ERL Advisor) • Michael Baker International – Keith Meyer (Senior Pipeline Advisor), Paul Carson (Corporate Pipeline Engineer) b. Please provide names and contact information for any person or entity you know will be impacted by the special permit. PHMSA may perform appropriate public scoping. The applicant’s assistance in identifying these parties will speed the process considerably. Adjacent landowners/land managers potentially impacted: Cook Inlet Region, Inc. Jason Brune Sr. Director, Land and Resources Page 31 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 PO Box 93330 Anchorage, AK 99509 (907) 263-5104 Bureau of Land Management Earle Williams Chief, Branch of realty and Conveyance Services BLM Alaska State Office 222 West 7th Avenue #13 Anchorage, AK 99513-7504 (907) 271-5762 Alaska Department of Natural Resources Tom Stokes State Pipeline Coordinator 3651 Penland Parkway Anchorage, AK 99508 (907) 269-6419 Alaska Department of Transportation & Public Facilities Joe Kemp Gasline Liaison 2301 Peger Road Fairbanks, AK 99709 (907) 451-5497 Brooke Merrell Transportation Planner United States National Park Service, Alaska Regional Office 240 W 5th Ave Anchorage, AK 99501 (907) 644-3397 Don Striker Superintendent Denali National Park and Preserve PO Box 9 Denali Park, AK 99755-0009 (907) 683-9532 c. If you have engaged in any stakeholder or public communication regarding this request, please include information regarding this contact. Alaska LNG has been active in stakeholder engagement throughout Alaska. As well, Federal, state and local agency engagement is ongoing. In 2015 and 2016,Page 32 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Alaska LNG Pipeline held one-on-one as well as multiagency engagement meetings to cover pipeline design construction and routing. Additionally, there have been over 20 engagement meetings between Alaska LNG and PHMSA. The MLBV spacing special permit was a topic of discussion at multiple meetings. Additionally, an overview of this special permit was provided at a joint meeting with PHMSA and FERC on April 19, 2016. PHMSA has participated in scoping and public outreach lead by FERC related to the Alaska LNG Pipeline FERC Resource Reports. Details of the public outreach, which included both members of tribal entities and the general public, are provided in Sections 1.9 and Appendix D of the FERC Resource Report 1. VIII. Bibliography Alaska LNG Project. 2017a. FERC Resource Report No. 1 (General Project Description)10 Alaska LNG Project. 2017b. FERC Resource Report No. 2 (Water Use and Quality) Alaska LNG Project. 2017c. FERC Resource Report No. 3 (Fish, Wildlife, and Vegetation) Alaska LNG Project. 2017d. FERC Resource Report No. 4 (Cultural Resources) Alaska LNG Project. 2017e. FERC Resource Report No. 5 (Socioeconomics) Alaska LNG Project. 2017f. FERC Resource Report No. 6 (Geological Resources) Alaska LNG Project. 2017g. FERC Resource Report No. 7 (Soils) Alaska LNG Project. 2017h. FERC Resource Report No. 8 (Land Use, Recreation, and Aesthetics) Alaska LNG Project. 2017i. FERC Resource Report No. 9 (Air and Noise Quality) Alaska LNG Project. 2017j. FERC Resource Report No. 10 (Alternatives) Alaska LNG Project. 2017k. FERC Resource Report No. 11 (Reliability and Safety) Eiber, R., and Kiefner, J. 2010. Review of Safety Considerations for Natural Gas Pipeline Block Valve Spacing. ASME Standards Technology, LLC. Columbus. July. IX. Conditions: Example of what special permit (SP) conditions address 10 Alaska LNG Project FERC Resource Reports are available for review at: https://alaska-lng.com/regulatory- process/ferc-application-exhibits/resource-reports/. Page 33 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 a) Spacing will only be increased beyond 49 CFR Part 192 limits in Class 1 locations. The maximum spacing north of Fairbanks will be 50 miles, while the maximum spacing south of Fairbanks will be 30 miles. b) MLBVs will be placed as close as reasonably possible to the start and end mileposts in Class 2, 3 and 4 locations and will not exceed the spacing requirements of 49 CFR 192.179(a). c) An engineering analysis must be performed to confirm that the number and location of MLBVs proposed in the special permit account for the criteria in Section 846.1.1 of ASME B31.8. d) Enhanced valve closure criteria that will initiate valve closure when either of the following conditions occurs: o Pressure drops to 75% of the operating pressure at the sectionalizing mainline valve based upon maximum flow model gradients for the upstream compressor station discharge at MOP (2050 psig). In addition, ASV set points shall not be less than that required to actuate the valve before a downstream RCV actuates. o Decrease in operating pressure in fifteen (15) minutes is greater than 10%. e) Real time monitoring at the Pipeline Control Center of MLBVs located at compressor, heater and metering stations (RCVs). f) In high consequence areas (49 CFR 192.905) in Class 1 and 2 locations, sectionalizing block valve spacing must comply with the requirements of 49 CFR 192.179(a). g) Emergency closure drills simulating shutting down of a randomly selected section of transmission line will be performed at least once in a calendar year, but within an interval not to exceed 15 months. The operator may conduct a table-top emergency closure drill to meet this requirement for no more than two out of each three calendar years. The operator will conduct a site-specific emergency closure drill at a field site at least once in every three calendar years. h) Pipeline control room operators will immediately and directly notify the 911 emergency call center(s) for the affected communities and jurisdictions, when a rupture is indicated. i) Valve position and operational status of all RCVs affected by a leak/rupture event until positive isolation of the effected segment is confirmed will be continually monitored by pipeline control center operators. j) An emergency response plan will be developed: Page 34 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 o identifying the appropriate public safety access point (911 emergency call center), fire, police, and other public officials to be notified; o identifying responsibility, resources, jurisdictional area, and emergency contact telephone numbers for both local and out-of-area calls of each government organization that may respond to a pipeline emergency; and o establishing protocols for informing the officials about the operator's ability to respond to the pipeline emergency and means of communication. k) Detailed maintenance procedures will be developed for all MLBV and operators installed on the Mainline. These procedures will follow manufacturer recommendations and industry practice. l) Detailed maintenance procedures will be developed for all pressure sensing equipment installed with the MLBV. These procedures will follow manufacturer recommendations and industry practice. m) A training program will be implemented for appropriate operating personnel to ensure they have a thorough knowledge of, and are qualified to implement, the emergency response plan procedures. Page 35 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Table 3 – Identified Sites and Structures within the Mainline PIR adjacent to Class 1 Locations [See MLBV Locations in Table 1] Milepost Offset Distance (feet) Direction Class Location Feature Comment 80.66 693 Left 1 Structure 174.78 363 Left 1 Structure DOT/PF Garage 174.85 288 Left 1 Structure 174.86 296 Left 1 Structure 174.86 335 Left 1 Structure 174.87 542 Left 1 Structure 174.90 452 Left 1 Structure 175.12 571 Left 1 Structure 236.12 1450 Left 1 Structure 236.12 494 Left 1 Structure 236.12 542 Left 1 Structure 236.12 547 Left 1 Structure 236.68 867 Left 1 Identified Site Marion Creek Campground 241.06 1364 Right 1 Structure 310.41 760 Right 1 Structure 310.42 821 Right 1 Structure 352.79 603 Left 1 Associated Structure to Identified Site Hotspot Cafe 352.80 638 Left 1 Identified Site Hotspot Cafe 358.41 619 Right 1 Structure 438.83 215 Left 1 Structure 438.96 1324 Left 1 Structure 438.98 966 Left 1 Structure 439.14 938 Left 1 Structure 439.20 514 Left 1 Structure 439.20 872 Left 1 Structure 439.21 1191 Left 1 Structure 439.26 607 Left 1 Structure 439.27 1203 Left 1 Structure 439.31 971 Left 1 Structure 469.64 589 Left 1 Structure 469.69 983 Left 1 Structure 469.70 1014 Left 1 Structure 469.70 927 Left 1 Structure 470.69 1194 Right 1 Structure 470.69 833 Right 1 Structure 470.69 750 Right 1 Structure 470.71 302 Right 1 Structure 470.71 412 Right 1 Structure 471.40 1025 Right 1 Structure 471.42 701 Right 1 Structure 471.86 75 Left 1 Structure 471.95 352 Right 1 Structure Page 36 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Table 3 – Identified Sites and Structures within the Mainline PIR adjacent to Class 1 Locations [See MLBV Locations in Table 1] Milepost Offset Distance (feet) Direction Class Location Feature Comment 471.96 252 Left 1 Structure 471.97 662 Right 1 Structure 471.97 418 Left 1 Structure 471.97 399 Right 1 Structure 471.97 208 Left 1 Structure 471.98 242 Left 1 Structure 472.04 535 Right 1 Structure 472.28 754 Right 1 Structure 472.33 564 Right 1 Structure 472.34 651 Right 1 Structure 472.35 577 Right 1 Structure 472.37 597 Right 1 Structure 472.38 710 Right 1 Structure 497.83 1396 Right 1 Structure 497.84 1210 Right 1 Structure 497.88 1447 Right 1 Structure 498.76 1157 Right 1 Structure 501.37 941 Right 1 Structure 502.73 1385 Right 1 Structure 504.24 1396 Right 1 Structure 504.87 269 Left 1 Structure 505.03 1379 Left 1 Structure 506.03 1338 Right 1 Structure 511.07 1191 Right 1 Structure 511.86 758 Right 1 Structure 511.86 939 Right 1 Structure 512.89 1057 Right 1 Structure 513.05 760 Left 1 Structure 513.06 1065 Left 1 Structure 513.06 307 Left 1 Structure 513.09 366 Left 1 Structure 513.09 963 Left 1 Structure 513.09 857 Left 1 Structure 513.10 1311 Left 1 Structure 513.16 1161 Left 1 Structure 513.17 682 Left 1 Structure 513.23 1071 Left 1 Structure 514.79 1039 Left 1 Structure 514.82 1232 Left 1 Structure 523.45 585 Right 1 Structure 526.82 359 Left 1 Structure 529.54 497 Right 1 Structure 529.80 934 Left 1 Identified Site Denali RV Park and Motel 536.66 1457 Right 1 Structure Denali Salmon Bake Cabins ‐ Single cabin 536.66 1465 Right 1 Structure Denali Salmon Bake Cabins ‐ Single cabin 536.66 1420 Right 1 Structure Denali Salmon Bake Cabins ‐ Single cabin Page 37 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Table 3 – Identified Sites and Structures within the Mainline PIR adjacent to Class 1 Locations [See MLBV Locations in Table 1] Milepost Offset Distance (feet) Direction Class Location Feature Comment 536.66 1345 Right 1 Structure Denali Salmon Bake Cabins ‐ Single cabin 536.66 1346 Right 1 Structure Denali Salmon Bake Cabins ‐ Single cabin 536.66 1409 Right 1 Structure Denali Salmon Bake Cabins ‐ Single cabin 536.68 1409 Right 1 Identified Site Alpine Glow Restaurant 536.70 1016 Right 1 Structure 536.71 1349 Right 1 Structure Denali Bluffs Hotel ‐ Single cabin 536.71 1359 Right 1 Structure Denali Bluffs Hotel ‐ Single cabin 536.72 1266 Right 1 Structure Denali Bluffs Hotel ‐ Single cabin 536.72 1378 Right 1 Structure Denali Bluffs Hotel ‐ Single cabin 536.72 1288 Right 1 Structure Denali Bluffs Hotel ‐ Single cabin 536.73 1393 Right 1 Structure Denali Bluffs Hotel ‐ Single cabin 536.73 1313 Right 1 Structure Denali Bluffs Hotel ‐ Single cabin 536.73 1401 Right 1 Structure Denali Bluffs Hotel ‐ Single cabin 536.74 1422 Right 1 Structure Denali Bluffs Hotel ‐ Single cabin 536.75 1437 Right 1 Structure Denali Bluffs Hotel ‐ Single cabin 536.81 1099 Right 1 Identified Site Grand Denali Lodge 536.81 993 Right 1 Associated Structure to Identified Site Grand Denali Lodge 536.85 1171 Right 1 Associated Structure to Identified Site Grand Denali Lodge 537.10 1437 Right 1 Structure 537.31 1344 Right 1 Associated Structure to Identified Site ERA Helicopters 537.32 1312 Right 1 Identified Site ERA Helicopters 551.32 1224 Right 1 Structure 551.34 1457 Right 1 Structure 551.39 1203 Right 1 Structure 551.43 1357 Right 1 Structure 551.65 1376 Right 1 Identified Site McKinley Creekside Cabins 551.65 1442 Right 1 Associated Structure to Identified Site McKinley Creekside Cabins 551.65 1258 Right 1 Associated Structure to Identified Site McKinley Creekside Cabins 551.65 1435 Right 1 Associated Structure to Identified Site McKinley Creekside Cabins 551.65 957 Right 1 Associated Structure to Identified Site McKinley Creekside Cabins 551.66 1404 Right 1 Associated Structure to Identified Site Denali Perch Resort 551.66 1430 Right 1 Associated Structure to Identified Site Denali Perch Resort 551.66 1459 Right 1 Associated Structure to Identified Site Denali Perch Resort 551.86 1335 Right 1 Associated Structure to Identified Site Denali Perch Resort 551.87 1025 Right 1 Associated Structure to Identified Site Denali Perch Resort 556.31 542 Right 1 Structure 556.46 587 Right 1 Structure 556.48 332 Right 1 Structure 556.51 177 Right 1 Structure 559.85 1380 Left 1 Structure Power Plant 560.07 554 Right 1 Structure Denali Fly Fishing Guides 560.15 845 Left 1 Structure 564.83 809 Right 1 Structure 566.33 1417 Right 1 Identified Site Local Gov't building 566.35 607 Right 1 Identified Site DOT/PF Cantwell Station Page 38 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Table 3 – Identified Sites and Structures within the Mainline PIR adjacent to Class 1 Locations [See MLBV Locations in Table 1] Milepost Offset Distance (feet) Direction Class Location Feature Comment 566.48 651 Right 1 Structure 566.50 511 Left 1 Structure 566.51 473 Right 1 Structure 566.69 394 Right 1 Structure 566.69 604 Right 1 Structure 566.74 654 Right 1 Structure 566.79 1043 Right 1 Structure 566.79 1361 Right 1 Structure 566.79 1017 Right 1 Structure 588.74 660 Right 1 Structure 588.74 810 Right 1 Structure 588.75 755 Right 1 Structure 588.77 910 Right 1 Structure 588.78 337 Right 1 Structure 608.38 1389 Left 1 Structure 608.39 1371 Left 1 Structure 608.39 1435 Left 1 Structure 608.45 1357 Left 1 Structure 608.64 345 Left 1 Structure 608.67 212 Right 1 Structure 608.69 126 Left 1 Structure 615.43 886 Left 1 Structure 615.44 956 Left 1 Structure 630.42 1125 Left 1 Identified Site Byers Lake Campground (73 units) 634.11 1449 Right 1 Identified Site Trapper Creek Pizza Pub 634.13 1430 Right 1 Associated Structure to Identified Site Trapper Creek Pizza Pub 634.14 729 Right 1 Structure 634.17 523 Right 1 Structure 636.20 1244 Left 1 Structure 650.39 1132 Right 1 Structure 650.41 1379 Left 1 Structure 657.69 982 Left 1 Structure 658.27 533 Left 1 Structure 662.53 1388 Left 1 Structure 664.35 1282 Left 1 Structure 664.66 1345 Left 1 Structure 664.67 1008 Left 1 Structure 664.68 581 Left 1 Structure 664.74 1016 Right 1 Structure 664.78 385 Right 1 Structure 664.83 979 Right 1 Structure 665.03 476 Right 1 Structure 665.62 981 Left 1 Structure 665.70 1432 Left 1 Structure 665.70 1318 Left 1 Structure 665.70 1239 Left 1 Structure Page 39 of 40 <<>> ALASKA LNG PIPELINE MLBV SPACING SPECIAL PERMIT: ATTACHMENT C DATE: AUGUST 1, 2019 Table 3 – Identified Sites and Structures within the Mainline PIR adjacent to Class 1 Locations [See MLBV Locations in Table 1] Milepost Offset Distance (feet) Direction Class Location Feature Comment 665.70 767 Left 1 Structure 665.70 1055 Left 1 Structure 665.71 1446 Left 1 Structure 665.71 726 Left 1 Structure 665.81 1342 Left 1 Structure 665.88 1062 Left 1 Structure 727.78 171 Right 1 Structure 764.53 1206 Right 1 Structure 764.54 1313 Right 1 Structure 764.62 870 Left 1 Structure 764.76 935 Left 1 Structure 764.91 1412 Left 1 Structure 764.92 1245 Left 1 Structure 764.94 648 Left 1 Structure 765.03 712 Left 1 Structure 797.12 1254 Left 1 Structure 797.13 487 Left 1 Structure 797.14 1092 Left 1 Structure 797.20 204 Right 1 Structure 797.57 812 Left 1 Structure 798.30 1246 Right 1 Associated Structure to Identified Site Nikiski Ship Repair 798.33 1279 Right 1 Associated Structure to Identified Site Nikiski Ship Repair 798.34 1150 Right 1 Identified Site Nikiski Ship Repair 798.54 1447 Left 1 Identified Site Commercial Building 801.27 767 Left 1 Structure 801.31 1352 Left 1 Structure 803.58 966 Left 1 Structure 803.60 1038 Left 1 Structure 803.62 1135 Left 1 Structure 806.32 1030 Right 1 Structure Tesoro Kenai Refinery 806.32 895 Right 1 Structure Tesoro Kenai Refinery 806.32 1120 Right 1 Structure Tesoro Kenai Refinery 806.32 1075 Right 1 Structure Tesoro Kenai Refinery 806.32 662 Right 1 Structure Tesoro Kenai Refinery 806.32 617 Right 1 Structure Tesoro Kenai Refinery 806.33 1444 Left 1 Structure Completed by PHMSA in Washington, DC on: September 9, 2019 Page 40 of 40 ## Provenance - Official: Yes - Source: - Source ID: `phmsa-special-permits` - SHA-256: `56b42a4793f200bb1fabef0df869385cd1a804271d9c0294cc906ab5d802cfe8` - Retrieved: 2026-08-20T01:06:17.853Z - Exported: 2026-08-25T03:24:59.664Z - Document slug: `phmsa-special-permit-phmsa-2017-0045` ### Source metadata ```json { "materialSubtype": "pipeline_special_permit", "operator": "Alaska Gas Development Corporation – AGDC", "system": "Gas Transmission", "issuedOn": "2019-09-09", "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-2017-0045", "docketDocumentCount": 4, "decisionDocumentCount": 4, "decisions": [ { "id": "PHMSA-2017-0045-0009-0900006484a19d52", "regulationsGovDocumentId": "PHMSA-2017-0045-0009", "title": "2017-0045 AGDC MLBV Spacing LOD", "postedDate": "2021-02-03", "documentUrl": "https://www.regulations.gov/document/PHMSA-2017-0045-0009", "pdfUrl": "https://downloads.regulations.gov/PHMSA-2017-0045-0009/attachment_1.pdf", "pdfArtifactPath": 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"2810acc676b83e76a626d0b78a189463fbff56105eb9301ccf9157fb8059d0fd", "extractedTextPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2017-0045/phmsa-2017-0045-0009-0900006484a19d53.txt", "extractedTextSha256": "7f8a6dc01acd916adab5496aa93eef24f328747272a7b9c3edeee7841f250c25", "pageCount": 16, "extractionVersion": 2 }, { "id": "PHMSA-2017-0045-0009-0900006484a19d54", "regulationsGovDocumentId": "PHMSA-2017-0045-0009", "title": "2017-0045AGDC SP MLBV - SPAF", "postedDate": "2021-02-03", "documentUrl": "https://www.regulations.gov/document/PHMSA-2017-0045-0009", "pdfUrl": "https://downloads.regulations.gov/PHMSA-2017-0045-0009/attachment_3.pdf", "pdfArtifactPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2017-0045/phmsa-2017-0045-0009-0900006484a19d54.pdf", "pdfArtifactSha256": "6b94f88ce0b54cf5f4f11336fcc28234933c863e916a7efdab5f19d671dcae8b", "extractedTextPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2017-0045/phmsa-2017-0045-0009-0900006484a19d54.txt", "extractedTextSha256": "489ea8afcd618b0f3004ae41083b5be2a54e25f6f9e95926bcfa261be73fde69", "pageCount": 11, "extractionVersion": 2 }, { "id": "PHMSA-2017-0045-0009-0900006484a19d57", "regulationsGovDocumentId": "PHMSA-2017-0045-0009", "title": "2017-0045 - AGDC- Alaska LNG Pipeine SP MLBV4 FEA FONSI -", "postedDate": "2021-02-03", "documentUrl": "https://www.regulations.gov/document/PHMSA-2017-0045-0009", "pdfUrl": "https://downloads.regulations.gov/PHMSA-2017-0045-0009/attachment_4.pdf", "pdfArtifactPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2017-0045/phmsa-2017-0045-0009.pdf", "pdfArtifactSha256": "1373bd4bcf6e600f85aba35be30c39e43887e71e98cd7ad87ff30377e73067d2", "extractedTextPath": "data/sources/phmsa-special-permits/artifacts/phmsa-2017-0045/phmsa-2017-0045-0009.txt", "extractedTextSha256": "cd5185c15454d6bcab97c80c3d0c923e3dbbcff4b7037f750ab79ec10c53d802", "pageCount": 40, "extractionVersion": 2 } ], "citedSections": [ "192.197", "192.179", "192.5", "192.112", "192.328", "192.620", "179.6", "192.903", "192.905", "192.615", "192.63", "192.745", "194.09", "192.631", "192.6", "192.605", "190.341", "190.34", "179.9", "192.111", "192.327", "174.78", "174.85", "174.86", "174.87", "174.90", "175.12" ], "caveat": "The issued-permit index establishes issuance, not current validity or applicability to facilities beyond those covered by the permit. Read the official decision and conditions.", "jurisdiction": "US", "operatorName": "Alaska Gas Development Corporation – AGDC" } ```