BRIDGER PIPELINE LLC — Notice of Probable Violation

party submissionOfficial PDF520075003_Operator Response and Request For Hearing_03082007.pdf#

party submissionOfficial PDF520075003_Petition For Reconsideration_04212009.pdf#

520075003_FinalOrder_04022009_text.pdf, page 1Official PDFAPR 2 2009 VIA CERTIFIED MAIL-RETURN RECEIPT REQUESTED [7005 0390 0005 6163 7459] Mr. Hank True President Bridger Pipeline Company, LLC 455 N. Poplar Street P.O. Drawer 2360 Casper, WY 82602 Re: CPF No. 5-2007-5003 Dear Mr. True: Enclosed is the Final Order issued in the above-referenced case. It makes findings of violation and specifies actions that need to be taken by Bridger to comply with the pipeline safety regulations. When the terms of the compliance order have been completed, as determined by the Director, Western Region, this enforcement action will be closed. Your receipt of this Final Order constitutes service of that document 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: Chris Hoidal Director, Western Region, PHMSA Colin G. Harris, Esq. Holme Roberts & Owen LLP 1801 13th St., Ste 300 Boulder, CO 80302-5387 Fax: (303) 866-0200#

520075003_FinalOrder_04022009_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 ) Bridger Pipeline Company, LLC, ) CPF No. 5-2007-5003 ) ) ) Respondent. ) ____________________________________) FINAL ORDER On June 6-10, July 18-21, and August 15-18, 2005, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and Hazardous Materials Safety Administration’s Office of Pipeline Safety (PHMSA) conducted a safety inspection of the hazardous liquid pipeline systems operated by Bridger Pipeline Company, LLC (Bridger or Respondent), and several related companies in Montana and Wyoming. Montana and North Dakota. As a result of the inspection, the Director, Western Region (Director), issued a combined notice of probable violation and proposed compliance order (CPF No. 5-2006-5004) by letter dated February 21, 2006, to one of the companies (Belle Fourche), alleging violations of the hazardous liquid pipeline safety regulations with respect to the inspected facilities. By letters dated May 26 and December 26, 2006, Belle Fourche objected to the notice on the grounds that the individual companies were separate and distinct legal entities and should be named separately. 1 Bridger operates crude oil transmission pipelines in In response to those objections, the Director withdrew the original charges on February 2, 2007, and, on the same date, issued separate enforcement documents to each company, including a Notice of Probable Violation and Proposed Compliance Order (Notice) issued to Bridger in this case. committed certain violations of 49 C.F.R. Part 195 and proposed that Bridger take measures to correct the alleged violations. In addition, pursuant to 49 C.F.R. § 190.205, the Notice advised Respondent to take appropriate corrective action to address several warning items or face future potential enforcement action. 2 In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that Bridger had 1 The companies inspected were Bridger Pipeline Company, LLC, Belle Fourche Pipeline Company (Belle Fourche), and Butte Pipeline Company (Butte). These companies share the same manual of operating procedures and some of the same employees and officers. 2 The Director issued separate notices to Belle Fourche (CPF No. 5-2007-5002) and Butte (CPF No. 5-2007-5008). This Final Order concerns only the Notice issued to Bridger. Final agency action has already been taken in the case involving Belle Fourche. The case involving Butte is still pending at this time.#

520075003_FinalOrder_04022009_text.pdf, page 32 Bridger responded to the Notice by letter dated March 8, 2007 (Response). In its Response, the company contested the allegations of violation and requested a hearing. In accordance with 49 C.F.R. § 190.211, a combined hearing was held on August 31, 2007, in Lakewood, Colorado, with an attorney from the Office of Chief Counsel, PHMSA, presiding. Bridger, Belle Fourche, and Butte were jointly represented by counsel at the hearing. After the hearing, the companies submitted a single post-hearing brief (Brief) on October 11, 2007, and additional information by letter dated December 21, 2007. To the extent that the issues raised at the hearing and in the Brief relate to Bridger, they are addressed below. As a preliminary matter, the parties agree that in making “Findings of Violation,” PHMSA burden of production and the burden of persuasion. Dir., Office of Workers’ Comp. Programs, Dep’t of Labor v. Greenwich Collieries, 512 U.S. 267, 276 (1994). The standard of proof is the traditional preponderance-of-the-evidence standard. Steadman v. SEC, 450 U.S. 91, 102 (1981). Respondent argues in its Brief that PHMSA failed to meet its burden of proof on all contested Items in the Notice (i.e., Items 3, 4, 5, 10, 11, and 14). As discussed more fully below, I find that PHMSA did in fact meet its burden of proof on all the charges. carries the burden of proving the allegations set forth in the Notice.3 This includes both the FINDINGS OF VIOLATION The Notice alleged that Respondent committed violations of 49 C.F.R. Part 195, as follows: Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.214, which provides: § 195.214 Welding procedures. (a) Welding must be performed by a qualified welder in accordance with welding procedures qualified under Section 5 of API 1104 or Section IX of the ASME Boiler and Pressure Vessel Code (incorporated by reference, see §195.3). The quality of the test welds used to qualify the welding procedure shall be determined by destructive testing. (b) Each welding procedure must be recorded in detail, including the results of the qualifying tests. This record must be retained and followed whenever the procedure is used. The Notice alleged that Bridger violated § 195.214 by failing to perform welding in accordance with procedures that had been qualified by the use of test welds determined to be of acceptable quality through destructive testing. Specifically, the Notice alleged that butt weld and fillet weld procedures used by Respondent for integrity repairs on the Poplar pipeline in 2005 had not been qualified through the use of destructive testing. During the inspection, the PHMSA inspector 3 Under the Administrative Procedure Act, “the proponent of a rule or order has the burden of proof . . . . A sanction may not be imposed or rule or order issued except on consideration of the whole record or those parts thereof cited by a party and supported by and in accordance with the reliable, probative, and substantial evidence.” 5 U.S.C. § 556(d).#

520075003_FinalOrder_04022009_text.pdf, page 43 noted that Respondent’s welding procedures did not include results from destructive testing that were required in order to qualify the procedures. Violation Report at 2 (Feb. 7, 2008).4 Bridger contended that testimony at the hearing showed the company “used procedures that had been qualified by a predecessor operator of the pipeline. In any event, Bridger now has its own qualified welding procedures.” Brief at 14. However, I can find no evidence in the record to substantiate this claim. Both Respondent’s procedures and the procedures of the previous operator are in the record, but neither includes any record of qualifications using destructive testing. While Respondent stated in its Brief that testimony at the hearing showed Bridger used procedures that had been qualified, the hearing officer noted that Respondent did not introduce any evidence at the hearing to support this statement, and I find none in the record. Even if I were to assume the previous operator did indeed qualify the procedures properly through the use of destructive testing, the fact remains that Bridger failed to present any tangible evidence of these tests and failed to retain any records of such tests, as required under § 195.214(b). Finally, Bridger’s statements concerning its efforts to qualify the procedures after PHMSA’s inspection are irrelevant to the determination of whether or not the company was in compliance at the time of the inspection. Accordingly, after considering all of the evidence, I find Respondent violated 49 C.F.R. § 195.214 by failing to perform welding in accordance with welding procedures that had been qualified using test welds of acceptable quality, as determined by destructive testing. Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.230, which states: § 195.230 Welds: Repair or removal of defects. (a) Each weld that is unacceptable under § 195.228 must be removed or repaired. Except for welds on an offshore pipeline being installed from a pipe lay vessel, a weld must be removed if it has a crack that is more than 8 percent of the weld length. (b) Each weld that is repaired must have the defect removed down to sound metal and the segment to be repaired must be preheated if conditions exist which would adversely affect the quality of the weld repair. After repair, the segment of the weld that was repaired must be inspected to ensure its acceptability. The Notice alleged that Respondent violated § 195.230 by failing to repair and re-inspect a weld that was “unacceptable” under § 195.228. Specifically, the Notice alleged that Bridger rejected weld XR-11 because it had a pinhole defect but failed to repair and re-inspect it. the record included an inspection form utilized by Bridger’s radiographer that shows he had determined this particular weld to be unacceptable. Violation Report Ex. 2. When questioned about this during the PHMSA inspection, Respondent’s personnel were unable to produce any record of the weld ever having been repaired and re-inspected. Violation Report at 3. 5 Evidence in 4 The inspector provided copies of Respondent’s procedures, dated February 2005, for the record. Violation Report Ex. 1. 5 This weld was performed by Respondent’s personnel during a short segment replacement project on the Poplar pipeline. It is not the same “weld XR-11” that was part of a 17,000-foot repair project on the same pipeline.#

520075003_FinalOrder_04022009_text.pdf, page 54 In its written submissions and at the hearing, Respondent presented several arguments why it had not violated § 195.230. First, it argued that weld XR-11 should not be considered “unacceptable. ” Brief at 3-4. Second, it argued that even if PHMSA now deemed the weld to be unacceptable, Bridger had already repaired the weld. Brief at 4. Third, it argued that Bridger did not have fair notice of the agency’s interpretation and application of this standard. Response at 4. As for Bridger’s first argument that weld XR-11 should not be considered “unacceptable,” the company contends that neither the criteria for the acceptability of welds in § 195.228 nor Section 9 of American Petroleum Institute Welding Standard 1104 (API 1104), which is incorporated therein, specify that pinholes are unacceptable. Respondent’s engineer testified in an affidavit that “[s]ection 9.3 [of API 1104] lists and explains the defects that . . . may warrant rejection in connection with radiographic testing. A ‘pinhole’ is not one of them.” Brief Ex. 6 at ¶ 26. In addition, Respondent’s consultant expressed the opinion that “[t]he list of unacceptable defects [in Section 9 of API 1104] does not include a ‘pinhole.’ Therefore . . . the mere fact that a radiographer found a ‘pinhole’ . . . does not mean that the weld failed the acceptability criteria of API-1104.” Brief Ex. 7 at ¶ 12. Because a pinhole is not listed as an unacceptable defect in § 195.228 or Section 9 of API 1104, Bridger argues that § 195.230 does not require that it be repaired. Brief at 3. Respondent is correct that neither §§ 195.230, 195.228, nor Section 9 of API 1104 expressly states that a “pinhole” is an unacceptable weld defect. company may reject a weld for any reason other than those explicitly referenced in Section 9.3. Section 9.2 states: 6 Section 9, however, does provide that a All nondestructive test methods are limited in the information that can be derived from the indications they produce. The company may therefore reject any weld that appears to meet these acceptance standards if, in its opinion, the depth of an imperfection may be detrimental to the weld. Accordingly, an operator may reject a weld if the company finds an imperfection that it considers “detrimental to the weld,” even if the type of imperfection is not explicitly enumerated in Section 9 of API 1104. This is precisely what Bridger did. The record clearly shows that the inspection was performed by Bridger’s welding inspection contractor and that the contractor’s radiographer noted his rejection of this particular weld on his inspection form. The form included a column labeled “Weld Acceptability” and two columns beneath that column with headings of “Yes” and “No.” Violation Report Ex. 2. The radiographer marked the “No” column under the “Weld Acceptability” heading for weld XR-11, indicating that he had determined the weld was unacceptable. The radiographer also recorded, under the column entitled “Type of Defects in Rejectable Welds, ” that the defect type was a pinhole. In his affidavit submitted by Respondent, the radiographer acknowledged that he had “indicated that weld XR-11 was not acceptable.” Brief 6 In this case, radiographic testing was used by Respondent to examine weld XR-11. Brief at 3. Section 9.3 of API 1104 specifies acceptance standards for weld imperfections located by radiographic testing.#

520075003_FinalOrder_04022009_text.pdf, page 65 Ex. 5. Since it was Bridger’s own contractor who determined that XR-11 was “unacceptable” under § 195.228 and API 1104, the company was required under § 195.230 to repair and re- inspect the weld to ensure integrity. As for Respondent’s second argument that the company had in fact repaired the weld, Bridger acknowledged that it did not have a record of the repair and that such lack of documentation was most likely due to a clerical error. Response at 4. The company argued, however, that normal company practice was to grind down and repair pinhole imperfections in welds. Id. Bridger also submitted several affidavits of persons familiar with the matter who attested that weld XR-11 had “likely” been repaired. The affidavit of the radiographer who personally examined weld and affidavit of another employee, who had spoken to the weld foreman of the repair project, XR-11 indicated that he “believe[s] that weld XR-11 was repaired.”7 Brief Ex. 5. The testimony indicated: He [the weld foreman] informed me that it was the practice on this project to grind down any “pinhole” anomalies, at which point the weld was not [sic] longer considered to be rejectable by T&K. [He also] informed me that it was likely that XR-11 was ground down, and mistakenly not noted in writing by the inspector on the applicable T&K worksheet or any subsequent document. Brief Ex. 6 at 4. 8 While such statements may be helpful in determining the company’s standard practices, I find them unpersuasive in this case. First, there is no definitive statement in the record that the repair was actually made. More importantly, Bridger has no documentation of the repair having been made, even though the company was or should have been fully aware of its obligation under 49 C.F.R. § 195.266 to maintain a complete record of all girth welds, including the disposition of each rejected weld. The absence of any record of a repair and re-inspection in this case, when coupled with the lack of other tangible evidence or conclusive testimony, is telling. Finally, Respondent argued that PHMSA is attempting to punish the company for violating a standard without providing fair notice of the agency’s prospective interpretation or application of such standard. According to Bridger, it would violate due process to hold the company liable under PHMSA’s interpretation of § 195.230 without fair notice. Response at 4. Respondent is correct that governmental agencies may not violate a person’s right of due process by depriving such person of property without providing a minimum level of “fair notice” as to what may constitute a violation of law. “Due process requires that parties receive fair notice before being deprived of property . . . . In the absence of notice—for example, where the regulation is not sufficiently clear to warn a party about what is expected of it—an agency may not deprive a party of property by imposing civil or criminal liability.” Gen. Elec. Co. v. U.S. EPA, 53 F.3d 1324, 1328-29 (D.C. Cir. 1995) (citations omitted) (internal quotation marks omitted). See also, United States v. Chrysler Corp., 158 F.3d 1350, 1354 (D.C. Cir. 1998); 7 In its Brief at 4, Bridger misidentified this individual as “the welder who made weld XR-11” when in fact the individual was the inspector of the weld, according to the individual’s own affidavit. 8 It is not clear from the record how long ago the witness actually spoke to the weld foreman. Respondent was not able to locate the foreman to offer testimony in this case. Brief at 8.#

520075003_FinalOrder_04022009_text.pdf, page 76 Trinity Broad. of Fla., Inc. v. FCC, 211 F.3d 618, 628 (D.C. Cir. 2000). When an agency interprets a regulation through enforcement rather than pre-enforcement efforts, the issue of notice rests on “whether the regulated party received, or should have received, notice of the agency’s interpretation in the most obvious way of all: by reading the regulations. If, by reviewing the regulations and other public statements issued by the agency, a regulated party acting in good faith would be able to identify, with ‘ascertainable certainty,’ the standards with which the agency expects parties to conform, then the agency has fairly notified a petitioner of the agency’s interpretation.” Gen. Elec. Co., 53 F.3d at 1329.9 In this case, I find, as a matter of law, that Bridger received fair notice of the conduct that was required of the company. Section 195.230 is clear on its face and provided Bridger with adequate notice that each unacceptable weld must either be removed or repaired and re- inspected. Section 195.228, and Section 9 of API 1104, incorporated therein, are also quite clear that a company may deem a weld unacceptable on its own or for a variety of explicitly enumerated reasons. In this case, Bridger itself determined that weld XR-11 was unacceptable; therefore, the company was required to address the weld accordingly. Having considered all of the evidence and issues presented, I find Respondent violated 49 C.F.R. § 195.230 by failing to repair a weld that the company had determined was unacceptable. Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(c)(1), which states: § 195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies . . . . [A]ppropriate 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: (1) Making construction records, maps, and operating history available as necessary for safe operation and maintenance . . . . The Notice alleged that Respondent violated § 195.402 by failing to make updated maps and alignment sheets available as necessary for safe operation and maintenance of the Poplar pipeline. Specifically, the Notice alleged that Bridger maintained only one set of updated alignment sheets, which showed new crossings and other changes to the facility, and kept those documents at the Glendive office rather than making them available to personnel performing operations and maintenance functions in the field. It was impractical for PHMSA’s inspector to include a copy of the alignment sheets in the record, but he noted that Bridger’s supervisor 9 Such “ascertainable certainty” may not be possible where an agency has given conflicting public interpretations of a regulation. In addition, even in those situations where an “agency does not issue contradictory public statements, it may fail to give sufficient fair notice to justify a penalty if the regulation is so ambiguous that a regulated party cannot be expected to arrive at the correct interpretation using standard tools of legal interpretation, must therefore look to the agency for guidance, and the agency failed to articulate its interpretation before imposing a penalty.” United States v. Lachman, 387 F.3d 42, 57-58 (1st Cir. 2004) (citation omitted).#

520075003_FinalOrder_04022009_text.pdf, page 87 informed him that the set of alignment sheets at the Glendive office was the only updated (i.e., accurate) copy for the Poplar pipeline. Violation Report at 4. In its Response, the company stated only that “[a]lignment sheets have been disseminated and Bridger is engaged in an ongoing process of updating.” Response at 5. In its Brief, Respondent contended that the requirements of the regulation were met by keeping the updated maps at the Glendive office, “where pipeline operations and maintenance are based.” Brief at 14. Under § 195.402(a) and (c)(1), as quoted above, persons performing operations and maintenance activities in the field, such as excavation activities that require precisely locating underground facilities, must have current maps of the pipeline facility on hand when those activities are being conducted. Performing such activities without any maps or with outdated or inaccurate maps increases the chances that a pipeline will be struck and damaged, causing a release of product harmful to the public and environment. The evidence shows that Bridger had only one set of current alignment sheets and that set did not leave the Glendive office. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.402(c)(1) by failing to make current maps available as necessary for the safe operation and maintenance of the Poplar pipeline. Item 10: The Notice alleged that Respondent violated 49 C.F.R. § 195.422(a), which states: § 195.422 Pipeline repairs. (a) Each operator shall, in repairing its pipeline systems, insure that the repairs are made in a safe manner and are made so as to prevent damage to persons or property. The Notice alleged that Respondent violated § 195.422(a) by failing to ensure that integrity repairs performed on the Poplar pipeline in 2005 were made in a safe manner. Specifically, it alleged that Bridger failed to use a nondestructive testing (NDT) method to examine sleeve-to- pipe fillet welds associated with type-B repair sleeves. The Notice also alleged that industry practice has been to use NDT to ensure that type-B repair sleeves are installed in a safe manner. The Notice alleged further that Respondent’s repair records did not even indicate whether visual examinations of such welds had been performed. During the PHMSA inspection, the inspector noted that Bridger had made repairs using type-B sleeves, but there was no record that such repairs had been visually inspected or tested using NDT. The inspector documented statements made by two of Respondent’s employees that the company had visually inspected the welds but did not need to perform NDT because such testing had been performed on two sleeve repairs on another pipeline operated by a sister company and that such tests had been successful. Violation Report at 5. Bridger raised several defenses to Item 10. First, it contended that the company ensured type-B repair sleeves were installed in a safe manner by using fully qualified welders and procedures, by visually inspecting the welds, and by performing a post-repair hydrostatic test of the pipeline. Response at 6. Second, it argued that PHMSA failed to provide the company with fair notice of the agency’s interpretation and application of this NDT standard.#

520075003_FinalOrder_04022009_text.pdf, page 98 As for Bridger’s first defense that the company ensured the repairs were made in a safe manner, the company presented one of its engineers, who stated that he had been told by the welding testified that, to his knowledge, the company had used qualified welders and procedures and that the company had performed a hydrostatic test on the pipeline. Id. at ¶¶ 8 and 10. Respondent maintained these measures constituted compliance with § 195.422 and American Society of Mechanical Engineers (ASME) Standard B31.4, which Respondent referred to as “the relevant professional code governing pipeline transportation systems. Respondent contended that Section 451.6.3 of ASME B31.4 “allows for ‘other methods’ along with visual inspection” to ensure the safety of repair welds and that Respondent chose hydrostatic testing in addition to visual inspection. Response at 6. foreman that all of the welds were visually inspected. Brief Ex. 6 at ¶ 9.10 The witness also ” Response at 5. In particular, With regard to the use of qualified workers and procedures, Respondent is correct to point out that these are critical for ensuring repairs are made in a safe manner. However, the use of qualified workers and procedures is not a substitute for post-repair examination. The use of qualified workers and procedures only serve prospectively to make it more likely that repairs will be made safely in the future. The use of post-repair examinations is also needed to ensure that repairs were in fact made safely. Moreover, I have found that Bridger did not use qualified welding procedures when performing fillet welds on the Poplar pipeline in 2005 (see Item 3 of this Order). With regard to the visual examinations and hydrotest, I find little support in the record for Respondent’s assertion that it conducted visual examinations of these repair welds, other than second-hand accounts and hearsay. Even if visual examinations were performed, they do not provide enough information on their own to determine whether repair welds were properly performed. For that reason, another type of post-repair examination method is required. While Respondent asserted that the leading industry standard accepts the use of hydrostatic testing in addition to visual examinations in such circumstances, the standard actually states that “[w]elds should also be examined by at least one other nondestructive examination method” in addition to visual examinations. ASME B31.4 § 451.6.3(b) (2002) (emphasis added). Rather than utilize another method of NDT, as recommended in the leading industry standard, Respondent instead chose to hydrotest the pipeline. At the hearing, the Director explained that hydrostatic testing is not a suitable process for determining the soundness of a type-B sleeve repair. This is because hydrotests are not capable of testing the integrity of the fillet welds on a type-B repair sleeve. In fact, Respondent informed PHMSA, by letter dated December 21, 2007, that it had recently performed NDT on several type-B repair sleeves from the 2005 repair project at issue in this case and found some sleeves had cracks in the pipe-to-sleeve fillet weld that had not been detected by Bridger during any of its previous post-repair examination methods, including the hydrostatic test. Respondent also determined that six of the twelve excavated repairs were not made in their intended locations. The cracks in the repair welds and the incorrect locations of the repair sleeves are further indications that the repairs were not performed in a safe manner. 10 The date this witness spoke to the foreman is not evident in the record, but it was likely years ago, since Respondent was not able to locate the foreman to testify. Brief at 8.#

520075003_FinalOrder_04022009_text.pdf, page 109 While NDT may be an appropriate method to ensure type-B repair sleeves are installed in a safe manner, the text of § 195.422(a) does not explicitly require the use of NDT to determine the safety of such repairs. As Respondent correctly notes, § 195.422(a) is a performance-based regulation that requires a specified minimum level of safety for pipeline repairs but does not prescribe a specific process or method to be used for each type of repair. With regard to the repairs at issue in this case, the question is whether Respondent used an evaluation process capable of ensuring that type-B repair sleeves were installed in a safe manner. For the reasons expressed above, I find the methods used by Respondent to determine the safety of those repairs were inadequate to comply with § 195.422(a). As for Bridger’s second argument that PHMSA failed to provide fair notice of its interpretation and application of this regulation to require NDT, Respondent argued that it “could not have reasonably ascertained that OPS now considers NDT to be a mandatory requirement under 49 C.F.R. § 195.422(a),” because the regulation, on its face, imposes no such requirement. Brief at 10. Bridger has clearly misinterpreted the agency’s application of § 195.422 in this case. As explained above, PHMSA does not take the position that NDT, specifically, is a mandatory requirement of the regulation. Rather, the agency notes the industry practice has been to use NDT to meet the performance-based regulation for the type of pipeline repair at issue in this case. It is clear from the text of § 195.422(a) that in order to ensure a particular pipeline repair has been made in a safe manner, an operator must use an evaluation method that is capable of making that determination. As a matter of law, therefore, I find that Bridger had fair notice of the requirement within § 195.422(a) that it use an evaluation method capable of determining type-B sleeve repairs were made in a safe manner. Unfortunately, for the reasons expressed above, the methods of evaluation used by Bridger were insufficient to comply with this requirement. Respondent’s assertion that the company was not aware NDT was the “industry standard” is specious, as Bridger itself cited the ASME B31.4 standard, which states explicitly that repair welds should be examined by NDT. Whether or not NDT is the industry standard, however, is ultimately irrelevant because § 195.422(a) does not bind Respondent to the industry standard. Respondent may comply with the regulation by using one or more evaluation methods capable of determining that “the repairs are made in a safe manner;” but the operator must be able to demonstrate the chosen method is capable of making such a determination. In this case, I find Bridger’s chosen evaluation method was not capable of demonstrating the repairs were made safely. Accordingly, after considering all of the evidence and arguments presented, I find Respondent violated 49 C.F.R. § 195.422(a) by failing to ensure that type-B repairs sleeves were completed in a safe manner. Item 11: 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) [E]ach 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#

520075003_FinalOrder_04022009_text.pdf, page 1110 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 certain pressure control equipment on the Poplar pipeline to determine that such equipment was functioning properly, was in good mechanical condition, and adequate in terms of capacity and reliability of operation. Specifically, the Notice alleged that Bridger failed to test or calibrate “transducers that transmit data” to the company’s Supervisory Control and Data Acquisition (SCADA) center. The Notice alleged that such devices were part of the company’s pressure control system and therefore had to be inspected and tested periodically under § 195.428(a). The Director’s Violation Report also referenced an enforcement action brought against the previous operator of the Poplar pipeline in 2004 for the same issue. Violation Report at 6.11 Bridger raised several defenses to Item 11. First, the company argued that the requirements in § 195.428(a) do not apply to pressure “transmitters,” which the company termed the equipment at issue in the Notice. Response at 7. Second, the company argued that Bridger did not have fair notice of this interpretation and application of § 195.428(a). Id. As a general matter, the parties discussed at the hearing whether a distinction could be drawn between the terms “transducer” and “transmitter” and, if so, whether that distinction had any bearing on the allegation. A “transducer” is a generic term referring to a device that reads data in one form (for example, pipeline pressure measured in pounds) and translates that data into an electronic signal that can be transmitted, usually by wire. A “transmitter” is an electronic assembly with a transducer at the front end and that transmits the signal. Although there is a technical distinction between the two terms, in this case the terms refer to the same piece of equipment that, for ease of discussion, I will refer to simply as a “pressure transmitter.” The company offered several reasons why § 195.428(a) does not apply to pressure transmitters. First, it explained that Bridger’s pipeline uses on-site devices that are “hard-wired to mechanically shut down the system locally and independently of the SCADA system” when pressure reaches a certain level. Brief at 12. Respondent distinguished those devices from pressure transmitters that send pressure data to a SCADA center, arguing that the regulation only applies to local mechanical devices and not to pressure transmitters. While Respondent is correct to point out that local mechanical pressure control equipment is covered by § 195.428(a), the regulation is not so limited as to exclude other types of devices used to monitor and control operating pressure on a pipeline. By its terms, § 195.428(a) requires “each pressure limiting device, relief valve, pressure regulator, or other item of pressure control equipment” to be tested and inspected at specified intervals. The regulation does not explicitly define “pressure control equipment,” but the ordinary meaning of those terms would include devices used to control pipeline operating pressure. The requirements within § 195.428(a) do not distinguish between local and remote control devices, nor does the regulation differentiate between devices used to control emergency overpressures and those used to control pressure during normal operations. 11 In the Matter of Shell Pipeline Company L.P., CPF No. 5-2004-5020, Warning Letter (Sept. 23, 2004).#

520075003_FinalOrder_04022009_text.pdf, page 1211 Regulated hazardous liquid pipelines have controls and protective equipment to control pressure during emergency pressure surges and other variations from normal operations. See § 195.406(b). A pipeline operator may establish set points for the activation of emergency shutdown and overpressure devices as high as 110% of the established maximum operating pressure (MOP) of a pipeline. Id. During normal operations, however, pipeline operators utilize electronic pressure monitoring equipment to assist in operating the pipeline within the established MOP. When pressure transmitters are used to monitor pipeline pressure, the transmitters send pressure data to a program logic computer or SCADA control center where persons and computers make operational decisions based on such data. Safe operation of a pipeline facility depends on the accuracy of the pressure data being transmitted. If pressure transmitters are not calibrated, they may send inaccurate pressure data to the program logic computer or SCADA center, potentially resulting in the operation of a pipeline at a pressure higher than intended, perhaps even higher than the MOP, without the controller’s knowledge. In fact, erroneous pressure data may result in a pipeline being operated at an unsafe pressure as high as 110% of MOP without the controller’s knowledge and without triggering any automatic remote or local emergency overpressure protection devices. Regular operation of a pipeline above MOP is a significant safety risk to the public, employees, and the environment, and is not permitted by the pipeline safety regulations. See § 195.406(a). For these reasons, regular testing and calibration of pressure transmitters that send pressure signals to on-site devices and to off- site locations that control pipeline pressure is important for public safety and is a requirement under § 195.428(a). Second, Respondent argued that PHMSA’s interpretation of § 195.428(a) to include pressure transmitters would logically require the agency to extend the applicability of the regulation to all other SCADA-related equipment, such as computers, software, alarms, displays, databases, and even satellite communications. Brief at 12. PHMSA has never suggested or actually applied the regulation so broadly as to require annual testing of all SCADA-related equipment. In addition, it would be neither logical nor necessary to extend the application of the regulation to every component arguably associated with a SCADA system. On the other hand, pressure transmitters that actually monitor pipeline pressure, convert such data to electronic signals, and transmit such data to an operator’s SCADA system reasonably fall within the scope of the regulation. For these reasons, I find Respondent’s argument unpersuasive. Third, Respondent argued that PHMSA’s position on testing pressure transmitters “contradict[s]” other pipeline regulations. Brief at 12. Respondent’s argument is based on language within the proposed compliance order in the Notice that would require Bridger to test all pressure transmitters, including those that are “part of the computational pipeline monitoring (CPM) system.” Respondent argued that CPM systems, including associated pressure transmitters, are required to be tested under § 195.444 and that subjecting such devices to both §§ 195.428(a) and 195.444 would result in conflicting requirements. Brief at 12-13. This is incorrect. Section 195.444 regulates CPM leak detection systems. A CPM leak detection system may use a variety of techniques for detecting leaks, including physical inspections, hydrocarbon detection sensors, software-based monitoring, and SCADA monitoring. See API standard 1130, incorporated by reference at § 195.444. If an operator uses SCADA monitoring as a part of its CPM leak detection system regulated under § 195.444, that does not negate or conflict with the requirement under § 195.428(a) to test pressure transmitters if they also#

520075003_FinalOrder_04022009_text.pdf, page 1312 function as part of a pressure control device. The proposed compliance order likely used the term “CPM system” to cover pressure transmitters that send signals to a SCADA system or other device that controls pressure. Moreover, Respondent did not offer any evidence demonstrating that compliance with both regulations was somehow inconsistent or impracticable. Accordingly, I find this argument unconvincing. To avoid further confusion, however, I have replaced “CPM system” with “device or a SCADA system that controls pressure” in the compliance order. Finally, Respondent argued that PHMSA failed to provide the company with fair notice of its interpretation and application of § 195.428(a) to require testing of SCADA pressure transmitters. Brief at 13. In particular, Bridger argued that the company could not have reasonably ascertained that § 195.428(a) applies to SCADA pressure transmitters because “the industry understanding and custom was that such devices were not considered to be the sort of mechanical ‘pressure control equipment’ that the regulation was intended to cover.” Id. On the contrary, Bridger had abundant notice that § 195.428(a) has been interpreted to include pressure transmitters sending signals to a SCADA system or other device that controls pressure. The language of the regulation itself is broadly worded to apply generally to equipment used to control pipeline pressure. Moreover, the agency’s interpretation of the regulation with regard to pressure transmitters has been communicated to the regulated pipeline industry through various enforcement actions over a number of years. 12 Furthermore, in this case, the agency also provided actual notice of its interpretation to Bridger’s sister company, Belle Fourche Pipeline Company, and to the previous operator of Bridger’s Poplar pipeline, Shell Pipeline Company. On May 19, 2004, the Director notified Belle Fourche that it had allegedly violated § 195.428(a) by failing to calibrate pressure transmitters to make sure that accurate data was being transmitted. 13 In addition, the Director issued an enforcement action on September 24, 2004, to Shell Pipeline Company, warning the operator that failure to produce documentation showing the company had tested and inspected SCADA pressure 12 See, e.g., In the Matter of BP Transportation (Alaska) Inc., CPF No. 5-2002-5011W, Warning Letter (Apr. 30, 2002); In the Matter of Cenex Harvest States, CPF No. 5-2003-5029, Warning Letter (Nov. 18, 2003); In the Matter of Kinder Morgan Energy Partners, CPF No. 2-2004-6008M, Notice of Amendment (Apr. 15, 2004); and In the Matter of ExxonMobil Pipeline Company, CPF No. 5-2005-5008, Notice of Probable Violation, Proposed Compliance Order, Proposed Civil Penalty, and Notice of Amendment (Feb. 18, 2005), Final Order (Jan. 9, 2007), pending reconsideration on other grounds. In ExxonMobil, the operator argued that pressure transmitters sending pressure and flow rate signals to control logic devices or a remote operating control center were not pressure control equipment. The Final Order found, however, that “a pressure transmitter . . . sending signals to another device or a SCADA system that controls pressure . . . is considered to be a pressure control device and as such must be tested and inspected and the data . . . recorded once each calendar year not to exceed 15 months in accordance with 49 C.F.R. § 195.428(a)” because “these devices are integral in the control of pressures for the . . . pipeline.” 13 In the Matter of Belle Fourche Pipeline Company, CPF No. 5-2004-5010, Notice of Probable Violation, Proposed Civil Penalty, Proposed Compliance Order, and Notice of Amendment (May 19, 2004), Final Order (Dec. 11, 2006), pending reconsideration on other grounds. Belle Fourche is a separate legal entity from Respondent; however, the two companies share many of the same employees and officials. For example, Bridger’s lead engineer was the official addressee in the 2004 Belle Fourche enforcement action. The companies also share the same president, who was the official recipient of both the Final Order issued in the 2004 Belle Fourche case and the present enforcement action against Bridger.#

520075003_FinalOrder_04022009_text.pdf, page 1413 was or should have been aware of the aforementioned enforcement actions by which PHMSA stated publicly that pressure transmitters were covered by the testing requirements of transmitters for the Poplar pipeline constituted a probable violation of § 195.428(a).14 Bridger § 195.428(a). Accordingly, I find, as a matter of law, Bridger had fair notice of the agency’s interpretation and application of this requirement. Respondent did not refute the factual allegation in the Notice that it had failed to test or calibrate the SCADA pressure transmitters on the Poplar pipeline at intervals not exceeding 15 months, but at least once each calendar year. Therefore, upon consideration of all of the evidence and issues discussed above, I find that Respondent violated 49 C.F.R. § 195.428(a) by failing to inspect and test the pressure transmitters on the Poplar pipeline at specified intervals. Item 14: The Notice alleged that Respondent violated 49 C.F.R. § 195.583, which states: § 195.583 What must I do to monitor atmospheric corrosion control? (a) You must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows: If the pipeline is located: Then the frequency of inspection is: Onshore At least once every 3 calendar years, but with intervals not exceeding 39 months . . . . (b) During inspections you must give particular attention to pipe at soil-to-air interfaces, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water. (c) If you find atmospheric corrosion during an inspection, you must provide protection against the corrosion as required by § 195.581. The Notice alleged that Respondent violated § 195.583 by failing to perform documented atmospheric corrosion inspections. Specifically, that Bridger did not have records of any completed atmospheric corrosion inspections and that none of the pipe supports appeared to have been inspected. Violation Report at 14. When the PHMSA inspector asked company officials whether Bridger planned to inspect pipe surfaces that were in contact with concrete supports, Respondent’s lead engineer indicated that the company did not have procedures to examine those pipe surfaces and had not documented any external corrosion inspections. Violation Report at 14. The inspector photographed a pipe at a support location at Glendive and included the photograph as evidence in the record. Violation Report Ex. 5. At the hearing, Respondent’s lead engineer stated that while the company had not used specific forms to document its atmospheric corrosion inspections, the company did perform generic inspections and identified corrosive surfaces at times. In its Brief, Bridger introduced an affidavit from the same person, stating that “specific external corrosion inspection procedures were not necessarily written down,” but that the company had “routine inspection procedures for pipelines,” and that “any significant external corrosion that was found would have been addressed appropriately.” The witness also stated that the company had a reference to external corrosion in its operations and maintenance (O&M) manual. Brief Ex. 6 at ¶ 28. Respondent 14 In the Matter of Shell Pipeline Company L.P., CPF No. 5-2004-5020, Warning Letter (Sept. 23, 2004).#

520075003_FinalOrder_04022009_text.pdf, page 1514 contended that “Bridger [was] in material compliance, or [has] been addressing the alleged deficiencies.” Brief at 13-14 (emphasis added). While Bridger’s lead engineer testified that the company performed “routine” O&M inspections, the company could not state explicitly how or when these inspections occurred, whether such inspections occurred at the requisite intervals under the regulation, whether the company always checked for atmospheric corrosion during such inspections, or whether such inspections specifically checked pipe surfaces that were in contact with concrete supports—all requirements under § 195.583. Bridger was also unable to produce any records of having performed such inspections, which the company is required to keep under § 195.589(c). Furthermore, a photograph taken at Respondent’s pipeline facility indicates that atmospheric corrosion had gone undetected, further evidence that Bridger had not performed atmospheric corrosion inspections within the required intervals. Finally, Respondent’s statements concerning efforts to improve its forms and procedures after the PHMSA inspection are not relevant to the determination of whether or not Respondent was in compliance at the time of the inspection. Accordingly, after considering all of the evidence, I find Bridger violated 49 C.F.R. § 195.583 by failing to perform documented atmospheric corrosion inspections, particularly at pipe surfaces in contact with concrete supports. Freedom of Information Act (FOIA) Issue: Respondent objected generally to the setting of a hearing in this proceeding while the company still had a FOIA request for documents pending with the agency. Bridger argued in its Brief that PHMSA’s decision to go forward with the hearing, despite the company’s FOIA request and over its objections, constituted “a violation of Respondent’s due process rights.” Brief at 14. Respondent did not present any evidence or cite any legal authority in support of this claim. PHMSA has specific procedures in place to guarantee a respondent’s procedural due process rights in informal adjudications. See 49 C.F.R. Part 190. In accordance with those procedures, PHMSA provided Bridger with all of the materials from the agency’s case file well in advance of the date set for the hearing. process rights were violated. 15 Therefore, Bridger cannot reasonably assert that its procedural due Furthermore, the law is quite clear that an agency may proceed with an adjudication despite a respondent’s filing of a FOIA request. As the Supreme Court has stated, “[I]nterference with the agency proceedings opens the way to the use of the FOIA as a tool of discovery, over and beyond that provided by the regulations issued.” Renegotiation Bd. v. Bannercraft Clothing Co., 415 U.S. 1, 24 (1974); see also, Columbia Packaging Co. v. U.S. Dep’t of Agric., 563 F.2d 495, 499-500 (1st Cir. 1977) (stating that “FOIA was not enacted to provide litigants with an additional discovery tool” and that “discovery in the different types of agency litigation is primarily a matter either for agency regulation or separate Congressional determination”). Based upon the foregoing, I find Respondent’s due process rights were not violated by the setting of a hearing in this proceeding while Bridger’s FOIA request for documents was still pending. 15 See 49 C.F.R. § 190.211(e). It should also be noted that PHMSA responded to Bridger’s FOIA request on March 7, 2007, approximately six months prior to the hearing. The agency responded to the company’s FOIA appeal on October 2, 2008.#

520075003_FinalOrder_04022009_text.pdf, page 1615 The findings of violation contained in this Order will be considered prior offenses in any subsequent enforcement action taken against Respondent. COMPLIANCE ORDER The Notice proposed a compliance order with respect to Items 3, 4, 5, 10, 11, and 14 in the Notice for violations of §§ 195.214, 195.230, 195.402(c)(1), 195.422(a), 195.428(a), and 195.583, respectively. 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. With respect to several of the proposed compliance order items, Respondent argued that “a grant of jurisdiction to require remedial measures is not an absolute duty to do so under any circumstances,” and that a “cost-benefit assessment” of the proposed compliance terms shows that they would be “unnecessary or excessive.” Response at 4 and 6–8. At the hearing, Respondent argued that the proposed compliance terms would be very expensive and the cost would far exceed any benefit gained from the remedial measures. While PHMSA considers expected costs and benefits when promulgating new safety regulations, each operator must comply with them once they become final unless the company has requested and received a waiver. 49 U.S.C. § 60118(a) and (c). PHMSA does not permit the noncompliant operation of a pipeline facility merely because it would be expensive for the operator to adhere to the established set of safety standards. Furthermore, it is entirely possible that Respondent realized an economic benefit by avoiding certain activities otherwise required by the regulations. Accordingly, I reject Respondent’s argument that PHMSA should refrain from ordering the company to come into compliance with applicable safety regulations. Pursuant to the authority of 49 U.S.C. § 60118(b) and 49 C.F.R. § 190.217, Respondent is hereby ordered to take the following actions to ensure compliance with the pipeline safety regulations applicable to its operations: 1. With respect to the violation of § 195.214 (Item 3), Bridger shall submit to the Director for approval its welding procedures and supporting documentation showing that such procedures have been qualified using destructive testing in accordance with § 195.214. The procedures must address welding that may be performed during construction, operations, and maintenance activities, including the installation of in- service repair sleeves. 2. With respect to the violation of § 195.230 (Item 4), Bridger shall submit to the Director documentation that weld XR-11 has been excavated, examined, and removed or repaired, as appropriate, in accordance with § 195.230. 3. With respect to the violation of § 195.402(c)(1) (Item 5), Bridger shall submit to the Director for approval its written procedures for ensuring that construction records, maps, and operating history are made available to persons needing them in the field#

520075003_FinalOrder_04022009_text.pdf, page 1716 and any other location as necessary for safe operations and maintenance. Bridger shall update all maps and alignment sheets of the Poplar pipeline used by operations and maintenance personnel so that each document accurately reflects the location of the following: breakout tanks; pump stations; scraper and sphere facilities; pipeline valves; facilities to which § 195.402(c)(9) applies; rights-of-way; safety devices to which § 195.428 applies; all crossings of public roads, railroads, rivers, buried utilities; and foreign pipelines. Each document shall also indicate the following: maximum operating pressure of each pipeline; and diameter, grade, type, and nominal wall thickness of all pipe. Submit documentation of compliance, including a copy of the updated alignment sheets, to the Director. 4. With respect to the violation of § 195.422(a) (Item 10), pursuant to the Notice of Proposed Compliance Order, and based upon Bridger’s post-hearing disclosure dated December 21, 2007 (which revealed that certain excavated sleeve-to-pipe fillet welds associated with type-B repair sleeves installed on the Poplar pipeline in 2005 were fillet welds associated with type-B repair sleeves installed on the Poplar pipeline as part of the referenced integrity repairs of 2005. The method of examination shall be NDT unless Bridger submits to the Director for prior approval a proposal to use another method of examination capable of complying with § 195.422(a). Each excavated weld that has an indication of cracking or other cause for repair must be repaired in accordance with procedures that comply with 49 C.F.R. Part 195 and that have been submitted to the Director for prior approval. Documentation of each excavation, examination, and repair must be maintained and submitted. found to have “toe cracks”), Bridger shall excavate and examine all sleeve-to-pipe 5. With respect to the violation of § 195.428(a) (Item 11), Bridger shall ensure that each pressure limiting device, relief valve, pressure regulator, or other item of pressure control equipment, including pressure transmitter sending signals to another device or a SCADA system that controls pressure, has been inspected and tested in accordance with § 195.428(a) 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. Develop procedures to ensure future inspections and tests take place at the requisite intervals. Submit documentation of completion, including inspection and test results and developed procedures. 6. With respect to the violation of § 195.583 (Item 14), Bridger must develop and follow procedures for performing atmospheric corrosion inspections of all piping exposed to the atmosphere, giving particular attention to pipe surfaces at soil-to-air interfaces and at pipe supports, among other locations, in accordance with § 195.583. Remediate any atmospheric corrosion found during the inspection in accordance with § 195.583. Documentation of these actions must be maintained and submitted. 7. Maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and report the cost as follows: (a) total cost associated with preparation, revision of plans and procedures, and performance of studies and analyses; and (b) total cost associated with physical changes to the pipeline infrastructure, including replacements and additions.#

520075003_FinalOrder_04022009_text.pdf, page 1817 8. Documentation of compliance with each item shall be submitted within 60 days of receipt of this Final Order to the Director, Western Region, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 12300 W. Dakota Ave. # 110, Lakewood, CO 80228-2585. 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 ITEMS With respect to Items 1, 2, 6(a), 6(b), 7, 8(a), 8(b), 9, 12, and 13, the Notice alleged probable violations of Part 195 but did not propose a civil penalty or compliance order for these items. Therefore, these are considered to be warning items. The warnings were for: 49 C.F.R. § 195.49 (Notice Item 1) – Respondent’s alleged failure to submit an accurate form RSPA F 7000-1.1 for calendar year 2004. The report submitted did not report the correct number of electronic resistance weld pipe miles installed between 1950 and 1959. 49 C.F.R. § 195.204 (Notice Item 2) – Respondent’s alleged failure to perform documented inspections of construction and weld repairs in 2005 to ensure they were performed as required by regulation; also, the company’s alleged failure to utilize inspectors who were properly trained and qualified in construction and welding processes. 49 C.F.R. § 195.402(a) (Notice Item 6a) – Respondent’s alleged failure to follow its own written procedures for conducting periodic reviews of work completed to determine the adequacy of the company’s written procedures for normal operations and maintenance. 49 C.F.R. § 195.402(a) (Notice Item 6b) – Respondent’s alleged failure to follow its own written procedures for conducting periodic reviews of work completed to determine the adequacy of the company’s written procedures for abnormal operations. 49 C.F.R. § 195.402(c)(12) (Notice Item 7) – Respondent’s alleged failure to establish and maintain liaison with local emergency responders, including those at remote locations, to learn their responsibilities and resources when responding to pipeline emergencies and to acquaint the officials with Respondent’s ability in responding to emergencies and means of communication. 49 C.F.R. § 195.403(b)(1) (Notice Item 8a) – Respondent’s alleged failure to review with personnel at intervals not exceeding 15 months, but at least once each calendar year, their performance in meeting the objectives of Respondent’s emergency response training program.#

520075003_FinalOrder_04022009_text.pdf, page 1918 49 C.F.R. § 195.403(c) (Notice Item 8b) – Respondent’s alleged failure to verify that its supervisors have a thorough knowledge of the emergency response procedures for which they are responsible to ensure compliance. 49 C.F.R. § 195.410(a) (Notice Item 9) – Respondent’s alleged failure to maintain several line markers that were discovered to be down along the Poplar pipeline segment north of Glendive and just south of the Highway 254 crossing. 49 C.F.R. § 195.440 (Notice Item 12) – Respondent’s alleged failure to establish an adequate public education program that enables the general public to recognize a pipeline emergency and to report it to the operator or appropriate emergency responders. 49 C.F.R. § 195.579(c) (Notice Item 13) – Respondent’s alleged failure to inspect the internal surface of pipe upstream and downstream of pipe replacements that were part of integrity repairs for the Poplar pipeline. Having considered such information, I find, pursuant to 49 C.F.R. § 190.205, that probable violations of 49 C.F.R. § 195.49 (Notice Item 1), § 195.204 (Notice Item 2), § 195.402(a) (Notice Item 6a), § 195.402(a) (Notice Item 6b), § 195.402(c)(12) (Notice Item 7), § 195.403(b)(1) (Notice Item 8a), § 195.403(c) (Notice Item 8b), § 195.410(a) (Notice Item 9), § 195.440 (Notice Item 12), and § 195.579(c) (Notice Item 13) have occurred and Respondent is hereby advised to correct such conditions. In the event that PHMSA finds a violation for any of these items 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. The petition must be received within 20 days of Respondent’s receipt of this Final Order and must contain a brief statement of the issue(s). The 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 shall be effective upon receipt. ___________________________________ __________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety#

520075003_closure letter_11102010_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED November 10, 2010 Mr. Hank True President Bridger Pipeline Company, LLC 455 N Poplar St. P.O. Drawer 2360 Casper, WY 82602 CPF 5-2007-5003 Dear Mr. True: On April 2, 2009, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to Bridger Pipeline Company (Bridger) a Final Order on CPF 5-2007-5003. Bridger subsequently filed a petition for reconsideration and on June 16, 2009 PHMSA issued a Decision on that petition for reconsideration and a Compliance Order. During the time period that the Final Order was being developed, there was a “whistle blower” concern relating to previous sleeve repairs associated with this case. To address this issue, Bridger re-excavated a previously repaired sleeve and, in the presence of PHMSA personnel, performed a non-destructive test (NDT) on that sleeve’s welds. These welds had previously been NDT’ed as a requirement of the Compliance Order. The whistle blower concerns with these welds were not observed on this weld, but some minor visual flaws were discovered which were subsequently repaired and then NDT’ed again. Based on our review of the documentation you provided, it has been determined that you have now 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 114331, 114330, 114253)#

520075003_Stay of Final Order_05082009_text.pdf, page 1Official PDFMAY 8 2009 CERTIFIED MAIL – RETURN RECEIPT REQUESTED [7005 1160 0001 0047 7117] Mr. Hank True President Bridger Pipeline Company, LLC 455 N. Poplar Street P.O. Drawer 2360 Casper, WY 82602 Re: In the Matter of Bridger Pipeline Company, LLC CPF No. 5-2007-5003 Dear Mr. True: I am in receipt of your Petition for Reconsideration, dated April 22, 2009, wherein you request that I reconsider Item 11 of the Final Order issued in the above-referenced case. Your letter further requests a stay of the terms of the Compliance Order associated with that Item, and an extension of time to comply with certain other terms of the Compliance Order. By this letter, the terms of the Compliance Order concerning the inspection and testing of SCADA pressure transmitters (Requirement 5), are stayed pending the issuance of a decision on your Petition. By this letter, an extension of time is also granted to comply with the terms of the Compliance Order contained in Requirements 2 and 4. The deadline for compliance with Requirements 2 and 4 shall be October 31, 2009. Should you have any questions with respect to the terms of the Compliance Order, please contact Mr. Chris Hoidal, Director, Western Region, at (720) 963-3160. Sincerely, Jeffrey D. Wiese Associate Administrator for Pipeline Safety cc: Chris Hoidal Director, Western Region, PHMSA Colin G. Harris, Esq. Holme Roberts & Owen LLP 1801 13th St., Ste 300 Boulder, CO 80302-5387#

bpl 5-2007-5003 nopv-pco 2-2-07_text.pdf, page 1Official PDFU. S. De partrnent of Transportation Pipeline and Hazardous Materials Safety Administration 12300 W Dakota Ave, Suite 110 Lakewood, CO 80228 NOTICE OF PROBABLE VIOLATION and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT RE UESTED February 2, 2007 Mr. Hank True President Bridger Pipeline Company LLC 455 North Poplar Street Casper, WY 82601 SENT TO COMPLIANCE REGIS Y Hardcopy Electronically ¹ of Copiest l Date ~Ã CPF No. 5-2007-5003 Dear Mr. True. Between June 6-10, 2005, July 18-21, 2005, and August 15-18, 2005, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected your of Bridger Pipeline Company's (BPL) Poplar pipeline system in Montana. This inspection included a review of supporting Operation and Mamtenance (08aM) records for all systems in Casper and New Castle, Wyoming as well as Glendive and Baker, Montana. 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. 49 Annual report Beginning no later than June 15, 2005, each operator must annually complete and submit DOT form RSPA F 7000-1. 1 for each type of hazardous liquid pipeline facility operated at the end of the previous year. A separate report is required for crude oil, HVL (including anhydrous ammonia), petroleum products, and carbon dioxide pipelines. Operators are encouraged, but not required, to file an annual report by June 15, 2004, for calendar year 2003.#

bpl 5-2007-5003 nopv-pco 2-2-07_text.pdf, page 2Data is incorrect on the Annual Report for Calendar Year 2004 for the Poplar pipeline. The Poplar pipeline report does not state all of the miles of electronic resistance weld pipe installed between 1950 and 1959. 2. $195. 204 Inspection - General. Inspection must be provided to ensure the installation of pipe or pipeline systems in accordance with the requirements of this subpart. No person may be used to perform inspections unless that person has been trained and is qualified in the phase of construction to be inspected. Records for the Poplar pipeline integrity repair work in 2005 do not adequately document construction and welding inspection. Additionally records did not include qualifications of construction and welding process inspectors. 3, $195, 214 Welding procedures (a) Welding must be performed by a qualified welder in accordance with welding procedures qualified under Section 5 of API 1104 or Section IX of the ASME Boiler and Pressure Vessel Code (ibr, see g 195, 3) . The quality of the test welds used to qualify the welding procedure shall be determined by destructive testing. (b) Each welding procedure must be recorded in detail, including the results of the qualifying tests, This record must be retained and followed whenever the procedure is used. Butt weld and fillet weld procedures used for the Poplar pipeline mtegrity repairs completed in 2005 were not qualified using destructive testing. 4. $195. 230 Welds: Repair or removal of defects. (a) Each weld that is unacceptable under $195. 228 must be removed or repaired, Except for welds on an offshore pipeline being installed from a pipe lay vessel, a weld must be removed if it has a crack that is more than 8 percent of the weld length. (b) Each weld that is repaired must have the defect removed down to sound metal and the segment to be repaired must be preheated if conditions exist which would adversely affect the quality of the weld repair. After repair, the segment of the weld that was repaired must be inspected to ensure its acceptability. Records show that weld number XR 11 made during a short segment replacement project on the Poplar pipeline was rejected for a pinhole. There is no record that this weld was repaired and re-inspected. This weld XR 11 is not the same weld XR 11 that was part of the 17, 000 foot repair project on the Poplar Pipeline. 5. $195. 402 Procedural manual for operations, maintenance, 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:#

bpl 5-2007-5003 nopv-pco 2-2-07_text.pdf, page 3(1) Making construction records, maps, and operating history available as necessary for safe operation and maintenance. Alignment sheets reviewed in Glendive for the Poplar pipeline have been redlined to reflect new crossings and other changes. BPL reported that this set of alignment sheets are the only updated copy for the Poplar pipeline. 6 $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. a. BPL procedures require periodic review of work done by the operator to determine the adequacy of procedures used in normal operations and maintenance. BPL has not completed any of these reviews. b. BPL procedures require periodic review of work done by the operator to determine the adequacy of procedures used in controlling abnormal operations. BPL has not completed any of these reviews. 7, $195. 402 Procedural manual for operations, maintenance, 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 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. BPL liaison activity efforts do not insure that local responders, including those at remote locations, understand how to respond to a pipeline emergency for the Poplar, and Butte pipeline systems. 8. $195. 403 Emergency Response Training. (b) At the intervals not exceeding 15 months, but at least once each calendar year, each operator shall:#

bpl 5-2007-5003 nopv-pco 2-2-07_text.pdf, page 4(1) Review with personnel their performance in meeting the objectives of the emergency response training program set forth in paragraph (a) of this section; and (c) Each operator shall require and verify that its supervisors maintain a thorough knowledge of that portion of the emergency response procedures established under 195. 402 for which they are responsible to ensure compliance. a. BPL does not review with personnel, once each calendar year not to exceed 15 months, their performance in meeting the objectives of the emergency response training program. b BPL does not verify that their supervisors have adequate knowledge of emergency response procedures. 9. $195. 410 Line markers. (a) Except as provided in paragraph (b) of this section, each operator shall place and maintain line markers over each buried pipeline in accordance with the following: (1) Markers must be located at each public road crossing, at each railroad crossing, and in sufficient number along the remainder of each buried line so that its location is accurately known. During this inspection several markers were down along the Poplar pipeline segment that is north of Glendive just south of the Highway 254 crossing. 10, $195. 422 Pipeline Repairs. (a) Each operator shall, in repairing its pipeline systems, insure that the repairs are made in a safe manner and are made so as to prevent damage to persons or property. None of the several type B repair sleeves installed on the Poplar pipeline in 2005 were NDTed at the sleeve to pipe fillet welds. Operator's records do not appear to indicate if these welds were visually examined. Industry practice has been to use some type of NDT inspection of all sleeve to pipe fillet welds to insure that repairs are made in a safe manner to prevent damage to persons or property during and after repairs. 11. $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/i 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.#

bpl 5-2007-5003 nopv-pco 2-2-07_text.pdf, page 5BPL does not, once each calendar year not to exceed 15 months, test or calibrate pressure transducers that transmit data to the SCADA center on the Poplar pipeline. Pressure transmitters that send pressure data to manned SCADA centers are part of the pressure control system and as such must be tested once each calendar year not to exceed 15 months. 12. $195. 440 Public awareness Each operator shall establish a continuing educational program to enable the public, appropriate government organizations and persons engaged in excavation-related activities to recognize a hazardous liquid or a carbon dioxide pipeline emergency and to report it to the operator or the fire, police, or other appropriate public officials. The program must be conducted in English and in other languages commonly understood by a significant number and concentration of non-English speaking population in the operator's operating areas. BPL's Public Awareness Program is inadequate, at providing pipeline information to the general public. 13. $195. 579 What must I do to mitigate internal corrosion? (c) Removing pipe. Whenever you remove pipe from a pipeline, you must inspect the internal surface of the pipe for evidence of'corrosion. If you find internal corrosion requiring corrective action under Sec. 195„585, you must investigate circumferentially and longitudinally beyond the removed pipe (by visual examination, indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the removed pipe. There is no documented internal inspection of pipe upstream or downstream of pipe replacements that were part of the integrity repairs for the Poplar Pipeline. 14. $195. 583 What must I do to monitor atmospheric corrosion control? (a) You must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows: If the pipeline is located: Then the frequency of inspection is: Onshore At least once every 3 calendar years, but with intervals not exceeding 39 months Offshore At least once each calendar year, but with intervals not exceeding 15 months (b) During inspections you must give partiicular attention to pipe at soil-to-air interfaces, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water. (c) If you find atmospheric corrosion during an inspection, you must provide protection against the corrosion as required by Sec. 195. 581. BPL has not completed or documented any of their atmospheric corrosion inspections BPL has no plan for examining those pipe surfaces that are in contact with concrete saddles.#

bpl 5-2007-5003 nopv-pco 2-2-07_text.pdf, page 6Pro osed Com liance Order Pursuant to 49 United States Code $ 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to BPL. Please refer to the Proposed Compliance Order that is enclosed and made a part of this Notice. Warnin Items With respect to item(s) 1, 2, 6a, 6b, 7, 8a, 8b, 9, 12, and 13 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 BPL being subject to additional enforcement action. Res onse 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. 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 5-2007-5003 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, C is 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 ¹114331, ¹114330, ¹114253)#

bpl 5-2007-5003 nopv-pco 2-2-07_text.pdf, page 7PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code $ 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to BPL a Compliance Order incorporating the following remedial requirements to ensure the compliance of BPL with the pipeline safety regulations: 1. With respect to Item 3 of the Notice BPL must: Ensure that all weld procedures used for pipeline construction, repairs, and operation and maintenance have been qualified using destructive testing Provide PHMSA records of all the above welding procedures to include the qualification records. 2. With respect to Item 4 of the Notice BPL must: Excavate and examine XR 11 on a short replacement project on the Poplar pipeline not to be confused with weld XR 11 that was part of the 17, 000 foot repair project on the Poplar pipeline. If defects are found then those defects shall be repaired. Document all inspection and repair activities and provide those records to PHMSA. 3. With respect to Item 5 of the Notice BPL must. Update all Poplar pipeline alignment sheets used by operations and maintenance personnel to accurately reflect the location of breakout tanks, pump stations, scraper and sphere facilities, pipeline valves, facilities to which $195. 402(c)(9) apphes, rights- of-way, safety devices to which $195. 428 applies, all crossings of public roads, railroads, rivers, buried utilities and foreign pipelines, the maximum operating pressure of each pipeline, and the diameter, grade, type and nominal wall thickness of all pipe, Ensure that appropriate operations personnel receive copies of these revised drawings. Provide a copy of those updated alignment sheets to PHMSA. 4. With respect to Item 10 of the Notice BPL must: Excavate and nondestructively test 50'/0 of all sleeve to pipe fillet welds made as part of the Poplar pipeline integrity repairs of 2004 and 2005. If any of the excavated welds shows indications of cracking then the balance of all welds will be excavated and nondestructively tested. Provide documentation of all weld inspections and any associated repairs to PHMSA.#

bpl 5-2007-5003 nopv-pco 2-2-07_text.pdf, page 85. With respect to Item 11 of the Notice BPL must Test all pressure transducers that are used for operations of the Poplar pipeline including those transducers that are part of the computational pipeline monitoring (CPM) system. Ensure that all pressure transducers that are used for operations of the Poplar pipeline, including those transducers that are part of the CPM system, are tested and inspected once each calendar year not to exceed 15 months. Provide documentation of tests for all pressure transducers that are used for operations of the Poplar pipeline including those transducers that are part of the CPM system. 6. With respect to Item 14 of the Notice BPL must: Complete an atmospheric corrosion inspection of all exposed piping on the Poplar and pipeline. These inspections shall include but not be limited to the soil to air interfaces and under pipe supports. Document all of the above inspections Provide protection for all areas of corrosion found during the above inspections. 7. Within 60 days of issuance of the Final Order, Bridger Pipeline Company (BPL) must complete the above items, and submit the required documentation and procedures to the Director, Western Region, Pipeline and Hazardous Materials Administration, 12300 West Dakota Ave, ¹110, Lakewood, Colorado 80228. 8 BPL shall maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to 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.#

520075003_Decision on Petition for Reconsideration_06162009_text.pdf, page 1Official PDFJUN 16 2009 VIA CERTIFIED MAIL-RETURN RECEIPT REQUESTED [7005 1160 0001 0046 9600] Mr. Hank True President Bridger Pipeline Company, LLC 455 N. Poplar Street P.O. Drawer 2360 Casper, WY 82602 Re: CPF No. 5-2007-5003 Dear Mr. True: Enclosed is the decision on the petition for reconsideration filed by Bridger Pipeline Company, LLC in the above-referenced case. For the reasons specified therein, the decision withdraws the finding of violation with regard to Item 11, and reaffirms the previously-granted extension of time to complete the terms of the Compliance Order associated with Items 4 and 10. This decision is the final administrative action in this proceeding. Your receipt of the document constitutes service 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: Colin G. Harris, Esq. Holme Roberts & Owen LLP 1801 13th St., Ste 300 Boulder, CO 80302-5387 Fax: (303) 866-0200#

520075003_Decision on Petition for Reconsideration_06162009_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 ) Bridger Pipeline Company, LLC, ) CPF No. 5-2007-5003 ) ) ) Petitioner. ) ____________________________________) DECISION ON RECONSIDERATION On April 2, 2009, in accordance with 49 U.S.C. § 60118 and 49 C.F.R. § 190.213, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a Final Order in this matter finding Bridger Pipeline Company, LLC (Bridger or Petitioner) had violated certain federal pipeline safety standards within 49 C.F.R. Part 195. Specifically, the Final Order found Bridger had violated §§ 195.214 (Item 3 in the Final Order), 195.230 (Item 4), 195.402(c)(1) (Item 5), 195.422(a) (Item 10), 195.428(a) (Item 11), and 195.583 (Item 14). PHMSA did not assess any civil penalties against Bridger for the violations, but ordered the company to take specific corrective actions to achieve compliance. The Final Order also found Bridger had committed 10 other probable violations and warned the company to correct them or face possible future enforcement action. On April 21, 2009, Petitioner filed a petition for reconsideration of the final order as permitted pursuant to § 190.215 (Petition). In the Petition, Bridger sought reconsideration of the finding in the Final Order regarding the violation of § 195.428(a) (Item 11), and the terms of the Compliance Order associated with that violation. Petitioner also requested a stay of those compliance terms. Finally, Bridger sought reconsideration of the time allowed to comply with the terms of the Compliance Order associated with §§ 195.230 and 195.422(a) (Items 4 and 10, respectively). By letter dated April 24, 2009, Petitioner submitted an affidavit in support of its request for reconsideration of those requirements in the Compliance Order. By letter dated May 8, 2009, I granted a stay of the terms of the Compliance Order associated with Item 11, as well as an extension of time to comply with the terms associated with Items 4 and 10. The merits of Bridger’s petition for reconsideration are discussed below. Item 4: The Final Order found Bridger had violated 49 C.F.R. § 195.230 by failing to repair a pipeline weld that the company had earlier determined was unacceptable. The terms of the Compliance Order associated with that violation require the company to submit documentation#

520075003_Decision on Petition for Reconsideration_06162009_text.pdf, page 32 that the weld has been excavated, examined, and removed or repaired, as appropriate. The completion of this corrective action was ordered within 60 days of receipt of the Final Order. In its Petition, Bridger contended there are “compelling grounds to reverse the ruling,” but elected not to seek reconsideration of the finding of violation “in the spirit of cooperation.”1 Petition at 5. Petitioner did, however, seek reconsideration of the 60-day period for fulfilling the associated terms of the Compliance Order. Bridger contended that it needed more time to locate, hire and mobilize a crew to complete the repairs and that wet and muddy spring weather conditions would delay commencement. Bridger requested that the company be given 180 days from issuance of a modified Compliance Order, effectively resulting in a deadline in late- November to early-December 2009. In order to expeditiously address Petitioner’s request for an extension, I issued a letter on May 8, 2009, which provided an extension of time until October 31, 2009, to complete the Compliance Order terms associated with Item 4. After considering the Petition in full, I reaffirm the extended deadline of October 31, 2009, finding that it provides sufficient time for Bridger to complete the required activities given weather conditions and the logistics of implementation. Accordingly, the compliance deadline for the Compliance Order terms associated with Item 4 remains October 31, 2009. Item 10: The Final Order found Bridger had violated 49 C.F.R. § 195.422(a) by failing to ensure that certain pipeline repairs were completed in a safe manner. The terms of the Compliance Order associated with that violation require the company to, among other things, submit documentation that the repair welds have been excavated, examined, and, if necessary, repaired. As with Item 4, the completion of these corrective actions was ordered within 60 days of receipt of the Final Order. In its Petition, Bridger stated that it had completed examination of approximately 60% of the welds subject to this requirement, but that the scope of this project and scheduling issues for both the contractor and Bridger in relation to other pipeline maintenance projects warranted reconsideration of the 60-day period for compliance. Bridger requested that the deadline be extended to 180 days from issuance of a modified Compliance Order, which, as referenced above, would result in a deadline of late-November to early-December 2009. By the same letter dated May 8, 2009, I provided Bridger an extension of time until October 31, 2009, to comply with the terms of the Compliance Order associated with Item 10. After 1 Although Bridger did not seek reconsideration of the finding of violation, the company argued in its Petition that no evidence in the record supported the finding that the welding inspector had determined the pinhole defect was “detrimental” to the weld. I have considered Petitioner’s argument, but reaffirm the finding in the Final Order based upon Bridger’s own records, which show that the company (through its welding inspector) had rejected the weld because it found the weld to be unacceptable and had documented its determination on an inspection form. The company was therefore required to remove or repair the weld pursuant to § 195.230. Final Order at 4-5. Bridger also argued in its Petition that one of the company’s witnesses definitively stated the weld had been repaired. To the contrary, Bridger had multiple witnesses testify that the operator’s normal practice was to repair welds but that with respect to the particular weld at issue in this case, the same witnesses testified that they “believe[d]” the repair had been made or that the repair had “likely” been made—hardly definitive statements. Final Order at 5. I note further that Bridger had no record of the repair ever being made.#

520075003_Decision on Petition for Reconsideration_06162009_text.pdf, page 43 considering Bridger’s Petition, I reaffirm the new deadline of October 31, 2009, finding that it provides sufficient time for Bridger to complete the required activities. Accordingly, the deadline for compliance with the terms of the Compliance Order associated with Item 10 remains October 31, 2009. Item 11: The Final Order found that Bridger violated 49 C.F.R. § 195.428(a) by failing to calibrate transmitters that sent pressure data to the company’s Supervisory Control and Data Acquisition (SCADA) center. The relevant language of § 195.428(a) states: § 195.428 Overpressure safety devices and overfill protection systems. (a) [E]ach 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 finding of violation in the Final Order was based, in part, on an interpretation and application of the term “pressure control equipment” to apply to those devices referred to in the Notice that send pressure data from Bridger’s pipeline to the company’s SCADA center. In its Petition, Bridger argued, inter alia, that such devices were neither properly alleged in the Notice, nor properly determined in the Final Order, to be items of “pressure control equipment” under § 195.428(a). Pressure transducers and transmitters The Notice alleged that Bridger failed to calibrate “pressure transducers that transmit data to the SCADA center on the Poplar pipeline.” Notice at 5. The Notice further stated that “[p]ressure transmitters that send pressure data to manned SCADA centers are part of the pressure control system.” Id. Bridger argued in its Petition that the Notice “did not consistently or clearly define or identify the type of equipment that Bridger allegedly failed to test.” Petition at 2. The company further argued that because of the confusion caused by this imprecise allegation, Bridger introduced evidence that the company tested local mechanical transducers, rather than pressure transmitters. Bridger now contends that the company has been prejudiced by the assertion in the Final Order “for the first time in this proceeding,” that the allegation in the Notice applies to pressure transmitters that deliver signals to the SCADA system. Id. Bridger’s argument that the devices at issue in this case were not properly identified in the Notice is unpersuasive in light of the actual language of the Notice, which adequately described the equipment at issue as the pressure transducers that transmit data to the SCADA center. The Notice further identified the devices as the pressure transmitters that send pressure data to manned SCADA centers. As explained in the Final Order, use of both terms “transducer” and “transmitter” in the Notice referred to the same transducer-transmitter assembly that senses pressure on Bridger’s pipeline and transmits that pressure data to the company’s SCADA center.#

520075003_Decision on Petition for Reconsideration_06162009_text.pdf, page 54 As further explained in the Final Order, a “transducer” is a generic term referring to an electro- mechanical device that reads a physical metric (in this case, pipeline pressure) and translates that data into an electronic signal that can then be transmitted, usually by wire. A “transmitter” is the electronic assembly that is comprised of a transducer at the front end and that transmits the signal. Although the two terms can be distinguished in certain applications, the use of these terms together in the Notice referred to the common assembly that Bridger uses to measure pipeline pressure, to translate that data into an electronic signal, and then to transmit that data to the company’s SCADA center. For brevity, the Final Order used the term “pressure transmitter” to refer to this entire mechanism. Accordingly, the term “pressure transmitter,” as used in the Final Order, means the assemblies comprised of a combined transducer-transmitter that Bridger uses to sense pressure on the Poplar pipeline and send that pressure data to its SCADA center. At the hearing, Petitioner introduced evidence that the company calibrates other types of transducers, referred to as on-site mechanical devices that sense pressure, which are hard-wired to mechanically shut down the pipeline during an overpressure. Bridger’s expert readily admitted, however, that such mechanical transducers operate “locally and independent of the SCADA system. ” Final Order at 10. Since those devices for which Petitioner introduced evidence do not transmit data to the SCADA center, they clearly were not the devices at issue in the Notice. Nor do I find anything in the record to support Petitioner’s assertion that PHMSA clarified at the hearing the intent of the Notice was to allege that Bridger failed to test mechanical transducers. That would certainly not be consistent with the allegation in the Notice, because Petitioner’s mechanical transducers do not transmit pressure data to the SCADA center. If, on the other hand, statements made at the hearing by PHMSA were meant to focus the discussion or allegation on the transducer components of the combined transducer-transmitter units identified in the Notice, that would not be inconsistent with the allegation or finding in the Final Order that Bridger failed to calibrate its pressure transmitters that send pressure data to the SCADA center, because as explained above, such devices consist of a transducer. Ordinary meaning of “pressure control equipment” in § 195.428(a) The Final Order found that § 195.428(a) does not explicitly define “pressure control equipment,” but that the ordinary meaning of those terms would include devices used to control pipeline operating pressure, such as pressure transmitters that send pressure data to a SCADA center where operating pressure is controlled. In its Petition, Bridger objected to any use of the “ordinary meaning” of this term, because PHMSA had not presented evidence about the ordinary meaning at the hearing. Petition at 2. PHMSA’s use of the ordinary meaning was nothing more than a reference to generally- understood meanings of the words “pressure,” “control,” and “equipment.” For example, “pressure” is defined as the application of force to something by something else in contact with it. The American Heritage Dictionary of the English Language 1389 (4th ed. 2000). As used in § 195.428(a), therefore, “pressure” refers to the application of force to the pipe by the hazardous liquid inside. The dictionary defines “control” as the exercise of influence over something. Id. at 400. In this case, we are referring to exercising influence over pipeline pressure. Finally, the#

520075003_Decision on Petition for Reconsideration_06162009_text.pdf, page 65 dictionary defines “equipment” as the tool utilized for a particular purpose. Id. at 603. Putting these terms together, it is not difficult to recognize the ordinary meaning of “pressure control equipment” includes the tools and devices used by a pipeline operator to restrain and control pressure within a pipeline. I do not find anything improper about taking note of the ordinary meaning of the phrase “pressure control equipment, ” and deducing therefrom that the broad meaning of the term includes pressure transmitters to the extent they are used to control pipeline pressure. Whether the application of § 195.428(a) in the Final Order was too broad As mentioned above, the Final Order interpreted “pressure control equipment” in § 195.428(a) to include pressure transmitters that send pressure signals to on-site devices and to off-site locations that control pipeline pressure. Bridger objected to this interpretation in its Petition, arguing that such a broad interpretation would include all pressure transmitters “even if the transmitter simply sends a [pressure] signal to a SCADA system.” Petition at 2. After a careful and thorough reconsideration of the agency’s application of the regulation in this proceeding, I have concluded that the application of § 195.428(a) in the Final Order to cover all pressure transmitters, regardless of their actual role in the operator’s overpressure protection system, was in error. While a broad interpretation that would encompass all such devices could be legally supported, I find as a matter of policy that § 195.428(a) should not be applied so broadly as to cover all pressure transmitters indiscriminately. The broad treatment of all pressure transmitters in the Final Order did not properly consider certain distinctions between pressure transmitters that serve as an integral part of a pipeline’s overpressure protection system, and those that only function to send pressure information to the SCADA system for other reasons. For example, certain pressure transmitters on a pipeline may be utilized to send pressure data to remote terminal units or program logic computers that use that data to automatically control pressure to avoid an overpressure event. These types of pressure transmitters, and other devices integral to a pipeline’s overpressure protection system, clearly should be (and are) covered by the regulatory requirement in § 195.428(a). By comparison, pressure transmitters that only send pressure information to the SCADA system for use by a human controller, or for other informational purposes, may not be part of a particular pipeline’s overpressure protection system, and as such are not intended to be covered by § 195.428(a). Even though the ordinary meaning of “pressure control equipment” could potentially include the latter, PHMSA does not intend to apply the requirement in § 195.428(a) so broadly. Whether the evidence supports a finding of violation under § 195.428(a) Based upon my conclusion that § 195.428(a) should not apply indiscriminately to all pressure transmitters but only to those that are integral to a pipeline’s overpressure protection system, I must reconsider whether the evidence in this case supports a finding of violation. In its Petition, Bridger argued that “PHMSA presented no [evidence] about Bridger’s transmitters and its#

520075003_Decision on Petition for Reconsideration_06162009_text.pdf, page 76 SCADA system in relation to the regulatory meaning of ‘pressure control equipment.’” Petition at 2. I agree that PHMSA did not introduce any evidence showing how the pressure transmitters on Bridger’s system were actually utilized other than that they sent pressure information to the company’s SCADA center. I find the evidence introduced by PHMSA is insufficient to conclude whether the pressure transmitters referred to in the Notice were integral to the pipeline’s overpressure control system. Bridger, on the other hand, introduced evidence that its overpressure control system utilized local mechanical devices that operated independent of its SCADA system. Without additional evidence in the record demonstrating that the pressure transmitters referred to in the Notice were an integral part of Bridger’s overpressure protection system, I cannot find a violation of § 195.428(a). Accordingly, I am withdrawing the finding of violation with respect to § 195.428(a). The terms of the Compliance Order associated with this violation are also withdrawn. Since the violation is withdrawn for the above reasons, it is not necessary to address the additional arguments for withdrawal presented by Bridger in its Petition. Conclusion: The terms of the Compliance Order associated with Items 4 and 10 are modified such that the deadline for completion of both Items is October 31, 2009. The finding of violation in Item 11 of the Final Order is withdrawn, as are the terms of the Compliance Order associated with that Item. All other terms of the Final Order remain in effect as set forth therein. This Decision on Reconsideration is the final administrative action in this proceeding. ___________________________________ __________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety#