COFFEYVILLE RESOURCES CRUDE TRANSPORTATION, LLC — Notice of Probable Violation

case documentOfficial PDF320165006_NOPV_PCP_PCO_07252016.pdf#

party submissionOfficial PDF320165006_Operator Response to Notice_08292016.pdf#

320165006_Final Order_10312017_text.pdf, page 1Official PDFOctober 31, 2017 Mr. John Lipinski Chief Executive Officer and President CVR Refining, LP 2277 Plaza Drive Suite 500 Sugar Land, TX 77479 Re: CPF No. 3-2016-5006 Dear Mr. Lipinski: Enclosed please find the Final Order issued in the above-referenced case to your subsidiary, Coffeyville Resources Crude Transportation, LLC (CRCT). It makes findings of violation, assesses a reduced civil penalty of $448,600, and acknowledges receipt of payment of the partial penalty amount of $156,400, by wire transfer, dated September 28, 2016. A remaining balance of $292,200 is now due. In addition, the Final Order specifies actions that need to be taken by CRCT to comply with the pipeline safety regulations. The penalty payment terms are set forth in the Final Order. When the remainder of the civil penalty has been paid and the terms of the compliance order completed, as determined by the Director, Central Region, this enforcement action will be closed. Service of the Final Order by certified mail is deemed effective upon the date of mailing, or as otherwise provided under 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Alan K. Mayberry Associate Administrator for Pipeline Safety Enclosure cc: Mr. Allan C. Beshore, Director, Central Region, Office of Pipeline Safety, PHMSA Mr. Robert Haugen, Executive Vice President of Refining Operations, Coffeyville Resources Crude Transportation, LLC, 2277 Plaza Drive, Suite 500; Building B, Sugar Land, TX 77479 CERTIFIED MAIL - RETURN RECEIPT REQUESTED#

320165006_Final Order_10312017_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 ) ) Coffeyville Resources Crude Transportation, LLC, ) a subsidiary of CVR Refining, LP, ) CPF No. 3-2016-5006 ) Respondent. ) __________________________________________ ) FINAL ORDER On September 14-18 and 21-25, 2015, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the facilities and records of Coffeyville Resources Crude Transportation, LLC (CRCT or Respondent), in Bartlesville, Oklahoma, and its facilities in Kansas and Oklahoma. In 2012, CVR Energy, Inc., formed a limited partnership, CVR Refining, LP, to own, operate and grow its petroleum refining and related logistic businesses. CVR Refining, LP’s petroleum business includes CRCT which operates an approximately 65,000-barrel-per-day, crude oil gathering and pipeline/trucking system located in Oklahoma and Kansas. The gathering system is comprised of more than 350 miles of company- owned pipelines and associated tankage and truck transportation facilities.1 As a result of the inspection, the Director, Central Region, OPS (Director), issued to Respondent, by letter dated July 25, 2016, a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that CRCT had committed 11 violations of 49 C.F.R. Part 195 and proposed assessing a civil penalty of $497,600 for the alleged violations. The Notice also proposed ordering Respondent to take certain measures to correct the alleged violations. The Notice included several warning items pursuant to 49 C.F.R. § 190.205, which required no further action but warned the operator to correct the probable violations or face future possible enforcement action. CRCT responded to the Notice by letter dated August 29, 2016 (Response). The company contested some of the allegations, offered additional information in response to the Notice, and requested that the proposed civil penalty be reduced. For certain uncontested items, Respondent submitted partial payment of the proposed penalties in the amount of $156,400 by wire transfer dated September 28, 2016. Respondent did not request a hearing and therefore has waived its right to one. 1 http://www.cvrrefining.com/RefiningOperations/index html (last accessed September 22, 2017).#

320165006_Final Order_10312017_text.pdf, page 3CPF No. 3-2016-5006 Page 2 FINDINGS OF VIOLATION UNCONTESTED In its Response, CRCT did not contest certain allegations in the Notice that it violated 49 C.F.R. Part 195, as follows: Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.404(c)(3), which states: § 195.404 Maps and records. (a) … (c) Each operator shall maintain the following records for the periods specified: (1) … (3) A record of each inspection and test required by this subpart shall be maintained for at least 2 years or until the next inspection or test is performed, whichever is longer. The Notice alleged that Respondent violated 49 C.F.R. § 195.404(c)(3) by failing to maintain a record of each required inspection for at least two years. Specifically, the Notice alleged that Respondent failed to maintain records demonstrating that certain over-pressure protection devices were checked annually and failed to have records of inspecting certain flow controllers at the pump stations. The PHMSA inspection was conducted in September 2015, which meant that CRCT allegedly should have been able to provide records for the inspection of these devices from at least September of 2013. CRCT, however, was unable to show that the over-pressure protection and flow control devices had been inspected annually at Hooser Station in 2014, Coffeyville Station in 2014-2015, Valley Station in 2015, and Valley Booster Station in 2014. 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. § 195.404(c)(3) by failing to maintain records of each required inspection of over-pressure protection devices and flow controllers for at least two years. Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.404(c)(3), as quoted above, by failing to maintain a record of each required inspection for at least two years. Specifically, the Notice alleged that Respondent failed to document its monthly above-ground breakout tank inspections conducted in accordance with API 653 (incorporated by reference, see § 195.432). The Notice alleged that the OPS inspector reviewed tank-inspection records and found that CRCT did not have all the monthly inspection documents for 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. § 195.404(c)(3) by failing to maintain for at least two years a record of each required monthly above-ground breakout tank inspection. Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.410(a)(2)(ii), which states:#

320165006_Final Order_10312017_text.pdf, page 4CPF No. 3-2016-5006 Page 3 § 195.410 Line markers. (a) Except as provided in paragraph (b) of this section, each operator shall place and maintain line markers over each buried pipeline in accordance with the following: (1) … (2) The marker must state at least the following on a background of sharply contrasting color: (i) … (ii) The name of the operator and a telephone number (including area code) where the operator can be reached at all times. The Notice alleged that Respondent violated 49 C.F.R. § 195.410(a)(2)(ii) by failing to provide a telephone number where the operator could be reached at all times on line markers placed over each buried pipeline. Specifically, the Notice alleged that while driving the 12-inch Broome-to- Coffeyville line through Coffeyville, the OPS inspector noted that the mainline and mainline valves were marked with old line markers that contained an incorrect telephone number that was inactive. Other markers directed callers to report pipeline emergencies but did not state the telephone number on the line markers. The inspector also noticed that on the #1-8-inch and #3- 8-inch lines, line markers from the previous operator were still present. 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. § 195.410(a)(2)(ii) by failing to provide a telephone number where the operator could be reached at all times on line markers placed over each buried pipeline. Item 8: The Notice alleged that Respondent violated 49 C.F.R. § 195.428(a), which states: § 195.428 Overpressure safety devices and overfill protection systems. (a) Except as provided in paragraph (b) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, or in the case of pipelines used to carry highly volatile liquids, at intervals not to exceed 71∕2 months, but at least twice each calendar year, inspect and test each pressure limiting device, relief valve, pressure regulator, or other item of pressure control equipment to determine that it is functioning properly, is in good mechanical condition, and is adequate from the standpoint of capacity and reliability of operation for the service in which it is used. The Notice alleged that Respondent violated 49 C.F.R. § 195.428(a) by failing to inspect and test the thermal relief valves at Broome station at intervals not to exceed 15 months, but at least once each calendar year. Specifically, the Notice alleged that during the field inspection, the OPS inspector found that Broome station had five new thermal relief valves on the newly built section of the station. CRCT personnel indicated that the new section was built in February of 2014 and that the relief valves were scheduled for inspection in December of 2015. The inspections should have been completed within 15 months, or by May 31, 2015, but at the time of the OPS inspection in September 2015, the valves had not been inspected.#

320165006_Final Order_10312017_text.pdf, page 5CPF No. 3-2016-5006 Page 4 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. § 195.428(a) by failing to inspect and test the thermal relief valves at Broome station at intervals not to exceed 15 months. Item 9: 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 its above-ground breakout tanks according to API 653. Specifically, the Notice alleged that Respondent did not conduct the five-year in-service external tank inspections specified in Subsection 6.3.2.1 of API 653, which requires the inspection to occur every five years or RCA/4N years (where RCA is the difference between the measured shell thickness and the minimum required thickness in mils, and N is the shell corrosion rate in mils per year), whichever is less. Since CRCT had no information on shell corrosion rates to apply the RCA/4N equation, it was required to conduct inspections every five years. When Respondent acquired the tanks, it was required to inspect the tanks no later than five years after the most recent inspection. If Respondent could not determine if or when a prior inspection had occurred, the operator would be required to perform an API 653 inspection immediately after acquiring the breakout tanks and then again five years later.2 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 its above-ground breakout tanks according to API 653 in that it failed to conduct the five-year in- service external tank inspections. Item 11: The Notice alleged that Respondent violated 49 C.F.R. § 195.432(d), 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 2 Sunoco Pipeline L.P, CPF No. 4-2007-5040, Final Order at 7, 2010 WL 5761108, at *5 (Dec. 16, 2010).#

320165006_Final Order_10312017_text.pdf, page 6CPF No. 3-2016-5006 Page 5 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. . . (d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator’s last recorded date of the inspection, whichever is earlier. The Notice alleged that Respondent violated 49 C.F.R. § 195.432(d) by failing to inspect its above-ground breakout tanks according to API 653, in that it failed to conduct the initial 10-year out-of-service tank inspections by 2009. Specifically, the Notice alleged that CRCT acquired the breakout tanks in 2004, but did not have any records of previous inspections. Without records of previous inspections, pursuant to § 195.432(b), Respondent was required to begin the 10-year interval for initial out-of-service tank inspections on May 3, 1999. This required the tanks to be inspected by May 3, 2009, but Respondent failed to perform the tank inspections by that date. 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(d) by failing to inspect its above-ground breakout tanks according to API 653, in that it failed to conduct the initial 10-year out-of-service tank inspections by 2009. Item 14: 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 [emergency flow restricting devices] 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 a high consequence area (HCA). Specifically, the Notice alleged that Respondent could not provide any documentation showing it had taken preventive and mitigative (P&M) measures in accordance with its integrity management program (IMP). The IMP plan, implemented on February 21, 2013, references appendices for P&M measures and P&M evaluation forms, but P&M measures did not appear to have been documented or developed, nor had the evaluation#

320165006_Final Order_10312017_text.pdf, page 7CPF No. 3-2016-5006 Page 6 forms been filled out. 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 consequences of a pipeline failure that could affect an HCA. Item 17: The Notice alleged that Respondent violated 49 C.F.R. § 195.573(a)(1), which states: § 195.573 What must I do to monitor external corrosion control? (a) Protected pipelines. You must do the following to determine whether cathodic protection required by this subpart complies with §195.571: (1) Conduct tests on the protected pipeline at least once each calendar year, but with intervals not exceeding 15 months. However, if tests at those intervals are impractical for separately protected short sections of bare or ineffectively coated pipelines, testing may be done at least once every 3 calendar years, but with intervals not exceeding 39 months. The Notice alleged that Respondent violated 49 C.F.R. § 195.573(a)(1) by failing to conduct annual testing of its cathodic protection on multiple facilities in the CRCT system from 2013- 2015. Specifically, the Notice alleged that a review of CRCT’s annual cathodic-protection readings identified 10 facilities at which Respondent failed to perform annual cathodic- protection monitoring. 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. § 195.573(a)(1) by failing to conduct annual testing of its cathodic protection on multiple facilities in the CRCT system from 2013- 2015. Item 18: The Notice alleged that Respondent violated 49 C.F.R. § 195.583(a), which states: § 195.583 What must I do to monitor atmospheric corrosion control? (a) You must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows: If the pipeline is located: Then the frequency of inspection is: Onshore……………………………... Offshore……………………………... At least once every 3 calendar years, but with intervals not exceeding 39 months At least once each calendar year, but with intervals not exceeding 15 months The Notice alleged that Respondent violated 49 C.F.R. § 195.583(a) by failing to conduct atmospheric corrosion inspections of its onshore pump stations at least once every three years.#

320165006_Final Order_10312017_text.pdf, page 8CPF No. 3-2016-5006 Page 7 Specifically, the Notice alleged that in response to a request by the OPS inspector for atmospheric inspection records from 2009-2015, CRCT submitted records showing ultrasonic (UT) inspections of the wall thickness of the above-ground facilities in Coffeyville Station for 2012 and 2013, as well as Hooser Station in 2013. However, Respondent did not have records indicating that atmospheric inspections were performed at the time of the UT evaluations. Additionally, Respondent did not have records for Broome, Shidler, Coffeyville, Valley, Valley Booster #1 and #2, and Hooser stations. 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. § 195.583(a) by failing to conduct atmospheric corrosion inspections of its onshore pump stations at least once every three years. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. CONTESTED The Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows: Item 13: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h)(4)(i)(C), which states: § 195.452 Pipeline integrity management in high consequence areas. (a)… (h) What actions must an operator take to address integrity issues? (1) General requirements. An operator must take prompt action to address all anomalous conditions that the operator discovers through the integrity assessment or information analysis. In addressing all conditions, an operator must evaluate all anomalous conditions and remediate those that could reduce a pipeline’s integrity. An operator must be able to demonstrate that the remediation of the condition will ensure that the condition is unlikely to pose a threat to the long-term integrity of the pipeline. A reduction in operating pressure cannot exceed 365 days without an operator taking further remedial action to ensure the safety of the pipeline. An operator must comply with § 195.422 when making a repair… (4) Special requirements for scheduling remediation. (i) Immediate repair conditions. An operator’s evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formula in section 451.7 of ASME/ANSI B31.4 (incorporated by reference, see § 195.3). An operator must treat the following conditions as immediate repair conditions: (A) … (C) A dent located on the top of the pipeline (above the 4 and 8 o’clock#

320165006_Final Order_10312017_text.pdf, page 9CPF No. 3-2016-5006 Page 8 positions) that has any indication of metal loss, cracking or a stress riser.3 The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h)(4)(i)(C) by failing to temporarily reduce operating pressure or shut down the pipeline until it completed the repair of certain “immediate repair” conditions. Specifically, the Notice alleged that Respondent did not reduce pressure or shut down the Valley 6-inch Segment 2 and Segment 3 lines once it discovered five top-side dents with metal loss, which are considered immediate repair conditions under § 195.452(h)(4)(i)(C). At the time of the OPS inspection, CRCT’s supervisors on the job indicated that no pressure reduction was taken at the time of discovery. In its Response, CRCT contested the allegation of violation on two grounds. First, it contended that the anomalies identified by its in-line inspection (ILI) vendor had been misclassified as “dents.” Second, it argued that a pressure reduction was unnecessary, based on its vendor’s engineering analysis of a safe operating pressure. On the first issue, CRCT argued that the anomalies had been misclassified as dents when, in fact, its experience with previous repairs of the Valley 6-inch pipeline showed that many anomalies were actually “small scratches on the outer surface of the pipe, presumably artifacts of the pipe installation.” CRCT explained that its ILI procedures nevertheless required the vendor to report all depth anomalies greater than two percent and that it treated any such anomalies located on the top side of the pipe as immediate-repair conditions, regardless of metal loss.4 CRCT acknowledged that two of the anomalies shown on the chart in its Response did, in fact, meet the company’s own criteria for immediate repair because they were top-side anomalies with a depth greater than two percent, but that the other three did not.5 On the second issue, Respondent argued that considering the fact that these anomalies “may have been misclassified as dents” yet two still met the company’s own criteria for immediate repair, CRCT agreed “that an evaluation of a safe operating pressure for the line is required by PHMSA regulations.” According to the company, it undertook such an analysis but found that no pressure reduction was required because the ILI final report had showed that the calculated safe operating pressure for the pipeline was greater than the operating pressures that had been reported to PHMSA by CRCT.6 It based this calculation on the maximum allowable operating pressure (MAOP) for the segments, not the operating pressure.7 Respondent reported to PHMSA that its operating pressure was 500 psi and that the MAOP was 620 psi.8 3 49 CFR § 195.452(h) was subsequently amended on March 11, 2015 (Pipeline Safety: Miscellaneous Changes to Pipeline Safety Regulations, 80 FR 12762). 4 Response at 6. 5 Id. 6 Id., 5-6. 7 Response, Attachment A. 8 Violation Report, Ex. E, Att. 5; Response, Att. A.#

320165006_Final Order_10312017_text.pdf, page 10CPF No. 3-2016-5006 Page 9 I find both arguments unpersuasive. Section 195.452(h)(4)(i) requires operators to take immediate action to address various types of anomalous conditions discovered through an integrity assessment. These include dents located on the top of the pipeline where there is any indication of metal loss. Once an immediate-repair condition is discovered, to maintain safety, an operator must temporarily reduce operating pressure or shut down the pipeline until the operator completes the repair of the condition. In this case, Respondent received an integrity assessment that identified five dents on the top side of the pipe with metal loss, but failed to reduce pressure or shut down the Valley 6-inch Segments 2 and 3 after the discovery. Respondent received two “Pipeline Inspection Reports” from its ILI vendor that included a section titled “Dent - Immediate Prioritized Repairs.”9 This section listed the five anomalies identified in the Notice and indicated that they were dents with metal loss.10 Respondent ultimately repaired each of these conditions and received five completed repair worksheets for the anomalies that categorized each “External Pipe Condition” anomaly as a “Dent w/Metal Loss.”11 Thus, Respondent’s own vendor and its own documents treated these anomalies as dents. Although Respondent now claims that these five anomalies “may have been misclassified as dents,” it has provided no evidence demonstrating that it performed a documented analysis at the time it received the vendor’s report to justify disregarding them as immediate-repair conditions. I therefore find that the ILI vendor’s report, together with the company’s own repair worksheets, constitute sufficient information about the conditions that CRCT is deemed to have discovered that the conditions presented a potential integrity threat.12 Accordingly, Respondent was required to treat the five anomalies as dents with metal loss, which are immediate-repair conditions. One of the anomalies warrants additional discussion. The anomaly identified as ID#1400203/Wheel count 37672.20 was reported by the vendor as a “dent with metal loss” because of metal loss in close proximity to the dent. In consideration of tool tolerances, the vendor’s reporting of this anomaly as a dent with metal loss was reasonable and would be within the reporting specifications for the vendor’s tools. Again, Respondent has provided no contemporaneous information indicating that the tool results were considered unacceptable or erroneous by CRCT. Even accepting, without supporting evidence, that this anomaly was misclassified, there were four other dents with metal loss for which CRCT should have implemented a pressure reduction or shut down Segments 2 and 3. Moreover, as noted above, Table 1 in the Response shows two anomalies with greater than two percent depth, located above the 4 and 8 o’clock positions, with metal loss. Under CRCT’s own procedures, any anomaly greater than two percent on the top side of the pipe was supposed to have been treated as an immediate-repair condition, regardless of metal loss.13 Therefore, under both the regulation and CRCT’s own procedures, Respondent was required to reduce operating pressure or shut down the pipeline. 9 Violation Report, Ex. H, at 5-6 and 9-10. 10 Id. 11 Violation Report, Ex. H, at 16, 30, 41, 55, and 70. 12 49 C.F.R. § 195.452(h)(2). 13 Response, at 6.#

320165006_Final Order_10312017_text.pdf, page 11CPF No. 3-2016-5006 Page 10 Finally, I also reject Respondent’s argument that a pressure reduction was unnecessary based on the vendor’s engineering analysis. Respondent based this analysis on the MAOP of the pipeline, and therefore reasoned that since its actual operating pressure was more than 20 percent lower than the MAOP, it did not need to reduce pressure to comply with pipeline safety regulations. This is incorrect. The regulations require either a temporary reduction in operating pressure or a shutdown of the pipeline when immediate-repair conditions are discovered, regardless of the MAOP. Accordingly, after considering all of the evidence, I find that CRCT violated § 195.452(h)(4)(i)(C) by failing to temporarily reduce operating pressure or shut down the pipeline until it had completed the repair of these immediate-repair conditions. Item 15: The Notice alleged that Respondent violated 49 C.F.R. § 195.505(b), which states: § 195.505 Qualification program. Each operator shall have and follow a written qualification program. The program shall include provisions to: (a)… (b) Ensure through evaluation that individuals performing covered tasks are qualified. The Notice alleged that Respondent violated 49 C.F.R. § 195.505(b) by failing to follow its own written qualification program to ensure through evaluation that individuals performing covered tasks were qualified. Specifically, the Notice alleged that while reviewing the mainline valve inspection records, the OPS inspector asked for operator-qualification records of three CRCT employees conducting valve inspections. The company allegedly was unable to provide any records that showed the employees were qualified to inspect and operate mainline valves for the years 2013-2015. In its Response, CRCT stated that the three employees at issue were trained, qualified, and able to perform mainline valve inspections. It argued that each employee had pipeline experience or was trained by other employees with pipeline experience, and all three employees had documented operator qualifications for numerous pipeline tasks far more complex than inspecting a mainline valve, which includes only a visual inspection and manual operation. CRCT contended, therefore, that all three employees were fully qualified for mainline valve inspections, but “simply lacked all of the appropriate documentation.”14 Section 195.505 requires operators to follow a written program to ensure through evaluation that individuals performing covered tasks are able to perform the tasks safely and can recognize and react to abnormal operating conditions. In this case, the record is absent of any evidence showing that the personnel identified in the Notice had been evaluated specifically for the task of performing mainline valve inspections. Respondent produced information relating to the workers’ general experience and qualifications for other tasks, but did not demonstrate that its 14 Response, at 8.#

320165006_Final Order_10312017_text.pdf, page 12CPF No. 3-2016-5006 Page 11 own established process for assessing individuals was carried out and documented for these individuals to perform mainline valve inspections. There was also no evidence that the three employees took any required classes and passed tests associated with the covered task of inspecting mainline valves.15 Respondent is required to follow its operator qualification program and therefore must ensure that each employee performing a covered task has been qualified for that task. This includes following written procedures established by the operator to evaluate each employee, using an examination or other form of assessment to ensure they are qualified. Individuals performing mainline valve inspection must be qualified specifically to ensure that the inspections are conducted properly and that any abnormal operating conditions are recognized and reacted to appropriately. After considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.505(b) by failing to follow its own written qualification program to ensure through evaluation that individuals performing covered tasks were qualified. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed $200,000 per violation for each day of the violation, up to a maximum of $2,000,000 for any related series of violations.16 In determining the amount of a civil penalty under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature, circumstances, and gravity of the violation, including adverse impact on the environment; the degree of Respondent’s culpability; the history of Respondent’s prior offenses; and any effect that the penalty may have on its ability to continue doing business; and the good faith of Respondent in attempting to comply with the pipeline safety regulations. In addition, I may consider the economic benefit gained from the violation without any reduction because of subsequent damages, and such other matters as justice may require. The Notice proposed a total civil penalty of $497,600 for the violations cited above. Item 4: The Notice proposed a civil penalty of $23,300 for Respondent’s violation of 49 C.F.R. § 195.404(c)(3), for failing to maintain records of each required inspection of over-pressure protection devices and flow controllers for at least two years. Respondent did not contest the allegation or request a reduction in the proposed penalty. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $23,300 for 15 Violation Report at 60 (stating that “OQ Qualifications show[ed] that [the employees] were not qualified for the years the inspections occurred” and Respondent stated that it was “unable to provide qualification records for the inspection of mainline valves that cover October 2013 to August 2015”). 16 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).#

320165006_Final Order_10312017_text.pdf, page 13CPF No. 3-2016-5006 Page 12 violation of 49 C.F.R. § 195.404(c)(3), which amount has already been paid. Item 5: The Notice proposed a civil penalty of $25,900 for Respondent’s violation of 49 C.F.R. § 195.404(c)(3), for failing to maintain for at least two years a record of each monthly above- ground breakout tank inspection required. Respondent neither contested the allegation nor presented any evidence or argument justifying elimination of the proposed penalty. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $25,900 for violation of 49 C.F.R. § 195.404(c)(3), which amount has already been paid. Item 8: The Notice proposed a civil penalty of $33,100 for Respondent’s violation of 49 C.F.R. § 195.428(a), for failing to inspect and test the thermal relief valves at Broome station at intervals not to exceed 15 months. CRCT did not contest the probable violation, but requested that the proposed penalty be reduced based on its prompt correction of the deficiency. CRCT noted that it had inspected and tested the thermal relief valves in January 2016, soon after the violation had been identified during the OPS inspection. CRCT further stated that because this violation did not identify any issues requiring corrective action for the valves themselves, the gravity factor for the proposed penalty should be lowered. I disagree. With respect to Respondent promptly correcting the violation, I find that correcting a violation after it has already been identified by OPS is not grounds to reduce the penalty, as Respondent is obligated to remediate the noncompliance issue once it becomes aware of it.17 With respect to the gravity factor, the Violation Report alleged that pipeline safety had been compromised in an area other than an HCA. This allegation is supported by the record. The purpose of a relief valve inspection is to ensure that the valve works in an emergency situation. Thermal relief valves are important for maintaining the integrity of above-ground piping. Inspection of these valves is essential to ensuring that the relief device will function as designed. Respondent’s failure to inspect and test relief valves necessary to prevent pipeline failures compromised safety, even though more serious problems, such as a release or issues requiring corrective action, did not occur. For these reasons, I find that there is no justification to reduce the proposed penalty. Based upon the foregoing, I assess Respondent a civil penalty of $33,100 for violation of 49 C.F.R. § 195.428(a). Item 9: The Notice proposed a civil penalty of $54,700 for Respondent’s violation of 49 C.F.R. § 195.432(b), for failing to conduct five-year in-service external tank inspections according to API 653. CRCT did not contest the allegation of violation but requested that the penalty be reduced, at a minimum, by 30 percent because five of the inspections were completed within what would have been the second round of five-year inspections following CRCT’s acquisition of these assets. CRCT stated that the remaining four tanks are now in compliance with the inspection requirements. Furthermore, CRCT argued that the gravity of the violation should be lower because subsequent inspection reports for these tanks did not identify any imminent threats 17 See, e.g., In the Matter of Enbridge Pipelines LLC, Final Order, CPF No. 3-2007-5022, at 3, 2009 WL 2336996 (Jun. 2, 2009) (finding corrective action taken after an accident had already occurred did not warrant mitigation of the proposed penalty).#

320165006_Final Order_10312017_text.pdf, page 14CPF No. 3-2016-5006 Page 13 to tank integrity. Finally, CRCT argued that a penalty reduction was justified because “the severity score of the issue…is better characterized as having no significant impact and that gravity for pipeline safety…was minimally affected.”18 As stated above, Respondent’s correction of a violation after it has already been identified by OPS is not grounds to reduce a proposed penalty. With respect to gravity, the Violation Report alleged that pipeline safety or integrity was compromised in an HCA or an HCA “could affect” segment. While Respondent argued that the violation did not lead to an actual imminent threat, pipeline safety was still compromised. Although the tanks were within diked areas, several of the tanks were located in HCAs, which means that a failure of a tank could affect an HCA such as the Verdigris River. Finally, the “severity score” referenced in Part E3 of the Violation Report was not considered in either the proposed or assess civil penalty. For the above reasons, I find that there is no justification to reduce the proposed penalty. Accordingly, I assess Respondent a civil penalty of $54,700 for violation of 49 C.F.R. § 195.432(b). Item 11: The Notice proposed a civil penalty of $54,700 for Respondent’s violation of 49 C.F.R. § 195.432(d), for failing to conduct the initial 10-year out-of-service tank inspection according to API 653. Respondent neither contested the allegation nor presented any evidence or argument justifying elimination of the proposed penalty. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $54,700 for violation of 49 C.F.R. § 195.432(d), which amount has already been paid. Item 13: The Notice proposed a civil penalty of $79,200 for Respondent’s violation of 49 C.F.R. § 195.452(h)(4)(i)(C), for failing to temporarily reduce the operating pressure or shut down the pipeline until it had completed the repair of immediate-repair conditions. CRCT argued that, at a minimum, the penalty amount should be reduced by 60 percent because only two of the five cited repairs actually met CRCT’s criteria for immediate repair. I reject this argument, having already found that Respondent violated the regulation with respect to each of the five identified anomalies. CRCT further argued that the gravity of the violation should be reduced to reflect that it “minimally affected” safety, as demonstrated by the ILI report, rather than “safety or integrity was compromised in an HCA” or “could-affect” areas. Finally, Respondent argued that the severity score in Part E3 of the Violation Report should be reduced. I am unconvinced that any penalty reduction is warranted. Once CRCT received the ILI results from its vendor identifying immediate conditions, it was required to implement pressure reductions or shut down the pipelines without delay. It failed to do so. The anomalies were located in an HCA, meaning that the failure to reduce the operating pressure or shut down the pipeline compromised pipeline safety in an HCA until the proper repairs could be made. In an HCA, operators have to comply with more stringent safety standards and failing to comply with them represents a heightened risk to people and sensitive environments within that HCA. Accordingly, I find the Violation Report correctly identified the gravity factor as “safety or 18 Response at 12.#

320165006_Final Order_10312017_text.pdf, page 15CPF No. 3-2016-5006 Page 14 integrity was compromised in an HCA or an HCA ‘could affect’ segment.” As discussed above, the “severity score” from Part E3 of the Violation Report was not a factor in calculating the proposed civil penalty. Finally, this violation constitutes a repeat violation of the same regulation that had previously been identified in a final order issued to Respondent on November 13, 2013 in CPF No. 3-2012-5010, Item 3.19 Accordingly, I assess Respondent a civil penalty of $79,200 for Respondent’s violation of 49 C.F.R. § 195.452(h)(4)(i)(C). Item 15: The Notice proposed a civil penalty of $79,200 for Respondent’s violation of 49 C.F.R. § 195.505(b), for failing to follow its own written qualification program to ensure through evaluation that individuals performing covered tasks were qualified. CRCT argued that the penalty amount should be reduced to an amount commensurate with a record-keeping violation. Further, CRCT contended that the gravity of the violation was minimal and the severity score in Part E3 of the Violation Report should be reduced. This violation was not simply a record-keeping error. While Respondent believed that its employees were sufficiently trained to perform this particular covered task, the record demonstrates that the individuals had not been formally qualified through Respondent’s established operator-qualification program to perform the covered task of inspecting mainline valves. Accordingly, the violation is for failing to comply with the operator qualification requirement, not for failing to keep records. With respect to the gravity factor, the Violation Report alleged that safety or integrity was compromised in an HCA or an HCA “could-affect” segment. Respondent has made a convincing argument that safety was only minimally affected, given the work history and experience of the individuals involved and the likelihood that despite their lack of proper qualification, they were able to safely perform the action of inspecting mainline valves. Accordingly, I assess Respondent a reduced civil penalty of $30,200 for violation of 49 C.F.R. § 195.505(b). Item 17: The Notice proposed a civil penalty of $95,000 for Respondent’s violation of 49 C.F.R. § 195.573(a)(1), for failing to conduct annual testing of its cathodic protection on multiple facilities in the CRCT system from 2013-2015. CRCT did not contest the allegation of violation but requested that the proposed penalty be reduced, stating that it exceeded the regulatory requirements for annual readings by collecting other cathodic-protection data at its pipeline facilities. Based on its accelerated ILI frequency (three-year interval) and aggressive repair campaign (2,847 repairs since 2013), CRCT asserted that any threat to pipeline integrity posed by the lapse in annual cathodic-protection reading documentation was “rendered moot” as the annual readings were not CRCT’s only method of detecting threats to the pipeline. It therefore requested that the gravity of the violation was minimal. I find Respondent’s argument unpersuasive. External corrosion remains one of the top threats to pipelines. While CRCT’s aggressive use of ILI to address the threat is noteworthy, ILI detects 19 Coffeyville Resources Crude Transportation, LLC, Final Order, CPF No. 3-2012-5010, 2013 WL 7019193 (issued Nov. 13, 2013).#

320165006_Final Order_10312017_text.pdf, page 16CPF No. 3-2016-5006 Page 15 metal loss after it occurs. Cathodic protection, if properly implemented and monitored, is designed to prevent corrosion in the first place. Failing to monitor cathodic protection on CRCT’s pipeline presented a risk that inadequate corrosion control could lead to metal loss. Accordingly, the Violation Report correctly identified the gravity as “safety or integrity was compromised in an HCA or an HCA ‘could affect’ segment.” Based upon the foregoing, I assess Respondent a civil penalty of $95,000 for violation of 49 C.F.R. § 195.573(a)(1). Item 18: The Notice proposed a civil penalty of $52,500 for Respondent’s violation of 49 C.F.R. § 195.583(a), for failing to conduct atmospheric-corrosion inspections of its onshore pump stations at least once every three years. Respondent neither contested the allegation nor presented any evidence or argument justifying elimination of the proposed penalty. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $52,500 for violation of 49 C.F.R. § 195.583(a), which amount has already been paid. In summary, having reviewed the record and considered the assessment criteria for each of the Items cited above, I assess Respondent a total civil penalty of $448,600. Respondent has already rendered a partial payment of $156,400, by wire transfer dated September 28, 2016. Therefore, Respondent’s outstanding civil penalty is $292,200. 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, OK 79169. The Financial Operations Division telephone number is (405) 954-8845. Failure to pay the remaining $292,200 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 6, 14, and 18 in the Notice for violations of 49 C.F.R. §§ 195.410(a)(2)(ii), 195.452(i)(1) and 195.583(a), 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 in response to the proposed compliance order: With respect to Item 6, Respondent conducted a survey, as proposed, but failed to provide#

320165006_Final Order_10312017_text.pdf, page 17CPF No. 3-2016-5006 Page 16 follow-up documentation showing that the additional line markers had been installed. Therefore, this compliance order item will remain in this Order. With respect to Item 14, Respondent provided insufficient information and therefore must provide additional documentation to explain its position. Therefore, this compliance order item will remain in the Order. With respect to Item 18, CRCT provided adequate documentation to show that the requirements in the proposed compliance order had been completed. Specifically, CRCT showed that it had developed and implemented a schedule to atmospherically inspect the stations and all other above-ground piping. Accordingly, I find that compliance has been achieved with respect to this violation and therefore it is not necessary to include it in in the Final Order. 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 § 195.410(a)(2)(ii) (Item 6), Respondent must survey the 16-inch and 12-inch line from Broome Station to Coffeyville Station and the line(s) to the Refinery and replace and/or update the line markers with the correct phone 24-hour number. In regards to the #1-8-inch and #3-8-inch, CRCT must identify all exposures on those lines and replace any line markers from the previous operator with its own line markers. 2. With respect to the violation of § 195.452(i)(1) (Item 14), Respondent must develop the appendices for Section Five of its IMP and begin following the procedures for P&M measures as defined by the IMP plan. Specifically, the revised procedures must include: (1) more detail regarding when the P&M measures will be implemented; (2) how the deleted Appendices E.2, E.4, and E.6 are covered; (3) enough detail in the leak detection appendices to adequately show how the company’s leak detection system works and what company personnel are doing to operate the system; and (5) a description in the Emergency Flow Restricting Device (EFRD) appendices of whether EFRDs are needed or not and justification for the decision. It is requested (not mandated) that CRCT maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to the Director, Central Region, Pipeline and Hazardous Materials Safety Administration. It is requested that these costs be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses; and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. 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.#

320165006_Final Order_10312017_text.pdf, page 18CPF No. 3-2016-5006 Page 17 Failure to comply with this Order may result in administrative assessment of civil penalties not to exceed $200,000 for each violation for each day the violation continues or in referral to the Attorney General for appropriate relief in a district court of the United States. WARNING ITEMS With respect to Items 1, 2, 3, 7, 10, 12, and 16, the Notice alleged probable violations of Parts 194 and 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. § 194.7(b) (Item 1) ─ Respondent’s alleged failure to conduct the quarterly notification drills as specified by its OPA 90/Emergency Response Plan; 49 C.F.R. § 195.404(b)(1) (Item 2) ─ Respondent’s alleged failure to maintain the discharge records for its pump stations for three years; 49 C.F.R. § 195.404(c)(3) (Item 3) ─ Respondent’s alleged failure to maintain records for the inspection of its mainline valves for at least two years on three lines; 49 C.F.R. § 195.426 (Item 7) ─ Respondent’s alleged failure to use a suitable device to ensure that the pressure in the pipe barrel was relieved prior to insertion or removal of scrapers or spheres; 49 C.F.R. § 195.432(b) (Item 10) ─ Respondent’s alleged failure to complete the repairs recommended in an API 653 inspection of certain in-service breakout tanks, or to complete a summary of why the repairs were not implemented; 49 C.F.R. § 195.453(h)(1) (Item 12) ─ Respondent’s alleged failure to notify PHMSA that CRCT could not meet its own schedule for remediating immediate- repair conditions, as required under 195.452(h)(3), and for taking a temporary pressure reduction; and 49 C.F.R. § 195.571 (Item 16) ─ Respondent’s alleged failure to properly apply the consideration of voltage (IR) drop to a test point located on the Hooser 8-inch line, as required by paragraph 6.3 of NACE SP0169. CRCT presented information in its Response showing that it had taken certain actions to address the cited items. If OPS 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 has a right to submit a Petition for Reconsideration of this Final Order. The petition must be sent to: Associate Administrator, Office of Pipeline Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC 20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address. PHMSA will accept petitions received no later than 20 days after receipt of service of this Final Order by#

320165006_Final Order_10312017_text.pdf, page 19CPF No. 3-2016-5006 Page 18 the Respondent, provided they contain a brief statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.243. The filing of a petition automatically stays the payment of any civil penalty assessed. Unless the Associate Administrator, upon request, grants a stay, all other terms and conditions of this Final Order are effective upon service in accordance with 49 C.F.R. § 190.5. October 31, 2017 ___________________________________ __________________________ Alan K. Mayberry Date Issued Associate Administrator for Pipeline Safety#

320165006_Closure Letter_02212018_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED February 21, 2018 Mr. Robert Haugen Executive Vice President of Refining Operations Coffeyville Resources Crude Transportation, LLC 2277 Plaza Drive Suite 500; Building B Sugarland, TX 77479 CPF 3-2016-5006 Dear Mr. Haugen: On October 31, 2017, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to Coffeyville Resources Crude Transportation, LLC (CRCT) a Final Order in the above-referenced case. This Order included a Compliance Order and Civil Penalty assessment. Based on our review of the documentation you provided and confirmation of payment of the civil penalty, it has been determined that you have complied with the terms of this Order. Accordingly, this case is now closed and no further action is contemplated with respect to the matters involved in this case. Thank you for your cooperation in this matter. Sincerely, Allan C. Beshore Director, Central Region Pipeline and Hazardous Materials Safety Administration#

320165006_NOPV PCP PCO_07252016_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED July 25, 2016 Mr. Robert Haugen Executive Vice President of Refining Operations Coffeyville Resources Crude Transportation, LLC 2277 Plaza Drive Suite 500; Building B Sugarland, TX 77479 CPF 3-2016-5006 Dear Mr. Haugen: On September 14-18 and 21-25, 2015, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49 United States Code inspected your records in Bartlesville, Oklahoma and your facilities in Kansas and Oklahoma. As a result of the inspection, it appears that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violation(s) are: 1. §194.7 Operating restrictions and interim operating authorization (b) An operator must operate its onshore pipeline facilities in accordance with the applicable response plan.#

320165006_NOPV PCP PCO_07252016_text.pdf, page 2Coffeyville Resources Crude Transportation, LLC personnel (CVR) did not conduct the quarterly notification drills as specified by their OPA 90/Emergency Response Plan. CVR personnel indicated that they did not conduct the quarterly notifications drills because they relied on their SCADA alarm callouts to meet that requirement. However, the use of the alarm logs does not meet the exercise documentation requirements. Furthermore, the National Preparedness for Response Exercise Program guidelines (PREP) does not recognize that actual alarm events can be used in lieu of the drills. 2. §195.404 Maps and Records. (b) Each operator shall maintain for at least 3 years daily operating records that indicate- (1) The discharge pressure at each pump station; CVR was not maintaining the discharge records for their pump stations for three years. While reviewing the pressure discharge records, CVR personnel indicated that they were only keeping two years of discharge records for each of their pump stations. 3. §195.404 Maps and Records. (c) Each operator shall maintain the following records for the periods specified; (3) A record of each inspection and test required by this subpart shall be maintained for at least 2 years or until the next inspection or test is performed, whichever is longer CVR did not maintain records for the inspection of their mainline valves for at least two years on three lines. The missing inspections were for the second half of 2013. PHMSA conducted the inspection in September 2015. CVR should have kept all records for mainline valves from at least September 2013. However, CVR personnel could not provide any records to show that they had inspected the mainline valves for the second half of 2013 for the following lines: Segment Number of Valves 2nd inspection cycle Broome to Coffeyville 12” 7 Missing Broome to Coffeyville 16” 2 Missing Coffeyville to Coffeyville Refinery 3 Missing 2#

320165006_NOPV PCP PCO_07252016_text.pdf, page 3CVR did indicate through records for valve inspection of other line segments that the inspections could have occurred in July of 2013. But there were no other records to substantiate this assertion. 4. §195.404 Maps and Records. (c) Each operator shall maintain the following records for the periods specified; (3) A record of each inspection and test required by this subpart shall be maintained for at least 2 years or until the next inspection or test is performed, whichever is longer CVR did not maintain the records demonstrating that the over-pressure protection devices were checked annually. Additionally, CVR did not document the inspection of the flow controllers at the pump stations. The PHMSA inspection was conducted in September of 2015, which would require CVR to maintain the records for the inspection of these devices from at least September of 2013. CVR was unable to show that the over-pressure protection and flow control devices at Hooser station, Coffeyville station, Valley Station, and Valley Booster were inspected annually for the periods shown below. While reviewing the records for over-pressure protection, the following stations’ records were noted as missing: Station Missing Record of Inspection Year Hooser 2014 Coffeyville 2014, 2015 Valley 2015 Valley Booster 2014 5. §195.404 Maps and Records. (c) Each operator shall maintain the following records for the periods specified; (3) A record of each inspection and test required by this subpart shall be maintained for at least 2 years or until the next inspection or test is performed, whichever is longer CVR personnel did not document their monthly above-ground breakout tank inspections in accordance with API 653. Review of the required tank inspection records found that CVR did not have all the monthly inspection documents for 2013 through 2015. The missing monthly tank inspection records are as follows: 3#

320165006_NOPV PCP PCO_07252016_text.pdf, page 4Tank Number Year and Month missed. Tank 1105 Tank 1106 Tank 22A1 Tank 22A2 Tank 22A3 Tank 200 2014: 1, 2, 3, 4, 5, 6, 11, 12 2014: 1, 2, 3, 4, 5, 6, 11, 12 2014: 1, 2, 3, 4, 5, 6, 12 2014: 1, 2, 3, 4, 5, 6, 11, 12 2014: 1, 2, 3, 4, 5, 6, 9, 12 2013: 10, 11, 12 2014: 5, 6, 7, 8, 9, 10, 11, 12 2015: 2, 3 Tank 225 2013: 10, 12 2014: 5, 6, 7, 8, 9, 10, 11, 12 2015: 2, 3 Tank 230 2013: 10, 12 2014: 5, 6, 7, 8, 9, 10, 11, 12 2015: 2, 3 Tank 270 2013: 10, 12 2014: 5, 6, 7, 8, 9, 10, 11, 12 2015: 2, 3, 4, 5, 6, 7 Tank 285 2013: 10, 11, 12 2014: 1, 2, 3, 4, 5, 6, 7, 8, 9, 10 2015: 1, 2, 3, 6 Tank 290 2013: 10, 11, 12 2014: 1, 2, 3, 4, 5, 6, 7, 8, 9, 10 2015: 1, 2, 3, 6 6. §195.410 Line markers. (a) Except as provided in paragraph (b) of this section, each operator shall place and maintain line markers over each buried pipeline in accordance with the following: (2) The marker must state at least the following on a background of sharply contrasting color: (ii) The name of the operator and a telephone number (including area code) where the operator can be reached at all times. CVR’s line markers did not contain a telephone number where the operator could be reached at all times. Additionally, there were some exposures that had the line markers with only the previous pipeline operator’s information. While driving the 12” Broome to Coffeyville line through Coffeyville, it was noted that the mainline and the mainline valves were marked with old line markers that contained an incorrect telephone number. The line markers contained a 316-251-4000 number for night 4#

320165006_NOPV PCP PCO_07252016_text.pdf, page 5time calls that was inactive. The other number, 1-800-982-4112, takes the caller to a recording that directed callers of any pipeline emergencies to call 1-800-696-2614 – a number which is not stated on the line markers. It was also noticed that on the #1-8” and #3-8” lines, the exposures observed during the field evaluation still contained the line markers from the previous operator. Line markers are required to state the current operator. 7. §195.426 Scraper and sphere facilities. No operator may use a launcher or receiver that is not equipped with a relief device capable of safely relieving pressure in the barrel before insertion or removal of scrapers or spheres. The operator must use a suitable device to indicate that pressure has been relieved in the barrel or must provide a means to prevent insertion or removal of scrapers or spheres if pressure has not been relieved in the barrel. CVR did not use a suitable device to ensure that the pressure in the barrel was relieved prior to insertion or removal of scrapers or spheres. During the field evaluation of the CVR system, it was noted that at many of the launchers/receivers at the pump stations, the chain to prevent opening the trap door was disconnected from the warning device on the barrel. In order for this warning device to work properly, the chain must be connected. 8. §195.428 Overpressure safety devices and overfill protection systems (a) Except as provided in paragraph (b) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, or in the case of pipelines used to carry highly volatile liquids, at intervals not to exceed 7½ months, but at least twice each calendar year, inspect and test each pressure limiting device, relief valve, pressure regulator, or other item of pressure control equipment to determine that it is functioning properly, is in good mechanical condition, and is adequate from the standpoint of capacity and reliability of operation for the service in which it is used. CVR did not inspect and test the thermal relief valves at Broome station at intervals not to exceed 15 months, but at least once each calendar year in 2015. During the field inspection, it was found that Broome station had installed five new thermal relief valves on the newly built section of the station. As of the PHMSA inspection in September 2015, these relief valves had not been inspected. CVR personnel indicated that the new section was built in February of 2014 and that the relief valves were scheduled for inspection in December of 2015. The inspections should have been completed by May 31, 2015. 5#

320165006_NOPV PCP PCO_07252016_text.pdf, page 69. §195.432 Inspection of in-service breakout tanks. (b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks according to API Std 653 (except section 6.4.3, Alternative Internal Inspection Interval) (incorporated by reference, see §195.3). However, if structural conditions prevent access to the tank bottom, its integrity may be assessed according to a plan included in the operations and maintenance manual 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. CVR personnel did not inspect their above-ground breakout tanks according to API 653 in that they did not conduct the five year in-service external tank inspections. Section 6.3.2 of API 653 requires external inspections by an authorized inspector. Subsection 6.3.2.1 requires the inspection to occur every five years or RCA/4N years (where RCA is the difference between the measured shell thickness and the minimum required thickness in mils, and N is the shell corrosion rate in mils per year) whichever is less. Since CVR had no information on shell corrosion rates to apply the RCA/4N equation, they should have had an external inspection of the tanks by an authorized inspector five years from the time they acquired the tanks. The tanks were acquired in 2004. Review of the required tank inspection records found that CVR did not conduct the required five year external inspection for nine of their breakout tanks by 2009. The tanks that were not inspected every five years in accordance with API 653 are as follows: Valley Center Tank 290 Hooser Tank 270 Hooser Tank 230 Hooser Tank 225 Hooser Tank 200 Valley Center Tank 285 Broome Tank 1106 Coffeyville Tank 22A2 Plainville Tank 20 10. §195.432 Inspection of in-service breakout tanks. (b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks according to API Std 653 (except section 6.4.3, Alternative Internal Inspection Interval) (incorporated by reference, see 6#

320165006_NOPV PCP PCO_07252016_text.pdf, page 7§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. CVR did not complete the recommended repairs as indicated in the API 653 inspection, nor was there any summary of why those repairs were not implemented. During the field review of the breakout tanks, it was noted that some of the recommended repairs to the tanks had not been completed. For example: a) b) c) d) There were no tell-tale holes in the re-enforcement pads on the tanks at Broome and Hooser. Additionally, tell-tale holes were found plugged at Coffeyville Station. These must be open to the atmosphere per API 650. Soil was up against the tank shell at Broome station. It was also noticed that the mounds of soil at Coffeyville were washing away and building up against the tanks. In Coffeyville, there was no electrical ground cable between the stairs and the floating roof. The wheels that roll on the roof are not sufficient for the ground. No sealant was found around the rivets at Broome station. API 653 Section 6.9.3 states that “The owner/operator shall ensure that the disposition of all recommended repairs and monitoring is documented in writing and that reasons are given if recommended actions are delayed or deemed unnecessary.” At the time of the PHMSA inspection, there was no summary of why the repairs were delayed or deemed unnecessary. 11. §195.432 Inspection of in-service breakout tanks. (d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator's last recorded date of the inspection, whichever is earlier. Where paragraph (b) states: 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. CVR personnel did not inspect their above-ground breakout tanks according to API 653, in 7#

320165006_NOPV PCP PCO_07252016_text.pdf, page 8that they did not conduct the initial 10 year out-of-service tank inspections by 2009. CVR acquired the breakout tanks in 2004. CVR did not have any records of previous inspections so the inspection intervals began on May 3, 1999. API 653 states that the initial inspection interval must not exceed 10 years. Because CVR did not have any data from the previous operator, the interval for inspection must start at 10 years. This required all the tanks to be inspected by May 3, 2009. The following are the tanks PHMSA identified that missed the 2009 out-of-service inspection date: Tanks Last API 653 Out of Service Inspection Valley Center Tank 290 July 21, 2014 Hooser Tank 270 July 14, 2014 Hooser Tank 230 September 2015 Hooser Tank 225 Unknown Hooser Tank 200 Unknown Valley Center Tank 285 January 26, 2015 Broome Tank 1106 February 8, 2013 Coffeyville Tank 22A2 June 11, 2012 Plainville Tank 20 May 8, 2014 12. §195.452 Pipeline integrity management in high consequence areas. (h) What actions must an operator take to address integrity issues? (1) General requirements. An operator must take prompt action to address all anomalous conditions the operator discovers through the integrity assessment or information analysis. In addressing all conditions, an operator must evaluate all anomalous conditions and remediate those that could reduce a pipeline's integrity. An operator must be able to demonstrate that the remediation of the condition will ensure the condition is unlikely to pose a threat to the long-term integrity of the pipeline. An operator must comply with § 195.422 when making a repair. (i) Temporary pressure reduction. An operator must notify PHMSA, in accordance with paragraph (m) of this section, if the operator cannot meet the schedule for evaluation and remediation required under paragraph (h)(3) of this section and cannot provide safety through a temporary reduction in operating pressure. CVR personnel did not notify PHMSA that CVR could not meet the schedule for evaluation and remediation required under 195.452(h)(3). Review of the ILI repair records and final reports found that CVR took anywhere from one to five days to repair an immediate repair condition with no pressure reduction. The #1-8 line was operating at 272 psig and the #3-8 Line was operating at 98 psig. The repairs that did not get reported to PHMSA are as follows: 8#

320165006_NOPV PCP PCO_07252016_text.pdf, page 9#1-8” Line: Dig # Final Report Date Repair Date 137971.28 October 18, 2014 November 19, 2014 137975.02 October 18, 2014 November 19, 2014 137976.57 October 18, 2014 November 19, 2014 #3-8” Line Dig# Final Report Date Repair Date 95573 October 18, 2014 October 23, 2014 13. §195.452 Pipeline integrity management in high consequence areas. (h) What actions must an operator take to address integrity issues? (4) Special requirements for scheduling remediation (i) Immediate repair conditions. An operator's evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formula in Section 451.6.2.2 (b) of ANSI/ ASME B31.4 (incorporated by reference, see § 195.3). An operator must treat the following conditions as immediate repair conditions: (C) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) that has any indication of metal loss, cracking or a stress riser. CVR did not take any pressure reduction from the operating pressure on the Valley 6” #2 and #3 line segments once they were notified of top side dents with metal loss (immediate repair conditions). Records provided to PHMSA indicated that the lines were operating at approximately 500 psig in 2014. CVR’s supervisors on the job indicated to PHMSA at the time of the inspection that no pressure reduction was taken. The following immediate repairs should have had a pressure reduction done once CVR was notified of the immediate conditions: Valley 6” #2 Dig # Final Report Date Repair Date 10769.67 June 23, 2014 July 16, 2014 9513.54 June 23, 2014 August 6, 2014 24364.91 June 23, 2014 August 27, 2014 37672.2 June 23, 2014 July 15, 2014 9#

320165006_NOPV PCP PCO_07252016_text.pdf, page 10Valley 6” #3 Dig# Final Report Date Repair Date 46468.67 June 30, 2014 July 16, 2014 This probable violation is a repeat violation as identified in CPF 3-2012-5010, Item 3. 14. §195.452 Pipeline integrity management in high consequence areas. (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. CVR did not take measures to prevent and mitigate consequences of a pipeline failure that could affect a high consequence area per their Integrity Management Plan (IMP). CVR could not provide any documentation showing that CVR had taken preventive and mitigative (P&M) actions per their IMP. The IMP plan, implemented on February 21, 2013, references appendices for P&M measures and P&M evaluation forms. However, the P&M measures did not appear to be documented in that the appendices were never developed and, the evaluation forms were not filled out. 15. §195.505 Qualification program. Each operator shall have and follow a written qualification program. The program shall include provisions to: (b) Ensure through evaluation that individuals performing covered tasks are qualified; 10#

320165006_NOPV PCP PCO_07252016_text.pdf, page 11CVR did not follow its written qualification program to ensure through evaluation that individuals performing covered tasks are qualified. While reviewing the mainline valve inspection records, PHMSA asked for the Operator Qualification records of the three employees conducting the valve inspection. CVR was unable to provide any records that showed that the employees were qualified to inspect and operate mainline valves for the years 2013-2015. 16. §195.571 What criteria must I use to determine the adequacy of cathodic protection? Cathodic protection required by this Subpart must comply with one or more of the applicable criteria and other considerations for cathodic protection contained in paragraphs 6.2 and 6.3 of NACE SP 0169 (incorporated by reference, see § 195.3). CVR did not properly apply the consideration of voltage (IR) drop to a test point located on the Hooser 8” line as required by paragraph 6.3 of NACE SP0169. Review of the cathodic protection records found what initially appeared to be consecutive low readings at the test station located at West Fuller property line on the Hooser 8”. The readings found for that location were as follows: Year Reading 2010 -0.600v 2011 -0.690v 2012 -0.640v 2013 -0.800v 2014 -0.650v 2015 -0.570v The records also identified a “native” potential of the pipe to be -0.200v. There was no documentation within the records that showed that CVR did an instant-off potential to verify that the low readings would meet the 100mv drop criterion. If CVR is going to utilize the 100 mv criterion to verify adequate cathodic protection, the instant-off reading or some other form of IR drop consideration must be performed and documented. 17. §195.573 What must I do to monitor external corrosion control? (a) Protected pipelines. You must do the following to determine whether cathodic protection required by this subpart complies with §195.571: (1) Conduct tests on the protected pipeline at least once each calendar year, but with intervals not exceeding 15 months. However, if tests at those intervals are 11#

320165006_NOPV PCP PCO_07252016_text.pdf, page 12impractical for separately protected short sections of bare or ineffectively coated pipelines, testing may be done at least once every 3 calendar years, but with intervals not exceeding 39 months. CVR did not conduct annual testing of its cathodic protection on multiple facilities in the CVR system between and 2013 and 2015. Review of CVR’s annual cathodic protection readings identified the following facilities that missed the annual cathodic protection monitoring: Facility Years Missed Broome Station and Tank readings 2013, 2014 Coffeyville Station and Tank readings 2013, 2014 Valley Station tank readings 2013 Hooser Station 2013 Broome to Coffeyville 16” 2013, 2015 Broome to Coffeyville 12” 2013, 2014, 2015 Coffeyville Station to Refinery – 12” & 16” 2013, 2014 Shidler 4” Discharge Line 2013 Humboldt Line 2013, 2014 Hooser Station to Highway 99 2013 18. §195.583 What must I do to monitor atmospheric corrosion control? (a) You must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows: If the pipeline is located: Onshore Offshore Then the frequency of inspection is: At least once every 3 calendar years, but with intervals not exceeding 39 months At least once each calendar year, but with intervals not exceeding 15 months CVR did not conduct atmospheric corrosion inspections of its onshore pump stations at least once every three years. In response to a request for atmospheric inspection records from 2009-2015, CVR submitted records showing ultrasonic (UT) inspections of the wall thickness of the above- ground facilities in Coffeyville station for 2012 and 2013 as well as Hooser Station in 2013. However, there were no records indicating that atmospheric inspections were being done at the time of this UT evaluation. Additionally, no other records were submitted for Broome, Shidler, Coffeyville, Valley, Valley Booster #1 and #2, and Hooser stations. 12#

320165006_NOPV PCP PCO_07252016_text.pdf, page 13Proposed Civil Penalty Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $200,000 per violation per day the violation persists up to a maximum of $2,000,000 for a related series of violations. For violations occurring prior to January 4, 2012, the maximum penalty may not exceed $100,000 per violation per day, with a maximum penalty not to exceed $1,000,000 for a related series of violations. The Compliance Officer has reviewed the circumstances and supporting documentation involved in the above probable violation(s) and has recommended that you be preliminarily assessed a civil penalty of $497,600 as follows: Item number PENALTY 4 $23,300 5 8 $25,900 $33,100 9 $54,700 11 13 $54,700 $79,200 15 $79,200 17 $95,000 18 $52,500 Warning Items With respect to items) 1, 2, 3, 7, 10, 12, and 16, 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. Proposed Compliance Order With respect to items) 6, 14, 18, and pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Coffeyville Resources Crude Transportation, 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 13#

320165006_NOPV PCP PCO_07252016_text.pdf, page 14authorizes 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 3-2016-5006 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, Allan C. Beshore Director, Central Region, OPS Pipeline and Hazardous Materials Safety Administration Enclosures: Proposed Compliance Order Response Options for Pipeline Operators in Compliance Proceedings 14#

320165006_NOPV PCP PCO_07252016_text.pdf, page 15PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Coffeyville Resources Crude Transportation, LLC a Compliance Order incorporating the following remedial requirements to ensure the compliance of Coffeyville Resources Crude Transportation, LLC (CVR) with the pipeline safety regulations: 1. 2. 3. 4. 5. In regard to Item Number six of the Notice pertaining to line markers on the Coffeyville 16” and 12” and the exposures on the #1-8” and #3-8”, CVR must survey the 16” and 12” from Broome Station to Coffeyville Station and the line(s) to the Refinery and replace and/or update the line markers with the correct phone 24 hour number. In regards to the #1-8” and #3-8”, CVR must identify all exposures on those lines and replace any line markers from the previous operator with their own line markers. In regard to Item Number 14 of the Notice pertaining to failing to implement the Preventive and Mitigative (P&M) measures as defined in the Integrity Management Plan (IMP) and developing the appendices for the P&M Measures, CVR must develop the appendices for Section five of the IMP and begin following the procedures for P&M measures as defined by the IMP plan. In regard to Item Number 18 of the Notice pertaining to atmospheric corrosion inspections, CVR must develop and implement a schedule and to atmospherically inspect the stations and all other above-ground piping. In regard to item number one above, CVR must complete the survey and replacement of the line markers within 30 days of the date of receipt of the Final Order. In regards to Item number two above, CVR must complete the development of the appendices for the P&M measures within 45 days of the date of the Final Order. CVR must also implement the P&M measures procedures upon completion of the development of the measures. Additionally, for a period of one year from the date of the Final Order, CVR will submit quarterly status reports outlining the P&M measures taken to the Director, PHMSA Central Region. In regards to item number three above, CVR will submit a schedule to atmospherically inspect the stations and any other above-ground piping within 30 days of the receipt of the Final Order. The atmospheric inspections of all above ground piping must be completed within one year of the date of the Final Order. It is requested (not mandated) that Coffeyville Resources Crude Transportation, LLC maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to Allan C. Beshore, Director, Central Region, Pipeline and Hazardous Materials Safety Administration. It is requested that these costs be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses, and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. 15#