# SUNOCO PIPELINE L.P. — Notice of Probable Violation

**Citation:** CPF 420165020  
**Type / status:** enforcement / historical  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** 2016-06-02

CLOSED notice of probable violation citing 195.401(b)(1), 195.402(a), 195.432(b), 195.432(d), 195.452(l)(1), 195.56(a), 195.579(a), 199.202.

## Document text

Notice of Probable Violation involving SUNOCO PIPELINE L.P.. PHMSA's enforcement data identifies the cited regulations as 195.401(b)(1),  195.402(a),  195.432(b),  195.432(d),  195.452(l)(1),  195.56(a),  195.579(a),  199.202. The case was opened on 2016-06-02 and is reported as closed as of 2018-01-08. Proposed civil penalty: $169,200. Assessed civil penalty: $141,700. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420165020_Closure Letter_01082018.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420165020/420165020_Closure%20Letter_01082018.pdf

420165020_Closure Letter_01082018_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420165020/420165020_Closure%20Letter_01082018_text.pdf

420165020_Final Order_09152017.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420165020/420165020_Final%20Order_09152017.pdf

420165020_Final Order_09152017_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420165020/420165020_Final%20Order_09152017_text.pdf

420165020_NOPV PCP PCO_06022016.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420165020/420165020_NOPV%20PCP%20PCO_06022016.pdf

420165020_NOPV PCP PCO_06022016_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420165020/420165020_NOPV%20PCP%20PCO_06022016_text.pdf

420165020_Operator Response to Notice_07112016.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420165020/420165020_Operator%20Response%20to%20Notice_07112016.pdf

420165020_Final Order_09152017_text.pdf

September 15, 2017
Mr. Kelcy L. Warren
Chief Executive Officer
Sunoco Pipeline, LP
8111 Westchester Drive
Dallas, TX 75225
Re: CPF No. 4-2016-5020
Dear Mr. Warren:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation, assesses a reduced civil penalty of $141,700, and specifies actions that need to be
taken by Sunoco Pipeline, LP, to comply with the pipeline safety regulations. This is to
acknowledge partial payment of the civil penalty in the amount of $33,700 by wire transfer dated
July 13, 2016, leaving a balance due of $108,000. The payment terms for the remaining penalty
are set forth in the Final Order. When the civil penalty has been paid and the terms of the
compliance order completed, as determined by the Director, Southwest Region, this enforcement
action will be closed. Service of the Final Order by certified mail is deemed effective upon the
date of mailing, or as otherwise 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: Director, Southwest Region, Office of Pipeline Safety, PHMSA
Mr. Ryan Coffey, Executive Vice-President – Operations, Sunoco Pipeline, LP, 800 E.
Sonterra Boulevard, San Antonio, TX 78258
Mr. Todd Nardozzi, Senior Manager, DOT Compliance, Sunoco Pipeline, LP
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 )
)
Sunoco Pipeline, LP, ) CPF No. 4-2016-5020
)
Respondent. )
____________________________________)
FINAL ORDER
From March 24, 2014, to July 1, 2015, pursuant to 49 U.S.C. § 60117, a representative of the
Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety
(OPS), conducted an on-site pipeline safety inspection of the facilities and records of Sunoco
Pipeline, LP (Sunoco or Respondent), throughout Texas. Sunoco is now an indirect subsidiary
of Energy Transfer Partners, LP, and operates approximately 6,800 miles of pipeline transporting
primarily crude oil and refined products in Texas, Oklahoma, Pennsylvania, Michigan, and
several other states.1
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to
Respondent, by letter dated June 2, 2016, a Notice of Probable Violation, Proposed Civil
Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the
Notice proposed finding that Sunoco had committed various violations of 49 C.F.R. Part 195 and
proposed assessing a civil penalty of $169,200 for the alleged violations. The Notice also
proposed ordering Respondent to take certain measures to correct the alleged violations and
included a warning pursuant to 49 C.F.R. § 190.205. The warning item required no further
action but warned the operator to correct the probable violation or face future potential
enforcement action.
Sunoco responded to the Notice by letter dated July 11, 2016 (Response). The company
contested several of the allegations, offered additional information in response to the Notice, and
requested that the proposed civil penalty be reduced. Respondent did not request a hearing and
therefore has waived its right to one.
1 See Sunoco Logistics Partners, LP, website, at http://www.sunocologistics.com/ (last accessed August 18, 2017).
On April 28, 2017, Sunoco’s general partner, Sunoco Logistics Partners, LP, announced a merger with Energy
Transfer Partners, LP,which Sunoco Logistics Partners, LP, has changed its name to Energy Transfer Partners, LP.



CPF No. 4-2016-5020
Page 2
FINDINGS OF VIOLATION
UNCONTESTED
In its Response, Sunoco did not contest the allegations in the Notice that it violated 49 C.F.R.
Part 195, as follows:
Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.56(a), which states:
§ 195.56 Filing safety-related condition reports.
(a) Each report of a safety-related condition under §195.55(a) must be
filed (received by OPS) within five working days (not including Saturday,
Sunday, or Federal Holidays) after the day a representative of the operator
first determines that the condition exists, but not later than 10 working days
after the day a representative of the operator discovers the condition.
Separate conditions may be described in a single report if they are closely
related. Reports may be transmitted by electronic mail
to InformationResourcesManager@dot.gov, or by facsimile at (202) 366-
7128.
The Notice alleged that Respondent violated 49 C.F.R. § 195.56(a) by failing to file safety-
related condition reports with PHMSA within five working days after determining conditions
existed that met the criteria of a safety-related condition. Specifically, the Notice alleged that on
December 3, 2013, Sunoco discovered nine anomalies in high consequence areas (HCAs),
including KLLR-CORS 13-2A, KLLR-CORS 13-3A, KLLR-CORS 13-4A, and 13-4B, and
documented the anomalies as “immediate conditions” due to physical damage to the pipeline.
The KLLR-CORS 13-3A, KLLR-CORS 13-4A, and 13-4B conditions were repaired on
December 18, 2013, which exceeded five working days from December 4, 2013, the date Sunoco
determined safety-related conditions existed. Further, the KLLR-CORS 13-2A condition was
repaired on December 19, 2013, which also exceeded five working days after the December 4,
2013 determination of the condition.
Respondent did not contest this allegation of violation. Accordingly, based upon a review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 195.56(a) by failing to file safety-
related condition reports with PHMSA within five working days after determining conditions
existed that met the criteria of a safety-related condition.
Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), which states:
§ 195.402 emergencies.
Procedural manual for operations, maintenance, and
(a) General. Each operator shall prepare and follow for each pipeline
system a manual of written procedures for conducting normal operations
and maintenance activities and handling abnormal operations and
emergencies. This manual shall be reviewed at intervals not exceeding 15
months, but at least once each calendar year, and appropriate changes made



CPF No. 4-2016-5020
Page 3
as necessary to insure that the manual is effective. This manual shall be
prepared before initial operations of a pipeline system commence, and
appropriate parts shall be kept at locations where operations and
maintenance activities are conducted.
The Notice alleged that Respondent violated 49 C.F.R. § 194.402(a) by failing to follow its own
written procedures for tank maintenance. Specifically, the Notice alleged that Sunoco failed to
follow Subpart F, § 195.432 of its Operations and Maintenance Manual, Inspection of In-Service
Breakout Tanks procedure, by not documenting conditions that could affect safe operation of its
breakout tanks. The requisite documentation was allegedly not completed in the following
instances:
1. During the PHMSA field inspection at Sunoco’s Ringgold facility in September 2014, the
PHMSA inspector found a crack on the Tank 2703 ringwall that had been discovered by
Sunoco in February 2014. Sunoco’s monthly inspection reports for Tank 2703 from
February 2014 to September 2014 demonstrated that Sunoco failed to document the crack
on the ringwall.
2. Tank 5 at Sunoco’s Colorado City facility was found to have approximately 10 feet of the
ringwall foundation severely damaged, which was noted on the tank’s post-inspection
repair report in December 2011. Sunoco’s monthly inspection reports for Tank 5
demonstrated that personnel failed to document the tank’s ringwall damage on its
monthly reports from August 2012 to December 2013. The damage was repaired in 2014
after the PHMSA inspector inquired about the damage.
3. During a PHMSA field inspection at Sunoco’s Corsicana facility in September 2014,
Tank 2602 was found to have a half-inch crack on the ringwall foundation. Tank 2602
monthly reports from September 2013 to August 2014 showed that Sunoco had failed to
document any ringwall damage during that time. The crack was repaired in October
2014 after the PHMSA inspector inquired about the damage.
Respondent did not contest these allegations of violation. Accordingly, based upon a review of
all of the evidence, I find that Respondent violated 49 C.F.R. § 195.402(a) by failing to follow its
own written procedures for tank maintenance.
Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.432, which states, in
relevant part:
§ 195.432 (a)…
Inspection of in-service breakout tanks.
(b) Each operator must inspect the physical integrity of in-service
atmospheric and low-pressure steel above-ground breakout tanks according
to API Std 653 (except section 6.4.3, Alternative Internal Inspection
Interval) (incorporated by reference, see §195.3). However, if structural
conditions prevent access to the tank bottom, its integrity may be assessed
according to a plan included in the operations and maintenance manual



CPF No. 4-2016-5020
Page 4
under §195.402(c)(3). The risk-based internal inspection procedures in API
Std 653, section 6.4.3, cannot be used to determine the internal inspection
interval . . . .
(d) The intervals of inspection specified by documents referenced in
paragraphs (b) and (c) of this section begin on May 3, 1999, or on the
operator's last recorded date of the inspection, whichever is earlier.
The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) and (d) by failing to
perform internal inspections of in-service breakout tanks within the maximum interval of 10
years prescribed by API 653, Section 6.4.2.2, which states: “When corrosion rates are not known
and similar service experience is not available to estimate the bottom plate minimum thickness at
the next inspection, the internal inspection interval shall not exceed 10 years.” Specifically, the
Notice alleged that Sunoco could not provide the out-of-service internal inspection reports for
tanks 2601, 2603, 42, and 2720 to confirm that an internal inspection had been performed and
corrosion rates had been established.
According to the Notice, if the date of the last inspection cannot be determined based on
available records, an operator should perform an API 653 inspection immediately after acquiring
a breakout tank from another operator. Since Sunoco acquired ownership of tanks 2601, 2603,
and 2720 on August 1, 2005, and tank 42 on February 17, 2006, and could not determine when
the last internal inspections were performed, and the corrosion rates of the tanks were not known,
an internal inspection allegedly should have been performed immediately upon acquisition and
then at an interval not exceeding 10 years. The aforementioned internal-inspection reports had
also been requested by PHMSA during a 2007 inspection but Sunoco had been unable to provide
them at that time.
In addition, the Notice alleged that Tank 44 had been constructed in 1992 but had not had its first
out-of-service internal inspection performed until 2012. Since Tank 44 did not have a corrosion
rate established, Sunoco needed to perform an internal inspection on Tank 44 in 2009, 10 years
after PHMSA adopted API 653 in 1999. Sunoco allegedly failed to perform an internal
inspection within this required time frame.
Finally, the type of liner for Tank 2703 was unknown. The last internal inspection of the tank
was performed on September 15, 1995, by the previous owner. The 1995 inspection report
stated that there was internal corrosion found on the tank bottom, but no corrosion rate had been
established. Sunoco scheduled the next internal inspection for 2015, an interval of 20 years,
even though Sunoco did not know what liner was applied during the tank’s repairs. Since the
material and thickness of the liner were not known and the corrosion rate was also unknown, the
inspection interval could not be more than 10 years and therefore Sunoco needed to perform an
internal inspection by 2005. Sunoco failed to perform an internal inspection within this 10-year
interval.
Respondent did not contest these allegations of violation. Accordingly, based upon a review of
all of the evidence, I find that Respondent violated 49 C.F.R. § 195.432(b) and (d) by failing to
perform internal inspections within the maximum interval of 10 years prescribed by API 653.



CPF No. 4-2016-5020
Page 5
Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 195.579(a), which states:
§ 195.579 What must I do to mitigate internal corrosion?
(a) General. If you transport any hazardous liquid or carbon dioxide that
would corrode the pipeline, you must investigate the corrosive effect of the
hazardous liquid or carbon dioxide on the pipeline and take adequate steps
to mitigate internal corrosion.
The Notice alleged that Respondent violated 49 C.F.R. § 195.579(a) by failing to have
procedures for mitigating internal corrosion by identifying the potential for internal corrosion at
low points, changes in elevation, sharp bends, infrequently-used piping, pump stations, and
“dead legs” and by assessing, monitoring, and, mitigating the effects of internal corrosion at
those identified locations. Specifically, the Notice alleged that Sunoco’s procedures addressing
internal corrosion were developed and implemented in 2011 and were designed to “mitigate
facility releases and improve asset reliability and availability.” The procedures specifically
mentioned that the purpose of the plan was to assess and learn the general condition of both
active and idle piping within the facility. While this manual was put in place to require internal-
corrosion assessments, the plan allegedly lacked specific and detailed information regarding the
actions necessary to perform adequate assessments on the facility piping. The procedure was
under revision at the time of the PHMSA inspection and a draft had been prepared to expand the
scope and application of the procedure. The procedure had not, however, been finalized or
implemented.
Finally, the Notice alleged that Sunoco’s existing procedure that addressed internal corrosion in
dead legs and low-flow pipelines was issued in 2013. The Dead Leg Removals and Line
Flushing Procedure OPER-PR-0008 was created to determine the extent of lines that would
require attention as part of the integrity program based on operating conditions. The procedure
required identification of dead legs and actions necessary to manage those identified pipelines.
The procedure, as written, allegedly did not include provisions for reevaluation after changes or
modifications had been made within a station or on the pipelines that could affect its operating
conditions. According to the Notice, Sunoco’s pipeline system had had several accidents where
releases occurred due to internal corrosion, including several in dead legs and low spots in its
facilities, with eight reportable accidents occurring on terminal piping since 2010.
Respondent did not contest this allegation of violation. Accordingly, based upon a review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 195.579(a) by failing to have
procedures for mitigating internal corrosion, by identifying the potential for internal corrosion at
low points, changes in elevation, sharp bends, infrequently-used piping, pump stations, and dead
legs and by assessing, monitoring and, mitigating the effects of internal corrosion at those
identified locations.
CONTESTED
The Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows:
Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.401(b)(1), which states:



CPF No. 4-2016-5020
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§ 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 correct,
within a reasonable time, conditions that could adversely affect the safe operation of its pipeline
system. Specifically, the Notice alleged that Sunoco failed to correct or repair two conditions
that could adversely affect the safe operation of its breakout tanks.
First, during the PHMSA field inspection of Sunoco’s Colorado City facility in July 2014, Tank
5 was allegedly found to have approximately 10 feet of the ringwall foundation severely
damaged. The ringwall had been damaged during the tank’s out-of-service repairs in 2011,
which was noted on Sunoco’s “Tank 5 Out of Service Post-Repair Report” in December 2011.
Sunoco, however, did not repair the ringwall foundation until August 2014, after the PHMSA
inspector had inquired during the 2014 field inspection about the ringwall’s damage. The Notice
alleged that Sunoco did not correct the condition “within a reasonable time” because it waited
two years and seven months to conduct the repair.
Second, during the PHMSA field inspections at Sunoco’s Ringgold and Corsicana facilities in
September 2014, Tank 2703 and Tank 2602 were allegedly found to have half-inch cracks on
their ringwall foundations. The crack on Tank 2703 had been discovered by Sunoco during the
tank’s In-Service Inspection in February 2014. The cracks were repaired on October 25, 2014,
after being noted during the PHMSA field inspection in September 2014. The Notice alleged
that Sunoco had failed to correct these conditions that could adversely affect the safe operation
of its pipeline system “within a reasonable time” because it waited eight months to complete the
repair.
In its Response, Sunoco acknowledged that the damage to the concrete ringwalls was not
addressed at the time of the inspections in July and September 2014, respectively. However, it
contended that the damage to the ringwalls was superficial in nature and did not pose any
significant or adverse risk to the safe operation of its pipeline system.
The company further stated that at the time of the 2011 post-repair inspection of Tank 5, the
damage to the tank’s ringwall did not pose a concern to the structural integrity or the safe
operation of the tank. A review of the tank-settlement measurements from inspection reports
conducted on Tank 5 in 2006 and again in 2011 indicated that there was no evidence of active
settlement and that the deflection and settlement readings were within API allowable limits. The



CPF No. 4-2016-5020
Page 7
shell-settlement survey was again confirmed as having no unacceptable settlement or deflection
during the January 2016 inspection report.
With respect to the ringwall cracks observed on Tanks 2703 at Ringgold and 2602 at Corsicana,
Sunoco likewise contended that the cracks in the ringwalls did not pose a concern to the
structural integrity or safe operation of the tanks. Sunoco argued that, in general, surface cracks
on concrete ringwalls do not pose a serious threat to the stability of a tank unless enough of a
ringwall section is missing so as to create a large enough area where the downward forces of the
tank shell can cause a significant out-of-plane deflection.
Although the company’s “API 653 In-Service Inspection Report for Tank 2703” noted a crack in
the ringwall, the condition was noted to be appropriate for “consideration” for repair, not as a
compliance deficiency. Sunoco stated that consideration was given to the nature of the crack,
and it was determined that it did not pose a serious threat to the stability or the continued safe
operation of the tank.
Sunoco further argued that it took steps to remediate the conditions of the ringwall of each tank
and provided documentation to OPS subsequent to the repairs while the inspection was ongoing.
It argued that the phrase “within a reasonable time” is subjective and discretionary, and that
based on its evaluation of the seriousness of the cracks, it took appropriate action in compliance
with the pipeline safety regulations. Sunoco stated that its internal subject-matter experts at no
time concluded that the ringwall damage posed any significant or adverse risk to the safe
operation of the pipeline system. Accordingly, Sunoco requested that this Item and the
associated Proposed Compliance Order be withdrawn, as well as the associated proposed civil
penalty.
In its recommendation, OPS disagreed with Sunoco’s response that the damage and cracks found
on the tanks were “superficial in nature and did not pose any significant or adverse risk to the
safe operation of its pipeline system,” and that the phrase “reasonable time” was subjective and
discretionary with respect to the timing of the repairs. OPS stated that a “reasonable time”
needed to be defined in an operator’s procedures, and that, as seen in Item 1 of the Notice,
Sunoco’s procedures failed to do so. According to OPS, Sunoco acknowledged that its DOT
Maintenance Manual Procedure 195.432 should define the term “reasonable” with respect to the
timing of repairs for conditions found during tank inspection, including monthly, external,
ultrasound (UT), and internal inspections.2 Moreover, Sunoco’s own “In-Service Inspection
Report for Tank 2703” stated: “There was moderate to severe cracking in the concrete,”
contradicting Sunoco’s claim that the damage was superficial.
Analysis
I have reviewed the record and find that Sunoco failed to repair the two conditions within a
reasonable time. Section 195.401(b)(1) requires each operator to correct a discovered condition
2 Response, at 3.



CPF No. 4-2016-5020
Page 8
within a reasonable time if the condition could adversely affect the safe operation of its pipeline
system. In this case, for Tank 5, the “HMT Final API 653 Out-of-Service Inspection Report,
Tank No. 5” included photographs demonstrating the damage to the ringwall foundation.3 The
company’s inspection report also noted that “minor cracks should be sealed to minimize further
degradation.”4 Photographs by the PHMSA inspector of Tank 5 taken on July 30, 2014, 5 Tank
2703 at the Ringold facility taken on September 17, 2014,6 and Tank 2602 taken on September
18, 2014,7 all reveal the extent of the damage to the ringwall.
Section 3.2.1 of Sunoco’s own “In-Service Inspection Report for Tank 2703” stated: “There was
moderate to severe cracking in the concrete. Consider repairing the cracks in the concrete.” 8
The report included a photograph showing the severity of the crack.9 I find the contemporaneous
photographs and Sunoco’s own “In-Service Inspection Report for Tank 2703” persuasive as to
the severity of the damage to the ringwall. The report also characterized the cracks as “moderate
to severe,” not superficial. The evidence in the photographs and Sunoco’s own reports all
support a finding that the cracks were not insignificant or insubstantial.
Cracks in a ringwall can be potential access points for moisture and water seepage that could
eventually result in corrosion of the reinforcing steel and further damage to the ringwall.
Accordingly, I find the damage to ringwalls at issue in this matter could adversely affect the safe
operation of Respondent’s pipeline system and therefore needed to be repaired within a
reasonable time frame to prevent them from becoming an even bigger safety issue.
Sunoco knew about the damaged ringwalls but failed to make repairs for a time period ranging
from almost a year to over two-and-a-half years. Given the extent of the cracking, I find that it
was not reasonable for Sunoco to wait this amount of time before making these repairs.
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.401(b)(1) by failing to correct within a reasonable time conditions that could adversely
affect the safe operation of its pipeline system.
These findings of violation will be considered prior offenses in any subsequent enforcement
action taken against Respondent.
3 Violation Report, Ex. B, at 115 (“HMT Final API 653 Out-of-Service Inspection Report, Tank No. 5, January 2001
and December 7, 2011, Section 8 Post Repair Photographs”).
4 Id., Ex. B, at 6 (“HMT Final API 653 Out-of-Service Inspection Report, Tank No. 5, January 2001 and December
7, 2011).
5 Id.,, Ex. B, at 127-28.
6 Id., Ex. B, at 135-36.
7 Id., Ex. B, at 189.
8 Id., Ex. B, at 143 (Tank 2703 API 653 In-Service Inspection Report by Mott Tank (Feb. 26, 2014)).
9 Id., Ex. B, at 185 (Tank 2703 API 653 In-Service Inspection Report by Mott Tank (Feb. 26, 2014)).



CPF No. 4-2016-5020
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WITHDRAWN
Pipeline integrity management in high consequence areas.
(l) What records must an operator keep to demonstrate compliance? (1)
An operator must maintain, for the useful life of the pipeline, records that
demonstrate compliance with the requirements of this subpart. At a
Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(l), which states, in
relevant part:
§ 195.452 (a)…
minimum, an operator must maintain the following records for review
during an inspection:
(i) A written integrity management program in accordance with
paragraph (b) of this section.
(ii) Documents to support the decisions and analyses, including any
modifications, justifications, deviations and determinations made,
variances, and actions taken, to implement and evaluate each element of the
integrity management program listed in paragraph (f) of this section. . . .
The Notice alleged that Respondent violated 49 C.F.R. § 195.452(l) by failing to maintain
records to support actions taken to implement and evaluate each element of its integrity
management program established under 49 C.F.R. Subpart F. Specifically, the Notice alleged
that Sunoco failed to provide records of the field changes made to the safety-related set points
when a 20 percent pressure reduction took place because of anomalies identified by in-line
inspection runs.
In its Response, Sunoco submitted Management of Change records (MOCs), along with Action
Items and Point-to-Point Short Forms for each MOC referenced in Item 6. Sunoco indicated the
creation of the MOC, along with the completion of the associated Field and SCADA Action
Items, served as the documentation required to show that field-related set points had been
changed and Point-to-Point verification with the field device and SCADA screen had taken
place.
OPS reviewed Sunoco’s submitted Action Items and Point-to-Point Short Forms for each MOC,
which had not been provided during the PHMSA inspection. The documentation was reviewed
and accepted by OPS as demonstrating that the changes to safety-related set points that had been
verified. OPS therefore recommended that this Item be withdrawn.
Accordingly, Item 6 is withdrawn from the Notice, along with the associated compliance order
and proposed civil penalty.
ASSESSMENT OF PENALTY
Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed



CPF No. 4-2016-5020
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$200,000 per violation for each day of the violation, up to a maximum of $2,000,000 for any
related series of violations. 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; and any effect
that the penalty may have on its ability to continue doing business; and the good faith of
Respondent in attempting to comply with the pipeline safety regulations. In addition, I may
consider the 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 $169,200 for the violations cited above.
Item 1: The Notice proposed a civil penalty of $33,700 for Respondent’s violation of 49 C.F.R.
§ 195.56(a), for failing to file safety-related condition reports with PHMSA within five working
days after determining conditions existed that met the criteria of a safety-related condition.
Respondent neither contested the allegation nor presented any evidence or argument justifying
elimination of the proposed penalty. Accordingly, having reviewed the record and considered
the assessment criteria, I assess Respondent a civil penalty of $33,700 for violation of 49 C.F.R.
§ 195.56(a), which amount has already been paid.
Item 2: The Notice proposed a civil penalty of $33,500 for Respondent’s violation of 49 C.F.R.
§ 195.401(b)(1), for failing to correct conditions that could adversely affect the safe operation of
its pipeline system within a reasonable time. As noted above, I found that Sunoco failed to
repair cracks in the ringwall foundations of two breakout tanks in a timely manner.
With regard to the penalty assessment criteria noted in the Violation Report, I find that the
nature, circumstances, gravity, and culpability factors have been considered appropriately and I
confirm the proposed penalty. In particular, cracks in a ringwall can be potential access points
for moisture and water seepage that could eventually result in corrosion of the reinforcing steel
and further damage to the ringwall. Damage to ringwalls need to be repaired in a reasonable
time frame to prevent them from becoming an even bigger safety issue. The Violation Report
acknowledged that pipeline safety was minimally affected by Respondent’s violation; as a result,
this mitigating factor was already taken into account in the proposed penalty. Based upon the
foregoing, I assess Respondent a civil penalty of $33,500 for violation of 49 C.F.R. § 195.401(b).
Item 3: The Notice proposed a civil penalty of $36,700 for Respondent’s violation of 49 C.F.R.
§ 195.402(a), for failing to follow its written procedures for tank maintenance. Sunoco argued
that the proposed penalty should be reduced because the proposed civil penalty “does not
appropriately reflect assessment considerations.”10 Sunoco argued that, compared to Item 2 of
the Notice, the proposed civil penalty for Item 3 was disproportionately higher and that the
violation resulted in “no injuries or fatalities, no explosion(s), no wildlife impact, and no water
contamination and, accordingly, no impact on health, and little (if any) impact on the
environment, which was short term and promptly remediated.”11
10 Response, at 5.
11 Id.



CPF No. 4-2016-5020
Page 11
I disagree. Having reviewed the record, I find that the penalty amount proposed in the notice is
warranted, considering the nature, circumstances, and gravity of the violation and Respondent’s
level of culpability. PHMSA calculates each penalty individually, based on the unique facts and
circumstances of the specific violation, using the same penalty criteria and logarithm. The
higher penalty for this violation, as opposed to Item 2, is based, at least in part, on the fact that
this violation compromised pipeline safety or integrity to a greater extent. A more serious
gravity factor warrants a higher penalty amount.
Sunoco has failed to provide any justification for reducing the proposed penalty based on the
assessment criteria. Accordingly, having reviewed the record and considered the assessment
criteria, I assess Respondent a civil penalty of $36,700 for violation of 49 C.F.R. § 195.402(a).
Item 4: The Notice proposed a civil penalty of $37,800 for Respondent’s violation of 49 C.F.R.
§ 195.432(b) and (d), for failing to perform internal inspections within the maximum interval of
10 years prescribed by API 653. Sunoco did not contest this allegation of violation but argued
that the penalty should be reduced because the out-of-service internal inspection reports for
Tanks 2720 and 42 were not available during the PHMSA inspection, but were included as part
of the Response. Sunoco stated that Tank 2720’s 2005 internal inspection report established a
corrosion rate on the prior tank bottom. Sunoco also stated that when the new tank bottom was
installed in 2005, a new internal inspection interval was calculated to be 20 years, using the
established corrosion rate of the old bottom that had been replaced. As for Tank 42, Sunoco
stated that it was evaluating repair records “associated with the December 14, 1995 internal
inspection…..to validate the internal inspection interval of 20 years.”12
I reject Sunoco’s argument for a penalty reduction. As for Tank 2720, Sunoco set a new
inspection rate of 20 years that was based on the established corrosion rate for the old tank
bottom. Since Sunoco replaced the tank bottom with a new bottom, the corrosion rate from the
old bottom could not be used for calculating the internal inspection interval. The new tank
bottom, however, had an unknown corrosion rate, so the internal inspection interval would be 10
years and the internal inspection for Tank 2720 should have been performed in 2005. As for
Tank 42, the Response did not include any documentation that would validate a 20-year internal
inspection interval.
Considering that the Notice listed nine breakout tanks, for which Sunoco admittedly failed to
perform internal inspections within the maximum interval of 10 years, as prescribed by API 653,
I see no basis for a penalty reduction. Having reviewed the record, I find that the penalty amount
proposed in the notice is warranted considering the nature, circumstances, and gravity of the
violation and Respondent’s level of culpability.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $37,800 for violation of 49 C.F.R. § 195.432(b) and (d).
Item 6: The Notice proposed a civil penalty of $27,500 for Respondent’s violation of 49 C.F.R.
§ 195.452(l) by failing to maintain documents to support actions taken to implement and
12 Response, at 7.



CPF No. 4-2016-5020
Page 12
evaluate each element of its integrity management program. This item has been withdrawn and,
therefore, there is no penalty associated with it.
In summary, having reviewed the record and considered the assessment criteria for each of the
Items cited above, I assess Respondent a total reduced civil penalty of $141,700, of which
$33,700 has already been paid.
Payment of the remaining civil penalty must be made within 20 days of service. Federal
regulations (49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through
the Federal Reserve Communications System (Fedwire), to the account of the U.S. Treasury.
Detailed instructions are contained in the enclosure. Questions concerning wire transfers should
be directed to: Financial Operations Division (AMK-325), Federal Aviation Administration,
Mike Monroney Aeronautical Center, 6500 S MacArthur Blvd, Oklahoma City, OK 79169. The
Financial Operations Division telephone number is (405) 954-8845.
Failure to pay the remaining penalty of $108,000 will result in accrual of interest at the current
annual rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23.
Pursuant to those same authorities, a late penalty charge of six percent (6%) per annum will be
charged if payment is not made within 110 days of service. Furthermore, failure to pay the civil
penalty may result in referral of the matter to the Attorney General for appropriate action in a
district court of the United States.
COMPLIANCE ORDER
The Notice proposed a compliance order with respect to Items 2, 4, 6, and 7 in the Notice for
violations of 49 C.F.R. §§ 195.401(b)(1), 195.432(b) and (d), 195.452(l), and 195.579(a),
respectively. Since Item 6 has been withdrawn, the associated provisions in the Proposed
Compliance Order for that item are not included.
Under 49 U.S.C. § 60118(a), each person who engages in the transportation of hazardous liquids
or who owns or operates a pipeline facility is required to comply with the applicable safety
standards established under chapter 601. Pursuant to the authority of 49 U.S.C. § 60118(b) and
49 C.F.R. § 190.217, Respondent is ordered to take the following actions to ensure compliance
with the pipeline safety regulations applicable to its operations:
1. With respect to the violation of § 195.401(b)(1) (Item 2), Respondent must further
define in its procedures reasonable time frames for the repair of conditions that may
be found during tank inspections, including monthly, external, UT, and internal
inspections of tanks.
Sunoco submitted procedure 195.432 Inspection of In-Service Breakout Tanks to
address part of this item in the Compliance Order. Sunoco addressed the integrity
inspection plan for tanks with concrete bottoms or liners in Section 195.432(3)(VII).



CPF No. 4-2016-5020
Page 13
OPS reviewed Sunoco’s submitted 195.432 procedure, which addresses part of the
Compliance Order for Item 2. The Section 195.432(3)(VII) Sunoco submitted was
unchanged from the previous procedure PHMSA had reviewed during the inspection,
and is not acceptable. Therefore, Sunoco must resubmit amended procedures to
comply with this Order.
2. With respect to the violation of § 195.432(b), (d) (Item 4), Respondent must
perform internal inspections on its breakout tanks that have exceeded 10 years, as
required by § 195.432, and must also perform internal inspections on tanks 2601,
2603, 42, and 2720 as soon as possible or provide the previous actual internal
inspection reports to verify internal inspections were performed. Sunoco must also
develop and implement a bottom-integrity inspection plan for its tanks that have
concrete liners and reevaluate the time interval for tanks with unknown corrosion
rates. Sunoco must provide the Southwest Region with the integrity inspection plan,
and a plan and time frame for performing internal inspections as required.
Since the time of the PHMSA inspection, Sunoco stated that it had made revisions to
its Dead Leg Removals and Line Flushing, and its Facility Integrity Program
procedures. Sunoco submitted to OPS a copy of its Facility Integrity Program,
Pipeline internal Corrosion Control Guideline, and Dead Leg Removals and Line
Flushing Procedure. Sunoco must also determine if any other existing procedures
should be considered for revision or any new procedures developed. Any additional
revised procedures or newly developed procedures must be submitted to PHMSA for
review within 90 days of the Final Order.
3. With respect to the violation of § 195.579(a) (Item 7), Respondent must develop
procedures to assess the integrity of its facility piping and to include provisions for
monitoring and mitigating the effects of internal corrosion on all of its pipelines.
Sunoco must perform an assessment to fully determine the corrosive effect of the
transported products on its pipeline system to include consideration of low points,
changes in elevation, sharp bends, infrequently used pump stations, and dead legs.
4. Sunoco must submit documentation and procedures required by this Compliance
Order within 90 days of the date of the Final Order and perform the required internal
inspections of the tanks within 180 days of the Final Order.
It is requested (not mandated) that Sunoco Pipeline L.P., maintain documentation of the safety
improvement costs associated with fulfilling this Compliance Order and submit the total to the
Director, Southwest Region, Pipeline and 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 to comply with any of the required items upon a
written request timely submitted by the Respondent and demonstrating good cause for an
extension.



CPF No. 4-2016-5020
Page 14
Failure to comply with this Order may result in administrative assessment of civil penalties not
to exceed $200,000 for each violation for each day the violation continues or in referral to the
Attorney General for appropriate relief in a district court of the United States.
WARNING ITEM
With respect to Item 5, the Notice alleged probable violations of Part 199 but did not propose a
civil penalty or compliance order for this item. Therefore, this is considered to be a warning
item. The warning is for:
49 C.F.R. § 199.202 (Item 5) ─ Respondent’s alleged failure to follow its written
alcohol misuse plan by failing to perform a post-accident alcohol test on a
covered employee as soon as practicable after the employee’s performance of a
covered task allegedly contributed to an accident.
If OPS finds a violation of this provision in a subsequent inspection, Respondent may be subject
to future enforcement action.
Under 49 C.F.R. § 190.243, Respondent has a right to submit a Petition for Reconsideration of
this Final Order. The petition must be sent to: Associate Administrator, Office of Pipeline
Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC
20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address. PHMSA
will accept petitions received no later than 20 days after receipt of service of this Final Order by
the Respondent, provided they contain a brief statement of the issue(s) and meet all other
requirements of 49 C.F.R. § 190.243. The filing of a petition automatically stays the payment of
any civil penalty assessed. Unless the Associate Administrator, upon request, grants a stay, all
other terms and conditions of this Final Order are effective upon service in accordance with
49 C.F.R. § 190.5.
September 15, 2017
___________________________________ __________________________
Alan K. Mayberry Date Issued
Associate Administrator
for Pipeline Safety

420165020_Closure Letter_01082018_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
January 8, 2018
Mr. Ryan Coffey
Executive Vice President of Operations
Sunoco Pipeline, LP
800 East Sonterra Blvd.
San Antonio, TX 78258
CPF 4-2016-5020
Dear Mr. Coffey:
On September 15, 2017, the Pipeline and Hazardous Materials Safety Administration (PHMSA)
issued to Sunoco Pipeline, L.P. a Final Order in the above-referenced case. This Final Order
included a Compliance Order and Civil Penalty assessment. Based on our review of the
documentation you provided and confirmation of payment of the civil penalty, it has been
determined that you have complied with the terms of this Order.
Accordingly, this case is now closed and no further action is contemplated with respect to the
matters involved in this case. Thank you for your cooperation in this matter.
Sincerely,
Terri J. Binns
Acting Director, Southwest Region
Pipeline and Hazardous Materials Safety Administration

420165020_NOPV PCP PCO_06022016_text.pdf

NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED COMPLIANCE ORDER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
June 2, 2016
Mr. David Chalson
Vice President of Operations
Sunoco Pipeline L.P.
4041 Market Street
Aston, PA 19014
CPF 4-2016-5020
Dear Mr. Chalson:
From March 24, 2014 to July 1, 2015, a representative of the Pipeline and Hazardous Materials
Safety Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49
United States Code inspected your procedures, records and pipeline facilities throughout Texas.
As a result of the inspection, it appears that you have committed probable violations of the Pipeline
Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable
violations are:
1. §195.56 Filing safety-related condition reports.
(a) Each report of a safety-related condition under § 195.55(a) must be filed (received
by the Administrator) in writing within 5 working days (not including Saturdays,
Sundays, or Federal holidays) after the day a representative of the operator first
determines that the condition exists, but not later than 10 working



conditions may be described in a single report if they are closely related. To file a
report by facsimile (fax), dial (202) 366-7128.
Sunoco failed to file safety-related condition reports with PHMSA within five working days after
determining conditions existed that met the criteria of a safety-related condition as per
195.55(a) (б).
Beginning on September 20, 2013, Sunoco performed an integrity assessment on their Keller to
Corsicana segment using a deformation and magnetic flux leakage (MFL) internal tool. On
December 3, 2013, Sunoco discovered nine anomalies in high consequence areas (HCAs),
including KLLR-CORS 13-2A, KLLR-CORS 13-3A, KLLR-CORS 13-4A and 13-4B, and
documented the anomalies as immediate conditions due to physical damage to the pipeline. On
December 4, 2013, Sunoco issued a 20% operating pressure reduction due to the immediate
conditions through a Management of Change 6328 on the 16" Ringgold to Corsicana segment.
The 20% operating pressure reduction established December 4, 2013 as the date Sunoco
determined a safety-related condition existed
The KLLR-CORS 13-3A, KLLR-CORS 13-4A and 13-4B conditions were repaired on December
18, 2013, which exceeded five working days from December 4, 2013 to the date Sunoco
determined safety-related conditions existed. Further, the KLLR-CORS 13-2A condition was
repaired on December 19, 2013, which also exceeded five working days after the date of
determination of the condition. Accordingly, Sunoco failed to file timely safety-related condition
reports in violation of § 195.56.. The following table gives additional details regarding each
condition:
Date
Determined
Business Days
Dig Number
Condition
Date
(Day of 20%
Repair Date
after
20%
Discovered
Pressure
Determination
Pressure
Reduction)
/Discovery
Reduction
KLLR-CORS 13-2A
Top Dent w/
Metal Loss
12/3/2013
12/4/2013
12/19/2013
11/12
MOC
6328
KLLR-CORS 13-3A
Top Dent w/
12/3/2013
12/4/2013
12/18/2013
10/11
MOC
Metal Loss
6328
KLLR-CORS 13-4A
Top Dent w/
12/3/2013
12/4/2013
12/18/2013
10/11
MOC
Metal Loss
6328
KLLR-CORS 13-4B
Top Dent w/
12/3/2013
12/4/2013
12/18/2013
10/11
MOC
Metal Loss
6328
2



2. §195.401 General Requirements.
(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.
Sunoco failed to correct conditions that could adversely affect the safe operation of its pipeline
system within a reasonable time. Specifically, Sunoco failed to correct or repair within a reasonable
time, several conditions that could adversely affect the safe operation of its breakout tanks as
follows:
During the PHMSA field inspection at Sunoco’s Colorado City facility in July 2014, Tank 5 was
found to have approximately 10 feet of the ring wall foundation severely damaged. The Ring wall
had been damaged during the tank’s out of service repairs in 2011 and was noted during Sunoco’s
Tank 5 Out of Service Post Repair report in December 2011. Sunoco, however, did not repair the
ring-wall foundation until August 2014, after the PHMSA inspector had inquired about the ring-
wall’s damage during the field inspection in July 2014. Sunoco failed to correct a condition that
could adversely affect the safe operation of its pipeline system within a reasonable time. Two years
and seven months was not a reasonable time for repairing the condition of Tank 5.
During the PHMSA field inspections at Sunoco’s Ringgold and Corsicana facilities in September
2014, Tank 2703 and Tank 2602, were found to have a half-inch crack on their ringwall foundation.
The crack on Tank 2703 had been discovered by Sunoco during the tank’s In-Service Inspection
in February 2014. Section 3.2.1 of the In-Service Inspection Report for Tank 2703 states, “There
was moderate to severe cracking in the concrete. Consider repairing the cracks in the concrete.”
Sunoco did not repair the crack as per API Standard 653 “Tank Inspection, Repair, Alteration, and
Reconstruction”, 3rd edition which states 4.5.2.2 Concrete pads, ringwalls, and piers, showing
evidence of spalling, structural cracks, or general deterioration, shall be repaired to prevent water
from entering the concrete structure and corroding the reinforcing steel. Sunoco did not repair the
condition on either tank at a reasonable time. The cracks were repaired on October 25, 2014, after
they were noted during the PHMSA field inspections in September 2014. Sunoco failed to correct
conditions that could adversely affect the safe operation of its pipeline system within a reasonable
time.
3. §195.402 Procedure manual for operations, maintenance, and emergencies.
(a) General. Each operator shall prepare and follow for each pipeline system a
manual of written procedures for conducting normal operations and maintenance
3



reviewed at intervals not exceeding 15 months, but at least once each calendar year,
and appropriate changes made as necessary to insure that the manual is effective.
This manual shall be prepared before initial operations of a pipeline system
commence, and appropriate parts shall be kept at locations where operations and
maintenance activities are conducted.
Sunoco did not follow their written procedure for tank maintenance. Specifically, Sunoco failed
to follow Subpart F, Section 195.432 of their Operations and Maintenance Manual, Inspection
of In-Service Breakout Tanks procedure, by not documenting conditions that could affect safe
operation of its breakout tanks. Section 195.432, Section 1. I. of the manual, states, “All above
ground breakout tanks shall be given a visual inspection on a monthly basis. Results of the visual
inspection shall be recorded on form (Sun-42446-A Monthly Aboveground Storage Tank
Inspection Report and maintained in the appropriate DOT file” and Section 1. III states “Evidence
of leaks; shell distortion; signs of settlement; corrosion; and damage or deterioration of the
foundation, paint coatings, insulation systems, and appurtenances or other potential problems shall
be documented for review by the facility manager or a designated engineer or authorized
inspector.” The requisite documentation was not completed in the following instances:
During the PHMSA field inspection at Sunoco’s Ringgold facility in September 2014, the PHMSA
inspector found a crack on Tank 2703’s ringwall. The crack on Tank 2703 had been previously
discovered during the tank’s In-Service Inspection in February 2014. The Sunoco’s monthly
inspection reports for Tank 2703 from February 2014 to September 2014 demonstrated Sunoco
failed to document the crack on the ring wall. Tank 5 at Sunoco’s Colorado City facility, was
found to have approximately 10 feet of the ring wall foundation severely damaged and was noted
on the tank’s post inspection repair report in December 2011. Sunoco’s monthly inspection reports
for Tank 5 demonstrate personnel failed to document the tank’s ring wall damage on their monthly
reports from August 2012 to December 2013. The damage was repaired in 2014 after the PHMSA
inspector inquired about the damage.
During a PHMSA field inspection at Sunoco’s Corsicana facility in September 2014, Tank 2602
was found to have a half-inch crack on the ring wall foundation. Tank 2602 monthly reports
from September 2013 to August 2014 where reviewed and Sunoco failed to document any ring
wall damage during that time. The crack was repaired in October 2014 after the PHMSA
inspector inquired about the damage.
4. §195.432 Inspection of in-service breakout tanks.
(b) Each operator must inspect the physical integrity of in-service atmospheric and
low-pressure steel aboveground breakout tanks according to API Standard 653
(incorporated by reference, see § 195.3). However, if structural conditions prevent
access to the tank bottom, the bottom integrity may be assessed according to a plan
included in the operations and maintenance manual under § 195.402(c)(3).
4



(d) The intervals of inspection specified by documents referenced in paragraphs (b)
and (c) of this section begin on May 3, 1999, or on the operator's last recorded date of
the inspection, whichever is earlier.
Sunoco failed to perform internal inspections within the maximum interval of 10 years prescribed
by API 653, Section 6.4.2.2 which states, "[w]hen corrosion rates are not known and similar
service experience is not available to estimate the bottom plate minimum thickness at the next
inspection, the internal inspection interval shall not exceed 10 years." and §195.432 for the
following breakout tanks:
Tank Built
Date
Bottom
API 653
API 653
Next API 653
Sunoco's
Sunoco's
Lining
Applied by
Internal
required
API
653
API
653
operator
Inspection
Internal
Internal
Internal
Previous
Inspection
Inspection
Current
Inspection
Performed
Schedule
Interval
by year:
2601
1947
Concrete
1997
Unknown*
2005
2017
(scheduled)
> 10
2602
1947
Concrete
2007
5/10/2007
2017
2027
(scheduled)
> 10
2603
1947
Fiberglass
Epoxy
2000
Film
Unknown*
2005
2/1/2020
> 10
Thin
44
2032
1992
Epoxy
2012
1/1/2012
2009
(scheduled)
>10
15
1953
2028
Concrete
2008
2/1/08
2018
(scheduled)
>10
17
2027
1953
Concrete
2007
2/1/07
2017
(scheduled)
>10
42
1953
Concrete
1996
Unknown*
2005
2016
(scheduled)
> 10
2703
1954
UNKNOWN
1995
1/1/1995
2005
2015
(scheduled)
> 10
2720| 1956| EPOXY
2004
Unknown* 2005
/ 2025
> 10
* NOTE: Out-of-service internal inspection reports were not provided.
Sunoco could not provide the out-of-service internal inspection reports for tanks 2601, 2603, 42,
2720 to confirm an internal inspection had been performed and corrosion rates had been
established. If the date of the last inspection cannot be determined based on the available records,
an operator should perform an API 653 inspection immediately after acquiring a breakout tank
from another operator. Since Sunoco acquired ownership of tanks 2601, 2603 and 2720 on August
1, 2005, and tank 42 on February 17, 2006, and could not determine when the last internal
inspections were performed, and the corrosion rates of the tanks are not known, the internal
inspection interval should not have exceeded 10 years. The aforementioned internal inspection
reports were also asked for by PHMSA during a 2007 inspection and Sunoco was unable to provide
them at that time.
5



Tank 44 was constructed in 1992 and had its first out-of-service internal inspection performed in
2012. Since Tank 44 did not have a corrosion rate established, Sunoco needed to perform an
internal inspection on Tank 44 in 2009, 10 years after PHMSA adopted API 653 in 1999. Sunoco
failed to perform an internal inspection within the required time frame.
Finally, the type of liner for Tank 2703 is unknown. The last internal inspection of the tank was
performed on September 15, 1995 by the previous owner. The 1995 inspection report states there
was internal corrosion found on the bottom, but no corrosion rate was established. Sunoco has
scheduled the next internal inspection for 2015, an interval of 20 years, even though Sunoco did
not know what liner was applied during the tank’s repairs. Since the material and thickness of the
liner is not known and the corrosion rate is unknown, the inspection interval should have been 10
years and Sunoco needed to perform an internal inspection in 2005. Sunoco failed to perform an
internal inspection within the 10 year interval.
5. §199.202 Alcohol misuse plan.
Each operator must maintain and follow a written alcohol misuse plan that
conforms to the requirements of this part and DOT Procedures concerning alcohol
testing programs. The plan shall contain methods and procedures for compliance
with all the requirements of this subpart, including required testing, recordkeeping,
reporting, education and training elements.
Sunoco failed to follow their written alcohol misuse plan by failing to perform a post-accident
alcohol test on a covered employee as soon as practicable, after the employee’s performance of a
covered function contributed to an accident.
On September 24, 2013, at 1:08 p.m., a Sunoco employee was performing a maintenance covered
task on a mainline block valve when an accident, reportable under 49 CFR Part 195, occurred. The
cause was found to be the employee’s failure to follow Sunoco’s maintenance procedure which
led to a suspension of the employee’s OQ qualifications. A post-accident alcohol test was
performed on September 25, 2013 at 2:20 p.m., approximately 23 hours after the accident. Sunoco
failed to conduct post-accident alcohol testing within 8 hours of an accident employee whose
performance of a covered task caused the accident as per their procedure.
Sunoco’s Substance Abuse Policy Appendix D Alcohol Misuse Prevention Plan and Procedures
(AMPPP), Section II, B, 3. Post-Accident Testing, states a post-accident test will occur as soon as
possible but no later than 8 hours following an accident. It also states each employee shall be
required to submit to an alcohol test within 2 hours of the accident.
6. §195.452 Pipeline integrity management in high consequence areas.
(l) What records must be kept? (1) An operator must maintain for review during an
inspection:
6



(i) A written integrity management program in accordance with paragraph (b) of
this section.
(ii) Documents to support the decisions and analyses, including any modifications,
justifications, deviations and determinations made, and actions taken, to
implement and evaluate each element of the integrity management program listed
in paragraph (f) of this section.
Sunoco failed to provide documents to support actions taken to implement and evaluate each
element of the integrity management program. Specifically, Sunoco failed to provide the records
of the field changes made to the safety related set points when a 20% pressure reduction took place
as a result of anomalies identified by ILI runs. During the inspection in May 2014, PHMSA
identified four (4) instances where a 20% pressure reduction took place.
As per Sunoco’s Management of Change (MOC) procedure, PR-11-0039, 2.1 Facilities or
Equipment Affected states ‘This procedure is designed to manage permanent or temporary changes
to all pipeline and terminal facilities and the operations that affect these facilities. This procedure
is intended for changes to the following, but is not limited to: 1. Pipelines and pipeline
components; 2. Pump station equipment and pipeline; 3. Instrumentation and Control equipment
and program;’ and etc.
From Sunoco’s MOC procedure, Section 6.0 Examples, a MOC is required for ‘Changes to
pipeline operating conditions based on Inline Inspection Results’. During the review in May 2014,
of the MOC documentation, inspectors requested Sunoco to provide documentation to demonstrate
that the field changes to the safety related set points had been documented due to the pressure
reductions. Sunoco responded that field documentation was not required as all the field changes
were part of Management of Change (MOC) process. A review of the MOC documentation does
not indicate that adjustments to devices or safety related set points were made in the field.
The following instances of the Management of Changes due to the pressure reductions are:
a) MOC ID# 5003
Date Created: 12/13/2012; Date Required: 12/13/2012
Location: F-Colo-Colorado City WTG (facility)
b) MOC ID# 6257
Date created: 12/6/2013; date required: 12/6/2013
Location: F-Ring-Ringgold (Facility)
c) MOC ID# 6328
Date created: 12/4/2013; Date required: 12/4/2013
Location: F-Ring- Ringgold Facility
d) MOC ID # 6411
7



Date created: 12/20/2013; Date required: 12/20/2013
Location: F-Ring-Ringgold Facility
The inspectors also reviewed Sunoco’s Operation and Maintenance Manual, Section 195.446:
Control Room Management which states:
“SPLP Requirements / Process description
1. Field maintenance technical groups are responsible for ensuring the accuracy of field
instrumentation exchanging data with the SCADA systems……… Testing and calibration
of each type of instrument will be done in accordance with these schedules and to
accuracies as defined within the Eastern area CMMS maintenance Management
system……..
Implement API RP 1165 whenever a SCADA system is added, expanded or replaced, unless
it is determined that certain provisions of API RP 1165 are not practical.
Conduct point to point verification between SCADA displays and related field equipment
when field equipment is added or moved and when other changes that affect pipeline safety
are made to field equipment or SCADA displays
Field personnel shall contact the appropriate control room when emergency conditions
exist and when making field changes that affect control room operations.”
While in the field, PHMSA requested Sunoco to provide documentation to demonstrate the field
changes to the safety related set points had been documented due to the pressure reductions.
Sunoco was unable to provide documentation to indicate that this was performed.
2. 3. 4. 7. §195.579 What must I do to mitigate internal corrosion?
(a) General. If you transport any hazardous liquid or carbon dioxide that would
corrode the pipeline, you must investigate the corrosive effect of the hazardous liquid
or carbon dioxide on the pipeline and take adequate steps to mitigate internal
corrosion.
Sunoco does not have procedures for mitigating internal corrosion to identify the potential for
internal corrosion at low points, changes in elevation, sharp bends, infrequently used piping, pump
stations, and dead legs or assessing, monitoring and mitigating the effects of internal corrosion at
those identified locations. Sunoco’s procedures that address internal corrosion include: Pipeline
Internal Corrosion Control Guideline CORR-TG-0501, Facility Integrity Program OPER-PR-
0003, Dead Leg Removals and Line Flushing Procedure OPER-PR-0008.
Sunoco’s Facility Integrity Program OPER-PR-003 was developed and implemented in 2011 and
was designed to “mitigate facility releases and improve asset reliability and availability.” The
procedures specifically mention that the purpose of the plan is to assess and learn the general8



condition of both active and idle piping within the facility. While this manual was put in place to
include assessments including internal corrosion, the plan lacks specific and detailed information
regarding the actions necessary to performed adequate assessments on the facility piping. The
procedure is currently under revision and a draft has been prepared to expand the scope and
application of the procedure. The procedure has not, however, been finalized or implemented.
Sunoco’s final procedure that addresses internal corrosion in dead legs and low flow pipelines was
issued in 2013. Sunoco’s Dead Leg Removals and Line Flushing Procedure OPER-PR-0008 was
created to determine the extent of lines that would require attention as part of the integrity program
based on the operating conditions. The procedure requires identification of dead legs and then
actions necessary to manage those identified pipelines. The procedure as written does not include
provisions for reevaluation after changes or modifications are made within a station or on the
pipelines that could affect their operating conditions.
Sunoco’s pipeline system has had several accidents where releases occurred due to internal
corrosion, including several in dead legs and low spots in their facilities. Sunoco has experienced
eight reportable accidents on terminal piping since 2010 involving internal corrosion.
Proposed Civil Penalty
Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $200,000
per violation per day the violation persists up to a maximum of $2,000,000 for a related series of
violations. For violations occurring prior to January 4, 2012, the maximum penalty may not exceed
$100,000 per violation per day, with a maximum penalty not to exceed $1,000,000 for a related
series of violations. The Compliance Officer has reviewed the circumstances and supporting
documentation involved in the above probable violations and has recommended that you be
preliminarily assessed a civil penalty of $169,200 as follows:
Item number PENALTY
1 $33,700
2 $33,500
3 $36,700
4 $37,800
6 $27,500
Warning Items
With respect to item 5 we have reviewed the circumstances and supporting documents involved
in this case and have decided not to conduct additional enforcement action or penalty assessment
proceedings at this time. We advise you to promptly correct these item. Failure to do so may
result in additional enforcement action.
9



Proposed Compliance Order
With respect to items 2, 4, 6, and 7 pursuant to 49 United States Code § 60118, the Pipeline and
Hazardous Materials Safety Administration proposes to issue a Compliance Order to Sunoco
Pipeline L.P. Please refer to the Proposed Compliance Order, which is enclosed and made a part
of this Notice.
Response to this Notice
Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in
Compliance Proceedings. Please refer to this document and note the response options. All
material you submit in response to this enforcement action may be made publicly available. If you
believe that any portion of your responsive material qualifies for confidential treatment under 5
U.S.C. 552(b), along with the complete original document you must provide a second copy of the
document with the portions you believe qualify for confidential treatment redacted and an
explanation of why you believe the redacted information qualifies for confidential treatment under
5 U.S.C. 552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a
waiver of your right to contest the allegations in this Notice and authorizes the Associate
Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to
you and to issue a Final Order.
In your correspondence on this matter, please refer to CPF 4-2016-5020 and for each document
you submit, please provide a copy in electronic format whenever possible.
Sincerely,
R. M. Seeley
Director, Southwest Region
Pipeline and Hazardous Materials Safety Administration
Enclosures: Proposed Compliance Order
Response Options for Pipeline Operators in Compliance Proceedings
10



PROPOSED COMPLIANCE ORDER
Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) proposes to issue to Sunoco Pipeline L.P., a Compliance Order
incorporating the following remedial requirements to ensure the compliance of Sunoco Pipeline
L.P. with the pipeline safety regulations:
1. 2. 3. 3. 4. 5. In regard to Item Number 2 of the Notice pertaining to failing to correct or repair
conditions found during tank inspections within a reasonable time. Sunoco must
define in their procedures a reasonable time frame to repair conditions found during
tank inspection, including monthly, external, UT, and internal inspections of tanks.
In regard to Item Number 4 of the Notice pertaining to exceeding the internal
inspection interval of 10 years, Sunoco must perform internal inspections on its
breakout tanks that have exceeded 10 years as required by §195.432 and must also
perform internal inspections on tanks 2601, 2603, 42, 2720 as soon as possible or
provide the previous actual internal inspection reports to verify internal inspections
were performed. Sunoco must also develop and implement a bottom integrity
inspection plan for their tanks that have concrete liners and reevaluate the time
interval for tanks with unknown corrosion rates. Provide to this office the integrity
inspection plan, and a plan and time frame for performing internal inspections as
required.
In regard to Item Number 6 of the Notice, Sunoco must revise its management of
change (MOC) procedures to include actions taken to implement the integrity
management program, specifically when a pressure reduction is to take place. MOC
procedures must include documentation of field activities taken and their potential
impact prior to implementation. The documentation should include the changes
made to specific devices and safety-related set points made in the field due to
pressure reductions.
In regard to Item Number 7 of the Notice, Sunoco must develop procedures to
assess the integrity of their facility piping and to include provisions for monitoring
and mitigating the effects of internal corrosion in all of their pipelines. Sunoco must
perform an assessment to fully determine the corrosive effect of the transported
products on their pipeline system to include consideration of low points, changes
in elevation, sharp bends, infrequently used pump stations, and dead legs.
Pertaining to items above of the Proposed Compliance Order, Sunoco must
complete the required documentation within 90 days of the date of the Compliance
Order and perform the required internal inspections of the tanks within 180 days of
the Compliance Order.
It is requested (not mandated) that Sunoco Pipeline L.P., maintain documentation
of the safety improvement costs associated with fulfilling this Compliance Order
and submit the total to R. M. Seeley, Director, Southwest Region, Pipeline and
11



Hazardous Materials Safety Administration. It is requested that these costs be
reported in two categories: 1) total cost associated with preparation/revision of
plans, procedures, studies and analyses, and 2) total cost associated with
replacements, additions and other changes to pipeline infrastructure.
12

## Provenance

- Official: Yes
- Source: <https://primis.phmsa.dot.gov/enforcement-data/case/420165020>
- Source ID: `phmsa-enforcement`
- SHA-256: `7a8c0921b779dd9b29b0315db8020c3fc4a2d77bac54e1bfb40dd25690771e38`
- Retrieved: 2026-08-20T04:44:44.458Z
- Exported: 2026-08-23T14:46:58.217Z
- Document slug: `phmsa-enforcement-420165020`

### Source metadata

```json
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  "dataAsOf": "08/04/2026 12PM",
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}
```