# GREAT LAKES GAS TRANSMISSION CO — Notice of Probable Violation

- **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:** Not available
- **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.

Official case documents:

320191003_Closure Letter_03022021.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_Closure%20Letter_03022021.pdf

320191003_Closure Letter_03022021_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_Closure%20Letter_03022021_text.pdf

320191003_Final Order_01252021.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_Final%20Order_01252021.pdf

320191003_Final Order_01252021_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_Final%20Order_01252021_text.pdf

320191003_NOPV PCP PCO_06252019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_NOPV%20PCP%20PCO_06252019.pdf

320191003_NOPV PCP PCO_06252019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_NOPV%20PCP%20PCO_06252019_text.pdf

320191003_Operator Hearing Request Withdrawn_02052020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320191003/320191003_Operator%20Hearing%20Request%20Withdrawn_02052020.pdf

320191003_NOPV PCP PCO_06252019_text.pdf

NOTICE 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:



1. 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



3. 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



5. (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



6. 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



7. 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



9. 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



10. 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



 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



12. 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



Proposed 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



Following 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



PROPOSED 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

VIA 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

January 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



U.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).



CPF 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.



CPF 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 devic
- **truncated:** true
- **body characters:** 62414