{"operation":"document","citation":"PHMSA-2006-26533","title":"Gulf South Pipeline Co LP — Pipeline Special Permit","source_type":"permit","agency":"Pipeline and Hazardous Materials Safety Administration","status":"current","official":true,"published_on":"2007-08-24","effective_on":"2007-08-24","summary":"PHMSA-2006-26533, issued 2007-08-24 for Gulf South Pipeline Co LP's gas transmission system.","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2006-26533.json","markdown":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2006-26533.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-special-permit-phmsa-2006-26533","source_url":"https://www.regulations.gov/docket/PHMSA-2006-26533","body":"PHMSA pipeline special permit PHMSA-2006-26533. Operator: Gulf South Pipeline Co LP. System: Gas Transmission. Issue date: 2007-08-24.\n\n<<<PAGE 1>>>\n\nU.S. Department\nof Transportation\nAdministrator\nWashington, DC 20590\n1200 New Jersey Ave. SE\nPipeline and Hazardous\nMaterials Safety\nAdministration\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nAUG 2 4 2007\nMr. Walt Bennett\nVice President - Operations\nGulf South Pipeline Company, LP\n20 East Greenway Plaza, Suite 900\nHouston, Texas 77046\nDocket No. PHMSA-2006-26533\nDear Mr. Bennett:\nOn November 16, 2006 you wrote to the Pipeline and Hazardous Materials Safety\nAdministration (PHMSA) requesting a waiver of compliance from PHMSA's pipeline safety\nregulations in 49 CFR 192.111, 192.201 and 192.619 for the Gulf South Pipeline Company\n(GSP) East Texas to Mississippi Expansion Project. The regulations establish the design factor\nfor steel pipe and the required capacity of pressure relieving and limiting stations. PHMSA\ndetermined that a waiver of 192.619 is unnecessary.\nThe PHMSA is granting this waiver through a special permit, which is enclosed with this letter.\nThis special permit allows GSP to design, construct and operate the pipeline with design factors\nof 0.80 in Class 1 locations, 0.67 in Class 2 locations and 0.56 in Class 3 locations in\naccordance with the conditions specified in the special permit. The special permit provides\nsome relief from the Federal pipeline safety regulations for GSP while ensuring that pipeline\nsafety is not compromised.\nMy staff would be pleased to discuss this special permit or any other regulatory matter with\nyou. Florence Hamn, Director of Regulations (202-366-4595), would be pleased to assist you.\nSincerely,\nBuriese\nJeffrey D. Wiese\nActing Associate Administrator\nfor Pipeline Safety\nEnclosure (Special Permit)\n\n<<<PAGE 2>>>\n\nAdministrator\n400 Seventh Street, S.W.\nWashington, D.C. 20590\nPipeline and Hazardous\nMaterials Safety Administration\nDEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION (PHMSA)\nSPECIAL PERMIT\nDocket Number:\nPHMSA-2006-26533\nPipeline Operator:\nGulf South Pipeline Company, LP\nDate Requested:\nNovember 16, 2006\nCode Section(s):\n49 CFR 192.111 and 192.201\nGrant of Special Permit:\nThe Pipeline and Hazardous Materials Safety Administration (PHMSA) grants this special\npermit to Gulf South Pipeline Company, LP (GSP). The Federal pipeline safety regulations in\n49 CFR 192.111 limit the design factors and operating stress levels for natural gas transmission\nsteel pipelines to 72 percent of the specified minimum yield strength (SMYS) in class 1\nlocations, 60 percent SMYS in class 2 locations and 50 SMYS percent in class 3 locations.\nThis special permit allows GSP to design, construct and operate the East Texas to Mississippi\nExpansion Project pipeline using design factors and operating stress levels of up to 80 percent\nSMYS in class 1 locations, 67 percent SMYS in class 2 locations and 56 percent SMYS in class\n3 locations. This special permit also allows GSP to operate up to 67 percent SMYS at class 1\nlocation road crossings and up to 56 percent SMYS at class 2 location road crossings. This\nspecial permit covers approximately 255.4 miles of 42-inch pipe and 3 miles of 36-inch pipe in\nclass 1 locations, 3.5 miles of 42-inch pipe in class 2 locations and 468 feet of 42-inch pipe in\nclass 3 locations.\nThe PHMSA grants this special permit based on the findings set forth in the \"Special Permit\nAnalysis and Findings\" document, which can be read in its entirety in Docket # PHMSA-2007-\n26533 in the DOT's Docket Management System (DMS) located on the internet at\nhttp://dms.dot.gov.\n\n<<<PAGE 3>>>\n\n2\nBecause the proposed operating stress level of 80 percent SMYS is higher than the upper limit\nof the required overpressure protection under existing regulations [1.e., ten percent over\nmaximum allowable operating pressure (MAOP) or 75 percent SMYS], this special permit also\nallows GSP to establish the overpressure protection limit up to 104 percent of the pipeline\nMAOP in Class 1 locations, which corresponds to 83.2 percent SMYS. The pipeline\noverpressure criteria in Class 2 and 3 locations must conform to existing regulations. The\npipeline MAOP will be 1,333 psig.\nFor the purpose of this special permit, the \"special permit area\" means the area consisting of\nthe entire pipeline right-of-way for those segments of the pipeline that will operate above 72\npercent of SMYS in Class 1 locations, 60 percent SMYS in Class 2 locations and 50 percent\nSMYS in Class 3 locations. This special permit is subject to the conditions set forth below.\nConditions:\nThe grant of this special permit is subject to the following conditions:\n1) Steel Properties: The skelp/plate must be micro alloyed, fine grain, fully killed steel with\ncalcium treatment and continuous casting.\n2)\nManufacturing Standards: The pipe must be manufactured according to American\nPetroleum Institute Specification 5L, Specification for Line Pipe (API SL), product\nspecification level 2 (PSL 2), supplementary requirements (SR) for maximum operating\npressures and minimum operating temperatures. Pipe carbon equivalents must be at or\nbelow 0.23 percent based on the material chemistry parameter (Pcm) formula.\nFracture Control: API 5L, the American Society of Mechanical Engineers B31.8\nStandard (ASME B31.8) and other specifications and standards address the steel pipe\ntoughness properties needed to resist crack initiation, crack propagation and to ensure\ncrack arrest during a pipeline failure caused by a fracture. GSP must institute an overall\nfracture control plan addressing steel pipe properties necessary to resist crack initiation\nand crack propagation and to arrest a fracture within eight pipe joints with a 99 percent\noccurrence probability or within five pipe joints with a 90 percent occurrence probability.\nThe plan must include acceptable Charpy Impact and Drop Weight Tear Test values,\nwhich are measures of a steel pipeline's toughness and resistance to fracture. The fracture\ncontrol plan, which must be submitted to PHMSA headquarters, must be in accordance\nwith API 5L, Appendix F and must include the following tests:\n\n<<<PAGE 4>>>\n\na) SR SA - Fracture Toughness Testing for Shear Area: Test results must indicate at\nleast 85 percent minimum average shear area for all X- 70 heats and 80 percent\nminimum shear area for all X- 80 heats with a minimum result of 80 percent shear\narea for any single test. The test results must also ensure a ductile fracture and arrest;\nb) SR 5B - Fracture Toughness Testing for Absorbed Energy; and\nc) SR 6 - Fracture Toughness Testing by Drop Weight Tear Test: Test results must be\nat least 80 percent of the average shear area for all heats with a minimum result of 60\npercent of the shear area for any single test. The test results must also ensure a ductile\nfracture and arrest.\nThe above fracture initiation, propagation and arrest plan must account for the entire\nrange of pipeline operating temperatures, pressures and gas compositions planned for the\npipeline diameter, grade and operating stress levels, including maximum pressures and\nminimum temperatures for shut-in conditions associated with the special permit area.\nWhere the use of stress factors, pipe grade, operating temperatures and gas composition\nmake fracture toughness calculations non-conservative, correction factors must be used.\nIf the fracture control plan for the pipe in the special permit area does not meet these\nspecifications, GSP must submit to PHMSA headquarters an alternative plan providing an\nacceptable method to resist crack initiation, crack propagation and to arrest ductile\nfractures in the special permit area.\n4)\nSteel Plate Quality Control: The steel mill and/or pipe rolling mill must incorporate a\ncomprehensive plate/coil mill and pipe mill inspection program to check for defects and\ninclusions that could affect the pipe quality. This program must include a plate or rolled\npipe (body and all ends) ultrasonic testing (UT) inspection program per ASTM A578 to\ncheck for imperfections such as laminations. An inspection protocol for centerline\nsegregation evaluation using a test method referred to as slab macro-etching must be\nemployed to check for inclusions that may form as the steel plate cools after it has been\ncast. A minimum of one macro-etch or a suitable alternative test must be performed from\nthe first or second heat (manufacturing run) of each sequence (approximately 4 heats) and\ngraded on the Mannesmann scale or equivalent. Test results with a Mannesmann scale\nrating of one or two out of a possible four or five scale are acceptable.\n\n<<<PAGE 5>>>\n\n4\nPipe Seam Quality Control: A quality assurance program must be instituted for pipe weld\nseams. The pipe weld seam tests must meet the minimum requirements for tensile\nstrength in API 5L for the appropriate pipe grade properties. A pipe weld seam hardness\ntest using the Vickers hardness testing of a cross-section from the weld seam must be\nperformed on one length of pipe from each heat. The maximum weld seam and heat\naffected zone hardness must be a maximum of 280 Vickers hardness (Hv10). The\nhardness tests must include a minimum of three readings for each heat affected zone,\nthree readings in the weld metal and two readings in each section of pipe base metal for a\ntotal of 13 readings. The pipe weld seam must be 100 percent UT inspected after\nexpansion and hydrostatic testing per APL 5L.\nPuncture Resistance: Steel pipe must be puncture resistant to an excavator weighing up\nto 65 tons. Puncture resistance will be calculated based on industry established\ncalculations such as the Pipeline Research Council International's \"Reliability Based\nPrevention of Mechanical Damage to Pipelines\" calculation method.\n7)\nMill Hydrostatic Test: The pipe must be subjected to a mill hydrostatic test pressure of\n94 percent SMYS or greater for ten seconds.\n8)\nPipe Coating: The application of a corrosion resistant coating to the steel pipe must be\nsubject to a coating application quality control program. The program must address pipe\nsurface cleanliness standards, blast cleaning, application temperature control, adhesion,\ncathodic disbondment, moisture permeation, bending, minimum coating thickness,\ncoating imperfections and coating repair.\nField Coating: A field girth weld joint coating application specification and quality\nstandards to ensure pipe surface cleanliness, application temperature control, adhesion\nquality, cathodic disbondment, moisture permeation, bending, minimum coating\nthickness, holiday detection and repair quality must be implemented in field conditions.\nField joint coatings must be non-shielding to cathodic protection (CP). Field coating\napplicators must use valid coating procedures and be trained to use these procedures.\n10)\nCoatings for Trenchless Installation: Coatings used for directional bore, slick bore and\nother trenchless installation methods must resist abrasions and other damages that may\noccur due to rocks and other obstructions encountered in this installation technique.\n\n<<<PAGE 6>>>\n\n5\n11) Bends Quality: Certification records of factory induction bends and/or factory weld\nbends must be obtained and retained. All bends, flanges and fittings must have carbon\nequivalents (CE) below 0.42 or a pre-heat procedure must be applied prior to welding for\nCE above 0.42.\n12) Fittings: All pressure rated fittings and components (including flanges, valves, gaskets,\npressure vessels and compressors) must be rated for a pressure rating commensurate with\nthe MAOP and class location of the pipeline. Designed fittings (including tees, elbows\nand caps) must have the same design factors as the adjacent pipe class location.\n13) Design Factor - Pipelines: Pipe installed under this special permit in Class 1, 2 and 3\nlocations may use design factors of 0.80, 0.67 and 0.56 respectively. Road crossings in\nClass 1 and 2 areas may use design factors of 0.67 and 0.56 respectively.\n14) Design Factor - Stations: The following compressor and measurement and regulation\nstations may use a design factor of 0.54: The affected stations are Carthage Junction\nCompressor Station, Vixen Compressor Station, Energy Transfer Corporation\nMeasurement and Regulation Station. Design of future stations associated with this\npipeline must follow 49 CFR § 192.111.\n15) Temperature Control: The compressor station discharge temperature must be limited to\n120° Fahrenheit. A temperature above this maximum temperature of 120° Fahrenheit\nmay be approved, if GSP technical coating operating tests show that the pipe coating will\nproperly with-stand the higher operating temperature for long term operations.\n16) Overpressure Protection Control: Mainline pipeline overpressure protection must be\nlimited to a maximum of 104 percent MAOP.\n17) Welding Procedures: The appropriate PHMSA regional office must be notified within 14\ndays of the beginning of welding procedure qualification activities. Automated or manual\nwelding procedure documentation must be submitted to the same PHMSA regional office.\n18) Depth of Cover: The soil cover must be a minimum depth of 36 inches in all areas. In\nareas where threats from chisel plowing or other activities are threats to the pipeline, the\ntop of the pipeline must be installed at least one foot below the deepest penetration above\n\n<<<PAGE 7>>>\n\n6\nthe pipeline. If routine patrols or other observed conditions indicate the possible loss of\ncover over the pipeline, GSP will perform a depth of cover study and replace cover as\nnecessary to meet the minimum depth of cover requirements specified herein.\n19) Construction Quality: A construction quality assurance plan to ensure quality standards\nand controls must be maintained throughout the construction phase with respect to:\ninspection, pipe hauling and stringing, field bending, welding, non-destructive\nexamination (NDE) of girth welds, field joint coating, pipeline coating integrity tests,\nlowering of the pipeline in the ditch, padding materials to protect the pipeline, backfilling,\nalternating current (AC) interference mitigation and CP systems. All girth welds must be\nnon-destructively examined (NDE) by radiography or alternative means. The NDE\nexaminer must have all required and current certifications.\n20) Interference Currents Control: Control of induced AC from parallel electric transmission\nlines and other interference issues that may affect the pipeline must be incorporated into\nthe design of the pipeline and addressed during the construction phase. Issues identified\nand not originally addressed in the design phase must be brought to PHMSA's attention.\nAn induced AC program to protect the pipeline from corrosion caused by stray currents\nmust be in place within six months after placing the pipeline in service.\n21) Test Level: The pre-in service hydrostatic test must be to a pressure producing a hoop\nstress of: 100 percent SMYS and 1.25 X MAOP in areas to operate to 80 percent SMYS;\nat least 1.5 X MAOP in areas to operate to 67% SMYS; and at least 1.5 X MAOP in areas\nto operate to 56% SMYS.\n22) Assessment of Test Failures: Any pipe failure occurring during the pre-in service\nhydrostatic test must undergo a root cause failure analysis to include a metallurgical\nexamination of the failed pipe. The results of this examination must preclude a systemic\npipeline material issue and the results must be reported to PHMSA headquarters and the\nappropriate PHMSA regional office.\n23) Supervisory Control and Data Acquisition (SCADA) System Capabilities: A SCADA\nsystem to provide remote monitoring and control of the entire pipeline system must be\nemployed\n\n<<<PAGE 8>>>\n\n7\n24) SCADA Procedures: A detailed procedure for establishing and maintaining accurate\nSCADA set points must be established to ensure the pipeline operates within acceptable\ndesign limits at all times.\n25) Mainline Valve Control: Mainline valves located on either side of a pipeline segment\ncontaining a High Consequence Area (HCA) where personnel response time to the valve\nexceeds one hour must be remotely controlled by the SCADA system. The SCADA\nsystem must be capable of opening and closing the valve and monitoring the valve\nposition, upstream pressure and downstream pressure. As an alternative, a leak detection\nsystem for mainline valve control is acceptable.\n26) Pipeline Inspection: The pipeline must be capable of passing ILI tools. All headers and\nother segments covered under this special permit that do not allow the passage of an ILI\ndevice must have a corrosion mitigation plan.\n27) Gas Quality Monitoring: An acceptable gas quality monitoring and mitigation program\nmust be instituted to not exceed the following limits:\na) H¿S (1 grain per 100 standard cubic feet or 16 parts per million (ppm), maximum);\nb) CO2 (3 percent maximum);\nc) H2O (less than or equal to 7 pounds per million standard cubic feet and no free water);\nand\nd) Other deleterious constituents that may impact the integrity of the pipeline must be\ninstituted.\ne) The pipeline must have an ongoing pigging and liquids sampling plan to identify,\nmitigate and remove deleterious constituents.\nf) When H¿S is above eight parts ppm, the gas stream constituents must be reviewed for\nimplementation of a quarterly pigging/inhibitor injection program including follow up\nsampling of liquids at receipt points.\n29) Gas Quality Control: Filters/separators must be installed at locations where gas is\nreceived into the pipeline where the incoming gas stream quality includes potentially\ndeleterious constituents to minimize the entry of contaminants and to protect the integrity\nof downstream pipeline segments.\n30) Gas Quality Monitoring Equipment: Equipment, including moisture analyzer,\nchromatograph and semi-annual H¿S sampling (quarterly sampling where H¿S is above\n\n<<<PAGE 9>>>\n\n8\neight ppm), must be installed to permit the operator to manage and limit the introduction\nof contaminants and free liquids into the pipeline.\n31) Cathodic Protection: The initial CP system must be operational within 12 months of\nplacing any pipeline segment in service.\n32) Interference Current Surveys: Interference surveys must be performed within six months\nof placing the pipeline in service to ensure compliance with applicable NACE\nInternational Standard Recommended Practices 0169 and 0177 (NACE RP 0169 and\nNACE RP 0177) for interference current levels. If interference currents are found, GSP\nwill determine if there have been any adverse affects to the pipeline and mitigate the\naffects as necessary. GSP will report to PHMSA the results of any negative finding and\nthe associated mitigative efforts to the appropriate PHMSA regional office.\n33) Corrosion Surveys: Corrosion surveys of the affected pipeline must be completed within\nsix months of placing the respective CP system (s) in operation to ensure adequate\nexternal corrosion protection per NACE RP 0169. The survey will also address the\nproper number and location of CP test stations as well as AC interference mitigation and\nAC grounding programs per NACE RP 0177.\n34) Verification of Cathodic Protection: An interrupted close interval survey (CIS) must be\nperformed in concert and integrated with ILI in accordance with 49 CFR 192 Subpart O\nreassessment intervals for all HCA pipeline mileage. At least one CP test station must be\nlocated within each HCA with a maximum spacing between test stations of one-half mile\nwithin an HCA. If any annual test station reading fails to meet 49 CFR 192 Subpart I\nrequirements, remedial actions must occur within six months. Remedial actions must\ninclude a close interval survey (CIS) on each side of the affected test station and all\nmodifications to the CP system necessary to ensure adequate external corrosion control.\n35) Initial Close Interval Survey (CIS) - Initial: A CIS must be performed on the pipeline\nwithin two years of the pipeline in- service date. The CIS results must be integrated with\nthe baseline ILI to determine whether further action is needed.\n36) Pipeline Markers: GSP must employ line-of-sight markings on the pipeline in the special\npermit area except in agricultural areas or large water crossings such as lakes where line\nof sight markers are not practical. The marking of pipelines is also subject to Federal\nEnergy Regulatory Commission orders or environmental permits and local restrictions.\n\n<<<PAGE 10>>>\n\n9\n37) Pipeline Patrolling: Pipeline patrolling must be conducted at least monthly (12 times per\ncalendar year), not to exceed 45 days, to inspect for excavation activities, ground\nmovement, wash-outs, leakage or other activities and conditions affecting the safe\noperation of the pipeline.\n38) Monitoring of Ground Movement: An effective monitoring/mitigation plan must be in\nplace to monitor for and mitigate issues of unstable soil and ground movement.\n39) Initial ILI: GSP must perform a baseline ILI in association with the construction of the\npipeline using a high-resolution Magnetic Flux Leakage (MFL) tool to be completed\nwithin three years of placing a pipeline segment in service. GSP must perform a baseline\ngeometry tool run after completion of the hydrostatic strength test and backfill of the\npipeline, (just prior to placing the pipeline in service) but no later than six months after\nplacing the pipeline in service under a special permit.\n40) Future ILI: A second high-resolution MFL inspection must be performed and completed\non the pipe subject to this waiver within the first reassessment interval required by\n49 CFR Subpart O, regardless of HCA classification. Future ILI must be performed on a\nfrequency consistent with Subpart O for the entire pipeline covered by this waiver.\n41) Direct Assessment Plan: Headers, mainline valve bypasses and other sections covered by\nthis special permit that cannot accommodate ILI tools must be part of a Direct\nAssessment (DA) plan or other acceptable integrity monitoring method using External\nand Internal Corrosion Direct Assessment criteria (ECDA/ICDA).\n42) Damage Prevention Program: The Common Ground Alliance (CGA) Alliance's damage\nprevention best practices applicable to pipelines must be incorporated into the GSP\ndamage prevention program.\n43) Anomaly Evaluation and Repair: Anomaly evaluations and repairs in the special permit\narea must be performed based upon the following:\na) Anomaly Response Time: Repair Immediately\n- Any anomaly within a waiver area operating up to 80% SMYS with a failure\npressure ratio (FPR) equal to or less than 1.1\n- Any anomaly within a waiver area operating up to 67% SMYS with a FPR equal\nto or less than 1.25\n\n<<<PAGE 11>>>\n\n10\n- Any anomaly within a waiver area operating up to 56% SMYS with a FPR equal\nto or less than 1.4\nb) Anomaly Response Time: Repair Within One Year\n- Any anomaly within a waiver area operating at up to 80% SMYS with a FPR\nequal to or less than 1.25\n- Any anomaly within a waiver area operating at up to 67% SMYS with a FPR\nequal to or less than 1.5\n- Any anomaly within a waiver area operating at up to 56% SMYS with a FPR\nequal to or less than 1.8\nc) Anomaly Response Time: Monitored Conditions\n- Anomalies not requiring immediate or one year repairs must be reassessed\naccording to CFR 49, Part 192, Subpart O and the American Society of\nMechanical Engineers (ASME) standard B31.8S requirements and class location\nfactor.\n- Each anomaly not repaired under the immediate repair requirements must have a\ncorrosion growth rate and ILI tool tolerance assigned per the Gas Integrity\nManagement Program (IMP) to determine the maximum re-inspection interval.\nd) Anomaly Assessment Methods\n- GSP must confirm the remaining strength (R-STRENG) effective area method, R-\nSTRENG - 0.85dL, and ASME B31G assessment methods are valid for the pipe\ndiameter, wall thickness, grade, operating pressure, operating stress level and\noperating temperature. GSP must also use the most conservative method until\nconfirmation of the proper method is made to PHMSA headquarters.\n- Dents in the pipe in the waiver area must be evaluated and repaired per 49 CFR\n§ 192.309(b) for initial ILI and per 49 CFR 192.933(d) for future ILI.\n44) Potential Impact Radius Calculation Updates: If the pipeline operating pressures and gas\nquality are determined to be outside the parameters of the C-FER Study, a revised study\nwith the updated parameters must be incorporated into the IMP.\n45) Reporting - Immediate: GSP must notify the appropriate PHMSA regional office within\n24 hours of any non-reportable leaks occurring in the special permit area.\n\n<<<PAGE 12>>>\n\n11\n46) Reporting - 180 Day: Within 180 days of the pipeline in- service date under a special\npermit, GSP shall report on its compliance with special permit conditions to PHMSA\nheadquarters and the appropriate regional office.\n47) Annual Reporting: Following approval of the special permit, GSP must annually report\nthe following:\na) The results of any in-line inspection (ILI) or direct assessment results performed\nwithin the special permit area during the previous year;\nb) Any new integrity threats identified within the special permit area during the previous\nyear,\nc) Any encroachment in the special permit area, including the number of new residences\nor public gathering areas;\nd) Any class or HCA changes in the special permit area during the previous year;\ne) Any reportable incidents associated with the special permit area that occurred during\nthe previous year;\nf) Any leaks on the pipeline in the special permit area that occurred during the previous\nyear;\ng) A list of all repairs on the pipeline in the special permit area made during the previous\nyear;\nh) On-going damage prevention initiatives on the pipeline in the special permit area and\na discussion of their success or failure;\ni) Any changes in procedures used to assess and/or monitor the pipeline operating under\nthis special permit; and\nj) Any company mergers, acquisitions, transfers of assets, or other events affecting the\nregulatory responsibility of the company operating the pipeline to which this special\npermit applies.\nLimitations:\nThe PHMSA has the sole authority to make all determinations on whether GSP has complied\nwith the specified conditions. Should GSP fail to comply with any conditions of this special\npermit, or should PHMSA determine this special permit is no longer appropriate or that this\n\n<<<PAGE 13>>>\n\n12\nspecial permit is inconsistent with pipeline safety, PHMSA may revoke this special permit and\nrequire GSP to comply with the regulatory requirements in 49 CFR §§ 192.111 and 192.201.\nAUTHORITY: 49 U.S.C. 60118(c) and 49 CFR § 1.53.\nAUG 2 4 2007\nIssued in Washington, DC on\nJeffrey D. Wiese,\nAssociate Administrator for Pipeline Safety","truncated":false,"body_characters":26700}