FRONT RANGE PIPELINE, LLC. — Warning Letter

520175002W_Warning letter_03272017_text.pdf, page 1Official PDFWARNING LETTER CERTIFIED MAIL - RETURN RECEIPT REQUESTED March 27, 2017 Mr. Richard Petersen President Front Range Pipeline, LLC 803 Highway 212 South Laurel, MT 59044 CPF 5-2017-5002W Dear Mr. Petersen: On August 8 through 12, and September 6 through 9, 2016, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), pursuant to Chapter 601 of 49 United States Code, inspected your Front Range Pipeline in Laurel, Montana. As a result of the inspection, it is alleged that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violations are:#

520175002W_Warning letter_03272017_text.pdf, page 21. §195.452 Pipeline integrity management in high consequence areas. (l) What records must an operator keep to demonstrate compliance? (1) An operator must maintain, for the useful life of the pipeline, records that demonstrate compliance with the requirements of this subpart. At a minimum, an operator must maintain the following records for review during an inspection: (ii) Documents to support the decisions and analyses, including any modifications, justifications, deviations and determinations made, variances, and actions taken, to implement and evaluate each element of the integrity management program listed in paragraph (f) of this section. Front Range Pipeline, LLC (FRP) failed to provide documentation from the 2014 in-line inspection (ILI) assessments for the 16” ML Santa Rita to Raynesford, and 16” ML Raynesford to Laurel pipeline segments. 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 Std 653. FRP failed to inspect the physical integrity of in-service aboveground breakout tanks according to the time intervals referenced in API Std 653. At the time of the inspection, it was noted that FRP exceeded the five-year in-service inspections for the breakout tanks located at the Laurel Refinery. Tank #95 in-service inspections occurred on October 10, 2008, and August 19, 2016. Tank #100 in-service inspections occurred on October 11, 2008, and September 15, 2015. 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. FRP failed to provide records to demonstrate that the high-low level test/inspection of the overfill protection devices for Tanks 95 and 100 at the Laurel Refinery were performed. 4. §195.452 Pipeline integrity management in high consequence areas. (j) What is a continual process of evaluation and assessment to maintain a pipeline’s integrity? (3) Assessment intervals. An operator must establish five-year intervals, not to exceed 68 months, for continually assessing the pipe’s integrity. An operator must base the assessment intervals on the risk the pipe poses to the high consequence area to determine the priority for assessing the pipeline segments. An operator must establish the assessment intervals based on the factors specified in paragraph (e) of this section, the analysis of the results from the last 2#

520175002W_Warning letter_03272017_text.pdf, page 3integrity assessment, and the information analysis required by paragraph (g) of this section. FRP failed to perform their continual assessments within the five-year interval for the following segments: 10” Santa Rita to Cut Bank (7/8/2010, 9/26/2015), 10” ML Canadian Border to Santa Rita (7/12/2010, 9/24/2015), 10” Loop Line Canadian Border to Santa Rita (7/5/2010, 9/26/2015), 12” Canadian Border to 16” Launcher (6/30/2010, 7/23/2015), 16” Launcher to Santa Rita (6/30/2009, 7/15/2014), 16” ML Santa Rita to Raynesford (6/25/2009, 7/18/2014), and 16” ML Raynesford to Laurel (6/29/2009, 9/29/2014). 5. §195.420 Valve maintenance. (b) Each operator shall, at intervals not exceeding 7 ½ months, but at least twice each calendar year, inspect each mainline valve to determine that it is functioning properly. FRP failed to demonstrate that an inspection on Valve #FR55 was performed during the first part of 2016. 6. §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 7 ½ 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. FRP failed to demonstrate that the overpressure safety device inspections for the pipelines that are associated with Tanks 95 and 100 were performed for calendar years 2013 through 2016. 7. §195.412 Inspection of rights-of-way and crossing under navigable waters. (a) Each operator shall, at intervals not exceeding 3 weeks, but at least 26 times each calendar year, inspect the surface conditions on or adjacent to each pipeline right-of-way. Methods of inspection include walking, driving, flying or other appropriate means of transversing the right-of-way. Records available at the time of inspection indicated that the maximum three (3) week interval between right-of-way inspections allowed under §195.412(a) was exceeded between September 21, 2015 and October 13, 2015. 3#

520175002W_Warning letter_03272017_text.pdf, page 48. §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: Onshore – At least once every 3 calendar years, but with intervals not exceeding 39 months. Records were not provided to demonstrate that FRP performed atmospheric corrosion inspections for aboveground piping associated with breakout tanks 95 and 100, located at the Laurel Refinery. In addition, the 2014 atmospheric corrosion inspection records for Judith Gap Pump Station were not provided. The 2014 atmospheric corrosion inspection records for Santa Rita and Conrad Pump Stations were reviewed; however, the 2011 atmospheric corrosion inspection records for those pump stations were not provided. Therefore, the three (3) calendar years’ inspection, but with intervals not exceeding 39 months, could not be determined. The atmospheric corrosion inspection records for Cut Bank Pump Station were missing for the last two (2) intervals. Records in the file appear to be a copy from 2005 but the date was crossed out to indicate the inspection year of 2014. In addition, the atmospheric corrosion inspection records for Buffalo Creek were provided but the records were missing the date that the inspections were performed and the personnel who did the inspection. 9. §195.573 What must I do to monitor external corrosion control? (e) Corrective Action. You must correct any identified deficiency in corrosion control as required by §195.401(b). However, if the deficiency involves a pipeline in an integrity management program under §195.452, you must correct the deficiency as required by §195.452(h). Records were not provided to demonstrate that FRP took adequate actions to correct the identified 2014 deficiencies associated with Tanks 10 and 16 at the Santa Rita Terminal. The tanks were not meeting the -0.850V or the 100mv shift criteria. FRP changed to a four-point test station in 2014 for collecting pipe-to-soil potential readings on Tank 10 and Tank 16. The “off” pipe-to-soil potential readings from 2015 did not meet the -0.850V criteria and the 100mv shift was not checked and/or documented. 10. §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 every 3 calendar years, but with intervals not exceeding 39 months. 4#

520175002W_Warning letter_03272017_text.pdf, page 5Records were not provided to demonstrate that FRP conducted the 2013, 2014, and 2016 annual pipe-to-soil potential readings of the Ominex 4” crossing (TS# 82730) on the 10” from Canadian Border to Santa Rita segment, June 2014 pipe-to-soil potential readings of the 6” receiver in the Santa Rita Station, 2015 annual pipe-to-soil potential readings of the 16" line segment from Santa Rita to Laurel, and 2016 pipe-to-soil potential readings of the lines within the Santa Rita Station. Regarding the 8" inactive line from Laurel to Billings, FRP continues to maintain DOT compliance. However, there was a missing record for Test Station #60 for calendar years 2013, 2014, 2015, and 2016. Comments from cathodic protection (CP) records for this test station indicated that they didn't have access during the annual pipe-to-soil potential readings. 11. §195.579 what must I do to mitigate internal corrosion? (b) Inhibitors. If you use corrosion inhibitors to mitigate internal corrosion, you must- (3) Examine the coupons or other monitoring equipment at least twice each calendar year, but with intervals not exceeding 7 ½ months. Records were not provided to demonstrate that FRP examined the coupons or other monitoring equipment for the second part of 2015 or 2016 at Santa Rita, Cut Bank, Great Falls, and Laurel Stations. 12. §195.589 What corrosion control information do I have to maintain? (c) You must maintain a record of each analysis, check, demonstration, examination, inspection, investigation, review, survey, and test required by this subpart in sufficient detail to demonstrate the adequacy of corrosion control measures or that corrosion requiring control measures does not exist. You must retain these records for at least 5 years, except that records related to §§195.569, 195.573(a) and (b), and 195.579(b)(3) and (c) must be retained for as long as the pipeline remains in service. Records were not provided to demonstrate that the annual pipe-to-soil potential readings for the piping at the Laurel Refinery were taken for the years 2013, 2014, 2015, and 2016. Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $205,638 per violation per day the violation persists up to a maximum of $2,056,380 for a related series of violations. For violation occurring between January 4, 2012 to August 1, 2016, 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. 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. 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 5#

520175002W_Warning letter_03272017_text.pdf, page 6this time. We advise you to correct the item(s) identified in this letter. Failure to do so will result in Front Range Pipeline, LLC being subject to additional enforcement action. No reply to this letter is required. If you choose to reply, in your correspondence please refer to CPF 5-2017-5002W. Be advised that all material you submit in response to this enforcement action is subject to being 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). Sincerely, Chris Hoidal Director, Western Region Pipeline and Hazardous Materials Safety Administration cc: PHP-60 Compliance Registry PHP-500 D. Fehling (#153728, #153727, and 153726) 6#