GREAT LAKES GAS TRANSMISSION CO — Notice of Probable Violation

party submissionOfficial PDF320191003_Operator Hearing Request Withdrawn_02052020.pdf#

320191003_NOPV PCP PCO_06252019_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED June 25, 2019 Mr. Stanley Chapman Executive VP and President of US Natural Gas Pipelines Great Lakes Gas Transmission (GLGT) 700 Louisiana St., Suite 300 Houston, TX 77002 CPF 3-2019-1003 Dear Mr. Chapman: From April 16-20, 2018, April 30-May 4, 2018, May 14 – 18, 2018, May 21 – 24, 2018, June 4 -6, 2018, July 16 – 20, 2018, July 23 – 27, 2018, and August 20 – 24, 2018, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), Michigan Public Service Commission and Minnesota Department of Public Safety, pursuant to Chapter 601 of 49 United States Code (U.S.C.) inspected your Great Lakes Gas Transmission (GLGT) facilities in Michigan, Minnesota and Wisconsin. As a result of the inspection, it is alleged that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations (CFR). The items inspected and the probable violations are:#

320191003_NOPV PCP PCO_06252019_text.pdf, page 21. 2. 192.709 Transmission Lines: Record Keeping Each operator shall maintain the following records for transmission lines for the periods specified: (a) ….. (c) A record of each patrol, survey, inspection, and test required by sub-parts L and M of this part must be retained for at least 5 years or until the next patrol, survey, inspection or test is completed, whichever is longer. Great Lakes Gas Transmission (GLGT) failed to maintain, for transmission lines, a record of each patrol, survey, inspection, and test required by sub-parts L and M of Part 192 for at least 5 years or until the next patrol, survey, inspection or test is completed, whichever is longer. Specifically, GLGT could not provide records to show compliance with the requirements of 192.731 for pressure relieving devices at the Brevort Compressor Station for 2017. During the inspection, the PHMSA inspector requested Over Pressure Protection (OPP) test records for transmitters PT802, PT902, PT101 and PT103. GLGT was unable to produce the testing records. GLGT stated that the GLGT employee responsible for testing and documenting the testing of the transmitter left the company. A GLGT supervisor contacted the ex-employee via phone and the ex-employee stated that the work had been completed, however the paperwork was not completed. 192.731 Compressor stations: Inspection and testing of relief devices. (c) Each remote control shutdown device must be inspected and tested at intervals not exceeding 15 months, but at least once each calendar year, to determine that it functions properly. Great Lakes Gas Transmission (GLGT) failed to test and inspect each remote control shutdown device at intervals not exceeding 15 months, but at least once each calendar year, to determine that it functions properly. Specifically, GLGT did not inspect the pipeline suction transmitters EQ# 10019330 and EQ#10019331 at the Boyne Falls compressor station. During the field inspection of the Boyne Falls Compressor Station, a state agent inspector for PHMSA reviewed the Over Pressure Protection (OPP) transmitter testing records for the GLGT assets. The test records documented that the pressure transmitters were tested in 2014 and 2016, but the transmitters were not tested in 2015 and 2017. The compressor station is a bi-directional facility. These pipeline suction transmitters protected the discharge side of the pipeline MAOP during reverse flow operations. Because of the bi-directional flow capabilities at this station, the transmitters should have been tested once each calendar year, not to exceed 15 months and not bi-annually. 2#

320191003_NOPV PCP PCO_06252019_text.pdf, page 33. 4. 192.473 External corrosion control: Interference currents (a) Each operator whose pipeline system is subjected to stray currents shall have in effect a continuing program to minimize the detrimental effects of such currents. Great Lakes Gas Transmission (GLGT) failed to have in effect a continuing program to minimize the detrimental effects of stray currents. During the field inspection, at the Superior meter station, a PHMSA inspector observed alternating current (AC) voltage readings greater than 4 volts AC. The 100 line’s AC voltage measurement was 6.29 volts AC and the 200 line’s AC voltage measurement was 5.2 volts AC. PHMSA also reviewed the most recent CP survey record at the same location and 10 volts AC voltage measurement was recorded. AC voltages in excess of 15 VAC are a risk for personal step and touch potential hazards on buried or submerged pipelines. Although the voltages measured on GLGT pipeline are well below this threshold, there are risks associated with AC current densities on the pipeline as it may result in accelerated corrosion. NACE provides guidance to help correlate between the AC current density and the risk of corrosion. By not requiring a study until 15 volts AC or greater, GLGT neglects the potential risk for corrosion that could occur at the lower voltage levels and therefore, did not have a continuing program to minimize the detrimental effects of stray currents. 192.609 Change in class location: Required study. Whenever an increase in population density indicates a change in class location for a segment of an existing steel pipeline operating at hoop stress that is more than 40 percent of SMYS, or indicates that the hoop stress corresponding to the established maximum allowable operating pressure for a segment of existing pipeline is not commensurate with the present class location, the operator shall immediately make a study to determine: (a) The present class location for the segment involved. (b) The design, construction, and testing procedures followed in the original construction, and the comparison of these procedures with those required for the present class location by the applicable provisions of this part. (c) The physical condition of the segment to the extent it can be ascertained from the available records; (d) (e) The operating and maintenance history of the segment; The maximum actual operating pressure and the corresponding operating hoop stress, taking pressure gradient into account, for the segment of pipeline involved; and 3#

320191003_NOPV PCP PCO_06252019_text.pdf, page 45. (f) The actual area affected by the population density increase and physical barriers or other factors which may limit further expansion of the more densely populated area. Great Lakes Gas Transmission (GLGT) failed to perform the required study when the population along its pipeline increased at three locations: • The Frontier Campground in Saxon, WI. The existence of Frontier Campground was evident on aerial maps as far back as 2005 and each year thereafter. GLGT failed to identify this location in its patrols and leakage surveys until April 2017. The commensurate MAOP study indicated the pipe cannot support the current MAOP. A remediation plan is in place to replace the pipe in 2019. PHMSA received notification from GLGT that it had reduced the MAOP for Line 100 and Line 200 from 974 psig to 812 psig until the pipe replacement project (February – April 2019). Records for 2015 and 2016 indicate that the campground was identified, but the criteria for determination of class 3 was not adequate. This condition dates to the inspection years of 2013, 2014, 2015 and 2016. • Pet-O-Sega Campground, located in Michigan, was also identified in April 2017. Historic aerial imagery indicates the campground was functioning as far back as 1998, and GLGT indicates the campground has been operational since the 1930's. In 2009 the campground was classified as an identified site resulting in HCA’s GLGT-128 and GLGT-264. According to an agreement with GLGT, Pet-O-Sega plans to restrict usage of the campground to within 300 feet of the pipeline and the buildings within 300 feet of the pipeline will be removed or relocated in 2019. • Victorian Heights Assisted Living Facility, located in Crystal Falls, MI was constructed in 2001 and did not become a class three location until August 2017. In 2004, GLGT classified the Victorian Heights assisted living facility as an identified site, meeting both the limited mobility and occupancy criteria. However, the number of dwelling units within the facility were not accounted for. This was corrected and the facility identified as a class 3 location in August 2017. Pipe replacement is scheduled to be complete before August 2019. Frontier Campground, Pet-O-Sega Campground and Victorian Heights Assisted Living Facility were identified by GLGT after implementing their new survey/patrol procedure. 192.745 Valve maintenance: Transmission Line Valves (a) Each transmission line valve that might be required during any emergency must be inspected and partially operated at intervals not exceeding 15 months, but at least once each calendar year. 4#

320191003_NOPV PCP PCO_06252019_text.pdf, page 56. Great Lakes Gas Transmission (GLGT) failed to inspect and partially operate at intervals not exceeding 15 months, but at least once each calendar year, valves which are required to be used during an emergency.  During the inspection of the Saginaw Valley Unit in Michigan, a PHMSA inspector identified that cross-over valve 12-1-Z would be used to blow down Line 100 between Chippewa Meter Station and Midland Meter Station in an emergency. This valve was inspected every other year. Records indicated it was inspected on 9/19/14 and 9/21/16 not meeting the compliance requirement of intervals not exceeding 15 months but at least once each calendar year for 2015 and 2017.  During the review of annual valve inspection records for the Blue Lake Unit in Michigan, a PHMSA state agent inspector identified several valves indicated as Emergency Isolation Valves (EIV), but they were not inspected at least once each calendar year for 2015 and 2017. These valves were Sault St. Marie Lateral valves MB- 22, MY-60, 660.8-10, 660.8-12, 660.8-12.2. Upon further investigation, it was determined that some valves may have been misclassified in the SAP (work scheduling) data base. After this discovery, GLGT reviewed line diagrams to verify EIV’s and reconciled the SAP data base ensure proper classification and inspection periods. 192.739 Pressure limiting and regulating stations: Inspection and testing. (a) (3) Each pressure limiting station, relief device (except rupture discs), and pressure regulating station and its equipment must be subjected at intervals not exceeding 15 months, but at least once each calendar year, to inspections and tests to determine that it is- … Except as provided in paragraph (b) of this section, set to control or relieve at the correct pressure consistent with the pressure limits of 192.201(a); Great Lakes Gas Transmission (GLGT) failed to inspect and test each pressure limiting station, relief device, and pressure regulating station and its equipment at intervals not exceeding 15 months, but at least once each calendar year, to determine that it is set to control or relieve at the correct pressure consistent with the pressure limits of 49 CFR 192.201(a). While performing a field inspection at the Shevlin Compressor Station, located in Minnesota, the MNOPS inspector requested records to verify the pressure gauge’s calibration date and identified that the last time the pressure gauge was calibrated was in 2015. The operator’s procedure requires calibration gauges be calibrated annually. GLGT’s employee used a pressure gauge for inspection of a pressure relief valve that had an elapsed calibration certification. Failure to calibrate gages, including pressure gages, reduces the likelihood of having accurate calibration gauges for set point control and relief pressures settings. As such, the relief device could not be properly tested to determine that the pressure was consistent with the pressure limits of 49 CFR 192.201(a). 5#

320191003_NOPV PCP PCO_06252019_text.pdf, page 67. 192.739 Pressure limiting and regulating stations: Inspection and testing. (a) (4) Each pressure limiting station, relief device (except rupture discs), and pressure regulating station and its equipment must be subjected at intervals not exceeding 15 months, but at least once each calendar year, to inspections and tests to determine that it is- properly installed and protected from dirt, liquids, or other conditions that might prevent proper operation. Great Lakes Gas Transmission (GLGT) failed to inspect and maintain the relief vents from the relief devices to protect from dirt, liquids or other conditions that might prevent proper operation. During the field inspection in Michigan and Minnesota, locations were identified where the relief vents were damaged or inadequate. The following locations were found not to meet the requirements of this section:  The relief fuel gas system at the Brevort Compressor Station was found without protection from accumulation of water, ice or snow as it has no cap or is not designed to restrict water and snow getting into the pipe and down to the relief device by other means.  At the Cloquet, MN Compressor Station, on the Unit 502 starter, a relief valve rain cap was damaged and not preventing accumulation of ice, water or snow.  At the Crystal Falls, MI Compressor Station - Unit 1, two vents on the east side of the building need caps. On Unit 2, vents on the west side of the building had no caps and were open straight to the elements. 8. 192.935 What additional preventative and mitigative measures must an operator take? (c) Automatic shut-off valves (ASV) or Remote control valves (RCV). If an operator determines, based on a risk analysis, that an ASV or RCV would be an efficient means of adding protection to a high consequence area in the event of a gas release, an operator must install the ASV or RCV. In making that determination an operator must, at least, consider the following factors - swiftness of leak detection and pipe shutdown capabilities, the type of gas being transported, operating pressure, the rate of potential release, pipeline, profile, the potential of ignition, and location of nearest response personnel. 6#

320191003_NOPV PCP PCO_06252019_text.pdf, page 79. Great Lakes Gas Transmission (GLGT) has not completed the system wide ASV/RCV study since the issue was identified in 2015. GLGT was unable to provide a record for periodic ASV/RCV study due to expansion of an HCA or identification of a new HCA. At the time of the inspection, records presented were incomplete and many of the valves indicated that they were under review or gathering data. For the valves that indicate the study has been completed, GLGT was unable to provide a record of what was considered in the study and why actions were taken or not taken. GLGT provided a list of the valves with line-break controls; all pipeline block valves have line-break controls. The Gas Control group performed a study and identified the low-pressure settings for each main line valve. The TEP-ASV-RCV-US outlines the process used to determine if a valve should be considered for modification. Yet GLGT did not have a record of these studies even though new HCA and Class 3 locations have been identified each year within the inspection scope. While GLGT has line break control on all mainline valves, periodic review is required to be focused on high consequence areas, especially when new HCA’s are identified. GLGT provided a listing of valves that bounded an HCA segment. These are all ASV with low pressure point activation. 192.909 How can an operator change its integrity management program? (b) Notification. An operator must notify OPS, in accordance with 192.949, of any change to the program that may substantially affect the program’s implementation or may significantly modify the program or schedule for carrying out the program elements. An operator must also notify a State or local pipeline safety authority when either a covered segment is located in a State where OPS has an interstate agent agreement, or an interstate covered segment is regulated by that State. An operator must provide the notifications within 30 days after adopting this type of change into its program. Great Lakes Gas Transmission (GLGT) failed to notify OPS, in accordance with 192.949, of any change to its integrity management program (IMP) that may substantially affect the program’s implementation or may significantly modify the program or schedule for carrying out the program elements. Specifically, GLGT did not make notification to PHMSA nor appropriate State authorities after adopting and implementing a Probabilistic Risk model in 2016 for its IMP. This was a significant change from a Relative Risk Model previously utilized for its IMP as it required new formulas, new risk ranking factors, and new procedures. TC/GLGT did perform a results comparison between the two models as a way to vet the new model 7#

320191003_NOPV PCP PCO_06252019_text.pdf, page 810. and documented those results. GLGT never provided notification to OPS, either by electronic mail or mail, as required by 192.949. 192.481 Atmospheric corrosion control: Monitoring (a) Each operator must inspect each pipeline or portion of pipe that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows: If the pipeline is located: Onshore ……….. Offshore ……….. Then the frequency of inspection is: At least once every 3 calendars years, but with intervals not exceeding 39 months At least once each calendar year, but with intervals not exceeding 15 months (b) During inspections the operator must give particular attention to pipe at the soil-to-air interfaces, under thermal insulation, under disbanded coatings, at pipe supports in splash zones, at deck penetrations, and in spans over water. (c) If atmospheric corrosion is found during an inspection, the operator must provide protection against the corrosion as required by 192.479. Great Lakes Gas Transmission (GLGT) failed to give particular attention to pipe under taped flanges and also under insulation during its atmospheric corrosion inspection.  At Shevlin, Unit 3, GLGT failed to inspect flanges in the compressor building for atmospheric corrosion because there was masking tape around the flange outside ring. This made the flange face area and bolts during the atmospheric corrosion inspection not visible to the inspector. In most cases, the tape became a pseudo insulation, so corrosion under the tape did not take place. Atmospheric inspection records for 2017 would have had the tape on the flanges as was evident from the old paint. Therefore, no visual inspection took place. It was explained that the tape was in place to help with leak detection inside the building at the flange face. It is unknown how long the tape had been in place. After being identified by the PHMSA inspection team, the tape was removed and the flanges were inspected; no significant corrosion was identified. However, on one flange it was observed that some rusting was occurring due to concentrating water vapor from the cold wall effect near the compressors. PHMSA requested all compressor stations be checked and correct, which GLGT completed.  Most recent (2016) atmospheric corrosion inspection record for Unit 8903 MI Saginaw Valley Saint Clair Meter Station discharge header siphon valve MY-92 and suction header siphon valve MY-77 did not include line items for these valves. There was also no record of removal of insulation nor repairs made following the AC inspection. During the field inspection, staff could not examine the Saint Clair Meter Station discharge header siphon valve MY-92 or suction header siphon valve MY-77 because they were covered in insulation. GLGT removed the insulation, performed the inspection and found Grade 3 corrosion. The insulation has been removed permanently and valves posted for inspection. 8#

320191003_NOPV PCP PCO_06252019_text.pdf, page 9 At MLV 2-1 MP 80 the GLGT crew dug out a small intended above ground valve because it was buried in the dirt. MLV 2-1: A few small diameter gas lines, valves, and flanges at valve sites that are installed low near the ground were in contact or partially covered by soil. The locations were fully exposed/remediated from contact with soil at the time of the inspection, none of which revealed coating condition higher than grade 3. 11. 192.605 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least once each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. (b) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following, if applicable, to provide safety during maintenance and operations. (1) Operating, maintaining and repairing the pipeline in accordance with each of the requirements of this subpart and subpart M of this part. Great Lakes Gas Transmission (GLGT) failed to follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response, including operating, maintaining and repairing the pipeline in accordance with each of the requirements of subparts L and M of Part 192. Specifically, GLGT did not observe during patrols to repair and maintain fences at stations where fences were in disrepair, as required by 192.705. 49 CFR 192.705(a) requires operators have patrol programs to observe “other factors affecting safety and operations”. During the inspection of the Ashland Unit in Wisconsin, the PHMSA inspector identified several locations where either the gap between the ground and fence was large due to frost heave or where the fence and gates were unstable and falling down. These conditions can allow access of unauthorized personnel, fences or posts to fall on to pipeline facilities, or cause injury to authorized personnel accessing the site. 9#

320191003_NOPV PCP PCO_06252019_text.pdf, page 1012. 192.167 Compressor stations: Emergency shutdown (a) Except for unattended field compressor stations of 1,000 horsepower (746 kilowatts) or less, each compressor station must have an emergency shutdown system that meets the following: (1) ……. (i) (ii) (4) It must be operable from at least two locations, each of which is: Outside the gas area of the station: Near the exit gates, if the station is fenced or near emergency exits, if not fenced; and (iii) Not more than 500 feet (153 meters) from the limits of the station. Great Lakes Gas Transmission’s (GLGT) emergency shutdown (ESD) system was not operable from at least two locations, each of which was outside the gas area of the compressor stations and near the stations’ exit gates. There are 14 compressor stations on the GLGT system with a total of 29 units. Nine stations had new units installed after 1970 and therefore, GLGT should have modified the emergency shutdown (ESD) systems to meet the requirements of two ESD switches outside the gas area near the exit gates, but failed to do so. While GLGT did provide numerous ESD push button stations around the station at entry gates, outside buildings and inside the control rooms, they failed meet the minimum requirement of two locations near the exit gates, if the station is fenced or near emergency exits. The compressor stations that were found not to meet the minimum requirements were:  CS 2 – Thief River Falls  CS 3 - Shevlin  CS 5 - Cloquet  CS 6 – Iron River  CS 7 - Wakefield  CS 8 – Crystal Falls  CS 10 - Naubinway  CS 11 – Boyne Falls  CS 13 – Otisville These conditions were observed during the field inspections as well as a review of the station line diagrams indicating the ESD “button” locations provided by GLGT. 10#

320191003_NOPV PCP PCO_06252019_text.pdf, page 11Proposed Civil Penalty Under 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil penalty not to exceed $213,268 per violation per day the violation persists, up to a maximum of $2,132,679 for a related series of violations. For violation occurring on or after November 2, 2015 and before November 27, 2018, the maximum penalty may not exceed $209,002 per violation per day, with a maximum penalty not to exceed $2,090,022. For violations occurring prior to November 2, 2015, the maximum penalty may not exceed $200,000 per violation per day, with a maximum penalty not to exceed $2,000,000 for a related series of violations The Compliance Officer has reviewed the circumstances and supporting documentation involved in the above probable violation(s) and has recommended that you be preliminarily assessed a civil penalty of $152,800 as follows: Item number PENALTY Item 1 $25,200 Item 2 Item 4 $28,600 $37,600 Item 6 $27,600 Item 12 $33,800 Warning Items With respect to items 3,5,7,8,9,10 and 11 we have reviewed the circumstances and supporting or penalty assessment proceedings at this time. We advise you to promptly correct these documents involved in this case and have decided not to conduct additional enforcement action items). Failure to do so may result in additional enforcement action. Proposed Compliance Order With respect to item 12 pursuant to 49 U.S.C. § 60118, the Pipeline and Hazardous Materials GLGT). Please refer to the Proposed Compliance Order, which is enclosed and made a part afety Administration proposes to issue a Compliance Order to Great Lakes Gas Transmissio of this Notice. Response to this Notice Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in Compliance Proceedings. Please refer to this document and note the response options. All material you submit in response to this enforcement action may be made publicly available. If you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). 11#

320191003_NOPV PCP PCO_06252019_text.pdf, page 12Following the receipt of this Notice, you have 30 days to submit written comments, or request a hearing under 49 CFR § 190.211. If you do not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order. If you are responding to this Notice, we propose that you submit your correspondence to my office within 30 days from receipt of this Notice. This period may be extended by written request for good cause. In your correspondence on this matter, please refer to CPF 3-2019-1003 and, for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, Allan C. Beshore Director, Central Region, OPS Pipeline and Hazardous Materials Safety Administration Enclosures: Proposed Compliance Order Response Options for Pipeline Operators in Enforcement Proceedings 12#

320191003_NOPV PCP PCO_06252019_text.pdf, page 13PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Great Lakes Gas Transmission (GLGT) a Compliance Order incorporating the following remedial requirements to ensure the compliance of Great Lakes Gas Transmission (GLGT) with the pipeline safety regulations: 1. 2. In regard to Item Number 12 of the Notice pertaining to emergency shutdowns at compressor stations, Great Lakes Gas Transmission (GLGT) must modify its ESD shutdowns to provide a minimum of two locations operable from outside of the gas areas near the exit gates at Thief River Falls, Shevlin, Cloquet, Iron River, Wakefield, Crystal Falls, Naubinway, Boyne Falls and Otisville Compressor Stations within six months of the final order. It is requested (not mandated) that Great Lakes Gas Transmission (GLGT) maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to Allan Beshore, Director, Central Region, Pipeline and Hazardous Materials Safety Administration. It is requested that these costs be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses, and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. 13#

320191003_Closure Letter_03022021_text.pdf, page 1Official PDFVIA ELECTRONIC MAIL TO: stanley chapman iii@tcenergy.com, and lee romack@tcenergy.com March 2, 2021 Mr. Stanley Chapman Executive VP and President of US Natrual Gas Pipelines Great Lakes Gas Transmission (GLGT) 700 Louisiana St., Suite 300 Houston, TX 77002 Re: CPF 3-2019-1003 Dear Mr. Chapman On January 25, 2021, the Pipeline and Hazardous Materials Administration (PHMSA) issued to Great Lakes Gas Transmission a Final Order in the above referenced case. This Order included a Notice of Probable Violation and Civil Penalty and Compliance Order. Based on our review of the documentation provided and confirmation of payment of the civil penalty, as well as evidence provided to support completion of the terms of the compliance order it has been determined that you have complied with the terms of the Order. This letter is to inform you no further action is necessary and this case is now closed. Thank you for your cooperation. Sincerely, Gregory A. Ochs Director, Central Region, OPS Pipeline and Hazardous Materials Safety Administration cc: Lee Romack, Director Regulatory Compliance CA/US lee_romack@tcenergy.com#

320191003_Final Order_01252021_text.pdf, page 1Official PDFJanuary 25, 2021 VIA ELECTRONIC MAIL TO: stanley chapman iii@tcenergy.com Mr. Stanley G. Chapman, III EVP and President of U.S. and Mexico Natural Gas Pipelines Great Lakes Gas Transmission Ltd. Partnership TC Energy Corporation 700 Louisiana Street Houston, Texas 77002 Re: CPF No. 3-2019-1003 Dear Mr. Chapman: Enclosed please find the Final Order issued in the above-referenced case. It withdraws two of the allegations of violation, makes other findings of violation, assesses a reduced civil penalty of $96,600, and specifies actions that need to be taken by Great Lakes Gas Transmission, LP, a subsidiary of TC Energy Corporation, to comply with the pipeline safety regulations. The penalty payment terms are set forth in the Final Order. When the civil penalty has been paid and the terms of the compliance order completed, as determined by the Director, Central Region, this enforcement action will be closed. Service of the Final Order by electronic mail is effective upon the date of transmission, as provided under 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Alan K. Mayberry Associate Administrator for Pipeline Safety Enclosure cc: Mr. Gregory Ochs, Director, Central Region, Office of Pipeline Safety, PHMSA Ms. Wendy West, Vice President, Pipeline Safety & Compliance, TC Energy Corp., wendy_west@tcenergy.com Mr. H. Lee Romack, Director, U.S. Regulatory Compliance, TC Energy Corp., lee_romack@tcenergy.com CONFIRMATION OF RECEIPT REQUESTED#

320191003_Final Order_01252021_text.pdf, page 2U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION OFFICE OF PIPELINE SAFETY WASHINGTON, D.C. 20590 _____________________________________ In the Matter of ) Great Lakes Gas Transmission, LP, ) CPF No. 3-2019-1003 a subsidiary of TC Energy Corporation, ) ) ) ) Respondent. ) _____________________________________) FINAL ORDER From April 16th through August 24, 2018, pursuant to 49 U.S.C. §§ 60106 and § 60117, representatives of the Michigan Public Service Commission and the Minnesota Department of Public Safety, as agents for the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the facilities and records of Great Lakes Gas Transmission, LP (GLGT or Respondent), in Michigan, Minnesota, and Wisconsin. GLGT, a subsidiary of TC Energy Corporation (TC Energy), operates a 2,115-mile natural gas transmission pipeline system across Michigan, Minnesota, and Wisconsin.1 As a result of the inspection, the Director, Central Region, OPS (Director), issued to Respondent, by letter dated June 25, 2019, a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice), which also included warning items pursuant to 49 C.F.R. § 190.205. In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that GLGT had committed five violations of 49 C.F.R. Part 192 and proposed assessing a civil penalty of $152,800 for the alleged violations. The Notice also proposed ordering Respondent to take certain measures to correct one of the alleged violations. The warning items required no further action but warned the operator to correct the probable violations or face possible future enforcement action. After requesting and receiving an extension of time to respond, TC Energy, on behalf of GLGT, responded to the Notice by letter dated August 30, 2019 (Response). Respondent contested several of the allegations and associated penalties, and requested a hearing. GLGT also requested to meet informally with OPS to discuss the case. On January 7, 2020, representatives from OPS Central Region and GLGT met in PHMSA’s Central Region office in Chicago, Illinois. During that discussion, Respondent provided a supplemental response to the Notice (Supplemental Response). By letter dated February 5, 2020, Respondent withdrew its request for a hearing and thereby authorized the entry of this Final Order without further notice. 1 Pipeline Safety Violation Report (Violation Report), at 1 (June 20, 2019) (on file with PHMSA).#

320191003_Final Order_01252021_text.pdf, page 3CPF No. 3-2019-1003 Page 2 FINDINGS OF VIOLATION The Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows: Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 192.709(c), which states: § 192.709 Transmission lines: Record keeping. Each operator shall maintain the following records for transmission lines for the periods specified: (a) . . . (c) A record of each patrol, survey, inspection, and test required by subparts L and M of this part must be retained for at least 5 years or until the next patrol, survey, inspection, or test is completed, whichever is longer. The Notice alleged that Respondent violated 49 C.F.R. § 192.709(c) by failing to retain a record of each patrol, survey, inspection and test required under subparts L and M for at least five years, or until the next patrol, survey, inspection or test is completed, whichever is longer. Specifically, the Notice alleged that GLGT did not maintain testing records for each pressure-relief device required under § 192.731, which is contained within subpart M of Part 192. During the inspection, GLGT informed PHMSA that testing records could not be located for pressure transmitters PT802, PT902, PT101, and PT103. In its Response, GLGT contested the allegation of violation and requested that the civil penalty be reduced or withdrawn. In its Supplemental Response, GLGT provided the missing testing records and confirmed that the tests had been properly completed.2 GLGT explained that the records were not produced during the inspection because its supervisor was new and not familiar with its electronic record-keeping system.3 GLGT further explained that the records did not include As-Found/As-Left (AFAL) values because the technician conducting the tests failed to record this information in the database.4 As a result, the records that GLGT provided to PHMSA were incomplete. Maintaining complete records is critical to pipeline safety. In the absence of complete records, an operator cannot perform effective oversight to confirm compliance with its regulatory requirements. Thus, maintaining incomplete records constitutes a failure to maintain all required records.5 Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 192.709(c) by failing to retain testing records for each transmitter required under § 192.731for at least five years or until the next test, whichever is longer. Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 192.731(c), which states: 2 Supplemental Response, at 7. 3 Id., at 6. 4 Id. 5 In re Buckeye Partners, LP, CPF No. 3-2007-5026, Final Order, (Dec. 30, 2010), at 2.#

320191003_Final Order_01252021_text.pdf, page 4CPF No. 3-2019-1003 Page 3 § 192.731 Compressor stations: Inspection and testing of relief devices. (a) . . . (c) Each remote control shutdown device must be inspected and tested at intervals not exceeding 15 months, but at least once each calendar year, to determine that it functions properly. The Notice alleged that Respondent violated 49 C.F.R. § 192.731(c) by failing to inspect and test each remote-control shutdown device at intervals not exceeding 15 months, but at least once each calendar year, to determine that it functions properly. Specifically, the Notice alleged that GLGT did not inspect pipeline suction transmitters EQ# 10019330 and EQ#10019331 at the Boyne Falls Compressor Station at the requisite intervals. The Notice alleged that because of the bi-directional flow of the station, the transmitters protect the discharge side of the pipeline during reverse-flow operations. As a result, the suction transmitters act as relief devices and should be tested once each calendar year, not to exceed 15 months, pursuant to the requirements in § 192.731(c). In its Response, GLGT contested the allegation of violation and requested that the civil penalty be reduced or withdrawn. At the January 7, 2020 meeting and in its Supplemental Response, GLGT explained that the primary overpressure protection (OPP) device at the Boyne Falls Compressor Station is the pressure transmitter on the compressor unit and that the field transmitters on the suction and discharge pipes are secondary.6 GLGT also provided records demonstrating that the pressure transmitters were inspected once each calendar year, as required by § 192.731(c).7 In his Region Recommendation, the Director accepted GLGT’s explanation that the primary OPP device at the Boyne Falls Compressor Station is the pressure transmitter on the unit, which is inspected annually pursuant to § 192.731(c) and that the suction transmitters were secondary OPP for the station.8 As a result, the Director recommended withdrawal of the allegation of violation.9 Accordingly, after considering all of the evidence, I find that GLGT complied with the requirements set forth in § 192.731(c) because it inspected and tested each remote-control shutdown device at intervals not exceeding 15 months, but at least once each calendar year, to determine that it functions properly. Based upon the foregoing, I hereby order that Item 2 of the Notice and its associated penalty be withdrawn. Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 192.609, which states: § 192.609 Change in class location: Required study. Whenever an increase in population density indicates a change in class 6 Supplemental Response, at 9-10. 7 Region Recommendation, at 4. 8 Id. 9 Id.#

320191003_Final Order_01252021_text.pdf, page 5CPF No. 3-2019-1003 Page 4 location for a segment of an existing steel pipeline operating at hoop stress that is more than 40 percent of [Specified Minimum Yield Strength (SMYS)], or indicates that the hoop stress corresponding to the established maximum allowable operating pressure for a segment of existing pipeline is not commensurate with the present class location, the operator shall immediately make a study to determine: (a) The present class location for the segment involved. (b) The design, construction, and testing procedures followed in the original construction, and a comparison of these procedures with those required for the present class location by the applicable provisions of this part. (c) The physical condition of the segment to the extent it can be ascertained from available records; (d) The operating and maintenance history of the segment; (e) The maximum actual operating pressure and the corresponding operating hoop stress, taking pressure gradient into account, for the segment of pipeline involved; and (f) The actual area affected by the population density increase, and physical barriers or other factors which may limit further expansion of the more densely populated area The Notice alleged that Respondent violated 49 C.F.R. § 192.609 by failing to conduct a study when it experienced an increase in population density at three locations along its pipeline that were indicative of a change in class location for a segment of an existing steel pipeline operating at a hoop stress greater than 40 percent of SMYS. Respondent did not contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 192.609 by failing to conduct a study when it experienced an increase in population density at three locations along its pipeline that were indicative of a change in class location for a segment of an existing steel pipeline operating at a hoop stress greater than 40 percent of SMYS. Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 192.739(a)(3), which states: § 192.739 Pressure limiting and regulating stations: Inspection and testing. (a) Each pressure limiting station, relief device (except rupture discs), and pressure regulating station and its equipment must be subjected at intervals not exceeding 15 months, but at least once each calendar year, to inspections and tests to determine that it is - (1) . . . (3) Except as provided in paragraph (b) of this section, set to control or relieve at the correct pressure consistent with the pressure limits of § 192.201(a); . . . The Notice alleged that Respondent violated 49 C.F.R. § 192.739(a)(3) by failing to inspect and#

320191003_Final Order_01252021_text.pdf, page 6CPF No. 3-2019-1003 Page 5 test each pressure limiting station, relief device (except rupture discs), and pressure regulating station and its equipment to determine that it is set to control or relieve at the correct pressure consistent with the pressure limits of § 192.201(a), at intervals not exceeding 15 months but at least once each calendar year. Specifically, the Notice alleged that during the inspection of the Shelvin Compressor Station, GLGT could not verify the calibration date of the pressure gauge used to test various pressure-relieving equipment, which had last been calibrated in 2015. The Notice alleged that without an accurate pressure gauge, GLGT could not properly inspect and test its relief devices to determine that they were set to control or relive at the correct pressure consistent with the pressure limits of § 192.201(a). In its Response, GLGT contested the allegation of violation and requested that the civil penalty be reduced or withdrawn. In its Supplemental Response, GLGT explained that the gauge was not calibrated because its supervisor was demonstrating a covered task during the inspection, and that if he/she were performing the annual inspection required under § 192.739(a)(3), then he/she would use a calibrated pressure gauge.10 The burden of proof is on OPS to establish that GLGT failed to inspect and test its relief device to determine that it is set to control or relieve at the correct pressure consistent with the pressure limits of § 192.201(a).11 It is unclear from the record if the annual inspection and test of the relief device at the Shelvin Compression Station was performed using an uncalibrated gauge. Having an uncalibrated gauge at the station during the state inspection is not determinative; another pressure gauge could have been used to perform the required inspection and test of the relief device. There are no calibration records or other documents in the record to determine whether the pressure gauge actually used during these tests and inspections was calibrated. In his Region Recommendation, the Director noted that after the state inspection, GLGT performed a calibration test of gauge S/N 2197 ID 823 in May 2018, and that the calibration test failed.12 A failed calibration test performed post-state inspection, however, is not indicative of a violation of § 192.739(a)(3). OPS did not offer any additional evidence to demonstrate that GLGT actually used an uncalibrated gauge to perform the cited pressure tests. Accordingly, after considering all of the evidence I find that OPS has not met its burden of proof in establishing that GLGT failed to inspect and test each relief device annually, but not to exceed 15 months, to determine that it is set to control or relieve at the correct pressure consistent with the pressure limits of § 192.201(a). Based upon the foregoing, I hereby order that Item 6 be withdrawn. Item 12: The Notice alleged that Respondent violated 49 C.F.R. § 192.167(a)(4): § 192.167 Compressor stations: Emergency shutdown. (a) Except for unattended field compressor stations of 1,000 horsepower (746 kilowatts) or less, each compressor station must have an 10 Supplemental Response, at 12. 11 In re Golden Pass Pipeline, LLC, CPF No. 4-2008-1017, Final Order, (Mar. 22, 2011) at fn 25. 12 Region Recommendation, at 7.#

320191003_Final Order_01252021_text.pdf, page 7CPF No. 3-2019-1003 Page 6 emergency shutdown system that meets the following: (1) . . . (4) It must be operable from at least two locations, each of which is: (i) Outside the gas area of the station: (ii) Near the exit gates, if the station is fenced or near emergency exits, if not fenced; and (iii)Not more than 500 feet (153 meters) from the limits of the station. The Notice alleged that Respondent violated 49 C.F.R. § 192.167(a)(4) by failing to ensure each compressor station had an emergency shutdown system that is operable from at least two locations that are located outside the gas area of the station, near the exit gates or emergency exits, and not more than 500 feet from the limits of the station. Specifically, the Notice alleged that GLGT had nine compressor stations that failed to have an emergency shutdown system operable from at least two locations that are located near the exit gates or emergency exits. In its Response, GLGT contested this allegation of violation and requested that the civil penalty be reduced or withdrawn. In its Supplemental Response, GLGT provided information concerning the corrective actions it had taken to complete the proposed compliance actions for this item.13 Specifically, GLGT explained that in 2019 it had modified its emergency shutdown systems at four compressor stations to come into compliance with § 192.167(a)(4), and had scheduled the remaining five compressor stations for corrective action in 2020.14 It did not offer any evidence to rebut the allegation that these nine compressor stations were out of compliance during the inspection. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 192.167(a)(4) by failing to ensure each compressor station had an emergency shutdown system that is operable from at least two locations that are located near the exit gates or emergency exits. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed $200,000 per violation for each day of the violation, up to a maximum of $2,000,000 for any related series of violations.15 In determining the amount of a civil penalty under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature, circumstances, and gravity of the violation, including adverse impact on the environment; the degree of Respondent’s culpability; the history of Respondent’s prior offenses; any effect that the penalty may have on its ability to continue doing business; and the good faith of Respondent in attempting to comply with the pipeline safety regulations. In addition, I may consider the 13 Supplemental Response, at 14. 14 Id. 15 These amounts are adjusted annually for inflation. See 49 C.F.R. § 190.223.#

320191003_Final Order_01252021_text.pdf, page 8CPF No. 3-2019-1003 Page 7 economic benefit gained from the violation without any reduction because of subsequent damages, and such other matters as justice may require. The Notice proposed a total civil penalty of $152,800 for the violations cited above. Item 1: The Notice proposed a civil penalty of $25,200 for Respondent’s violation of 49 C.F.R. § 192.709(c), for failing to retain a record of each patrol, survey, inspection and test required under subparts L and M of Part 192 for at least five years, or until the next patrol, survey, inspection or test is completed, whichever is longer. In its Supplemental Response, GLGT requested that the penalty be reduced or withdrawn due to certain extenuating circumstances.16 GLGT did not clarify what specific extenuating circumstances warranted a reduction in or elimination of the penalty. Therefore, I will assume the company is referring to the fact that its supervisor was not familiar with its document database and did not produce the requested documents during the inspection. Although the requested records were eventually produced by GLGT during the January 7, 2020 meeting, they were still incomplete because they were missing AFAL values. The Violation Report accurately notes that this was a records-keeping violation that minimally impacted pipeline safety.17 GLGT did not provide a reasonable justification for its noncompliance that would warrant a credit under Part E8-Good Faith in the Violation Report. GLGT did not fail to achieve compliance due to unforeseeable circumstances outside of its control; instead, its technician simply forgot to completely record the test and inspection results. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $25,200 for violation of 49 C.F.R. § 192.709(c). Item 2: The Notice proposed a civil penalty of $ 28,600 for Respondent’s violation of 49 C.F.R. § 192.731(c), for failing to inspect and test each remote-control shutdown device at intervals not exceeding 15 months, but at least once each calendar year, to determine that it functions properly. For the reasons discussed above, I find that the Respondent did not violate this regulation. Accordingly, I hereby withdraw the proposed penalty for violation of 49 C.F.R. § 192.731(c). Item 4: The Notice proposed a civil penalty of $37,600 for Respondent’s violation of 49 C.F.R. § 192.609, for failing to conduct a study when it experienced an increase in population density at three locations along its pipeline that were indicative of a change in class location for a segment of an existing steel pipeline operating at hoop stress greater than 40 percent of SMYS. GLGT neither contested the allegation nor presented any evidence or argument justifying a reduction in the proposed penalty. After GLGT discovered the non-compliance, it took documented action to complete the class location studies prior to the inspection and the proposed penalty was therefore reduced to the lowest level of culpability. However, the operator did not self-report the violation, and the violation occurred in an HCA or HCA could-affect area. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $37,600 for violation of 49 C.F.R. § 192.609. 16 Supplemental Response, at 6. 17 Id., at 6, 8.#

320191003_Final Order_01252021_text.pdf, page 9CPF No. 3-2019-1003 Page 8 Item 6: The Notice proposed a civil penalty of $27,600 for Respondent’s violation of 49 C.F.R. § 192.739(a)(3), for failing to inspect and test each pressure limiting station, relief device (except rupture discs), and pressure regulating station and its equipment, at intervals not exceeding 15 months but at least once each calendar year, to determine that it is set to control or relieve at the correct pressure consistent with the pressure limits of § 192.201(a). For the reasons discussed above, I find that the Respondent did not violate this regulation. Accordingly, I hereby withdraw the proposed penalty. Item 12: The Notice proposed a civil penalty of $33,800 for Respondent’s violation of 49 C.F.R. § 192.167(a)(4), for failing to ensure each compressor station had an emergency shutdown system that is operable from at least two locations that are near the exit gates or emergency exits. In its Supplemental Response, GLGT requested that the penalty be reduced or withdrawn because it was based on an erroneous determination in the Violation Report that this was a repeat offense rather than a singular violation applying to multiple locations.18 After reviewing the Violation Report for Item 12, I disagree.19 Under Part E2 - Repeat Violation, the Violation Report correctly indicated that this was not a repeat violation.20 Further, Part E6 - Gravity accurately notes that this was a singular violation applying to multiple locations.21 Because the violation was found at 9 different compressor stations, it has 9 instances of violation. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $33,800 for violation of 49 C.F.R. § 192.167(a)(4). In summary, having reviewed the record and considered the assessment criteria for each of the Items cited above, I assess Respondent a total civil penalty of $96,600. Payment of the civil penalty must be made within 20 days of service. Federal regulations (49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed instructions are contained in the enclosure. Questions concerning wire transfers should be directed to: Financial Operations Division (AMK-325), Federal Aviation Administration, Mike Monroney Aeronautical Center, 6500 S MacArthur Blvd, Oklahoma City, Oklahoma 79169. The Financial Operations Division telephone number is (405) 954-8845. Failure to pay the $96,600 civil penalty will result in accrual of interest at the current annual rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to those same authorities, a late penalty charge of six percent (6%) per annum will be charged if payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty may result in referral of the matter to the Attorney General for appropriate action in a district court of the United States. 18 Supplemental Response, at 14. 19 The Violation Report erroneously labeled Item 12 as “Item 6” on page 81. 20 Violation Report, at 83. 21 Id., at 85.#

320191003_Final Order_01252021_text.pdf, page 10CPF No. 3-2019-1003 Page 9 COMPLIANCE ORDER The Notice proposed a compliance order with respect to Item 12 in the Notice for violation of 49 C.F.R. § 192.167(a)(4). Under 49 U.S.C. § 60118(a), each person who engages in the transportation of gas or who owns or operates a pipeline facility is required to comply with the applicable safety standards established under chapter 601. Pursuant to the authority of 49 U.S.C. § 60118(b) and 49 C.F.R. § 190.217, Respondent is ordered to take the following actions to ensure compliance with the pipeline safety regulations applicable to its operations: 1. With respect to the violation of § 192.167(a)(4) (Item 12), Respondent must modify its emergency shutdown systems to provide a minimum of two locations operable from outside of the gas areas near the exit gates or emergency exits at the following compressor stations: 1. Thief River Falls Compressor Station; 2. Shevlin Compressor Station; 3. Cloquet Compressor Station; 4. Iron River Compressor Station; 5. Wakefield Compressor Station; 6. Crystal Falls Compressor Station; 7. Naubinway Compressor Station; 8. Boyne Falls Compressor Station; and 9. Otisville Compressor Station. Each compressor station listed above must be completed within six months of issuance of this Final Order and documentation sent to the Director. The Director may grant an extension of time to comply with any of the required items upon a written request timely submitted by the Respondent and demonstrating good cause for an extension. It is requested (not mandated) that Respondent maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to the Director. It is requested that these costs be reported in two categories: (1) total cost associated with preparation/revision of plans, procedures, studies and analyses; and (2) total cost associated with replacements, additions and other changes to pipeline infrastructure. Failure to comply with this Order may result in the administrative assessment of civil penalties not to exceed $200,000, as adjusted for inflation (49 C.F.R. § 190.223), for each violation for each day the violation continues or in referral to the Attorney General for appropriate relief in a district court of the United States.#

320191003_Final Order_01252021_text.pdf, page 11CPF No. 3-2019-1003 Page 10 WARNING ITEMS With respect to Items 3, 5, 7, 8, 9, 10, and 11, the Notice alleged probable violations of Part 192, but identified them as warning items pursuant to § 190.205. The warnings were for: 49 C.F.R. § 192.473(a) (Item 3) ─ Respondent’s alleged failure to have in effect a continuing program to minimize the detrimental effects of stray currents; 49 C.F.R. § 192.745(a) (Item 5) ─ Respondent’s alleged failure to inspect and partially operate, at intervals not exceeding 15 months but at least once each calendar year, each transmission line valve that might be required during an emergency; 49 C.F.R. § 192.739(a)(4) (Item 7) – Respondent’s alleged failure to test and inspect each pressure limiting station, relief device (except rupture discs), and pressure regulating station and its equipment to determine it is properly installed and protected from dirt, liquids, or other conditions that might prevent proper operation at intervals not exceeding 15 months, but at least once each calendar year; 49 C.F.R. § 192.935(c) (Item 8) ─ Respondent’s alleged failure to determine, based on a risk analysis that considers all the factors listed in § 192.935(c), that an ASV or RCV would be an efficient means of adding protection to a high consequence area in the event of a gas release, and to install the ASV or RCV as necessary; 49 C.F.R. § 192.909(b) (Item 9) ─ Respondent’s alleged failure to notify OPS, in accordance with § 192.949, or the applicable State or local pipeline safety authority, of any change to its integrity management program that might substantially affect the program’s implementation or significantly modify the program or schedule for carrying out the program elements; 49 C.F.R. § 192.481(b) (Item 10) ─ Respondent’s alleged failure, during atmospheric corrosion inspections, to give particular attention to pipe at the soil- to-air interfaces, under thermal insulation, under disbonded coatings, at pipe supports in splash zones, at deck penetrations, and in spans over water; and 49 C.F.R. § 192.605(a) (Item 11) ─ Respondent’s alleged failure to prepare and follow for each pipeline a manual of written procedures for conducting operations and maintenance activities in accordance with each of the requirements of subpart L and subpart M of Part 192. GLGT presented information in its Response showing that it had taken certain actions to address the cited items. If OPS finds a violation of any of these items in a subsequent inspection, Respondent may be subject to future enforcement action.#

320191003_Final Order_01252021_text.pdf, page 12CPF No. 3-2019-1003 Page 11 Under 49 C.F.R. § 190.243, Respondent may submit a Petition for Reconsideration of this Final Order to the Associate Administrator, Office of Pipeline Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC 20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address, no later than 20 days after receipt of service of this Final Order by Respondent. Any petition submitted must contain a statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.243. The filing of a petition automatically stays the payment of any civil penalty assessed. The other terms of the order, including corrective action, remain in effect unless the Associate Administrator, upon request, grants a stay. The terms and conditions of this Final Order are effective upon service in accordance with 49 C.F.R. § 190.5. January 25, 2021 ___________________________________ __________________________ Alan K. Mayberry Date Issued Associate Administrator for Pipeline Safety#