# EXPRESS HOLDINGS (USA), LLC — Notice of Probable Violation

- **operation:** document
- **citation:** CPF 320205005
- **title:** EXPRESS HOLDINGS (USA), LLC — Notice of Probable Violation
- **source type:** enforcement
- **agency:** Pipeline and Hazardous Materials Safety Administration
- **status:** historical
- **official:** true
- **published on:** 2020-03-19
- **effective on:** Not available
- **summary:** CLOSED notice of probable violation citing 195.401(b)(1), 195.406(a)(3), 195.406(b), 195.410(a)(1), 195.410(a)(2)(ii), 195.412(a), 195.581(a), 195.583(b).
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- **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/320205005
**body:**

Notice of Probable Violation involving EXPRESS HOLDINGS (USA), LLC. PHMSA's enforcement data identifies the cited regulations as 195.401(b)(1),  195.406(a)(3),  195.406(b),  195.410(a)(1),  195.410(a)(2)(ii),  195.412(a),  195.581(a),  195.583(b). The case was opened on 2020-03-19 and is reported as closed as of 2021-08-16. Proposed civil penalty: $346,400. Assessed civil penalty: $264,500. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

320205005_Decision on Petition for Reconsideration_07262021_(16-153538S).pdf: https://primis.phmsa.dot.gov/enforcement-documents/320205005/320205005_Decision%20on%20Petition%20for%20Reconsideration_07262021_(16-153538S).pdf

320205005_Decision on Petition for Reconsideration_07262021_(16-153538S)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320205005/320205005_Decision%20on%20Petition%20for%20Reconsideration_07262021_(16-153538S)_text.pdf

320205005_Final Order_05202021_(16-153538S).pdf: https://primis.phmsa.dot.gov/enforcement-documents/320205005/320205005_Final%20Order_05202021_(16-153538S).pdf

320205005_Final Order_05202021_(16-153538S)_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320205005/320205005_Final%20Order_05202021_(16-153538S)_text.pdf

320205005_NOPV PCP_03192020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320205005/320205005_NOPV%20PCP_03192020.pdf

320205005_NOPV PCP_03192020_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320205005/320205005_NOPV%20PCP_03192020_text.pdf

320205005_Operator Petition for Reconsideration_06092021_(16-153538S).pdf: https://primis.phmsa.dot.gov/enforcement-documents/320205005/320205005_Operator%20Petition%20for%20Reconsideration_06092021_(16-153538S).pdf

320205005_Operator Post-Hearing Submission_11232020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320205005/320205005_Operator%20Post-Hearing%20Submission_11232020.pdf

320205005_Operator Pre-Hearing Submission_10132020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320205005/320205005_Operator%20Pre-Hearing%20Submission_10132020.pdf

320205005_Operator Response to Notice and Request for Hearing and Statement of Issues_07032020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320205005/320205005_Operator%20Response%20to%20Notice%20and%20Request%20for%20Hearing%20and%20Statement%20of%20Issues_07032020.pdf

320205005_PHC Hearing Scheduled_07202020.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320205005/320205005_PHC%20Hearing%20Scheduled_07202020.pdf

320205005_PHC Hearing Scheduled_07202020_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/320205005/320205005_PHC%20Hearing%20Scheduled_07202020_text.pdf

320205005_Final Order_05202021_(16-153538S)_text.pdf

May 20, 2021
VIA ELECTRONIC MAIL TO: ver.yu@enbridge.com
Mr. Vern Yu
Executive Vice President and President, Liquid Pipelines
Enbridge, Inc.
200 Fifth Avenue Place
425 – 1st Street S.W.
Calgary, Alberta, Canada T2P 3L8
Re: CPF No. 3-2020-5005
Dear Mr. Yu:
Enclosed please find the Final Order issued in the above-referenced case to your subsidiary,
Express Holdings (USA), LLC. It withdraws one allegation of violation, makes findings of
violation, and assesses a civil penalty of $264,500. The penalty payment terms are set forth in
the Final Order. This enforcement action closes automatically upon receipt of payment. 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
Mr. Darren Hunter, Hunter Masalski LLC, Counsel for Enbridge, darren@huntermasalski.com
Mr. David Stafford, Manager, U.S. Compliance, Enbridge, david.stafford@enbridge.com
Mr. Michael Koby, Vice President, U.S. Operations, Enbridge, michael.koby@enbridge.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 )
Express Holdings (USA), LLC, ) CPF No. 3-2020-5005
a subsidiary of Enbridge, Inc., )
)
)
)
Respondent. )
____________________________________)
FINAL ORDER
Between November 14, 2016 and February 3, 2017, pursuant to 49 U.S.C. § 60117, representatives
of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety
(OPS), conducted an on-site pipeline safety inspection of the Platte pipeline system based in Casper,
Wyoming operated by Express Holdings (USA), LLC (Express or Respondent). Express operates
the Platte crude oil pipeline system consisting of approximately 933 miles of 20-inch diameter pipe,
33 storage/breakout tanks, and 19 pump stations running from Casper Wyoming to Wood River
Illinois.1 Express is a subsidiary of Enbridge, Inc. which acquired the system through a merger with
Spectra Energy Corporation in February of 2017.2
As a result of the inspection, the Director, Central Region, OPS (Director), issued to Respondent, by
letter dated March 19, 2020, a Notice of Probable Violation and Proposed Civil Penalty (Notice),
which also included a warning pursuant to 49 C.F.R. § 190.205. In accordance with 49 C.F.R.
§ 190.207, the Notice proposed finding that Express had committed eight violations of 49 C.F.R.
Part 195, two of which were warning items. The Notice proposed assessing a civil penalty of
$346,400 for six of the alleged violations. The two warning items required no further action, but
warned Respondent to correct the probable violations or face possible future enforcement action.
After being granted an extension of time by the Director, Express responded to the Notice by letter
dated July 3, 2020 (Response). Express contested three of the allegations and requested a hearing.
A hearing was subsequently held on October 23, 2020, via video teleconference before a PHMSA
Presiding Official. At the hearing, Respondent was represented by counsel. Respondent provided
additional written material for the record prior to the heating on October 13, 2020 (Pre-hearing
submission) and following the hearing on November 23, 2020 (Post-hearing submission). The
1 PHMSA Safety Violation Report (Violation Report), (March 19, 2020) (on file with PHMSA), at 1.
2 Enbridge, Inc. website, Enbridge’s Energy Infrastructure Assets, Factsheet 53, available at
https://www.enbridge.com/~/media/Enb/Documents/Factsheets/FS EnergyInfrastructureAssets.pdf?la=en (last visited
April 22, 2021). Spectra Energy Corporation acquired the Platte pipeline system from Kinder Morgan Pipelines (USA)
Inc. in March of 2013.



CPF No. 3-2020-5005
Page 2
Director submitted a post-hearing recommendation on December 23, 2020 (Recommendation).
FINDINGS OF VIOLATION
The Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows:
Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.401(b)(1), which states:
§ 195.401 General requirements.
(a)…
(b) An operator must make repairs on its pipeline system
according to the following requirements:
(1) Non Integrity management repairs. Whenever an
operator discovers any condition that could adversely affect the
safe operation of its pipeline system, it must correct the
condition within a reasonable time. However, if the condition is
of such a nature that it presents an immediate hazard to persons
or property, the operator may not operate the affected part of the
system until it has corrected the unsafe condition.
The Notice alleged that Respondent violated 49 C.F.R. § 195.401(b)(1) by failing to make non-
integrity management repairs on its pipeline system within a reasonable time after it discovered a
condition that could adversely affect the safe operation of the pipeline system. Specifically, the
Notice alleged that between July 10, 2013 and August 24, 2018, Respondent operated the pipeline
with a condition that permitted the pressure of the pipeline to potentially exceed 110 percent of the
Maximum Operating Pressure (MOP) in the event of an inadvertent mainline-valve closure, power
failure, loss of communication, or other abnormal operation. The Notice cited a transient study
conducted by Respondent’s predecessor that identified the risk of overpressure conditions and set
forth recommendations designed to prevent the pipeline pressure from exceeding 110 percent of the
MOP. This included a recommendation for the installation of an Automated Pipeline Shutdown
(APS) between Casper and Salisbury and the modification of an existing APS between Salisbury
and Wood River.3
In its Response and at the hearing, Respondent argued that it complied with the applicable
regulations and requested that the allegation and the associated proposed civil penalty be withdrawn.
Respondent argued that transient study, which was commissioned by the prior operator, contained
recommendations, not mandates. Respondent stated that there is no regulatory requirement under
Part 195, including under the Control Room Management (CRM) standard set forth in Section
195.446, for operators to install an APS making the installation of an APS a voluntary measure that
would supplement existing practices and provide an additional layer of surge protection.4 In its
response and at the hearing, Respondent described these existing protections and noted the lack of
instances where the MOP was actually exceeded by 110 percent as tending to corroborate that the
3 These actions were ultimately taken after another transient study was conducted by Respondent in August of 2018.
4 Post-hearing submission, at 4.



CPF No. 3-2020-5005
Page 3
surge protections in place were effective.5
For its part, OPS maintained that the transient study identified conditions where abnormal operation
would result in 110 percent exceedance at various locations on the pipeline and served to identify
the need for action to address the potential for overpressure conditions.6 The transient study stated,
in pertinent part:
4.2.1.1 No Surge Mitigation --- Without the relief and HULP
Neither relief nor [High Upstream Line Pressure] HULP were
installed in these stations and mainline valves: Douglas, Yoder,
Harrisburg, Centralia, Monte, Ethlyn, Howpoint, Troy, Daniel
and Wood River ESDV4003, the simulation results show:
 Douglas and Centralia: complies with the code (ASME B31.4 –
2009) in that the maximum transient surge pressure is less than
110% MOP if the mainline valve fail closed.
 Yoder, Harrisburg, Monte and Ethlyn: do NOT comply with the
code (ASME B31.4 – 2009) in that the maximum transient surge
pressure is greater than 110% MOP if the mainline valve fail
closed.
 Hawpoint, Troy and Daniel: do NOT comply with the code
(ASME B31.4 – 2009) in that the maximum transient surge
pressure is greater than 110% MOP if the mainline valve fail
closed.
 Wood River ESDV4003: this valve located upstream of the relief
valve, does NOT comply with the code (ASME B31.4 – 2009) in
that the maximum transient surge pressure is greater than 110%
MOP if fail closed.
The simulation shows that either relief or HULP should be
considered in order to comply with the code and ensure the
pipeline safety for the following stations and mainline valves:
Yoder, Harrisburg, Monte, Ethlyn, Hawpoint, Troy, Daniel and
Wood River ESDV4003.7
Thus, the transient study concluded that due to the absence of surge mitigation at certain pump
stations, the pipeline would not comply with ASME B31.4-2009 (“Pipeline Transportation Systems
for Liquid Hydrocarbons and Other Liquids”) if the mainline valves fail-closed, because the
5 Post-hearing submission, at 5.
6 Recommendation, at 4.
7 Transient Study, at 11.



CPF No. 3-2020-5005
Page 4
maximum surge pressure would exceed 110 percent of the MOP. Respondent noted that ASME
B31.4 is not incorporated by reference in Section 195.401(b)(1), and is only incorporated by
reference in Sections 195.110(a) and 195.452(b). (See 49 C.F.R. § 195.3). Respondent is correct
that it would be inappropriate for PHMSA to rely on this consensus standard to support a regulatory
requirement to install an APS. However, the manner in which this standard was referenced in the
transient study is indicative of Respondent’s awareness that its existing overpressure protections
were not sufficient to meet consensus industry practices.
OPS also noted that in addition to the transient study, the potential overpressure condition had been
identified in 2014 in Facility Procedure Modification Request (FPMR) #2108. FPMR #2108 calls
for a solution to address potential surges associated with an unplanned valve failure. The FPMR
stated, in pertinent part:
As a result of the recently completed PHMSA Inspection on the
Platte Pipeline System, a solution is required to prevent
prolonged exceedances of the licensed Maximum Allowable
Operating Pressure as measured by the discharge pressure
transmitters. This is applicable to two pump stations -
Harrisburg and Marysville.8
In response to Respondent’s contention that it had sufficient overpressure protections in place that
made further action to address the potential safety condition identified in the transient study
unnecessary, OPS pointed out that the Wood River relief valve had been improperly set and had to
be lowered from 260 to 218 psi in 2016.9 OPS also pointed to the fact that incorrect set-points were
in place for the supervisory control and data acquisition (SCADA) controls at the Harrisburg Pump
Station and the Marysville Pump Station during the relevant time frame. OPS explained that if
Respondent had reviewed the required hydrostatic pressure test information and set up a new surge
analysis, these inaccurate controls could have been identified and corrected, but instead incorrect
set-points continued for an extended period of time.10 In discussing the notable absence of a surge
analysis being performed, Respondent stated that it had incorporated additional block valves with
instrumentation. OPS believed that this type of change would itself call for a new surge analysis
since the addition of these valves could actually make the transients worse if not properly controlled
through proper set-points on discharge pressure and adequate employment of valve timing.11
Finally, if the pressure control measures identified by Respondent as having been sufficient to
address the overpressure condition such as adherence to its control room management procedures
had been adequate, there would have been no need to issue MOC 2018-246 in 2018, which
ultimately implemented APS and changes to APS systems.12
Having considered these arguments, I find that Respondent had sufficient information identifying
8 Violation Report, Exhibit A.
9 Recommendation, at 8.
10 Recommendation, at 9.
11 Recommendation, at 6.
12 Recommendation, at 10.



CPF No. 3-2020-5005
Page 5
potential overpressure conditions that could adversely affect the safe operation of its pipeline system
that action was required to address these conditions under the cited regulation. While Respondent is
correct that the particular remedy recommended by the transient study—installation of an APS—is
not a code requirement, some action that would have addressed the potential overpressure condition
in a comparably effective manner was required by the cited regulation. OPS met its burden of
showing that Respondent did not take action that would have been comparable to an APS to address
the adverse condition on its system identified in the transient study and the FPMR.
Accordingly, after considering all of the evidence and the legal issues presented, I find that
Respondent violated 49 C.F.R. § 195.401(b)(1) by failing to make non-integrity management repairs
on its pipeline system within a reasonable time after it discovered a condition that could adversely
affect the safe operation of the pipeline system.
Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.406(a)(3), which states:
§ 195.406 Maximum operating pressure.
(a) Except for surge pressures and other variations from
normal operations, no operator may operate a pipeline at a
pressure that exceeds any of the following:
(1)…
(3) Eighty percent of the test pressure for any part of the
pipeline which has been pressure tested under subpart E of this
part.
The Notice alleged that Respondent violated 49 C.F.R. § 195.406(a)(3) by operating a part of its
pipeline at a pressure that exceeded 80 percent of the test pressure of the pipeline portion that had
been tested under Subpart E of Part 195. Specifically, the Notice alleged 22 instances in which the
actual discharge pressure exceeded 80 percent of test pressure (Maximum Operating Pressure or
MOP) at the Harrisburg, Holdrege, Blue Hill, Deshler, Marysville, and Quote pump stations.
In its Response and at the hearing, Respondent argued that it complied with the applicable
regulations and requested that the allegation and the associated proposed civil penalty be withdrawn.
Express contended that the cited incidents were either surges or other variations from normal
operations, as permitted under Section 195.406(a), were permissible calibrations, or otherwise did
not exceed MOP.13 At the hearing, OPS stated that having had an opportunity to review new
documentation that was not provided at the time of the inspection but newly submitted by Express at
the hearing, it would no longer pursue violations for 20 of the 22 alleged incidents, but stated that it
still had questions regarding the following two incidents at Marysville Pump Station:
13 Post-hearing submission at 6.



Month of Pressure
Exceedance
Hydrostatic Test
Pressure (psi)
Actual Discharge
Pressure (psi)
1/2015 1424 1139.2 1144.138551
1/2016 1424 1139.2 80% of Test Pressure 1166.845526
Express argued that the two remaining incidents, like the other 20, were permissible surges or
other variations from normal operations, or otherwise did not exceed 80 percent of test
pressure.14 At the hearing, Express presented testimony from its Technical Services Operations
Specialist explaining why the two referenced events were not violations of Section
195.406(a)(3). In reviewing the data, this individual explained that there was a change in the
SCADA system after Enbridge became the pipeline owner. In August of 2017, the legacy
OASyS SCADA system was replaced by a new CygNet SCADA system and records transferred
to the new system. Express presented evidence that this incident was very brief (less than 1
minute) and a very minor exceedance (only 100.1 percent of MOP). Regarding the January 2016
incident, the MOP was 1139.2 psi, and the actual recorded discharge was 1166.8 psi, which
equates to 102.6 percent of MOP. The archived SCADA data matched the data provided to OPS
at the time of the inspection, showing that this incident was also very brief and lasted less than
two minutes.15 Express further explained that it conducted a follow-up review of the amp data
for the Marysville pumps and found that a smaller horsepower (“HP”) pump was turned off, and
then a larger HP pump was started, which caused the brief pressure surge. More specifically,
Main Pump 1 (“MP1”) with 450 HP was turned off, and then MP2 with 1500 HP was started.
Express stated that the brief two-minute surge event was a result of this start-up. (Marysville
Pump Amp Trends for January 2016).16
For its part, OPS expressed a desire for more information to be further satisfied that the two
referenced incidents amounted to allowable surges and stated that there may be various
alternative explanations for the exceedances besides an allowable surge, such as the
manipulation of data in the process of changing from one SCADA system to another.17 OPS,
however, did not have persuasive evidence to support the notion that there may be other
explanations, and specifically did not present any evidence of manipulation of data.
At the hearing, OPS conceded that with respect to 20 of the 22 instances cited in the Notice,
Express had established compliance. With respect to the other two instances, Express provided
information and explanations demonstrating that both incidents were surges of very brief
duration and occurred during start-up operations which are allowed under the regulation.
Accordingly, after considering all of the evidence and the legal issues presented, I find that the
evidence does not support the allegation in the Notice. Based upon the foregoing, I hereby order
that this Item be withdrawn.
14 Post-hearing submission, at 7.
15 Id.
16 Id.
17 Recommendation, at 17.



CPF No. 3-2020-5005
Page 2
Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.406(b), which states:
§ 195.406 Maximum operating pressure.
(a)…
(b) No operator may permit the pressure in a pipeline
during surges or other variations from normal operations to
exceed 110 percent of the operating pressure limit
established under paragraph (a) of this section. Each
operator must provide adequate controls and protective
equipment to control the pressure within this limit.
The Notice alleged that Respondent violated 49 C.F.R. § 195.406(b) by failing to provide
adequate controls and protective equipment to control the operating pressure of the pipeline
system to prevent it from exceeding 110 percent of the MOP established under § 195.406(a)
during surges or other variations from normal operations. Specifically, the Notice alleged that
five pressure safety valves located at the Ogallala, Yoder, and Guernsey pump stations were set
at 1300 psig when they were required to be set at 1100 psig.
Respondent did not contest this allegation of violation. Accordingly, after considering all of the
evidence, I find that Respondent violated 49 C.F.R. § 195.406(b) by failing to provide adequate
controls and protective equipment to control the operating pressure of the pipeline system to
prevent it from exceeding 110 percent of the MOP established under § 195.406(a) during surges
or other variations from normal operations.
Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.412(a), which states:
§ 195.412 Inspection of rights-of-way and crossings
under navigable waters.
(a) Each operator shall, at intervals not exceeding 3
weeks, but at least 26 times each calendar year, inspect the
surface conditions on or adjacent to each pipeline right-of-
way. Methods of inspection include walking, driving, flying
or other appropriate means of traversing the right-of-way.
The Notice alleged that Respondent violated 49 C.F.R. § 195.412(a) by failing to inspect the
surface conditions on or adjacent to the pipeline right-of-way at intervals not exceeding 3 weeks,
but at least 26 times each calendar year by an appropriate means for traversing the right-of-way.
Specifically, the Notice alleged that Respondent’s aerial patrols of Unit 3773 did not allow for
observation of the surface conditions at 17 specified locations where PHMSA inspectors
observed excessive vegetation and/or tree canopy overgrowth preventing a clear view of the
ground.
Respondent did not contest this allegation of violation. Accordingly, after considering all of the
evidence, I find that Respondent violated 49 C.F.R. § 195.412(a) by failing to inspect the surface
conditions on or adjacent to the pipeline right-of-way at intervals not exceeding 3 weeks, but at
least 26 times each calendar year by an appropriate means for traversing the right-of-way.



CPF No. 3-2020-5005
Page 3
Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 195.581(a), which states:
§ 195.581 Which pipelines must I protect against
atmospheric corrosion and what coating material may I
use?
(a) You must clean and coat each pipeline or portion of
pipeline that is exposed to the atmosphere, except pipelines
under paragraph (c) of this section.
The Notice alleged that Respondent violated 49 C.F.R. § 195.581(a) by failing to clean and coast
each pipeline or portion of pipeline that was exposed to the atmosphere. Specifically, the Notice
alleged that Respondent failed to clean and coat a portion of its pipeline near Richmond, Kansas
where disbanded coating was present which resulted in external corrosion at that location.
Respondent did not contest this allegation of violation. Accordingly, after considering all of the
evidence, I find that Respondent violated 49 C.F.R. § 195.581(a) by failing to clean and coast
each pipeline or portion of pipeline that was exposed to the atmosphere.
Item 8: The Notice alleged that Respondent violated 49 C.F.R. § 195.583(b), which states:
§ 195.583 What must I do to monitor atmospheric
corrosion control?
(a)…
(b) During inspections you must give particular attention
to pipe at soil-to-air interfaces, under thermal insulation,
under disbonded coatings, at pipe supports, in splash zones,
at deck penetrations, and in spans over water.
The Notice alleged that Respondent violated 49 C.F.R. § 195.583(b) by failing in three instances
to give particular attention to pipe at pipe supports and in spans over water during atmospheric
corrosion inspections. Specifically, the Notice alleged that Express: (1) failed to remove seven
of the nine pipe supports of the Meng cable suspended span over water so that the pipe surface
under all of the supports could be inspected; (2) failed to remove a metallic child guard at Span
9-1446+87-9350 so that the pipe surface under the guard could be inspected; and (3) failed to
remove a metallic child guard at Span 6-5526+67-5260 so that the pipe surface under the guard
could be inspected.
In its Response and at the hearing, Respondent argued that it complied with the applicable
regulations and requested that the allegation and the associated proposed civil penalty be
withdrawn. Respondent argued that OPS erred by alleging in the Notice that Express failed to
inspect under the pipe supports when the regulation requires attention be paid at the pipe
supports.18 Respondent explained that it did give particular attention to the pipe supports, that no
staining or other evidence of atmospheric corrosion was present at any of the nine supports, and
argued that its removal of two of the nine supports complied with the requirement to sufficiently
18 Post-hearing submission, at 8.



CPF No. 3-2020-5005
Page 4
monitor for atmospheric corrosion.19 Respondent argued that Section 195.583(b) uses precise
language to instruct pipeline operators where to conduct atmospheric corrosion inspections on
the pipeline. The regulation specifically states that operators are required to conduct atmospheric
corrosion inspections of the pipe as follows:
 AT soil-to-air interfaces;
 UNDER thermal insulation;
 UNDER disbonded coatings;
 AT pipe supports;
 IN splash zones;
 AT deck penetrations; and
 IN spans over water.20
Respondent argued that if OPS wanted to enforce a requirement that operators inspect under
every pipe support, the agency would have needed to specify that requirement clearly in the
standard in the same way that it spelled out that operators are required to inspect under thermal
insulation and under disbonded coatings. Respondent argued that Section 195.583(b) is not
vague or ambiguous and “at” does not equal “under.” Respondent argued that OPS’ attempt to
impose a requirement to inspect under every pipe support in this enforcement proceeding was
inconsistent with the plain language of the regulation and therefore was arbitrary and
impermissible.21
OPS disagreed with Respondent’s argument and explained the safety benefits of inspecting under
all pipe supports, even in the absence of any staining or other evidence of atmospheric corrosion.
OPS explained that staining is not always visible at different angles or even the same angles, and
by the time staining has occurred and is visible to the naked eye, active corrosion on the pipeline
is likely. OPS believes that waiting for staining to be detectable around the pipe support is
inconsistent with the intent of § 195.583 and that operators are obligated to look for the problem
and mitigate the issue before it occurs, not after.22 OPS also took issue with Express’s reference
to in-line inspection (ILI) data to demonstrate that there was no corrosion at the pipe supports on
the Meng Span that would affect the safe operation of the pipeline before the next scheduled
inspection. OPS noted that while an ILI does provide valuable information, the additional metal
of the pipeline supports makes the metal loss of the pipeline difficult to detect.23
OPS also disagreed with Respondent’s argument concerning the use of the word “under” the pipe
supports in the allegation as the basis for the violation. OPS explained its position that pipe
supports can have different configurations. Supports can be off to the side, and not necessarily
under or over, thus “at a pipe support” would encompass all configurations of a pipe support. In
19 Post-hearing submission, at 9.
20 Post-hearing submission, at 10.
21 Id.
22 Recommendation, at 23.
23 Id.



CPF No. 3-2020-5005
Page 5
this case, the pipe supports identified on the Meng span were located under the pipe. OPS also
felt the comparison with the use of “under” with respect to thermal insulation was incorrect
because of how the thermal insulation versus pipe supports can be installed on the pipe. Thermal
insulation wraps around and blankets the pipe and the use of under makes sense logically
whereas for pipeline supports, “under” would not always be applicable based on the style or
design.24
Having considered these arguments, this issue turns on whether the regulation at issue put
operators on notice that OPS expects operators to remove every pipe support when conducting
atmospheric corrosion inspections even in the absence of any staining. I find that with respect to
the specific facts in this case, Respondent has the better of the argument concerning the words
“at” or “under”. With regard to OPS’ point that in the case of thermal wraps, the use of “under”
made more sense, this argument could equally be seen as supporting Respondent’s position and
OPS did not explain why the regulation could not have simply stated that all supports must be
removed to inspect for non-visible atmospheric corrosion if that was the intent.25 There is no
avoiding the fact that the regulation does not use the word “under” and the prior enforcement
cases cited by OPS are not clear and authoritative to the extent that would have put Respondent
on Notice that all pipe supports must be removed. For example, the Cenex case cited by OPS
was a case in which “Areas in the vicinity of the pipe supports had rust on the pipe” that may
have indicated corrosion between the pipe and the support, yet the support was not lowered.26 If
Respondent had similarly observed external rust in the vicinity of the pipe supports, it would
have called for additional removal of the supports. In this case, however, there is no evidence of
such rust in the record. The Cenex case does not establish that all supports must be removed
even in the absence of visible rust or staining. Respondent reasoned that removal of two of the
nine supports constituted a representative sample (over 20 percent) of the supports which was
sufficient to meet the minimum requirement of the regulation to pay particular attention at pipe
supports in spans over water.
The regulation gives a fair amount of discretion to operators concerning the manner in which
attention is paid at supports during atmospheric corrosion monitoring. While OPS may have
good reasons for wanting the removal of all supports to be mandatory even in the absence of any
staining, based on the plain language of this one-sentence regulation, and in the absence of any
authoritative history of any pipeline operator being found in violation of the cited regulation
under similar circumstances, I find that the use of an alleged violation of § 195.583(b) to
establish a new requirement for Express regarding the need to remove all pipe supports even in
the absence of any staining would not be consistent with OPS’ obligations under fair notice.
OPS should have used means other than a civil penalty enforcement action to notify operators
such as Respondent that all pipe supports must be removed during atmospheric corrosion
24 Recommendation, at 22.
25 In the case of a thermal insulation inspection, which has its own considerations such as the potential for excessive
moisture to remain present, OPS has never required that all insulation must be removed and has accepted removal of
a representative sample as acceptable. Moreover, external observations such as areas where the thermal insulation
has deteriorated can inform the extent to which removal is called for.
26 In the Matter of Cenex Pipeline, LLC, CPF No. 5-2012-5013, at 9.



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inspections, even in the absence of any staining, and should have done so in advance.27
Therefore, I find that the withdrawal of this instance of the allegation in Item 8 is warranted in
this case.28
With respect to the other two instances of inadequate atmospheric corrosion inspections cited in
the Notice involving the child supports, however, Respondent’s argument is unpersuasive. Color
photographs of these child supports presented at the hearing clearly showed staining from
atmospheric corrosion was present at the interface between the guards and the pipe.29 In these
two instances, the removal of the guards for further inspection was necessary to fulfill the
requirement to give particular attention to these pipe span areas during the inspections and their
removal was deemed necessary by the operator in the next round of inspections in 2017.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.583(b) by failing in two instances at the specified child guard locations to give particular
attention to pipe at pipe supports in spans over water during atmospheric corrosion inspections.
The Assessment of Penalty below will reflect a reduction to account for only two of the three
alleged instances of violation having been proven.
These findings of violation will be considered prior offenses in any subsequent enforcement
action taken against Respondent.
ASSESSMENT OF PENALTY
Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed
$200,000 per violation for each day of the violation, up to a maximum of $2,000,000 for any
related series of violations.30 In determining the amount of a civil penalty under 49 U.S.C.
§ 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature,
circumstances, and gravity of the violation, including adverse impact on the environment; the
degree of Respondent’s culpability; the history of Respondent’s prior offenses; any effect that
the penalty may have on its ability to continue doing business; the good faith of Respondent in
attempting to comply with the pipeline safety regulations; and self-disclosure or actions to
correct a violation prior to discovery by PHMSA. In addition, I may consider the economic
benefit gained from the violation without any reduction because of subsequent damages, and
such other matters as justice may require. The Notice proposed a total civil penalty of $346,400
for the violations cited above.
27 This holding does not mean that the regulation never requires operators to look under the supports. It only holds
that OPS did not present evidence under the particular facts of this case that indications of corrosion that would have
called for removal of the other 7 of the 9 supports.
28 It should be emphasized that this determination is based on the particular circumstances of this case and should
not be construed to broadly prohibit OPS from pursuing enforcement actions in other instances in which a particular
public safety concern indicates a need for enforcement.
29 Violation Report, Exhibit C.
30 These amounts are adjusted annually for inflation. See 49 C.F.R. § 190.223.



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Item 1: The Notice proposed a civil penalty of $46,600 for Respondent’s violation of 49 C.F.R.
§ 195.401(b)(1), for failing to make non-integrity management repairs on its pipeline system
within a reasonable time after it discovered a condition that could adversely affect the safe
operation of the pipeline system. With respect to the nature and circumstances of the violation,
promptly addressing an adverse condition is a fundamental responsibility of pipeline operator.
The fact that no major overpressure event occurred is fortunate, but does not negate the
importance of addressing the known potential for such an event. With respect to gravity,
ensuring that the risk of an overpressure condition is addressed before becoming a potential
integrity threat is a key part of safely operating a hazardous liquid pipeline system. With respect
to culpability and good faith, Respondent’s failure to correct the adverse condition was not
consistent with the purpose of the regulation. I find that nothing in the record would indicate that
the proposed civil penalty amount would impact Respondent’s ability to continue in business.
Respondent has not presented any information or arguments that would warrant a reduction in
the civil penalty amount proposed in the Notice for this violation. Accordingly, having reviewed
the record and considered the assessment criteria, I assess Respondent a civil penalty of $46,600
for violation of 49 C.F.R. § 195.401(b)(1).
Item 2: The Notice proposed a civil penalty of $76,000 for Respondent’s violation of 49 C.F.R.
§ 195.406(a)(3) by operating a part of its pipeline at a pressure that exceeded 80 percent of the
test pressure of the pipeline portion that had been tested under Subpart E of Part 195. For the
reasons discussed above, I found that Respondent did not violate this regulation and withdrew
the allegation. Accordingly, the penalty proposed in the Notice for this violation is also
withdrawn
Item 3: The Notice proposed a civil penalty of $58,400 for Respondent’s violation of 49 C.F.R.
§ 195.406(b), for failing to provide adequate controls and protective equipment to control the
operating pressure of the pipeline system to prevent it from exceeding 110 percent of the MOP
established under § 195.406(a) during surges or other variations from normal operations.
Express neither contested the allegation nor presented any evidence or argument that would
warrant any reduction in the proposed penalty. Having reviewed the record and the penalty
factors including the nature, circumstances, gravity, and Respondent’s culpability, I find that the
record supports the proposed penalty. Accordingly, having reviewed the record and considered
the assessment criteria, I assess Respondent a civil penalty of $58,400 for violation of 49 C.F.R.
§ 195.406(b).
Item 6: The Notice proposed a civil penalty of $77,700 for Respondent’s violation of 49 C.F.R.
§ 195.412(a), for failing to inspect the surface conditions on or adjacent to the pipeline right-of-
way at intervals not exceeding 3 weeks, but at least 26 times each calendar year by an
appropriate means for traversing the right-of-way. Express neither contested the allegation nor
presented any evidence or argument that would warrant a reduction in the proposed penalty.
Having reviewed the record and the penalty factors including the nature, circumstances, gravity,
and Respondent’s culpability, I find that the record supports the proposed penalty. Accordingly,
having reviewed the record and considered the assessment criteria, I assess Respondent a civil
penalty of $77,700 for violation of 49 C.F.R. § 195.412(a).



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Item 7: The Notice proposed a civil penalty of $29,300 for Respondent’s violation of 49 C.F.R.
§ 195.581(a), for failing to clean and coast each pipeline or portion of pipeline that was expose
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