BELLE FOURCHE PIPELINE CO — Notice of Probable Violation

520095042_nopv-pcp-pco_12302009_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED December 30, 2009 Mr. Tad True Vice President, True Oil Belle Fourche Pipeline Company 895 W. River Cross Road P.O. Drawer 2360 Casper, WY 82602 CPF 5-2009-5042 Dear Mr. True: On August 24-28, 2008, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), pursuant to Chapter 601 of 49 United States Code, inspected two of your company’s pipeline systems, the Belle Fourche Pipeline and Sussex Diesel Pipeline in Casper, Wyoming. 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 violations are: 1. §195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operation and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year,#

520095042_nopv-pcp-pco_12302009_text.pdf, page 2and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. BFPL records as well as conversations with BFPL personnel showed that the company had not reviewed or revised its O&M Manual from 2005 to 2008. An operator is required to perform those reviews and make appropriate changes once each calendar year, but at intervals not exceeding 15 months. 2. §195.402 Procedural manual for operation, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. (c) Maintenance and Normal Operations. The manual required by paragraph (a) of this section must include procedures for the following to provide safety during maintenance and normal operations: (12) Establishing and maintaining liaison with fire, police, and other appropriate public officials to learn the responsibility and resources of each government organization that may respond to a hazardous liquid or carbon dioxide pipeline emergency and acquaint the officials with the operator’s ability in responding to a hazardous liquid or carbon dioxide pipeline emergency and means of communication. BFPL had not established and maintained liaison with fire, police or other appropriate public officials along its pipeline system in Wyoming. BFPL’s Public Awareness Program stated that the company would compile data (names, addresses, phone numbers, etc.) pertaining to local fire, police, and other emergency and public officials that could be involved with a response to a hazardous liquid pipeline emergency involving a BFPL pipeline. However, BFPL had no documentation showing that the company had collected such data or performed the required liaison activities. BFPL was issued a warning for a similar citation in CPF 5-2007-5002. 3. §195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. 2#

520095042_nopv-pcp-pco_12302009_text.pdf, page 3(c) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following to provide safety during maintenance and normal operations: (13) Periodically reviewing the work done by operator to determine the effectiveness of the procedures used in normal operation and maintenance and taking corrective action where deficiencies are found. BFPL had not been periodically reviewing the work completed by its personnel to determine the effectiveness of their Pipeline Operations and Maintenance Manual (O&M Manual). BFPL had a procedure for performing such reviews in Section 3.8 of the “Organization and Responsibilities” section of the BFPL O&M Manual. Nonetheless, the company had no record of those reviews at the time of the inspection. Section 195.404 requires that an operator maintain a record of each inspection and test required by subpart F of Part 195 for at least 2 years or until the next inspection or test is performed, whichever is longer. The absence of any records is a violation of the pipeline safety regulations and BFPL’s own procedures. It also indicates that the required inspections did not occur, which is consistent with statements made by the company’s operating personnel at the time of the inspection. 4. §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; BFPL did not have a pressure recording device at the Guernsey Pump Station and the company did not maintain any pressure discharge records for that facility. Each operator is required to maintain at least 3 years’ worth of records documenting the daily discharge pressures at each pump station. 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. BFPL’s tank data sheets showed that the Sussex breakout tank received an API Standard 653 out-of-service internal inspection in 2001. However, an inspection report was not in BFPL’s files or otherwise available for review at the time of the inspection. The operator is required to keep a complete record of inspections per Section 6 of API 653 until the next inspection of its type is performed. 6. §195.406 Maximum operating pressure. (b) No operator may permit the pressure in a pipeline during surges or other variations from normal operations to exceed 110 percent of the operating pressure limit established under paragraph (a) of this section. Each operator must provide adequate controls and protective equipment to control the pressure within this limit. 3#

520095042_nopv-pcp-pco_12302009_text.pdf, page 4BFPL had no safety device(s) installed at the Guernsey Pump Station to prevent overpressuring of the pumping equipment and piping installed at that facility or of the pipeline located downstream from that station. Each pipeline operator must provide adequate controls and protective equipment to control the pressure within the maximum operating pressure (MOP) during normal operations and 110% of MOP during abnormal operations. 7. §195.412 Inspection of rights-of-way and crossings 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 mean of traversing the right-of-way. BFPL did not inspect its pipeline right-of-way at the appropriate time intervals for the Montana portion of the Bicentennial Line. The evidence shows that the required interval was exceeded between March 24 and April 21, 2008, and between June 4 and July 5, 2008. BFPL had records of over-flights occurring between these dates, but those records indicate that the Montana portion of the Bicentennial line was not over-flown. In addition, the recordkeeping process for right-of-way inspections made it difficult for BFPL to keep track of inspection intervals for the various segments of its pipeline system, thereby increasing the probability that a right-of-way inspection could be missed. An operator is required to patrol all of their pipelines at an interval not exceeding 3 weeks but at least 26 times per year and to maintain a record of those patrols. 8. §195.420 Valve maintenance. (b) Each operator shall, at intervals not exceeding 7 1/2 months, but at least twice each calendar year, inspect each mainline valve to determine that it is functioning properly. BFPL failed to inspect numerous mainline valves at the required frequency from 2006 to 2007. BFPL records confirm the following 25 mainline valves were not inspected twice during the 2006 calendar year: Area Valve Designation Area Valve Designation Shilight/Kaye 010-011 Donkey Creek 010-002 Shilight/Kaye 015-005 Donkey Creek 010-003 Shilight/Kaye 015-004 Donkey Creek 010-001 Shilight/Kaye 015-005 Donkey Creek 010-101 Shilight/Kaye 015-002 Sussex Products 069-0001 Shilight/Kaye Poison Draw 6” Tie In Sussex Products 069-0006 (6”) Shilight/Kaye Poison Draw Line 8” Sussex Products 069-0006 (4”) Shilight/Kaye 010-0056 Sussex Products 069-0007 (6”) 4#

520095042_nopv-pcp-pco_12302009_text.pdf, page 5Shilight/Kaye 101-006 Sussex Products 069-0007 (4”) Shilight/Kaye 015-001 Sussex Products 069-0008 Shilight/Kaye 015-011 Shilight/Kaye 015-012 Shilight/Kaye 101-008 Shilight/Kaye 101-009 Shilight/Kaye 010-010 In addition, BFPL records show that inspections for the following 22 mainline valves exceeded the 7 ½ month maximum inspection interval: Valve Designation Period Days in excess of 7 ½ months 010-001 June 1, 2006 to January 14, 2007 2 010-101 June 1, 2006 to January 14, 2007 2 015-002 June 7, 2006 to January 25, 2007 7 6” Tie In June 7, 2006 to January 25, 2007 7 8” Poison Draw Line June 7, 2006 to January 25, 2007 7 010-005 June 7, 2006 to January 25, 2007 7 010-006 June 7, 2006 to January 25, 2007 7 015-001 June 8, 2006 to January 25, 2007 6 010-008 May 23, 2006 to January 22, 2007 19 010-009 May 23, 2006 to January 22, 2007 19 010-010 May 23, 2006 to January 22, 2007 19 069-0001 April 20, 2006 to January 11, 2007 41 069-0003 October 8, 2006 to July 13, 2007 53 Incoming Trap October 8, 2006 to July 13, 2007 53 069-0004 March 2, 2006 to December 17, 2006 65 Outgoing Launcher March 2, 2006 to December 17, 2006 65 069-0005 March 2, 2006 to December 17, 2006 65 5#

520095042_nopv-pcp-pco_12302009_text.pdf, page 6069-0007 April 10, 2006 to January 9, 2007 49 Iberline Incoming Trap April 10, 2006 to January 9, 2007 49 069-0007 April 10, 2006 to January 9, 2007 49 Iberline Outgoing Launcher April 10, 2006 to January 9, 2007 49 069-0008 April 10, 2006 to January 4, 2007 44 Each operator must inspect each mainline valve at least twice each calendar year at intervals not exceeding 7 ½ months and maintain records of such inspections for at least 2 years. 9. §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. BFPL records established that a number of its pressure limiting devices were not inspected and tested at the required frequency between the years 2006 to 2008. An operator is required to inspect and test each item of pressure control equipment once each calendar year not to exceed 15 months. • Donkey Creek and Hwy 450 stations pressure controls were not tested and inspected in the 2007 calendar year. Additionally, BFPL exceeded the 15-month interval for testing and inspecting pressure controls at these stations by 68 and 98 days, respectively. • Seiler station pressure controls exceeded the 15-month interval for testing and inspecting in the 2007 calendar year by 120 days. • At the time of this inspection, BFPL had not yet tested and inspected Sussex pump station and Guernsey terminal for the 2008 calendar year, resulting in BFPL exceeding the 15-month interval by a minimum of 145 and 105 days, respectively. 10. §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. 6#

520095042_nopv-pcp-pco_12302009_text.pdf, page 7(d) After October 2, 2000, the requirements of paragraphs (a) and (b) of this section for inspection and testing of pressure control equipment apply to the inspection and testing of overfill protection systems. Conversations with BFPL personnel confirmed that the high-level alarms on the following three breakout tanks associated with the Sussex Diesel Line had never been tested at the prescribed intervals ▪ Sussex Pump Station Breakout Tank ▪ Davis Station (Tank 74) Breakout Tank ▪ Hawk Point Terminal Breakout Tank Each operator must inspect and test overfill protection system on each breakout tank at least once each calendar year at intervals not to exceed 15 months, and maintain records of those inspections and tests for at least two years. 11. §195.432 Inspection of in-service breakout tanks. (a) Except for breakout tanks inspected under paragraphs (b) and (c) of this section, each operator shall, at intervals not exceeding 15 months, but at least each calendar year, inspect each in-service breakout tank. (b) Each operator shall inspect the physical integrity of in-service atmospheric and low pressure steel aboveground breakout tanks according to section 4 of API Standard 653. 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). BFPL’s tank data sheets verified that BFPL had never performed an External Tank Inspection on the Sussex Breakout Tank. Because it appears this tank received an internal inspection in 2001 this tank should have received an external inspection no later than 2006, as well as the 5-year interval prescribed in API 653 Section 6.3.2. 12. §195.436 Security of facilities. Each operator shall provide protection for each pumping station and breakout tank area and other exposed facility (such as scraper traps) from vandalism and unauthorized entry. BFPL had no security fencing installed around the Donkey Creek Pump Station. Also 4.5 to 5 foot high security fencing around the Sussex Pump Station and Sussex Breakout Tank was only made of 4 foot high 6 inch grid woven steel wire with 2 strands of barbed wire above it. This type of fence will keep livestock out of the facility but it is not adequate to prevent vandalism and unauthorized entry to the facility. 13. §195.577 What must I do to alleviate interference currents? (a) For pipelines exposed to stray currents, you must have a program to identify, test for, and minimize the detrimental effects of such currents. BFPL’s cathodic protection monitoring records for the 12” Donkey Creek Pipeline in the area in and around Guernsey station and Ft Laramie station for the 2006 calendar year showed several test stations with high off levels. High off levels indicate that cathodic 7#

520095042_nopv-pcp-pco_12302009_text.pdf, page 8protection interference currents may be adversely affecting a pipeline. Nonetheless, at the time of the inspection, BFPL had not taken the appropriate steps to perform an interference study to determine if there were interference currents on their pipeline or to mitigate any of the interference currents that might exist. The Pipeline Safety Regulations require an operator to identify, test for, and minimize the detrimental effects of stray currents. 14. §195.579 What must I do to mitigate internal corrosion? (a) General. If you transport any hazardous liquid or carbon dioxide that would corrode the pipeline, you must investigate the corrosive effect of the hazardous liquid or carbon dioxide on the pipeline and take adequate steps to mitigate internal corrosion. Since 2006, BFPL has experienced at least three leaks due to internal corrosion, a condition that may be the result of the corrosive effects of the crude oil that is being shipped through its pipeline system. The Pipeline Safety Regulations require an operator who transports a hazardous liquid that could corrode a pipe to investigate and take adequate steps to mitigate that condition. Nonetheless, at the time of the inspection, BFPL had not conducted such an investigation or taken any steps to mitigate that condition. 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 $221,200 as follows: Item Number PENALTY 1 $37,100 5 $17,100 8 $30,800 9 $62,100 10 $30,800 11 $43,300 Warning Items With respect to items 7 and, 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 item(s). Be advised that failure to do so may result in Belle Fourche Pipeline Company being subject to additional enforcement action. 8#

520095042_nopv-pcp-pco_12302009_text.pdf, page 9Proposed Compliance Order With respect to items 2, 3, 4, 6, 10, 11, 12, 13, and 14 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Belle Fourche Pipeline Company. 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 qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order. In your correspondence on this matter, please refer to CPF 5-2009-5042 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 (#120773) 9#

520095042_nopv-pcp-pco_12302009_text.pdf, page 10PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Belle Fourche Pipeline Company (BFPL) a Compliance Order incorporating the following remedial requirements to ensure the compliance of BFPL with the pipeline safety regulations: 1. In regard to Item Number 2 of the Notice pertaining to the lack of the development of a list of local fire, police, and other emergency and public officials: BFPL must develop a list of local fire, police, and other emergency and public officials that could potentially respond to an emergency associated with BFPL's hazardous liquid pipelines in Wyoming. BFPL must then conduct periodic liaison activities with these entities to .accomplish the following: • Learn the responsibilities and resources of each entity. • Acquaint each agency with BFPL's ability in responding to a hazardous liquid pipeline emergency. • Understand the means of communication that could be used between BFPL and each entity in the event of a pipeline emergency. 2. In regard to Item Number 3 of the Notice pertaining to BFPL not reviewing the work done by its personnel to determine the effectiveness of procedures: BFPL must review the work done by its employees to determine the effectiveness of their procedure and they must document such reviews. 3. In regard to Item Number 4 of the Notice pertaining to the lack of a pressure recording device at the Guernsey Pump Station: BFPL must install a pressure recording device at the Guernsey Pump Station to record the discharge pressure of the station. BFPL must then retain the pressure records for a minimum of three years. 4. In regard to Item Number 6 of the Notice pertaining to the lack of a safety device that prevents overpressuring of pumping equipment at the Guernsey Pump Station: BFPL must install an overpressure protection device at the Guernsey Pump Station that prevents the Maximum Operating Pressure (MOP) of the piping at the station and the pipeline downstream from the station from being exceeded. 5. In regard to Item Number 10 of the Notice pertaining to the lack of inspection and testing of high level alarms on three breakout tanks on the Sussex Diesel Line: BFPL must inspect and test the high level alarms on the following tanks: ▪ Sussex Pump Station Breakout Tank (BOT) ▪ Davis Station (Tank 74) BOT ▪ Hawk Point Terminal BOT 6. In regard to Item Number 11 of the Notice pertaining to exceeding the maximum interval of 5 years for an API Standard 653 External Inspection of the Sussex diesel BOT: BFPL must conduct an API Standard 653 External Inspection on their Sussex diesel BOT. 10#

520095042_nopv-pcp-pco_12302009_text.pdf, page 117. In regard to Item Number 12 of the Notice pertaining to the lack of security fencing around the Donkey Creek Pump Station and the inadequate security fencing around the Sussex Pump Station and Sussex BOT: BFPL must install security fencing around the Donkey Creek Pump Station that is a minimum of six feet high and includes a minimum of 3 strands of barbed wire above the fencing. Appropriate warning signs and operator contact information must be installed on the fencing and all gates must be adequately locked. In addition, BFPL must replace the security fencing around the Sussex Pump Station and Sussex Breakout Tank with security fencing that is a minimum of six feet high and includes a minimum of 3 strands of barbed wire above the fencing. Appropriate warning signs and operator contact information must be installed on the fencing and all gates must be adequately locked. 8. In regard to Item Number 13 of the Notice pertaining to High "Off' CP levels on the 12" Donkey Creek Pipeline located between Guernsey station and Ft Laramie station: BFPL must perform an interference study on the Donkey Creek Pipeline between Guernsey station and Ft Laramie station and remediate any stray currents that are found. 9. In regard to Item Number 14 of the Notice pertaining to potentially corrosive crude oil being shipped through the Belle Fourche Pipeline System may be causing internal corrosion of the pipeline system: BFPL must conduct an investigation to determine if crude oil being shipped through their pipeline system is causing internal corrosion. If the investigation determines that the crude oil is in fact causing internal corrosion, BFPL must take appropriate remedial actions to prevent internal corrosion from continuing to occur in their pipeline system. 10. BFPL must complete the items described above within 60 days of receipt of the Final Order. 11. Belle Fourche Pipeline Company shall 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. Costs shall be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses, and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. 11#

520095042_Decision on the Petition for Reconsideration_03292012_text.pdf, page 1Official PDFMAR 29 2012 Mr. Tad True Vice President Belle Fourche Pipeline Company P.O. Box 2360 Casper, WY 82602 Re: CPF No. 5-2009-5042 Dear Mr. True: Enclosed please find the decision on the petition for reconsideration filed by Belle Fourche Pipeline Company in the above-referenced case. For the reasons set forth in the decision, your petition to withdraw the findings of violation in Items 13 and 14 of the Final Order is denied. In addition, your petition to withdraw the terms of the compliance order associated with Item 14 is denied. Your petition to find that Belle Fourche has satisfied the terms of the compliance order associated with Item 13 is granted. Service of this document by certified mail is complete upon mailing as 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. Alan Mayberry, Deputy Associate Administrator for Field Operations, OPS Mr. Chris Hoidal, Director, Western Region, OPS Mr. Colin Harris, Holme Roberts & Owen LLP 1801 13th Street, Suite 300, Boulder, CO 80302-5259 CERTIFIED MAIL – RETURN RECEIPT REQUESTED [71791000164203446319]#

520095042_Decision on the Petition for Reconsideration_03292012_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 ) Belle Fourche Pipeline Company, ) CPF No. 5-2009-5042 ) ) ) Petitioner. ) ____________________________________) DECISION ON PETITION FOR RECONSIDERATION On November 21, 2011, pursuant to 49 U.S.C. §§ 60118 and 60122, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a Final Order in this proceeding finding that Belle Fourche Pipeline Company (BFPL or Petitioner) committed nine violations of the pipeline safety regulations in 49 C.F.R. Part 195. The Final Order assessed a civil penalty of $131,900 for four of the violations and ordered BFPL to take certain corrective measures (Compliance Order). BFPL operates approximately 600 miles of pipeline in Montana, North Dakota, and Wyoming transporting crude oil and refined petroleum products.1 BFPL submitted a Petition for Reconsideration of the Final Order dated December 9, 2011 (Petition). In its Petition, BFPL requested reconsideration of Items 13 and 14 in the Final Order, which had found that BFPL violated 49 C.F.R. §§ 195.577(a) and 195.579(a), respectively. Petitioner also requested a stay of the terms of the Compliance Order associated with those items pending the issuance of a decision on its Petition. PHMSA granted the stay on 2 January 13, 2012. Pursuant to 49 C.F.R. § 190.215, a respondent may petition for reconsideration of a final order that has been issued pursuant to § 190.213. Section 190.215 provides that PHMSA does not consider repetitious information or arguments, but may consider additional facts or arguments if the Petitioner submits a valid reason explaining why such information was not presented prior to issuance of the final order. PHMSA may grant or deny, in whole or in part, a petition for reconsideration without further proceedings, but may request additional information or comment as deemed appropriate. 1 This information is reported by BFPL as required by 49 C.F.R. § 195.49. On its website, the company states that it operates 1,500 miles of pipeline. http://www.truecos.com/BFPL (last accessed Mar. 8, 2012). 2 The Final Order did not assess civil penalties for Items 13 and 14. On December 19, 2011, BFPL submitted payment in full of the civil penalties assessed in the Final Order for Items 8, 9, 10, 11.#

520095042_Decision on the Petition for Reconsideration_03292012_text.pdf, page 32 Item 13: The Final Order determined that BFPL violated 49 C.F.R. § 195.577(a), which states: § 195.577 What must I do to alleviate interference currents? (a) For pipelines exposed to stray currents, you must have a program to identify, test for, and minimize the detrimental effects of such currents. The Final Order determined that BFPL failed to have and implement a program to identify, test for, and minimize the detrimental effects of stray currents on the company’s pipeline. As stated in the Order, the operator’s cathodic protection survey records from January 2006 to December 2008 showed there were areas on its pipeline with high “off” levels, indicative of interference currents that could have an adverse effect on the pipeline. BFPL could not produce a documented interference study or any other evidence to demonstrate the company took action in accordance with § 195.577(a) to test the interference currents that were detected during the surveys to determine whether any effects were adverse to the pipeline and to mitigate detrimental effects. In its Petition, BFPL acknowledged that § 195.577(a) requires companies to identify, test for, and minimize the detrimental effects of electrical current flowing from an external source to the affected pipeline. company argued that there was insufficient evidence of a violation presented by OPS, and that the evidence of compliance presented by BFPL was not properly considered. 3 Petitioner disagreed, however, that BFPL violated this requirement. The First, BFPL argued that the finding of violation was in error because the evidence presented by OPS did not support the finding. Specifically, Petitioner stated that the cathodic protection survey records from 2006 to 2008 were not sufficient evidence to prove a violation. 4 As noted in the Final Order, BFPL’s survey records from 2006-2008 indicated that its pipeline was exposed to interference currents. Under § 195.577(a), the company was required to identify, test for, and minimize the detrimental effects of those stray currents. Despite the indications of interference currents, BFPL did not produce any evidence to demonstrate that it had taken action during the time period in question to conduct tests to determine whether the interference currents were adversely affecting the pipeline.5 These facts constituted sufficient evidence for PHMSA to find that BFPL violated § 195.577(a). Second, Petitioner argued that the company’s survey records from 2006-2008 demonstrated that the company did, in fact, have a program to identify and test for interference currents. Petitioner stated “[t]he whole purpose of the surveys” was to identify and test for interference currents, citing testimony it offered at the hearing.6 Petitioner claimed that this evidence was not addressed in the Order. 3 Petition at 2. 4 Petition at 2. 5 BFPL conducted a close interval survey in July 2009, but as stated in the Final Order, the survey was performed after the OPS inspection, and therefore did not demonstrate compliance for the time period in question. 6 Petition at 3.#

520095042_Decision on the Petition for Reconsideration_03292012_text.pdf, page 43 The Final Order specifically addressed this position taken by the operator and the evidence it offered in support. For example, the Final Order noted that “BFPL claimed the reports used by PHMSA in support of the allegation demonstrated this program was in place and implemented.”7 While the survey report records showed Petitioner could apparently detect interference currents on its pipeline, the Order concluded that the records themselves did not demonstrate compliance with § 195.577(a) because, among other things, BFPL never actually tested the interference currents during the time period in question to determine if they were detrimental.8 BFPL argued in its Petition that it was not necessary for the company to test the interference currents because testimony in the record “unarguably shows” that the interference currents were not detrimental to the pipeline. 9 Petitioner cited a statement by its witness that the pipelines in the area are all tied together with either piping, electrical grounding, or bonds. Petitioner argued there was no need to conduct additional tests or mitigation “because any issues had already been mitigated.”10 Petitioner claimed this evidence was not acknowledged or refuted in the Order. The Final Order specifically discussed BFPL’s claim that it knew the source of the current and that it was not detrimental. 11 The Order quoted the company’s own Brief, which recited the testimony of its witness that the pipelines in the area “are tied together with either piping, Final Order determined, however, that the company’s assumption that interference currents were not detrimental was not an excuse for failing to conduct the testing required under the regulation. BFPL provided no evidence that it performed an analysis during the time period in question to confirm that interference currents were not detrimental to the pipeline. electrical grounding between the different pipeline companies in the area, or by bonds.”12 The Lastly, Petitioner argued that it was improper for the Final Order to include a statement that BFPL failed to follow written procedures for determining if the stray currents had detrimental effects. Petitioner claimed the issue of “written procedures” was never raised at the hearing. 13 The Notice of Probable Violation provided sufficient notice to BFPL that the company had allegedly violated the requirement in § 195.577(a) to identify, test for, and minimize the detrimental effects of interference currents. 14 Whether or not BFPL had adequate written procedures in place for these activities, the company violated § 195.577(a) by failing to test the interference currents to determine if they were detrimental to the pipeline facility. 7 Final Order at 16. 8 Although Petitioner is correct that the testimony it offered on this point was not quoted in the Order, the testimony only repeated the claim advanced by the company, namely that “[t]he survey reports used by [PHMSA] inspectors . . . is conclusive evidence that Belle Fourche implements this program.” BFPL’s Hearing Exhibit 10 at ¶3. 9 Petition at 3. 10 Petition at 3. 11 Final Order at 15. 12 Final Order at 15, (quoting BFPL’s Post-hearing Brief at 22 (Oct. 11, 2010), which cited Hearing Ex. 10 at ¶4). 13 Petition at 4. See also Final Order at 16. Petitioner submitted copies of its written procedures. 14 Petitioner’ program under § 195.577 must be in writing in accordance with § 195.402(c)(3).#

520095042_Decision on the Petition for Reconsideration_03292012_text.pdf, page 54 For the above reasons, I confirm that BFPL committed a violation of § 195.577(a). BFPL’s petition to withdraw the finding of violation for Item 13 is denied. In its Petition, BFPL argued that the close interval survey (CIS) it performed in July 2009 should be found to have satisfied the terms of the Compliance Order associated with Item 13. 15 In its post-hearing submission, OPS “agree[d] that the performance of that CIS renders the proposed further action to remediate this compliance item. BFPL’s request that PHMSA find it has compliance order unnecessary.”16 For these reasons, I find there is no need for BFPL to take satisfied the compliance terms associated with Item 13 is granted. Item 14: The Final Order determined that BFPL violated 49 C.F.R. § 195.579(a), which states: § 195.579 What must I do to mitigate internal corrosion? (a) General. If you transport any hazardous liquid or carbon dioxide that would corrode the pipeline, you must investigate the corrosive effect of the hazardous liquid or carbon dioxide on the pipeline and take adequate steps to mitigate internal corrosion. The Final Order found that BFPL had failed to investigate the corrosive effect of the hazardous liquid it transported and to take adequate steps to mitigate internal corrosion. As stated in the Order, BFPL’s pipeline system experienced at least three pipeline leaks between 2006 and 2008 that were caused by internal corrosion, but the company never investigated the corrosive effect of the product or mitigated the internal corrosion. In its Petition, BFPL did not disagree that the company never investigated the corrosive effect of the product or mitigated internal corrosion. Petitioner argued, however, the regulation did not require the company to conduct an investigation in the first place. Petitioner stated that the regulation “does not impose an absolute obligation” on all operators to conduct an internal corrosion study, but only in cases where “such liquid ‘would’ corrode the pipeline” is an regulation in a way that requires the company to conduct an internal corrosion study irrespective used guidance to broaden the regulatory requirement beyond the text of the regulation. investigation required.17 Petitioner claimed the Final Order was erroneous in applying the of the nature of the liquids transported. Petitioner also argued the Final Order impermissibly After reviewing the Final Order, I find PHMSA applied § 195.579(a) in a manner that is consistent with the text of the regulation. Section 195.579(a) establishes a duty for operators to investigate and mitigate internal corrosion whenever the product would corrode the pipeline. Petitioner’s pipeline system experienced a series of accidents caused by internal corrosion— evidence the product transported “would corrode the pipeline.”18 Despite the information that product was actually causing internal corrosion, BFPL failed to investigate and mitigate the 15 Petition at 6-7. 16 OPS Post-Hearing Submittal at 10 (Nov. 12, 2010). 17 Petition at 5. 18 § 195.579(a).#

520095042_Decision on the Petition for Reconsideration_03292012_text.pdf, page 65 internal corrosion. BFPL’s failure to investigate and take steps to mitigate the internal corrosion support the agency’s conclusion that the company violated the requirements in § 195.579(a). The agency’s conclusion was based on application of the regulation to the facts of the case. 19 Reference to an Advisory Bulletin in the Final Order was merely ancillary. For example, the Order cited to an Advisory Bulletin issued by the agency in 2008 to explain why BFPL’s purported interpretation of the regulation was erroneous. BFPL had claimed the regulation requires prior “knowledge or reasonable belief” that product would corrode the pipeline before triggering the investigation requirements in § 195.579(a). Based on that interpretation, the company had argued it was never obligated to conduct an investigation. 20 To explain why that interpretation is incorrect, the Final Order cited to the advisory, which was issued to remind operators of their responsibilities to identify circumstances under which the potential for internal corrosion must be investigated. In particular, the advisory noted that § 195.579(a) requires operators “to determine if the hazardous liquids they are transporting could corrode the pipeline and, if so, take adequate steps to mitigate that corrosion potential.”21 The document cautioned operators that even though “the base commodity may not be corrosive, all hazardous liquids regulated under part 195 could be corrosive during some phase of the production and/or manufacturing process when contaminants could be introduced.” The advisory was consistent with statements made by the agency in the preamble to the original rulemaking. preamble, nor the advisory conveyed that operators must first have knowledge or reasonable belief that a product would corrode the pipeline before triggering § 195.579(a). 22 Contrary to the interpretation advanced by BFPL, neither the regulation, its Petitioner cited two court decisions that it claimed supported the position that an agency may not rely on interpretive guidance to expand a regulation without going through notice and comment.23 Since the finding of violation was not based on the advisory or interpretive guidance, the two decisions cited by Petitioner are inapplicable. 24 19 See Final Order at 18 (finding that “[g]iven the pipeline failures caused by internal corrosion, BFPL was required under§ 195.579(a) to investigate the corrosive effects of the hazardous liquid transported in its pipeline system.”). 20 Brief at 24 (stating “there must be some type of prior knowledge or reasonable belief, based on the circumstances, that the hazardous liquid would corrode the pipeline.”); see also Final Order at 17. 21 Proper Identification of Internal Corrosion Risk, 73 Fed. Reg. 71,089 (Nov. 24, 2008). 22 Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines, 66 Fed. Reg. 66,994, 67,000 (Dec. 27, 2001) (stating the rule “requires operators to investigate the effects of transporting hazardous liquid or carbon dioxide which could corrode the pipeline, and take adequate steps to mitigate corrosion.”). 23 Petition at 5, citing Natural Resources Defense Council v. EPA, 643 F.3d 311, 321 (D.C. Cir. 2011); and National Mining Ass’n v. Jackson, 768 F.Supp.2d 34, 49 (D.D.C. 2011). 24 Agencies may issue regulatory interpretations in accordance with 5 U.S.C. § 553(b)(A). An “administrative interpretation . . . becomes of controlling weight unless it is plainly erroneous or inconsistent with the regulation.” Bowles v. Seminole Rock & Sand Co., 325 U.S. 410 (1945).#

520095042_Decision on the Petition for Reconsideration_03292012_text.pdf, page 76 In addition to the above legal arguments, Petitioner maintained that as a factual matter the internal corrosion leaks experienced on the BFPL pipeline system were not sufficient evidence to establish that the product transported would corrode the pipeline. Petitioner made this same argument prior to issuance of the Final Order, claiming the leaks were disconnected in time, location, operations, and type of crude.25 The Final Order has already determined that BFPL “may not ignore information about [the] internal corrosion leaks on its pipeline merely because it does not consider the leaks to be related in time or location. Likewise, the fact that leaks occurred on idle lines or dead legs is no excuse to imagine stronger evidence that an operator must take action under § 195.579(a) than the not to investigate the corrosive effects.”26 I find no reason to alter that determination. It is hard occurrence of multiple leaks on its pipeline system that were caused by internal corrosion. Finally, Petitioner maintained there was no evidence in the record that the leaks resulted from corrosion caused by “the specific type of liquid transported” by BFPL.27 I find no support in the record for Petitioner’s assertion. The company’s own records indicate that the leaks were caused by internal corrosion. As noted in the Final Order, even if an operator believes the commodity it transports is not normally corrosive, contaminants may be introduced during upset conditions when untreated corrosive materials may bypass the treatment process and enter the pipeline. 28 For the above reasons, I confirm that BFPL committed a violation of § 195.579(a). BFPL’s petitions to withdraw the finding of violation and associated compliance terms for Item 14 are denied. The stay granted on January 13, 2012, is hereby lifted. Petitioner must complete the actions required by the Compliance Order associated with Item 14 (paragraph 4 on page 26 of the Final Order) and submit documentation demonstrating compliance, as set forth therein, within 60 days of the date of this Decision. Except as specified above for Item 13, all other terms of the Final Order remain in effect and are not modified by this Decision. This Decision on Reconsideration is the final administrative action in this proceeding. ___________________________________ ____________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety 25 Brief at 24-25. 26 Final Order at 18. 27 Petition at 6. 28 Final Order at 18.#

520095042_closure letter_06262012_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED June 26, 2012 Mr. Tad True Vice President Belle Fourche Pipeline Company 455 North Popular Casper, WY 82601 CPF 5-2009-5042 Dear Mr. True: On November 21, 2011, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to Belle Fourche Pipeline Company 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, Chris Hoidal Director, Western Region Pipeline and Hazardous Materials Safety Administration cc: PHP-60 Compliance Registry PHP-500 G. Davis (#120773)#

520095042_Final Order_11212011_text.pdf, page 1Official PDFNOV 21 2011 Mr. Tad True Vice President Belle Fourche Pipeline Company 455 North Popular Casper, WY 82601 Re: CPF No. 5-2009-5042 Dear Mr. True: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation, withdraws several allegations, assesses a reduced civil penalty of $131,900, and specifies actions that must be taken by Belle Fourche 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. Alan Mayberry, Deputy Associate Administrator for Field Operations, Pipeline Safety Mr. Chris Hoidal, Director, Western Region, PHMSA Mr. Colin Harris, Holme Roberts & Owen LLP 1801 13th Street, Suite 300, Boulder, CO 80302-5259 CERTIFIED MAIL – RETURN RECEIPT REQUESTED [71791000164202826396]#

520095042_Final Order_11212011_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 ) Belle Fourche Pipeline Company, ) CPF No. 5-2009-5042 ) ) ) Respondent. ) ____________________________________) FINAL ORDER On August 24 through 28, 2008, 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 Belle Fourche Pipeline Company (BFPL or Respondent) in Casper, Wyoming. Belle Fourche operates approximately 600 miles of pipeline in Montana, North Dakota, and Wyoming transporting crude oil and refined petroleum products. 1 As a result of the inspection, the Director, Western Region, PHMSA (Director), issued to Respondent, by letter dated December 30, 2009, 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 Respondent had committed 13 violations of 49 C.F.R. Part 195 and proposed a civil penalty of $221,200 for the alleged violations. The Notice also proposed to order that Respondent take certain measures to correct the alleged violations. BFPL responded to the Notice by letters dated February 19 and August 30, 2010 (collectively, Response). The company contested several of the allegations and requested a hearing. In accordance with 49 C.F.R. § 190.211, a hearing was held on September 9, 2010, in Lakewood, Colorado, with an attorney from the Office of Chief Counsel, PHMSA, presiding. After the hearing, Respondent provided additional written material for the record by letter dated October 11, 2010 (Brief). FINDINGS OF VIOLATION The Notice alleged that Respondent committed violations of 49 C.F.R. Part 195, as follows: Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), which states: 1 This information is reported by Respondent pursuant to 49 C.F.R. § 195.49.#

520095042_Final Order_11212011_text.pdf, page 32 § 195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. The Notice alleged that Respondent violated § 195.402(a) by failing to review or revise its operations and maintenance (O&M) manual at least once each calendar year from 2005 to 2008. BFPL’s O&M manual obtained during the PHMSA inspection in August 2008 was dated February 2005 and stamped “Rev. 1.0,” suggesting the company had not revised the document since 2005. Respondent’s compliance coordinator stated during the inspection that BFPL had not reviewed or revised the O&M manual since 2005.2 At the hearing, Respondent explained that the revision number and date on the O&M manual were oversights and that statements by the employee during the agency’s inspection were misinformed and erroneous. Respondent presented a witness who testified that he had personally performed annual reviews of BFPL’s O&M manual in accordance with § 195.402(a) since 2006. Respondent also introduced completed “Revision Request Forms,” which show that annual reviews were performed, and as a result of those reviews, that certain determinations were made to revise the procedures.3 The Director stated at the hearing that he recommended withdrawing Item 1 based on the company’s assertions and submissions. For this reason, Respondent provided no additional information regarding Item 1 in its post-hearing Brief.4 After considering all of the evidence and the explanation provided by BFPL that the company conducted annual reviews and made revisions to its O&M manual during the period in question, the Director has recommended this allegation of violation be withdrawn. Accordingly, I am withdrawing this allegation of violation. Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a) and (c)(12), which state: § 195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations 2 Violation Report at 3. 3 Respondent Hearing Exhibit 11. 4 Brief at 2.#

520095042_Final Order_11212011_text.pdf, page 43 and maintenance activities and handling abnormal operations and emergencies . . . . (c) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following to provide safety during maintenance and normal operations: . . . (12) Establishing and maintaining liaison with fire, police, and other appropriate public officials to learn the responsibility and resources of each government organization that may respond to a hazardous liquid or carbon dioxide pipeline emergency and acquaint the officials with the operator’s ability in responding to a hazardous liquid or carbon dioxide pipeline emergency and means of communication. The Notice alleged that Respondent violated § 195.402(a) and (c)(12) by failing to follow the company’s written procedures for liaison with fire, police, and other appropriate public officials. Specifically, the Notice alleged that BFPL’s written procedures for public awareness required the compilation of certain data, including the names, addresses, and phone numbers of local emergency officials who would respond to a hazardous liquid pipeline emergency. During the inspection, Respondent had no documentation that it had collected such data and performed the required liaison activities. The Notice further alleged that BFPL had previously been issued a warning for this issue. 5 The evidence in the record includes the portion of Respondent’s O&M manual requiring the company to “Compile data (Organizations, names of contact personnel, phone no’s (emergency and regular No’s), and addresses of all Emergency Officials within the vicinity (area of jurisdiction) of the pipeline route or facility[sic].”6 At the hearing and in its Brief, Respondent did not contest the allegation of violation, but provided information to demonstrate that the company has now prepared a list of all the relevant police and fire departments, county emergency managers, and public officials in order to maintain liaison. Respondent said that it has also become a member of the relevant state pipeline associations, which affords the company an opportunity to maintain liaison with required emergency responders and public officials. After considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.402(a) and (c)(12) by failing to follow its written procedures for establishing and maintaining liaison with fire, police, and other appropriate public officials. Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a) and (c)(13), which state: § 195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations 5 In the Matter of Belle Fourche Pipeline Co., Final Order, CPF No. 5-2007-5002, at 5, 2008 WL 1981035 (Apr. 28, 2008). 6 Violation Report, Exhibit B.#

520095042_Final Order_11212011_text.pdf, page 54 and maintenance activities and handling abnormal operations and emergencies . . . . (c) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following to provide safety during maintenance and normal operations: . . . (13) Periodically reviewing the work done by operator personnel to determine the effectiveness of the procedures used in normal operation and maintenance and taking corrective action where deficiencies are found. The Notice alleged that Respondent violated § 195.402(a) and (c)(13) by failing to follow the company’s written procedures for reviewing the work done by personnel to determine the effectiveness of O&M procedures and to take corrective action to address deficiencies. Specifically, the Notice alleged that Section 3.8 of BFPL’s O&M manual required the company to periodically review the work done by personnel, but at the time of the inspection, Respondent had no records that such reviews had ever been conducted. The evidence in the record includes Section 3.8 of BFPL’s O&M procedures, which provides that Respondent will “review the performance of personnel and the contents of this manual at intervals not to exceed 15 months, but at least once each calendar year, to ensure the effectiveness of this manual.”7 The Violation Report also notes that BFPL’s compliance coordinator stated that he did not think there had ever been a formal review of personnel work to determine the effectiveness of the O&M procedures.8 In its Response, Respondent stated that it believed field employees had conducted the required reviews, although the company had not yet located any specific record of such reviews. At the hearing, Respondent presented a witness who testified that he had performed periodic review of work done by personnel as part of the company’s operator qualification (OQ) program. During that process, the witness explained, employees were trained to perform certain tasks, and once qualified, would then be observed performing the task. If any issues arose during their performance of such tasks, including deficiencies in the procedures themselves, the company would take corrective action to change the procedures accordingly. BFPL also introduced into evidence an affidavit by the same witness, who attested as follows: I have periodically reviewed the work performed by Belle Fourche Pipeline Company employees to determine the effectiveness of the procedures found in the O&M Manual. In compliance with 49 C.F.R. § 195.402(c)(13), I interact with the employees and advise them on their performance on a day to day basis, and assure that corrective action is taken when necessary. 7 Violation Report, Exhibit C. 8 Violation Report at 6.#

520095042_Final Order_11212011_text.pdf, page 65 During the hearing, the Director recommended withdrawing Item 3 based on the company’s assertions and submissions at the hearing. For this reason, Respondent provided no additional information regarding Item 3 in its post-hearing Brief.9 After considering the evidence and the explanation provided by BFPL that the company followed its procedures, the Director has recommended this allegation of violation be withdrawn. Accordingly, I am withdrawing this allegation of violation. Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.404(b)(1), which states: § 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 § 195.404(b)(1) by failing to maintain daily discharge pressure records at the Guernsey Pump Station for at least 3 years. The Notice further alleged the company did not have a pressure recording device at that pump station. Included in the record as evidence of the violation is a photograph of the Fort Laramie pipeline and pump at Guernsey Station, showing an absence of either a pressure recording chart or related instrumentation for recording the discharge pressure of the pump. 10 The Violation Report also noted that Respondent’s Guernsey Station manager told the inspector that the company did not have any pressure records for its Fort Laramie pipeline.11 At the hearing and in its Brief, Respondent contended that the regulation does not require the company to install or use a pressure recording device at its pump station. Rather, BFPL argued that the regulation only requires operators to maintain daily records of discharge pressure if the company collects such information. 12 BFPL explained that since it does not collect daily pressure information for the Guernsey station, the company did not violate § 195.404(b)(1) by not maintaining daily discharge pressure records. Respondent also explained that the pump at Guernsey station is insufficient to exceed maximum operating pressure (MOP) during normal or abnormal operations, and that the operator had previously determined that the discharge pressure could only reach 182 pounds per square in gauge (psig), less than 20% SMYS, based on the pump curves. because there was no risk of overpressure. 13 The company had concluded that it did not need a pressure recording device Section 195.404(b)(1) requires that operators maintain “daily operating records that indicate . . . [t]he discharge pressure at each pump station.”14 The regulation does not contain any 9 Brief at 4. 10 Violation Report, Exhibit D. 11 Violation Report at 7. 12 Brief at 5. 13 A pump curve is a graphical description of a centrifugal pump’s performance, that is the pump head (or pressure) versus the flow rate, expressed in feet of head (or feet of water) units. One foot of “head” equates to approximately 0.433 psig of “pressure.” BFPL submitted for the record the pump curve. Respondent Hearing Exhibit 15. 14 (emphasis added).#

520095042_Final Order_11212011_text.pdf, page 76 exemptions for pumps that will not exceed MOP, or for pumps that do not have recording devices installed. Respondent has therefore suggested an interpretation of § 195.404(b)(1) that is not supported by the language of the rule. Under the regulation, BFPL must have the means to record the discharge pressure at each pump station and must maintain daily records of that information, regardless of the particular characteristics of the pump station. The evidence demonstrates that BFPL did not maintain daily discharge pressure records at the Guernsey Pump Station for at least 3 years. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.404(b)(1) by failing to maintain daily discharge pressure records at the Guernsey Pump Station for at least 3 years. Item 5: 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 . . . (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 § 195.404(c)(3) by failing to maintain records of a breakout tank inspection until the next inspection. Specifically, the Notice alleged that BFPL’s tank data sheets indicated that it performed an API Standard 653 out-of-service internal inspection of the Sussex breakout tank in 2001, and had not yet performed the next internal inspection. The Notice further alleged that the company did not have any records from the 2001 internal inspection required to be maintained pursuant to § 195.404(c)(3). The evidence in the record of the violation includes BFPL’s tank data sheet showing that an internal inspection of the Sussex Breakout Tank was conducted in June 2001. In its Response, BFPL explained that while it did perform some work on the breakout tank in 2001, it did not perform an API Standard 653 internal inspection and therefore did not maintain a record of the work. At the hearing, Respondent presented testimony from its Area Supervisor responsible for operations of the tank in 2001 who testified that the company did not perform an API Standard 653 internal inspection in 2001. The witness stated that the record cited in the Notice, which was the basis for the allegation, was actually an error, created years after 2001 as an intended summary of historical inspections. The company further explained that the tank had just been installed in 1997, and therefore it would not have been reasonable for the company to perform such an in-depth internal inspection after only 4-5 years when the interval for such inspections can be up to 20 years under the API Standard. After considering all of the evidence in the record, I find the evidence demonstrates that it was more likely that BFPL did not perform an API Standard 653 internal inspection in 2001 and that the company’s record provided to PHMSA during the inspection was in error. Of particular relevance is that the tank in question was constructed in 1997 and would not have been due for an API Standard 653 internal inspection in 2001. Given the BFPL employee’s sworn testimony that no such inspection occurred in 2001, and that the entry was in error, I find the evidence#

520095042_Final Order_11212011_text.pdf, page 87 supports withdrawing this allegation of violation. Accordingly, I am withdrawing this allegation of violation. Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.406(b), which states: § 195.406 Maximum operating pressure. (a) . . . . (b) No operator may permit the pressure in a pipeline during surges or other variations from normal operations to exceed 110 percent of the operating pressure limit established under paragraph (a) of this section. Each operator must provide adequate controls and protective equipment to control the pressure within this limit. The Notice alleged that Respondent violated § 195.406(b) by failing to have protective equipment at the Guernsey Pump Station to control pressure from exceeding 110 percent of the MOP during surges either at the station or on the pipeline downstream from the station. Included in the record as evidence of the violation are photographs that show the absence of an overpressure safety device at the Guernsey Station and on the pipeline downstream from the pump. In addition, during the PHMSA inspection, Respondent’s station operator stated that overpressure control devices are not needed on the Fort Laramie line because the pump curves prove that pressure cannot exceed MOP.15 At the hearing and in its Brief, Respondent argued that the company’s pump curve demonstrates that the Guernsey Pump Station cannot produce pressure exceeding 182 psig on the Ft. Laramie line, which is less than 20% of the MOP of the pipeline. A witness also testified at the hearing that the geography and flat terrain would not contribute to surges in the line. Since the pipeline cannot exceed MOP, even during surges, BFPL argued that it is not required to provide any additional “controls and protective equipment” to control the pressure within 110% of MOP under the regulation. BFPL acknowledged that it could not submit for the record any documented analysis supporting its determination that pressure could not exceed MOP other than the pump curve. At the hearing, the Director acknowledged that it may be conceivable for an operator to demonstrate through a documented analysis that no additional protective pressure controls are necessary for a pipeline based on certain characteristics of the line, such as MOP, the physical limitations of the pump, and geography. In such a situation, however, the Director explained that PHMSA would normally expect a rigorous surge pressure analysis and documentation to demonstrate that no additional protective pressure controls are necessary. Both parties agreed that pipelines can at times experience surges in pressure beyond the levels created by the pump alone. As explained above, a pump curve is a graphical description of a centrifugal pump’s performance, that is, pump head (or pressure) versus flow rate. The pump curve submitted by Respondent demonstrates the maximum head pressure that can be produced by the Guernsey Station pump. At a zero discharge flow rate, the pump would produce a head pressure of approximately 450 feet of water (approximately 195 psig). In addition, there is an elevation drop 15 Violation Report at 9.#

520095042_Final Order_11212011_text.pdf, page 98 of approximately 225 feet from Guernsey Station to the Ft. Laramie pipeline terminus. Considering the elevation change, the pump could conceivably produce a pressure at the pipeline terminus of approximately 675 feet of water (450 + 225), or approximately 292 psig (195 + 97), which is far less than the 1468 psig design pressure of the pipeline. In addition to the static condition (zero flow or “dead head”), an operator usually would also be expected to perform an actual surge analysis to demonstrate maximum pressure that could be reached in a transient condition, such as during a sudden valve closure or pump shutdown. During a surge, the pressure in the line could conceivably be higher for a short period of time than the zero flow condition described above. This is due to the pressure wave that travels inside the pipeline during a rapid transient. In the present case, I find it that even at transient conditions, pressure in the pipeline could not reach the design pressure of the pipeline. Therefore, there is no need for additional controls or protective equipment under the current operating configuration (i.e., only the current pump provides pressure to the segment). After considering the evidence and the explanation provided by BFPL, the Director has recommended this allegation of violation be withdrawn. Accordingly, I am withdrawing this allegation of violation. Item 8: The Notice alleged that Respondent violated 49 C.F.R. § 195.420(b), which states: § 195.420 Valve maintenance. (a) . . . . (b) Each operator shall, at intervals not exceeding 7½ months, but at least twice each calendar year, inspect each mainline valve to determine that it is functioning properly. The Notice alleged that Respondent violated § 195.420(b) by failing to inspect mainline valves at least twice during the 2006 calendar year and at intervals not exceeding 7½ months between 2006 and 2007. Included in the record as evidence of the violation are 17 pages of valve inspection records from 2005 through 2008, which the Notice alleged demonstrate that BFPL missed either or both of the maximum inspection intervals on 47 occasions during the period in question. At the hearing and in its Brief, Respondent acknowledged some of the violations occurred as alleged in the Notice. 16 Specifically, BFPL acknowledged 16 instances of valves not being inspected during the 2006 calendar year, 17 and 10 instances of valves not being inspected at 7½- arguing that: 15 had been inspected at the proper intervals during quarterly pigging activities; 2 had been inspected at the proper intervals, but PHMSA miscalculated the 7½-month interval; 2 were valves not subject to the pipeline safety regulations; and 2 were duplicate entries on the list. month intervals.18 Respondent contested the remaining 21 instances of missed valve inspections, 16 See Respondent Hearing Exhibit 17. 17 Those 16 instances involve the following valves: 010-001; 010-002; 010-003; 010-0056; 010-010; 010-011; 010- 101; 015-001; 015-002; 015-004; 015-005; 101-006; 101-008; 101-009; 6-inch Tie In; and Poison Draw 8-inch. 18 Those 10 instances involve the following valves: 010-005; 010-006; 010-008; 010-009; 010-010; 015-001; 015- 002; 069-0005; 6-inch Tie In; and Poison Draw 8-inch.#

520095042_Final Order_11212011_text.pdf, page 109 One of BFPL’s arguments, that PHMSA miscalculated the 7½-month interval, is based on the assertion that the agency simply added 225 days to the prior valve inspection date. BFPL contended that because the regulation establishes the maximum interval as “7½ months,” not 225 days, it was permissible for the company to perform inspections up to the 15th day of the 8th month following the most-recent inspection. The company contended that two instances of the alleged violations were inspections that actually occurred within this interval. introduced evidence to support its assertions with regard to the other contested instances, including charts and pigging logs. 19 BFPL also After reviewing the evidence in the record, I find Respondent has demonstrated the validity of its claims. Namely, Respondent has demonstrated that of the 21 instances of alleged violations that Respondent contested: 17 had been inspected at the proper intervals; 2 were valves on unregulated gathering lines not subject to this pipeline safety requirement; and 2 were duplicate entries on the list. Accordingly, these allegations of violation are hereby withdrawn. Furthermore, I find the regulation does not preclude Respondent’s method of calculating the 7½- month maximum inspection interval. For this reason, Respondent has demonstrated that its noncompliance with respect to 10 of the other instances of violations lasted, on average, for only 12 days. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.420(b) by failing to inspect mainline valves at the mandated intervals on 26 occasions. Item 9: 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 . . . 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 § 195.428(a) by failing to inspect and test pressure limiting devices at five different locations within intervals not exceeding 15 months, but at least once each calendar year. Specifically, the Notice alleged that: (1) BFPL failed to inspect and test station pressure controls at the Donkey Creek and Hwy 450 stations during the 2007 calendar year; (2) that inspection intervals of those same controls exceeded 15-month intervals by 68 days and 98 days, respectively; (3) that BFPL exceeded the 15-month interval for inspecting and testing pressure controls at the Seiler station by 120 days in 2007; and (4) that BFPL exceeded the 15-month interval for inspecting and testing pressure controls at the Sussex pump station and Guernsey terminal in 2008 by 145 days and 105 days, respectively. The Violation Report includes nine pages of Safety Device Inspection Forms from 2006 through 2008 demonstrating that Respondent had performed inspections and tests of the pressure limiting 19 Also as a result of this calculation, Respondent maintained that certain other inspections were missed by an average of only 12 days, not 16 days as implied in the Notice.#

520095042_Final Order_11212011_text.pdf, page 1110 devices at intervals that exceeded the maximum 15-month interval or that were not at least once per calendar year. 20 With regard to the alleged violation pertaining to the Donkey Creek facility, Respondent contested the allegations on the grounds that new devices had been installed at the station in 2007. At the hearing and in its Brief, the company explained that in October 2007, it replaced Pumps 1, 2, and 3 and added a new Pump 4 at the station, effectively restarting the inspection intervals for those pressure controls. The Director contended at the hearing that Respondent never demonstrated the new pumps were actually inspected and tested (e.g., calibrated) when they were installed in 2007. In its Brief, however, Respondent submitted additional documentation to validate that the new pumps had been inspected and tested as part of the installation process. After reviewing the evidence in the record, I find that Respondent has demonstrated the validity of its claim that the Donkey Creek station was reconfigured in 2007 by replacing and adding pumps. The pressure limiting devices installed as part of that reconfiguration were tested and inspected as part of the installation process in October 2007, roughly 13 months after the previous test of pressure limiting devices at Donkey Creek. For this reason, I find the evidence supports withdrawing the alleged violation pertaining to the Donkey Creek facility. With regard to the remaining allegations, Respondent initially argued in its Response that the Notice failed to identify the precise equipment at issue, the equipment is not subject to § 195.428(a), and the regulation is impermissibly vague. At the hearing, however, Respondent acknowledged that it understood the precise equipment at issue in the allegations and that the devices are indeed pressure limiting devices subject to the inspection and testing requirements in § 195.428(a). The company also stated that it could not provide records to rebut the alleged violation. In its Brief, BFPL acknowledged that it did not fully comply with this requirement. 21 Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.428(a) by failing to inspect and test pressure limiting devices at the Hwy 450 and Seiler stations in 2007, and at the Sussex pump station and Guernsey terminal in 2008. The allegations with regard to the Donkey Creek station are withdrawn. Item 10: The Notice alleged that Respondent violated 49 C.F.R. § 195.428(d), 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 . . . 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 . . . . 20 Violation Report, Exhibit H. 21 Brief at 16.#

520095042_Final Order_11212011_text.pdf, page 1211 (d) After October 2, 2000, the requirements of paragraphs (a) and (b) of this section for inspection and testing of pressure control equipment apply to the inspection and testing of overfill protection systems. The Notice alleged that Respondent violated 49 C.F.R. § 195.428(d) by failing to inspect and test certain overfill protection systems (i.e., high level alarms) at intervals not exceeding 15 months, but at least once each calendar year. Specifically, the Notice alleged that BFPL had never inspected and tested the high level alarms at three breakout tanks associated with the Sussex Diesel Line: the Sussex Pump Station Breakout Tank; Davis Station Breakout Tank (Tank 74); and Hawk Point Terminal Breakout Tank. Evidence in the record includes the PHMSA inspector’s notes from the inspection, during which BFPL could not provide any records to demonstrate the high-level alarms had been inspected and tested since 2001. In addition, the PHMSA inspector interviewed BFPL personnel who stated that they did not think the high-level alarms had been inspected and tested at any frequency. 22 Respondent initially argued in its Response that the Notice failed to identify the precise equipment at issue, the equipment is not subject to § 195.428(d), and the regulation is impermissibly vague. At the hearing, however, Respondent acknowledged that overfill protection (high level) alarm devices existed on the three tanks identified in the Notice, and that the company did not have records to demonstrate the devices had been tested at the required intervals under the regulation. The company explained, however, that it could provide records of “hand gauging” the tanks every month to verify the accuracy of the levels displayed by the SCADA system. The Director explained at the hearing that hand gauging would not have tested the mechanical- electrical high alarm switches on the tanks, but would only test the accuracy of the SCADA tank level indications. In its Brief, however, Respondent contended that hand gauging resulted in “substantial compliance” with § 195.428(d), explaining again that the company verified that tank levels were consistent with SCADA read-outs. The company contended that it had also “visited” each breakout tank at least once daily. The overfill protection (high level) alarm devices on the three tanks identified in the Notice send an alarm to personnel when product in the tank is approaching a level that is close to overfilling or when the tank has been overfilled. Respondent’s hand gauging to verify the accuracy of SCADA tank level indicators never actually inspected and tested the overfill alarm devices to determine they were functioning properly and were adequate for the service in which they were to be used. Therefore the hand gauging practice did not achieve compliance with § 195.428(d). There is also no evidence that daily “visits” to the tanks achieved compliance. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.428(d) by failing to inspect and test the overfill protection systems at three breakout tanks. Item 11: The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b), which states: § 195.432 Inspection of in-service breakout tanks. 22 Violation Report at 16.#

520095042_Final Order_11212011_text.pdf, page 1312 (a) . . . . (b) Each operator shall inspect the physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according to section 4 of API Standard 653 . . . . 23 The Notice alleged that Respondent failed to inspect the physical integrity of certain in-service breakout tanks according to Section 4 of API Standard 653. Section 4 provides for the evaluation of the suitability of existing tanks for continued service and for making decisions involving repairs. Section 4 references the tank inspection intervals contained in Section 6 of the API Standard. Specifically, the Notice alleged that Respondent failed to perform an external inspection of the Sussex Breakout Tank within the 5-year interval prescribed in API Standard 653, Section 6.3.2. Evidence in the record of the violation includes tank data sheets that fail to document any external inspections of the tank between 2001 and 2006.24 This Item is related to Item 5, which alleged that Respondent failed to maintain a record of the internal inspection of the Sussex breakout tank in 2001. In Item 5, I found that Respondent never performed an internal inspection of the tank in 2001 based on a preponderance of the evidence. In its Brief, BFPL characterized the separate alleged violation of § 195.432(b) in Item 11 as “premised on the mistaken assumption by PHMSA that an API 653 Internal Inspection occurred in 2001. Since no such inspection occurred, there was no obligation to conduct the cited external inspection.”25 Respondent’s contention, however, is not an accurate characterization of either the alleged violation in Item 11 or the requirement in § 195.432(b). This allegation is that Respondent failed to perform an external inspection of the Sussex Breakout Tank at the interval set forth in API Standard 653, Section 6.3.2, which provides: “All tanks shall be given a visual external inspection by an authorized inspector. This inspection shall be called the external inspection and must be conducted at least every 5 years. ” The requirement to perform an external (in-service) inspection of “all tanks” every 5 years is independent of the separate requirement in API Standard 653 to perform internal (out of service) tank inspections. Regardless of whether or not Respondent completed an internal inspection in 2001, the regulation still mandated that it conduct an external inspection at the maximum interval of 5 years. Since the evidence in the record demonstrates that Respondent never conducted an external inspection in the 5-year period between 2001 and 2006, BFPL failed to comply with this requirement. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.432(b) by failing to inspect the physical integrity of the breakout tank according to API Standard 653. 23 Section 195.432(b) was amended after the inspection. It presently reads: “Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according to API Standard 653 . . . .” Pipeline Safety: Periodic Updates of Regulatory References to Technical Standards and Miscellaneous Edits, 75 Fed. Reg. 48,593, 48,607 (Aug. 11, 2010). 24 Violation Report, Exhibit E. 25 Brief at 19.#

520095042_Final Order_11212011_text.pdf, page 1413 Item 12: The Notice alleged that Respondent violated 49 C.F.R. § 195.436, which states: § 195.436 Security of facilities. Each operator shall provide protection for each pumping station and breakout tank area and other exposed facility (such as scraper traps) from vandalism and unauthorized entry. The Notice alleged that Respondent violated § 195.436 by failing to provide adequate protection from vandalism and unauthorized entry for each pump station and breakout tank. Specifically, the Notice alleged that BFPL had not installed any perimeter fencing around the Donkey Creek Pump Station. The Notice further alleged that BFPL had only installed 4.5-foot high woven steel grid wire fence with 2 strands of barbed wire around the Sussex Pump Station and Sussex Breakout Tank, which were not adequate to prevent vandalism and unauthorized entry to the facility. The evidence in the record includes photographs that show the absence of fencing around Donkey Creek Pump Station and a representative portion of the type of fencing at the Sussex Pump Station and Breakout Tank. 26 The Violation Report further noted that Respondent’s compliance coordinator stated during the inspection that security fencing was not necessary for either facility because of the remote location and presence of personnel at the Donkey Creek facility.27 At the hearing and in its Brief, Respondent contested the allegation of violation, stating there is adequate protection at Donkey Creek through 24/7 staffing and because the location of the station is two miles away from the closest public road. As to the Sussex facility, BFPL argued that the facility has a security fence as documented in the Notice and is located five miles from the closest public road. Respondent also asserted that § 195.436 does not specify a uniform standard, and that protection for each station may differ depending on the unique circumstances of the facility. BFPL cited to a previous agency interpretation that the company argued states that fencing is not required.28 Respondent also claimed that during a previous PHMSA inspection, agency inspectors had accepted that the remoteness of the facilities contributed to the adequacy of the security. At the hearing, the Director argued that the previous agency interpretation established that adequate security fencing or continuous surveillance is required under § 195.436 to protect against vandalism and unauthorized entry. The Director also explained that at Donkey Creek, the on-site person has job duties other than surveillance, including operation of the pipeline. Although not cited by either party during the hearing, PHMSA has previously issued final orders deciding this issue of contention.29 As those cases demonstrate, PHMSA has routinely rejected 26 Violation Report, Exhibit I. 27 Violation Report at 20. 28 Brief at 20 (citing OPS Hearing Exhibit 7: Interpretation of 49 C.F.R. § 195.436 (Aug. 13, 1980)). 29 See, e.g., In the Matter of Sunoco Pipeline, L.P., Final Order, CPF No. 4-2007-5040, 2010 WL 5761108 (Dec. 16, 2010); In the Matter of Plains Pipeline, L.P., Final Order, CPF No. 4-2009-5005, 2010 WL 2228553 (Apr. 6, 2010);#

520095042_Final Order_11212011_text.pdf, page 1514 the argument that § 195.436 permits a lower level of protection merely because a facility is located in a remote area. PHMSA has also rejected the argument that livestock fencing provides adequate protection from vandalism and unauthorized entry. The 1980 interpretation cited by both parties states that while “fencing is not necessarily required, one of the ways to comply with this regulation would be to construct a fence adequate to protect the facility from vandalism and wire livestock fence or an eight-foot chain link fence with no barbed wire are both inadequate to unauthorized entry.”30 The interpretation explains further that either a simple four-strand, barbed meet the requirements of the regulation. In addition, surveillance that consisted of only hourly inspections also did not meet the requirements. The evidence in the record demonstrates that Respondent’s Donkey Creek facility has no perimeter fencing and no other means of protecting the facility from vandalism and unauthorized entry. While there is staffing at the facility, the mere presence of an individual is not sufficient to provide continuous security when that person has primary duties other than security surveillance, including such duties as operating the pipeline facility. With regard to the Sussex Pump Station and Breakout Tank, the evidence in the record demonstrates that it is surrounded by a fence 4.5 feet high, comprised of wire grid, concrete reinforced panels with two strands of barbed wired above the panels. Based on the examples of inadequate security fencing from the 1980 interpretation and prior cases, I similarly find this fence to be inadequate because it is only 4.5 feet high and has large grid openings that would be easy hand or foot holds with which to climb. The remoteness of either facility does not, by itself, constitute additional security precautions. In fact, remoteness could make such a facility more attractive to vandalism or unauthorized entry. For the above reasons, I find that Respondent violated 49 C.F.R. § 195.436 by failing to provide adequate protection from vandalism and unauthorized entry for the Donkey Creek Pump Station and the Sussex Pump Station and Breakout Tank. Item 13: The Notice alleged that Respondent violated 49 C.F.R. § 195.577(a), which states: § 195.577 What must I do to alleviate interference currents? (a) For pipelines exposed to stray currents, you must have a program to identify, test for, and minimize the detrimental effects of such currents. The Notice alleged that Respondent violated § 195.577(a) by failing to have and implement a program to identify, test for, and minimize the detrimental effects of stray currents. Specifically, the Notice alleged that BPFL’s cathodic protection monitoring records for the 12-inch Donkey Creek Pipeline in the area of Guernsey and Ft. Laramie stations for the 2006 calendar year show several test stations with high “off” levels, commonly indicative of cathodic protection interference currents adversely affecting a pipeline. The Notice alleged that BFPL had not taken steps to perform an interference study to determine if there were interference currents or to mitigate any interference currents that existed. and In the Matter of Jayhawk Pipeline, L.L.C., Final Order, CPF No. 3-2002-5021, 2003 WL 25429861 (Dec. 11, 2003). 30 OPS Hearing Exhibit 7.#

520095042_Final Order_11212011_text.pdf, page 1615 The evidence in the record includes the cathodic protection survey records for the pipeline from January 2006 to December 2008. 31 In addition, during the inspection, BFPL’s Wyoming Corrosion Supervisor stated that performing interference current investigations was problematic because BFPL could not get cooperation from other pipeline operators in the area.32 In response to the allegation, Respondent contended both that the pipeline was not exposed to stray currents, and that even if the pipeline had been exposed to stray currents, BFPL had a program in place to identify, test for, and minimize the detrimental effects of such currents. At the hearing, Respondent contended that the readings referenced in the Notice did not indicate there were any detrimental stray currents because BFPL knew the source of the currents was other parties’ pipelines, and that the source was not deleterious to Respondent’s pipeline. In its Brief, BFPL explained that the pipelines in the area “are tied together with either piping, electrical grounding between the different pipeline companies in the area, or by bonds.” In addition, BFPL explained that the readings relied upon by PHMSA were not accurate because not all rectifiers had been interrupted, which gave “higher structure IR readings than if all the rectifiers tied to this line were interrupted.” Respondent also submitted evidence that in July 2009, the company performed a close interval survey (CIS) for the pipeline, which confirmed that no “detrimental stray currents” were impacting BFPL pipeline facilities in that area. The evidence in the record of the cathodic protection survey readings for Respondent’s pipeline indicate there were certain areas with high “off” levels. Even if not all rectifiers had been interrupted, as Respondent contended, the indication by the readings was that there were interference currents in the area of Respondent’s pipeline. At a minimum, Respondent was required to have a program to identify and test those indications of interference currents. Respondent’s defense to the allegation is based on its contention that it understood the source of these interference currents and believed they were not detrimental. Whether or not Respondent knew the source of interference currents in the area of its pipeline, or believed the source of those currents was not detrimental, § 195.577 still requires BFPL to have a program to identify and address those stray currents. The company’s belief that interference currents were not detrimental does not excuse it from the requirement to have a program for identifying and testing to ensure they are indeed not detrimental. The third-party who performed a CIS for Respondent in 2009 stated in a follow-up letter that, “Immediately prior to performing the CIS, potentials were measured at several representative test stations in the test area. Foreign CP Systems in the vicinity were then cycled to determine if they affected the subject pipeline. Current interrupters were then installed at Foreign CP Systems statement confirms there were stray currents in the area of Respondent’s pipeline, that is, currents from foreign sources were affecting the cathodic protection system on the pipeline. which were found to affect the pipeline segment along with all Company CP Systems.”33 This Since all indications were that Respondent’s pipeline was being exposed to stray currents, BFPL was required to have a program to identify, test for, and minimize the detrimental effects of such currents. 31 Violation Report, Exhibit J. 32 Violation Report at 21. 33 Respondent Hearing Exhibit 8.#

520095042_Final Order_11212011_text.pdf, page 1716 Respondent further contended that it had a program in place to identify, test for, and minimize the detrimental effects of such currents. BFPL claimed the reports used by PHMSA in support of the allegation demonstrated this program was in place and implemented. After reviewing this evidence, however, I fail to find how these cathodic protection survey readings could constitute “a program to identify, test for, and minimize the detrimental effects of such currents. ” The records are merely cathodic protection survey readings and contain no indication of stray current identifications, documentation of any testing of such currents for detrimental effects, or discussion of any efforts to minimize detrimental effects. Nor do I find any other evidence in the record that Respondent ever identified, tested for, or took actions to minimize the detrimental effects of any stray currents at that location until after PHMSA’s inspection of the facility in August 2008. Contrary to Respondent’s contention, the fact that BFPL took measures to investigate the stray currents after PHMSA’s inspection does not demonstrate that BFPL was in compliance at the time of PHMSA’s inspection. Prior to the PHMSA inspection, BFPL had merely assumed there were no problems in the area of its pipeline despite indications of stray currents, and never prepared and followed written procedures for determining the accuracy of its assumption. It was not until PHMSA identified the issue during an inspection that BFPL contracted for a third-party to study the issue. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.577(a) by failing to have and implement a program to identify, test for, and minimize the detrimental effects of stray currents. Item 14: The Notice alleged that Respondent violated 49 C.F.R. § 195.579(a), which states: § 195.579 What must I do to mitigate internal corrosion? (a) General. If you transport any hazardous liquid or carbon dioxide that would corrode the pipeline, you must investigate the corrosive effect of the hazardous liquid or carbon dioxide on the pipeline and take adequate steps to mitigate internal corrosion. The Notice alleged that Respondent violated § 195.579(a) by failing to investigate the corrosive effect of the hazardous liquid transported by its pipeline and to take steps to mitigate internal corrosion. Specifically, the Notice alleged that BFPL had experienced at least three pipeline leaks since 2006 due to internal corrosion, but never conducted an investigation of the corrosive effect of the hazardous liquid or took steps to mitigate the condition. The evidence in the record includes documentation of the following four leaks on BFPL’s pipeline system that were attributed to internal corrosion: (1) on April 30, 2006, near McKenzie, North Dakota, 25 barrels of crude oil were released during a failure; (2) on December 22, 2007, near Gillette, Wyoming, 40 barrels were released during a failure; (3) on July 15, 2008, near Gillette, Wyoming, 550 barrels were released during a failure; and (4) on March 18, 2009, near Moorcroft, Wyoming, 32 barrels were released during a failure of a non-regulated gathering line. The first three failures were required to be reported under 49 C.F.R. § 195.50. The record also includes accident report forms filed by Respondent for each of the three reportable accidents. All three forms show that Respondent determined the cause of each failure#

520095042_Final Order_11212011_text.pdf, page 1817 to be internal corrosion.34 The Violation Report noted that during the PHMSA inspection, BFPL’s DOT Compliance Coordinator stated that the company had not conducted an internal corrosion investigation in accordance with § 195.579(a).35 At the hearing and in its Brief, Respondent argued there is a discrepancy between the allegation in the Notice and the actual regulatory requirement. While the Notice alleged that Respondent was required to investigate corrosive effects if the product in its pipeline “could corrode a pipe,”36 BFPL contended that the regulation states that investigation of corrosive effects is only required when an operator transports a hazardous liquid that “would corrode the pipeline. ”37 BFPL argued the later requires a higher “threshold level of information or evidence to trigger the requirement” represented by prior knowledge or a reasonable belief on the part of the operator that the product would indeed corrode the pipeline.38 BFPL contended further that it never had knowledge or a reasonable belief that the product transported would corrode the pipeline. The various leaks identified in the Notice, Respondent asserted, did not cause the company to know or reasonably believe there was a risk of internal corrosion because the leaks were unrelated to one another, happened in two different states, involved different crude, occurred at different times, and two of them occurred on inactive line segments where there could have been standing oil or water in the pipe. Since Respondent did not know or reasonably suspect that the product transported would corrode the pipeline, BFPL maintained that it did not have a regulatory duty to investigate the product for corrosive effects.39 PHMSA has publicly communicated to pipeline operators that § 195.579(a) requires operators to determine if the hazardous liquids transported could corrode the pipeline, and the agency has never implied, as Respondent suggests, that there must first be confirmed knowledge or reasonable belief on the part of the operator that the product will cause internal corrosion. For example, PHMSA published an Advisory Bulletin in the Federal Register reminding operators that the regulations “require operators to determine if the hazardous liquids they are transporting could corrode the pipeline.”40 In addition, the original agency rulemaking that promulgated § 195.579(a) explained in the preamble that the standard “requires operators to investigate the effects of transporting hazardous liquid or carbon dioxide which could corrode the pipeline, and take adequate steps to mitigate corrosion.”41 34 Violation Report, Exhibit K. 35 Violation Report at 22. 36 Notice at 8 (emphasis added). 37 § 195.579(a) (emphasis added). 38 Brief at 24. 39 In its initial Response, Belle Fourche claimed the regulation is also “impermissibly and unconstitutionally vague and ambiguous” because PHMSA has not defined in the regulation the circumstances when an operator must investigate the corrosive effect of a hazardous liquid. BFPL did not raise this constitutional argument at the hearing or in its Brief. For the reasons set forth in this decision, I find the regulation is not “impermissibly and unconstitutionally vague and ambiguous,” and that the agency has also provided additional guidance to operators regarding the applicability of this safety standard. 40 Advisory Bulletin on the Proper Identification of Internal Corrosion Risk, 73 Fed. Reg. 71,089 (Nov. 24, 2008). 41 Final Rule on Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines, 66 Fed. Reg. 66,994, 67,000 (Dec. 27, 2001).#

520095042_Final Order_11212011_text.pdf, page 1918 PHMSA has applied the regulation in the same manner. In a prior enforcement decision that is similar in many respects to the present case, PHMSA determined that a pipeline operator violated § 195.579(a) when it failed to investigate the corrosive effect of the product transported after experiencing several leaks caused by internal corrosion. and on a lateral pipeline used for inputting trucked barrels of crude oil. Even though the operator had investigated the corrosive effects of the product on its mainline pipe, the operator violated § 195.579(a) when it failed to perform the same investigation for such non-mainline pipes where the leaks had occurred. 42 The leaks occurred on a dead leg BFPL’s situation is similar in that the company has experienced multiple leaks on its pipeline system due to internal corrosion, some of which occurred on idle or non-mainline pipe. In this case, however, there is no evidence that Respondent ever investigated the corrosive effects of the product, even on its mainline pipeline. The company may not ignore information about internal corrosion leaks on its pipeline merely because it does not consider the leaks to be related in time or location. Likewise, the fact that leaks occurred on idle lines or dead legs is no excuse not to investigate the corrosive effects. Internal corrosion may be caused by the corrosive effects of product being transported through a pipeline system. Even if an operator believes that the commodity it transports is not normally corrosive, PHMSA has found that contaminants can be introduced to noncorrosive products during production and manufacturing processes, such as during upset conditions at a processing plant or refinery. During upset conditions, untreated product may bypass the treatment process and enter the pipeline, introducing corrosive materials. Given the pipeline failures caused by internal corrosion, BFPL was required under § 195.579(a) to investigate the corrosive effects of the hazardous liquid transported in its pipeline system. The evidence demonstrates that BFPL failed to perform such an investigation. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.579(a) by failing to investigate the corrosive effects of the hazardous liquid transported by its pipeline. 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 $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 42 In the Matter of Sunoco Pipeline, L.P., Final Order, CPF No. 4-2007-5040, 2010 WL 5761108 (Dec. 16, 2010).#

520095042_Final Order_11212011_text.pdf, page 2019 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 $221,200 for the violations in Items 1, 5, 8, 9, 10, and 11. Since Items 1 and 5 have been withdrawn, penalties are not assessed for these items. Item 8: The Notice proposed a civil penalty of $30,800 for Respondent’s violation of 49 C.F.R. § 195.420(b). As discussed above, I found that BFPL failed to inspect mainline valves on 26 occasions at the maximum intervals required by regulation. I also withdrew allegations that Respondent violated the regulation on 21 additional occasions. In its Brief, Respondent argued that the penalty should be reduced for several reasons. First, Respondent contended, and I agree, that the circumstances of the violation warrant a reduction to the civil penalty to reflect that I have withdrawn 21 of the 47 instances of the alleged violation. Second, Respondent argued there was a “lack of any risk to health or safety” by the violation. I disagree with this contention. Properly functioning mainline valves are essential to the safe operation of hazardous liquid pipeline systems; they are used to limit the volume of product released in the event of a spill. One purpose of the mandatory valve inspection interval set forth in § 195.420(b) is to ensure that valve problems are identified and corrected before they impact the safety of the pipeline system. BFPL failed to inspect approximately 21 mainline valves at proper intervals on 26 occasions. Accordingly, I find BFPL’s failure to perform these timely inspections presented a pipeline safety risk. Third, Respondent argued that the Violation Report erroneously stated there were potential impacts to high consequence areas (HCAs) as a result of the violation, when there are not any HCAs in the area of the valves that had missed inspections. The only evidence presented in the Violation Report of the location of HCAs are several maps, but they are of such a large scale, and are not supported by additional documentation, that it is inconclusive as to whether there are the record, I agree the evidence does not support finding potential impacts to HCAs. In this regard, the gravity of the violation warrants a reduction to the proposed civil penalty. any HCAs in the area of the valves that had missed inspections.43 Accordingly, after reviewing Fourth, BFPL argued that the Violation Report included no evidence of the degree of culpability, but rather stated simply that the company was “culpable” because it had knowledge of the regulation. In prior final orders, I have found that when evaluating an operator’s culpability, I determine the extent to which the company deserves the blame for the violation that occurred.44 In this case, as the operator of the pipeline facility, BFPL is responsible for compliance and therefore is culpable for these violations of the pipeline safety regulations. I find no reason to determine there is any lesser degree of culpability on the part of Respondent for these violations. 43 Violation Report, Exhibit L. 44 In the Matter of Alyeska Pipeline Service Co., Decision on Petition for Reconsideration, CPF No. 5-2006-5018, 2010 WL 2228550, at 2-3 (Mar. 1, 2010) (citing the American Heritage Dictionary of the English Language 442 (4th ed. 2000)).#

520095042_Final Order_11212011_text.pdf, page 2120 Fifth, Respondent argued that it had demonstrated good faith in attempting to achieve compliance, as the company had implemented a “vigorous valve inspection program, that [the missed inspections] were isolated occurrences, and most importantly that a majority of the valves inspections in a timely manner, the numerous instances of missed valve inspections in this case preclude any penalty reduction for good faith in attempting to achieve compliance. at issue in fact were inspected.”45 While Respondent may have performed other valve Sixth, Respondent contested the statement in the Violation Report that “BFPL has a poor record of compliance with Part 195 requirements,” since there was no finding that BFPL previously violated this regulation. In prior final orders, I have found that “[w]hile a repeat violation of the exact same regulatory section is certainly the most acute example of a prior offense, I am not precluded from considering [a respondent’s] overall compliance history, including all previous violations of the pipeline safety regulations regardless of regulatory section number. ”46 Accordingly, when evaluating BFPL’s history of prior offenses, “I may consider not only instances of past violations of the same regulation, but also the company’s history of other offenses, such as prior violations of other regulations, the extent to which such violations resulted in civil penalties, and whether corrective action was necessary.”47 With regard to history of prior offenses, the Violation Report cited three prior enforcement actions issued against BFPL in the five-year period preceding the Notice in this case. In the prior enforcement actions, Respondent was found to have committed approximately 11 violations of the pipeline safety regulations, requiring the agency to order specific corrective measures to ensure compliance. In addition, those violations resulted in more than $90,000 in civil penalties. Accordingly, I have weighed Respondent’s history of prior offenses and find that when viewed as a whole, it supports the proposed penalty and does not warrant any reduction. Finally, BFPL argued the penalty should be reduced to reflect relatively lower penalty assessments in other PHMSA enforcement actions. Specifically, Respondent cited a previous final order in which PHMSA assessed a lower penalty against a different operator for failing to inspect and test nine mainline valves in violation of § 195.420(b). 48 PHMSA sets civil penalties by applying the statutory assessment criteria on a case-by-case basis. Given the unique facts of each offense, operating conditions of each pipeline, an operator’s individual compliance history, how the violation was discovered, its duration, whether the operator made a good faith effort to comply with the regulation prior to the inspection, and whether there was any immediate or potential safety or environmental impacts, it is not uncommon for there to be some variance in the penalties assessed for different operators’ violation of the same code section. This fact-sensitive approach is consistent with PHMSA’s largely performance-based regulatory scheme, which involves the consideration of risk factors 45 Brief at 12. 46 Alyeska Pipeline Service Co., CPF No. 5-2006-5018, at 3. See also 49 U.S.C. § 60122(b)(2)(B) and 49 C.F.R. § 190.225(b)(2), which authorizes PHMSA to consider such other matters as justice may require in determining the amount of a civil penalty. 47 Alyeska Pipeline Service Co., CPF No. 5-2006-5018, at 3. 48 See In the Matter of Texas Eastern Petroleum Products Co., Final Order, CPF No. 3-2004-5027, 2006 WL 3825327 (Jan. 3, 2006).#

520095042_Final Order_11212011_text.pdf, page 2221 and complexities unique to each pipeline system. Moreover, PHMSA has found it appropriate to increase many of its civil penalties over the years, including those for violations of assessment criteria. § 195.420(b).49 Therefore I do not find this is a reason to reduce the penalty in light of the other Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a reduced civil penalty of $15,800 for its violation of § 195.420(b). Item 9: The Notice proposed a civil penalty of $62,100 for Respondent’s violation of 49 C.F.R. § 195.428(a). As discussed above, I found that BFPL failed to inspect and test station pressure limiting devices at the Hwy 450 Station, Seiler Station, Sussex Pump Station, and Guernsey Terminal. I have withdrawn the allegations with regard to the Donkey Creek station. In its Response and Brief, Respondent argued that the penalty should be reduced for several reasons. First Respondent contended, and I agree, that the circumstances of the violation warrant a reduction to the civil penalty to reflect that I have withdrawn the allegations of violation with regard to the Donkey Creek station. Second, Respondent argued “there was no risk of harm to the environment or to public safety” from the violation. I disagree with this assertion, however. Properly functioning pressure control equipment provides critical protection against pipeline system failures caused by overpressure. Regular inspections of overpressure protection devices allow operators to identify and repair problems before more serious incidents occur, such as pipeline system failures. In fact, pipeline failures are known to have occurred as a direct result of a pipeline operator failing to perform regular inspections under this regulation. perform such inspections presented a pipeline safety risk. 50 Accordingly, I find BFPL’s failure to Third, Respondent contested the statements in the Violation Report that suggested the violations “could potentially impact” populated and ecological HCAs, including the North Platte River. Specifically, BFPL argued with regard to Highway 450 and Sussex stations that there are no HCAs that could be affected. At Guernsey terminal, Respondent contended that it would not be possible to experience an overpressure situation. Respondent also introduced as Exhibit 22 spill modeling data related to the North Platte River, which the company argued proves that a spill could not impact the river. Respondent did not discuss Seiler Station specifically. After reviewing the record, I find there is an absence of conclusive evidence of potential impacts to HCAs by this noncompliance. In this regard, the gravity of the violation warrants a reduction to the proposed civil penalty. Fourth, BFPL argued that the Violation Report included no evidence of any degree of culpability, but rather stated the company was “culpable” simply because it had knowledge of the regulation. For the same reasons expressed in Item 8, as operator of the pipeline, BFPL is responsible for compliance and therefore is culpable for these violations of the pipeline safety 49 See, e.g., In the Matter of Nustar Logistics, L.P., F/K/A Valero Logistics Operations, L.P., CPF No. 4-2005-5048, 2009 WL 1211363 (Mar. 11, 2009) (assessing a civil penalty of $105,000 for violation of § 195.420(b)). 50 See, e.g., In the Matter of Jayhawk Pipeline, LLC, Final Order, CPF No. 3-2008-5006, 2010 WL 5761106 (Dec. 16, 2010).#

520095042_Final Order_11212011_text.pdf, page 2322 regulations. I find no reason to determine there is any lesser degree of culpability on the part of Respondent for these violations. Fifth, Respondent contested the statement in the Violation Report that “BFPL has a poor record of compliance with Part 195 requirements,” since there was no finding that BFPL previously violated this regulation. For the same reasons expressed in Item 8, I find that when viewed as a whole, Respondent’s history of prior offenses support the proposed penalty and do not warrant any reduction. Furthermore, the Violation Reported confirmed that Respondent has previously been found in violation of this specific regulation.51 Sixth, Respondent argued the proposed penalty “does not reflect the good faith efforts of BFPL to comply, including corrective measures already implemented. record, however, that BFPL took corrective measures to achieve compliance. Regardless, corrective measures taken after the violation has already been identified by PHMSA do not warrant a penalty reduction. ”52 I do not find evidence in the Finally, BFPL argued the penalty should be reduced to reflect lower penalty assessments in prior cases. For the reasons stated above, it is appropriate for the civil penalties in this case to differ from prior cases given the unique facts of each case and that PHMSA has increased civil penalties over the years, including those for violations of § 195.428(a).53 Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a reduced civil penalty of $42,000 for its violation of § 195.428(a). Item 10: The Notice proposed a civil penalty of $30,800 for Respondent’s violation of 49 C.F.R. § 195.428(d). As discussed above, I found that BFPL failed to inspect and test the overfill protection systems at three breakout tanks. In its Response, BFPL contested the penalty assessment “because it is inconsistent with enforcement in similar cases, is disproportionate to the nature and gravity of the alleged violation, and does not reflect the good faith efforts of BFPL to comply, including corrective measures already implemented, among other reasons.”54 At the hearing and in its Brief, BFPL did not further clarify these general arguments, but requested that PHMSA consider its practice of hand gauging as good faith efforts “to comply with the ultimate objectives of section 195.428(d). ”55 Respondent’s violation of § 195.428(d) was not merely an inspection missed by several days, but rather an extended period of noncompliance. BFPL never inspected and tested the high level alarms at the three breakout tanks. Overfill protection systems provide crucial protection against spills and regular inspections and tests of such systems are key to ensuring that these systems 51 Violation Report at 23. See In the Matter of Belle Fourche Pipeline Co., Final Order, CPF No. 5-2004-5010, at 5 (Dec. 11, 2006). 52 Response at 11. 53 For example, in Jayhawk Pipeline, CPF No. 3-2008-5006, cited above, PHMSA assessed a civil penalty of $96,000 for violation of § 195.428(a). 54 Response at 12-13. 55 Brief at 18.#

520095042_Final Order_11212011_text.pdf, page 2423 operate properly. Accordingly, I find BFPL’s failure to perform such inspections presented a pipeline safety risk, and that the civil penalty proposed is appropriate given the nature, circumstances and gravity of the violation. As the operator of the pipeline facility, BFPL is also culpable for this violation of the pipeline safety regulations. With regard to BFPL’s statement in its Response that the penalty is inconsistent with other enforcement cases, Respondent did not cite to any other enforcement cases. For the reasons stated above, I find it is appropriate for civil penalties to differ from one case to another given the unique facts of each case. Finally, BFPL requested that PHMSA consider its practice of hand gauging as good faith efforts to comply with the “ultimate objectives” of the regulation. As noted above, hand gauging was performed to verify that tank level indicators on its SCADA system were accurate. The gauging did not actually test the overfill alarm devices to determine they were functioning properly. Moreover, there is no evidence in the record that Respondent undertook such hand gauging for the purpose of attempting to comply with § 195.428(d). Lastly, with regard to any “corrective measures already implemented,” I do not find evidence in the record that BFPL took corrective measures to achieve compliance. Therefore I do not find such practice warrants a penalty reduction for good faith. I have also weighed Respondent’s history of prior offenses and find that when viewed as a whole, it supports the proposed penalty and does not warrant any reduction. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $30,800 for its violation of § 195.428(d). Item 11: The Notice proposed a civil penalty of $43,300 for Respondent’s violation of 49 C.F.R. § 195.432(b). As discussed above, I found that BFPL failed to perform an external inspection of the Sussex Breakout Tank at the required interval established by API Standard 653. In its Response, BFPL contested the penalty assessment “because it is inconsistent with enforcement in similar cases, is disproportionate to the nature and gravity of the alleged violation, and does not reflect the good faith efforts of BFPL to comply, including corrective however, BFPL did not further clarify these general arguments. measures already implemented, among other reasons.”56 At the hearing and in its Brief, With regard to nature, circumstances, and gravity, I find Respondent’s failure to inspect the physical integrity of its breakout tank at the proper interval to evaluate the suitability for continued service presented a risk to pipeline safety that supports the proposed civil penalty. As the operator of the pipeline facility, BFPL is culpable for this violation of the pipeline safety regulations. For the reasons stated above, it is appropriate for civil penalties to differ from one case to another given the unique facts of each case. I have also weighed Respondent’s history of prior offenses and find that when viewed as a whole, it supports the proposed penalty and does not warrant any 56 Response at 13.#

520095042_Final Order_11212011_text.pdf, page 2524 reduction. Furthermore, the Violation Reported confirmed that Respondent has previously been found in violation of this regulation.57 Lastly, with regard to any “corrective measures already implemented,” although Respondent has taken corrective measures to achieve compliance, such measures taken after the violation has already been identified by PHMSA do not warrant a penalty reduction. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $43,300 for its violation of § 195.432(b). 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 $131,900. Respondent has not provided any evidence suggesting that Respondent is unable to pay the proposed civil penalty. Therefore, I find Respondent is able to pay the penalty without adversely affecting its ability to continue in business. Payment of the civil penalty must be made within 20 days of receipt of this Final Order. Federal regulations (49 C.F.R. § 89.21(b)(3)) require this payment 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, OK 73125; (405) 954- 8893. Failure to pay the $131,900 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 United States District Court. COMPLIANCE ORDER The Notice proposed a compliance order with respect to Items 2, 3, 4, 6, 10, 11, 12, 13, and 14 in the Notice for the violations described above. Since Items 3 and 6 have been withdrawn, the associated terms of the proposed compliance order are not included for those items. With regard to the terms of the proposed compliance order associated with Items 2, 4 and 11, Respondent has taken the following actions to fulfill the terms of the proposed compliance order: As proposed for Item 2, Respondent has developed a list of all relevant county sheriff departments, county fire departments, county emergency managers, and public officials 57 Violation Report at 23. See In the Matter of Belle Fourche Pipeline Co., Final Order, CPF No. 5-2004-5010, at 5 (Dec. 11, 2006).#

520095042_Final Order_11212011_text.pdf, page 2625 requiring liaison. Respondent also became a member of the Wyoming Pipeline Association, which is a consortium of pipeline operators with a mission of improving public awareness including liaison with local responders. As proposed for Item 4, Respondent has installed a pressure recording device at the Guernsey pump station. As proposed for Item 11, Respondent has completed an API Standard 653 Internal Inspection of the Sussex diesel breakout tank. Accordingly, since compliance has been achieved with respect to these violations, the compliance terms are not included in this Order. With regard to the proposed compliance order associated with Item 10, BFPL contended in its Response that “certain alarms have been installed and are being tested,” but provided no further explanation or documentation at the hearing or in its Brief that the company has inspected and tested the high level alarms specified in the proposed compliance order.58 With regard to the proposed compliance order associated with Item 12, BFPL did not provide any documentation of additional protection installed at the Donkey Creek Pump Station, Sussex Pump Station, and Sussex Breakout Tank. With regard to the proposed compliance order associated with Item 13, BFPL contended in its Response and Brief that it had already performed a CIS in June-July 2009 and determined based on that study that no detrimental stray currents are impacting its facilities in the specified area. After reviewing the referenced study, it appears that the purpose of the CIS was to evaluate cathodic protection levels and areas of coating damage. In Respondent’s Exhibit 7, its third- party contractor states that it “was contracted to perform a close interval On/Off cathodic protection survey on the 12[-inch] Belle Fourche Pipeline as part of Belle Fourche Pipeline’s ongoing integrity program.” It is not evident from the record that the CIS constituted an interference study. With regard to the proposed compliance order associated with Item 14, BFPL contended in its Response that “BFPL has initiated an investigation to determine if there are any additional steps necessary to mitigate the effects of internal corrosion, ” but provided no further explanation or documentation at the hearing or in its Brief regarding such an investigation. 59 Under 49 U.S.C. § 60118(a), each person who engages in the transportation of hazardous liquids by pipeline or who owns or operates a hazardous liquid 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: 58 Response at 12. 59 Response at 16.#

520095042_Final Order_11212011_text.pdf, page 2726 1. With respect to the violation of § 195.428(d) (Item 10), BFPL must inspect and test the high level alarms on the following tanks: Sussex Pump Station Breakout Tank (BOT); Davis Station (Tank 74) BOT; and Hawk Point Terminal BOT. 2. With respect to the violation of § 195.436 (Item 12), BFPL must install adequate protection from vandalism and unauthorized entry for the Donkey Creek Pump Station, Sussex Pump Station, and Sussex Breakout Tank. The protection must consist of the following, unless BFPL can demonstrate an alternative method of protection that achieves the same or greater level of safety and security: security fencing that is a minimum of six feet high and includes a minimum of three strands of barbed wire above the fencing with appropriate warning signs and operator contact information installed on the fencing, and with gates that can be locked. 3. With respect to the violation of § 195.577(a) (Item 13), BFPL must perform an interference study on the Donkey Creek Pipeline between Guernsey station and Ft. Laramie station and remediate any stray currents that are found. 4. With respect to the violation of § 195.579(a) (Item 14), BFPL must conduct an investigation to determine if crude oil transported through its pipeline system has the ability to cause internal corrosion. If the results of the investigation warrant, BFPL must develop and follow procedures for appropriate remedial actions to mitigate the occurrence of internal corrosion. 5. BFPL must complete the actions required by this Compliance Order and submit documentation demonstrating compliance within 60 days following receipt of the Final Order. Documentation of compliance must be submitted to the Director, Western Region, Pipeline and Hazardous Materials Safety Administration, 12300 W. Dakota Ave. #110, Lakewood, CO 80228. Documentation may be submitted in an electronic format when feasible. 6. It is requested that BFPL maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and report the total cost to the Director in two categories: (a) total cost associated with preparation and revision of plans and procedures, and performance of studies and analyses; and (b) total cost associated with physical changes, if any, to the pipeline infrastructure, including replacements and additions. 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 demonstrating good cause for an extension. Failure to comply with this Order may result in 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. WARNING ITEM In addition, with respect to Item 7, the Notice alleged a probable violation of Part 195 and specifically considered this to be a warning item. The warning was for:#

520095042_Final Order_11212011_text.pdf, page 2827 49 C.F.R. § 195.412(a) (Item 7) – Respondent allegedly failed to inspect the right-of-way of its Bicentennial pipeline in Montana at the required intervals between March 24 and April 21, 2008, and between June 4 and July 5, 2008. Specifically, the Notice alleged Respondent had aerial inspection records for the Bicentennial pipeline during those periods, but the records indicated the Montana portion had not been flown. If OPS finds this issue in a subsequent inspection, Respondent may be subject to future enforcement action. Under 49 C.F.R. § 190.215, Respondent has a right to submit a Petition for Reconsideration of this Final Order to the Associate Administrator for Pipeline Safety, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC 20590. A petition must be received within 20 days of Respondent’s receipt of the Final Order. The petition must contain a brief statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.215. The filing of the petition automatically stays the payment of any civil penalty assessed. All other terms of the order, including any required corrective action, shall remain in full force and effect unless the Associate Administrator, upon request, grants a stay. The terms and conditions of this Final Order are effective upon service in accordance with 49 C.F.R. § 190.5. ___________________________________ __________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety#