EL PASO NATURAL GAS CO — Notice of Probable Violation

party submissionOfficial PDF420071007_NOPV Post Hearing Response_06122008.pdf#

case documentOfficial PDF420071007_nopvpcppco_07242007_text.pdf#

420071007_Closure Letter_05292012_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED May 29, 2012 Mr. Daniel B. Martin Senior Vice President, Pipeline Safety El Paso Corporation P.O. Box 2511 Houston, TX 77252-2511 Mr. Lee Hobbs Senior Vice President and General Manager US Pipelines ANR Pipeline Corporation TransCanada Corporation P.O. Box 2446 Houston, TX 77252-2446 CPF 4-2007-1007 Dear Mr. Martin and Mr. Hobbs: On March 10, 2011, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to El Paso Corporation and ANR Pipeline Company a Final Order in the above-referenced case. This Order included a Compliance Order and Civil Penalty assessment. Payment of the civil penalty was received on April 4, 2011. Based on our review of the documentation you provided, it has been determined that you have complied with the terms of this Order. Accordingly, this case is now closed and no further action is contemplated with respect to the matters involved in this case. Thank you for your cooperation in this matter. Sincerely, R. M. Seeley Director, Southwest region Pipeline and Hazardous Materials Safety Administration#

420071007_Final Order_03102011_text.pdf, page 1Official PDFMAR 10 2011 Mr. Daniel B. Martin Senior Vice President, Pipeline Safety El Paso Corporation P.O. Box 2511 Houston, TX 77252-2511 Mr. Lee Hobbs Senior Vice President and General Manager US Pipelines ANR Pipeline Corporation Trans Canada Corporation P. O. Box 2446 Houston, TX 77252-2446 Re: CPF No. 4-2007-1007 Gentlemen: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation, assesses a civil penalty of $129,000 against El Paso Corporation, and specifies actions that need to be taken by both El Paso Corporation and ANR Pipeline Company to comply with the pipeline safety regulations. The penalty payment terms are set forth in the Final Order. When the civil penalty has been paid and the terms of the compliance order completed, as determined by the Director, Southwest Region, this enforcement action will be closed. Service of the Final Order by certified mail is deemed effective upon the date of mailing, or as otherwise provided under 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Jeffrey D. Wiese Associate Administrator for Pipeline Safety Enclosure cc: Mr. Rod Seeley Director, Southwest Region, PHMSA CERTIFIED MAIL – RETURN RECEIPT REQUESTED [7005 1160 0001 0040 0153]#

420071007_Final Order_03102011_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 ) El Paso Pipeline Corporation, ) CPF No. 4-2007-1007 and ) ANR Pipeline Company, ) ) ) ) ) ) Respondents. ) ____________________________________) FINAL ORDER During the weeks of April 17-21, May 1-5, and May 22-26, 2006, pursuant to 49 U.S.C. § 60117, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the facilities and records of El Paso Pipeline Group, a division of El Paso Corporation (El Paso) in Houston, Texas. The following pipeline systems were covered in the inspection: Southern Natural Gas Co., Colorado Interstate Gas Co., El Paso Natural Gas Co., Tennessee Gas Pipeline Co. (El Paso), ANR Pipeline Co., Mojave Pipeline Operating Co., and Bear Creek Storage Co. Collectively, these systems include over 47,000 miles of natural gas transmission pipelines. As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to El Paso, by letter dated July 24, 2007, a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that El Paso had committed various violations of 49 C.F.R. Part 192 and proposed assessing a civil penalty of $129,000 for two of the alleged violations. The Notice also proposed ordering El Paso to take certain measures to correct the alleged violations. On February 22, 2007, one of El Paso’s subsidiaries, ANR Pipeline Company (ANR), was acquired by a subsidiary of TransCanada Corporation.1 Both El Paso and ANR (collectively, Respondents) responded to the Notice by letter dated August 23, 2007 (Response), contested the allegations, and requested a hearing. An informal hearing was subsequently held on April 30, 2008, in Houston, Texas, with an attorney from the Office of Chief Counsel, PHMSA, presiding. At the hearing, Respondents were represented by counsel and submitted a binder of documents and slides. After the hearing, the companies provided additional material for the record by letter dated June 12, 2008 (Closing). 1 Response, at 1.#

420071007_Final Order_03102011_text.pdf, page 32 FINDINGS OF VIOLATION The Notice alleged that Respondents violated 49 C.F.R. Part 192, as follows: Item 1: The Notice alleged that Respondents violated 49 C.F.R. § 192.5(c), which states, in relevant part: § 192.5 Class locations. (a) . . . (c) The length of Class locations 2, 3, and 4 may be adjusted as follows: (1) . . . (2) When a cluster of buildings intended for human occupancy requires a Class 2 or 3 location, the class location ends 220 yards (200 meters) from the nearest building in the cluster. § 192.903 What definitions apply to this subpart? The following definitions apply to this subpart: . . . High consequence area means an area established by one of the methods described in paragraphs (1) or (2) as follows: (1) An area defined as— (i) A Class 3 location under §192.5; or . . . . The Notice alleged that Respondents violated 49 C.F.R. § 192.5 by failing to properly delineate a Class 3 location for High Consequence Area (HCA) 2718 on Line 1204, in a manner that captured all buildings intended for human occupancy in the class location unit. Specifically, the Notice alleged that the boundaries established under Respondents’ approach for delineating Class 3 locations did not include approximately eight structures to the west of HCA 2718 on its HCA map, as required by § 192.5. In their Response and at the hearing, the companies contended that they interpreted the regulations on “clustering” to allow them to exclude these eight buildings from the Class 3 area. Under 49 C.F.R. Part 192, natural gas pipelines are categorized into different class locations. The purpose of designating class locations is to apply higher safety standards to pipelines located near densely populated areas and to protect people working and living in those areas. External stresses on pipelines, the potential for damage from third parties, and other factors which contribute to accidents all tend to increase with higher population densities in the vicinity of pipelines, as do the consequences of accidents. Under the regulations, class locations are used as a means of determining the frequency of monitoring pipelines and patrolling rights-of-way, for conducting leakage surveys, and for determining the maximum allowable operating pressure (MAOP) of gas pipelines.#

420071007_Final Order_03102011_text.pdf, page 43 A “class location unit” is defined under the regulations as an “area that extends 220 yards (200 meters) on either side of the centerline of any continuous 1-mile (1.6 kilometer) length of pipeline. ”2 The class location is determined by the number and type of buildings in a given lowest density and Class 4 being the highest. A group of buildings within the class location unit is sometimes referred to as a “cluster” of buildings. continuous one-mile length of pipeline known as the "sliding mile,”3 with Class 1 being the Class 3 areas are defined in the pipeline safety regulations as “any class location unit that has 46 or more buildings intended for human occupancy.”4 Each separate dwelling unit in a multiple dwelling unit building is counted as a separate building intended for human occupancy.5 Class 3 areas also include those where the pipeline lies within 100 yards of either a building or a small, well-defined outside area, such as a playground, recreation area, outdoor theater, or other place of public assembly, that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period.6 The length of a Class 3 location unit, however, can be adjusted under certain circumstances. Under § 192.5(c)(2), “[w]hen a cluster of buildings intended for human occupancy requires a Class 2 or 3 location, the class location ends 220 yards (200 meters) from the nearest building in the cluster,” rather than at the end of the one-mile class location unit that would otherwise determine the end point of the unit. Clustering is therefore a means of reducing the length of a Class 2 or 3 area in a sliding mile unit that requires a Class 2 or 3 location.7 In this case, however, Respondents argue that clustering should also serve as a means of excluding buildings in the sliding mile from being part of the Class 3 area at all. They argue that the group of eight buildings to the west of HCA 2718 on their HCA map should be excluded from the Class 3 area, despite being located within the Class 3 sliding mile containing the other buildings in the HCA. 2 49 C.F.R. § 192.5(a)(1). 3 For example, a pipeline can be divided into 1/8 mile segments and the number of buildings tallied for each segment. The “sliding mile” would be calculated by summing eight consecutive 1/8 mile segment tallies, and assigning the Class accordingly. Then the sliding mile is moved down by one segment and the process is repeated, until the entire line has been evaluated and Classes assigned. Modern software programs typically calculate the sliding mile foot by foot. 4 49 C.F.R. § 192.5(b)(3)(i). 5 49 C.F.R. § 192.5(a)(2). 6 49 C.F.R. § 192.5(b)(3)(ii). 7 For example, if all buildings in a sliding mile containing enough buildings to require a Class 3 location were clustered in the middle of that sliding mile, the Class 3 area would end 220 yards from the nearest building (on either side of the cluster through which the pipeline passes) rather than at the end of the one-mile class location unit that would otherwise be the basis for classification. Thus, if the cluster itself were 200 yards in length, the total length of the Class 3 area would be 640 yards.#

420071007_Final Order_03102011_text.pdf, page 54 They contend that a June 1996 rule amendment, which was reversed one month later, provides preamble of the 1996 correction: support for their position.8 In particular, Respondents cite the following discussion in the “Since the revision was published, [the Research & Special Programs Administration (RSPA)] has learned that many operators customarily apply the cluster adjustment irrespective of buildings outside the cluster. We also learned that this practice was tacitly accepted by RSPA enforcement personnel and may be consistent with instruction at RSPA’s Transportation Safety Institute.”9 Based upon this language, Respondents now contend that the NOPV issued in this proceeding reflects a “new” requirement being imposed by PHMSA in the absence of notice and comment rulemaking and that such new requirement is inconsistent with earlier actions by the agency.10 I reject Respondents’ argument for several reasons. First, § 192.5(c)(2) states that “[w]hen a cluster of buildings intended for human occupancy requires a Class 2 or 3 location, the class location ends 220 yards (200 meters) from the nearest building in the cluster.” Thus, as noted above, the length of a Class 2 or 3 location can be reduced by clustering. The ability to conduct a cluster adjustment, however, is explicitly premised on a given sliding mile unit and the buildings therein requiring a Class 2 or 3 location to begin with. Moreover, § 192.5(c)(2) must be read in conjunction with § 192.5(a)(1), which defines the term “class location unit, ” and subsection (b)(3), which defines the term “Class 3 location. ” When all three subsections are read together, Respondents’ interpretation of clustering contradicts the plain language and purpose of the regulations. If an operator could use clustering to exclude groups of buildings in the sliding mile unit from the unit’s Class 3 classification altogether, it would undermine the regulatory requirement to use a continuous one-mile distance as the class location unit and, under some circumstances, would circumvent the regulatory definition of a Class 3 location. Second, it should be noted that the class location regulations for gas pipelines have been in place for decades and the regulatory requirements reflected in the NOPV are not new. While Respondents are correct that the amendment was reversed by the correction and the previous language on cluster adjustment restored, it is important to note that the amendment being reversed was itself only a narrow limitation stating that a cluster adjustment could only be used for class location units where all buildings in the one-mile unit were in a single cluster. 11 The amended rule did not allow buildings within the sliding mile to be excluded from the class location even before the amendment was reversed. Restoring the status quo—that the cluster 8 See Final Rule, Regulatory Review; Gas Pipeline Safety Standards, 61 FR 28770 (June 6, 1996). See also Correction of Final Regulation, Regulatory Review; Gas Pipeline Safety Standards; Correction, 61 FR 35139 (July 5, 1996). 9 61 FR 35139. 10 Respondents also argue that PHMSA had the opportunity to review its class location procedures during previous El Paso inspections and did not issue any citations for non-compliance. The absence of citations for non-compliance during one inspection visit, however, does not preclude PHMSA from citing the operator as the result of a subsequent inspection. 11 61 FR 28772.#

420071007_Final Order_03102011_text.pdf, page 65 adjustment could potentially be used even when there was more than one Class 3 cluster in a given one-mile Class 3 class location unit—in no way permits clustering to be used as a mechanism to exclude individual or smaller groups of buildings from being part of a particular Class 3 unit. Under the regulations in place both prior to the amendment and after the correction, if individual or smaller groups of buildings are within a Class 3 class location unit, any cluster adjustment must be conducted in a manner that includes them as part of a Class 3 cluster and the Class 3 area endpoint of that cluster would be 220 yards from the outermost building.12 I find that the regulations do not permit the use of clustering as a mechanism to exclude buildings within a Class 3 sliding mile from being part of a Class 3 area and therefore part of the HCA. Respondents were unable to demonstrate that PHMSA published any guidance or other material that would have justified reliance on the approach to clustering now advocated by Respondents. Their approach is inconsistent with the plain language of the regulations and would frustrate the purpose of the class location regulations, which is to ensure that higher safety standards apply in more highly populated areas and thus provide greater protection for human occupants in those areas. Accordingly, after considering all of the evidence and the legal issues presented, I find that Respondents violated 49 C.F.R. § 192.5(c) by failing to define a Class 3 location for HCA 2718 on Line 1204 in a manner that captured all buildings intended for human occupancy in that class location unit. Item 2: The Notice alleged that Respondents violated 49 C.F.R. § 192.907(a), which states: § 192.907 What must an operator do to implement this subpart? (a) General. No later than December 17, 2004, an operator of a covered pipeline segment must develop and follow a written integrity management program that contains all the elements described in § 192.911 and that addresses the risks on each covered transmission pipeline segment. The initial integrity management program must consist, at a minimum, of a framework that describes the process for implementing each program element, how relevant decisions will be made and by whom, a time line for completing the work to implement the program element, and how information gained from experience will be continuously incorporated into the program. The framework will evolve into a more detailed and comprehensive program. An operator must make continual improvements to the program. The Notice alleged that Respondents violated 49 C.F.R. § 192.907(a), by failing to develop and follow, by December 17, 2004, an integrity management program that contained all the elements described in § 192.911. That section states: 12 Nothing in this Final Order is intended to prevent an operator from making proper use of clustering to reduce the length of a Class 2 or 3 area. For example, if a given sliding mile had a group of 47 buildings situated in the first 200 yards at one end of the sliding mile and a second group of 47 buildings situated in the last 200 yards at the other end of the sliding mile and no buildings in between, the 420 yard lengths at either end would be Class 3 areas and the 920 yards in the middle of the mile would not. However, if one or more buildings were later constructed in between, the outermost building would become the last building in each of the two Class 3 clusters and that enlarged cluster’s Class 3 area would have to be expanded to encompass that building plus 220 yards.#

420071007_Final Order_03102011_text.pdf, page 76 § 192.911 What are the elements of an integrity management program? An operator's initial integrity management program begins with a framework (see §192.907) and evolves into a more detailed and comprehensive integrity management program, as information is gained and incorporated into the program. An operator must make continual improvements to its program. The initial program framework and subsequent program must, at minimum, contain the following elements. (When indicated, refer to ASME/ANSI B31.8S (incorporated by reference, see § 192.7) for more detailed information on the listed element.) (a) An identification of all high consequence areas, in accordance with § 192.905. Specifically, the Notice alleged that Respondents failed to identify all HCA areas known as “identified sites” and certain other areas meeting the HCA definition on the basis of having 20 or more structures or certain class location changes.13 In their Response and at the hearing, El Paso and ANR acknowledged that several of their HCAs were “misclassified” in 2004 and stated that they took action in 2005 to “re-classify those areas which had earlier been misclassified as non-HCAs. ”14 Respondents, however, stated that they believed they were in compliance with the regulations because they had developed a detailed and comprehensive HCA identification process and had made ongoing improvements to this process. The companies further argued that they should not be penalized for “the human errors involved in the initial implementation. ”15 The relevant regulations required pipeline operators to identify all HCAs by December 17, 2004 (December 2004 Deadline). Based on the information in the record, 85 HCAs, totaling approximately 32 miles in length, were not properly designated as HCAs by the December 2004 manner in which the process was implemented resulted in the failure to identify the 32 miles as however, did not refute the allegation that they failed to identify these 85 areas as HCAs. Deadline.16 sufficient to constitute compliance with this requirement. The companies acknowledged that the HCA mileage. At the hearing, Respondents expressed the view that the missed areas were statistically insignificant in light of the size of the companies’ overall systems. Respondents, The fact that Respondents had an HCA identification process in place is not Accordingly, after considering all of the evidence and the legal issues presented, I find that Respondents violated 49 C.F.R. § 192.907(a) by failing to develop and follow an integrity management program that included the identification of all HCAs on their pipeline routes by the December 2004 Deadline. To the extent that the information and arguments offered by Respondents are relevant to whether and at what level a civil penalty should be assessed, these are discussed in the Assessment of Penalty section below. 13 49 C.F.R. § 192.903. 14 Closing, at 5. 15 Id., at 6. 16 Respondents’ PowerPoint Presentation dated April 30, 2008, slide 34.#

420071007_Final Order_03102011_text.pdf, page 87 Item 3: The Notice alleged that Respondents violated 49 C.F.R. § 192.917(a) which states: § 192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (a) Threat identification. An operator must identify and evaluate all potential threats to each covered pipeline segment. Potential threats that an operator must consider include, but are not limited to, the threats listed in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 2, which are grouped under the following four categories: (1) Time dependent threats such as internal corrosion, external corrosion, and stress corrosion cracking; (2) Static or resident threats, such as fabrication or construction defects; (3) Time independent threats such as third party damage and outside force damage; and (4) Human error. The Notice alleged that Respondents violated 49 C.F.R. § 192.917(a) by failing to identify and evaluate all potential threats to each covered pipeline segment in their systems. Specifically, it alleged that Respondents failed to consider the threats listed in ASME/ANSI B31.8S, section 2, and to have a threat evaluation process that comprehensively integrated available data to enable full consideration of interacting threat conditions on pipeline integrity. 17 In their Response and at the hearing, El Paso and ANR contended that their threat evaluation and risk-ranking process did indeed account for combinations of threats. The companies indicated that they had considered interactive threats in the risk-ranking process, in accordance with Section 2.2 of ASME B31.8S, and provided several examples, including: (1) the interaction of pre-1970 electric-resistance welded (ERW) pipe with land movement and frost heave conditions; (2) the interaction of couplings, welds, bell and spigot pipe, wrinkle bends with frost heave or backfill removal; and (3) the interaction of coating type and corrosion history. At the hearing, OPS responded by pointing out that while Respondents did consider multiple threats, they did so in an additive, as opposed to a multiplicative, manner. Respondents’ method of considering multiple threats was to assign a numerical value to each of the different threats and then to add those values together for purposes of ranking the overall rather than to add them. They argued that the agency’s position constituted an “unwritten threat level.18 Respondents argued that OPS’ allegation of violation was based upon the agency’s position that the proper method of ranking risk was to multiply the various risk values interpretation” having no factual predicate or scientific basis and that OPS was unable to derive an appropriate multiplier for these interactive threats. 17 ASME B31.8S, Section 2.2, Integrity Threat Classification, states: “The interactive nature of threats (i.e., more than one threat occurring on a section of pipeline at the same time) shall also be considered. An example of such an interaction is corrosion at a location that also has third party damage.” 18 Closing, at 6.#

420071007_Final Order_03102011_text.pdf, page 98 A determination of whether Respondents complied with their obligations under the regulation turns on whether the additive approach they took was sufficient to achieve the purpose of the requirement. As commonly used, the term “interactive” means that the threats are influencing or having an effect on each other. There is no question that multiple pipeline threats influence or have effects on each other. In the context of analyzing interactive threats for purposes of identifying and mitigating safety risks, the real question is how are the threats interacting? Two or more threats acting on the same pipe location may raise the threat beyond what either threat would do independently or if simply added together. For example, does the risk associated with pre-1970 ERW pipe double with the risk of frost heave or does the potential for frost heave increase the ERW pipe risk twenty times? Fully considering threats and performing effective risk ranking requires at least some degree of technical analysis of how the threats interact. The integrity management regulations are designed to be flexible and to allow operators to develop their own processes for threat evaluation that are best suited to their particular pipeline systems and operations. However, such flexibility does not mean that Respondents may simply add threat scores and disregard the undisputedly more complex relationship among threats. The intent of a threat evaluation process is to provide an operator with a sophisticated and accurate measure of the individual and combined threats facing its pipeline system, so that it may address these threats and reduce pipeline integrity risks. In this case, Respondents need not use any specific “plus” factor or any other particular logarithm or process. Rather, the regulations give Respondents the flexibility to develop a procedure that realistically assesses the interactive nature of threats. Only through such a realistic assessment, however, will Respondents have an accurate indication of the potential threats to the integrity of their system. Accordingly, after considering all of the evidence and the legal issues presented, I find that Respondents violated 49 C.F.R. § 192.917(a) by failing to have a threat evaluation process that comprehensively integrated available data to enable full consideration of interacting threat conditions on pipeline integrity. Item 4: The Notice alleged that Respondents violated 49 C.F.R. § 192.933(a), which states: § 192.933 What actions must be taken to address integrity issues? (a) General requirements. An operator must take prompt action to address all anomalous conditions that the operator discovers through the integrity assessment. In addressing all conditions, an operator must evaluate all anomalous conditions and remediate those that could reduce a pipeline's integrity. An operator must be able to demonstrate that the remediation of the condition will ensure that the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment of the covered segment. If an operator is unable to respond within the time limits for certain conditions specified in this section, the operator must temporarily reduce the operating pressure of the pipeline or take other action that ensures the safety of the covered segment. If pressure is reduced, an operator must determine the temporary reduction in operating pressure using ASME/ANSI B31G (incorporated by reference, see Sec. 192.7) or AGA Pipeline Research Committee Project PR-3-805 (``RSTRENG''; incorporated by reference, see Sec. 192.7) or reduce the operating pressure to a level not exceeding 80% of the level at the time the condition was discovered. (See appendix A to this#

420071007_Final Order_03102011_text.pdf, page 109 part 192 for information on availability of incorporation by reference information). A reduction in operating pressure cannot exceed 365 days without an operator providing a technical justification that the continued pressure restriction will not jeopardize the integrity of the pipeline.19 The Notice alleged that Respondents violated 49 C.F.R. § 192.933(a) by failing to take prompt action to address two anomalous conditions on the 2nd North Main of the Southern Natural Gas pipeline system that were discovered through the integrity assessment process. Specifically, the Notice alleged that an anomalous condition (74% wall loss) at Mile Post (MP) 188-45+00 and an anomalous condition at MP 190-49+31 (70% wall loss) were recoated and backfilled, whereas the applicable requirements dictated pipe replacement, repair sleeves, or a reduction in MAOP. In their Response and at the hearing, El Paso and ANR argued that they were not required to perform repairs or implement a pressure reduction to address the two anomalies. They contended that the class area involved in both locations had increased from Class 2 to Class 3. They argued that the NOPV allegation was based on OPS using the Class 3 design factor and the RSTRENG method to conclude that a pressure reduction was required in the absence of repairs, whereas the companies elected to use the ASME B31G method, as permitted by the regulations, and that the latter method allowed the use of the original (Class 2) design factor. Respondents stated that they believed many other pipeline operators took the same approach. At the hearing, OPS maintained that operators were required to make repairs consistent with the current class location. Class location requirements are central to determining the appropriate MAOP on gas pipelines. The integrity management regulations were established for the purpose of increasing the level of safety in HCAs and populated areas. Respondents’ argument that anomaly remediation requirements should be based on the original design factor, rather than the current class location, has the unfortunate consequence that older pipelines would continue to be operated with safety margins below what would be permitted if a new pipeline were to be constructed in the same area. Respondents are correct, however, that the ASME B31G method is a permissible method for determining the appropriate pressure reduction under circumstances where an operator elects not to perform a repair. At the same time, pipeline operators have a general duty to “evaluate all anomalous conditions this case, 74% and 70% of wall thickness respectively, are of sufficient magnitude that they could reduce the pipeline’s integrity, particularly given potential interaction with other threats. and remediate those that “could reduce” a pipeline’s integrity.”20 The depth of the anomalies in Moreover, Respondents did not provide any information concerning the tolerances of the tool that measured these anomalies; therefore, it is possible that the anomalies may even be 2-3% deeper than reported. Respondents also did not provide any information concerning the growth rates of these anomalies. 19 This regulation has since been amended (72 FR 39016; July 17, 2007). 20 49 C.F.R. § 192.933(a).#

420071007_Final Order_03102011_text.pdf, page 1110 If Respondents were allowed to simply recoat and backfill these locations without remediating them, the anomalies could potentially grow to a magnitude exceeding 80% of wall thickness before the next reassessment were conducted. This could potentially be as long as five years. In addition, these anomalies were located in a HCA and therefore posed a heightened threat to public safety. Under the circumstances, a prudent pipeline operator should have either: (1) concluded that these two anomalous conditions could reduce the pipeline’s integrity and performed repairs or implemented a pressure reduction to ensure safe operation; or (2) performed further technical study of the nature of the anomalies and their growth rates to justify a determination that the anomalies could not reduce the pipeline’s integrity. I am not persuaded that the generic approach taken by Respondents, of simply applying ASME B31G, met their obligation to evaluate all anomalous conditions and remediate those that could reduce the pipeline’s integrity. Accordingly, after considering all of the evidence and the legal issues presented, I find that Respondents violated 49 C.F.R. § 192.933(a) by failing to take prompt action to address two anomalous conditions on the 2nd North Main of the Southern Natural Gas pipeline system. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondents. ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122, Respondents are subject to an administrative civil penalty not to exceed $100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any related series of violations. In determining the amount of a civil penalty under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature, circumstances, and gravity of the violation, including adverse impact on the environment; the degree of Respondents’ culpability; their history of prior offenses; their ability to pay the penalty and any effect that the penalty may have on its ability to continue doing business; and the good faith of Respondents in attempting to comply with the pipeline safety regulations. In addition, I may consider the economic benefit gained from the violation without any reduction because of subsequent damages, and such other matters as justice may require. The Notice proposed a total civil penalty of $129,000 for the violations cited above. In the instant case, El Paso was the parent company of ANR at the time of the violations. Therefore, it is the sole “person” financially liable for penalties assessed pursuant to 49 C.F.R. § 190.223 in this proceeding. As a general matter, El Paso also argues that § 60109(c)(9)(A)(iii) only permits PHMSA to act under § 60109(a)(2) to order an operator to revise its integrity management program with a Notice of Amendment type of enforcement action (i.e., to require Respondents to amend their plans and procedures). The company further argues that this statute precludes or does not give PHMSA the authority to act under any other section of Chapter 601 to enforce integrity management program regulations by issuing compliance orders and civil penalties.#

420071007_Final Order_03102011_text.pdf, page 1211 With the enactment of the Pipeline Safety Improvement Act of 2002 (PSIA), the U.S. Congress directed the Department of Transportation, PHMSA, to establish and issue regulations detailing standards for the implementation of an integrity management program. The authority set forth in §§ 60119 and 60122 to enforce pipeline safety standards, laws and regulations through compliance orders and civil penalties has been codified since 1979 and nothing in PSIA or the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (PIPES Act) affected this authority. Any suggestion that, prior to the PIPES Act, section 60109(c)(9)(A)(iii) limited the agency’s authority with respect to operator conduct and to only require an operator to amend an inadequate or noncompliant integrity management program is therefore incorrect. Considering the authority established in §§ 60118 and 60122; the legislative history of both PSIA and the PIPES Act, including H.R. Rep. No. 109-717, Part 2, § 2(g), at 16 (Dec. 5, 2006); and the legal issues presented, I find that PHMSA had the authority and did properly exercise the full spectrum of enforcement tools upon a determination that a risk analysis or integrity management program is inadequate or noncompliant. Item 2: The Notice proposed a civil penalty of $49,000 for Respondents’ violation of § 192.907(a) for failing to have and follow an integrity management program that included the identification of all HCAs on their pipeline routes by the December 2004 Deadline. The identification of all HCAs is a key step in the integrity management process. Failure to indentify all HCAs could hinder an operator’s integrity management program and adversely impact safety. In their Response and at the hearing, the companies stated that the non- compliance was the result of “human error.” Many violations of regulatory requirements, however, are the result of human error. That does not negate the seriousness of the non- compliance. Respondents also noted that only 32 miles of pipeline were affected. However, 32 miles of pipeline is significant, even on a system as large as Respondents’ . The companies have presented no information or arguments that warrant a reduction in the civil penalty amount proposed in the Notice. Accordingly, having reviewed the record and considered the assessment criteria, I assess El Paso a civil penalty of $49,000 for violation of 49 C.F.R. § 192.907(a). Item 4: The Notice proposed a civil penalty of $80,000 for Respondents’ violation of § 192.933(a), for failing to take required action to promptly address two anomalous conditions on the 2nd North Main of the Southern Natural Gas pipeline system. The failure to promptly remediate anomalous conditions of the magnitude involved in this case can have direct safety impacts on the public. While Respondents raised legitimate questions concerning whether the decision not to repair or remediate the two cited anomalies was allowed by the code, having determined that a violation occurred, the gravity of the violation is sufficiently serious to warrant the civil penalty amount proposed in the Notice. Accordingly, having reviewed the record and considered the assessment criteria, I assess El Paso a civil penalty of $80,000 for violation of 49 C.F.R. § 192.933(a).#

420071007_Final Order_03102011_text.pdf, page 1312 In summary, having reviewed the record and considered the assessment criteria for each of the Items cited above, I assess El Paso a total civil penalty of $129,000. Payment of the civil penalty must be made within 20 days of service. Federal regulations (49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed instructions are contained in the enclosure. Questions concerning wire transfers should be directed to: Financial Operations Division (AMZ-341), Federal Aviation Administration, Mike Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, Oklahoma 73125. The Financial Operations Division’s telephone number is (405) 954-8893. Failure to pay the $129,000 civil penalty will result in accrual of interest at the current annual rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to those same authorities, a late penalty charge of six percent (6%) per annum will be charged if payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty may result in referral of the matter to the Attorney General for appropriate action in a district court of the United States. COMPLIANCE ORDER The Notice proposed a compliance order with respect to Items 1−4 in the Notice for violations of 49 C.F.R. §§ 192.5(c), 192.907(a), 192.917(a), and 192.933(a), respectively. Under 49 U.S.C. § 60118(a), each person who engages in the transportation of gas or who owns or operates a pipeline facility is required to comply with the applicable safety standards established under chapter 601. Pursuant to the authority of 49 U.S.C. § 60118(b) and 49 C.F.R. § 190.217, Respondents are ordered to take the following actions to ensure compliance with the pipeline safety regulations applicable to their operations: 1. With respect to the violation of § 192.5(c) (Item 1), El Paso must re-establish the proper boundary for HCA 2718 in accordance with applicable requirements. Both El Paso and ANR must verify all other HCA boundaries for accuracy and ensure any areas initially excluded from their original HCA boundaries are in compliance with the 49 C.F.R. Subpart O integrity management requirements. 2. With respect to the violation of § 192.907(a) (Item 2), Respondents must revise their HCA identification processes as necessary to ensure the complete and accurate identification of all HCAs and take steps to ensure that their personnel are trained to fully utilize such processes. 3. With respect to the violation of § 192.917(a) (Item 3), Respondents must revise their respective threat evaluation processes as necessary to include the use of comprehensively integrated available data to enable full consideration of interacting threat conditions on pipeline integrity. 4. With respect to the violation of § 192.933(a) (Item 4), Respondents must perform corrosion repairs as necessary at the specified locations based on their current classing.#

420071007_Final Order_03102011_text.pdf, page 1413 5. Within 90 days following receipt of this Final Order, submit documentation demonstrating completion of Items 1-4 above to the Director, Southwest Region, PHMSA. Include documentation reporting the costs associated with fulfilling this compliance order and submit the total to the Regional Director. Report costs in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies, and analyses, and 2) total cost associated with replacements, additions, and other changes to pipeline infrastructure. The Regional Director may grant an extension of time to comply with any of the required items upon a written request timely submitted by either Respondents and demonstrating good cause for an extension. Failure to comply with this Order may result in the administrative assessment of civil penalties not to exceed $100,000 for each violation for each day the violation continues or in referral to the Attorney General for appropriate relief in a district court of the United States. Under 49 C.F.R. § 190.215, Respondents have a right to submit a petition for reconsideration of this Final Order. Should either Respondent elect to do so, the petition must be sent to: Associate Administrator, Office of Pipeline Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC 20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address. PHMSA will accept petitions received no later than 20 days after receipt of service of this Final Order by the Respondents, provided they contain a brief statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.215. The filing of a petition automatically stays the payment of any civil penalty assessed. Unless the Associate Administrator, upon request, grants a stay, all other terms and conditions of this Final Order are effective upon service in accordance with 49 C.F.R. § 190.5. ___________________________________ __________________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety#