DELEK LOGISTICS OPERATING, LLC. — Notice of Probable Violation

party submissionOfficial PDF420185001_Operator Response to Notice and Request for Time Extension_03072018.pdf#

420185001_Final Order_02042019_text.pdf, page 1Official PDFFebruary 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#

420185001_Final Order_02042019_text.pdf, page 2U.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).#

420185001_Final Order_02042019_text.pdf, page 3CPF 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#

420185001_Final Order_02042019_text.pdf, page 4CPF 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.#

420185001_Final Order_02042019_text.pdf, page 5CPF No. 4-2018-5001 Page 4 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:#

420185001_Final Order_02042019_text.pdf, page 6CPF 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:#

420185001_Final Order_02042019_text.pdf, page 7CPF No. 4-2018-5001 Page 6 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.#

420185001_Final Order_02042019_text.pdf, page 8CPF 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.#

420185001_Final Order_02042019_text.pdf, page 9CPF 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.#

420185001_Final Order_02042019_text.pdf, page 10CPF 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).#

420185001_Final Order_02042019_text.pdf, page 11CPF No. 4-2018-5001 Page 10 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#

420185001_Final Order_02042019_text.pdf, page 12CPF 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.#

420185001_Final Order_02042019_text.pdf, page 13CPF 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, page 1Official PDFCERTIFIED 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, page 1Official PDFNOTICE 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#

420185001_NOPV PCP PCO_02072018_text.pdf, page 2commence, 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#

420185001_NOPV PCP PCO_02072018_text.pdf, page 3Lion 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#

420185001_NOPV PCP PCO_02072018_text.pdf, page 4(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#

420185001_NOPV PCP PCO_02072018_text.pdf, page 5maintenance 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#

420185001_NOPV PCP PCO_02072018_text.pdf, page 6(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#

420185001_NOPV PCP PCO_02072018_text.pdf, page 7then 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#

420185001_NOPV PCP PCO_02072018_text.pdf, page 810. §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#

420185001_NOPV PCP PCO_02072018_text.pdf, page 9Proposed 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#

420185001_NOPV PCP PCO_02072018_text.pdf, page 10PROPOSED 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#

420185001_NOPV PCP PCO_02072018_text.pdf, page 119. 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#