# DELEK LOGISTICS OPERATING, LLC. — Notice of Probable Violation

**Citation:** CPF 420185001  
**Type / status:** enforcement / historical  
**Agency:** Pipeline and Hazardous Materials Safety Administration  
**Effective:** Not stated  
**Published:** 2018-02-07

CLOSED notice of probable violation citing 195.214(a), 195.402(a), 195.432(b), 195.452(f)(3), 195.452(f)(7), 195.452(i)(1), 195.452(k), 195.54(a), 195.61.

## Document text

Notice of Probable Violation involving DELEK LOGISTICS OPERATING, LLC.. PHMSA's enforcement data identifies the cited regulations as 195.214(a),  195.402(a),  195.432(b),  195.452(f)(3),  195.452(f)(7),  195.452(i)(1),  195.452(k),  195.54(a),  195.61. The case was opened on 2018-02-07 and is reported as closed as of 2019-09-19. Proposed civil penalty: $129,600. Assessed civil penalty: $129,600. Open the official case record for notices, responses, orders, and the latest status.

Official case documents:

420185001_Closure Letter_09192019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420185001/420185001_Closure%20Letter_09192019.pdf

420185001_Closure Letter_09192019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420185001/420185001_Closure%20Letter_09192019_text.pdf

420185001_Final Order_02042019.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420185001/420185001_Final%20Order_02042019.pdf

420185001_Final Order_02042019_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420185001/420185001_Final%20Order_02042019_text.pdf

420185001_NOPV PCP PCO_02072018.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420185001/420185001_NOPV%20PCP%20PCO_02072018.pdf

420185001_NOPV PCP PCO_02072018_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420185001/420185001_NOPV%20PCP%20PCO_02072018_text.pdf

420185001_Operator Response to Notice and Request for Time Extension_03072018.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420185001/420185001_Operator%20Response%20to%20Notice%20and%20Request%20for%20Time%20Extension_03072018.pdf

420185001_Final Order_02042019_text.pdf

February 4, 2019
Mr. Ezra Uzi Yemin
CEO and Chairman of the Board
Delek Logistics Partners, LP
7102 Commerce Way
Brentwood, TN 37027
Re: CPF No. 4-2018-5001
Dear Mr. Yemin:
Enclosed please find the Final Order issued in the above-referenced case to your subsidiary,
Delek Logistics Operating, LLC. It makes findings of violation, assesses a civil penalty of
$129,600, and specifies actions that need to be taken by Delek to comply with the pipeline safety
regulations. The penalty payment terms are set forth in the Final Order. When the civil penalty
has been paid and the terms of the compliance order completed, as determined by the Director,
Southwest Region, Office of Pipeline Safety, PHMSA, this enforcement action will be closed.
Service of the Final Order by certified mail is effective upon the date of mailing, 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: Ms. Mary McDaniel, Director, Southwest Region, Office of Pipeline Safety, PHMSA
Mr. John H. Warren, Vice President, Operations, Delek Logistics Operating, LLC, 1001
School Street, El Dorado, AR 71730
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 )
Delek Logistics Operating, LLC, ) CPF No. 4-2018-5001
a subsidiary of Delek Logistics Partners, LP, )
)
)
)
Respondent. )
__________________________________________)
FINAL ORDER
On multiple dates between February and April 2016, 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 Delek Logistics Operating, LLC (Delek or Respondent), in El Dorado, Arkansas.1
The pipeline and transportation system subject to the inspection consisted of approximately 375
miles of crude-oil pipelines in Arkansas and Louisiana, with two breakout tanks located in
Magnolia, Arkansas.2 Delek operates as a subsidiary of Delek Logistics Partners, LP.3
As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to
Respondent, by letter dated February 7, 2018, a Notice of Probable Violation, Proposed Civil
Penalty, and Proposed Compliance Order (Notice), which also included a warning pursuant to
49 C.F.R. § 190.205. In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that
Delek had committed seven violations of 49 C.F.R. Part 195 and proposed assessing a civil
penalty of $129,600 for the alleged violations. The Notice also proposed ordering Respondent to
take certain measures to correct the alleged violations. The warning items required no further
action but warned the operator to correct the probable violations or face possible future
enforcement action.
Delek responded to the Notice by letter dated March 7, 2018 (Response). The company neither
admitted nor denied the allegations of violation and did not contest the proposed civil penalty,
1 Delek is now the operator of the facilities previously operated by “Lion” or “Lion Oil Trading & Transportation.”
(Response, at 1).
2 Pipeline Safety Violation Report (Violation Report), (February 6, 2018) (on file with PHMSA), at 1.
3 Company Overview of Delek Logistics Operating, LLC, available at
https://www.bloomberg.com/research/stocks/private/snapshot.asp?privcapId=233828860 (last accessed June 13,
2018).



CPF No. 4-2018-5001
Page 2
but provided information concerning the corrective actions it had taken and requested additional
time to complete certain of the proposed compliance actions. Respondent did not request a
hearing and therefore has waived its right to one.
FINDINGS OF VIOLATION
In its Response, Delek did not contest the allegations in the Notice that it violated 49 C.F.R. Part
195, as follows:
Item 2: The Notice alleged that Respondent 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 [American Petroleum Institute (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). The risk-based
internal inspection procedures in API Std 653, section 6.4.3 cannot be used
to determine the internal inspection interval.
The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) by failing to inspect the
physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks
according to API Standard 653. Specifically, the Notice alleged that Delek failed to perform an
external tank inspection for Breakout Tank #2002 within the maximum five-year interval, as
required in API Standard 653, section 6.3.2.1. According to Delek’s documentation at the time
of the PHMSA inspection (March 2016), Delek had conducted the most recent external
inspection in December 2008. As such, the inspection interval was exceeded by 27 months.
Respondent did not contest this allegation of violation. Accordingly, based upon a review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 195.432(b) by failing to inspect the
physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks
according to API Standard 653.
Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), which states:
§ 195.402 Procedural manual for operations, maintenance, and
emergencies.
(a) General. Each operator shall prepare and follow for each pipeline
system a manual of written procedures for conducting normal operations
and maintenance activities and handling abnormal operations and
emergencies. This manual shall be reviewed at intervals not exceeding 15
months, but at least once each calendar year, and appropriate changes made



CPF No. 4-2018-5001
Page 3
as necessary to insure that the manual is effective. This manual shall be
prepared before initial operations of a pipeline system commence, and
appropriate parts shall be kept at locations where operations and
maintenance activities are conducted.
The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a) by failing to follow for each
pipeline system a manual of written procedures for conducting normal operations and
maintenance activities and handling abnormal operations and emergencies. Specifically, the
Notice alleged that Delek failed to follow its own procedure, LTP-OP-110.0: Floating Roof
Safety, Access/Ignition 195.405, dated February 11, 2015. Section 6.5 of that procedure states:
Upon accessing the roof, one of the first actions shall be to verify that
the tank and roof are properly electrically bonded (grounded) to assure
there is no static potential between the roof and shell. Normally there
should be a bond wire between the tank shell and roof that may also be
bonded to or through the rolling stairs. Roof seal grounded/bond strips
should also be inspected to make sure the seal, roof and shell are all
electrically bonded (at the same static voltage).
Based on the PHMSA inspector’s review of the Floating Roof Seal Inspection Checklist,
Respondent failed to inspect the tank and roof to ensure they were electrically bonded and to
assure there was no static potential between the roof and shell, as required by procedure LTP-
OP-110.0. This inspection was not performed for tank #2002 from 2011-2015, or for tank #437
from 2013-2015.
Respondent did not contest this allegation of violation. Accordingly, based upon a review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 195.402(a) by failing to follow for
each pipeline system its own manual of written procedures for conducting normal operations and
maintenance activities and handling abnormal operations and emergencies.
Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.214(a), which states:
§ 195.214 Welding procedures.
(a) Welding must be performed by a qualified welder or welding
operator in accordance with welding procedures qualified under section 5,
section 12, or Appendix A of API Std 1104 (incorporated by reference, see
§ 195.3), or section IX of the ASME Boiler and Pressure Vessel Code
(BPVC) (incorporated by reference, see § 195.3). The quality of the test
welds used to qualify welding procedures must be determined by
destructive testing.4
The Notice alleged that Respondent violated 49 C.F.R. § 195.214(a) by failing to have welding
performed by a qualified welder or welding operator in accordance with welding procedures
qualified under section 5, section 12, or Appendix A of API Standard 1104, or section IX of the
4 49 C.F.R. § 195.214(a) was amended in January 2017 to include Appendix B of API Standard 1104.



CPF No. 4-2018-5001
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ASME BPVC. Specifically, the Notice alleged that during the inspection, the PHMSA inspector
reviewed anomaly #S60273 (8.93% deformation in a High Consequence Area (HCA) on a 6-inch
outside-diameter 0.280” WT Smackover pipeline) repair sheet. In July 2015, three welds (XR53,
XR54, and XR55) were made to replace 84.04 feet of pipe in order to remove six anomalies,
including #S60273. The PHMSA inspector reviewed a pipeline repair sheet and radiographic
weld report but neither document listed the welder identification or the welder’s name.
Respondent also could not provide visual weld-inspection reports for these three welds, as
required by API Standard 1104. As a result, the welder(s) could not be identified or their
qualifications confirmed.
Respondent did not contest this allegation of violation. Accordingly, based upon a review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 195.214(a) by failing to have
welding performed by a qualified welder or welding operator in accordance with welding
procedures qualified under section 5, section 12, or Appendix A of API Standard 1104, or
section IX of the ASME BPVC.
Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(i)(1), which states:
§ 195.452 Pipeline integrity management in high consequence areas.
(a) . . . .
(i) What preventive and mitigative measures must an operator take to
protect the high consequence area?
(1) General requirements. An operator must take measures to prevent
and mitigate the consequences of a pipeline failure that could affect a high
consequence area. These measures include conducting a risk analysis of the
pipeline segment to identify additional actions to enhance public safety or
environmental protection. Such actions may include, but are not limited to,
implementing damage prevention best practices, better monitoring of
cathodic protection where corrosion is a concern, establishing shorter
inspection intervals, installing EFRDs on the pipeline segment, modifying
the systems that monitor pressure and detect leaks, providing additional
training to personnel on response procedures, conducting drills with local
emergency responders and adopting other management controls.
The Notice alleged that Respondent violated 49 C.F.R. § 195.452(i)(1) by failing to take
measures to prevent and mitigate the consequences of a pipeline failure that could affect an
HCA. Specifically, the Notice alleged that Delek failed to perform an adequate risk analysis of
its pipeline segments to determine the appropriate preventive and mitigative (P&M) measures.
Delek uses its procedure, IMP Section 11: Identification of Preventive/ Mitigative Measures, as
the process and methodology to evaluate its pipeline system and identify these P&M measures
that could potentially reduce the risk of a failure and/or limit the consequence of a failure.
Section 11.3 of this procedure states:
The following events will cause the Integrity Data Specialist to form a
P&M Evaluation Team within six months of their occurrence:



CPF No. 4-2018-5001
Page 5
- Notification that new assessment or inspection results have been
received;
- Identification of a previously unknown threat to a pipeline segment
that is serious enough to warrant attention to ensure continued pipeline
integrity, such as an approved Field Report on Potential New High
Consequence Area Along Pipeline Route (see Sec. 2.4), an aerial or ground
patrol discovery of significant third party activity, a leak or rupture from an
unsuspected threat mechanism.
-Receipt of any other information which could affect the results of
previous P&M reviews or otherwise impact the integrity of the pipeline
section.
According to the Notice, Delek utilized multiple in-line inspection (ILI) tools to assess the
integrity of various pipeline segments between September 6, 2012, and September 8, 2015. On
at least seven separate occasions, Delek allegedly failed to follow its IMP Section 11.0 procedure
upon receipt of ILI inspection results. The Notice further alleged that Respondent failed to
document the P&M actions that were taken to enhance public safety or environmental protection.
Based on records provided to the PHMSA inspector, Respondent allegedly had not followed its
own process or methodology since April 3, 2005.
Respondent did not contest this allegation of violation. Accordingly, based upon a review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 195.452(i)(1) by failing to take
measures to prevent and mitigate the consequences of a pipeline failure that could affect an
HCA.
Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(k), which states:
§ 195.452 Pipeline integrity management in high consequence areas.
(a) . . . .
(b) What program and practices must operators use to manage
integrity? Each operator of a pipeline covered by this section must:
(1) . . .
(5) Implement and follow the program. . .
(k) What methods to measure program effectiveness must be used? An
operator’s program must include methods to measure whether the program
is effective in assessing and evaluating the integrity of each pipeline
segment and in protecting the high consequence areas. See Appendix C of
this part for guidance on methods that can be used to evaluate a program’s
effectiveness.
The Notice alleged that Respondent violated 49 C.F.R. § 195.452(k) by failing to measure
whether its integrity management program (IMP) was effective in assessing and evaluating the
integrity of each pipeline segment and in protecting HCAs. Specifically, the Notice alleged that
Delek’s IMP Manual, Section 12.4: Evaluation of Performance Measures (Manual), states:



CPF No. 4-2018-5001
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The [Delek] Integrity Management Review Board will annually evaluate
the effectiveness of its integrity assessment methods, and the preventive and
mitigation risk control activities, including repair. Performance measures
will be compared to previous years' metrics to look for trends. The Integrity
Management Review Board will review the metrics for continued tracking
and add any additional metrics to aid in the evaluation of the effectiveness
of the IMP. The Integrity Management Review Board will also evaluate the
effectiveness of its management systems and processes in supporting
integrity management decisions. A combination of performance measures
and system audits are [sic] necessary to evaluate the overall effectiveness
of an IMP. The Integrity Management Review Board will issue a written
report documenting discussions and findings.
While the Manual required an annual review of the IMP’s effectiveness, Respondent allegedly
could not demonstrate that such a review had been performed for the calendar years 2011, 2013,
or 2015.5
Respondent did not contest this allegation of violation. Accordingly, based upon a review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 195.452(k) by failing to measure
whether its IMP was effective in assessing and evaluating the integrity of each pipeline segment
and in protecting HCAs.
Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(f) and (g), which state,
in relevant part:
§ 195.452 Pipeline integrity management in high consequence areas.
(a) . . . .
(f) What are the elements of an integrity management program? . . .An
operator must include, at minimum, each of the following elements in its
written integrity management program: . . .
(3) An analysis that integrates all available information about the
integrity of the entire pipeline and the consequences of a failure (see
paragraph (g) of this section): . .
(g) What is an information analysis? In periodically evaluating the
integrity of each pipeline segment (paragraph (j) of this section), an operator
must analyze all available information about the integrity of the entire
pipeline and the consequences of a failure. This information includes:
(1) Information critical to determining the potential for, and preventing,
damage due to excavation, including current and planned damage
5 The Notice also noted, based on PHMSA’s review of Delek’s 2012 and 2014 records, that Respondent failed to
apply the guidance provided in Part 195, Appendix C, Section V, to measure its IMP’s performance and that Delek’s
performance metrics did not provide meaningful insight into its performance. While operators are not required to
follow the guidance in Appendix C and this particular statement in the Notice does not constitute part of the
allegation of violation, the “methods” used by an operator to evaluate program effectiveness must be able to
accomplish this performance-based requirement.



CPF No. 4-2018-5001
Page 7
prevention activities, and development or planned development along the
pipeline segment;
(2) Data gathered through the integrity assessment required under this
section;
(3) Data gathered in conjunction with other inspections, tests,
surveillance and patrols required by this Part, including, corrosion control
monitoring and cathodic protection surveys; and
(4) Information about how a failure would affect the high consequence
area, such as location of the water intake.
The Notice alleged that Respondent violated 49 C.F.R. § 195.452(f) and (g) by failing to conduct
an information analysis as part of its IMP that analyzed all available information about the
integrity of the entire pipeline and the consequences of a failure. Specifically, the Notice alleged
that Delek did not analyze all relevant risk categories and operating conditions when evaluating
individual pipeline-segment risks. Respondent’s procedure, IMP Section 3.0: Risk Assessment
Procedures, Section 3.2: Risk Ranking Methodology, states:
[Delek] has developed a relative risk ranking model based on the guidelines
and techniques developed by W. Kent Muhlbauer 1, who is a recognized
authority on pipeline risk management. As indicated in Figure 3-1, this
model scores various mechanisms for pipeline failure to develop a relative
probability index score for a release from a given pipeline segment. A
separate scoring is developed for the relative consequences for the pipe
segment release. The product of these two indices (Probability Index X
Consequence Index) generates the relative risk index score for the pipeline
segment. Higher scores with this model represent higher risks when
comparing two or more pipeline segments.
Additionally, Respondent’s IMP Section 3.6: Validation and Recalculation of Risk, states:
Validation of the risk assessment model and corresponding results is an
important and ongoing process in an IMP. The [Delek]
Maintenance/Engineering Superintendent will oversee this validation
process using the Integrity Data Specialist as appropriate. The
Maintenance/Engineering Superintendent will assure that the data and
methods being used are correct, comprehensive and that the results
generated by the model make sense and are consistent with operator
experiences. A modification to the risk assessment process or a
recalculation of the relative risks will be performed when sufficient
additional objective data are available to affect the outcome and
corresponding ranking of affected HCA segments for assessment purposes.
NOTE that for pipeline systems under the jurisdiction of the Texas Railroad
Commission, current regulations (16TAC §8.101) require that the Risk
Assessment be re-performed every three years.



CPF No. 4-2018-5001
Page 8
The PHMSA inspector reviewed Delek’s Figure 3-1: Relative Risk Analysis Method and risk-
analyses results for randomly-selected covered segments. Based on this review, the Notice
alleged that Respondent failed to analyze relevant risks related to equipment, weather,
manufacture, and outside-force threats. Respondent performed its most recent risk analysis in
2010, after determining which of its pipeline segments were in areas unusually sensitive to
environmental damage. Since the date of this determination, Respondent allegedly had not
updated its risk-analysis data for pipe re-routing and replacement, new ILI data, third-party
damage, leak history, and incidents.
Respondent did not contest this allegation of violation. Accordingly, based upon a review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 195.452(f) and (g) by failing to
analyze all available information about the integrity of its entire pipeline and the consequences of
a failure.
Item 10: The Notice alleged that Respondent 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). The risk-based internal inspection procedures in
API Std 653, section 6.4.3 cannot be used to determine the internal
inspection interval.
The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) by failing to inspect the
physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks
according to API Standard 653. Specifically, the Notice alleged that Delek failed to perform an
initial internal inspection for Breakout Tank #2002 within the maximum 10-year interval, as
required in API Standard 653, section 6.4.2.1. Breakout Tank #2002 was allegedly placed in
service on or about July 2, 2003, but as of March 2016, Delek had still not performed an internal
inspection as required by section 6 of API Standard 653.
Respondent did not contest this allegation of violation. Accordingly, based upon a review of all
of the evidence, I find that Respondent violated 49 C.F.R. § 195.432(b) by failing to inspect the
physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks
according to API Standard 653.
These findings of violation will be considered prior offenses in any subsequent enforcement
action taken against Respondent.



CPF No. 4-2018-5001
Page 9
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.6 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 in 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 $129,600 for the violations cited above.
Item 5: The Notice proposed a civil penalty of $36,000 for Respondent’s violation of 49 C.F.R.
§ 195.452(i)(1), for failing to take measures to prevent and mitigate the consequences of a
pipeline failure that could affect an HCA. Delek neither contested the allegation nor presented
any evidence or argument justifying elimination of the proposed penalty. Accordingly, having
reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of
$36,000 for violation of 49 C.F.R. § 195.452(i)(1).
Item 6: The Notice proposed a civil penalty of $36,000 for Respondent’s violation of 49 C.F.R.
§ 195.452(k), for failing to measure whether its IMP was effective in assessing and evaluating
the integrity of each pipeline segment and in protecting HCAs. Delek neither contested the
allegation nor presented any evidence or argument justifying elimination of the proposed
penalty. Accordingly, having reviewed the record and considered the assessment criteria, I
assess Respondent a civil penalty of $36,000 for violation of 49 C.F.R. § 195.452(k).
Item 7: The Notice proposed a civil penalty of $36,000 for Respondent’s violation of 49 C.F.R.
§ 195.452(f) and (g), for failing to analyze all available information about the integrity of the
entire pipeline and the consequences of a failure. Delek neither contested the allegation nor
presented any evidence or argument justifying elimination of the proposed penalty. Accordingly,
having reviewed the record and considered the assessment criteria, I assess Respondent a civil
penalty of $36,000 for violation of 49 C.F.R. § 195.452(f) and (g).
Item 10: The Notice proposed a civil penalty of $21,600 for Respondent’s violation of
49 C.F.R. § 195.432(b), for failing to inspect the physical integrity of in-service atmospheric and
low-pressure steel above-ground breakout tanks according to API Standard 653. Delek neither
contested the allegation nor presented any evidence or argument justifying elimination of the
proposed penalty. Accordingly, having reviewed the record and considered the assessment
criteria, I assess Respondent a civil penalty of $21,600 for violation of 49 C.F.R. § 195.432(b).
In summary, having reviewed the record and considered the assessment criteria for each of the
6 These amounts are adjusted annually for inflation. See, e.g., Pipeline Safety: Inflation Adjustment of Maximum
Civil Penalties, 82 Fed. Reg. 19325 (April 27, 2017).



CPF No. 4-2018-5001
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Items cited above, I assess Respondent a total civil penalty of $129,600.
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, Mike
Monroney Aeronautical Center, 6500 S MacArthur Blvd, Oklahoma City, Oklahoma 79169.
The Financial Operations Division telephone number is (405) 954-8845.
Failure to pay the $129,600 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 Items 2, 3, 4, 5, 6, 7, and 10 in the
Notice for violations of 49 C.F.R. §§ 195.432(b), 195.402(a), 195.214(a), 195.452(i)(1),
195.452(k), 195.452(f) and (g), and 195.432(b), respectively. 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 has indicated that Respondent has taken the following actions to
address one of the cited violations:
1. With respect to the violation of § 195.432(b) (Item 2), Respondent has performed
an external inspection for Breakout Tank #2002 in accordance with API Standard
653, Section 6.3.2.1.
Accordingly, I find that compliance has been achieved with respect to this violation. Therefore,
the compliance terms proposed in the Notice for Item 2 are not included in this Order.
As for the remaining compliance terms, pursuant to the authority of 49 U.S.C. § 60118(b) and 49
C.F.R. § 190.217, Respondent is ordered to take the following actions to ensure compliance with
the pipeline safety regulations applicable to its operations:
1. With respect to the violation of § 195.402(a) (Item 3), Respondent must inspect its
breakout tanks for electrical bond and revise its Floating Roof Seal Inspection
Checklist to include the inspection of electric bond, to assure there is no static
potential between the roof and shell during operation and maintenance activities;
2. With respect to the violation of § 195.214(a) (Item 4), Respondent must develop a
process to capture information that indicates welding has been performed by a



CPF No. 4-2018-5001
Page 11
qualified welder in accordance with welding procedures qualified under section 5 of
API Standard 1104. Respondent must also develop a form for the visual inspection of
welds;
3. With respect to the violation of § 195.452(i)(1) (Item 5), Respondent must
conduct an adequate risk analysis to determine measures to prevent and mitigate the
consequence of a pipeline failure that could affect an HCA;
4. With respect to the violation of § 195.452(k) (Item 6), Respondent must establish
methods to annually measure IMP effectiveness to ensure the program is effective in
assessing and evaluating the integrity of each of its pipeline segments and in
protecting HCAs;
5. With respect to the violation of § 195.452(f) and (g) (Item 7), Respondent must
analyze all relevant risk categories and operating conditions and evaluate individual
pipeline segment risks in analyzing and integrating all available information about the
integrity of its covered pipeline segments and consequences of a failure; and
6. With respect to the violation of § 195.432(b) (Item 10), Respondent must perform
an internal inspection of Breakout Tank #2002 and must incorporate the correct
edition of API Standard 653 as set forth in 49 CFR § 195.3.
7. Respondent must submit to the Director, within 30 days following receipt of the
Final Order, written documentation of steps taken to satisfy Compliance Order Items
1 and 2 above.
8. Respondent must submit to the Director, within 90 days following receipt of the
Final Order, written documentation of steps taken to satisfy Compliance Order Items
3 through 6 above.
The Director may grant an extension of time to comply with any of the required items upon a
written request timely submitted by the Respondent and demonstrating good cause for an
extension.
It is requested that Respondent maintain documentation of the safety improvement costs
associated with fulfilling this Compliance Order and submit the total to the Director. It is
requested that these costs be reported in two categories: (1) total cost associated with
preparation/revision of plans, procedures, studies and analyses; and (2) total cost associated with
replacements, additions and other changes to pipeline infrastructure.
Failure to comply with this Order may result in the administrative assessment of civil penalties
not to exceed $200,000, as adjusted for inflation (49 C.F.R. § 190.223), for each violation for
each day the violation continues or in referral to the Attorney General for appropriate relief in a
district court of the United States.



CPF No. 4-2018-5001
Page 12
WARNING ITEMS
With respect to Items 1, 8, and 9, the Notice alleged probable violations of Part 195 but did not
propose a civil penalty or compliance order for these items. Therefore, these are considered to
be warning items. The warnings were for:
49 C.F.R. § 195.402(a) (Item 1) ─ Respondent’s alleged failure to follow its own
manual of written procedures for conducting normal operations and maintenance
activities and handling abnormal operations and emergencies, specifically,
Respondent’s Integrity Management Plan, Section 6.0: Conducting
Assessments/Results Review required by §195.452(b)(1);
49 C.F.R. § 195.61 (Item 8) ─ Respondent’s alleged failure to submit geospatial
data to PHMSA on or before June 15, 2015; and
49 C.F.R. § 195.54(a) (Item 9) ─ Respondent’s alleged failure to file an accident
report on DOT Form 7000-1 within 30 days of the discovery of a reportable
release at its Smackover Station.
If PHMSA finds a violation of any of these items in a subsequent inspection, Respondent may be
subject to future enforcement action.
Under 49 C.F.R. § 190.243, Respondent may submit a Petition for Reconsideration of this Final
Order to the Associate Administrator, Office of Pipeline Safety, PHMSA, 1200 New Jersey
Avenue, SE, East Building, 2nd Floor, Washington, DC 20590, with a copy sent to the Office of
Chief Counsel, PHMSA, at the same address, no later than 20 days after receipt of service of this
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.
February 4, 2019
___________________________________ __________________________
Alan K. Mayberry Date Issued
Associate Administrator
for Pipeline Safety

420185001_Closure Letter_09192019_text.pdf

CERTIFIED MAIL - RETURN RECEIPT REQUESTED
September 19, 2019
Michael Odigie
Vice President Asset integrity and Reliability
Delek Logistics Operating, LLC
12700 Park Central Drive
Dallas, Texas 75251
CPF 4-2018-5001
Dear Mr. Odigie:
On February 4, 2019, the Pipeline and Hazardous Materials Safety Administration (PHMSA)
issued to Delek Logistics Operating, LLC (Delek), a Final Order in the above-referenced case.
This Order included a Compliance Order and Civil Penalty assessment. Delek submitted the
required information on July 30, 2019. Based on our review of the documentation provided, a
subsequent meeting with Delek officials to provide additional clarification on actions taken, and
confirmation of payment of the civil penalty, it has been determined that Delek has 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 Region
Office of Pipeline Safety
Pipeline and Hazardous Materials Safety Administration

420185001_NOPV PCP PCO_02072018_text.pdf

NOTICE OF PROBABLE VIOLATION
PROPOSED CIVIL PENALTY
and
PROPOSED COMPLIANCE ORDER
CERTIFIED MAIL - RETURN RECEIPT REQUESTED
February 7, 2018
Delek Logistics Operating, LLC
Mr. John Warren, Vice President - Operations
1001 School Street
El Dorado, AR 71730
CPF 4-2018-5001
Dear Mr. Warren:
On multiple dates between February 19 and April 1, 2016, 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 Delek Logistics Operating, LLC’s (Lion) Magnolia and Arkansas
pipeline systems in El Dorado, Arkansas.
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 violation(s)
are:
1. §195.402 Procedural manual for operations, maintenance, and emergencies.
(a) General. Each operator shall prepare and follow for each pipeline system a manual of written
procedures for conducting normal operations and maintenance activities and handling abnormal
operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months,
but at least once each calendar year, and appropriate changes made as necessary to ensure that the
manual is effective. This manual shall be prepared before initial operations of a pipeline system



commence, and appropriate parts shall be kept at locations where operations and maintenance
activities are conducted.
Lion failed to follow their Integrity Management Plan, Section 6.0: Conducting Assessments/Results
Review required by §195.452 (b) (1).
Lion’s IMP Plan Section 6.6: Recordkeeping and Distribution states, "All anomaly investigations will be
documented using Exposed Pipe Inspection Report form (see Appendix G) and additional forms as
appropriate (see Section 8.0 –Repair Procedures). The Pipeline Specialist will forward these forms to the
Regional Engineer for inclusion in the pipeline segment file."
While reviewing, records associated with 17.9 miles of 16” crude pipeline (Finny, Segment # 1002) smart
pig run in September 2012, it was noted that Lion had not reported any condition to this pipeline that
presents a potential threat to the integrity of the pipeline. Lion made two validation digs (Anomaly #
40000002 and Anomaly # 40000046). For both these digs, Lion failed to provide exposed pipe inspection
report form.
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).
Lion failed to perform an external tank inspection for breakout tank # 2002 within the maximum five-year
interval, in accordance with API 653 Section 6.3.2.1. According to the document provided by Lion, the
most recent external inspection occurred in December, 2008. At the time of the PHMSA inspection
(March 2016), the PHMSA inspector noted that the external inspection had not been performed within the
required interval. As a result, the inspection interval is exceeded by 27 months.
In accordance with § 195.432 and the referenced standard, API 653 6.3.2.1, an operator is required to
perform external inspections of all breakout tanks at an interval that may not exceed 5 years.
3. §195.402 Procedural manual for operations, maintenance, and emergencies.
(a) General. Each operator shall prepare and follow for each pipeline system a manual of written
procedures for conducting normal operations and maintenance activities and handling abnormal
operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months,
but at least once each calendar year, and appropriate changes made as necessary to ensure that the
manual is effective. This manual shall be prepared before initial operations of a pipeline system
commence, and appropriate parts shall be kept at locations where operations and maintenance
activities are conducted.
2



Lion failed to follow their procedure LTP-OP-110.0: Floating Roof Safety, Access/Ignition (Revised
2/11/2015) that meets the requirements of §195.405(a)
Section 6.5 of the procedure states, “Upon accessing the roof, one of the first actions shall be to verify that
the tank and roof are properly electrically bonded (grounded) to assure there is no static potential between
the roof and shell. Normally there should be a bond wire between the tank shell and roof that may also
be bonded to or through the rolling stairs. Roof seal grounded/bond strips should also be inspected to
make sure the seal, roof and shell are all electrically bonded (at the same static voltage)”.
When the PHMSA inspector requested records associated with the protection against ignitions and safe
access/egress involving the floating roof, Lion provided the Floating Roof Seal Inspection checklist to the
inspector. Based on the review of these records, Lion failed to inspect the tank and roof to ensure that
they are electrically bonded and to assure there is no static potential between the roof and shell as required
by procedure LTP-OP-110.0. This inspection was not performed for tank no. 2002 from 2011- 2015 and
tank no. 437 from 2013-2015. Lion failed to follow their procedure and perform these inspections as
required by procedure LTP-OP-110.0.
4. §195.214 Welding procedures.
(a) Welding must be performed by a qualified welder or welding operator in accordance with
welding procedures qualified under section 5, section 12 or Appendix A of API Standard 1104
(incorporated by reference, see §195.3), or section IX of ASME Boiler and Pressure Vessel Code
(BPVC) (incorporated by reference, see §195.3). The quality of the test welds used to qualify welding
procedures must be determined by destructive testing.
Lion failed to provide the records indicating that welding was performed by a qualified welder in
accordance with welding procedures qualified under section 5, section 12 or Appendix A of API Standard
1104 (incorporated by reference, see §195.3).
During the inspection, the PHMSA inspector reviewed anomaly # S60273 (8.93% deformation in HCA
area on a 6” OD, 0.280” WT Smackover pipeline) repair sheet. A total of three welds (XR53, XR54, and
XR55) were made to replace 84.04 feet of pipe in July 2015 in order to remove six anomalies including
S60273. Lion provided the PHMSA inspector a pipeline repair sheet and Radiographic weld report but
neither documents listed the welder ID or welder’s name. Lion also failed to provide visual weld
inspection reports for these three welds as required by API 1104. As a result, welder cannot be identified
and their qualification cannot be confirmed.
5. area?
§195.452 Pipeline integrity management in high consequence areas.
(i) What preventive and mitigative measures must an operator take to protect the high consequence
3



(1) General requirements. An operator must take measures to prevent and mitigate the
consequences of a pipeline failure that could affect a high consequence area. These measures include
conducting a risk analysis of the pipeline segment to identify additional actions to enhance public
safety or environmental protection. Such actions may include, but are not limited to, implementing
damage prevention best practices, better monitoring of cathodic protection where corrosion is a
concern, establishing shorter inspection intervals, installing EFRDs on the pipeline segment,
modifying the systems that monitor pressure and detect leaks, providing additional training to
personnel on response procedures, conducting drills with local emergency responders and adopting
other management controls.
Lion failed to take measures to prevent and mitigate the consequences of a pipeline failure that could
affect a high consequence area (HCA). Specifically, Lion failed to perform an adequate risk analysis of
its pipeline segments to determine measures to prevent and mitigate the consequences of a pipeline failure
that could affect a high consequence area.
Lion has a process and methodology (IMP Section 11: Identification of Preventive/ Mitigative Measures)
that they use to evaluate its pipeline system to identify preventative and mitigative measures that could
potentially reduce the risk of a failure and/or limit the consequence of failure. Section 11.3 of this
procedure states, “The following events will cause the Integrity Data Specialist to form a P&M Evaluation
Team within six months of their occurrence:
- Notification that new assessment or inspection results have been received.
- Identification of a previously unknown threat to a pipeline segment that is serious enough to
warrant attention to ensure continued pipeline integrity, such as an approved Field Report on
Potential New High Consequence Area Along Pipeline Route (see Sec. 2.4), an aerial or ground
patrol discovery of significant third party activity, a leak or rupture from an unsuspected threat
mechanism
- Receipt of any other information which could affect the results of previous P&M reviews or
otherwise impact the integrity of the pipeline section
Lion utilized multiple ILI tools to assess the integrity of the various pipeline segments between 9/6/2012
and 9/8/2015. On at least seven separate occasions, Lion failed to follow IMP section 11.0 procedure
upon receipt of ILI inspection results. Lion failed to document the measures taken to prevent and mitigate
the consequence of possible pipeline failure that could affect HCA to enhance public safety or
environmental protection.
Based on records provided to the PHMSA inspector, it appears the last time Lion followed their process
or methodology was on April 3, 2005.
6. §195.452 Pipeline integrity management in high consequence areas
(f) What are the elements of an integrity management program? An integrity management program
begins with the initial framework. An operator must continually change the program to reflect
operating experience, conclusions drawn from results of the integrity assessments, and other
4



maintenance and surveillance data, and evaluation of consequences of a failure on the high
consequence area. An operator must include, at minimum, each of the following elements in its
written integrity management program:
(7) Methods to measure the program's effectiveness (see paragraph (k) of this section);
(k) What methods to measure program effectiveness must be used? An operator's program must
include methods to measure whether the program is effective in assessing and evaluating the
integrity of each pipeline segment and in protecting the high consequence areas. see Appendix C of
this part for guidance on methods that can be used to evaluate a program's effectiveness.
Lion did not measure their pipeline integrity management program for effectiveness as required by the
regulation.
Lion’s IMP manual, Section 12: Integrity Management Plan Evaluation, sub section 12.4: Evaluation of
Performance Measures states, “The LOTT Integrity Management Review Board will annually evaluate
the effectiveness of its integrity assessment methods, and the preventive and mitigation risk control
activities, including repair. Performance measures will be compared to previous years’ metrics to look
for trends. The Integrity Management Review Board will review the metrics for continued tracking and
add any additional metrics to aid in the evaluation of the effectiveness of the IMP. The Integrity
Management Review Board will also evaluate the effectiveness of its management systems and processes
in supporting integrity management decisions. A combination of performance measures and system audits
are necessary to evaluate the overall effectiveness of an IMP. The Integrity Management Review Board
will issue a written report documenting discussions and findings”.
While the manual requires an annual review of the integrity management program effectiveness, Lion
personnel could not demonstrate that such a review had been performed for the calendar years 2011, 2013
and 2015.
Also, based on review of 2012 and 2014 records, the PHMSA inspector learned that Lion does not apply
the guidance provided in Appendix C to Part 195, Section V to measure performance. Lion’s performance
metrics are not providing meaningful insight into the integrity management program performance.
7. §195.452 Pipeline integrity management in high consequence areas
(f) What are the elements of an integrity management program? An integrity management program
begins with the initial framework. An operator must continually change the program to reflect
operating experience, conclusions drawn from results of the integrity assessments, and other
maintenance and surveillance data, and evaluation of consequences of a failure on the high
consequence area. An operator must include, at minimum, each of the following elements in its
written integrity management program:
(3) An analysis that integrates all available information about the integrity of the entire pipeline and
the consequences of a failure (see paragraph (g) of this section);
5



(g) What is an information analysis? In periodically evaluating the integrity of each pipeline
segment (paragraph (j) of this section), an operator must analyze all available information about
the integrity of the entire pipeline and the consequences of a failure. This information includes:
(1) Information critical to determining the potential for, and preventing, damage due to excavation,
including current and planned damage prevention activities, and development or planned
development along the pipeline segment;
(2) Data gathered through the integrity assessment required under this section;
(3) Data gathered in conjunction with other inspections, tests, surveillance and patrols required by
this Part, including, corrosion control monitoring and cathodic protection surveys; and
(4) Information about how a failure would affect the high consequence area, such as location of the
water intake.
Lion failed to correctly analyze and integrate all available information about the integrity of its covered
pipeline segments and consequence of failure because it did not consider all relevant risk categories and
operating conditions when evaluating individual pipeline segment risk.
Lion's IMP Section 3.0: Risk Assessment Procedures, Section 3.2: Risk Ranking Methodology states,
"LOTT has developed a relative risk ranking model based on the guidelines and techniques developed by
W. Kent Muhlbauer 1, who is a recognized authority on pipeline risk management. As indicated in Figure
3-1, this model scores various mechanisms for pipeline failure to develop a relative probability index score
for a release from a given pipeline segment. A separate scoring is developed for the relative consequences
for the pipe segment release. The product of these two indices (Probability Index X Consequence Index)
generates the relative risk index score for the pipeline segment. Higher scores with this model represent
higher risks when comparing two or more pipeline segments”.
In addition, Lion’s IMP Section 3.6: Validation and Recalculation of Risk states, “Validation of the risk
assessment model and corresponding results is an important and ongoing process in an IMP. The LOTT
Maintenance/Engineering Superintendent will oversee this validation process using the Integrity Data
Specialist as appropriate. The Maintenance/Engineering Superintendent will assure that the data and
methods being used are correct, comprehensive and that the results generated by the model make sense
and are consistent with operator experiences. A modification to the risk assessment process or a
recalculation of the relative risks will be performed when sufficient additional objective data are available
to affect the outcome and corresponding ranking of affected HCA segments for assessment purposes.
NOTE that for pipeline systems under the jurisdiction of the Texas Railroad Commission, current
regulations (16TAC §8.101) require that the Risk Assessment be re-performed every three years”.
The PHMSA inspector reviewed Figure 3-1: LOTT Relative Risk Analysis Method and results of risk
analysis of randomly selected covered segments. Based on review, it appears that Lion failed to consider
relevant risk related to equipment, weather, manufacture and outside force threat in Figure 3-1 and in their
risk analysis for the covered segments. Lion performed its most recent risk analysis in 2010 after they
determined their pipeline segments in areas that are an usually sensitive to environmental damage. Since
6



then LION has not updated its risk analysis data for pipe re-route and replacement, new ILI data, third
party damage, leak history and incident.
8. § 195.61 National Pipeline Mapping System
(a) Each operator of a hazardous liquid pipeline facility must provide the following geospatial data
to PHMSA for that facility:
(1) Geospatial data, attributes, metadata and transmittal letter appropriate for use in the
National Pipeline Mapping System. Acceptable formats and additional information are
specified in the NPMS Operator Standards manual available at
www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information
Systems Manager at (202) 366-4595.
(2) The name of and address for the operator.
(3) The name and contact information of a pipeline company employee, to be displayed on a
public Web site, who will serve as a contact for questions from the general public about
the operator's NPMS data.
(b) This information must be submitted each year, on or before June 15, representing assets as of
December 31, of the previous year. If no changes have occurred since the previous year's
submission, the operator must refer to the information provided in the NPMS Operator Standards
manual available at www.npms.phmsa.dot.gov or contact the PHMSA Geographic Information
Systems Manager at (202) 366-4595.
Lion failed to submit geospatial data to PHMSA on or before June 15, 2015. Lion did not experience any
changes but failed to contact PHMSA as required by the regulation.
9. §195.54 Accident reports.
(a) Each operator that experiences an accident that is required to be reported under § 195.50 must,
as soon as practicable, but not later than 30 days after discovery of the accident, file an accident
report on DOT Form 7000-1.
Lion failed to file an accident report on DOT Form 7000-1 within thirty days of the discovery of a
reportable release at their Smackover Station. Lion experienced a release of less than 5 gallons (19 liters)
of crude oil that was not cleaned up promptly at their Smackover Station in Arkansas during a maintenance
pig run on a 4” Louann pipeline. This segment of the Louann pipeline traverse through and Other
Populated Area (OPA) and as a result, it is subject to the PHMSA’s jurisdiction. The exact date of the
release was not determined; however, it was more than thirty days prior to the field inspection performed
by PHMSA on March 30, 2016.
7



10. §195.432 Breakout tanks.
(b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel
above-ground breakout tanks according to API Std 653 (except section 6.4.3, Alternative Internal Inspection
Interval) (incorporated by reference, see §195.3). However, if structural conditions prevent access to the tank
bottom, its integrity may be assessed according to a plan included in the operations and maintenance
manual under §195.402(c)(3). The risk-based internal inspection procedures in API Std 653, section 6.4.3
cannot be used to determine the internal inspection interval.
Lion failed to inspect the physical integrity of in-service Breakout Tank # 2002 within the required
timeframe. The tank was constructed to API 650 standard; placed in-service on or about July 2, 2003 and
as of March 2016, they had not performed an out-of-service internal inspection required by Section 6 of
API 653.
The intervals of inspection specified by API 653 section 6.4.2.1 states ‘The interval from initial service
until the initial internal inspection shall not exceed 10 years.’
Proposed Civil Penalty
Under 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil penalty not to exceed $209,002
per violation per day the violation persists up to a maximum of $2,090,022 for a related series of violations.
For violations occurring prior to November 2, 2015, the maximum penalty may not exceed $200,000 per
violation per day, with a maximum penalty not to exceed $2,000,000 for a related series of violations. The
Compliance Officer has reviewed the circumstances and supporting documentation involved in the above
probable violation(s) and has recommended that you be preliminarily assessed a civil penalty of $129,600
as follows:
Item number
PENALTY
5
6
7
10
$36,000
$36,000
$36,000
$21,600
Warning Items
With respect to items 1, 8, and 9 we have reviewed the circumstances and supporting documents
involved in this case and have decided not to conduct additional enforcement action or penalty
assessment proceedings at this time. We advise you to promptly correct these items. Failure to do so
may result in additional enforcement action.
8



Proposed Compliance Order
With respect to items 2, 3, 4, 5, 6, 7 and 10 pursuant to 49 United States Code § 60118, the Pipeline and
Hazardous Materials Safety Administration proposes to issue a Compliance Order to Delek Logistics
Operating, LLC. Please refer to the Proposed Compliance Order, which is enclosed and made a part of
this Notice.
Response to this Notice
Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in
Compliance Proceedings. Please refer to this document and note the response options. All material you
submit in response to this enforcement action may be made publicly available. If you believe that any
portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with
the complete original document you must provide a second copy of the document with the portions you
believe qualify for confidential treatment redacted and an explanation of why you believe the redacted
information qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30
days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice
and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice
without further notice to you and to issue a Final Order.
In your correspondence on this matter, please refer to CPF 4-2018-5001 and for each document you
submit, please provide a copy in electronic format whenever possible.
Sincerely,
Frank Causey
Acting 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 Delek Logistics Operating, LLC (Lion) a Compliance Order incorporating
the following remedial requirements to ensure the compliance of Lion with the pipeline safety regulations:
1. 2. 3. 4. 5. 6. 7. 8. In regard to Item Number 2 of the Notice pertaining to Lion’s failure to perform external
inspection for breakout tank # 2002 within the maximum 5-year interval, Lion must
perform an external inspection in accordance with API 653 Section 6.3.2.1.
In regard to Item Number 3 of the Notice pertaining to Lion’s failure to verify the tank and
roof are properly electrically bonded (grounded) to assure there is no static potential
between the roof and shell, Lion must inspect their Breakout Tanks for electrical bond and
revise their Floating Roof Seal Inspection Seal Checklist to include the inspection of
electric bond to assure there is no static potential between the roof and shell during
operation and maintenance activities.
In regard to Item Number 4 of the Notice pertaining to Lion’s failure to provide the records
which indicates welding was performed by a qualified welder in accordance with welding
procedure qualified under section 5 of API 1104, Lion must develop a process to capture
this information. Also, Lion must develop a form for the visual inspection of weld.
In regard to Item Number 5 of the Notice pertaining to Lion’s failure to take measures to
prevent and mitigate the consequences of a pipeline failure that could affect high
consequence area, Lion must conduct an adequate risk analysis to determine measures to
prevent and mitigate the consequence of a pipeline failure that could affect a high
consequence area.
In regard to Item Number 6 of the Notice pertaining to Lion’s failure to review the program
effectiveness of the integrity management program during the calendar year 2011, 2013,
and 2015. Lion must establish the methods to measures program effectiveness to assess
the integrity management program is effective in assessing and evaluating the integrity of
each of their pipeline segment and in protecting the high consequence areas annually.
In regard to Item Number 7 of the Notice pertaining to Lion’s failure to correctly analyze
and integrate all available information about the integrity of its covered pipeline segment
and consequence of failure, Lion must consider all relevant risk categories and operating
conditions and evaluate individual pipeline segment risks.
In regard to Item Number 10 of the Notice pertaining to Lion’s failure to inspect the
physical integrity of in-service Breakout Tank # 2002 within timeframe specified by API
653 section 6.4.2.1, Lion must perform an internal inspection. Also, Lion must incorporate
the correct edition of API 653 listed in §195.3.
Lion must complete items 1, 2 and 3 within 30 days and items 4, 5 6 and 7 within 90 days.
10



9. It is requested (not mandated) that Lion maintain documentation of the safety improvement
costs associated with fulfilling this Compliance Order and submit the total to Director,
Southwest, 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.
11

## Provenance

- Official: Yes
- Source: <https://primis.phmsa.dot.gov/enforcement-data/case/420185001>
- Source ID: `phmsa-enforcement`
- SHA-256: `31f84470c13aff3d904144e45860583c39d269ade80e048ffc10b13ecb3f2e9d`
- Retrieved: 2026-08-20T04:44:44.458Z
- Exported: 2026-08-22T16:43:07.773Z
- Document slug: `phmsa-enforcement-420185001`

### Source metadata

```json
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  "cpf": "420185001",
  "operator": "DELEK LOGISTICS OPERATING, LLC.",
  "region": "Southwest",
  "pipelineType": "INTERSTATE LIQUID ONSHORE",
  "caseStatus": "CLOSED",
  "citedSections": [
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    "195.402(a)",
    "195.432(b)",
    "195.452(f)(3)",
    "195.452(f)(7)",
    "195.452(i)(1)",
    "195.452(k)",
    "195.54(a)",
    "195.61"
  ],
  "dataAsOf": "08/04/2026 12PM",
  "caseDataAsOf": "2026-08-04",
  "attachmentCount": 7,
  "attachments": [
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      "bytes": 20130,
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    },
    {
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