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

**Citation:** CPF 420145028  
**Type / status:** enforcement / historical  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** 2014-11-10

CLOSED notice of probable violation citing 195.202, 195.432(b), 195.452(h)(2), 195.452(h)(4).

## Document text

Notice of Probable Violation involving CENTURION PIPELINE L.P.. PHMSA's enforcement data identifies the cited regulations as 195.202,  195.432(b),  195.452(h)(2),  195.452(h)(4). The case was opened on 2014-11-10 and is reported as closed as of 2019-08-29. Proposed civil penalty: $165,900. Assessed civil penalty: $122,700. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420145028_Closure Letter_08292019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145028/420145028_Closure%20Letter_08292019.pdf

420145028_Closure Letter_08292019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145028/420145028_Closure%20Letter_08292019_text.pdf

420145028_Decision on Petition for Reconsideration_06272019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145028/420145028_Decision%20on%20Petition%20for%20Reconsideration_06272019.pdf

420145028_Decision on Petition for Reconsideration_06272019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145028/420145028_Decision%20on%20Petition%20for%20Reconsideration_06272019_text.pdf

420145028_Final Order_03302017.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145028/420145028_Final%20Order_03302017.pdf

420145028_Final Order_03302017_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145028/420145028_Final%20Order_03302017_text.pdf

420145028_NOPV PCP PCO_11102014.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145028/420145028_NOPV%20PCP%20PCO_11102014.pdf

420145028_NOPV PCP PCO_11102014_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145028/420145028_NOPV%20PCP%20PCO_11102014_text.pdf

420145028_Operator Petition for Reconsideration_04242017.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145028/420145028_Operator%20Petition%20for%20Reconsideration_04242017.pdf

420145028_Operator Response to Notice and Request for Hearing_12172014_.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420145028/420145028_Operator%20Response%20to%20Notice%20and%20Request%20for%20Hearing_12172014_.pdf

420145028_Decision on Petition for Reconsideration_06272019_text.pdf

June 27, 2019
Mr. Mike Prince
Chief Executive Officer
Lotus Midstream, LLC
2150 Town Square Place, Ste 395
Sugar Land, Texas 77479
Re: CPF No. 4-2014-5028
Dear Mr. Prince:
Enclosed please find the Decision on the Petition for Reconsideration filed by your subsidiary,
Centurion Pipeline, LP, in the above-referenced case. For the reasons explained therein, the
Decision affirms the violations in the Final Order but reduces the total civil penalty to $122,700.
When the civil penalty has been paid, this enforcement action will be closed. The Decision
constitutes the final administrative action in this proceeding. Service of the Decision is made
pursuant to 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: Ms. Mary McDaniel, Director, Southwest Region, Office of Pipeline Safety, PHMSA
Mr. Scott Janoe, Esq., Baker Botts, LLP, 910 Louisiana Street, Houston, Texas 77002
Mr. Mike Morgan, General Manager – Operations, Centurion Pipeline, LP, 5 Greenway
Plaza, Suite 110, Houston, Texas 77046
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 )
Centurion Pipeline, LP, ) CPF No. 4-2014-5028
a subsidiary of Lotus Midstream, LLC, )
)
)
)
Petitioner. )
__________________________________________)
DECISION ON PETITION FOR RECONSIDERATION
Between April 2013 and February 2014, 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 Centurion
Pipeline, LP (Centurion or Petitioner),1 in Texas, New Mexico, and Oklahoma. Centurion
operates approximately 2,500 miles of pipeline transporting crude oil in Texas, Oklahoma, and
New Mexico.2
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to
Petitioner, by letter dated November 10, 2014, 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 Centurion had committed six violations of 49 C.F.R. Part 195 and
proposed a civil penalty of $165,900 for the alleged violations. The Notice also proposed
ordering certain compliance measures to correct one of the alleged violations.
Centurion responded to the Notice by letter dated December 17, 2014 (Response), contested the
allegations, and requested a hearing. Centurion submitted additional materials on April 20, 2015
(Supplemental Response). An informal hearing was held on April 30, 2015, in Houston, Texas,
before a Presiding Official from the Office of Chief Counsel, PHMSA. After the hearing,
Petitioner provided post-hearing statements for the record, dated June 26, 2015 (Closing), and
September 4, 2015 (Supplemental Closing). Pursuant to § 190.209(b)(7), the Director submitted
a written evaluation of Petitioner’s response material on July 28, 2015 (Recommendation).
1 Centurion is a subsidiary of Lotus Midstream LLC. Lotus Midstream, LLC website, available at
http://www.lotusmidstream.com/about-us (last accessed May 10, 2019). At the time of the inspection, Centurion
was a subsidiary of Occidental Petroleum Corporation.
2 This information is reported by Centurion for 2015 pursuant to 49 C.F.R. § 195.49.



CPF No. 4-2014-5028
Page 2
On March 30, 2017, pursuant to 49 C.F.R. § 190.213, PHMSA issued a Final Order in this
proceeding, finding that Centurion had committed violations of §§ 195.432(b) (Items 1, 2, and
3), 195.202 and 195.264 (Item 4), 195.452(h)(2) (Item 5), and 195.452(h)(4) (Item 6), as alleged
in the Notice. The Final Order assessed a reduced civil penalty of $137,100, and ordered
corrective action with respect to Item 4, as set forth in the Compliance Order.3
In accordance with 49 C.F.R. § 190.243, Centurion filed a timely Petition for Reconsideration
(Petition) of the Final Order on April 24, 2017, seeking reconsideration of Items 1-3, 5 and 6 and
the civil penalties associated with them.4 Centurion did not seek reconsideration of Item 4 or the
associated Compliance Order. The filing of the Petition automatically stayed payment of the
assessed civil penalties pursuant to § 190.243(c), but did not stay the corrective actions required
under the Compliance Order. The Compliance Order for Item 4 has been completed, so is not
included in this Decision.
Pursuant to 49 C.F.R. § 190.243, an operator may petition the Associate Administrator for
reconsideration of a final order issued under § 190.213. A petition must be received no later than
20 days after receipt of the order by the respondent, and must contain a statement of the
complaint and an explanation as to why the order should be reconsidered. If the operator
requests consideration of additional facts or arguments that were not presented prior to issuance
of the final order, the operator must submit the reasons why they were not previously presented.
Reconsideration is not a right to appeal or to seek a de novo review of the record. A decision on
a petition for reconsideration may be issued without further proceedings. Once issued, that
decision becomes the final administrative action in the enforcement proceeding.
In its Petition, Centurion continued to argue against PHMSA’s interpretations of 49 C.F.R.
§§ 195.432 and 195.452 in Items 1-3, 5 and 6, repeating many of the same arguments and citing
the same information contained in Petitioner’s previous submissions and addressed in the Final
Order. Centurion also presented certain new information and new arguments, but failed to
present a valid rationale for why this new information and arguments should be considered.
PHMSA is not obliged to consider them and may dismiss those portions of the Petition without
further consideration. However, despite these procedural grounds for dismissal, I have
considered the substance of the Petition as discussed in greater detail below and still find it
lacking. Finally, Centurion characterized the Petition as an attempt to clarify certain of its
previous statements, which Petitioner asserted PHMSA “may have misinterpreted and/or
misapplied.”5
Discussion
A. Inspection of In-Service Breakout Tanks (49 C.F.R. 195.432)
3 Centurion Pipeline, LP CPF No. 4-2014-5028 (March 30, 2017), available at
https://primis.phmsa.dot.gov/comm/reports/enforce/FOCPEvent opid 0 html?nocache=7530# TP 1 tab 3.
4 Petition, at 1.
5 Petition, at 2.



CPF No. 4-2014-5028
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Item 1 in the Final Order found that Centurion violated 49 C.F.R. § 195.432(b), which states:
§ 195.432 Inspection of in-service breakout tanks.
(a) ….
(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
under § 195.402(c)(3)…6
The Final Order found that Petitioner violated 49 C.F.R. § 195.432(b) by failing to conduct
monthly Routine In-Service Inspections of breakout Tanks 6832 and 6833 according to
American Petroleum Institute Standard 653 (API 653) and assessed a civil penalty of $20,800 for
the violation.7 At the time of its inspection, PHMSA requested tank-inspection reports for
Petitioner’s breakout tanks for years 2010 through 2013; however, Centurion could not provide
monthly inspection reports for breakout Tanks 6832 and 6833 for calendar year 2010, January
2011, February 2011, March 2011, April 2011, and August 2011. PHMSA found that the
absence of records supported the finding of violation, particularly since Centurion was required
to keep records of monthly breakout-tank inspections pursuant to
§ 195.404(c)(3).8
In the Petition, Centurion contended that Item 1 of the Final Order should be withdrawn for lack
of sufficient evidence. Centurion acknowledged “in retrospect” that it may not have provided a
sufficiently detailed explanation of the evidence it had provided at the hearing to show that the
company had complied with the requirement to conduct monthly visual inspection of the tanks
and that it did not have records for 37 of the 1,248 required inspections for the five tanks at the
company’s Wasson Facility. Centurion presented four objections to the finding of violation: (1)
that “standing alone, evidence of missing records is not proof that an inspection was not
performed – only that a record was not kept;”9 (2) that the company had a robust pipeline
inspection program, as well as other compliance inspection programs that looked for similar
issues, and therefore it was “less likely” that a violation had occurred; (3) that Centurion’s
breakout Tanks 6832 and 6833 were co-located with other tanks for which Centurion had records
of the same Routine In-Service Inspections during the relevant time period; and (4) that
Centurion had performed and documented visual inspections for breakout Tanks 6832 and 6833
6 API 653, Section 6.3.1.2, states that the length of time between Routine In-Service Inspections shall not exceed
one month.
7 The Notice originally proposed civil penalty of $42,400 for Item 1, however, the penalty was reduced to $20,800
for the reasons set forth in the Final Order (at page 12).
8 Section 195.404(c)(3) requires operators to maintain a record for each required inspection.
9 Petition, at 11.



CPF No. 4-2014-5028
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that “were essentially identical” to those that were required under API 653.10 Based on these
assertions, Centurion contended that the preponderance of the evidence supported the conclusion
that the company had conducted all of the required monthly Routine In-Service Inspections but
had simply failed to maintain adequate records of those inspections.11
I disagree. Centurion previously raised argument (1) in response to the Notice and PHMSA
rejected it in the Final Order. Specifically, PHMSA found that Petitioner’s failure to have any
records of performing the required inspections constituted credible evidence that Centurion did
not perform the inspections as required. As noted in the Final Order, the company “presented no
evidence that the inspections actually took place.” If there had been affidavits or other evidence
presented at the hearing that supported Centurion’s claim that the inspections had actually taken
place, then perhaps there would be a closer question of whether PHMSA had met its burden of
proving the violation. However, in the absence of such evidence, PHMSA was justified in
relying upon a lack of records that Centurion was separately obliged to keep under
§ 195.404(c)(3) and Centurion’s own procedures.12
With regard to arguments (2), (3) and (4), Petitioner attempts to demonstrate compliance with
§ 195.432(b) and the API 653 inspection requirements by presenting evidence that is either
unsubstantiated or not determinative of compliance. For example, the fact that Petitioner has
procedures for the performance of tank inspections does not demonstrate the procedures were
followed or that the tank inspections took place as required by the regulation. Just because an
operator has procedures to perform a certain task is immaterial to whether such tasks were
actually performed or performed properly. Similarly, the location of breakout Tanks 6832 and
6833 near other tanks for which Centurion conducted monthly Routine In-Service Inspections in
January 2010 through April 2011 and August 2011 also does not demonstrate that the requisite
API 653 inspection was performed on Tanks 6832 and 6833 during the period at issue. Having a
“robust, systematic approach” to inspections also does not demonstrate that the required
inspections were performed.
Finally, with regard to Centurion’s argument that it performed and documented other visual
inspections that were “essentially identical” to those required by API 653, I note that Section
6.3.1.3 of API 653 reads:
This routine in-service inspection shall include a visual inspection
of the tank's exterior surfaces. Evidence of leaks; shell distortions;
signs of settlement; corrosion; and condition of the foundation, paint
10 When a civil penalty is assessed for more than one instance of a violation (e.g., 37 tanks with missed inspections), each
additional instance beyond the first typically elevates the total penalty by less than the amount assessed for the first instance, with
each additional instance representing a smaller increase in proportion to the total. See, e.g., Plains Pipeline, LP, CPF No. 4-2013-
5007, n.61, 2015 WL 4397455, at *17 (May 22, 2015) (explaining that each additional tank out of compliance elevated the civil
penalty by less than the amount assessed for the first).
11 Petition, at 11.
12 Pipeline Safety Violation Report (Violation Report), (October 23, 2014) (on file with PHMSA), at 4.



CPF No. 4-2014-5028
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coatings, insulation systems, and appurtenances should be
documented for follow-up action by an authorized inspector.
I have reviewed the Wasson Tank Inspection Records for Tanks 6832 and 6833 that have been
provided by Petitioner and attached as Exhibit L to the Petition.13 These records, however, do
not address the requirements of API 653, nor do they specify that an inspection was actually
performed. The records also do not document the additional inspections such as environmental,
health and safety reviews, monthly tank gauging, and mixer and thief-hatch checks that
Centurion contends took place.
In summary, the record supports, by a preponderance of the evidence, the finding that Petitioner
failed to comply with § 195.432(b) and the API 653 Routine In-Service Inspection requirements.
Petitioner also asked that the civil penalty of $20,000 for this Item either be eliminated or
reduced. Centurion did not make any explicit argument in its Petition as to why the penalty
should be reduced under PHMSA’s penalty assessment criteria, but I have nevertheless reviewed
both the penalty criteria and how they were applied for this Item. Finally, I have reviewed the
Final Order, which already reduced the civil penalty from the proposed amount of $42,400 down
to $20,800 on the ground that the company “discovered the non-compliance and took
documented action to address the issue” prior to the PHMSA inspection.14 Finding no reason to
modify the findings or to reduce further the penalty assessed in the Final Order, PHMSA affirms
the violation of § 195.432(b) and the reduced civil penalty of $20,800.
Item 2 in the Final Order found that Centurion violated 49 C.F.R. § 195.432(b), as quoted above,
by failing to conduct “External Inspections”15 of four breakout tanks (Tanks 6688, 6965, 6948,
and 2722) within the required five-year interval, in accordance with API 653, and assessed a civil
penalty of $23,600 for the violation. Specifically, it found that with respect to Tank 6688,
Centurion had performed an External Inspection on February 5, 2008, but not again until March
7, 2014, exceeding the five-year interval by 394 days. With respect to Tank 6965, the Final Order
found that Centurion had performed an External Inspection on August 7, 2008, but not again until
October 10, 2013, exceeding the five-year interval by 63 days. With respect to Tank 6948, the
Final Order found that Centurion had performed an External Inspection on June 10, 2008, but not
13 Exhibit L to the Petition. This new evidence was presented for the first time with the Petition. Under 49 C.F.R.
§ 190.243(b), if the Petitioner seeks consideration of additional facts or arguments, “the respondent must submit the
reasons why they were not presented prior to issuance of the final order.” The Petitioner failed to present any
plausible reason why this evidence was not presented earlier, except that “Centurion did not anticipate PHMSA’s
interpretations on certain legal and factual issues.” Response, at 2. Such a rationale, of course, could be made for
virtually any new evidence that an operator may seek to present for the first time in a petition. Nevertheless, this
new evidence has been considered and is found to be irrelevant.
14 Final Order, at 12.
15 Section 6.3.2.1 of API 653 states: “All tanks shall be given a visual external inspection by an authorized
inspector. This inspection shall be called the external inspection and must be conducted at least every 5 years or
RCA/4N years (where RCA is the difference between the measured shell thickness and the minimum required
thickness in mils, and N is the shell corrosion rate in mils per year) whichever is less. Tanks may be in operation
during this inspection.”



CPF No. 4-2014-5028
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again until March 7, 2014, exceeding the five-year interval by 258 days. Finally, with respect to
Tank 2722, the Final Order found that Centurion had performed an External Inspection on October
23, 2007, but not again until June 21, 2013, exceeding the five-year interval by 240 days.
In its Petition, Centurion stated that it did not seek reconsideration of the finding of violation for
three of the four tanks (Tanks 6688, 6948, and 2722), but only for Tank 6965, on the basis that it
had complied with § 195.432(b) and API 653 because the required External Inspection was
performed within five “calendar years.” Petitioner argued: (1) that API 653 uses the colloquial
term “year;” (2) that commentary from the API Committee (Committee) and legal precedent
support the proposition that the term “year” may be understood to mean “calendar year” for
compliance purposes; and (3) that PHMSA improperly interpreted API 653 as cited in a
previously-issued administrative final order.16
Centurion previously raised arguments (1) and (2) in response to the Notice and PHMSA
rejected them in the Final Order. Specifically, PHMSA found that in a 2010 enforcement action,
the agency had determined that the five-year inspection period required by § 195.432(b) meant
five periods of 365 days each. In that case, PHMSA found that a pipeline operator had violated
§ 195.432(b) when the company exceeded an inspection interval of five consecutive 365-day
periods, even though the operator had performed an inspection within five calendar years.17
Petitioner’s contention regarding development of the API 653 consensus standard was also
rejected. Petitioner had argued that a Committee-member representative from a pipeline
operator had proposed changing the language in API 653 to make “years” effectively be
“calendar years.”18 However, this proposed change from “years” to “calendar years” was not
adopted, as seen by the plain language of Section 6.3.2.1 of API 653. Therefore, Centurion’s
argument that API 653 should be read to mean “calendar years” fails because the proposal to
make such a change was not accepted by the Committee. Moreover, a proposal by an API
committee member in the development of a standard is not persuasive or controlling on
PHMSA’s interpretation of its own regulations.
Furthermore, I find Petitioner’s reliance on two federal cases in support of its argument for
Centurion’s interpretation of the term “year” to be unpersuasive and irrelevant. Specifically,
Petitioner argues that courts permit the construction of a term to its natural or ordinary meaning
absence a statutory definition.19 While neither the Federal Pipeline Safety Laws nor 49 C.F.R.
Parts 190-199 defines the term “year,” PHMSA has previously interpreted it to be 365 days in its
adjudication of enforcement matters. Additionally, Black’s Law Dictionary defines “year” as “a
consecutive 365-day period beginning at any point” or “a span of twelve months.”20 Similarly,
16 Enbridge Pipelines (Ozark), L.L.C., CPF No. 4-2010-5008, 2010 WL 65316*38 (Aug. 17, 2010).
17 Id. (finding violations of the five-year inspection interval for a number of tanks that were inspected within five
calendar years, but not within five periods of 365 days).
18 Petition, at Exhibit C. See also Supplemental Response, at 8-9 and Appx. B.
19 Petition, at 10.
20 Black’s Law Dictionary (10th ed. 2014), which notably provides a separate definition for “calendar year.”



CPF No. 4-2014-5028
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Merriam-Webster’s definition of “year” indicates that it is a period “required for one revolution
of the earth around the sun.”21
Finally, with regard to argument (3), Petitioner argued that PHMSA should not rely on the 2010
Final Order because the operator in that case did not contest the violation and agreed to correct
the noncompliance. Again, I disagree. I find no reason why an uncontested finding of violation
in a published final order should somehow be discounted or dismissed as precedent just because
an operator chose not to challenge the facts or law underlying an allegation of violation. Further,
I find that even were PHMSA to conclude that the 2010 final order is merely informative, the
earlier enforcement action still provided fair notice to Centurion and the regulated community
that PHMSA has interpreted § 195.432(b) and API 653 to mean that the visual external-
inspection interval must not exceed five consecutive periods of 365 days each, rather than five
calendar years.
Accordingly, finding no reason to modify the findings in the Final Order, PHMSA affirms the
finding of violation of § 195.432(b) and the civil penalty of $23,600.
Item 3 in the Final Order found that Centurion violated 49 C.F.R. § 195.432(b), as quoted above,
by failing to make Ultrasonic Thickness (UT) measurements of breakout tanks at intervals not to
exceed five years, in accordance with API 653, and assessed a civil penalty of $23,600 for the
violation. As discussed above, with respect to Tank 6688, it found that Centurion had performed
an External Inspection on February 5, 2008, but not again until March 7, 2014, exceeding the
five-year interval by 394 days. With respect to Tank 6965, it found that Centurion had
performed an External Inspection on August 7, 2008, but not again until October 10, 2013,
exceeding the five-year interval by 63 days. With respect to Tank 6948, it found that Centurion
had performed an External Inspection on June 10, 2008, but not again until March 7, 2014,
exceeding the five-year interval by 258 days. Finally, with respect to Tank 2722, it found that
Centurion had performed an External Inspection on October 23, 2007, but not again until June
21, 2013, exceeding the five-year internal by 240 days.
In the Petition, Centurion argued that the finding of violation in Item 3 should be withdrawn
because the company knew the corrosion rates for its tanks, therefore making them subject to the
longer interval for UT testing found in Section 6.3.3.2.b of API 653, and not the five-year
interval for tanks with unknown corrosions rates under Section 6.3.3.2.a.22 Specifically,
Centurion contended that it had calculated the corrosion rates for the tanks at issue in accordance
with API 653 by comparing the actual wall-thickness data for each tank with past and historical
tank records. Centurion argued that its calculation method was consistent with API 653 Section
6.3.3.1, which states, in relevant part: “External, ultrasonic thickness measurements of the shell
21 Merriam Webster Dictionary website, available at https://www.merriam-webster.com/dictionary/year (last
accessed on May 10, 2019).
22 Section 6.3.2.2(a) of API 653 states: “When used, the ultrasonic thickness measurements shall be made at
intervals not to exceed the following: (a) When the corrosion rate is not known, the maximum interval shall be 5
years. Corrosion rates may be estimated from tanks in similar service based on thickness measurements taken at an
interval not exceeding 5 years.”



CPF No. 4-2014-5028
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can be a means of determining a rate of uniform general corrosion while the tank is in service.”
Finally, Centurion contended that PHMSA had not cited to any evidence to show that
Centurion’s methodology was inconsistent with API 653.
With its Petition, Centurion supplemented the evidentiary record with an API 653 Internal
Inspection Report for Tank 6688; the remaining records had been previously provided and
considered by PHMSA in making its determination in the Final Order. Nevertheless, I have
carefully reviewed all of the evidence and find that Centurion has again fallen short of providing
PHMSA with evidence demonstrating that it had actually calculated the corrosion rates, and
therefore knew the corrosion rates of the tanks at issue at the time of the PHMSA inspection.
The records provided by Centurion show that Petitioner did not calculate the corrosion rates in
2007 and 2008 when it conducted those External Inspections. The records with calculated
corrosion rates are from 2013 and 2014, and are only for Tanks 6965 and 2722.23 As a matter of
fact, the API 653 In-Service Inspection Report with the calculated corrosion rate for Tank 6865
was dated March 7, 2014, which was after the PHMSA inspection. Additionally, these records
show that Centurion did not calculate the corrosion rate for all the “courses” of the tank, even
though the company had the necessary data to perform said calculations. Finally, Centurion
conceded in its Petition that it does not have records of calculated corrosion rates.24 Therefore,
since Centurion did not know the corrosion rates for Tanks 6688, 6968, 6948, and 2722 when it
performed the External Inspections, those tanks were subject to the five-year interval of API 653
Section 6.3.3.2.a.
Finding no reason to modify the findings in the Final Order, PHMSA affirms the violation of
§ 195.432(b) and the civil penalty of $23,600.
B. Pipeline Integrity Management in High Consequence Areas (49 C.F.R. 195.452)
Item 5 in the Final Order found that Centurion violated 49 C.F.R. § 195.452(h)(2), which states:
§ 195.452 Pipeline integrity management in high consequence areas.
(a) ….
(h) What actions must an operator take to address integrity issues?...
(2) Discovery of condition. Discovery of a condition occurs when an
operator has adequate information about the condition to determine that the
condition presents a potential threat to the integrity of the pipeline. An
operator must promptly, but no later than 180 days after an integrity
assessment, obtain sufficient information about a condition to make that
determination, unless the operator can demonstrate that the 180-day period
is impracticable.
The Final Order determined that Petitioner violated 49 C.F.R. § 195.452(h)(2) by failing to
obtain sufficient information about an anomalous condition to determine, no later than 180
days after an integrity assessment, if the condition presented a potential threat to the integrity
23 Pre-Hearing Brief, at Appendix A.
24 Petition, at 9, FN 4.



CPF No. 4-2014-5028
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of the pipeline and assessed a reduced civil penalty of $28,800. The record shows that on
December 3, 2011, Petitioner completed an integrity assessment using a T.D. Williamson,
Inc. (TDW) SpirALL Magnetic Flux Leakage Multi Data Set tool (SMFL MDS tool or the
tool) as part of its continual reassessment of the 16-inch Bretch to Cushing #2 system. The
180-day deadline to obtain sufficient information was therefore May 31, 2012. Although
Petitioner experienced a 40-day period prior to the 180-day deadline during which it believed
the data might be unusable, the Final Order determined that such delay did not excuse it from
compliance with § 195.452(h)(2).
In the Petition, Centurion argued that the finding of violation for Item 5 should be withdrawn
because (1) the data issues, overall complexity, and novelty of the tool run made it impracticable
to discover the condition within 180 days, and (2) relevant PHMSA precedent supported
Centurion’s position.
With regard to argument (1), § 190.243 requires a petitioner to submit the reasons why any new
facts or arguments were not presented prior to issuance of the final order. Centurion has offered
no explanation as to why it failed to raise this impracticability argument previously, and, in fact,
now expressly contradicts its earlier statements at the hearing and in its Post-Hearing Brief,
which dismissed impracticability. For example, Centurion previously stated:
This case does not turn on the “impracticability” provision in
§ 195.452(h)(2). At the time the 16-inch SMFL MDS was launched, no one
at Centurion believed it would be impracticable to meet the 180-day
deadline. At the time the pig was retrieved in a damaged condition leading
to TDW’s declaration of a “Failed Run,” impracticability was not an issue
because at that time the 180-day clock effectively reset, and Centurion had
to consider a new run. When Centurion shared with TDW its approach to
potentially utilize the data from the damaged tool and TDW determined
there was “usable data” on January 27, 2012, impracticability ceased to be
an issue because Centurion met the 180-day discovery timeframe. Thus,
there was no point in this admittedly rare set of circumstances where
Centurion believed that completing the discovery process within 180 days
after the integrity assessment was impracticable. 25
Based on this prior representation, I find that Centurion has waived its right to raise the argument
of impracticability. Notwithstanding this finding, I have reviewed and carefully considered
Centurion’s new impracticability claim. PHMSA has previously held that “generally it is not an
impracticability where the vendor delay could have been anticipated ahead of time.”26 Centurion
states that the “impracticability of meeting the 180-day deadline stems from Centurion’s use of
state of the art technology in its pipeline integrity program.”27 Centurion claims that it could not
25 Post-Hearing Brief, at 20; Hearing Transcript, at 107: 16-18.
26 ExxonMobil Pipeline Co., CPF 4-2013-5027, 2015 WL 7175715, at *20 (October 1, 2015).
27 Petition, at 7.



CPF No. 4-2014-5028
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have foreseen the length of time it would take to gather and analyze the data from the in-line
inspection (ILI) run. Centurion emphasized in the record that it used (1) a complex, newly-
commercialized ILI technology tool;28 (2) the tool collected “the largest data set ever amassed in
a single run by TDW;”29 and (3) the run was the longest in TDW’s history.30
PHMSA has previously concluded that while a “delay by a tool vendor might render discovery
within 180 days impracticable, an operator's claim of impracticability requires considering all the
relevant facts of the delay. Where an operator's own actions contributed to the delay, as in the
present case, PHMSA does not consider that the operator is excused from compliance due to an
impracticability.”31 Here, I find that Centurion could have predicted that the 180-day deadline
would be problematic. Factors such as a new tool that had never been run before, the large
amount of data to be collected by the vendor, and the longest run in the vendor’s history, on their
face, contain enough uncertainty and the possibility of difficulties to persuade me that Centurion
could have anticipated a delay ahead of time and taken appropriate measures in advance of the
inspection to ensure timely discovery, as required by the regulation.
Further, Centurion claims that the Final Order “misquotes and misapplies relevant precedent.”
Petitioner cites to a lengthier quote from In the Matter of BP Pipelines (North America) Inc.,
which it alleges changes the application of PHMSA precedent.32 On the contrary, I find that the
complete quote in BP Pipeline supports PHMSA’s reasoning that Centurion had useable data
collected on the date of the tool run. Furthermore, PHMSA precedent has established that it is
the operator’s responsibility to obtain sufficient information under § 195.452(h)(2), except where
impracticable; in this case, however, Centurion fell short of doing so within the 180-day
timeframe.33 Therefore, I reject this argument that PHMSA’s established precedent supports
Centurion’s position.
Finding no reason to modify the findings in the Final Order, PHMSA affirms the violation of
§ 195.452(h)(2). As for the civil penalty, I have reviewed the assessment criteria cited in the
Violation Report, along with the evidence and arguments presented, and find that a reduction in
28 Post-Hearing Brief, at 20; Petition, at 6-7; Hearing Transcript, at 33:9-13
29 Post-Hearing Brief, at 20; Petition, at 6; Hearing Transcript, at 35:11-12, 47:12-21, 54:12-20.
30 Post-Hearing Brief, at 20; Petition, at 6; Hearing Transcript, at 46:5-12, 55:7-8.
31 ExxonMobil Pipeline Co., CPF 4-2013-5027 (Decision on Petition for Reconsideration), 2016 WL 2753318, at *9
(April 1, 2016).
32 “[D]iscovery is not tied solely to the date of the tool run but to the fact that at the completion of a tool run there
are assessment results from which an operator can obtain sufficient information.” BP Pipelines (North America),
Inc., CPF No. 3- 2005-5030, 2006 WL 7129217, at *6 (Sept. 6, 2006)).
33 “Even though § 195.452(h)(2) did not require Respondent to receive a final report within 180 days, it did require
Respondent to obtain ‘sufficient information,’ which means enough information to allow an operator to accurately
and reliably identify, locate, validate, and evaluate pipeline anomalies detected by the integrity assessment and to
properly classify them for repair, if necessary, under § 195.452(h).” Alyeska Pipeline Service Company, CPF No. 5-
2006-5018, Final Order, at 4-5 (issued Jan. 13, 2010)



CPF No. 4-2014-5028
Page 11
the penalty for good faith is warranted for this Item. Specifically, while Centurion’s use of new
and innovative ILI technology does not excuse the company from failing to comply with
§ 195.452(h)(2), it does provide a reasonable rationale for Centurion’s delay in meeting the 180-
day deadline for discovery. Accordingly, a reduced civil penalty of $14,400 is assessed for the
violation.
Item 6 in the Final Order found that Centurion violated 49 C.F.R. § 195.452(h)(4), which states:
§ 195.452 Pipeline integrity management in high consequence areas.
(a) ….
(h) What actions must an operator take to address integrity issues?...
(4) Special requirements for scheduling remediation -- (i) Immediate
repair conditions. An operators’ evaluation and remediation schedule must
provide for immediate repair conditions. To maintain safety, an operator
must temporarily reduce the operating pressure or shut down the pipeline
until the operator completes the repair of these conditions. An operator must
calculate the temporary reduction in operating pressure using the formulas
referenced in paragraph (h)(4)(i)(B) of this section. If no suitable remaining
strength calculation method can be identified, an operator must implement
a minimum 20 percent or greater operating pressure reduction, based on
actual operating pressure for two months prior to the date of inspection,
until the anomaly is repaired. An operator must treat the following
conditions as immediate repair conditions:
(A) Metal loss greater than 80% of nominal wall regardless of
dimensions.
(B) A calculation of the remaining strength of the pipe shows a
predicted burst pressure less than the established maximum operating
pressure at the location of the anomaly. Suitable remaining strength
calculation methods include, but are not limited to, ASME/ANSI B31G
(incorporated by reference, see § 195.3) and PRCI PR-3-805 (R-STRENG)
(incorporated by reference, see § 195.3).
(C) A dent located on the top of the pipeline (above the 4 and 8 o'clock
positions) that has any indication of metal loss, cracking or a stress riser.
(D) A dent located on the top of the pipeline (above the 4 and 8 o'clock
positions) with a depth greater than 6% of the nominal pipe diameter.
(E) An anomaly that in the judgment of the person designated by the
operator to evaluate the assessment results requires immediate action.
The Final Order found that Petitioner violated 49 C.F.R. § 195.452(h)(4) by failing to lower the
operating pressure or shutting down the pipeline upon discovering six immediate-repair
conditions and assessed a civil penalty of $40,300 for the violation. Specifically, PHMSA found
that upon discovering six immediate-repair conditions on July 11, 2012, Centurion failed to
reduce the operating pressure or shut down the pipeline until it completed the repairs on August
3, 2012. The conditions were classified as immediate-repair conditions, which prompted
Petitioner to schedule excavations to validate the conditions. However, the company failed
either “to reduce operating pressure or shut down the pipeline” until the company could



CPF No. 4-2014-5028
Page 12
complete the repair.34 Furthermore, Centurion had enough information to classify the conditions
prior to excavation and did in fact classify them as immediate repairs, thereby obligating the
company to reduce operating pressure or shut down the pipeline even if the classification turned
out to be a conservative estimate.
In the Petition, Centurion argued that the finding of violation in Item 6 should be withdrawn for
the following reasons: (1) Centurion’s ANSI / ASME Standard B31.4 (Std B31.4) calculations
yielded a safe operating pressure that was higher than the operating pressure in use at the time;
and (2) the allegation of violation runs contrary to PHMSA’s own guidance contained in the
preamble of the 2002 final rule amending 49 C.F.R. § 195.452(h)(4), which indicated that
“pressure reductions should be based on an engineering evaluation…… Centurion performed
that calculation and operated its pipeline at a safe operating pressure below the operating
pressure yielded by the required calculation.”35
With regard to argument (1), Centurion now contends that it provided evidence of its Std B31.4
calculations for the record and that this evidence was not properly considered by PHMSA in the
Final Order.36 But this argument was not presented prior to issuance of the final order.37 Despite
being provided ample opportunity to raise this argument of its Std B31.4 calculations yielding a
safe operating pressure prior to the Final Order, such as in its pre- and post-hearing submissions
or at the hearing, Centurion failed to do so and is now raising this argument for the first time
without explaining why it was not presented previously. Nevertheless, I find that Petitioner’s
argument falls short of demonstrating compliance with § 195.452(h)(4).
Section 195.452(h)(4)(i) requires an operator to temporarily reduce pressure or shut down the
pipeline upon discovery of an immediate-repair condition, until the condition is repaired. The
Final Order determined that Centurion should have reduced the operating pressure or shut down
the affected pipeline when it identified six conditions as immediate-repair conditions on July 11,
2012. The records produced by Centurion fail to demonstrate that it took such action in
accordance with § 195.452(h)(4). Centurion was required to reduce the operating pressure to a
minimum pressure not less than twenty percent of the highest operating pressure occurring at the
anomaly’s locations during the preceding sixty days.38 Pursuant to Centurion’s pressure-reading
charts from the preceding two months, the highest discharge pressure occurred on June 5, 2012
at approximately 700 psi, which means Centurion was required to reduce pressure to 140 psi.
However, the discharge operating pressure for the affected immediate-repair conditions from
July 12, 2012, to August 3, 2012, ranged from approximately 480 psi to 620 psi, higher than the
34 Final Order, at 11.
35 Petition, at 3-4.
36 See Petitioner’s Exhibit F. I note that these records were previously attached to OPS’ Violation Report in support
of Item 6. (See also PHMSA Violation Report, dated October 23, 2014, at 310-319.)
37 49 C.F.R. § 190.243(b).
38 Section 7.1.2, Action Required Upon Discovery of an Immediate Repair Condition, Centurion’s Integrity
Management Plan (IMP).



CPF No. 4-2014-5028
Page 13
safe pressure permitted by the regulation.39 Therefore, Centurion failed to reduce the operating
pressure to a minimum pressure not less than twenty percent of the highest operating pressure
occurring in the preceding sixty days in accordance with its IMP procedures or § 195.452(h)(4).
With regard to argument (2), Centurion is again raising a new argument without indicating why
it failed to previously raise it prior to issuance of the Final Order. Specifically, Centurion
contends that PHMSA is acting contrary to its own guidance from the 2002 final rule that
amended § 195.452(h)(4).40 Specifically, Petitioner relies on a limited statement within the
preamble, without providing the full context of PHMSA’s statement, which reads as follows:
[PHMSA] agree[s] that pressure reductions should be based on an engineering
evaluation, and changed the final rule accordingly. Although it is appropriate to
base the pressure reduction on the remaining wall thickness for corrosion, this may
not be the best method on which to base a pressure reduction for dents and gouges.
We modified the requirement so that an operator must calculate the temporary
reduction in the operating pressure using the formula in section 451.7 of
ASME/ANSI B31.4.41
As previously discussed, Petitioner does not demonstrate how the determination in the Final
Order or the above analysis runs contrary to the preamble language, which dealt with the issue of
the proper amount of a pressure reduction. The allegation of violation here does not involve the
amount of a pressure reduction but whether one was taken at all. The evidence is clear in this
case that Centurion neither took a pressure reduction nor shut down the pipeline in the face of a
potentially serious safety risk. The language of the regulation is clear: the operator must take
one action or the other. Additionally, Petitioner’s argument is contrary to the clear language in
its own IMP procedures and the plain language of the code. Therefore, I conclude Centurion’s
argument is without merit.
Finding no reason to modify the findings in the Final Order or the amount of the assessed
penalty, PHMSA affirms the violation of § 195.432(h)(4) and the civil penalty of $40,300.
Conclusion
Based on a review of the record and the information provided in the Petition, I hereby deny the
Petition in part and grant it in part, for the reasons set forth above.
Payment of the reduced civil penalty of $122,700 for Items 1, 2, 3, 5 and 6 is now due and must
be made within 20 days of service of this Decision. The payment instructions were set forth in
detail in the Final Order. Failure to pay the $122,700 civil penalty will result in accrual of
interest at the current annual rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9, and 49
C.F.R. § 89.23. Pursuant to those same authorities, a late penalty charge of six percent (6%) per
39 Id.
40 67 FR 1650, 1654-1655.
41 Id.



CPF No. 4-2014-5028
Page 14
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 United States District Court.
This Decision constitutes final agency action taken by PHMSA in the enforcement proceeding.
The terms and conditions of this Decision are effective upon service in accordance with
49 C.F.R. § 190.5.
June 27, 2019
_____________________________ __________________________
Alan K. Mayberry Date Issued
Associate Administrator
for Pipeline Safety

420145028_Final Order_03302017_text.pdf

March 30, 2017
Mr. Mike Morgan
General Manager - Operations
Centurion Pipeline L.P.
5 Greenway Plaza, Suite 110
Houston, TX 77046
Re: CPF No. 4-2014-5028
Dear Mr. Morgan:
Enclosed please find the Final Order issued in the above-referenced case. It makes findings of
violation and assesses a reduced civil penalty of $137,100. 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 certified mail is effective 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. R.M. Seeley, Director, Southwest Region, PHMSA, OPS
Mr. Ahren Tryon, Tryon Law Firm, 4148 Hockaday Drive, Dallas, Texas 75229
CERTIFIED MAIL - RETURN RECEIPT REQUESTED



CPF No. 4-2014-5028
Page 2
U.S. DEPARTMENT OF TRANSPORTATION
PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION
OFFICE OF PIPELINE SAFETY
WASHINGTON, D.C. 20590
___________________________________
In the Matter of )
Centurion Pipeline, LP, )
a subsidiary of Occidental ) CPF No. 4-2014-5028
Petroleum Corporation, )
)
)
)
Respondent. )
___________________________________ )
FINAL ORDER
From April 2013 to February 2014, 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 Centurion
Pipeline, LP (Centurion or Respondent) in Texas, New Mexico, and Oklahoma. Centurion
operates approximately 2,500 miles of pipeline transporting crude oil in Texas, New Mexico, and
Oklahoma.1
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to
Respondent, by letter dated November 10, 2014, 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 Centurion had committed six violations of 49 C.F.R. Part 195 and
proposed a civil penalty of $165,900 for the alleged violations. The Notice also proposed certain
corrective measures to correct one of the alleged violations.
Centurion responded to the Notice by letter dated December 17, 2014. Centurion contested
several of the allegations and requested a hearing. Centurion submitted an additional written
response on April 20, 2015 (Supplemental Response). In accordance with 49 C.F.R. § 190.211,
a hearing was held in Houston, Texas, on April 30, 2015, before a Presiding Official from the
Office of Chief Counsel, PHMSA. After the hearing, Respondent provided a post-hearing
statement for the record dated June 26, 2015 (Closing), as well as on September 4, 2015
(Supplemental Closing). Pursuant to § 190.209(b)(7), the Director submitted a written
evaluation of Respondent’s response material on July 28, 2015 (Recommendation).
1 This information is reported by Centurion for calendar year 2015 pursuant to 49 C.F.R. § 195.49.



CPF No. 4-2014-5028
Page 3
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. § 195.432(b), which states in
relevant part:
§ 195.432 Inspection of in-service breakout tanks.
(a) . . . .
(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).2
The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) by failing to conduct
monthly Routine In-Service Inspections of breakout tanks 6832 and 6833 according to API
Standard 653 (API 653). At the time of the inspection, inspection reports were requested for
Respondent’s breakout tanks for the years 2010 through 2013. Respondent could not provide
monthly inspection reports for breakout tanks 6832 and 6833 for calendar year 2010, January
2011, February 2011, March 2011, April 2011, and August 2011.
In its Supplemental Response, Respondent claimed the evidence did not support finding the
Company had failed to perform the inspections, but only that Respondent was unable to produce
documentation of the inspections. Respondent admitted that it could not produce the inspection
reports, but argued that it had identified recordkeeping issues on its own prior to the OPS
inspection and had fixed the issue. Respondent argued that it “was in continual compliance with
the regulation for all of its breakout tanks but two, and the administrative oversight happened
over a limited time period.”3
Respondent presented no evidence that the inspections actually took place. The absence of
records supports finding a violation, particularly since records of monthly breakout tank
inspections are required to be kept pursuant to the pipeline safety regulations.4
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.432(b) by failing to conduct monthly Routine In-Service Inspections of breakout tanks
6832 and 6833 according to API 653.
2 API 653, Section 6.3.1.2 states the time between Routine In-Service Inspections shall not exceed one
month.
3 Supplemental Response at 7.
4 § 195.404(c)(3) (requiring an operator to maintain a record of each required inspection).



CPF No. 4-2014-5028
Page 4
Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b), which states in
relevant part:
§ 195.432 Inspection of in-service breakout tanks.
(a) . . . .
(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).5
The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) by failing to conduct
External Inspections of four breakout tanks, 6688, 6965, 6948, and 2722 within the required five-
year interval according to API 653.
With respect to tank 6688, Respondent performed an External Inspection on February 5, 2008,
and then March 7, 2014, which exceeded the five-year interval by 394 days. With respect to tank
6965, Respondent performed an inspection on August 7, 2008, and then October 10, 2013, which
exceeded the five-year interval by 63 days. With respect to tank 6948, Respondent performed an
inspection on June 10, 2008, and then March 7, 2014, which exceeded the five-year interval by
258 days. Finally, with respect to tank 2722, Respondent performed an inspection on October
23, 2007, and then June 21, 2013, which exceeded the five-year interval by 240 days.
Respondent did not dispute that it exceeded the external inspection interval with respect to
breakout tanks 6688, 6948 and 2722, but disputed breakout tank 6965.6 Respondent argued that
“PHMSA’s inspectors may have cited Respondent because the time period between the external
inspections was 1890 days, or 5 years and two months. However, this is not a violation of 49
CFR 195.432(b). The follow-up external inspection occurred within five calendar years of the
previous external inspection.”7
Section 195.432(b) requires an operator to inspect a breakout tank according to API 653. One of
the inspection requirements in the API Standard is Section 6.3.2.1, which requires a visual in-
service inspection “conducted at least every 5 years.” Respondent argued that “every 5 years”
means at least once every five calendar years. For example, under Respondent’s reasoning, an
operator may inspect a tank in January 2010 and then again in December 2015.
5 API 653, Section 6.3.2.1 states, “All tanks shall be given a visual external inspection by an authorized
inspector. This inspection shall be called the external inspection and must be conducted at least every 5
years or RCA/4N years (where RCA is the difference between the measured shell thickness and the
minimum required thickness in mils, and N is the shell corrosion rate in mils per year) whichever is less.
Tanks may be in operation during this inspection.”
6 Supplemental Response at 8.
7 Supplemental Response at 8 (emphasis added).



CPF No. 4-2014-5028
Page 5
Respondent’s assertion is incorrect. PHMSA has previously determined the five-year inspection
period required by § 195.432(b) means five periods of 365 days. In a previous final order,
PHMSA found a pipeline operator had violated § 195.432(b) when the operator exceeded the
inspection interval of five 365-day periods, even though the operator had performed the
inspection within five calendar years.8 This means that if an operator inspects a tank in January
2010, the tank must be inspected again no later than January 2015.
Respondent cited to another case in which PHMSA found a violation of § 195.432(b) after an
operator “never conducted an external inspection in the 5-year period between 2001 and 2006.”9
It is not evident from that decision, however, when or if the operator actually conducted
inspections in 2001 and 2006.
Respondent also contended that during development of the API 653 consensus standard “both
approaches [five 365-day periods and five calendar years] were accepted and used by the API
committee member representatives.”10 I do not find this information persuasive or controlling,
most notably because PHMSA has already determined the five-year inspection period means five
periods of 365 days.
Respondent exceeded the five-year external inspection period for each of the four tanks listed in
the Notice. After considering the evidence, I find that Respondent violated 49 C.F.R.
§ 195.432(b) by failing to conduct External Inspections of four breakout tanks within the
required five-year interval according to API 653.
Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b), which states in
relevant part:
§ 195.432 Inspection of in-service breakout tanks.
(a) . . . .
(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).11
8 Enbridge Pipelines (Ozark), L.L.C., CPF No. 4-2010-5008, Item 1, 2010 WL 6531638 (Aug. 17, 2010)
(finding violations of the five-year inspection interval for a number of tanks that were inspected within
five calendar years, but not within five periods of 365 days).
9 Belle Fourche Pipeline Co., CPF No. 5-2009-5042, Item 11, 2011 WL 7006607 (Nov. 21, 2011).
10 Supplemental Closing at 4.
11 API 653, Section 6.3.3.2(a) states, “When used, the ultrasonic thickness measurements shall be made
at intervals not to exceed the following: (a) When the corrosion rate is not known, the maximum interval
shall be 5 years. Corrosion rates may be estimated from tanks in similar service based on thickness
measurements taken at an interval not exceeding 5 years.”



CPF No. 4-2014-5028
Page 6
The Notice alleged that Respondent violated § 195.432(b) by failing to make Ultrasonic
Thickness (UT) measurements of breakout tanks at intervals not to exceed five years according
to API 653. Specifically, the Notice alleged that Respondent failed to perform the measurements
within the maximum interval for breakout tanks 6688, 6965, 6948, and 2722.
With respect to tank 6688, Respondent performed a UT inspection on February 5, 2008, and then
March 7, 2014, which exceeded the five-year interval by 394 days. With respect to tank 6965,
Respondent performed a UT inspection on August 7, 2008, and then October 10, 2013, which
exceeded the five-year interval by 63 days. With respect to tank 6948, Respondent performed a
UT inspection on June 10, 2008, and then March 7, 2014, which exceeded the five-year interval
by 258 days. Finally, with respect to tank 2722, Respondent performed a UT inspection on
October 23, 2007, and then June 21, 2013, which exceeded the five-year interval by 240 days.
In its Supplemental Response, Respondent stated that the five-year interval only applies when
the corrosion rate is unknown, and the five-year interval did not apply in this case because
Centurion “was well aware of the corrosion rate for the cited breakout tanks.”12 Respondent
explained that it had “adequate experience and UT inspection results with a large number of
regulated and unregulated crude oil tanks to conclude that the corrosion rate on these tanks”
justified “establishing a 10-year [UT] inspection interval.”13 It stressed that the thickness testing
went beyond PHMSA’s requirements because Respondent “considers the single spot on each
course with the minimum thickness for the course in its shell integrity evaluations, rather than
averaging the readings to obtain the general thickness, and rate of general corrosion, of the
shell.”14 For the breakout tanks at issue, based on its test results, Respondent determined that “a
longer [UT] inspection interval was warranted based on the fact that these and all other tanks
have experienced such a consistently low rate of internal corrosion since their installation.”15
OPS responded that Respondent’s claim of using Minimum Wall Thickness was invalid. OPS
requested and discussed corrosion rates for these tanks on several occasions with Respondent
during the inspection. Respondent did not provide any evidence that it had calculated corrosion
rates or estimated corrosion rates from tanks in similar service based on thickness measurements.
Instead, Respondent stated that it had adequate experience and many UT inspection results. In
order to estimate corrosion rates from other tanks in similar service, OPS argued that Respondent
needed to perform an adequate Similar Service Assessment of the tanks, as required by API 653.
The evidence demonstrates Respondent did not properly calculate corrosion rates for the tanks at
issue. Therefore, Respondent was required to comply with the five-year maximum interval for
UT inspections. While Respondent repeated its assertion from Item 2 that the five-year
inspection interval means five calendar years, that argument is rejected for the same reasons
stated above.
12 Supplemental Response at 10.
13 Supplemental Response at 10.
14 Supplemental Response at 10.
15 Supplemental Response at 10.



CPF No. 4-2014-5028
Page 7
Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R.
§ 195.432(b) by failing to make UT measurements of breakout tanks at intervals not to exceed
five years according to API 653.
Item 4: The Notice alleged that Respondent violated 49 C.F.R. §§ 195.202 and 195.264 which
state in relevant part:
§ 195.202 Compliance with specifications or standards.
Each pipeline system must be constructed in accordance with
comprehensive written specifications or standards that are consistent with
the requirements of this part.
§ 195.264 Impoundment, protection against entry, normal/emergency
venting or pressure/vacuum relief for aboveground breakout tanks.
(a) A means must be provided for containing hazardous liquids in the
event of spillage or failure of an aboveground breakout tank195.446
Control room management.
(b) After October 2, 2000, compliance with paragraph (a) of this section
requires the following for the aboveground breakout tanks specified:
(1) For tanks built to API Specification 12F, API Standard 620, and
others (such as API Standard 650 or its predecessor Standard 12C), the
installation of impoundment must be in accordance with the following
sections of NFPA 30:
(i) Impoundment around a breakout tank must be installed in accordance
with section 4.3.2.3.2; and
(ii) Impoundment by drainage to a remote impounding area must be
installed in accordance with section 4.3.2.3.1.
The Notice alleged that Respondent violated 49 C.F.R. §§ 195.202 and 195.264 by failing to
construct several breakout tanks in accordance with comprehensive written specifications or
standards that are consistent with the requirements of this part. Specifically, the Notice alleged
that Respondent failed to have specifications that demonstrated breakout tank containment
impoundments met the requirements of NFPA 30 referenced in § 195.264. The Notice also
alleged that Respondent failed to present documentation, such as surveys or calculations, for any
of their breakout tanks constructed after October 2, 2000, to verify containment impoundment
volumes met the requirements of NFPA 30.
Respondent did not contest this allegation of violation. Accordingly, after considering the
evidence, I find that Respondent violated 49 C.F.R. §§ 195.202 and 195.264 by failing to
construct several breakout tanks in accordance with comprehensive written specifications or
standards that are consistent with the requirements of this part.
Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h)(2), which states in
relevant part:



CPF No. 4-2014-5028
Page 8
§ 195.452 Pipeline integrity management in high consequence areas.
(a) . . . .
(h) What actions must an operator take to address integrity issues? . . .
(2) Discovery of condition. Discovery of a condition occurs when an
operator has adequate information about the condition to determine that the
condition presents a potential threat to the integrity of the pipeline. An
operator must promptly, but no later than 180 days after an integrity
assessment, obtain sufficient information about a condition to make that
determination, unless the operator can demonstrate that the 180-day period
is impracticable.
The Notice alleged that Respondent violated 49 C.F.R. § 195.452 by failing to obtain sufficient
information no later than 180 days after an integrity assessment to determine if a condition
presented a potential threat to the integrity of its pipeline. Specifically, the Notice alleged that on
December 3, 2011, Respondent completed an assessment using a T.D. Williamson, Inc. (TDW)
SpirALL Magnetic Flux Leakage Multi Data Set tool (SMFL MDS tool or the tool) as part of its
continual reassessment of the 16-inch Bretch to Cushing #2 system. The Notice alleged the
180-day deadline to discover conditions was 180 days from the date of the tool run, or no later
than May 31, 2012. The Notice alleged that Respondent discovered six immediate repair
anomalies on July 11, 2012, which exceeded the 180-day deadline by 41 days.
Respondent argued that it did not fail to meet the 180-day deadline because the 180-day
assessment period had “reset” on December 15, 2011, when the Company was told the tool run
had failed and would need to be rerun.16 Respondent explained that when the tool was retrieved
on December 3, 2011, it had suffered extensive damage. The damage “called into question
whether or not any salvageable data could be extracted from the ILI [inline inspection] tool much
less whether such data would be reliable.”17 The tool vendor determined the tool had collected a
large quantity of data, but warned Respondent on December 7, 2011, there was evidence that the
data might be unreliable. On December 15, 2011, the vendor informed Respondent that the
inline inspection (ILI) run was a “Failed Run” due to data quality issues and an inability to
retrieve a sufficient data set from the tool for data evaluation and integration under the specified
anomaly detection parameters.18
Respondent received over 500GB of data from TDW.19 Despite having “staffing capabilities to
look at a very small portion of the data” and having issues with TDW’s technology for grading
the full ILI run, Respondent was able to examine a sample of the raw data between December 15
and December 20, 2011.20 Respondent and TDW worked together throughout late December
2011 and January 2012. On January 27, 2012, TDW declared the tool run data usable and agreed
16 Closing at 3.
17 18 19 Closing at 3; TDW Aff. at ¶ 13.
Closing at 3; TDW Aff. at ¶ 17.
Closing at 3; TDW Aff. at ¶ 17.
20 Closing at 4.



CPF No. 4-2014-5028
Page 9
to start grading the data.21 Respondent ultimately identified six anomalies that met its immediate
repair criteria.22
Respondent claimed that “TDW’s acceptance of the data on January 27, 2012, was critical
because before that time, Centurion was left with a ‘Failed Run’ designation and a data set that
was of no use given that Centurion could not have fully processed and graded it.”23 Therefore, it
argued, the “clock” had stopped on the 180-day assessment and did not reset until TDW agreed
the data could be used. In response to OPS’s suggestion that Respondent could have processed
the data itself,24 Respondent claimed that “Centurion would not and could not attempt to grade
the SMFL Multi Data Set in-line inspection data from TDW.”25
Respondent further stated that its actions resulted in a “better outcome from a regulatory and
safety standpoint than if Centurion had opted for the other legally permissible approach of
adhering to the ‘Failed Run’ designation and conducting a new ILI run within the allotted
reassessment interval (October 2012).”26
At the hearing, OPS disagreed the 180-day period ever stopped or reset. OPS argued that
pursuant to guidance IMP FAQ 4.13, a “reset” is appropriate only when the “quality of the ILI
data is suspect and an entire successful rerun of the ILI tool is performed.”27 Moreover, an
assessment is considered complete “on the date which final field activities related to the
assessment is performed.”28 Because Respondent did not perform a rerun of the assessment,
OPS argued that no reset occurred.29 At the hearing, the Director claimed Respondent had
usable data, which meant the 180-day deadline ran from the integrity assessment on December
15, 2011.30
Analysis
Pursuant to the integrity management regulations, after an operator performs an integrity
assessment, it must “obtain, within 180 days, the assessment data and determine whether
conditions presented a threat to the pipeline.”31 Discovery is tied “to the fact that at the
21 Closing at 4; TDW Aff. at ¶ 22.
22 Closing at 5.
23 Closing at 12.
24 Closing at 14; Tr. at 87-88.
25 Closing at 15-16; Mitchell Aff. at ¶¶ 6 to 9, 13 to 14.
26 Closing at 15-16.
27 PHMSA IMP FAQ 4.13.
28 Recommendation at 6-7; PHMSA IMP FAQ 4.13.
29 Recommendation at 7.
30 Tr. at 89.
31 BP Pipelines (North America) Inc., CPF No. 3-2005-5030, Final Order, 2006 WL 4453895, aff’d,
Decision on Petition for Reconsideration, at 2, 2006 WL 7129217 (Sep. 6, 2006); Alyeska Pipeline



CPF No. 4-2014-5028
Page 10
completion of a tool run there are assessment results from which an operator can obtain
sufficient information about the condition to determine that condition presents a potential threat
to the integrity of the pipeline.”32 In a prior enforcement decision, PHMSA explained that:
While it is usually evident when an integrity assessment is completed (e.g., at the
conclusion of a pressure test or ILI tool run), PHMSA has issued guidance to assist
operators in applying the regulation in less common situations. Among other
things, FAQ 4.13 provides that if ILI tool run data is determined to be “suspect and
an entire rerun is to be performed, then the evaluation will be expected within 180
days after the successful rerun.”33
In the current proceeding, Centurion performed an integrity assessment that was completed on
December 3, 2011. The regulation required Respondent to analyze the data and determine
whether the conditions in the pipe presented a threat within 180 days. Respondent did not
perform a rerun and did not otherwise argue the 180-day requirement was impracticable.
Following the tool run on December 3, 2011, there was approximately 40 days between
December 15, 2011, and January 27, 2012, during which Respondent believed the tool data was
unusable. But once Respondent understood the data was usable on January 27, 2012,
Respondent had more than 120 days before the regulatory deadline to determine the conditions
on the pipeline. Respondent has not contended, nor do I find, this constituted an
impracticability.
Respondent’s notable effort to salvage workable data from a potentially failed tool run is
considered below in the penalty assessment section. After considering all of the evidence,
however, I find that Respondent violated 49 C.F.R. § 195.452(h)(2) by failing to obtain sufficient
information about a condition to determine if the condition presented a potential threat to the
integrity of the pipeline no later than 180 days after the integrity assessment.
Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h)(4), which states in
relevant part:
Service Co., CPF No. 5-2006-5018, Final Order at 2, 2010 WL 6500066, aff’d Decision on Petition for
Reconsideration, 2010 WL 2228550 (Mar. 1, 2010) (finding that the operator violated 49 C.F.R.
§ 195.452(h)(2) by failing to promptly obtain, within 180 days after an integrity assessment, sufficient
information about anomalous conditions on the pipeline to determine if they present a potential threat to
integrity where vendor data was not provided until approximately 330 days after the integrity
assessment).
32 BP Pipelines (North America) Inc., CPF No. 3-2005-5030, Decision on Petition for Reconsideration, at
4, 2006 WL 4453895 (Sep. 6, 2006).
33 ExxonMobil Pipeline Co., CPF No. 4-2011-5016, Final Order at 21, 2013 WL 4478404 (June 27,
2013) (citing PHMSA IMP FAQ 4.13), aff’d, Decision on Petition for Reconsideration, 2014 WL
4635422 (July 9, 2014).



CPF No. 4-2014-5028
Page 11
§ 195.452 Pipeline integrity management in high consequence areas.
(a) . . . .
(h) What actions must an operator take to address integrity issues? . . .
(4) Special requirements for scheduling remediation—(i) Immediate repair
conditions. An operator’s evaluation and remediation schedule must
provide for immediate repair conditions. To maintain safety, an operator
must temporarily reduce operating pressure or shut down the pipeline until
the operator completes the repair of these conditions. An operator must
calculate the temporary reduction in operating pressure using the formula
in Section 451.6.2.2 (b) of ANSI/ASME B31.4 (incorporated by reference,
see § 195.3). An operator must treat the following conditions as immediate
repair conditions:
(A) Metal loss greater than 80% of nominal wall regardless of
dimensions.
(B) A calculation of the remaining strength of the pipe shows a predicted
burst pressure less than the established maximum operating pressure at the
location of the anomaly. Suitable remaining strength calculation methods
include, but are not limited to, ASME/ANSI B31G (“Manual for
Determining the Remaining Strength of Corroded Pipelines” (1991) or
AGA Pipeline Research Committee Project PR-3-805 (“A Modified
Criterion for Evaluating the Remaining Strength of Corroded Pipe”
(December 1989)). These documents are incorporated by reference and are
available at the addresses listed in Sec. 195.3.
(C) A dent located on the top of the pipeline (above the 4 and 8 o’clock
positions) that has any indication of metal loss, cracking or a stress riser.
(D) A dent located on the top of the pipeline (above the 4 and 8 o’clock
positions) with a depth greater than 6% of the nominal pipe diameter.
(E) An anomaly that in the judgment of the person designated by the
operator to evaluate the assessment results requires immediate action.
The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h)(4) by failing to temporarily
reduce operating pressure or shut down a pipeline until repairs of immediate conditions were
completed. Specifically, the Notice alleged that Respondent discovered six immediate repair
conditions on July 11, 2012, but failed to reduce operating pressure or shut down the pipeline
until the completion of the repairs on August 3, 2012.
Respondent argued that it did not violate the regulation for two reasons. First, Respondent
argued there were no immediate repair conditions. Respondent stated that the locations were
incorrectly identified as having dents with metal loss because the ILI tool “produced high-
resolution data sets with such granularity that it was capable of picking up what Centurion found
to be mill defects.”34 In other words, Respondent had acted on “preliminary information out of
an abundance of caution” and upon digging up the conditions found only “very small dent[s] but
34 Respondent Post-hearing Brief at 25 (emphasis omitted).



CPF No. 4-2014-5028
Page 12
no metal loss at each site.”35 Second, Respondent argued that even if the conditions were
immediate repair conditions, Respondent complied with the regulation by repairing the defects
within about two hours of digging up the conditions.
Analysis
Section 195.452(h)(4) requires a pipeline operator to remediate integrity issues according to a
schedule. Certain conditions must be repaired immediately, including any dent on the top of the
pipeline that has any indication of metal loss. An operator must immediately reduce pipeline
operating pressure or shut down a pipeline that has an immediate repair condition until the repair
is completed.
Respondent identified six conditions on July 11, 2012. The conditions were classified as
immediate repair conditions causing Respondent to schedule excavations to validate the
conditions. Although Respondent may not have known for certain if the conditions met
immediate repair criteria until their excavations, Respondent had enough information to classify
the conditions and Respondent did in fact classify them as immediate repairs. This obligated
Respondent to reduce operating pressure or shut down the pipeline even if classification of the
conditions was a conservative estimate based on the information available.36
In prior enforcement proceedings, PHMSA has consistently determined that an operator must
comply with § 195.452(h)(4) and reduce operating pressure or shut down the pipeline, even if the
operator’s classification of a condition is a conservative estimate. PHMSA has also determined
that § 195.452(h)(4) requires a pressure reduction or shutdown even if the condition meets
immediate repair criteria only after factoring in conservative tool tolerances.37
After considering the evidence, I find that Respondent violated 49 C.F.R. § 195.452(h)(4) by
failing to lower operating pressure or shut down the pipeline upon discovering six immediate
repair conditions.
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.
35 Respondent Post-hearing Brief at 25.
36 See, e.g., Alyeska Pipeline Service Co., CPF 5-2006-5018, Item 2, 2010 WL 6500066, at *4 (Jan. 13,
2010) (finding an anomaly must be treated as an immediate repair condition once the operator determines
it could meet the immediate repair criteria, even if the operator's determination is a conservative
estimate.)
37 ExxonMobil Pipeline Co., CPF No. 4-2013-5027, Item 5, 2015 WL 7175715, at *17 (Oct. 1, 2015).



CPF No. 4-2014-5028
Page 13
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 $165,900 for the violations cited above.
Item 1: The Notice proposed a civil penalty of $42,400 for Respondent’s violation of 49 C.F.R.
§ 195.432(b), for failing to conduct monthly inspections of two breakout tanks.
Respondent requested that the penalty be eliminated due to the alleged insufficiency of the
record compiled by PHMSA with respect to the assessment criteria requirements of 49 C.F.R.
§ 190.225. Having reviewed the record, including the Violation Report, which discusses each of
the assessment factors for each of the violations, I find Respondent’s argument does not warrant
elimination of the penalty.
With regard to nature and circumstances, OPS noted in the Violation Report this violation
concerned a failure to provide reports that documented monthly tank inspections. Respondent
argued that the penalty should be reduced under these factors because the violation was simply a
failure to keep records and only involved two tanks for a limited period of time. I reject this
argument. Respondent failed to provide any evidence that the required monthly inspections were
actually conducted and the time period in question is not insignificant.
With regard to gravity, OPS noted in the Violation Report that safe operation was minimally
affected. Respondent did not challenge this assessment.
With regard to good faith, the Violation Report suggested no credit. Respondent argued that the
penalty should be reduced under this factor because the violation only involved two tanks for a
limited period of time, the Company complied with the regulation for other tanks, and the
Company corrected the non-compliance before the inspection. I reject these arguments. The
number of tanks and the period of non-compliance warrants the proposed civil penalty.
With regard to culpability, OPS noted in the Violation Report that the operator failed to take
appropriate steps to comply with a requirement that was clearly applicable. Respondent argued
that the penalty should be reduced under this factor because it discovered the non-compliance
and took documented action to address the issue. I find Respondent’s argument persuasive. The
record reflects that Respondent had monthly inspection records for all breakout tanks after
August 2011. Since Respondent discovered and corrected the non-compliance before the OPS
inspection, a reduction to the penalty is appropriate.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a reduced civil penalty of $20,800 for violation of 49 C.F.R. § 195.432(b).



CPF No. 4-2014-5028
Page 14
Item 2: The Notice proposed a civil penalty of $23,600 for Respondent’s violation of 49 C.F.R.
§ 195.432(b), for failing to conduct five-year external inspections of four breakout tanks.
With regard to nature and circumstances OPS noted in the Violation Report that this violation
concerned a failure to inspect the breakout tanks at the proper interval to evaluate suitability for
continued service, which presented a risk to pipeline safety. Respondent argued that the penalty
should be reduced because breakout tank 6965 was inspected within five calendar years. Since
the finding of violation already explains how Respondent violated the regulation, this argument
is rejected.
With regard to gravity, OPS noted in the Violation Report that safe operation was minimally
affected. Respondent did not challenge this assessment. The Violation Report suggested no
credit under the culpability and good faith factors. In support of reduction of the penalty under
these factors, Respondent only repeated arguments that have already been rejected.
As operator of the pipeline facility, Respondent is culpable for this violation of the pipeline
safety regulations. I have also weighed Respondent’s history of prior offenses and find that
when viewed as a whole, it supports the proposed penalty and does not warrant reduction.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $23,600 for violation of 49 C.F.R. § 195.432(b).
Item 3: The Notice proposed a civil penalty of $23,600 for Respondent’s violation of 49 C.F.R.
§ 195.432(b), for failing to make ultrasonic thickness measurements of four breakout tanks.
With regard to nature and circumstances, OPS noted in the Violation Report that this violation
concerned a failure to measure thickness of the tanks at the proper interval to evaluate suitability
for continued service, which presented a risk to pipeline safety. Respondent argued that this item
should be withdrawn because the Company was well aware of the corrosion rate for the cited
breakout tanks based on thickness measurements over the service life of these and other tanks in
similar service. Respondent argued that because of these estimates, the five-year interval did not
apply. Since the finding of violation already explains how Respondent violated the regulation,
these arguments are rejected.
With regard to gravity, OPS noted in the Violation Report that safe operation was minimally
affected. Respondent did not challenge this assessment. The Violation Report suggested no
credit under the culpability and good faith factors. Respondent argued that if this item is not
withdrawn, the penalty should be eliminated or significantly reduced. In support Respondent
only repeated arguments that have already been rejected.
As operator of the pipeline facility, Respondent is culpable for this violation of the pipeline
safety regulations. I have also weighed Respondent’s history of prior offenses and find that
when viewed as a whole, it supports the proposed penalty and does not warrant reduction.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $23,600 for violation of 49 C.F.R. § 195.432(b).



CPF No. 4-2014-5028
Page 15
Item 5: The Notice proposed a civil penalty of $36,000 for Respondent’s violation of 49 C.F.R.
§ 195.452(h)(2) by failing to obtain sufficient information about a condition to determine if the
condition presented a potential threat to the integrity of the pipeline no later than 180 days after
an integrity assessment.
Respondent argued that this item should be withdrawn because the Company did not fail to meet
the 180-day deadline. Since the finding of violation already explains how Respondent violated
the regulation, this argument is rejected.
With regard to nature, OPS noted in the Violation Report that this violation concerned an
activities violation. Respondent did not challenge this assessment. With regard to
circumstances, OPS noted in the Violation Report that this violation began on June 1, 2012 and
had a duration of 40 days. Respondent argued that there was no violation and that the June 1,
2012 date should be modified to reflect a start date for the “discovery period” of January 27,
2012. Since the finding of violation already explains how Respondent violated the regulation,
this argument is rejected.
With regard to gravity, OPS noted in the Violation Report that the failure to discover conditions
within 180 days of an integrity assessment could result in a hazardous situation to the pipeline.
Respondent argued that the penalty should be reduced because there is no evidence in the record
that pipeline safety or integrity was compromised. I reject this argument. I find sufficient
support in the record that violating the pipeline safety regulations by delaying discovery of
unsafe conditions on the pipeline constituted an increased risk that compromised safety.
With regard to culpability, I note that Respondent made an effort to salvage workable data from
an initial tool run that had, at least at one point, been considered by the tool vendor to be a failed
run. This eventually led to a data set that could be analyzed for potential threats to pipeline
integrity in a shorter period of time than if Respondent had rerun the tool. Thus I find a
reduction to the penalty is appropriate.
Accordingly, having reviewed the record and considered the assessment criteria I assess
Respondent a reduced civil penalty of $28,800 for violation of 49 C.F.R. § 195.452(h)(2).
Item 6: The Notice proposed a civil penalty of $40,300 for Respondent’s violation of 49 C.F.R.
§ 195.452(h)(4) by failing to temporarily reduce operating pressure or shut down the pipeline
until repairs of immediate conditions were completed.
With regard to nature and circumstances, OPS noted in the Violation Report that this violation
concerned a failure to temporarily reduce operating pressure or shut down the pipeline until
classified immediate repairs were completed. Respondent argued that this item should be
withdrawn because there were no immediate repair conditions and that the defects were repaired
within two hours of digging up the conditions. Since the finding of violation already explains
how Respondent violated the regulation, these arguments are rejected.



CPF No. 4-2014-5028
Page 16
With regard to gravity, OPS noted in the Violation Report that the failure to reduce pressure
upon discovery of immediate repair conditions may result in the release of product into the
environment. Respondent argued that the penalty should be reduced because there is no
evidence in the record that pipeline safety or integrity was compromised. I reject this argument.
I find sufficient support in the record that Respondent’s failure to comply with the pipeline safety
regulations that required the Company to immediately reduce pressure or shut down the pipeline
due to unsafe conditions constituted an increased risk that compromised safety.
The Violation Report suggested no credit under the culpability and good faith factors.
Respondent only repeated arguments that have already been rejected.
As operator of the pipeline facility, Respondent is culpable for this violation of the pipeline
safety regulations. I have also weighed Respondent’s history of prior offenses and find that
when viewed as a whole, it supports the proposed penalty and does not warrant reduction.
Accordingly, having reviewed the record and considered the assessment criteria, I assess
Respondent a civil penalty of $40,300 for violation of 49 C.F.R. § 195.452(h)(4).
In summary, Respondent is assessed a total civil penalty of $137,100.
Payment of the civil penalty must be made within 20 days of service. Federal regulations
(49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal
Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed
instructions are contained in the enclosure. Questions concerning wire transfers should be
directed to: Financial Operations Division (AMK-325), Federal Aviation Administration, 6500 S
MacArthur Blvd., Oklahoma City, Oklahoma 79169. The Financial Operations Division
telephone number is (405) 954-8845.
Failure to pay the $137,100 civil penalty will result in accrual of interest at the current annual
rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to
those same authorities, a late penalty charge of six percent (6%) per annum will be charged if
payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty
may result in referral of the matter to the Attorney General for appropriate action in a district
court of the United States.
COMPLIANCE ORDER
The Notice proposed a compliance order with respect to Item 4 in the Notice for violations of 49
C.F.R. §§ 195.202 and 195.264. 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. The Director
indicated that Respondent has taken the following actions specified in the proposed compliance
order:



CPF No. 4-2014-5028
Page 17
With respect to the violations of §§ 195.202 and 195.264 (Item 4), Respondent evaluated
its tank dike areas and ensured that the dike areas meet the impoundment criteria.
Centurion has provided documentation to PHMSA in the form of current surveys,
drawings, and calculations that show the containment is in compliance with the
applicable requirements.
I find that compliance has been achieved with respect to this violation. Therefore, the
compliance terms proposed in the Notice are not included in this Order.
Under 49 C.F.R. § 190.243, Respondent may submit a petition for reconsideration of this Final
Order to the Associate Administrator for Pipeline Safety, PHMSA, 1200 New Jersey Avenue SE,
East Building, 2nd Floor, Washington, D.C. 20590, no later than 20 days after receipt of the
Final Order by Respondent. Any petition submitted must contain a statement of the issue(s) and
meet all other requirements of 49 C.F.R. § 190.243. The filing of a petition automatically stays
the payment of any civil penalty assessed. The other terms of the order, including corrective
action, remain in effect unless the Associate Administrator, upon request, grants a stay.
The terms and conditions of this Final Order are effective upon service in accordance with 49
C.F.R. § 190.5.
March 30, 2017
___________________________________ ________________________
Alan K. Mayberry Date Issued
Associate Administrator
for Pipeline Safety

420145028_Closure Letter_08292019_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
August 29, 2019
Mike Prince
Chief Executive Officer
Lotus Midstream, LLC
2150 Town Square, Ste 395
Houston, Texas 77046-7570
CPF 4-2014-5028
Dear Mr. Prince:
On June 27, 2019, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued
to Centurion Pipeline, LP a Decision on the Petition for Reconsideration in the above-referenced
case. This Decision affirmed the violations in the Final Order with a reduced Civil Penalty. Based
on our review of the documentation you have 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,
Mary L. McDaniel, P.E.
Director, Southwest
Pipeline and Hazardous Materials Safety Administration
Enclosure:
cc: Mr. Mike Morgan, General Manager-Operations, Centurion Pipeline, LP, 5 Greenway
Plaza, Suite 110, Houston, Texas 77046

420145028_NOPV PCP PCO_11102014_text.pdf

NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED COMPLIANCE ORDER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
November 10, 2014
Mr. Bill Moyer
President
Centurion Pipeline, L.P.
5 Greenway Plaza, Suite 110
Houston, TX 77046
CPF 4-2014-5028
Dear Mr. Moyer:
On April 2013 to February 2014, 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 in Texas, New
Mexico, and Oklahoma.
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. 195.432 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).
Centurion did not inspect the physical integrity of in-service atmospheric breakout tanks
according to API Standard 653. API Standard 653, Section 6.3.1.2 states the Routine In-Service
Inspections shall not exceed one month. Centurion’s Liquid Operations Manual, procedure P-
195.432, Inspection of In-Service Breakout Tanks, also states the frequency for Routine In-
service Inspection is monthly. Their Monthly Inspection of In-service Breakout Tanks Form F-
195.432(b) states the inspection form will be retained for five years.
At the time of the inspection, inspection reports were requested for Centurion’s breakout tanks
for the years 2010 through 2013. Breakout tanks 6832 and 6833 are located in Centurion’s
Wasson Facility along with three other breakout tanks, 6719, 6830, and 6831. Monthly
inspection reports were provided for tanks 6719, 6830, and 6831 for the time period as requested.
Centurion failed to provide monthly Routine In-Service Inspection reports for breakout tanks
6832 and 6833 to demonstrate the tanks were inspected as required by 49 CFR 195 and API
Standard 653, Section 6.3.1.2, incorporated by reference. Specifically, Centurion did not provide
monthly inspection reports for breakout tanks 6832 and 6833 for all of year 2010, January 2011,
February 2011, March 2011, April 2011, and August 2011.
2. 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).
Centurion did not inspect the physical integrity of in-service atmospheric breakout tanks
according to API Standard 653. API 653, Section 6.3.2.1 states, “All tanks shall be given a
visual external inspection by an authorized inspector. This inspection shall be called the external
inspection and must be conducted at least every 5 years or RCA/4N years (where RCA is the
difference between the measured shell thickness and the minimum required thickness in mils,
and N is the shell corrosion rate in mils per year) whichever is less. Tanks may be in operation
during this inspection.”
Centurion’s Liquid Operations Manual, procedure P-195.432, Inspection of In-Service Breakout
Tanks, also states the frequency for External Inspections is “Every 5 years”. Their Monthly
2



Inspection of In-service Breakout Tanks Form F-195.432(b) states the inspection form will be
retained for five years.
The following table summarizes the tanks that exceeded the 5 year interval.
Tank
Nominal
API 653
API 653
Capacity
(bbl.)
Date
Built
Roof
Type
Construction
Shell
Bottom
External
Previous
External
Current
External
Lining
Interval
6688
| 85000
1950
EFR
Welded
None
2/5/2008
3/7/2014
>5
6965
111000
1950
EFR
Welded
Claymax
8/7/2008
10/10/2013
>5
6948
30000
1950
EFR
Welded
None
06/10/08
3/7/2014
>5
2722
| 80000
1957
EFR
Welded
Claymax
10/23/2007 | 6/21/2013
>5
The previous External Inspection for tank 6688 was performed on February 5, 2008, during an
out of service internal inspection. The final out of service inspection report demonstrates there
was no corrosion rate calculated or established for Tank 6688. According to API 653, Section
6.3.2.1., the External Inspection interval is 5 years since the corrosion rate is unknown. The
following External Inspection was performed on March 7, 2014, which exceeded the 5 year
interval by 394 days.
The previous External Inspection for tank 6965 was performed on August 7, 2008, during an out
of service internal inspection. Centurion did not provide documentation or reports demonstrating
a corrosion rate was calculated of established for Tank 6965. According to API 653, Section
6.3.2.1., the External Inspection interval is 5 years since the corrosion rate is unknown. The
following External Inspection was performed on October 10, 2013, which exceeded the 5 year
interval by 63 days.
The previous External Inspection for tank 6948 was performed on June 10, 2008, during an in-
service inspection. Centurion did not provide documentation or reports demonstrating a
corrosion rate was calculated or established for Tank 6948. According to API 653, Section
6.3.2.1., the External Inspection interval is 5 years since the corrosion rate is unknown. The
following External Inspection was performed on March 7, 2014, which exceeded the 5 year
interval by 258 days.
The previous External Inspection for tank 2722 was performed on October 23, 2007, during an
out of service inspection. Centurion did not provide documentation or reports demonstrating a
corrosion rate was calculated or established for Tank 2722. According to API 653, Section
6.3.2.1., the External Inspection interval is 5 years since the corrosion rate is unknown. The
following External Inspection was performed on June 21, 2013, which exceeded the 5 year
interval by 240 days.
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
3



(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).
Centurion did not inspect the physical integrity of in-service atmospheric breakout tanks
according to API Standard 653. API 653, Section 6.3.3.2 states, API 653, Section 6.3.3.2(a)
states, "When used, the ultrasonic thickness measurements shall be made at intervals not to
exceed the following:
a) When the corrosion rate is not known, the maximum interval shall be 5 years. Corrosion
rates may be estimated from tanks in similar service based on thickness measurements
taken at an interval not exceeding 5 years."
Centurion's Liquid Operations Manual, procedure P-195.432, Inspection of In-Service Breakout
Tanks, states the frequency for Ultrasonic Thickness Inspections is "Every 5 years". Their
Monthly Inspection of In-service Breakout Tanks Form F-195.432(b) states the inspection form
will be retained for five years.
Centurion failed to perform "Ultrasonic Thickness Inspections" within the maximum interval of
five years prescribed by API 653 Section 6.3.3.2, for the following breakout tanks that have
unknown corrosion rates:
Tank
Nominal
(bbl.)
Capacity
Built
Date
Roof
Shell
Bottom
API 653
API 653
Type
Construction
Lining
Previous
External
External
Current
External
Interval
6688
85000
1950
EFR
Welded
None
2/5/2008
317/2014
>5
6965
111000
1950
EFR
Welded
Claymax
8/7/2008
10/10/2013
>5
6948
30000
1950
EFR
Welded
None
06/10/08
3/7/2014
>5
2722
80000
1957
EFR
Welded
Claymax
10/23/2007 | 6/21/2013
>5
The previous Ultrasonic Thickness Inspection (UTI) for tank 6688 was performed on February 5,
demonstrates there was no corrosion rate calculated or established for Tank 6688. According to
2008 during an out of service internal inspection. The final out-of-service inspection report
API 653, Section 6.3.3.2., the UTI interval is 5 years since the corrosion rate is unknown. The
current UTI was performed on March 7, 2014, which exceeded the 5 year interval by 394 days.
The previous UTI for tank 6965 was performed on August 7, 2008, during an out of service
internal inspection. The final out-of-service inspection report demonstrates there was no
corrosion rate calculated or established for Tank 6965. According to API 653, Section 6.3.3.2.,
the UTI interval is 5 years since the corrosion rate is unknown. The current UTI was performed
on October 10, 2013, which exceeded the 5 year interval by 63 days.
The previous UTI for tank 6948 was performed on June 10, 2008, during an in-service
inspection. Centurion did not provide documentation or reports demonstrating a corrosion rate
4



was calculated or established for Tank 6948. According to API 653, Section 6.3.3.2., the UTI
interval is 5 years since the corrosion rate is unknown. The current UTI was performed on
March 7, 2014, which exceeded the 5 year interval by 258 days.
The previous UTI for tank 2722 was performed on October 23, 2007, during an out of service
inspection. The final out-of-service report demonstrates there was no corrosion rate calculated or
established for Tank 2722. According to API 653, Section 6.3.3.2., the UTI interval is 5 years
since the corrosion rate is unknown. The current UTI was performed on June 21, 2013, which
exceeded the 5 year interval by 240 days.
4. §195.202 Compliance with specifications or standards.
Each pipeline system must be constructed in accordance with comprehensive
written specifications or standards that are consistent with the requirements of this
part.
195.264 Impoundment, protection against entry, normal/emergency venting or
pressure/vacuum relief for aboveground breakout tanks.
Impoundment, protection against entry, normal/emergency venting
(b) After October 2, 2000, compliance with paragraph (a) of this section requires the
following for the aboveground breakout tanks specified:
(1) For tanks built to API Specification 12F, API Standard 620, and others (such as API
Standard 650 or its predecessor Standard 12C), the installation of impoundment must
be in accordance with the following sections of NFPA 30:
(i) Impoundment around a breakout tank must be installed in accordance with section
4.3.2.3.2; and
(ii) Impoundment by drainage to a remote impounding area must be installed in
accordance with section 4.3.2.3.1.
Centurion failed to construct several breakout tanks in accordance with comprehensive written
specifications or standards that are consistent with the requirements of this part. Centurion failed
to provide comprehensive written specifications or standards to demonstrate breakout tank
containment impoundments met the requirements of NFPA 30 referenced in §195.264.
Centurion also failed to present documentation (surveys, calculations) for any of their breakout
tanks constructed after October 2, 2000, that verified the containment impoundment volumes met
the requirements of NFPA 30.
Centurion owns several breakout tanks throughout west Texas, New Mexico, and Oklahoma.
Ten of them were constructed from 2009 to 2012. Tanks 6693, 6832, 6692, 160100, 160101,
6691, 6833, were constructed in 2009, and tanks 6991, 7101, and 160102 were constructed in
2012. The impoundment requirements are contained in several paragraphs throughout the NFPA
30 standard.
5



5. 195.452 Pipeline integrity management in high consequence areas.
(h) What actions must an operator take to address integrity issues?
(2) Discovery of condition. Discovery of a condition occurs when an operator has
adequate information about the condition to determine that the condition presents a
potential threat to the integrity of the pipeline. An operator must promptly, but no
later than 180 days after an integrity assessment, obtain sufficient information
about a condition to make that determination, unless the operator can demonstrate
that the 180-day period is impracticable.
Centurion failed to obtain sufficient information about a condition to determine if the condition
presented a potential threat to the integrity of the pipeline no later than 180 days after an integrity
assessment.
On December 3, 2011, Centurion completed a TDW Spirall Magnetic Flux Tool run as part of
their continual reassessment of their 16-inch Bretch to Cushing #2 system. This would place the
180 day deadline on or about May 31, 2012. Centurion determined six anomalies met the
immediate repair criteria on July 11, 2012, which is 220 days after the tool run was completed.
Centurion was unable to demonstrate that the 180 day requirement was impracticable.
6. 195.452 Pipeline integrity management in high consequence areas.
(h) What actions must an operator take to address integrity issues?
(4) Special requirements for scheduling remediation
Immediate repair conditions. An operator's evaluation and remediation schedule
must provide for immediate repair conditions. To maintain safety, an operator must
temporarily reduce operating pressure or shut down the pipeline until the operator
completes the repair of these conditions. An operator must calculate the temporary
reduction in operating pressure using the formula in Section 451.6.2.2 (b) of ANSI/
ASME B31.4 (incorporated by reference, see § 195.3). An operator must treat the
following conditions as immediate repair conditions:
Metal loss greater than 80% of nominal wall regardless of dimensions.
(B) A calculation of the remaining strength of the pipe shows a predicted burst
pressure less than the established maximum operating pressure at the location of
the anomaly. Suitable remaining strength calculation methods include, but are not
limited to, ASME/ANSI B31G (``Manual for Determining the Remaining Strength
of Corroded Pipelines'' (1991) or AGA Pipeline Research Committee Project PR-3-
805 (``A Modified Criterion for Evaluating the Remaining Strength of Corroded
Pipe'' (December 1989)). These documents are incorporated by reference and are
available at the addresses listed in Sec. 195.3.
(C) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions)
that has any indication of metal loss, cracking or a stress riser.
6



(D) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions)
with a depth greater than 6% of the nominal pipe diameter.
(E) An anomaly that in the judgment of the person designated by the operator to
evaluate the assessment results requires immediate action.
Centurion failed to maintain safety by temporarily reducing operating pressure or shutting down
the pipeline until repairs of immediate conditions that they identified were completed. Centurion
failed to reduce the operating pressure, shut down the pipeline or make repairs and evaluations of
six immediate repair conditions in an HCA segment that met the immediate repair condition
criteria.
Centurion conducted an assessment using TDW’s ILI tool on their 16-inch Bretch to Cushing #2
system. There were six anomalies identified, in an HCA segment, by TDW as “deformation
(above 4 and 8”oclock positions) … w/associated Metal Loss” which meets the definition of an
immediate repair condition per 195.452(h)(4)(i)(C). These determinations were accepted by
Centurion. These immediate repairs were located in an HCA segment between the El Reno
facility and Cushing segment at MP’s 73.53, 74.57-A, B, C, D (four at this location). The
immediate repair at MP 84.54 was located approximately three miles upstream of the El Reno
facility, on the Bretch to El Reno segment. The six anomalies were identified and were sent to
operations for rehab repairs on July 12, 2012. The repairs on the six immediate repairs began 15
days after on July 27, 2012 and were completed 22 days later, on August 3, 2012.
Centurion did not reduce the operating pressure after six immediate repair anomalies were
discovered. Pressure charts provided by Centurion demonstrate the El Reno discharge pressure
from July 12, 2012 to the end of repairs (August 3, 2012) that affected the immediate repair
anomalies at MP 73.52, 74.57A, B, C, and D. The discharge operating pressure readings range
from approximately 540 psi to approximately 620 psi, which demonstrates there was no pressure
reduction.
Centurion’s Integrity Management Plan Section 7.1.2 -Action Required Upon Discovery of an
Immediate Repair Condition states, “Upon discovery of an immediate Repair condition, the
Manager, Pipeline Integrity will notify the Regional Manager of the need to either shut down the
line or reduce the operating pressure as possible until the Immediate Repair Condition is repaired
or remediated. The Regional Manager will make operating pressure changes as directed by the
Manager, Pipeline Integrity. The Manager, Pipeline Integrity will use guidance in ASME B31.4
for determining the reduction in operating pressure for corrosion anomalies. For all other types
of anomalies or if the formula yields a higher operating pressure, the minimum pressure
reduction will not be less than twenty percent of the highest operating pressure occurring at the
anomaly’s location during the preceding sixty days.”
ASME B31.4 is not applicable for calculating the temporary pressure reduction required for top-
side dents with metal loss. Pressure must be reduced for other types of immediate repair
conditions, but operators must develop appropriate engineering justification for the amount of
pressure reduction. A reduction in operating pressure is intended to provide an additional safety
margin until the defect can be remediated. To assure that additional margin is provided, the
7



pressure reduction must be based upon pressures that the pipe has actually experienced, with the
defect present (i.e., pressures for which safety has been demonstrated). These may be well below
the ‘maximum operating pressure’ for the pipe.
Pressure charts provided by Centurion via email, shows pressures from the preceding two
months of the day of discovery. The El Reno discharge pressure chart affecting the immediate
repair anomalies at MP 73.52, 74.57A, B, C, and D, shows the highest discharge pressure was
approximately 700 psi which occurred on approximately June 5, 2012. Centurion needed to take
a minimum of a 20% pressure reduction of the highest operating pressure in the preceding two
months as per their IMP procedure 7.1.2.
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 violation(s) and has recommended that you be preliminarily assessed a
civil penalty of $165,900 as follows:
Item number PENALTY
1 $42,400
2 $23,600
3 $23,600
5 $36,000
6 $40,300
Proposed Compliance Order
With respect to items 4 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous
Materials Safety Administration proposes to issue a Compliance Order to Centurion 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
8



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 4-2014-5028 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
9



PROPOSED COMPLIANCE ORDER
Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety
Administration (PHMSA) proposes to issue to Centurion a Compliance Order incorporating the
following remedial requirements to ensure the compliance of Centurion with the pipeline safety
regulations:
Item 1: In regard to Item Number 4 of the Notice pertaining to verifying the containment dike
volume for the various breakout tanks, Centurion must evaluate its tank dike areas and ensure
that the dike areas meet the impoundment criteria. Centurion must provide documentation to
PHMSA in the form of current surveys, drawings, and/or calculations that show the containment
complies with the applicable requirements of NFPA 30, incorporated by reference into Part 195.
Item 2: Pertaining to Item 1 of the Proposed Compliance Order, Centurion must complete the
required documentation within 90 days of the date of the Compliance Order.
Item 3: It is requested (not mandated) that Centurion 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 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.
10

## Provenance

- Official: Yes
- Source: <https://primis.phmsa.dot.gov/enforcement-data/case/420145028>
- Source ID: `phmsa-enforcement`
- SHA-256: `00694a77e70b93c106cb1010075e81cf108f0b7b5abf3ff01b7284aa604c10b9`
- Retrieved: 2026-08-20T04:44:44.458Z
- Exported: 2026-08-23T08:08:48.618Z
- Document slug: `phmsa-enforcement-420145028`

### Source metadata

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