# COLUMBIA GAS TRANSMISSION, LLC — Safety Order

**Citation:** CPF 120181016S  
**Type / status:** enforcement / historical  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** 2018-07-09

CLOSED safety order.

## Document text

Safety Order involving COLUMBIA GAS TRANSMISSION, LLC. The dataset does not identify a cited regulation for this case. The case was opened on 2018-07-09 and is reported as closed as of 2020-03-02. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

120181016S_Closure Letter_03022020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Closure%20Letter_03022020.pdf

120181016S_Closure Letter_03022020_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Closure%20Letter_03022020_text.pdf

120181016S_Notice Of Proposed Safety Order_07092018.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Notice%20Of%20Proposed%20Safety%20Order_07092018.pdf

120181016S_Notice Of Proposed Safety Order_07092018_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Notice%20Of%20Proposed%20Safety%20Order_07092018_text.pdf

120181016S_Operator Response to Notice_08082018.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Operator%20Response%20to%20Notice_08082018.pdf

120181016S_Safety Order_10102019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Safety%20Order_10102019.pdf

120181016S_Safety Order_10102019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Safety%20Order_10102019_text.pdf

120181016S_Safety Order_10102019_text.pdf

October 10, 2019
Mr. Stanley Chapman, III
Executive Vice President and President
U.S. Natural Gas Pipelines
TC Energy
700 Louisiana Street, Suite 700
Houston, Texas 77002
Re: CPF No. 1-2018-1016S
Dear Mr. Chapman:
Enclosed please find the Safety Order issued in the above-referenced case. It makes a finding
that the pipeline system of your subsidiary, Columbia Gas Transmission, LLC, has a condition or
conditions that pose a pipeline integrity risk and specifies actions that must be taken to ensure
that the public, property, and the environment are protected from the risk. When the terms of the
order have been completed, as determined by the Director, Eastern Region, this enforcement
action will be closed. Your receipt of the Safety Order constitutes service of the document, 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. Robert Burrough, Director, Eastern Region, Office of Pipeline Safety, PHMSA
Mr. Lee Romack, Manager, U.S. Regulatory Compliance, TC Energy, 700 Louisiana
Street, Suite 700, Houston, Texas 77002
Mr. Randal Broussard, Senior Vice President, U.S. Gas Operations East, Columbia Gas
Transmission, LLC, 201 Energy Parkway, Suite 100, Lafayette, Louisiana 70508
CERTIFIED MAIL - RETURN 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 )
Columbia Gas Transmission, LLC, )
a subsidiary of TC Energy, ) CPF No. 1-2018-1016S
)
)
)
Respondent. )
____________________________________)
SAFETY ORDER
Pursuant to Chapter 601 of Title 49, United States Code, the Pipeline and Hazardous Materials
Safety Administration (PHMSA), U.S. Department of Transportation, initiated an investigation
and information review of the safety of Columbia Gas Transmission, LLC’s (CGT) Leach
Xpress (LEX) gas pipeline system. CGT is a subsidiary of TC Energy (collectively,
Respondent).1 The investigation was initiated after PHMSA was notified, on June 7, 2018, of a
reportable incident that occurred on the LEX pipeline system, which resulted in the release of
approximately 165 million cubic feet (MMCF) of natural gas, an ignition of natural gas, and a
fire (Failure). The Failure resulted in the ejection of approximately 83 feet of 36-inch diameter
pipe from the ditch onto the right of way. The Failure occurred in a remote, Class 1 rural
location, and there were no reported injuries, fatalities or evacuations. The cause of the Failure
has not yet been determined.
As a result of the investigation, and pursuant to 49 U.S.C. § 60117(1), the Director, Eastern
Region, OPS (Director), issued a Notice of Proposed Safety Order (Notice) to CGT on July 9,
2018, proposing certain measures be taken to ensure that the public, property, and the
environment are protected from identified integrity risks related to the Failure. The Notice
notified Respondent of the preliminary findings of the investigation and proposed that
Respondent take certain measures to ensure that the public, property, and the environment are
protected from the integrity risk of LEX related to the Failure.
On August 8, 2018, TC Energy responded to the Notice on behalf of CGT (Response).2 In the
Response, Respondent did not contest the proposed findings or remedial requirements contained
in the Notice, but provided an update on the work it had completed to date to ensure the safe
1 See, TC Energy Website, available at https://www.tcenergy.com/operations/natural-gas/columbia-gas-transmission/
(last accessed October 3, 2019).
2 In May 2019, TransCanada Corporation changed its name to TC Energy. See, TC Energy Website, available at
https://www.tcenergy.com/TC-Energy/ (last accessed October 3, 2019).



CPF No. 1-2018-1016S
Page 2
operation of the LEX. Respondent did request that the Proposed Safety Order requirements be
modified based on the work completed and approved by PHMSA to date. In subsequent
submissions, including emails dated January 11 and February 22, 2019, Respondent submitted
additional documentation of completed actions. Respondent did not request a hearing and
therefore has waived its right to one.
FINDINGS OF PIPELINE INTEGRITY RISK
Respondent did not contest the proposed findings in the Notice that its pipeline has a condition or
conditions that pose a pipeline integrity risk. Accordingly, pursuant to 49 U.S.C. § 60117(1) and
49 C.F.R. § 190.239, I find as follows:
• Columbia Gas Transmission, LLC, a subsidiary of TC Energy, operates over 10,468
miles of interstate natural gas transmission pipelines, 37 storage fields across four states,
and transports an average of three billion cubic feet of natural gas per day through New
York, New Jersey, Pennsylvania, Maryland, Virginia, West Virginia, Ohio, Kentucky,
North Carolina, and Delaware. Columbia Gas was acquired by TransCanada Corporation
in 2016. In My 2019, TransCanada changed its name to TC Energy.
• The failed pipeline is a 36-inch diameter, 130 mile-long line that transports natural gas
and runs from Majorsville, Pennsylvania, to Crawford, Ohio. The Failure occurred near
milepost (MP) 20.6, approximately seven miles south of Moundsville, West Virginia
(Failure Site).
• The Affected Segment runs along several hills and ridges with steep elevation changes.
The Failure Site is located on Nixon Ridge.3
• The Affected Segment near the Failure Site was constructed in 2017. The pipeline at the
Failure Site consists of grade X-70, 36-inch steel pipe with a wall thickness of 0.515” and
0.618”. The pipeline has fusion bonded epoxy coating and double submerged arc welded
(DSAW) seams. The impressed current cathodic protection system had not been
energized, but Respondent was in the process of having it commissioned. Galvanic
anodes were installed at foreign lines crossings.
• The maximum allowable operating pressure (MAOP) of the Affected Segment is 1440
pounds per square inch gauge (psig), as established by hydrostatic test in 2017. At the
time of the Failure, the actual operating pressure of the pipeline upstream from the
Failure was 1280 psig; downstream of the Failure at the Eureka Metering Station, the
operating pressure was 1243.7 psig.
• At approximately 4:55 a.m. EDT on June 7, 2018, Respondent discovered a failure on the
3 “Affected Segment” means the approximately 50 miles of Respondent’s 30-inch and 36-inch LEX Pipeline from
the upstream Lone Oak Compressor Station (MP 7.2) near Lone Oak, West Virginia within Marshall County
through the downstream Summerfield Compressor Station (MP 57.2) near Summerfield, OH in Noble County. The
“Affected Segment” generally runs westerly through portions of Noble and Monroe Counties in Ohio, and Marshall
County in West Virginia.



CPF No. 1-2018-1016S
Page 3
LEX pipeline system, as determined by its gas controller, from a pressure drop
observation. The incident was determined to be a natural gas release, an ignition of
natural gas, and fire in the area of Moundsville, West Virginia. The Failure resulted in
the ejection of approximately 83 feet of 36-inch pipe from the ditch onto the right of way,
and the loss of 165 MMCF of natural gas. The Failure occurred in a remote, Class 1 rural
location. There were no reported injuries, fatalities or evacuations. The Failure was
reported to the National Response Center (NRC Report No. 1214458) on June 7, 2018, at
approximately 6:12 a.m. EDT.
• Respondent isolated the Affected Segment via manual closure of valves LEX-500, which
is a main line valve (MLV) known as MLV 2, and LEX-600 (MLV 3) (Isolated
Segment).4 MLV 2 is located approximately 1.6 miles upstream of the Failure Site and
was manually closed at approximately 5:20 a.m. EDT. MLV 3 is located approximately
12.75 miles downstream of the Failure Site and automatically closed at approximately
4:55 a.m. EDT. The upstream Lone Oak compressor station’s compressor units were
shut down via a command issued from Respondent’s Gas Control at approximately 4:36
a.m. EDT. In addition, LEX-700, MLV 4, further downstream from MLV 3,
automatically closed at approximately 5:32 a.m. EDT.
• PHMSA, Roberts Ridge Volunteer Fire Department, the West Virginia Department of
Environmental Protection, the West Virginia Division of Forestry, and the Federal
Energy Regulatory Commission responded to the scene. PHMSA inspectors initiated an
investigation of the Failure on June 7, 2018.
• The Isolated Segment, which was shut-in via the closure of MLVs 2 and 3, currently
remains out of service.
• On December 12, 2017, Respondent completed a hydrostatic test on “test section LX1-
3A” of the LEX pipeline, which includes the location of Failure. The section was
successfully tested for a duration of eight hours to a minimum test pressure of 1880 psig.
In addition, on December 14, 2017, Respondent ran an Enduro Digital Data Logger
Caliper tool from the Taylor B (746+11) launch site near Glen Easton, West Virginia, to
Games Ridge (1139+34.9) receive site near Moundsville, West Virginia. The report was
generated on December 20, 2017. On May 17, 2018, a combo High-Resolution Magnetic
Flux Leakage (HR MFL) + Geo Tool was run with an inertial measurement unit.
Respondent did not immediately receive the report from the combo HR MFL + Geo Tool
run, but the vendor was asked to provide an expedited preliminary in-line inspection
report as soon as practicable due to the Failure.
• Since the Failure, Respondent has identified six other points along the pipeline that,
based on their geotechnical flyover, are areas of concern due to the existence of large
spoil piles, steep slopes, or indications of slips. Respondent has also performed minor
repair work and grading of the Failure Site.
4 “Isolated Segment” means the approximately 14.35-mile segment of the LEX pipeline from the upstream valve
LEX-500 (MLV 2) at MP 18.5 to the downstream valve LEX-600 (MLV 3) at MP 32. It is the portion of the
“Affected Segment” that was shut-in after the failure on June 7, 2018, by closing MLV 2 (upstream of the failure)
and MLV 3 (downstream of the failure).



CPF No. 1-2018-1016S
Page 4
• The PHMSA investigation is ongoing and the cause of the Failure is unknown at this
time. The preliminary investigation suggests that the Failure was the result of land
subsidence causing stress on a girth weld.
ISSUANCE OF SAFETY ORDER
Section 60117(1) of Title 49, United States Code, provides for the issuance of a safety order,
after reasonable notice and the opportunity for a hearing, requiring corrective measures, which
may include physical inspection, testing, repair, or other action, as appropriate. The basis for
making the determination that a pipeline facility has a condition or conditions that pose a
pipeline integrity risk to public safety, property, or the environment is set forth both in the above-
referenced statute and 49 C.F.R. § 190.239.
After evaluating the foregoing findings and considering the age of the pipe involved, the
hazardous nature of the product transported, the circumstances surrounding the Failure, including
the uncertainties of the cause of the Failure and the potential for the conditions that caused the
Failure to be present elsewhere on the pipeline system, PHMSA finds that Respondent’s LEX
gas pipeline system has a condition or conditions that pose a pipeline integrity risk to public
safety, property, or the environment. Accordingly, PHMSA issues this Safety Order, which
requires that Respondent take measures specified below to address the risk.
CORRECTIVE MEASURES
The Notice proposed certain actions with respect to the Affected Segment. As described below,
Respondent has completed certain actions relating to Items 3 and 4.
As for the remaining compliance terms, pursuant to 49 U.S.C. § 60117(1) and 49 C.F.R.
§ 190.239, Respondent must take the following remedial requirements with respect to the
Affected Segment:
1. Review of Isolated Segment. Respondent must review and inspect the Isolated Segment
for conditions similar to those of the Failure including a review of construction, operating
and maintenance (O&M), and integrity management records such as in-line inspection
(ILI) results, hydrostatic tests, root cause failure analysis of the Failure, aerial and ground
patrols, cathodic protection, excavations and pipe replacements. Respondent must
address any findings that require remedial measures to be implemented within 30 days of
discovery.
Respondent has completed aerial and ground patrols of the Isolated Segment,5 however it
must still conclude its review of construction, O&M and integrity management records,
such as ILI results, hydrostatic tests, root cause failure analysis of the Failure, cathodic
protection, excavations and pipe replacement records in order to satisfy this Corrective
5 Response, at 1.



CPF No. 1-2018-1016S
Page 5
2. 3. 4. 5. 6. 7. Action Item.
Enhanced Surveillance and Monitoring. Respondent must provide for enhanced
patrolling and surveillance of the Isolated Segment until completion of the Root Cause
Failure Analysis required in Corrective Action 10.
Respondent completed enhanced surveillance and patrolling of the Isolated Segment
during the purge, load and restart of the pipeline. Its Response acknowledged that
additional surveillance, patrolling and monitoring will be included during the completion
of its actions in response to additional items.6 I have therefore modified this Corrective
Action Item to require that enhanced patrolling and surveillance of the Isolated Segment
continue until the completion of the Root Cause Failure Analysis required in Corrective
Action 10.
Installation of Strain Gauges. Respondent installed a total of 11 sets of strain gauges.
These strain gauges included those required as a part of its Repair Plan, and additional
sets determined to be needed after identification of an additional location with the
potential for land movement. Accordingly, Respondent has completed the requirements
of Corrective Action 3.
Hydrostatic Testing. Respondent completed a 49 C.F.R. Part 192 Subpart J pressure test
of all replacement pipe utilized at the failure site within the Isolated Segment, in
accordance with the Hydrostatic Testing Plan it provided to PHMSA on June 28, 2018.
Accordingly, Respondent has completed the requirements of Corrective Action 4.
Weather Contingency Plan. Within 30 days of receipt of this Safety Order, Respondent
must submit to the Director a contingency plan to operate and monitor the Isolated
Segment during saturated soil or flooding conditions, including enhanced patrolling and
surveillance.
Instrumented Leakage Survey. Within 30 days of receipt of this Safety Order,
Respondent must perform an aerial or ground instrumented leakage survey of the
Affected Segment. Respondent must investigate all leak indications and remedy all leaks
discovered. Respondent must submit documentation of this survey to the Director within
45 days of receipt of this Safety Order.
Respondent completed instrumented leakage surveys of the Isolated Segment between
July 13 and 15, 2018, following the purge and load steps during the restart of the
pipeline.7 However, Respondent has not submitted documentation of an aerial or ground
instrumented leakage survey for the entire Affected Segment as required.
Records Verification. Respondent must verify the records for the Affected Segment to
confirm the maximum operating pressure or MAOP (See PHMSA Advisory Bulletin
6 Response, at 1.
7 Response, at 2.



CPF No. 1-2018-1016S
Page 6
8. ADB 12-06). Respondent must submit documentation of this record verification within
45 days of receipt of this Safety Order.
Review of Prior Inline Inspection (ILI) Results. Within 30 days of receipt of this Safety
Order, Respondent must conduct a review of any previous ILI results of the Affected
Segment. Respondent must re-evaluate all ILI results, including a review of the ILI
vendors’ raw data and analysis. Respondent must determine whether any features were
present in the failed pipe joint and any other pipe removed. Also, Respondent must
determine if any features with similar characteristics are present elsewhere on the
Affected Segment. Respondent must submit documentation of this ILI review to the
Director within 45 days of receipt of this Safety Order as follows:
A. List all ILI tool runs, tool types, and the calendar years of the tool runs.
B. List, describe (type, size, wall loss, etc.), and identify the specific location of all ILI
features present in the failed joint and/or other pipe removed.
C. List, describe (type, size, wall loss, etc.), and identify the specific location of all ILI
features with similar characteristics present elsewhere on the Affected Segment.
D. Explain the process used to review the ILI results and the results of the
reevaluation.
9. Mechanical and Metallurgical Testing. Respondent developed a Work Plan and testing
protocol, assessment schedule, and commenced mechanical and metallurgical testing of
the failed segments by a third-party (Blade Energy Partners), as outlined in the Notice,
Corrective Action 9. Metallurgical testing of the failed segments commenced on July 30,
2018. To clarify, the testing protocol defines the requirement for five-day advanced
notice and that all testing reports are distributed simultaneously to OPS and Respondent.
In addition, daily progress reports and schedules of events from Blade Energy Partners
were disseminated to OPS. The final Failure Analysis Report prepared by Blade Energy
Partners, dated February 14, 2019, was submitted to OPS on February 22, 2019.
Accordingly, Respondent has completed the requirements of Corrective Action 9.
10. Root Cause Failure Analysis. Within 90 days following receipt of this Safety Order,
Respondent must complete a root cause failure analysis (RCFA) and submit a final report
of this RCFA to the Director. The RCFA must be supplemented and facilitated by an
independent third-party with prior written approval of the Director, and must document
the decision-making process used in the analysis and all factors contributing to the
Failure. The final report must include findings, any lessons learned, and whether the
findings and any lessons learned are applicable to other locations within Respondent’s
pipeline system.
11. Remedial Work Plan. On June 13, 2018, Respondent prepared an Integrity Verification
& Remedial Work Plan detailing the actions that it will, or already has, take to ensure the
continued integrity of the LEX pipeline. Geotechnical evaluations have been completed
along the entire LEX right-of-way and areas of concern identified. Measures to mitigate,
monitor and/or repair areas of identified land movement are underway. There are
currently no known conditions that would significantly impact the integrity of the
pipeline. Accordingly, Respondent has completed the requirements of Corrective Action
11.



CPF No. 1-2018-1016S
Page 7
12. Monthly Reports. Respondent must submit monthly reports to the Director that: (1)
include analysis of all available data and results of the testing and evaluations required by
this Safety Order; (2) describe the progress of repairs and other remedial actions being
undertaken; and (3) document all mandated actions and management of change plans to
ensure that all procedural modifications are incorporated into Respondent’s operations
and maintenance procedures manual. The first report will be due 30 days from issuance
of this Safety Order.
13. Safety Order Documentation Report (SODR). When Respondent has completed all the
corrective action items in this Safety Order, it must submit a final SODR in its entirety to
the Director. This will allow the Director to conduct a thorough review of all actions
taken by Respondent with regards to this Safety Order prior to approving the closure of
this Safety Order. The intent is for the SODR to summarize all activities and
documentation associated with this Safety Order in one document.
A. The Director may approve the SODR incrementally without approving the entire
SODR.
B. Once approved by the Director, the SODR will be incorporated by reference into
this Safety Order.
C. The SODR must include, but is not limited to:
i. Table of Contents;
ii. Summary of the Failure, and the response activities;
iii. Summary of pipe data/properties and all prior assessments of the Affected
Segment;
iv. Summary of all tests, inspections, assessments, evaluations, and analysis
required by this Safety Order;
v. Summary of the Mechanical and Metallurgical Testing as required by this
Safety Order;
vi. vii. Summary of the RCFA with all root causes as required by this Safety Order;
Documentation of all actions taken by Respondent to implement the RWP, the
results of those actions, and the inspection and repair criteria used;
viii. Documentation of any revisions to the RWP including those necessary to
incorporate the results of actions undertaken pursuant to this Safety Order and
whenever necessary to incorporate new information obtained during the
failure investigation and remedial activities;
Lessons learned while completing this Safety Order;
A path forward describing specific actions Respondent will take on its entire
pipeline system as a result of the lessons learned from work on this Safety
Order; and
xi. Appendices (if required).
With respect to each submission under this Safety Order that requires the approval of the
Director, the Director may: (a) approve, in whole or part, the submission; (b) approve the
submission on specified conditions; (c) modify the submission to cure any deficiencies; (d)
disapprove, in whole or in part, the submission, directing that Respondent modify the
submission; or (e) any combination of the above. In the event of approval, approval upon
conditions, or modification by the Director, Respondent shall take all required actions in the
ix. x.



CPF No. 1-2018-1016S
Page 8
submission as approved or modified by the Director. If the Director disapproves all or any
portion of the submission, Respondent shall correct all deficiencies within the time specified by
the Director, and resubmit it for approval. If a resubmitted item is disapproved in whole or in
part, the Director may again require Respondent to correct the deficiencies in accordance with
the foregoing procedure, and the Director may otherwise proceed to enforce the terms of this
Safety Order.
It is requested (not mandated) that Respondent maintain documentation of the safety
improvement costs associated with fulfilling this Safety 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.
The Director may grant an extension of time for compliance with any of the terms of this Safety
Order upon a written request timely submitted demonstrating good cause for an extension.
Respondent may appeal any decision of the Director to the Associate Administrator for Pipeline
Safety. Decisions of the Associate Administrator shall be final.
In your correspondence on this matter, please refer to CPF No. 1-2018-1016S and for each
document you submit, please provide a copy in electronic format whenever possible.
Be advised that all material you submit in response to this enforcement action is subject to being
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).
The actions taken pursuant to this Safety Order are in addition to and do not waive any
requirements that apply to Respondent’s pipeline system under 49 C.F.R. Parts 190 through 199,
under any other order issued to Respondent under authority of 49 U.S.C. Chapter 601, or under
any other provision of Federal or state law.
After receiving and analyzing additional data in the course of this proceeding and
implementation of the required tests and analysis, PHMSA may identify other safety measures
that need to be taken. In that event, Respondent will be notified of any proposed additional
measures and, if necessary, amendments to the Safety Order.
The terms and conditions of this Safety Order are effective upon service in accordance with 49
C.F.R. § 190.5.
October 10, 2019
___________________________________ __________________________
Alan K. Mayberry Date Issued
Associate Administrator
for Pipeline Safety

120181016S_Notice Of Proposed Safety Order_07092018_text.pdf

VIA FEDERAL EXPRESS MAIL AND FAX TO: (403) 920-2200
July 9, 2018
Mr. Randal Broussard
SVP, US Gas Operations East
Columbia Gas Transmission, LLC
201 Energy Parkway, Suite 100
Lafayette, LA 70508
CPF 1-2018-1016S
Dear Mr. Broussard:
Enclosed is a Notice of Proposed Safety Order (Notice) issued by the Pipeline and Hazardous
Materials Safety Administration (PHMSA) in the above-referenced case. The Notice proposes that
TransCanada take certain measures with respect to Columbia Gas Transmission, LLC’s Leach
Xpress (LEX) pipeline system, near Moundsville, WV. Your options for responding are set forth
in the Notice. Your receipt of the Notice constitutes service of that document under § 190.5.
We look forward to a successful resolution to ensure pipeline safety. Please direct any questions
on this matter to me at 609-771-7809.
Thank you for your cooperation in this matter.
Sincerely,
Robert Burrough
Director, Eastern Region
Pipeline and Hazardous Materials Safety Administration
Enclosure: Notice of Proposed Safety Order
Copy of 49 C.F.R. § 190.239
cc: Ms. Linda Daugherty, Deputy Associate Administrator for Field Operations, PHMSA
Mr. Stanley Chapman III, President, US Gas Pipelines, Columbia Midstream Group, LLC;
700 Louisiana Street, Suite 700, Houston, TX 77002



U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
_________________________________________
)
In the Matter of )
)
Columbia Gas Transmission, LLC, )
a subsidiary of TransCanada Corporation, ) )
)
CPF No. 1-2018-1016S
Respondent. )
_________________________________________ )
NOTICE OF PROPOSED SAFETY ORDER
Background and Purpose:
Pursuant to Chapter 601 of Title 49, United States Code, the Pipeline and Hazardous Materials
Safety Administration (PHMSA), U.S. Department of Transportation, has initiated an
investigation and information review of the safety of Columbia Gas Transmission, LLC’s, a
subsidiary of TransCanada Corporation (TransCanada or Respondent), Leach Xpress (LEX) gas
pipeline system.
The investigation was prompted after PHMSA was notified on June 7, 2018, by the National
Response Center of a reportable incident that occurred on the LEX pipeline system, which resulted
in the release of approximately 165 million cubic feet (MMCF) of natural gas, an ignition of natural
gas, and a fire (the Failure). The Failure resulted in the ejection of approximately 83 feet of 36-
inch pipe from the ditch onto the right of way. The Failure occurred in a remote, Class 1 rural
location and there were no reported injuries, fatalities or evacuations. The cause of the Failure has
not yet been determined.
As a result of the investigation, it appears conditions exist on your pipeline system that pose an
integrity risk to public safety, property, or the environment. Pursuant to 49 U.S.C. § 60117(1),
PHMSA, Office of Pipeline Safety (OPS), issues this Notice of Proposed Safety Order (Notice),
notifying you of the preliminary findings of the investigation, and proposing that you take certain
measures to ensure that the public, property, and the environment are protected from this integrity
risk.
Page 2 of 12



For the purposes of this Notice:
“Affected Segment” means the approximately 50 miles of TransCanada’s 30-inch and 36-inch
LEX Pipeline from the upstream Lone Oak Compressor Station (Mile Post 7.2) near
Lone Oak, WV within Marshall County through the downstream Summerfield Compressor Station
(MP 57.2) near Summerfield, OH in Noble County. The “Affected Segment” generally runs
westerly through portions of Noble and Monroe Counties in OH, and Marshall County in WV.
"Isolated Segment" means the approximately 14.35-mile segment of the LEX pipeline from the
upstream valve LEX-500 (MLV 2) at MP 18.5 to the downstream valve LEX-600 (MLV 3) at
MP 32. It is the portion of the “Affected Segment” that was shut-in after the failure on June 7, 2018
by closing MLV 2 (upstream of the failure) and MLV 3 (downstream of the failure) and that must
remain shut-in until a restart plan is approved by the “Director”.
"Director" means the Director, Pipeline and Hazardous Materials Safety Administration
(PHMSA), Office of Pipeline Safety, Eastern Region, 820 Bear Tavern Road Suite 103,
West Trenton, NJ 08628
Preliminary Findings:
 Columbia Gas Transmission, LLC, a subsidiary of TransCanada Corporation, operates
over 10,468 miles of interstate natural gas transmission pipelines, 37 storage fields across
four states, and transports an average of three billion cubic feet of natural gas per day
through New York, New Jersey, Pennsylvania, Maryland, Virginia, West Virginia, Ohio,
Kentucky, North Carolina and Delaware. Columbia Gas was acquired by TransCanada in
2016.1
 The failed pipeline is a 36-inch diameter line that transports natural gas and runs from
Majorsville, PA, to Crawford, OH, approximately 130 miles. The Failure occurred near
milepost 20.6, approximately seven miles south of Moundsville, WV (Failure Site).
 The Affected Segment runs along several hills and ridges with steep elevation changes.
The Failure Site is located on Nixon Ridge.
 The section of the Affected Segment near the Failure Site was constructed in 2017. The
pipeline at the Failure Site section consists of grade X-70, 36” steel pipe with a wall
thickness of 0.515” and 0.618”. The pipeline, which was manufactured by Durabond in
2015, has fusion bonded epoxy coating and double submerged arc welded (DSAW) seams.
The impressed current cathodic protection system has not been energized, but
1 See, TransCanada Website, available at https://www.transcanada.com/en/operations/natural-gas/columbia-gas-
transmission/(last accessed June 11, 2018)
Page 3 of 12



TransCanada is in the process of having it commissioned. Galvanic anodes were installed
at foreign lines crossings.
 The maximum allowable operating pressure (MAOP) of the Affected Segment is
1440 psig, as established by hydrostatic test in 2017. At the time of the Failure, the actual
operating pressure of the pipeline upstream from the Failure was 1280 psig; downstream
of the Failure at Eureka Metering Station, the operating pressure was 1243.7 psig.
 At approximately 4:55 a.m. EDT on June 7, 2018, TransCanada discovered a failure on
the LEX pipeline system, as determined by its gas controller, from a pressure drop
observation. The incident was determined to be a natural gas release, an ignition of natural
gas, and fire in the area of Moundsville, West Virginia. The Failure resulted in the ejection
of approximately 83 feet of 36-inch pipe from the ditch onto the right of way and the loss
of 165 MMCF of natural gas. The Failure occurred in a remote, Class 1 rural location.
There were no reported injuries, fatalities or evacuations. The Failure was reported to the
National Response Center (NRC Report No. 1214458) on June 7, 2018 at approximately
6:12 a.m. EDT.
 TransCanada isolated the Affected Segment via manual closure of LEX-500, a main line
valve (MLV) known as MLV 2, and LEX-600 (MLV 3) (Isolated Segment). MLV 2 is
located approximately 1.6 miles upstream of the Failure Site and was manually closed at
approximately 5:20 a.m. EDT. MLV 3 is located approximately 12.75 miles downstream
of the Failure Site and automatically closed at approximately 4:55 a.m. EDT. The
upstream Lone Oak compressor station’s compressor units were shut down via a
command issued from TransCanada’s Gas Control at approximately 4:36 a.m. EDT. In
addition, LEX-700, MLV 4, further downstream from MLV 3, automatically closed at
approximately 5:32 a.m. EDT.
 PHMSA, Roberts Ridge Volunteer Fire Department, West Virginia Department of
Environmental Protection, West Virginia Division of Forestry, and the Federal Energy
Regulatory Commission responded to the scene. PHMSA inspectors initiated an
investigation of the Failure on June 7, 2018.
 The Isolated Segment was shut-in via the closure of MLVs 2 and 3. The Isolated Segment
currently remains out of service.
 On December 12, 2017, TransCanada completed a hydrostatic test on test section LX1-
3A of the LEX pipeline, which includes the location of Failure. The section was
successfully tested for a duration of 8 hours to a minimum test pressure of 1880 psig. In
addition, on December 14, 2017, TransCanada ran an Enduro Digital Data Logger Caliper
tool from the Taylor B (746+11) launch site near Glen Easton, WV to Games Ridge
(1139+34.9) receive site near Moundsville, WV. The report was generated on
Page 4 of 12



December 20, 2017. On May 17th, 2018, a combo High-Resolution Magnetic Flux
Leakage (HR MFL) + Geo Tool was run with IMU. TransCanada has not yet received the
report from the combo HR MFL + Geo Tool run, but the vendor has been asked to provide
an expedited preliminary inline inspection report as soon as practicable due to the Failure.
PHMSA has not yet received the preliminary inline inspection report or any analysis from
the report.
 Since the Failure, TransCanada has identified six other points along the pipeline that,
based on their geotechnical flyover, are areas of concern due to the existence of large spoil
piles, steep slopes, or indications of slips. TransCanada has also performed minor repair
work and grading of the Failure Site.
 The PHMSA investigation is ongoing and the cause of the failure is unknown at this time.
The preliminary investigation suggests that the Failure was the result of land subsidence
causing stress on a girth weld.
 PHMSA has issued several Advisory Bulletins of note, including Advisory Bulletin
ADB 97-03 on March 4, 1997 entitled “Potential Soil Subsidence on Pipeline Facilities,”
cautioning owners and operators of possible hazards relating to soil subsidence on pipeline
facilities, and advising the need to monitor the potential impact of flooding and soil
subsidence on those facilities. PHMSA also issued Advisory Bulletin, ADB 12-06 on
May 7, 2012, entitled “Verification of Records Establishing MAOP and MOP,” advising
operators of gas transmission pipelines and associated facilities to verify that their records
confirm their MAOP and MOP.
Proposed Issuance of Safety Order:
Section 60117(1) of Title 49, United States Code, provides for the issuance of a safety order, after
reasonable notice and the opportunity for a hearing, requiring corrective action, which may include
physical inspection, testing, repair, replacement, or other action, as appropriate. The basis for
making the determination that a pipeline facility has a condition or conditions that pose a pipeline
integrity risk to public safety, property, or the environment is set forth both in the above referenced
statute and 49 C.F.R. § 190.239, a copy of which is enclosed.
After evaluating the foregoing preliminary findings of fact and considering the location of the
Failure Site on Nixon Ridge, the identification of six additional areas of concern based on the
existence of large spoil piles, steep slopes, or indications of slips, the fact that subsidence or
slippage could lead to additional failures of the pipeline in areas with similar geological conditions,
the fact that the Affected Segment was operating between approximately 86-89% of its MAOP at
the time of the Failure, the hazardous nature of the natural gas transported, the age of the pipe, and
the ongoing investigation to determine the cause of the failure, it appears that the continued
operation of the Affected Segment, without corrective measures, poses a pipeline integrity risk to
Page 5 of 12



public safety, property, and the environment.
Accordingly, PHMSA issues this Notice of Proposed Safety Order to notify Respondent of the
proposed issuance of a safety order and to propose that Respondent take measures specified herein
to address the potential risk
Proposed Corrective Actions:
Pursuant to 49 U.S.C. § 60117(1) and 49 C.F.R. § 190.239, PHMSA proposes to issue to
TransCanada Corporation a safety order incorporating the following remedial requirements with
respect to the Affected Segment and Isolated Segment:
1. Review of Isolated Segment. TransCanada must review and inspect the Isolated Segment
for conditions similar to those of the Failure including a review of construction, operating
and maintenance (O&M) and integrity management records such as in-line inspection
(ILI) results, hydrostatic tests, root cause failure analysis of the Failure, aerial and ground
patrols, cathodic protection, excavations and pipe replacements. Respondent must address
any findings that require remedial measures to be implemented within 30 days of
discovery.
2. Enhanced surveillance and monitoring. TransCanada must provide for enhanced
patrolling and surveillance of the Isolated Segment until the cause of the Failure is
determined.
3. Installation of Strain Gauges. Within 45 days of receipt of the final Safety Order,
TransCanada must install at least six (6) strain gauges on the pipeline in the immediate
area of the Failure. TransCanada must also determine if additional locations exist along
the Affected Segment with conditions similar to the Failure site and install strain gauges.
Hydrostatic Testing. TransCanada must provide for hydrostatic pressure testing of any
pipe installed in the Isolated Segment.
5. Weather Contingency Plan. Within 30 days of receipt of the final Safety Order,
TransCanada must submit to the Director a contingency plan to operate and monitor the
Isolated Segment during saturated soil or flooding conditions, including enhanced
patrolling and surveillance.
6. Instrumented Leakage Survey. Within 30 days of receipt of the final Safety Order,
TransCanada must perform an aerial or ground instrumented leakage survey of the
Affected Segment. TransCanada must investigate all leak indications and remedy all leaks
discovered. TransCanada must submit documentation of this survey to the Director within
45 days of receipt of the final Safety Order.
7. Records Verification. As recommended in PHMSA Advisory Bulletin 2012-06,
TransCanada must verify the records for the Affected Segment to confirm the maximum
4. Page 6 of 12



operating pressure or MAOP. TransCanada must submit documentation of this record
verification to the Director within 45 days of receipt of the final Safety Order.
8. Review of Prior Inline Inspection (ILI) Results. Within 30 days of receipt of the final
Safety Order, TransCanada must conduct a review of any previous inline inspection (ILI)
results of the Affected Segment. TransCanada must re-evaluate all ILI results, including a
review of the ILI vendors' raw data and analysis. TransCanada must determine whether
any features were present in the failed pipe joint and any other pipe removed. Also,
TransCanada must determine if any features with similar characteristics are present
elsewhere on the Affected Segment. TransCanada must submit documentation of this ILI
review to the Director within 45 days of receipt of the final Safety Order as follows:
A. List all ILI tool runs, tool types, and the calendar years of the tool runs.
B. List, describe (type, size, wall loss, etc.), and identify the specific location of all ILI
features present in the failed joint and/or other pipe removed.
C. List, describe (type, size, wall loss, etc.), and identify the specific location of all ILI
features with similar characteristics present elsewhere on the Affected Segment.
D. Explain the process used to review the ILI results and the results of the reevaluation.
9. Mechanical and Metallurgical Testing. Within 45 days of receipt of the final Safety
Order, TransCanada must arrange for third-party mechanical and metallurgical testing
and failure analysis of the failed pipe, including an analysis of soil samples and any
foreign materials. TransCanada must complete the testing and analysis as follows:
A. Document the chain-of-custody when handling and transporting the failed pipe
section and other evidence from the failure site.
B. Within 10 days of receipt of the final Safety Order, develop and submit the testing
protocol and the proposed testing laboratory to the Director for prior approval.
C. At least five days prior to beginning the mechanical and metallurgical testing, provide
the Director with the scheduled date, time, and location of the testing to allow for a
PHMSA representative to witness the testing.
D. Ensure the testing laboratory distributes all reports whether draft or final in their
entirety to the Director at the same time they are made available to TransCanada.
10. Root Cause Failure Analysis. Within 90 days following receipt of the final Safety Order,
TransCanada must complete a root cause failure analysis (RCFA) and submit a final
report of this RCFA to the Director. The RCFA must be supplemented and facilitated by
an independent third party with prior written approval of the Director, and must document
the decision-making process used in the analysis and all factors contributing to the
Failure. The final report must include findings, any lessons learned, and whether the
Page 7 of 12



findings and any lessons learned are applicable to other locations within TransCanada
pipeline system.
11. Remedial Work Plan. Within 90 days following receipt of the final Safety Order,
TransCanada must submit a Remedial Work Plan (RWP) to the Director for approval.
The Director may approve the RWP incrementally without approving the entire RWP.
TransCanada must revise the RWP as necessary to incorporate new information obtained
during the failure investigation and remedial activities, to incorporate the results of
actions undertaken pursuant to the final Safety Order, and to incorporate modifications
required by the Director. TransCanada must submit any such plan revisions to the Director
for prior approval. The Director may approve plan revisions incrementally. Once
approved by the Director, the RWP, and any revisions, will be incorporated by reference
into the final Safety Order. TransCanada must implement the RWP as approved by the
Director, including any revisions to the plan. The RWP must:
A. Specify the tests, inspections, assessments, evaluations, and remedial measures
TransCanada will use to verify the integrity of the Affected Segment. It must address
all known or suspected factors and causes of the June 7, 2018 failure. TransCanada
should consider both the risk of another failure and the consequence of another
failure to develop a prioritized schedule for RWP related work along the Affected
Segment.
B. Include a procedure or process to identify pipe in the Affected Segment with
characteristics similar to the contributing factors identified for the June 7, 2018
failure.
C. Include a procedure or process to gather all data necessary to review the failure
history (in service and pressure test failures) of the Affected Segment and to prepare
a written report containing all the available information such as the locations, dates,
and causes of leaks and failures.
D. Include a procedure or process to integrate the results of the metallurgical testing,
root cause failure analysis, and other corrective actions required by the final Safety
Order with all relevant pre-existing operational and assessment data for the Affected
Segment. Pre-existing operational data includes, but is not limited to, construction,
operations, maintenance, testing, repairs, prior metallurgical analyses, and any
third-party consultation information. Pre-existing assessment data includes, but is
not limited to, ILI tool runs, hydrostatic pressure testing, direct assessments, close
interval surveys, and DCVG/ACVG surveys.
E. Include a procedure or process to determine if conditions similar to those
contributing to the failure on June 7, 2018 are likely to exist elsewhere on the
Affected Segment.
F. Include a procedure or process to conduct additional field tests, inspections,
Page 8 of 12



assessments, and/or evaluations to determine whether, and to what extent, the
conditions associated with the failure on June 7, 2018 or any other integrity threats
are present elsewhere on the Affected Segment. At a minimum, this process must
consider all failure causes and specify the use of one or more of the following:
i. Inline inspection (ILI) tools that are technically appropriate for assessing the
pipeline system based on the cause of failure on June 7, 2018, and that can
reliably detect and identify anomalies,
ii. Hydrostatic pressure testing,
iii. Close-interval surveys,
iv. Cathodic protection surveys, to include interference surveys in coordination
with other utilities (e.g. underground utilities, overhead power lines, etc.) in
the area,
v. Coating surveys,
vi. Stress corrosion cracking surveys,
vii. Selective seam corrosion surveys; and,
viii. Other tests, inspections, assessments, and evaluations appropriate for the
failure causes.
Note: TransCanada may use the results of previous tests, inspections, assessments, and
evaluations if approved by the Director, provided the results of the tests, inspections,
assessments, and evaluations are analyzed with regard to the factors known or suspected
to have caused the June 7, 2018 failure.
G. Describe the inspection and repair criteria TransCanada will use to prioritize,
excavate, evaluate, and repair anomalies, imperfections, and other identified
integrity threats. Include a description of how any defects will be graded and a
schedule for repairs or replacement.
H. Based on the known history and condition of the Affected Segment, describe the
methods TransCanada will use to repair, replace, or take other corrective measures
to remediate the conditions associated with the pipeline failure on June 7, 2018, and
to address other known integrity threats along the Affected Segment. The repair,
replacement, or other corrective measures must meet the criteria specified in
paragraph G, above.
I. Include a procedure or process to implement continuing long-term periodic testing
and integrity verification measures to ensure the ongoing safe operation of the
Affected Segment considering the results of the analyses, inspections, evaluations,
and corrective measures undertaken pursuant to the final Safety Order.
J. Include a proposed schedule for completion of the RWP.
Page 9 of 12



12. Monthly Reports. TransCanada must submit monthly reports to the Director that: (1)
include analysis of all available data and results of the testing and evaluations required by
the final Safety Order; (2) describe the progress of repairs and other remedial actions
being undertaken; and (3) document all mandated actions and management of change
plans to ensure that all procedural modifications are incorporated into TransCanada’s
operations and maintenance procedures manual. The first report will be due 30 days from
issuance of the final Safety Order.
13. Safety Order Documentation Report (SODR). When TransCanada has completed all the
items in the final Safety Order it will submit a final SODR in its entirety to the Director.
This will allow the Director to conduct a thorough review of all actions taken by
TransCanada with regards to the final Safety Order prior to approving the closure of the
final Safety Order. The intent is for the SODR to summarize all activities and
documentation associated with the final Safety Order in one document.
A. The Director may approve the SODR incrementally without approving the entire
SODR.
B. Once approved by the Director, the SODR will be incorporated by reference into the
final Safety Order.
C. The SODR must include but is not limited to:
1. Table of Contents;
2. Summary of the pipeline failure of June 7, 2018, and the response activities;
3. Summary of pipe data/properties and all prior assessments of the Affected
Segment;
4. Summary of all tests, inspections, assessments, evaluations, and analysis required
by the final Safety Order;
5. Summary of the Mechanical and Metallurgical Testing as required by the final
Safety Order;
6. Summary of the RCFA with all root causes as required by the final Safety Order;
7. Documentation of all actions taken by TransCanada to implement the RWP, the
results of those actions, and the inspection and repair criteria used;
8. Documentation of any revisions to the RWP including those necessary to
incorporate the results of actions undertaken pursuant to the final Safety Order
and whenever necessary to incorporate new information obtained during the
failure investigation and remedial activities;
9. Lessons learned while completing the final Safety Order;
Page 10 of 12



10. A path forward describing specific actions TransCanada will take on its entire
pipeline system as a result of the lessons learned from work on the final Safety
Order; and
11. Appendices (if required).
With respect to each submission under the final Safety Order that requires the approval of the
Director, the Director may: (a) approve, in whole or part, the submission; (b) approve the
submission on specified conditions; (c) modify the submission to cure any deficiencies;
(d) disapprove, in whole or in part, the submission, directing that Respondent modify the
submission; or (e) any combination of the above. In the event of approval, approval upon
conditions, or modification by the Director, Respondent shall take all required actions in the
submission as approved or modified by the Director. If the Director disapproves all or any portion
of the submission, Respondent shall correct all deficiencies within the time specified by the
Director, and resubmit it for approval. If a resubmitted item is disapproved in whole or in part, the
Director may again require Respondent to correct the deficiencies in accordance with the foregoing
procedure, and the Director may otherwise proceed to enforce the terms of the final Safety Order.
The Director may grant an extension of time for compliance with any of the terms of the final
Safety Order upon a written request timely submitted demonstrating good cause for an extension.
TransCanada may appeal any decision of the Director to the Associate Administrator for Pipeline
Safety. Decisions of the Associate Administrator shall be final.
The actions proposed by this Notice are in addition to and do not waive any requirements that
apply to Respondent's pipeline system under 49 C.F.R. Parts 190 through 199, under any other
order issued to Respondent under authority of 49 U.S.C. § 60101 et seq., or under any other
provision of Federal or state law.
After receiving and analyzing additional data in the course of this investigation, PHMSA may
identify other corrective measures that need to be taken. In that event, Respondent will be notified
of any additional measures required and amendment of the final Safety Order will be considered.
To the extent consistent with safety, Respondent will be afforded notice and an opportunity for a
hearing prior to the imposition of any additional corrective measures.
Response to this Notice:
In accordance with § 190.239, you have 30 days following receipt of this Notice to submit a written
response to the Director. If you do not respond within 30 days, this constitutes a waiver of your
rights to contest 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 Safety Order. In
your response, you may indicate that you intend to comply with the terms of the Notice as
proposed, or you may request that an informal consultation be scheduled (you will also have the
opportunity to request an administrative hearing before a final Safety Order is issued). Informal
consultation provides you with an opportunity to explain the circumstances associated with the
risk conditions alleged in the Notice and, as appropriate, to present a proposal for a work plan or
other remedial measures, without prejudice to your position in any subsequent hearing.
If you and PHMSA agree within 30 days of informal consultation on a plan and schedule for you
Page 11 of 12



to address each identified risk condition, the parties may enter into a written consent agreement,
in which case PHMSA would then issue an administrative Consent Order incorporating the terms
of the agreement. If a consent agreement is not reached, or if you have elected not to request
informal consultation, you may request an administrative hearing in writing within 30 days
following receipt of the Notice or within 10 days following the conclusion of an informal
consultation that did not result in a consent agreement, as applicable. Following a hearing, if the
Associate Administrator finds the facility to have a condition that poses a pipeline integrity risk to
the public, property, or the environment in accordance with § 190.239, the Associate Administrator
may issue a final Safety Order.
Be advised that all material submitted in response to this enforcement action is subject to public
availability. 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).
In your correspondence on this matter, please refer to CPF No. 1-2018-1016S and for each
document you submit, please provide a copy in electronic format whenever possible.
7/9/2018
_________________________________ _____________________
Robert Burrough Date issued
Director, Eastern Region
Pipeline and Hazardous Materials Safety Administration
Page 12 of 12

120181016S_Closure Letter_03022020_text.pdf

OVERNIGHT EXPRESS DELIVERY
March 2, 2020
Mr. Stanley Chapman
Senior VP, US NG Pipelines
TC Energy
700 Louisiana Street
Houston, Texas 77002
CPF 1-2018-1016S
Dear Mr. Chapman:
On July 9, 2018, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a
Notice of Proposed Safety Order (NOPSO) with regard to the June 7, 2018 Leach Xpress pipeline
failure incident of TC Energy’s subsidiary, Columbia Gas Transmission, LLC (Columbia). On
October 10, 2019, PHMSA issued a Safety Order (SO) pursuant to the NOPSO referenced above.
The Safety Order included a list of various required Corrective Actions.
We have received an email and Safety Order Documentation Report (SODR) dated January 31,
2020, from Mr. Lee Romack, Director, Pipelines Regulatory Compliance at TC Energy. The
SODR was submitted as part of the final Corrective Action deliverable, required under item 13 of
the SO. Simultaneously, the email requested closure of the SO.
Based on our review of the documentation, it has been determined that your subsidiary, Columbia,
has 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 in this matter.
Sincerely,
Robert Burrough
Director, Eastern Region
Pipeline and Hazardous Materials Safety Administration
Cc (via electronic mail):
Mr. Lee Romack, Director, Pipelines Regulatory Compliance, TC Energy

## Provenance

- Official: Yes
- Source: <https://primis.phmsa.dot.gov/enforcement-data/case/120181016S>
- Source ID: `phmsa-enforcement`
- SHA-256: `37eb4e0c1b8d40f9094c547e29fc330b1d587477d349dae7ab04f6d1903f0105`
- Retrieved: 2026-08-20T04:44:44.458Z
- Exported: 2026-08-23T19:36:12.963Z
- Document slug: `phmsa-enforcement-120181016s`

### Source metadata

```json
{
  "cpf": "120181016S",
  "operator": "COLUMBIA GAS TRANSMISSION, LLC",
  "region": "Eastern",
  "pipelineType": "GAS INTERSTATE ONSHORE",
  "caseStatus": "CLOSED",
  "citedSections": [],
  "dataAsOf": "08/04/2026 12PM",
  "caseDataAsOf": "2026-08-04",
  "attachmentCount": 7,
  "attachments": [
    {
      "name": "120181016S_Closure Letter_03022020.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Closure%20Letter_03022020.pdf",
      "bytes": 1115783,
      "category": "agency_document"
    },
    {
      "name": "120181016S_Closure Letter_03022020_text.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Closure%20Letter_03022020_text.pdf",
      "bytes": 81067,
      "category": "agency_document"
    },
    {
      "name": "120181016S_Notice Of Proposed Safety Order_07092018.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Notice%20Of%20Proposed%20Safety%20Order_07092018.pdf",
      "bytes": 1093709,
      "category": "agency_document"
    },
    {
      "name": "120181016S_Notice Of Proposed Safety Order_07092018_text.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Notice%20Of%20Proposed%20Safety%20Order_07092018_text.pdf",
      "bytes": 215966,
      "category": "agency_document"
    },
    {
      "name": "120181016S_Operator Response to Notice_08082018.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Operator%20Response%20to%20Notice_08082018.pdf",
      "bytes": 249183,
      "category": "party_submission"
    },
    {
      "name": "120181016S_Safety Order_10102019.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Safety%20Order_10102019.pdf",
      "bytes": 1452279,
      "category": "agency_document"
    },
    {
      "name": "120181016S_Safety Order_10102019_text.pdf",
      "url": "https://primis.phmsa.dot.gov/enforcement-documents/120181016S/120181016S_Safety%20Order_10102019_text.pdf",
      "bytes": 172151,
      "category": "agency_document"
    }
  ],
  "extractedAgencyDocumentCount": 3,
  "attachmentPolicy": "Official attachment links are retained. Agency-issued documents may also include a verified local PDF and page-level text representation.",
  "jurisdiction": "US",
  "operatorName": "COLUMBIA GAS TRANSMISSION, LLC"
}
```