{"operation":"document","citation":"CPF 320191003","title":"GREAT LAKES GAS TRANSMISSION CO — Notice of Probable Violation","source_type":"enforcement","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2019-06-25","effective_on":null,"summary":"CLOSED notice of probable violation citing 192.167(a)(4), 192.473(a), 192.481, 192.605(a), 192.605(b)(1), 192.609, 192.709(c), 192.731(c), 192.739(a)(3), 192.739(a)(4), 192.745(a), 192.909(b), 192.935(c).","machine_formats":{"json":"https://regulus.evalyn.ai/document/phmsa-enforcement-320191003.json","markdown":"https://regulus.evalyn.ai/document/phmsa-enforcement-320191003.md"},"app_url":"https://regulus.evalyn.ai/document/phmsa-enforcement-320191003","source_url":"https://primis.phmsa.dot.gov/enforcement-data/case/320191003","body":"Notice of Probable Violation involving GREAT LAKES GAS TRANSMISSION CO. PHMSA's enforcement data identifies the cited regulations as 192.167(a)(4),  192.473(a),  192.481,  192.605(a),  192.605(b)(1),  192.609,  192.709(c),  192.731(c),  192.739(a)(3),  192.739(a)(4),  192.745(a),  192.909(b),  192.935(c). The case was opened on 2019-06-25 and is reported as closed as of 2021-03-02. Proposed civil penalty: $152,800. Assessed civil penalty: $96,600. Open the official case record for notices, responses, orders, and the latest status.\n\nOfficial case documents:\n\n320191003_Closure Letter_03022021.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_Closure%20Letter_03022021.pdf\n\n320191003_Closure Letter_03022021_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_Closure%20Letter_03022021_text.pdf\n\n320191003_Final Order_01252021.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_Final%20Order_01252021.pdf\n\n320191003_Final Order_01252021_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_Final%20Order_01252021_text.pdf\n\n320191003_NOPV PCP PCO_06252019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_NOPV%20PCP%20PCO_06252019.pdf\n\n320191003_NOPV PCP PCO_06252019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_NOPV%20PCP%20PCO_06252019_text.pdf\n\n320191003_Operator Hearing Request Withdrawn_02052020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_Operator%20Hearing%20Request%20Withdrawn_02052020.pdf\n\n320191003_NOPV PCP PCO_06252019_text.pdf\n\nNOTICE OF PROBABLE VIOLATION\nPROPOSED CIVIL PENALTY\nand\nPROPOSED COMPLIANCE ORDER\nCERTIFIED MAIL - RETURN RECEIPT REQUESTED\nJune 25, 2019\nMr. Stanley Chapman\nExecutive VP and President of US Natural Gas Pipelines\nGreat Lakes Gas Transmission (GLGT)\n700 Louisiana St., Suite 300\nHouston, TX 77002\nCPF 3-2019-1003\nDear Mr. Chapman:\nFrom April 16-20, 2018, April 30-May 4, 2018, May 14 – 18, 2018, May 21 – 24, 2018, June\n4 -6, 2018, July 16 – 20, 2018, July 23 – 27, 2018, and August 20 – 24, 2018, representatives\nof the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline\nSafety (OPS), Michigan Public Service Commission and Minnesota Department of Public\nSafety, pursuant to Chapter 601 of 49 United States Code (U.S.C.) inspected your Great Lakes\nGas Transmission (GLGT) facilities in Michigan, Minnesota and Wisconsin.\nAs a result of the inspection, it is alleged that you have committed probable violations of the\nPipeline Safety Regulations, Title 49, Code of Federal Regulations (CFR). The items\ninspected and the probable violations are:\n\n\n\n1. 2. 192.709 Transmission Lines: Record Keeping\nEach operator shall maintain the following records for transmission lines for the\nperiods specified:\n(a) …..\n(c) A record of each patrol, survey, inspection, and test required by sub-parts L\nand M of this part must be retained for at least 5 years or until the next patrol,\nsurvey, inspection or test is completed, whichever is longer.\nGreat Lakes Gas Transmission (GLGT) failed to maintain, for transmission lines, a\nrecord of each patrol, survey, inspection, and test required by sub-parts L and M of Part\n192 for at least 5 years or until the next patrol, survey, inspection or test is completed,\nwhichever is longer. Specifically, GLGT could not provide records to show compliance\nwith the requirements of 192.731 for pressure relieving devices at the Brevort\nCompressor Station for 2017.\nDuring the inspection, the PHMSA inspector requested Over Pressure Protection (OPP)\ntest records for transmitters PT802, PT902, PT101 and PT103. GLGT was unable to\nproduce the testing records. GLGT stated that the GLGT employee responsible for\ntesting and documenting the testing of the transmitter left the company. A GLGT\nsupervisor contacted the ex-employee via phone and the ex-employee stated that the\nwork had been completed, however the paperwork was not completed.\n192.731 Compressor stations: Inspection and testing of relief devices.\n(c) Each remote control shutdown device must be inspected and tested at intervals\nnot exceeding 15 months, but at least once each calendar year, to determine that it\nfunctions properly.\nGreat Lakes Gas Transmission (GLGT) failed to test and inspect each remote control\nshutdown device at intervals not exceeding 15 months, but at least once each calendar\nyear, to determine that it functions properly. Specifically, GLGT did not inspect the\npipeline suction transmitters EQ# 10019330 and EQ#10019331 at the Boyne Falls\ncompressor station.\nDuring the field inspection of the Boyne Falls Compressor Station, a state agent\ninspector for PHMSA reviewed the Over Pressure Protection (OPP) transmitter testing\nrecords for the GLGT assets. The test records documented that the pressure transmitters\nwere tested in 2014 and 2016, but the transmitters were not tested in 2015 and 2017. The\ncompressor station is a bi-directional facility. These pipeline suction transmitters\nprotected the discharge side of the pipeline MAOP during reverse flow operations.\nBecause of the bi-directional flow capabilities at this station, the transmitters should\nhave been tested once each calendar year, not to exceed 15 months and not bi-annually.\n2\n\n\n\n3. 4. 192.473 External corrosion control: Interference currents\n(a) Each operator whose pipeline system is subjected to stray currents shall have in\neffect a continuing program to minimize the detrimental effects of such currents.\nGreat Lakes Gas Transmission (GLGT) failed to have in effect a continuing program to\nminimize the detrimental effects of stray currents.\nDuring the field inspection, at the Superior meter station, a PHMSA inspector observed\nalternating current (AC) voltage readings greater than 4 volts AC. The 100 line’s AC\nvoltage measurement was 6.29 volts AC and the 200 line’s AC voltage measurement\nwas 5.2 volts AC. PHMSA also reviewed the most recent CP survey record at the same\nlocation and 10 volts AC voltage measurement was recorded. AC voltages in excess of\n15 VAC are a risk for personal step and touch potential hazards on buried or submerged\npipelines. Although the voltages measured on GLGT pipeline are well below this\nthreshold, there are risks associated with AC current densities on the pipeline as it may\nresult in accelerated corrosion. NACE provides guidance to help correlate between the\nAC current density and the risk of corrosion. By not requiring a study until 15 volts AC\nor greater, GLGT neglects the potential risk for corrosion that could occur at the lower\nvoltage levels and therefore, did not have a continuing program to minimize the\ndetrimental effects of stray currents.\n192.609 Change in class location: Required study.\nWhenever an increase in population density indicates a change in class location for\na segment of an existing steel pipeline operating at hoop stress that is more than 40\npercent of SMYS, or indicates that the hoop stress corresponding to the established\nmaximum allowable operating pressure for a segment of existing pipeline is not\ncommensurate with the present class location, the operator shall immediately make\na study to determine:\n(a) The present class location for the segment involved.\n(b) The design, construction, and testing procedures followed in the original\nconstruction, and the comparison of these procedures with those required for\nthe present class location by the applicable provisions of this part.\n(c) The physical condition of the segment to the extent it can be ascertained from\nthe available records;\n(d) (e) The operating and maintenance history of the segment;\nThe maximum actual operating pressure and the corresponding operating\nhoop stress, taking pressure gradient into account, for the segment of pipeline\ninvolved; and\n3\n\n\n\n5. (f) The actual area affected by the population density increase and physical\nbarriers or other factors which may limit further expansion of the more\ndensely populated area.\nGreat Lakes Gas Transmission (GLGT) failed to perform the required study when the\npopulation along its pipeline increased at three locations:\n• The Frontier Campground in Saxon, WI. The existence of Frontier Campground\nwas evident on aerial maps as far back as 2005 and each year thereafter. GLGT\nfailed to identify this location in its patrols and leakage surveys until April 2017.\nThe commensurate MAOP study indicated the pipe cannot support the current\nMAOP. A remediation plan is in place to replace the pipe in 2019. PHMSA\nreceived notification from GLGT that it had reduced the MAOP for Line 100 and\nLine 200 from 974 psig to 812 psig until the pipe replacement project (February –\nApril 2019). Records for 2015 and 2016 indicate that the campground was\nidentified, but the criteria for determination of class 3 was not adequate. This\ncondition dates to the inspection years of 2013, 2014, 2015 and 2016.\n• Pet-O-Sega Campground, located in Michigan, was also identified in April 2017.\nHistoric aerial imagery indicates the campground was functioning as far back as\n1998, and GLGT indicates the campground has been operational since the 1930's.\nIn 2009 the campground was classified as an identified site resulting in HCA’s\nGLGT-128 and GLGT-264. According to an agreement with GLGT, Pet-O-Sega\nplans to restrict usage of the campground to within 300 feet of the pipeline and the\nbuildings within 300 feet of the pipeline will be removed or relocated in 2019.\n• Victorian Heights Assisted Living Facility, located in Crystal Falls, MI was\nconstructed in 2001 and did not become a class three location until August 2017. In\n2004, GLGT classified the Victorian Heights assisted living facility as an identified\nsite, meeting both the limited mobility and occupancy criteria. However, the\nnumber of dwelling units within the facility were not accounted for. This was\ncorrected and the facility identified as a class 3 location in August 2017. Pipe\nreplacement is scheduled to be complete before August 2019.\nFrontier Campground, Pet-O-Sega Campground and Victorian Heights Assisted Living\nFacility were identified by GLGT after implementing their new survey/patrol\nprocedure.\n192.745 Valve maintenance: Transmission Line Valves\n(a) Each transmission line valve that might be required during any emergency\nmust be inspected and partially operated at intervals not exceeding 15 months,\nbut at least once each calendar year.\n4\n\n\n\n6. Great Lakes Gas Transmission (GLGT) failed to inspect and partially operate at\nintervals not exceeding 15 months, but at least once each calendar year, valves which are\nrequired to be used during an emergency.\n During the inspection of the Saginaw Valley Unit in Michigan, a PHMSA inspector\nidentified that cross-over valve 12-1-Z would be used to blow down Line 100 between\nChippewa Meter Station and Midland Meter Station in an emergency. This valve was\ninspected every other year. Records indicated it was inspected on 9/19/14 and 9/21/16\nnot meeting the compliance requirement of intervals not exceeding 15 months but at\nleast once each calendar year for 2015 and 2017.\n During the review of annual valve inspection records for the Blue Lake Unit in\nMichigan, a PHMSA state agent inspector identified several valves indicated as\nEmergency Isolation Valves (EIV), but they were not inspected at least once each\ncalendar year for 2015 and 2017. These valves were Sault St. Marie Lateral valves MB-\n22, MY-60, 660.8-10, 660.8-12, 660.8-12.2. Upon further investigation, it was\ndetermined that some valves may have been misclassified in the SAP (work scheduling)\ndata base. After this discovery, GLGT reviewed line diagrams to verify EIV’s and\nreconciled the SAP data base ensure proper classification and inspection periods.\n192.739 Pressure limiting and regulating stations: Inspection and testing.\n(a) (3) Each pressure limiting station, relief device (except rupture discs), and\npressure regulating station and its equipment must be subjected at intervals\nnot exceeding 15 months, but at least once each calendar year, to inspections\nand tests to determine that it is- …\nExcept as provided in paragraph (b) of this section, set to control or relieve\nat the correct pressure consistent with the pressure limits of 192.201(a);\nGreat Lakes Gas Transmission (GLGT) failed to inspect and test each pressure limiting\nstation, relief device, and pressure regulating station and its equipment at intervals not\nexceeding 15 months, but at least once each calendar year, to determine that it is set to control\nor relieve at the correct pressure consistent with the pressure limits of 49 CFR 192.201(a).\nWhile performing a field inspection at the Shevlin Compressor Station, located in Minnesota,\nthe MNOPS inspector requested records to verify the pressure gauge’s calibration date and\nidentified that the last time the pressure gauge was calibrated was in 2015. The operator’s\nprocedure requires calibration gauges be calibrated annually. GLGT’s employee used a\npressure gauge for inspection of a pressure relief valve that had an elapsed calibration\ncertification. Failure to calibrate gages, including pressure gages, reduces the likelihood of\nhaving accurate calibration gauges for set point control and relief pressures settings. As such,\nthe relief device could not be properly tested to determine that the pressure was consistent\nwith the pressure limits of 49 CFR 192.201(a).\n5\n\n\n\n7. 192.739 Pressure limiting and regulating stations: Inspection and testing.\n(a) (4) Each pressure limiting station, relief device (except rupture discs), and\npressure regulating station and its equipment must be subjected at\nintervals not exceeding 15 months, but at least once each calendar year, to\ninspections and tests to determine that it is-\nproperly installed and protected from dirt, liquids, or other conditions that\nmight prevent proper operation.\nGreat Lakes Gas Transmission (GLGT) failed to inspect and maintain the relief vents\nfrom the relief devices to protect from dirt, liquids or other conditions that might prevent\nproper operation. During the field inspection in Michigan and Minnesota, locations were\nidentified where the relief vents were damaged or inadequate.\nThe following locations were found not to meet the requirements of this section:\n The relief fuel gas system at the Brevort Compressor Station was found without\nprotection from accumulation of water, ice or snow as it has no cap or is not designed to\nrestrict water and snow getting into the pipe and down to the relief device by other\nmeans.\n At the Cloquet, MN Compressor Station, on the Unit 502 starter, a relief valve rain cap\nwas damaged and not preventing accumulation of ice, water or snow.\n At the Crystal Falls, MI Compressor Station - Unit 1, two vents on the east side of the\nbuilding need caps. On Unit 2, vents on the west side of the building had no caps and\nwere open straight to the elements.\n8. 192.935 What additional preventative and mitigative measures must an operator\ntake?\n(c) Automatic shut-off valves (ASV) or Remote control valves (RCV). If an operator\ndetermines, based on a risk analysis, that an ASV or RCV would be an efficient\nmeans of adding protection to a high consequence area in the event of a gas release,\nan operator must install the ASV or RCV. In making that determination an\noperator must, at least, consider the following factors - swiftness of leak detection\nand pipe shutdown capabilities, the type of gas being transported, operating\npressure, the rate of potential release, pipeline, profile, the potential of ignition, and\nlocation of nearest response personnel.\n6\n\n\n\n9. Great Lakes Gas Transmission (GLGT) has not completed the system wide ASV/RCV\nstudy since the issue was identified in 2015. GLGT was unable to provide a record for\nperiodic ASV/RCV study due to expansion of an HCA or identification of a new HCA.\nAt the time of the inspection, records presented were incomplete and many of the valves\nindicated that they were under review or gathering data. For the valves that indicate the\nstudy has been completed, GLGT was unable to provide a record of what was\nconsidered in the study and why actions were taken or not taken.\nGLGT provided a list of the valves with line-break controls; all pipeline block valves\nhave line-break controls. The Gas Control group performed a study and identified the\nlow-pressure settings for each main line valve. The TEP-ASV-RCV-US outlines the\nprocess used to determine if a valve should be considered for modification. Yet GLGT\ndid not have a record of these studies even though new HCA and Class 3 locations have\nbeen identified each year within the inspection scope.\nWhile GLGT has line break control on all mainline valves, periodic review is required to\nbe focused on high consequence areas, especially when new HCA’s are identified.\nGLGT provided a listing of valves that bounded an HCA segment. These are all ASV\nwith low pressure point activation.\n192.909 How can an operator change its integrity management program?\n(b) Notification. An operator must notify OPS, in accordance with 192.949, of any\nchange to the program that may substantially affect the program’s implementation\nor may significantly modify the program or schedule for carrying out the program\nelements. An operator must also notify a State or local pipeline safety authority\nwhen either a covered segment is located in a State where OPS has an interstate\nagent agreement, or an interstate covered segment is regulated by that State. An\noperator must provide the notifications within 30 days after adopting this type of\nchange into its program.\nGreat Lakes Gas Transmission (GLGT) failed to notify OPS, in accordance with\n192.949, of any change to its integrity management program (IMP) that may\nsubstantially affect the program’s implementation or may significantly modify the\nprogram or schedule for carrying out the program elements. Specifically, GLGT did not\nmake notification to PHMSA nor appropriate State authorities after adopting and\nimplementing a Probabilistic Risk model in 2016 for its IMP.\nThis was a significant change from a Relative Risk Model previously utilized for its IMP\nas it required new formulas, new risk ranking factors, and new procedures. TC/GLGT\ndid perform a results comparison between the two models as a way to vet the new model\n7\n\n\n\n10. and documented those results. GLGT never provided notification to OPS, either by\nelectronic mail or mail, as required by 192.949.\n192.481 Atmospheric corrosion control: Monitoring\n(a) Each operator must inspect each pipeline or portion of pipe that is exposed to\nthe atmosphere for evidence of atmospheric corrosion, as follows:\nIf the pipeline is located: Onshore ……….. Offshore ……….. Then the frequency of inspection is:\nAt least once every 3 calendars years, but\nwith intervals not exceeding 39 months\nAt least once each calendar year, but with\nintervals not exceeding 15 months\n(b) During inspections the operator must give particular attention to pipe at the\nsoil-to-air interfaces, under thermal insulation, under disbanded coatings, at\npipe supports in splash zones, at deck penetrations, and in spans over water.\n(c) If atmospheric corrosion is found during an inspection, the operator must\nprovide protection against the corrosion as required by 192.479.\nGreat Lakes Gas Transmission (GLGT) failed to give particular attention to pipe under taped\nflanges and also under insulation during its atmospheric corrosion inspection.\n At Shevlin, Unit 3, GLGT failed to inspect flanges in the compressor building for\natmospheric corrosion because there was masking tape around the flange outside ring. This\nmade the flange face area and bolts during the atmospheric corrosion inspection not visible\nto the inspector. In most cases, the tape became a pseudo insulation, so corrosion under the\ntape did not take place. Atmospheric inspection records for 2017 would have had the tape\non the flanges as was evident from the old paint. Therefore, no visual inspection took\nplace. It was explained that the tape was in place to help with leak detection inside the\nbuilding at the flange face. It is unknown how long the tape had been in place. After being\nidentified by the PHMSA inspection team, the tape was removed and the flanges were\ninspected; no significant corrosion was identified. However, on one flange it was\nobserved that some rusting was occurring due to concentrating water vapor from the cold\nwall effect near the compressors. PHMSA requested all compressor stations be checked\nand correct, which GLGT completed.\n Most recent (2016) atmospheric corrosion inspection record for Unit 8903 MI Saginaw\nValley Saint Clair Meter Station discharge header siphon valve MY-92 and suction header\nsiphon valve MY-77 did not include line items for these valves. There was also no record\nof removal of insulation nor repairs made following the AC inspection. During the field\ninspection, staff could not examine the Saint Clair Meter Station discharge header siphon\nvalve MY-92 or suction header siphon valve MY-77 because they were covered in\ninsulation. GLGT removed the insulation, performed the inspection and found Grade 3\ncorrosion. The insulation has been removed permanently and valves posted for inspection.\n8\n\n\n\n At MLV 2-1 MP 80 the GLGT crew dug out a small intended above ground valve because\nit was buried in the dirt. MLV 2-1: A few small diameter gas lines, valves, and flanges at\nvalve sites that are installed low near the ground were in contact or partially covered by\nsoil. The locations were fully exposed/remediated from contact with soil at the time of the\ninspection, none of which revealed coating condition higher than grade 3.\n11. 192.605 Procedural manual for operations, maintenance, and emergencies.\n(a) General. Each operator shall prepare and follow for each pipeline, a manual of\nwritten procedures for conducting operations and maintenance activities and\nfor emergency response. For transmission lines, the manual must also include\nprocedures for handling abnormal operations. This manual must be reviewed\nand updated by the operator at intervals not exceeding 15 months, but at least\nonce each calendar year. This manual must be prepared before operations of a\npipeline system commence. Appropriate parts of the manual must be kept at\nlocations where operations and maintenance activities are conducted.\n(b) Maintenance and normal operations. The manual required by paragraph (a) of\nthis section must include procedures for the following, if applicable, to provide\nsafety during maintenance and operations.\n(1) Operating, maintaining and repairing the pipeline in accordance with\neach of the requirements of this subpart and subpart M of this part.\nGreat Lakes Gas Transmission (GLGT) failed to follow for each pipeline, a manual of written\nprocedures for conducting operations and maintenance activities and for emergency response,\nincluding operating, maintaining and repairing the pipeline in accordance with each of the\nrequirements of subparts L and M of Part 192. Specifically, GLGT did not observe during\npatrols to repair and maintain fences at stations where fences were in disrepair, as required by\n192.705. 49 CFR 192.705(a) requires operators have patrol programs to observe “other factors\naffecting safety and operations”.\nDuring the inspection of the Ashland Unit in Wisconsin, the PHMSA inspector identified\nseveral locations where either the gap between the ground and fence was large due to frost\nheave or where the fence and gates were unstable and falling down. These conditions can\nallow access of unauthorized personnel, fences or posts to fall on to pipeline facilities, or cause\ninjury to authorized personnel accessing the site.\n9\n\n\n\n12. 192.167 Compressor stations: Emergency shutdown\n(a) Except for unattended field compressor stations of 1,000 horsepower (746\nkilowatts) or less, each compressor station must have an emergency shutdown\nsystem that meets the following:\n(1) …….\n(i) (ii) (4) It must be operable from at least two locations, each of which is:\nOutside the gas area of the station:\nNear the exit gates, if the station is fenced or near emergency exits, if not\nfenced; and\n(iii) Not more than 500 feet (153 meters) from the limits of the station.\nGreat Lakes Gas Transmission’s (GLGT) emergency shutdown (ESD) system was not operable\nfrom at least two locations, each of which was outside the gas area of the compressor stations\nand near the stations’ exit gates.\nThere are 14 compressor stations on the GLGT system with a total of 29 units. Nine stations\nhad new units installed after 1970 and therefore, GLGT should have modified the emergency\nshutdown (ESD) systems to meet the requirements of two ESD switches outside the gas area\nnear the exit gates, but failed to do so. While GLGT did provide numerous ESD push button\nstations around the station at entry gates, outside buildings and inside the control rooms, they\nfailed meet the minimum requirement of two locations near the exit gates, if the station is\nfenced or near emergency exits. The compressor stations that were found not to meet the\nminimum requirements were:\n CS 2 – Thief River Falls\n CS 3 - Shevlin\n CS 5 - Cloquet\n CS 6 – Iron River\n CS 7 - Wakefield\n CS 8 – Crystal Falls\n CS 10 - Naubinway\n CS 11 – Boyne Falls\n CS 13 – Otisville\nThese conditions were observed during the field inspections as well as a review of the station\nline diagrams indicating the ESD “button” locations provided by GLGT.\n10\n\n\n\nProposed Civil Penalty\nUnder 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil penalty not to\nexceed $213,268 per violation per day the violation persists, up to a maximum of $2,132,679\nfor a related series of violations. For violation occurring on or after November 2, 2015 and\nbefore November 27, 2018, the maximum penalty may not exceed $209,002 per violation per\nday, with a maximum penalty not to exceed $2,090,022. For violations occurring prior to\nNovember 2, 2015, the maximum penalty may not exceed $200,000 per violation per day, with\na maximum penalty not to exceed $2,000,000 for a related series of violations The\nCompliance Officer has reviewed the circumstances and supporting documentation involved in\nthe above probable violation(s) and has recommended that you be preliminarily assessed a civil\npenalty of $152,800 as follows:\nItem number\nPENALTY\nItem 1\n$25,200\nItem 2\nItem\n4\n$28,600\n$37,600\nItem 6\n$27,600\nItem 12\n$33,800\nWarning Items\nWith respect to items 3,5,7,8,9,10 and 11 we have reviewed the circumstances and supporting\nor penalty assessment proceedings at this time. We advise you to promptly correct these\ndocuments involved in this case and have decided not to conduct additional enforcement action\nitems). Failure to do so may result in additional enforcement action.\nProposed Compliance Order\nWith respect to item 12 pursuant to 49 U.S.C. § 60118, the Pipeline and Hazardous Materials\nGLGT). Please refer to the Proposed Compliance Order, which is enclosed and made a part\nafety Administration proposes to issue a Compliance Order to Great Lakes Gas Transmissio\nof this Notice.\nResponse to this Notice\nEnclosed as part of this Notice is a document entitled Response Options for Pipeline Operators\nin Compliance Proceedings. Please refer to this document and note the response options. All\nmaterial you submit in response to this enforcement action may be made publicly available. If\nyou believe that any portion of your responsive material qualifies for confidential treatment\nunder 5 U.S.C. 552(b), along with the complete original document you must provide a second\ncopy of the document with the portions you believe qualify for confidential treatment redacted\nand an explanation of why you believe the redacted information qualifies for confidential\ntreatment under 5 U.S.C. 552(b).\n11\n\n\n\nFollowing the receipt of this Notice, you have 30 days to submit written comments, or request\na hearing under 49 CFR § 190.211. If you do not respond within 30 days of receipt of this\nNotice, this constitutes a waiver of your right to contest the allegations in this Notice and\nauthorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice\nwithout further notice to you and to issue a Final Order. If you are responding to this Notice,\nwe propose that you submit your correspondence to my office within 30 days from receipt of\nthis Notice. This period may be extended by written request for good cause.\nIn your correspondence on this matter, please refer to CPF 3-2019-1003 and, for each\ndocument you submit, please provide a copy in electronic format whenever possible.\nSincerely,\nAllan C. Beshore\nDirector, Central Region, OPS\nPipeline and Hazardous Materials Safety Administration\nEnclosures: Proposed Compliance Order\nResponse Options for Pipeline Operators in Enforcement Proceedings\n12\n\n\n\nPROPOSED COMPLIANCE ORDER\nPursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety\nAdministration (PHMSA) proposes to issue to Great Lakes Gas Transmission (GLGT) a\nCompliance Order incorporating the following remedial requirements to ensure the compliance\nof Great Lakes Gas Transmission (GLGT) with the pipeline safety regulations:\n1. 2. In regard to Item Number 12 of the Notice pertaining to emergency shutdowns at\ncompressor stations, Great Lakes Gas Transmission (GLGT) must modify its\nESD shutdowns to provide a minimum of two locations operable from outside of\nthe gas areas near the exit gates at Thief River Falls, Shevlin, Cloquet, Iron\nRiver, Wakefield, Crystal Falls, Naubinway, Boyne Falls and Otisville\nCompressor Stations within six months of the final order.\nIt is requested (not mandated) that Great Lakes Gas Transmission (GLGT)\nmaintain documentation of the safety improvement costs associated with\nfulfilling this Compliance Order and submit the total to Allan Beshore, Director,\nCentral Region, Pipeline and Hazardous Materials Safety Administration. It is\nrequested that these costs be reported in two categories: 1) total cost associated\nwith preparation/revision of plans, procedures, studies and analyses, and 2) total\ncost associated with replacements, additions and other changes to pipeline\ninfrastructure.\n13\n\n320191003_Closure Letter_03022021_text.pdf\n\nVIA ELECTRONIC MAIL TO: stanley chapman iii@tcenergy.com, and lee romack@tcenergy.com\nMarch 2, 2021\nMr. Stanley Chapman\nExecutive VP and President of US Natrual Gas Pipelines\nGreat Lakes Gas Transmission (GLGT)\n700 Louisiana St., Suite 300\nHouston, TX 77002\nRe: CPF 3-2019-1003\nDear Mr. Chapman\nOn January 25, 2021, the Pipeline and Hazardous Materials Administration (PHMSA) issued to\nGreat Lakes Gas Transmission a Final Order in the above referenced case. This Order included a\nNotice of Probable Violation and Civil Penalty and Compliance Order. Based on our review of\nthe documentation provided and confirmation of payment of the civil penalty, as well as evidence\nprovided to support completion of the terms of the compliance order it has been determined that\nyou have complied with the terms of the Order.\nThis letter is to inform you no further action is necessary and this case is now closed. Thank you\nfor your cooperation.\nSincerely,\nGregory A. Ochs\nDirector, Central Region, OPS\nPipeline and Hazardous Materials Safety Administration\ncc: Lee Romack, Director Regulatory Compliance CA/US lee_romack@tcenergy.com\n\n320191003_Final Order_01252021_text.pdf\n\nJanuary 25, 2021\nVIA ELECTRONIC MAIL TO: stanley chapman iii@tcenergy.com\nMr. Stanley G. Chapman, III\nEVP and President of U.S. and Mexico Natural Gas Pipelines\nGreat Lakes Gas Transmission Ltd. Partnership\nTC Energy Corporation\n700 Louisiana Street\nHouston, Texas 77002\nRe: CPF No. 3-2019-1003\nDear Mr. Chapman:\nEnclosed please find the Final Order issued in the above-referenced case. It withdraws two of\nthe allegations of violation, makes other findings of violation, assesses a reduced civil penalty of\n$96,600, and specifies actions that need to be taken by Great Lakes Gas Transmission, LP, a\nsubsidiary of TC Energy Corporation, to comply with the pipeline safety regulations. The\npenalty payment terms are set forth in the Final Order. When the civil penalty has been paid and\nthe terms of the compliance order completed, as determined by the Director, Central Region, this\nenforcement action will be closed. Service of the Final Order by electronic mail is effective\nupon the date of transmission, as provided under 49 C.F.R. § 190.5.\nThank you for your cooperation in this matter.\nSincerely,\nAlan K. Mayberry\nAssociate Administrator\nfor Pipeline Safety\nEnclosure\ncc: Mr. Gregory Ochs, Director, Central Region, Office of Pipeline Safety, PHMSA\nMs. Wendy West, Vice President, Pipeline Safety & Compliance, TC Energy Corp.,\nwendy_west@tcenergy.com\nMr. H. Lee Romack, Director, U.S. Regulatory Compliance, TC Energy Corp.,\nlee_romack@tcenergy.com\nCONFIRMATION OF RECEIPT REQUESTED\n\n\n\nU.S. DEPARTMENT OF TRANSPORTATION\nPIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION\nOFFICE OF PIPELINE SAFETY\nWASHINGTON, D.C. 20590\n_____________________________________\nIn the Matter of )\nGreat Lakes Gas Transmission, LP, ) CPF No. 3-2019-1003\na subsidiary of TC Energy Corporation, )\n)\n)\n)\nRespondent. )\n_____________________________________)\nFINAL ORDER\nFrom April 16th through August 24, 2018, pursuant to 49 U.S.C. §§ 60106 and § 60117,\nrepresentatives of the Michigan Public Service Commission and the Minnesota Department of\nPublic Safety, as agents for the Pipeline and Hazardous Materials Safety Administration\n(PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of\nthe facilities and records of Great Lakes Gas Transmission, LP (GLGT or Respondent), in\nMichigan, Minnesota, and Wisconsin. GLGT, a subsidiary of TC Energy Corporation (TC\nEnergy), operates a 2,115-mile natural gas transmission pipeline system across Michigan,\nMinnesota, and Wisconsin.1\nAs a result of the inspection, the Director, Central Region, OPS (Director), issued to Respondent,\nby letter dated June 25, 2019, a Notice of Probable Violation, Proposed Civil Penalty, and\nProposed Compliance Order (Notice), which also included warning items pursuant to 49 C.F.R.\n§ 190.205. In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that GLGT had\ncommitted five violations of 49 C.F.R. Part 192 and proposed assessing a civil penalty of\n$152,800 for the alleged violations. The Notice also proposed ordering Respondent to take\ncertain measures to correct one of the alleged violations. The warning items required no further\naction but warned the operator to correct the probable violations or face possible future\nenforcement action.\nAfter requesting and receiving an extension of time to respond, TC Energy, on behalf of GLGT,\nresponded to the Notice by letter dated August 30, 2019 (Response). Respondent contested\nseveral of the allegations and associated penalties, and requested a hearing. GLGT also\nrequested to meet informally with OPS to discuss the case. On January 7, 2020, representatives\nfrom OPS Central Region and GLGT met in PHMSA’s Central Region office in Chicago,\nIllinois. During that discussion, Respondent provided a supplemental response to the Notice\n(Supplemental Response). By letter dated February 5, 2020, Respondent withdrew its request for\na hearing and thereby authorized the entry of this Final Order without further notice.\n1 Pipeline Safety Violation Report (Violation Report), at 1 (June 20, 2019) (on file with PHMSA).\n\n\n\nCPF No. 3-2019-1003\nPage 2\nFINDINGS OF VIOLATION\nThe Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows:\nItem 1: The Notice alleged that Respondent violated 49 C.F.R. § 192.709(c), which states:\n§ 192.709 Transmission lines: Record keeping.\nEach operator shall maintain the following records for transmission\nlines for the periods specified:\n(a) . . .\n(c) A record of each patrol, survey, inspection, and test required by\nsubparts L and M of this part must be retained for at least 5 years or until\nthe next patrol, survey, inspection, or test is completed, whichever is longer.\nThe Notice alleged that Respondent violated 49 C.F.R. § 192.709(c) by failing to retain a record\nof each patrol, survey, inspection and test required under subparts L and M for at least five years,\nor until the next patrol, survey, inspection or test is completed, whichever is longer. Specifically,\nthe Notice alleged that GLGT did not maintain testing records for each pressure-relief device\nrequired under § 192.731, which is contained within subpart M of Part 192. During the\ninspection, GLGT informed PHMSA that testing records could not be located for pressure\ntransmitters PT802, PT902, PT101, and PT103.\nIn its Response, GLGT contested the allegation of violation and requested that the civil penalty\nbe reduced or withdrawn. In its Supplemental Response, GLGT provided the missing testing\nrecords and confirmed that the tests had been properly completed.2 GLGT explained that the\nrecords were not produced during the inspection because its supervisor was new and not familiar\nwith its electronic record-keeping system.3 GLGT further explained that the records did not\ninclude As-Found/As-Left (AFAL) values because the technician conducting the tests failed to\nrecord this information in the database.4 As a result, the records that GLGT provided to PHMSA\nwere incomplete.\nMaintaining complete records is critical to pipeline safety. In the absence of complete records,\nan operator cannot perform effective oversight to confirm compliance with its regulatory\nrequirements. Thus, maintaining incomplete records constitutes a failure to maintain all required\nrecords.5 Accordingly, after considering all of the evidence, I find that Respondent violated\n49 C.F.R. § 192.709(c) by failing to retain testing records for each transmitter required under\n§ 192.731for at least five years or until the next test, whichever is longer.\nItem 2: The Notice alleged that Respondent violated 49 C.F.R. § 192.731(c), which states:\n2 Supplemental Response, at 7.\n3 Id., at 6.\n4 Id.\n5 In re Buckeye Partners, LP, CPF No. 3-2007-5026, Final Order, (Dec. 30, 2010), at 2.\n\n\n\nCPF No. 3-2019-1003\nPage 3\n§ 192.731 Compressor stations: Inspection and testing of relief devices.\n(a) . . .\n(c) Each remote control shutdown device must be inspected and tested\nat intervals not exceeding 15 months, but at least once each calendar year,\nto determine that it functions properly.\nThe Notice alleged that Respondent violated 49 C.F.R. § 192.731(c) by failing to inspect and test\neach remote-control shutdown device at intervals not exceeding 15 months, but at least once\neach calendar year, to determine that it functions properly. Specifically, the Notice alleged that\nGLGT did not inspect pipeline suction transmitters EQ# 10019330 and EQ#10019331 at the\nBoyne Falls Compressor Station at the requisite intervals. The Notice alleged that because of the\nbi-directional flow of the station, the transmitters protect the discharge side of the pipeline during\nreverse-flow operations. As a result, the suction transmitters act as relief devices and should be\ntested once each calendar year, not to exceed 15 months, pursuant to the requirements in\n§ 192.731(c).\nIn its Response, GLGT contested the allegation of violation and requested that the civil penalty\nbe reduced or withdrawn. At the January 7, 2020 meeting and in its Supplemental Response,\nGLGT explained that the primary overpressure protection (OPP) device at the Boyne Falls\nCompressor Station is the pressure transmitter on the compressor unit and that the field\ntransmitters on the suction and discharge pipes are secondary.6 GLGT also provided records\ndemonstrating that the pressure transmitters were inspected once each calendar year, as required\nby § 192.731(c).7\nIn his Region Recommendation, the Director accepted GLGT’s explanation that the primary\nOPP devic","truncated":true,"body_characters":62414}