CENEX PIPELINE LLC — Notice of Probable Violation

party submissionOfficial PDF520125013_Operator_response_06192012.pdf#

520125013_closure letter_04182014_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED April 18, 2014 Mr. John Traeger President Cenex Pipeline, LLC P.O. Box 909 Laurel, Montana 59044-0909 CPF 5-2012-5013 Dear Mr. Traeger: On December 31, 2012, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to Cenex Pipeline, LLC a Final Order in the above-referenced case. This Order included a Compliance Order. Based on our review of the documentation you provided and an on-site pipeline safety inspection on April 14, 2014, 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, Chris Hoidal Director, Western Region Pipeline and Hazardous Materials Safety Administration cc: PHP-60 Compliance Registry PHP-500 M. Petronis#

520125013_NOPV PCP PCO_05182012_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED May 18, 2012 Mr. Daniel Knepper President and Chief Operating Officer Cenex Pipeline Company 803 Highway 212 South P.O. Box 909 Laurel, MT 59044-0909 CPF 5-2012-5013 Dear Mr. Knepper: Between August 16 and October 29, 2010, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected Cenex Pipeline Company (Cenex) pipeline operation and maintenance (O&M) procedures and records in Laurel, Montana. In addition, PHMSA’s representative conducted field inspections of numerous Cenex pipeline facilities in Montana and North Dakota. As a result of these inspections, it appears that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violations are:#

520125013_NOPV PCP PCO_05182012_text.pdf, page 21. § 195.214 Welding procedures. (b) Each welding procedure must be recorded in detail, including the results of the qualifying tests. This record must be retained and followed whenever the procedure is used. Cenex did not record in detail the results of the qualifying tests for their in-service welding procedure 110504-1. This procedure is used for welding metal repair sleeves to pipe. The qualifying test records for in-service weld procedure 110504-1 lacked sufficient detail. Specifically, the test records did not differentiate between tests done for the groove weld and tests done for the sleeve (fillet) weld. The record showed the force required for the rupture of two tensile test coupons but the record did not show those coupons’ sizes or the results for the maximum and minimum tensile stresses that resulted from these tests. API 1104 Table B-1 requires that the groove weld have two tensile tests, two nick-break tests, two root bend tests and two face bend tests. API 1104 Table B-1 also requires that the sleeve weld have 4 nick-break tests, 4 face bend tests, and 4 macro tests. The record showed results for two nick-break tests, two root bend tests, and two face bend tests but the record did not differentiate if these tests were on the groove weld or sleeve weld. There were no results for sleeve weld macro tests. In accordance with § 195.214, an operator is required to maintain detailed records of weld procedure qualification tests. 2. §195.401 General requirements. (b) An operator must make repairs on its pipeline system according to the following requirements: (1) Non Integrity management repairs. Whenever an operator discovers any condition that could adversely affect the safe operation of its pipeline system, it must correct the condition within a reasonable time. However, if the condition is of such a nature that it presents an immediate hazard to persons or property, the operator may not operate the affected part of the system until it has corrected the unsafe condition. Cenex failed to correct within a reasonable time a discovered condition that could adversely affect the safe operation of its Minot Tanks 201 and 202. Specifically, during the 2007 external inspections of these tanks, Cenex discovered that these tanks would only be suitable for service if safe fill height recommendations were adhered to. However, during the 2010 inspection, neither of the inspection reports contained what the safe fill height was for each tank. Without an established safe fill height, Cenex cannot operate these tanks safely. An operator is required to correct conditions affecting safe operation of its system in a reasonable time after they discover the condition. 3. § 195.404 Maps and Records. (a) Each operator shall maintain current maps and records of its pipeline systems that include at least the following information; (1) Location and identification of the following pipeline facilities; (vii) Safety devices to which §195.428 applies. 2#

520125013_NOPV PCP PCO_05182012_text.pdf, page 3Cenex did not maintain current maps and records for its North Dakota section of the Cenex pipeline. Reviews of Cenex’s Piping and Instrumentation Diagrams (P&ID) revealed that Cenex had not updated the P&IDs for the North Dakota section of the Cenex pipeline with current pressure safety valve tag numbers. The location of those safety devices cannot be easily established unless the safety valve tag numbers are shown on the P&IDs. An operator must maintain current maps and records with the location and identification of safety devices to which § 195.428 applies. 4. § 195.404 Maps and Records. (a) Each operator shall maintain current maps and records of its pipeline systems that include at least the following information; (1) Location and identification of the following pipeline facilities; (i) Breakout tanks; (ii) Pump stations; (iv) Pipeline valves; (v) Facilities to which §195.402(c)(9) applies; (vi) Rights-of-way; and (vii) Safety devices to which §195.428 applies. (2) All crossings of public roads, railroads, rivers, buried utilities, and foreign pipelines. (3) The maximum operating pressure of each pipeline. (4) The diameter, grade, type and nominal wall thickness of all pipe. At the time of our inspection, Cenex did not have current maps and records of its pipeline system. The maps and records did not include the location and identification of all the pipeline features and appurtenances required under §195.404(a). Interviews with Cenex personnel revealed that it had been 10 years since Cenex had last updated the alignment sheets for the Cenex pipeline. There has been significant urban development and oil field activity along much of the Cenex pipeline in the last 10 years. During this time, there has been several pipeline repairs and replacement projects as well as pump station modifications. An operator must maintain current maps and records of its systems, including but not limited to, current information such as new third party crossings, new breakout tanks, and other pipeline changes as noted under 195.404(a). 5. § 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; and Cenex did not maintain daily operating discharge pressures for the Billings Tank Farm booster pump station. Specifically, Cenex did not have a pressure recording device for discharge pressures at the Billings Tank Farm booster pump, therefore, discharge pressures from this pump station could not be recorded. The Billings Tank Farm pump station discharges product into a pipeline section that carries it to the suction side of the Billings pump station, approximately 2.5 miles downstream from the Billings Tank Farm pump station. This section of pipeline crosses 3#

520125013_NOPV PCP PCO_05182012_text.pdf, page 4the Yellowstone River and traverses property that is not under the control of Cenex. An operator must maintain at least three years of daily discharge pressures at each pump station and therefore must maintain a discharge pressure recording device that will allow the operator to record those daily discharge records. 6. § 195.432 Inspection of in-service breakout tanks. (b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according to API Standard 653 (incorporated by reference, see § 195.3). However, if structural conditions prevent access to the tank bottom, the bottom integrity may be assessed according to a plan included in the operations and maintenance manual under § 195.402(c)(3). Cenex failed to perform external tank inspections for eight (8) of their breakout tanks within the maximum 5 year interval, in accordance with API 653 Section 6.3.2.1, either after 1) the previous external tank inspection or 2) May 3, 1999, the effective date of § 195.432(b), whichever came later. Cenex records show that the following breakout tanks’ external inspection intervals were exceeded by the following time periods. Cenex Breakout Tank Identifier API 653 external inspection deadlines Actual API 653 external inspection completion date Time period that Cenex exceeded the interval for API 653 external inspections Billings Tank 283 May 2004 September 2008 51months Billings Tank 284 April 2006 October 2009 41months Minot Tank 202 May 2004 November 2007 41 months Minot Tank 203 June 2005 November 2007 28 months Minot Tank 204 June 2006 November 2007 16 months Minot Tank 207 May 2004 November 2007 41 months Minot Tank 209 May 2004 November 2007 41 months Minot Tank 210 June 2005 November 2007 28 months In accordance with § 195.432 and the referenced standard, API 653 6.3.2.1, an operator is required to perform external inspections of all breakout tanks at an interval that may not exceed 5 years. 7. § 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…. (4) Special requirements for scheduling remediation 4#

520125013_NOPV PCP PCO_05182012_text.pdf, page 5(ii) 60-day conditions. Except for conditions listed in paragraph (h)(4)(i) of this section, an operator must schedule evaluation and remediation of the following conditions within 60 days of discovery of condition. (A) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 3% of the pipeline diameter (greater than 0.250 inches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12). (B) A dent located on the bottom of the pipeline that has any indication of metal loss, cracking or a stress riser. (iii) 180-day conditions. Except for conditions listed in paragraph (h)(4)(i) or (ii) of this section, an operator must schedule evaluation and remediation of the following within 180 days of discovery of the condition: (A) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld. Cenex failed to evaluate all dent anomalies within HCAs. Specifically, Cenex did not account for the in-line inspection tool’s accuracy when determining which anomalies required further investigation. During inspection interviews, Cenex acknowledged that they did not add the in- line inspection tool vendor’s reported tool tolerance to identified dent depths. During two deformation tool runs conducted in 2008, several dents were repaired but 16 dents were discovered within HCAs that would have had indications deeper than .25 inches had the tool vendor’s advertised accuracies been added to these dent’s reported depths. Subsequently these dents were not reported to be greater than .25 inches so they were not properly evaluated. The ID#s for the dents found during the Glendive Station to Minot Station in-line inspection are 14000022, 14000048, 14000027, 14000034, 14000051, 14000012, 14000013, 14000023, 14000069, 14000019, 14000076, 14000068, 14000058, and 14000060. The ID#s for the dents found during the Laurel Station to Billings Station in-line inspection are 14000003 and 14000004. Cenex’s vendor’s published deformation tool accuracy had a declared confidence level of ± 1% of the nominal outside diameter (OD) of the pipe 80% of the time. Both of these pipeline sections had a nominal OD of 8.625 inches. 1% of 8.625 inches is ±.09 inches. Allowing for the vendor’s advertised accuracies makes it possible that a dent reported as greater than .16 inches could actually be deeper than .25 inches. Taking into account the deformation tool accuracy, any deformation that was recorded on the deformation tool log that was found greater than .16 inches should have been evaluated to determine if the criteria under §195.452(h)(4)(ii) or §195.452(h)(4)(iii) had been met. If found to meet that criteria, these deformations should have been investigated, precisely measured and repaired if required. The annotated deformation logs provided by Cenex for the Glendive to Minot run and for the Laurel to Billings Station runs shows that there were 16 deformation tool dent calls greater than .16 inches within an HCA which were not properly evaluated, investigated, or repaired. An operator is required to evaluate any dent greater than .25 inches on pipe that is less than Nominal Pipe Size (NPS) 12 when the dent is located on the top of the pipeline or when the dent affects pipe curvature at a girth weld or a longitudinal seam weld. If the dent meets any of those criteria, the operator must repair that dent. 5#

520125013_NOPV PCP PCO_05182012_text.pdf, page 68. § 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…. (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…. (B) A calculation of the remaining strength of the pipe shows a predicted burst pressure less than the established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (``Manual for Determining the Remaining Strength of Corroded Pipelines'' (1991) or AGA Pipeline Research Committee Project PR-3-805 (``A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe'' (December 1989)). These documents are incorporated by reference and are available at the addresses listed in Sec. 195.3…. (iii) 180-day conditions. Except for conditions listed in paragraph (h)(4)(i) or (ii) of this section, an operator must schedule evaluation and remediation of the following within 180 days of discovery of the condition: (D) A calculation of the remaining strength of the pipe shows an operating pressure that is less than the current established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (``Manual for Determining the Remaining Strength of Corroded Pipelines'' (1991)) or AGA Pipeline Research Committee Project PR-3-805 (``A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe'' (December 1989)). These documents are incorporated by reference and are available at the addresses listed in Sec. 195.3. (E) An area of general corrosion with a predicted metal loss greater than 50% of nominal wall. (F) Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline, or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld. Cenex failed to properly evaluate metal loss anomalies found within HCAs on their Cenex pipeline. Cenex did not account for the in-line inspection tool’s accuracy with respect to metal loss. During inspection interviews, Cenex acknowledged that they did not account for the in-line 6#

520125013_NOPV PCP PCO_05182012_text.pdf, page 7inspection tool’s accuracy when they evaluated which metal loss anomalies required further investigation. From Cenex’s 2008 metal loss in-line inspection and repair records 40 anomalies were reviewed by PHMSA. It was found that of those 40 anomalies 4 were found to have had depths 34% of the nominal wall greater than the reported depths. This indicates that10% of all anomalies will have a depth 34% of nominal wall greater than their reported depth. Therefore, it can be assumed that for every 10 anomalies reported as having metal loss equal or greater than 16% of nominal wall one will have a measured metal loss depth of 50% of nominal wall. An operator must evaluate those metal loss anomalies that are greater than 50% of the nominal wall, taking the in-line inspection tool’s accuracy into account, to determine if these anomalies are at a crossing of another pipeline, or in an area with widespread circumferential corrosion, or in an area that could affect a girth weld. Additionally, an operator must evaluate anomalies using the in-line inspection tool’s accuracy to determine if they have sufficient remaining strength at the anomalies. If an operator finds that the metal loss anomaly meets any of these criteria then the anomaly must be repaired. 9. § 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; Cenex did not evaluate employees to determine they could recognize and react to task specific abnormal operating conditions when employees were re-qualified. Pursuant to § 195.505, an operator’s qualification program must include provisions to ensure that individuals performing covered tasks are qualified. ‘Qualified’ is defined in § 195.503 as “an individual [that] has been evaluated and can perform assigned covered tasks and recognize and react to abnormal operating conditions.” Cenex records show that employees were only evaluated for their ability to recognize and react to task specific AOCs when they were initially qualified. When employees were re-qualified they were not re-evaluated for their ability to recognize and react to task specific AOCs. An operator must ensure that employees are able to recognize and react to task specific AOCs when they are re-qualified. 10. § 195.573 What must I do to monitor external corrosion control? (c) Rectifiers and other devices. You must electrically check for proper performance each device in the first column at the frequency stated in the second column. Device Check frequency Rectifier................................. Reverse current switch Diode Interference bond whose failure would jeopardize structural protection At least six times each calendar year, but with intervals not exceeding 2 ½ months Other interference bond....................... At least once each calendar year, but with intervals not exceeding 15 months. 7#

520125013_NOPV PCP PCO_05182012_text.pdf, page 8Cenex failed to electrically check polarization cell replacements (PCRs) at least six times each calendar year with intervals not exceeding 2 ½ months. Specifically Cenex failed to electrically check polarization cell replacements recently installed where the Cenex pipeline parallels a wind farm electrical power transmission line between Fargo and Minot, North Dakota 6 times per year at intervals not to exceed 2 ½ months. Cenex informed PHMSA that they have only monitored these PCRs annually. These types of devices are considered to be a form of diode or reverse current switch in that they allow AC current to pass through them back to the source ground but they do not allow protective CP current to pass to ground thus minimizing AC interference currents that could jeopardize structural protection. An operator is required to electrically inspect devices like reverse current switches, diodes, and interference bonds whose failure could jeopardize structural protection at least six times each calendar year with intervals not exceeding 2 ½ months. 11. § 195.575 Which facilities must I electrically isolate and what inspections, tests, and safeguards are required? (e) If a pipeline is in close proximity to electrical transmission tower footings, ground cables, or counterpoise, or in other areas where it is reasonable to foresee fault currents or an unusual risk of lightning, you must protect the pipeline against damage from fault currents or lightning and take protective measures at insulating devices. Cenex failed to protect their pipeline against damage from fault currents or lighting. Interviews with Cenex personnel during the inspection of the Laurel to Billings section of the Cenex pipeline revealed that there was no fault current protection installed where the Cenex Products pipeline is in close proximity to a fence around an electrical substation that was located downstream from the Laurel Refinery. An operator must install ground fault protection where it is reasonable to foresee fault currents or unusual risk of lightning. 12. § 195.581 Which pipelines must I protect against atmospheric corrosion and what coating material may I use? (a) You must clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, except pipelines under paragraph (c) of this section… (c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, you need not protect against atmospheric corrosion any pipeline for which you demonstrate by test, investigation, or experience appropriate to the environment of the pipeline that corrosion will- (1) Only be a light surface oxide; or (2) Not affect the safe operation of the pipeline before the next scheduled inspection. Cenex failed to provide protection against atmospheric corrosion for a soil-to-air interface. Records show that on June 21, 2005 Cenex found that the soil-to-air interface at the Minot station mainline piping spool, identified as piping item FRS-1000, needed protective coating. On June 21, 2008, Cenex records show that this same soil-to-air interface still needed protective coating. Additionally Cenex could not provide evidence that this soil-to-air interface had been coated at the time of this 2010 inspection, thus establishing that Cenex failed to provide protection against atmospheric corrosion at its FRS-1000 mainline pipeline spool soil-to-air 8#

520125013_NOPV PCP PCO_05182012_text.pdf, page 9interface for at least 5 years. An operator is required to provide protection from atmospheric corrosion at all pipeline soil-to-air interfaces. 13. § 195.583 What must I do to monitor atmospheric corrosion control? (b) During inspections you must give particular attention to pipe at soil-to-air interfaces, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water. Cenex failed to monitor atmospheric corrosion at several above ground pipe supports located at the Billings station, Rosebud station, Glendive station, MP 98, MP 193B (Powder River DS block valve), MP 211B (Yellowstone River DS block valve), and MP 222. These pipe supports are either made from concrete or they are the type that cannot be easily lowered to ensure adequate monitoring of atmospheric corrosion between the pipe and the support can be accomplished. The areas in the vicinity of the supports had rust on the pipe at the interface between the pipe and the pipe supports that may indicate on-going atmospheric corrosion. An operator must monitor atmospheric corrosion between above ground pipe and its pipe supports. Proposed Civil Penalty Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $100,000 for each violation for each day the violation persists up to a maximum of $1,000,000 for any related series of violations. The Compliance Officer has reviewed the circumstances and supporting documentation involved in the above probable violations and has recommended that you be preliminarily assessed a civil penalty of $76,500 as follows: Item number PENALTY 6 $41,500 12 $35,000 Proposed Compliance Order With respect to item(s) 1, 2, 3, 4, 5, 7, 8, 9, 10, 11, 12 and 13 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Cenex. 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. 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 9#

520125013_NOPV PCP PCO_05182012_text.pdf, page 10qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order. In your correspondence on this matter, please refer to CPF 5-2012-5013 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, Chris Hoidal Director, Western Region Pipeline and Hazardous Materials Safety Administration Enclosures: Proposed Compliance Order Response Options for Pipeline Operators in Compliance Proceedings cc: PHP-60 Compliance Registry PHP-500 G. Davis (#129363, 129364, 129365) 10#

520125013_NOPV PCP PCO_05182012_text.pdf, page 11PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Cenex Pipeline Company a Compliance Order incorporating the following remedial requirements to ensure the compliance of Cenex Pipeline Company with the pipeline safety regulations: 1. In regard to Item Number 1 of the Notice pertaining to Cenex’s failure to maintain a detailed record of the qualification report for weld procedure 110504-1, ensure the weld qualification report for weld procedure 110504-1 includes; 1) the groove qualifying test results including the weld tensile strength coupon sizes and the breaking stress that each tensile strength coupon experienced during testing, nick- break test results, root bend test results, and face bend test results; and 2) the sleeve weld qualifying test results including the nick-break test results, the face bend test results, and the macro test results. Cenex must submit the corrected record of the weld qualification report for weld procedure 110504-1 to Chris Hoidal, Director, Western Region. 2. In regard to Item Number 2 of the Notice pertaining to Cenex’s failure to determine the safe fill height for Minot Tanks 201 and 202, Cenex must ensure that it has determined the safe fill height for these two tanks and Cenex must take actions to prevent operation of these tanks above the safe fill height. Cenex must provide those safe fill heights and documentation confirming actions taken to prevent operation above those safe fill heights to Chris Hoidal, Director, Western Region. 3. In regard to Item Number 3 of the Notice pertaining to Cenex’s failure to maintain current Piping and Instrumentation Diagrams (P&IDs) of the North Dakota section of the Cenex Products pipeline, Cenex must ensure that its P&IDs for the North Dakota section of the Cenex Products pipeline includes both the pressure safety valve tag numbers and the pressure set points associated with those devices. Cenex must provide those updated P&IDs to Chris Hoidal, Director, Western Region. 4. In regard to Item Number 4 of the Notice pertaining to Cenex’s failure to maintain current alignment sheets of its Cenex Products pipeline, Cenex must update their Cenex Products pipeline alignment sheets to ensure that they show current pipeline information including but not limited to all crossings of public roads, railroads, rivers, buried utilities, foreign pipeline crossings and other pipeline changes as required under 195.404(a). Cenex must provide these updated alignment sheets to Chris Hoidal, Director, Western Region. 5. In regard to Item Number 5 of the Notice pertaining to Cenex’s failure to maintain daily discharge pressures of its Billings Tank Farm pump station, Cenex must provide a pressure recording device at its Billings Tank Farm pump station that 11#

520125013_NOPV PCP PCO_05182012_text.pdf, page 12will allow them to record the daily discharge pressures of the Billings Tank Farm pump station and they must ensure that they continuously retain at least 3 years of those records. Cenex must provide evidence of the installation of the above pressure recording device and documentation that ensures Cenex will retain pressure discharge records for this site for at least three years to Chris Hoidal, Director, Western Region. 6. In regard to Item Number 7 of the Notice pertaining to Cenex’s failure to evaluate deformation anomalies discovered during the Cenex pipeline 2008 integrity assessment by taking the in-line inspection tool’s accuracies into account, Cenex must evaluate the following dent ID#s found during the Glendive Station to Minot Station in-line inspection: 14000022, 14000048, 14000027, 14000034, 14000051, 14000012, 14000013, 14000023, 14000069, 14000019, 14000076, 14000068, 14000058, and 14000060 and they must evaluate the following dent ID#s found during the Laurel Station to Billings Station in-line inspection: 14000003, 14000004. If any of these dents are found to be located on the top of the pipeline or found to affect pipe curvature at a girth weld or a longitudinal seam weld Cenex must then repair those dents. Cenex must submit records of the above evaluations and investigations and any subsequent repairs to Chris Hoidal, Director, Western Region. 7. In regard to Item Number 8 of the Notice pertaining to failure to evaluate some metal loss anomalies that could reduce their pipeline’s integrity, Cenex must re- review its ILI metal loss logs taking known data from the 2008 MFL ILI run and adding the in-line tool accuracy determined by previous 2008 anomaly investigations. Cenex must then investigate any anomalies that have a potential to meet the repair criteria under §195.452(h) and if anomalies are found to meet that criteria Cenex must make appropriate repairs to their pipeline. Cenex must submit records of the above evaluations and investigations and any subsequent repairs to Chris Hoidal, Director, Western Region. 8. In regard to Item Number 9 of the Notice pertaining to Cenex’s failure to evaluate employees ability to recognize and react to task specific abnormal operating conditions when employees are re-qualified, Cenex must ensure that all employees are evaluated for their ability to recognize and react to task specific abnormal operating conditions when they have and are being re-qualified. Cenex must provide documentation showing that re-qualified employees have been re- evaluated to recognize and react to task specific abnormal operating conditions to Chris Hoidal, Director, Western Region. 9. In regard to Item Number 10 of the Notice pertaining to Cenex’s failure to electrically inspect polarization cell replacements (PCRs) six times each calendar year with intervals not exceeding 2 ½ months, Cenex must ensure that they electrically inspect each of their PCRs recently installed where the Cenex pipeline parallels a wind farm electrical power transmission line between Fargo and Minot, 12#

520125013_NOPV PCP PCO_05182012_text.pdf, page 13North Dakota six times each calendar year at intervals not exceeding 2 ½ months. Cenex must provide documentation insuring that these PCRs are electrically inspected six times each calendar year at intervals not exceeding 6 months to Chris Hoidal, Director, Western Region. 10. In regard to Item Number 11 of the Notice pertaining to Cenex’s failure to install ground fault protection at the electrical substation downstream from the Laurel Refinery, Cenex must install ground fault protection at the electrical substation downstream from the Laurel Refinery between MP 0.5 and 0.8. Cenex must provide evidence that ground fault protection has been provided at this location to Chris Hoidal, Director, Western Region. 12. In regard to Item Number 12 of the Notice pertaining to inadequate coating of the soil-to-air interface on the Minot station mainline spool, Cenex must provide coating to the soil-to-air interface on the Minot station mainline spool which is identified in Cenex atmospheric inspection records as piping item FRS-1000. Cenex must provide evidence when the coating of this location has been completed to verify that Cenex has complied with this compliance order item. 13. In regard to Item Number 13 of the Notice pertaining to Cenex’s failure to inspect for atmospheric corrosion under above ground pipe supports, Cenex must inspect between the above ground pipe and its associated supports at Billings station, Rosebud station, Glendive station, MP 98, MP 193B Powder River DS block valve, MP 211B Yellowstone River DS block valve, and MP 222. Cenex must take actions to ensure that future inspections will allow inspection for atmospheric corrosion between above ground pipe and their associated supports at Billings station, Rosebud station, Glendive station, MP 98, MP 193B Powder River DS block valve, MP 211B Yellowstone River DS block valve, and MP 222. Cenex must repair any corrosion that is found during the required atmospheric corrosion inspections at these above ground pipe support locations. Cenex must provide evidence that measures have been taken to allow for future atmospheric corrosion inspections between above ground pipe and associated supports at the above locations and must provide documentation of atmospheric corrosion inspections and associated repairs at the above locations to Chris Hoidal, Director, Western Region. 14. Cenex must complete the above compliance order items within 60 days after receipt of the Final Order. 15. It is requested (not mandated) that Cenex maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to Chris Hoidal, Director, Western 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. 13#

520125013_Final Order_12312012_text.pdf, page 1Official PDFDECEMBER 31, 2012 Mr. John Traeger President Cenex Pipeline, LLC 803 Highway 212 South P.O. Box 909 Laurel, MT 59044-0909 Re: CPF No. 5-2012-5013 Dear Mr. Traeger: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation, assesses a reduced civil penalty of $41,500, and specifies actions that need to be taken by Cenex Pipeline, LLC, to comply with the pipeline safety regulations. The penalty payment terms are set forth in the Final Order. When the civil penalty has been paid and the terms of the Compliance Order completed, as determined by the Director, Western 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, Jeffrey D. Wiese Associate Administrator for Pipeline Safety Enclosure cc: Mr. Chris Hoidal, Director, Western Region, OPS Mr. Alan Mayberry, Deputy Associate Administrator for Field Operations, OPS CERTIFIED MAIL - RETURN RECEIPT REQUESTED#

520125013_Final Order_12312012_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 ) ) Cenex Pipeline, LLC, ) CPF No. 5-2012-5013 ) Respondent. ) ____________________________________) FINAL ORDER Between August 16 and October 29, 2010, pursuant to 49 U.S.C. § 60117, representatives 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 Cenex Pipeline, LLC (Cenex or Respondent), in Montana and North Dakota. Cenex operates approximately 1200 miles of hazardous liquid pipelines and associated terminals in the U.S.1 The Cenex Products pipeline system that was inspected by PHMSA extends approximately 671 miles from the CHS refinery in Laurel, Montana, to storage facilities in Billings and Glendive, Montana, and ends in Fargo, North Dakota.2 As a result of the inspection, the Director, Western Region, OPS (Director), issued to Respondent, by letter dated May 18, 2012, 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 Cenex had committed various violations of 49 C.F.R. Part 195 and proposed assessing a civil penalty of $76,500 for two of the alleged violations. The Notice also proposed ordering Respondent to take certain measures to correct the alleged violations. Cenex responded to the Notice by letter dated June 19, 2012 (Response). The company contested three of the allegations of violation, provided an explanation of its actions, and requested that the proposed civil penalty be reduced. Respondent did not request a hearing and therefore has waived its right to one. 1 https://www.cenex.com/portal/server.pt/community/1fuels/318 (last accessed December 13, 2012). 2 Pipeline Safety Violation Report (Violation Report), (April 18, 2012) (on file with PHMSA), at 1.#

520125013_Final Order_12312012_text.pdf, page 32 FINDINGS OF VIOLATION Uncontested Items In its Response, at the hearing, Cenex did not contest the allegations in the Notice that it violated 49 C.F.R. Part 195, as follows: Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.214(b), which states: § 195.214 Welding procedures. (a) … (b) Each welding procedure must be recorded in detail, including the results of the qualifying tests. This record must be retained and followed whenever the procedure is used. The Notice alleged that Respondent violated 49 C.F.R. § 195.214(b) by failing to record in detail the results of the qualifying tests for its in-service welding procedure 110504-1. Specifically, the Notice alleged that Cenex did not record the qualifying tests in a manner that differentiated between the tests done for the groove weld and tests done for the sleeve (fillet) weld in accordance with API 1104 Table B-1. Respondent did not contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.214(b) by failing to record in detail the results of the qualifying tests for its in-service welding procedure 110504-1. Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.404(a)(1)(vii), which states in relevant part: § 195.404 Maps and records. (a) Each operator shall maintain current maps and records of its pipeline systems that include at least the following information: (1) Location and identification of the following pipeline facilities: (i) … (vii) Safety devices to which § 195.428 applies. The Notice alleged that Respondent violated 49 C.F.R. § 195.404(a)(1)(vii) by failing to maintain maps and records that included current information on certain safety devices to which § 195.428 applies.3 Specifically, the Notice alleged that Cenex did not include the pressure safety valve tag numbers in its Piping and Instrument Diagrams (P&IDs) for the North Dakota section of its pipeline. 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(a)(1)(vii) by failing to maintain maps and records that included current information on certain safety devices to which § 195.428 applies. 3 Section 195.428 requires the inspection and testing of overpressure safety devices and overfill protection systems.#

520125013_Final Order_12312012_text.pdf, page 43 Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.404(a), which states: § 195.404 Maps and records. (a) Each operator shall maintain current maps and records of its pipeline systems that include at least the following information: (1) Location and identification of the following pipeline facilities: (i) Breakout tanks; (ii) Pump stations; (iii) Scraper and sphere facilities; (iv) Pipeline valves; (v) Facilities to which § 195.402(c)(9) applies; (vi) Rights-of-way; and (vii) Safety devices to which § 195.428 applies. (2) All crossings of public roads, railroads, rivers, buried utilities, and foreign pipelines. (3) The maximum operating pressure of each pipeline. (4) The diameter, grade, type, and nominal wall thickness of all pipe. The Notice alleged that Respondent violated 49 C.F.R. § 195.404(a) by failing to maintain current maps and records of its pipeline systems including current information showing the location and identification of certain pipeline features and appurtenances required under the regulation. Specifically, the Notice alleged that Cenex did not update the alignment sheets for the pipeline during the 10-year period preceding the inspection, despite significant urban development, oil field activity, pipeline repair and replacement projects, and pump station modifications that occurred during this time. 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(a) by failing to maintain current maps and records of its pipeline systems including current information showing the location and identification of certain pipeline features and appurtenances required under the regulation. Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.404(b)(1), which states in relevant part: § 195.404 Maps and records. (a) … (b) Each operator shall maintain for at least 3 years daily operating records that indicate— (1) The discharge pressure at each pump station; . . . . The Notice alleged that Respondent violated 49 C.F.R. § 195.404(b)(1) by failing to maintain daily operating records for at least three years that indicated the discharge pressure at one of its pump stations. Specifically, the Notice alleged that Cenex did not have a pressure-recording device for discharge pressures at the Billings Tank Farm pump station and therefore did not have three years of required records.#

520125013_Final Order_12312012_text.pdf, page 54 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(b)(1) by failing to maintain daily operating records for at least three years that indicated the discharge pressure at one of its pump stations. Item 6: 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 aboveground breakout tanks according to [American Petroleum Institute] API Standard 653 (incorporated by reference, see § 195.3). However, if structural conditions prevent access to the tank bottom, the bottom integrity may be assessed according to a plan included in the operations and maintenance manual under § 195.402(c)(3). The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) by failing to perform external tank inspections for eight of its breakout tanks within the maximum five-year interval, in accordance with Section 6.3.2.1 of API 653, from: (1) the date of the previous external tank inspection; or (2) May 3, 1999, the effective date of the regulation, whichever is later. Specifically, the Notice alleged that Cenex exceeded the interval for the API 653 external inspections on the eight specified tanks by time periods ranging from 16 months to 51 months. In its Response, Cenex acknowledged the deficiency and did not contest this allegation of violation, but provided information and explanations that it believed would warrant a reduction in the amount of the civil penalty proposed in the Notice for this item. 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 perform external tank inspections for eight of its breakout tanks within the maximum five- year interval, in accordance with Section 6.3.2.1 of API 653. To the extent the information and explanations in Cenex’s Response are relevant to the amount of the penalty proposed in the Notice for this violation, they will be addressed below in the Assessment of Penalty section. Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h), which states in relevant part: § 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 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.#

520125013_Final Order_12312012_text.pdf, page 65 (2) … (4) Special requirements for scheduling remediation —(i) Immediate repair conditions. An operator's evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formula in Section 451.6.2.2 (b) of ANSI/ASME B31.4 (incorporated by reference, see § 195.3). An operator must treat the following conditions as immediate repair conditions: (A) Metal loss greater than 80% of nominal wall regardless of dimensions. (B) A calculation of the remaining strength of the pipe shows a predicted burst pressure less than the established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (“Manual for Determining the Remaining Strength of Corroded Pipelines” (1991) or AGA Pipeline Research Committee Project PR-3-805 (“A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe” (December 1989)). These documents are incorporated by reference and are available at the addresses listed in § 195.3. (C) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) that has any indication of metal loss, cracking or a stress riser. (D) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 6% of the nominal pipe diameter. (E) An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action. (ii) 60-day conditions. Except for conditions listed in paragraph (h)(4)(i) of this section, an operator must schedule evaluation and remediation of the following conditions within 60 days of discovery of condition. (A) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 3% of the pipeline diameter (greater than 0.250 inches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12). (B) A dent located on the bottom of the pipeline that has any indication of metal loss, cracking or a stress riser. (iii) 180-day conditions. Except for conditions listed in paragraph (h)(4)(i) or (ii) of this section, an operator must schedule evaluation and remediation of the following within 180 days of discovery of the condition: (A) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld. The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h) by failing to evaluate all dent anomalies found within high consequence areas (HCAs). Specifically, the Notice alleged#

520125013_Final Order_12312012_text.pdf, page 76 that Cenex did not evaluate 16 dent anomalies having a depth greater than 0.25-inches because it did not account for the accuracy tolerance of the in-line inspection tool its vendor used to perform the in-line inspection. 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(h) by failing to evaluate all dent anomalies within HCAs. Item 8: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h), which states in relevant part: § 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. (2) … (4) Special requirements for scheduling remediation —(i) Immediate repair conditions. An operator's evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formula in Section 451.6.2.2 (b) of ANSI/ASME B31.4 (incorporated by reference, see § 195.3). An operator must treat the following conditions as immediate repair conditions: (A) . . . (ii) 60-day conditions. Except for conditions listed in paragraph (h)(4)(i) of this section, an operator must schedule evaluation and remediation of the following conditions within 60 days of discovery of condition. (A) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 3% of the pipeline diameter (greater than 0.250 inches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12). (B) A dent located on the bottom of the pipeline that has any indication of metal loss, cracking or a stress riser. (iii) 180-day conditions. Except for conditions listed in paragraph (h)(4)(i) or (ii) of this section, an operator must schedule evaluation and remediation of the following within 180 days of discovery of the condition:#

520125013_Final Order_12312012_text.pdf, page 87 (A) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld. (B) A dent located on the top of the pipeline (above 4 and 8 o'clock position) with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12). (C) A dent located on the bottom of the pipeline with a depth greater than 6% of the pipeline's diameter. (D) A calculation of the remaining strength of the pipe shows an operating pressure that is less than the current established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (“Manual for Determining the Remaining Strength of Corroded Pipelines” (1991)) or AGA Pipeline Research Committee Project PR-3- 805 (“A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe” (December 1989)). These documents are incorporated by reference and are available at the addresses listed in § 195.3. (E) An area of general corrosion with a predicted metal loss greater than 50% of nominal wall. (F) Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline, or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld. The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h) by failing to evaluate all metal loss anomalies found within HCAs. Specifically, the Notice alleged that Cenex did not evaluate at least four metal loss anomalies having a depth greater than 16 percent of nominal wall thickness because it did not account for the accuracy tolerance of the in-line inspection tool its vendor used to perform the in-line inspection (ILI). 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(h) by failing to evaluate all metal loss anomalies found within HCAs. Item 10: The Notice alleged that Respondent violated 49 C.F.R. § 195.573(c), which states: § 195.573 What must I do to monitor external corrosion control? (a) . . . (c) Rectifiers and other devices. You must electrically check for proper performance each device in the first column at the frequency stated in the second column. Device Check frequency Rectifier................................. Reverse current switch Diode At least six times each calendar year, but with intervals not exceeding 2½ months#

520125013_Final Order_12312012_text.pdf, page 98 Interference bond whose failure would jeopardize structural protection. Other interference bond.................. At least once each calendar year, but with intervals not exceeding 15 months. The Notice alleged that Respondent violated 49 C.F.R. § 195.573(c) by failing to electrically check for proper performance certain reverse current switches used to protect against external corrosion. Specifically, the Notice alleged that Cenex failed to check devices known as polarization cell replacements (PCRs) at least six times each calendar year but with intervals not exceeding 2½ months. According to the Notice, Respondent allegedly installed the PCRs at a location where the Cenex pipeline parallels a wind farm electric transmission line between Fargo and Minot, North Dakota but monitored them annually instead of at the specified 2½ month interval. 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(c) by failing to electrically check certain PCRs at least six times each calendar year but with intervals not exceeding 2½ months. Item 11: The Notice alleged that Respondent violated 49 C.F.R. § 195.575(e), which states: § 195.575 Which facilities must I electrically isolate and what inspections, tests, and safeguards are required? (a) … (e) If a pipeline is in close proximity to electrical transmission tower footings, ground cables, or counterpoise, or in other areas where it is reasonable to foresee fault currents or an unusual risk of lightning, you must protect the pipeline against damage from fault currents or lightning and take protective measures at insulating devices. The Notice alleged that Respondent violated 49 C.F.R. § 195.575(e) by failing to protect its pipeline against damage from reasonably foreseeable fault currents or lightning. Specifically, the Notice alleged that no fault-current protection was installed on the Laurel-to-Billings section of the Cenex pipeline that was in close proximity to a fence around an electrical substation located downstream from the Laurel Refinery. 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. § 195.575(e) by failing to protect its pipeline against damage from reasonably foreseeable fault currents or lightning. Item 13: The Notice alleged that Respondent violated 49 C.F.R. § 195.583(b), which states: § 195.583 What must I do to monitor atmospheric corrosion control? (a) …#

520125013_Final Order_12312012_text.pdf, page 109 (b) During inspections you must give particular attention to pipe at soil-to-air interfaces, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water. The Notice alleged that Respondent violated 49 C.F.R. § 195.583(b) by failing to give particular attention during atmospheric corrosion inspections to several aboveground pipe supports located at the Billings station, Rosebud station, Glendive station, Mile Post (MP) 98, MP 193B (Powder River DS block valve), MP 211B (Yellowstone River DS block valve), and MP 222. Areas in the vicinity of the pipe supports had rust on the pipe at the interface between the pipe and the pipe supports that may indicate on-going atmospheric corrosion. The supports are either made from concrete or are of a type that cannot be easily lowered to conduct the 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. § 195.583(b) by failing to give particular attention during atmospheric corrosion inspections to several aboveground pipe supports located at the Billings station, Rosebud station, Glendive station, MP 98, MP 193B (Powder River DS block valve), MP 211B (Yellowstone River DS block valve), and MP 222. Contested Items Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.401(b)(1), which states: § 195.401 General requirements. (a) … (b) An operator must make repairs on its pipeline system according to the following requirements: (1) Non Integrity management repairs. Whenever an operator discovers any condition that could adversely affect the safe operation of its pipeline system, it must correct the condition within a reasonable time. However, if the condition is of such a nature that it presents an immediate hazard to persons or property, the operator may not operate the affected part of the system until it has corrected the unsafe condition. The Notice alleged that Respondent violated 49 C.F.R. § 195.401(b)(1) by failing to correct within a reasonable time a discovered condition that could adversely affect the safe operation of its Minot Tanks 201 and 202. Specifically, the Notice alleged that during the 2007 external inspections of these tanks, Cenex discovered that they would only be suitable for service if safe- fill height recommendations were established and adhered to. However, during the 2010 inspection, neither of the inspection reports specified the safe-fill height for either tank. In its Response, Cenex explained that while the 2007 inspection report recommended a safe-fill height of 47’ 6” for tanks 201 and 202, Cenex had established a lower height of 41’ 11” for tank 201 and 42’ 5” for tank 202 and was able to document this process. As these safe-fill heights were more conservative than those recommended in the 2007 report, there was no need to change them.#

520125013_Final Order_12312012_text.pdf, page 1110 I agree. Accordingly, after considering all of the evidence, I find that Cenex complied with § 195.401(b)(1) with regard to tanks 201 and 202. Based upon the foregoing, I hereby order that Item 2 of the Notice be withdrawn. Item 9: 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 ensure through evaluation that individuals performing covered tasks were qualified. Specifically, the Notice alleged that Cenex employees were only evaluated for their ability to recognize and react to task- specific abnormal operating conditions (AOCs) when they were initially qualified, but not when they were subsequently re-qualified. In its Response, Cenex explained that its written qualification program did not require evaluations for task-specific AOCs as part of routine re-qualifications unless there was reason to believe an individual was no longer qualified. Cenex also noted that making evaluations for task-specific AOCs part of routine re-qualifications was not expressly required by § 195.505. Respondent is correct. Accordingly, after considering all of the evidence and the legal issues presented, I find that Respondent complied with § 195.505 with regard to evaluating employees on task specific AOCs. Based upon the foregoing, I hereby order that Item 9 of the Notice be withdrawn. Item 12: The Notice alleged that Respondent violated 49 C.F.R. § 195.581, which states in relevant part: § 195.581 Which pipelines must I protect against atmospheric corrosion and what coating material may I use? (a) You must clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, except pipelines under paragraph (c) of this section. . . (c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, you need not protect against atmospheric corrosion any pipeline for which you demonstrate by test, investigation, or experience appropriate to the environment of the pipeline that corrosion will— (1) Only be a light surface oxide; or (2) Not affect the safe operation of the pipeline before the next scheduled inspection. The Notice alleged that Respondent violated 49 C.F.R. § 195.581 by failing to clean and coat#

520125013_Final Order_12312012_text.pdf, page 1211 each pipeline or portion of pipeline that is exposed to the atmosphere. Specifically, the Notice alleged that on June 21, 2005, Cenex found that the soil-to-air interface at the Minot station mainline piping spool (piping item FRS-1000) needed protective coating. The Notice alleged that on June 21, 2008, Cenex records show that this same soil-to-air interface still needed protective coating and that Cenex could not provide evidence that this soil-to-air interface had been coated as of the time of the 2010 OPS inspection. In its Response, Cenex explained that piping item FRS-1000 and the 2005 and 2008 inspection dates cited in the Notice related to the Fargo Station soil-to-air interface, not the Minot Station. Respondent further explained that in 2009 UV tape coating had been installed over a paint coating and that no corrosion was present in the pipe spool as confirmed by in-line inspection. Upon considering all of the evidence, I find that Cenex was in compliance with § 195.581 with regard to piping item FRS-1000 at the Fargo Station. Accordingly, I hereby order that Item 12 of the Notice be withdrawn. ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed $100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any related series of violations. 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; the Respondent’s ability to pay the penalty 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 $76,500 for the violations cited above, $35,000 of which was for Item 12, which has now been withdrawn. Item 6: The Notice proposed a civil penalty of $41,500 for Respondent’s violation of 49 C.F.R. § 195.432(b), for failing to perform external tank inspections for eight of its breakout tanks within the maximum five-year interval, in accordance with Section 6.3.2.1 of API 653. In its Response, Cenex explained that external inspections involving some aspects of API 653 had been conducted, albeit by individuals who were not certified API 653 inspectors. Respondent also explained that all deficient API 653 external inspections at the Minot terminal were completed in 2007 and those at the Billings Tank Farm were completed in 2008 and 2009. With respect to the nature, circumstances, and gravity of this violation, any missed inspection has the potential to impact safety. Tank inspections in particular are a key part of safety and environmental protection because a tank failure can result in a significant spill incident. Respondent is culpable for the violation, as pipeline operators are obligated to perform full API 653 inspections of the tanks they operate. I acknowledge the actions taken by Respondent following discovery of the deficiencies that should ensure future inspections are scheduled in a#

520125013_Final Order_12312012_text.pdf, page 1312 timeframe that meets the regulatory requirement, but this does not constitute a good-faith effort to comply with the regulatory requirement prior to the missed inspections. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a total civil penalty of $41,500 for violation of 49 C.F.R. § 195.432(b). 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 (AMZ-341), Federal Aviation Administration, Mike Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, Oklahoma 73125. The Financial Operations Division telephone number is (405) 954-8893. Failure to pay the $41,500 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 1, 2, 3, 4, 5, 7, 8, 9, 10, 11, 12, and 13 in the Notice for violations of 49 C.F.R. §§ 195.214(b), 195.401(b)(1), 195.404(a)(1)(vii), 195.404(a), 195.404(b)(1), 195.452(h), 195.452(h), 195.505(b), 195.573(c), 195.575(e), 195.581, and 195.583(b), respectively. As noted above, Items 2, 9, and 12 have now been withdrawn and compliance terms for those items are not included in this Order. 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. 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 § 195.214(b) (Item 1), Respondent must ensure the weld qualification report for weld procedure 110504-1 includes: (1) the groove qualifying test results, including the weld tensile strength coupon sizes and the breaking stress that each tensile strength coupon experienced during testing, nick-break test results, root bend test results, and face bend test results; and (2) the sleeve weld qualifying test results, including the nick-break test results, the face bend test results, and the macro test results. Cenex must submit the corrected record of the weld qualification report for weld procedure 110504-1 to OPS Western Region (Director). 2. With respect to the violation of § 195.404(a)(1)(vii) (Item 3), Respondent must#

520125013_Final Order_12312012_text.pdf, page 1413 3. 4. 5. 6. 7. ensure that its P&IDs for the North Dakota section of the Cenex Products pipeline include both the pressure safety valve tag numbers and the pressure set points associated with those devices. Cenex must provide those updated P&IDs to the Director. With respect to the violation of § 195.404(a) (Item 4), Respondent must update its Cenex Products pipeline alignment sheets to ensure that they show current pipeline information, including, but not limited to, all crossings of public roads, railroads, rivers, buried utilities, foreign pipeline crossings and other pipeline changes as required under 195.404(a). Cenex must provide these updated alignment sheets to the Director. With respect to the violation of § 195.404(b)(1) (Item 5), Respondent must provide a pressure recording device at its Billings Tank Farm pump station that will allow it to record the daily discharge pressures of the Billings Tank Farm pump station and must continuously retain at least three years of those records. Cenex must provide evidence of the installation of the above pressure recording device and documentation that ensures Cenex will retain pressure discharge records for this site for at least three years to the Director. With respect to the violation of § 195.452(h) (Item 7), Respondent must evaluate the following dent ID numbers found during the Glendive Station to Minot Station in-line inspection: 14000022, 14000048, 14000027, 14000034, 14000051, 14000012, 14000013, 14000023, 14000069, 14000019, 14000076, 14000068, 14000058, and 14000060 and must evaluate the following dent ID numbers found during the Laurel Station to Billings Station in-line inspection: 14000003 and 14000004. If any of these dents are found to be located on the top of the pipeline or found to affect pipe curvature at a girth weld or a longitudinal seam weld, then Cenex must then repair those dents. Cenex must submit records of the above evaluations and investigations and any subsequent repairs to the Director. With respect to the violation of § 195.452(h) (Item 8), Respondent must re- review its ILI metal loss logs, taking known data from the 2008 MFL ILI run and adding the in-line tool accuracy determined by previous 2008 anomaly investigations. Cenex must then investigate any anomalies that have a potential to meet the repair criteria under §195.452(h) and if anomalies are found to meet that criteria, Cenex must make appropriate repairs to the pipeline. Cenex must submit records of the above evaluations and investigations and any subsequent repairs to the Director. With respect to the violation of § 195.573(c) (Item 10), Respondent must ensure that it electrically inspects each of their PCRs recently installed where the Cenex pipeline parallels a wind farm electrical power transmission line between Fargo and Minot, North Dakota, six times each calendar year, but at intervals not exceeding 2½ months. Cenex must provide documentation insuring that these PCRs are electrically inspected six times each calendar year, but at intervals not#

520125013_Final Order_12312012_text.pdf, page 1514 exceeding 2½ months to the Director. 8. With respect to the violation of § 195.575(e) (Item 11), Respondent must install ground fault protection at the electrical substation downstream from the Laurel Refinery between MP 0.5 and 0.8. Cenex must provide evidence that ground fault protection has been provided at this location to the Director. 9. With respect to the violation of § 195.583(b) (Item 13), Respondent must inspect between the aboveground pipe and its associated supports at Billings station, Rosebud station, Glendive station, MP 98, MP 193B Powder River DS block valve, MP 211B Yellowstone River DS block valve, and MP 222. Cenex must take actions to ensure that future inspections will allow inspection for atmospheric corrosion between aboveground pipe and their associated supports at Billings station, Rosebud station, Glendive station, MP 98, MP 193B Powder River DS block valve, MP 211B Yellowstone River DS block valve, and MP 222. Cenex must repair any corrosion that is found during the required atmospheric corrosion inspections at these aboveground pipe support locations. Cenex must provide evidence that measures have been taken to allow for future atmospheric corrosion inspections between aboveground pipe and associated supports at the above locations and must provide documentation of atmospheric corrosion inspections and associated repairs at the above locations to the Director. 10. It is requested that Cenex maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to the Director. It is requested that these costs be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses; and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. 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. Failure to comply with this Order may result in the administrative assessment of civil penalties not to exceed $100,000 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. Under 49 C.F.R. § 190.215, Respondent has a right to submit a petition for reconsideration of this Final Order. Should Respondent elect to do so, 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 the Respondent, provided they contain a brief statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.215. 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#

520125013_Final Order_12312012_text.pdf, page 1615 effective upon service in accordance with 49 C.F.R. § 190.5. ___________________________________ __________________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety#