ENABLE GAS TRANSMISSION, LLC — Notice of Probable Violation

party submissionOfficial PDF420071004_operator response to notice_09282007.pdf#

420071004_Closure Letter_01232012_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED January 23, 2012 Mr. Walter Ferguson Division Sr. VP MidStream Field Operations, Engineering & Construction CenterPoint Energy Gas Transmission, LLC P.O. Box 21734 Shreveport, Louisiana 71151 CPF 4-2007-1004 Dear Mr. Ferguson: On February 11, 2011, the Pipeline and Hazardous Materials Administration issued a Final Order to CenterPoint Energy Gas Transmission Company (CenterPoint) in the referenced case. Based on review of the documentation you provided and confirmation that the administrative civil penalty has been paid, it has been determined that CenterPoint has complied with the terms and conditions of the Final Order. Accordingly, PHMSA now considers this case closed and no further action is contemplated with respect to the maters 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#

420071004_FinalOrder_02112011_text.pdf, page 1Official PDFFEB 11 2011 Mr. Pete Kirsch Division Senior Vice President Pipeline, Operations and Engineering CenterPoint Energy Gas Transmission Company P.O. Box 1700 Houston, Texas 77210-1700 Re: CPF No. 4-2007-1004 Dear Mr. Kirsch: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation, withdraws certain allegations of violation, and assesses a reduced civil penalty of $51,000. The Final Order also specifies certain actions that need to be taken by CenterPoint 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. Your receipt of the 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: Mr. R.M. Seeley, Director, Southwest Region, PHMSA Mr. Kenneth B. Driver, Esq. Counsel for CenterPoint Energy Gas Transmission Jones Day 51 Louisiana Avenue, N.W. Washington, D.C. 20001 CERTIFIED MAIL – RETURN RECEIPT REQUESTED [7005 1160 0001 0041 3221]#

420071004_FinalOrder_02112011_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 ) CenterPoint Energy Gas Transmission Company, ) Respondent. ) ) ) ) ) ) CPF No. 4-2007-1004 _____________________________________________) FINAL ORDER On September 12-16, and November 14-18, 2005, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the Integrity Management Program records of CenterPoint Energy Gas Transmission Company (CenterPoint or Respondent), in Shreveport, Louisiana. approximately 8,200 miles of interstate natural gas pipelines, of which 186 miles were covered by its Integrity Management Program (IMP). 1 At the time of the inspection, Respondent operated As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Respondent, by letter dated March 29, 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 CenterPoint had violated 49 C.F.R. §§ 192.917(a), 192.917(c), 192.917(e)(1), 192.917(e)(4), 192.925(b)(1), 192.927(c)(1)(i), 192.927(c)(5)(ii), 192.929(b)(1), and 192.935(c) and proposed assessing a civil penalty of $95,000 for the alleged violations. The Notice also proposed ordering Respondent to take certain measures to correct the alleged violations. CenterPoint responded to the Notice by letter dated April 30, 2007. Respondent contested the allegations and requested a hearing. In advance of the hearing, by letter dated September 28, 2007, CenterPoint submitted an additional response detailing its arguments and providing supporting documents (Response). A hearing was subsequently held on October 11, 2007, in Houston, TX, with an attorney from the Office of Chief Counsel, PHMSA, presiding. Respondent was represented by counsel in this proceeding. After the hearing, CenterPoint provided a Post-Hearing Submission by letter dated November 13, 2007 (Closing). 1 CenterPoint Energy Gas Transmission Company is an indirect, wholly-owned subsidiary of CenterPoint Energy, Inc.#

420071004_FinalOrder_02112011_text.pdf, page 32 FINDINGS OF VIOLATION The Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows: Item 1: The Notice alleged that Respondent 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 third party damage and outside force damage; and (3) Time independent threats such as third party damage and outside force damage; and (4) Human error. The Notice also recited the relevant portion of ASME B31.8S, section 2, which states: ASME B31.8S, Section 2.2, Integrity Threat Classification 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.2 The Notice alleged that Respondent violated 49 C.F.R. § 192.917(a) by failing to identify or evaluate in its IMP the potential for interactive threats to each covered pipeline segment. Specifically, it alleged that CenterPoint’s procedures contained no process to ensure that multiple threats on the same pipeline were evaluated for interrelated effects.3 CenterPoint contested this allegation, arguing that it used a risk assessment model to add together the individual failure-likelihood values for each threat category, to reach an overall risk score. provided a measure of the interactive nature of threats. CenterPoint also indicated that it was not aware of any published standards beyond ASME B31.8S (ASME Standard) explaining how the company was supposed to evaluate “interactive” threats. Respondent maintained that its procedure appropriately considered the interactive nature of threats. 4 Respondent contended that by adding together different threats, the resulting score 2 AM. SOCIETY OF MECHANICAL ENGINEERS, “MANAGING SYSTEM INTEGRITY OF GAS PIPELINES”, ASME STANDARD B31.8S-2004 § 2.2 (JANUARY 14, 2005). 3 Notice at 1-2, citing CenterPoint Energy Gas Transmission Procedure PS-03-01-216, “Threat Identification and Risk Assessment,” Section 2.2. 4 Response at 4-7.#

420071004_FinalOrder_02112011_text.pdf, page 43 At the hearing, OPS argued that CenterPoint’s process of simply adding the scores of various threats did not constitute an adequate analysis of interactive threats. OPS explained that the combined threat posed by numerous threats could be greater than the sum of those threats individually. On that basis, OPS argued that Respondent’s process of simply adding threat scores did not reflect the complex relationship between multiple threats. For example, OPS indicated that the combined threats presented by internal corrosion and pipeline seam issues, at the same location, would be much greater than the sum of those threats if assessed individually. At the hearing and in its Closing, CenterPoint maintained its objection to this allegation. Respondent argued further that neither the regulation nor the referenced ASME Standard expressly requires that a “plus” factor be used when any two risk factors are present on the same covered segment.5 CenterPoint is correct that nothing in the regulation or the ASME Standard expressly requires a “plus” factor. Section 192.917(a) simply requires that the interactive nature of threats be considered. However, the lack of specificity in the regulation does not mean that it is acceptable to conduct a risk analysis which does not provide an accurate indication of the synergy of multiple threats. Respondent did not dispute the agency’s contention that a combination of threats might well produce a greater threat than the various threats assessed individually; rather, it argued that in the absence of more specific guidance, it was permissible to simply add the threat scores. The Integrity Management regulations are designed to be flexible and permit CenterPoint to come up with a process for threat evaluation that is best suited to its particular pipeline system and operations. However, such flexibility does not mean that Respondent 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. Respondent need not use any specific “plus” factor or any other particular logarithm or process. Rather, the regulations give CenterPoint the flexibility to develop a procedure that realistically assesses the interactive nature of threats. Only through such a realistic assessment, however, will Respondent have an accurate indication of the potential threats to the integrity of its system. Accordingly, based upon a review of all of the evidence, I find that Respondent violated § 192.917(a) by failing to identify or evaluate in its IMP the potential for interactive threats on each covered pipeline segment. Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(c), which states: § 192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (a) …. (c) Risk assessment. An operator must conduct a risk assessment that follows ASME/ANSI B31.8S, section 5, and considers the identified threats for each covered segment…. 5 Closing at 4.#

420071004_FinalOrder_02112011_text.pdf, page 54 The Notice alleged that Respondent violated 49 C.F.R. § 192.917(c) by failing to conduct a risk assessment in accordance with Section 5 of ASME B31.8S. Specifically, it alleged that CenterPoint did not provide documentation in its IMP to support the conclusion that the company could eliminate certain threats from its risk assessment for High Consequence Areas (HCAs) along its pipeline. for risk assessments in a prescriptive integrity management program. 6 Section 5 of the ASME Standard requires minimum data and criteria CenterPoint argued that its risk assessment did include a proper consideration of the required minimum data and criteria for risk assessment to support the elimination of certain threats. Respondent cited its procedures and numerous sections of the ASME Standard in support of its contention that its risk assessment process used the latest available data to determine if CenterPoint’s procedures that were in question but, rather, that Respondent had no threats could be eliminated.7 At the hearing, OPS explained that it was not the adequacy of documentation of having applied these procedures to its pipeline system. CenterPoint responded that it had used the latest data each time it ran the risk assessment model, to determine the threats on its system and whether any threats could be eliminated. However, Respondent provided no documentation of its application of the risk assessment model to the actual pipeline system data. In the absence of such evidence, PHMSA is unable to verify whether the elimination of a particular threat was appropriate or not. Improper elimination could result in HCAs not being properly assessed for the actual threats presented. If a threat is improperly eliminated, it could cause or contribute to a pipeline failure and cause harm to the public, property or the environment. For any given HCA segment where CenterPoint has eliminated a threat, Respondent must provide some evidence in support of its decision. Accordingly, I find that Respondent violated § 192.917(c) by failing to conduct a risk assessment that followed Section 5 of ASME B31.8S, by providing documentation for its decision to eliminate certain threats from its HCAs. Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(1), which states: § 192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (a) …. (e) Actions to address particular threats. If an operator identifies any of the following threats, the operator must take the following actions to address the threat. (1) Third party damage. An operator must utilize the data integration required in paragraph (b) of this section and ASME/ANSI B31.8S, Appendix A7 to determine the susceptibility of each covered segment to the threat of third party damage. If an operator identifies the threat of third party damage, the operator must implement comprehensive 6 A “High Consequence Area” is an area defined as either a Class 3 location or Class 4 location under § 192.5; any area in a Class 1 or Class 2 location where the potential impact radius is greater than 660 feet (200 meters) and the area within a potential impact circle contains 20 or more buildings intended for human occupancy; or as further defined in 49 C.F.R. § 192.903. 7 Response at 8-13.#

420071004_FinalOrder_02112011_text.pdf, page 65 additional preventive measures in accordance with § 192.935 and monitor the effectiveness of the preventive measures. If, in conducting a baseline assessment under § 192.921, or a reassessment under § 192.937, an operator uses an internal inspection tool or external corrosion direct assessment, the operator must integrate data from these assessments with data related to any encroachment or foreign line crossing on the covered segment, to define where potential indications of third party damage may exist in the covered segment. An operator must also have procedures in its integrity management program addressing actions it will take to respond to findings from this data integration. The Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(1) by failing to have a procedure or process to integrate data from internal inspection tools and External Corrosion Direct Assessment (ECDA) with data related to encroachments or foreign line crossings on certain covered segments, in order to define where potential indications of third-party damage might exist. Specifically, it alleged that CenterPoint’s procedures did not include processes for the integration of such data.8 Respondent admitted that its procedures “did not specifically state that the data from ECDA and foreign line crossings would be integrated.”9 However, CenterPoint argued that such data was integrated as part of its ECDA process; the company provided numerous supporting documents in support of its position. integrated some data, they do not demonstrate that Respondent had a written procedure in place, as required by the regulation. In the absence of such a procedure for data integration, there is no mechanism by which Respondent could consistently and accurately integrate assessment data with data on third-party damage. Accordingly, upon review of all of the evidence, I find that Respondent violated 49 C.F.R. § 192.917(e)(1) by failing to have a procedure or process for integrating data from internal inspection tools and ECDA with data related to encroachments or foreign line crossings on each covered pipeline segment. 10 While these documents may indeed indicate that CenterPoint Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(1), as quoted above, by failing to integrate data from internal inspection tools and ECDA with data related to encroachments and foreign line crossings on specific covered segments, in order to define where potential indications of third-party damage might exist. Specifically, it alleged that CenterPoint failed to integrate such data when it performed ECDA assessments for the ALE, BT-1, and A- 206 pipelines. At the hearing, CenterPoint provided documents showing that the company had, in fact, performed data integration on these pipelines.11 Accordingly, based upon a review of all of the evidence, I order that Item 4 be withdrawn. 8 Notice at 3, citing CenterPoint Procedures PS-03-01-110, GATHER, REVIEW AND INTEGRATE DATA; and PS-03- 01-216, THREAT IDENTIFICATION and RISK ASSESSMENT. 9 Response at 16. 10 Id. 11 Response at 19, Attachments 3.1-4.6.#

420071004_FinalOrder_02112011_text.pdf, page 76 Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(4), which states: § 192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program? (a) . . . . (e) Actions to address particular threats. If an operator identifies any of the following threats, the operator must take the following actions to address the threat. (1) …. (4) ERW pipe. If a covered pipeline segment contains low frequency electric resistance welded pipe (ERW), lap welded pipe or other pipe that satisfies the conditions specified in ASME/ANSI B31.8S, Appendices A4.3 and A4.4, and any covered or noncovered segment in the pipeline system with such pipe has experienced seam failure, or operating pressure on the covered segment has increased over the maximum operating pressure experienced during the preceding five years, an operator must select an assessment technology or technologies with a proven application capable of assessing seam integrity and seam corrosion anomalies. The operator must prioritize the covered segment as a high risk segment for the baseline assessment or a subsequent reassessment. The Notice alleged that Respondent violated 49 C.F.R. § 192.917(e)(4) by failing to specify an assessment method for each covered segment to identify anomalies associated with the specific threat identified for that segment. Specifically, the Notice alleged that CenterPoint’s Baseline Assessment Plan (BAP) did not identify an assessment technology with a proven application capable of assessing seam integrity and seam corrosion anomalies for covered pipe segments that contained ERW pipe and had experienced either seam failure or the operating pressure had exceeded maximum operating pressure within the last five years. Section A4 of ASME B31.8S states that “pressure testing must be performed to address the seam issue. allowed for either a hydrotest or the use of a Transverse Flux Inspection (TFI) tool; however, Section A4.4 of the ASME Standard only permits a hydrotest when assessing seam threats. A TFI tool is not an acceptable method of integrity assessment in this case. ”12 CenterPoint’s BAP Respondent admitted that its assessment tool selection guide mistakenly permitted the use of a TFI tool in response to a pressure increase on a pipeline segment containing ERW pipe or pipe with other specified seam issues.13 CenterPoint explained that it had intended to include the TFI tool option only for manufacturing defects, not seam threats.14 Respondent further explained that in spite of such mistake in its procedures, it never actually used a TFI tool in response to a pressure increase15 and that after the OPS inspection, it revised its procedures to address this issue. A TFI tool would not properly address the threat and could subsequently lead to a pipeline 12 ASME STANDARD B31.8S-2004, supra, § A4, “MANUFACTURING THREAT (PIPE SEAM AND PIPE).” 13 Response at 21; Closing at 8. 14 Id. 15 Id.#

420071004_FinalOrder_02112011_text.pdf, page 87 failure affecting public safety. Although CenterPoint notes that it revised its procedures, this modification occurred after the OPS inspection and therefore does not cure the violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 192.917(e)(4) by failing to select a proper assessment technology with a proven application capable of assessing seam integrity and seam corrosion anomalies. Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 192.925(b)(1), which states: § 192.925 What are the requirements for using External Corrosion Direct Assessment (ECDA)? (a) Definition. ECDA is a four-step process that combines preassessment, indirect inspection, direct examination, and post assessment to evaluate the threat of external corrosion to the integrity of a pipeline. (b) General requirements. An operator that uses direct assessment to assess the threat of external corrosion must follow the requirements in this section, in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.4, and in NACE RP 0502–2002 (incorporated by reference, see §192.7). An operator must develop and implement a direct assessment plan that has procedures addressing preassessment, indirect examination, direct examination, and post-assessment. If the ECDA detects pipeline coating damage, the operator must also integrate the data from the ECDA with other information from the data integration (§192.917(b)) to evaluate the covered segment for the threat of third party damage, and to address the threat as required by § 192.917(e)(1). (1) Preassessment. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE RP 0502–2002, section 3, the plan's procedures for preassessment must include— (i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment; and (ii) The basis on which an operator selects at least two different, but complementary indirect assessment tools to assess each ECDA Region. If an operator utilizes an indirect inspection method that is not discussed in Appendix A of NACE RP0502–2002, the operator must demonstrate the applicability, validation basis, equipment used, application procedure, and utilization of data for the inspection method. The Notice alleged that Respondent violated 49 C.F.R. § 192.925(b)(1) by failing to comply with its own procedures and the requirements of NACE RP 0502-2003 (NACE Standard), Section 3, in conducting ECDA preassessments. Specifically, it alleged four separate violations of § 192.925(b)(1). First, it alleged that CenterPoint violated the NACE Standard and its own procedures by failing to define minimum data collection requirements for conducting 16 preassessments. Second, it alleged that the company violated the NACE Standard and its own 16 NACE Standard Section 3.2.1.1 provides: “The pipeline operator shall define minimum data requirements based on the history and condition of the pipeline segment. In addition, the pipeline operator shall identify data elements that are critical to the success of the ECDA process.”#

420071004_FinalOrder_02112011_text.pdf, page 98 procedures by failing to document the basis for the conservative assumptions used on the ALE, BT-1 and A-206 pipelines. 17 Third, the Notice alleged that CenterPoint violated the NACE Standard and its own procedures by failing to document whether an ECDA feasibility assessment had been conducted. 18 Finally, it alleged that Respondent violated the NACE Standard and its own procedures by failing to document either the specific indirect inspection tools that were ultimately chosen or the basis for choosing them. 19 Regarding the first allegation, CenterPoint argued that it had collected adequate data to make an ECDA feasibility determination.20 However, Respondent admitted that its procedures “did not include a list of minimum data requirements defining when ECDA was a feasible violated 49 C.F.R. § 192.925(b)(1) by failing to define minimum data requirements concerning data collection for ECDA preassessments. alternative…”21 Accordingly, upon a review of all of the evidence, I find that Respondent Regarding the second allegation, CenterPoint argued that there is no requirement in § 192.925(b)(1) to document conservative assumptions.22 I disagree. Respondent’s own procedures allowed the use of conservative assumptions and required that they be documented.23 Nonetheless, CenterPoint explained that no conservative assumptions were documented because none were used on the ALE, BT-1, and A-206 pipelines.24 Accordingly, based on a review of the record, I hereby order that this portion of Item 6 be withdrawn. Regarding the third allegation, Respondent argued that it had performed an ECDA feasibility assessment on the ALE, BT-1 and A-206 pipelines.25 The company explained that it had recorded data on preassessment forms but admitted that its ECDA feasibility determination was not recorded.26 CenterPoint further argued that its documentation of ECDA regions and tool 17 Respondent’s ECDA Procedure PS-03-01-232 states that conservative defaults may be substituted when data is missing. Its Quality Assurance Procedure PS-03-01-268 requires the company to “verify that conservative assumptions were documented.” 18 NACE Standard Section 3.3.1 provides: “The pipeline operator shall integrate and analyze the data collected [as required in Section 3.2] to determine whether conditions for which indirect inspection tools cannot be used or that would preclude ECDA application exist.” 19 The Notice also alleged that Respondent failed to document whether the assessment tools were complementary to each other. Proper documentation of the basis for tool selection would invariably include information on whether the tools were complementary. Therefore I do not treat the language in the Notice on complementary tools as a separate allegation. 20 Response at 27-28. 21 Id. 22 Id. at 28. 23 See supra note 13. 24 Response at 28. 25 Id. at 29-30. 26 Id. at 30.#

420071004_FinalOrder_02112011_text.pdf, page 109 By failing to document the process it used to undertake a feasibility determination, Respondent skipped a key step in the ECDA process. Without such documentation, neither Respondent nor OPS can accurately determine whether the ECDA process was properly performed. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 192.925(b)(1) by failing to properly document a feasibility assessment for the ALE, BT-1 and A-206 pipelines. selections proved that it had in fact performed a feasibility determination.27 Again, I disagree. Regarding the fourth allegation, CenterPoint contended that it did document the specific indirect inspection tools selected for the BT-1, ALE, and A-206 pipelines. 28 The regulation requires an operator, as part of its preassessment procedure, to include “the basis on which an operator selects at least two different, but complementary indirect assessment tools to assess each ECDA region.” In addition, the publicly available 2004 OPS IMP Inspection Protocols indicated that on when certain tools should be used, none of these documents explains the basis on which Respondent nor OPS can verify that the proper tools were selected. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 192.925(b)(1) by OPS would verify an operator’s documentation of its ECDA tool selections.29 While CenterPoint has provided documents showing which tools it selected, as well as general guidance specific tools were selected for particular ECDA regions. Absent such documentation, neither failing to document the basis for its selection of indirect inspection tools. Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 192.925(b)(1)(i), as quoted above, and § 192.925(b)(2)(i) and (b)(3)(i), which state: § 192.925 What are the requirements for using External Corrosion Direct Assessment (ECDA)? (a-b) …. (2) Indirect examination. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE RP 0502–2002, section 4, the plan's procedures for indirect examination of the ECDA regions must include— (i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment;… (3) Direct examination. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE RP 0502–2002, section 5, the plan's procedures for direct examination of indications from the indirect examination must include— (i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment;… The Notice alleged that Respondent violated 49 C.F.R. § 192.925(b)(1)(i), (b)(2)(i) and (b)(3)(i) by failing to document how it applied more restrictive criteria when conducting ECDA for the 27 Id. 28 Response at 31, Attachments 6.1–6.3 ECDA Preassessment Forms. 29 PHMSA-OPS Gas Integrity Management Protocol Results Form, Protocol D.02.c, (Oct. 2004) (available at http://primis.phmsa.dot.gov/gasimp/documents.htm).#

420071004_FinalOrder_02112011_text.pdf, page 1110 first time on a covered segment. The cited regulations impose restrictive criteria requirements at the preassessment, indirect examination, and direct examination steps of the ECDA process. Specifically, the Notice alleged that the ECDA assessments for the ALE, BT-1, and A-206 pipelines did not contain any documentation of the more restrictive criteria that CenterPoint used for this initial ECDA. Respondent contested this allegation and provided documents to demonstrate that it had, in fact, this documentation and agrees that it demonstrates more restrictive criteria were in fact used and properly documented. Accordingly, based on the foregoing and a review of the record, I order that Item 7 be withdrawn. documented its use of more restrictive criteria at the time of the inspection.30 OPS has reviewed Item 8: The Notice alleged that Respondent violated 49 C.F.R. § 192.927(c)(1)(i), which states: § 192.927 What are the requirements for using Internal Corrosion Direct Assessment (ICDA)? (a) …. (c) The ICDA plan. An operator must develop and follow an ICDA plan that provides for preassessment, identification of ICDA regions and excavation locations, detailed examination of pipe at excavation locations, and post-assessment evaluation and monitoring. (1) Preassessment. In the preassessment stage, an operator must gather and integrate data and information needed to evaluate the feasibility of ICDA for the covered segment, and to support use of a model to identify the locations along the pipe segment where electrolyte may accumulate, to identify ICDA regions, and to identify areas within the covered segment where liquids may potentially be entrained. This data and information includes, but is not limited to— (i) All data elements listed in appendix A2 of ASME/ANSI B31.8S;… The Notice alleged that Respondent violated 49 C.F.R. § 192.927(c)(1)(i) by failing to evaluate the feasibility of ICDA for certain pipeline segments. Specifically, it alleged that CenterPoint failed to perform or document feasibility evaluations for ICDA preassessments performed on its FT-11 and ADT-8 pipelines. It also alleged that Respondent did not document the basis for selecting the feasibility criteria for pigging, water upsets, and introduction of sludge. The Notice further alleged that Respondent’s ICDA preassessment data for these pipelines was of “poor quality” and that this “could lead” to improper determinations of ICDA regions. CenterPoint argued that it had, in fact, performed and documented feasibility evaluations and feasibility flow charts for the FT-11 and ADT-8 pipelines, and that it had records of the source data used to fill out the charts. 31 The company also pointed to those portions of its IMP procedures that described the basis for selecting feasibility criteria.32 In response, OPS argued 30 Response at 32-35, Attachments 7.2-7.16 31 Response at 37, Attachments 8.1-8.2 and 8.5-8.12. 32 Id., Attachment 8.4, Procedure 03-01-238.#

420071004_FinalOrder_02112011_text.pdf, page 1211 that the flow charts did not constitute the evaluation required by the regulation but the agency did not explain why. While the feasibility flow charts are indeed sparse, they do show that Respondent performed some type of feasibility analysis. In the absence of more specific allegations or some explanation as to why Respondent’s documentation was inadequate, I find that the record does not support a finding of violation for this portion of the allegation. Finally, Respondent argued that it had the necessary data to perform ICDA preassessments and that it was not of “poor quality” . 33 Respondent provided numerous examples of such data.34 Again, the Notice did not explain why CenterPoint’s data was of poor quality or what data was missing. With such lack of specificity in the Notice and upon review of the documents provided by Respondent and which OPS has not addressed, I find that the record does not support a finding of violation on this portion of the allegation. Accordingly, based on the foregoing and a review of the record, I order that Item 8 be withdrawn. Item 9: The Notice alleged that Respondent violated 49 C.F.R. § 192.927(c)(5)(ii), which states: § 192.927 What are the requirements for using Internal Corrosion Direct Assessment (ICDA)? (a) …. (c) The ICDA plan. An operator must develop and follow an ICDA plan that provides for preassessment, identification of ICDA regions and excavation locations, detailed examination of pipe at excavation locations, and post-assessment evaluation and monitoring. (1) …. (5) Other requirements. The ICDA plan must also include– (i) …. (ii) Provisions for apply more restrictive criteria when conducting ICDA for the first time on a covered segment and that become less stringent as the operator gains experience;… The Notice alleged that Respondent violated 49 C.F.R. § 192.927(c)(5)(ii) by failing to document the more restrictive criteria the company used when conducting ICDA for the first time on a covered segment. Specifically, it alleged that CenterPoint failed to document these criteria, both in its ICDA plan and in the initial ICDAs performed on the FT-11 and ADT-8 pipelines. Respondent contested this allegation and provided numerous documents to demonstrate that it had in fact documented more restrictive criteria at the time of the inspection.35 OPS has reviewed these materials and agrees that CenterPoint was in compliance with this regulation at the time of the inspection. Accordingly, based upon the foregoing and a review of the record, I order that Item 9 be withdrawn. 33 Response at 38-39. 34 Response, Attachments 8.13-8.26. 35 Response at 41-43, Attachments 9.1-9.8.#

420071004_FinalOrder_02112011_text.pdf, page 1312 Item 10: The Notice alleged that Respondent violated 49 C.F.R. § 192.929(b)(1), which states: § 192.929 What are the requirements for using Direct Assessment for Stress Corrosion Cracking (SCCDA)? (a) …. (b) General requirements. An operator using direct assessment as an integrity assessment method to address stress corrosion cracking in a covered pipeline segment must have a plan that provides, at minimum, for— (1) Data gathering and integration. An operator's plan must provide for a systematic process to collect and evaluate data for all covered segments to identify whether the conditions for SCC are present and to prioritize the covered segments for assessment. This process must include gathering and evaluating data related to SCC at all sites an operator excavates during the conduct of its pipeline operations where the criteria in ASME/ANSI B31.8S (incorporated by reference, see §192.7), appendix A3.3 indicate the potential for SCC. This data includes at minimum, the data specified in ASME/ANSI B31.8S, appendix A3. The Notice alleged that Respondent violated 49 C.F.R. § 192.929(b)(1) by failing to provide in its IMP a systematic data collection and evaluation process for all covered pipeline segments. Specifically, the Notice alleged four separate violations regarding the SCCDA portion of CenterPoint’s IMP. First, it alleged that Respondent failed to include in its SCCDA plan a requirement for the gathering and integration of data related to SCC at all sites. Specifically, it alleged that CenterPoint excavated both covered and non-covered pipe segments, during its normal course of business, in a manner that met the criteria listed in the ASME Standard indicating potential SCC. The company’s procedures, however, allegedly failed to require the collection of data on non- covered pipelines, as required by the regulation. Second, it alleged that Respondent failed to follow its own procedures by not gathering and reviewing certain data elements used for SCCDA under the ASME Standard. Third, it alleged that Respondent failed to follow the ASME Standard by including a provision in its IMP for notifying PHMSA at least 180 days prior to using a “near-neutral” SCCDA plan. Fourth, it alleged that Respondent failed to follow the ASME Standard by neglecting to include a provision in its IMP requiring the performance of a hydrostatic “spike test” following an in-service leak or rupture attributable to SCC. Regarding the first allegation, Respondent argued that it had performed and documented inspections of its pipelines during excavation and that its procedures for doing so were contained in its Operations and Maintenance (O&M) manual, rather than in its IMP documentation.36 However, Respondent admitted that “its procedures at the time of the audit did not specifically call for evaluation of data at sites where criteria indicate the potential for SCC.”37 Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 192.929(b)(1) by failing to include in its SCCDA plan a requirement for the gathering and integration of data related to SCC at all excavation sites where the criteria listed in the ASME 36 Response at 46. 37 Id. at 47.#

420071004_FinalOrder_02112011_text.pdf, page 1413 Standard indicated the potential for SCC. Regarding the second allegation, Respondent argued that it had, in fact, evaluated the SCCDA- related data as required by its procedures; the company submitted Data Element Forms to support its position. that Respondent performed the requisite evaluations as of the date of the inspection. Accordingly, based on the foregoing and a review of the record, I order that this portion of Item 10 be withdrawn. 38 Upon review of these records, I find that these materials do demonstrate Regarding the third allegation, Respondent argued that its IMP procedure need not contain a provision for notifying PHMSA before using its near-neutral SCCDA plan. CenterPoint argued because § 192.921 allows for the use of direct assessment to address SCC, the near-neutral version of direct assessment technology cannot be considered an “Other Technology” for which it would have to give notice under §192.921(a)(4).39 Respondent also cited several PHMSA “Frequently Asked Questions” (FAQs) on Gas IMP for the proposition that these materials were that it was reasonable to conclude that it did not need to make an “Other Technology” notification to implement its near-neutral variant of SCCDA. internally inconsistent, and in conflict with the regulation.40 On that basis, CenterPoint argued Respondent’s argument, however, does not reflect the different assessment tools that can be used to satisfy the complex, performance-based Gas IMP requirements. Respondent lumps all SCCDA together when reaching its conclusion. Section A3 of the ASME Standard and GAS IMP FAQs distinguish between different kinds of SCCDA. The ASME Standard applies to high-pH SCCDA, not near-neutral SCCDA. 41 The only FAQ that specifically mentions near- neutral SCCDA indicates that it is considered an “Other Technology,” for which notification is required.42 While Section 192.921(a) does permit SCCDA as an assessment tool, it must be read in combination with Section 3 of the ASME Standard, which applies only to high-pH SCCDA. Therefore, near-neutral SCCDA presents a distinct set of issues. It is this distinction that led the drafters of FAQ 223 to note that near-neutral SCC is considered “Other Technology.” Accordingly, based on the foregoing and a review of the record, I find that Respondent violated 49 C.F.R. § 192.929(b)(1) by failing to include a provision in its IMP for notifying PHMSA 180 days before proposing to use its near-neutral SCCDA plan. Regarding the fourth allegation, Respondent argued that its procedures were, in fact, consistent with the requirements in the ASME Standard for hydrotesting a pipeline after an in-service leak or rupture attributable to SCC. CenterPoint contended that the ASME Standard does not use the phrase “spike test” that was mentioned in the Notice and that OPS had misinterpreted the intent 38 Id. at 48, Attachments 10.4-10.15. 39 Id. at 50. 40 Id. at 51, citing FAQs 40, 46, 97, and 223. The PHMSA Gas IMP FAQs are available online at: http://primis.phmsa.dot.gov/gasimp/faqlist.gim (last accessed September 16, 2010). 41 ASME B31.8S, Section A3.1. 42 FAQ #223.#

420071004_FinalOrder_02112011_text.pdf, page 1514 of the company’s procedures. I agree. Respondent’s procedures in place at the time of the inspection were consistent with Appendix A3.4b of the ASME Standard. Accordingly, based on the foregoing and a review of the record, I order that this portion of Item 10 be withdrawn. Item 11: The Notice alleged that Respondent violated 49 C.F.R. § 192.935(c), which states: § 192.935 What additional preventative and mitigative measures must an operator take? (a) …. (c) Automatic shut-off valves (ASV) or Remote control valves (RCV). If an operator determines, based on a risk analysis, that an ASV or RCV would be an efficient means of adding protection to a high consequence area in the event of a gas release, an operator must install the ASV or RCV. In making that determination, an operator must, at least, consider the following factors—swiftness of leak detection and pipe shutdown capabilities, the type of gas being transported, operating pressure, the rate of potential release, pipeline profile, the potential for ignition, and location of nearest response personnel. The Notice alleged that Respondent violated 49 C.F.R. § 192.935(c) and its own procedures by failing to perform a risk analysis to determine whether either ASVs or RCVs would be efficient means of adding protection for HCAs in the event of a gas release. CenterPoint argued that it had, in fact, performed such an analysis and submitted documentation in support of its position.43 These materials support Respondent’s argument. Accordingly, based on the foregoing and a review of the record, I order that Item 11 be withdrawn. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. Additional Issues In its Response, CenterPoint argued that PHMSA lacked the authority to impose a civil penalty for the alleged violations in this case.44 After the hearing, Respondent withdrew this argument.45 Respondent also argued that OPS should have addressed the issues in this case through a Notice of Amendment (NOA), rather than a Notice of Probable Violation. CenterPoint argued that because it was at an early stage of the implementation of its IMP program, an NOA would have been the appropriate enforcement mechanism. I disagree. There are no statutory or regulatory requirements that OPS use a particular tool in particular circumstances. The choice of enforcement tools resides uniquely with the agency. In this particular case, I do not believe that the agency abused its discretion or violated any regulation in choosing to issue a Notice of Probable Violation, as opposed to an NOA or other enforcement tool. 43 Response at 55-56. 44 Response at 1. 45 Closing at 2.#

420071004_FinalOrder_02112011_text.pdf, page 1615 ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, in determining the amount of the civil penalty, I must consider the following criteria: the nature, circumstances, and gravity of the violation, including adverse impact on the environment; the degree of Respondent’s culpability; the history of Respondent’s prior offenses; the Respondent’s ability to pay the penalty and any effect that the penalty may have on its ability to continue doing business; and the good faith of Respondent in attempting to comply with the pipeline safety regulations. In addition, I may consider the economic benefit gained from the violation without any reduction because of subsequent damages, and such other matters as justice may require. The Notice proposed a total civil penalty of $95,000 for violations of §§ 192.917(a), (c), (e)(1), (e)(4), and 192.925(b)(1). Having withdrawn the allegations of violation for Items 4 and 7, no civil penalty is appropriate for those items. Item 1: The Notice proposed a civil penalty of $17,000, for Respondent’s failure to properly evaluate in its IMP the potential for interactive threats for each covered pipeline segment. In its Closing, Respondent argued that the penalty should be withdrawn or substantially reduced due to the relatively minor gravity of the alleged violation. The company contended that the violation was not serious because its risk model had demonstrated that those pipeline segments were accurately prioritized for assessment. CenterPoint also argued that it was not culpable for a violation because it was not required to use a “plus” factor for interactive threats, that it had made a good-faith effort to comply with the regulation, and that it had not incurred any economic benefit as a result of the violation. Although it appears that the deficiencies in Respondent’s risk model have not led to any pipeline incidents, the company is nonetheless responsible for accurately addressing the potential for interactive threats on each covered pipeline segment. CenterPoint did not do this. The regulations do not require a specific “plus” factor but, rather, an analysis that accounts for the interactive nature of threats, i.e., that accounts for a combination of threats resulting in a greater risk than each threat considered individually. Absent such a type of analysis, CenterPoint may miss critical information on the safety of its pipeline facilities. As for the company’s good faith argument, the proposed penalty amount did take into account the company’s overall IMP compliance efforts and the less severe nature of the violation. Furthermore, the amount is far below the $100,000 per violation per day limit on administrative penalties. Finally, the proposed penalty amount did not include an economic-benefit component. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $17,000. Item 2: The Notice proposed a civil penalty of $17,000, for Respondent’s failure to provide documentation in its IMP to support the conclusion to eliminate certain threats from its risk assessment for HCAs. In its Closing, Respondent again argued that this penalty should be withdrawn or substantially reduced due to the relatively minor gravity of the alleged violation. The company contended that the violation was not serious because its experience had shown that its risk model accurately prioritized those pipeline segments for assessment. CenterPoint also#

420071004_FinalOrder_02112011_text.pdf, page 1716 argued that it was not culpable for the violation because its procedures explained when threats would be eliminated, that it had acted in good faith to comply with the regulations, and that it had not incurred any economic benefit as a result of the violation. As discussed above, Respondent provided no documentation of the application of its risk assessment to the actual pipeline system data. Therefore, neither Respondent nor OPS could determine if the company’s decisions to eliminate threats from HCAs were appropriate. Absent such documentation, potential errors in threat elimination may go unnoticed and ultimately undermine pipeline safety. As discussed in Item 1 above, the proposed penalty amount did take into account the company’s overall IMP compliance efforts, the less severe nature of the violation, and lack of economic benefit. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $17,000. Item 5: The Notice proposed a civil penalty of $17,000, for Respondent’s failure to select an assessment technology capable of assessing seam integrity and seam corrosion anomalies for covered segments containing ERW or similar pipe segments that had experienced seam failure or pressure exceeding maximum operating pressure in the last five years. In its Closing, Respondent argued that this penalty should be withdrawn or substantially reduced. Again, CenterPoint argued that this violation was not serious because it simply constituted an error in its procedures and that it had never actually used the incorrect technology for assessing seam integrity. The company argued that it was not culpable, had acted in good faith to comply, and that it had not derived any economic benefit from the violation. Although, Respondent’s error did not result in any damage to the pipeline system or the environment, accurate procedures are important to pipeline safety. By including a technology that would not properly address the specific threat, Respondent ran the risk of using the wrong diagnostic tool on its pipeline system. This error could have undermined pipeline safety. The relatively modest proposed penalty amount reflects Respondent’s acknowledged efforts to comply and the less severe nature of the violation. Furthermore, the amount is far below the $100,000 per violation per day limit on administrative penalties. Finally, the proposed penalty amount did not contain an economic benefit component. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $17,000. In summary, having reviewed the record and considered the assessment criteria for all the Items discussed above, I assess Respondent a reduced total civil penalty of $51,000. 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 telephone number is (405) 954-8893. Failure to pay the $51,000 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#

420071004_FinalOrder_02112011_text.pdf, page 1817 those same authorities, a late penalty charge of six percent (6%) per annum will be charged if payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty may result in referral of the matter to the Attorney General for appropriate action in a United States District Court. COMPLIANCE ORDER The Notice proposed a compliance order with respect to Items 1 through 11 in the Notice for violations of 49 C.F.R. §§ 192.917(a), 192.917(c), 192.917(e)(1), 192.917(e)(4), 192.925(b)(1), 192.927(c)(1)(i), 192.927(c)(5)(ii), 192.929(b)(1), and 192.935(c). I have withdrawn several of these items. In addition, the Director has indicated that Respondent has taken action to address some of the cited violations. The remaining compliance order requirements are set out below. 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, Respondent is ordered to take the following actions to ensure compliance with the pipeline safety regulations applicable to its operations. Respondent shall: 1. With respect to the violation of § 192.917(a) (Item 1), Respondent must implement its PS-03-01-216 procedure and develop and implement a process to ensure that the evaluation of interactive threats is addressed. CenterPoint must provide an evaluation of interactive threats for all covered segments. 2. With respect to the violation of § 192.917(c) (Item 2), Respondent must modify its IMP procedures to include a process to document any decisions to eliminate certain threats from its risk assessments. Such documentation shall clearly set out the basis for any decision to eliminate threats. Within 90 days of receipt of this Final Order, Respondent must modify its IMP procedures, develop and implement such process, and submit documentation of compliance with this item. 3. With respect to the violation of § 192.929(b)(1) (Item 10), Respondent must modify its IMP procedures to include a provision for notifying PHMSA of its intent to use any “Other Technology,” whenever the company plans to use its near-neutral SCCDA plan. Within 90 days of receipt of this Final Order, Respondent must modify its IMP procedures, develop and implement such provision, and submit documentation of compliance with this item. 4. Respondent is requested to maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to R.M. Seeley, Director, Southwest Region, PHMSA. Costs shall be reported in two categories: 1) total cost associated with#

420071004_FinalOrder_02112011_text.pdf, page 1918 preparation/revision of plans, procedures, studies and analyses, and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. The Director may grant an extension of time to comply with any of the required items upon a written request timely submitted by the Respondent demonstrating good cause for an extension. The Director has indicated that Respondent has amended its IMP procedures to address certain of the proposed compliance order terms. These actions satisfy the requirements in Items 3, 5 and 6 of the proposed compliance order. 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. 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 sent to: Associate Administrator, Office of Pipeline Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC 20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address. PHMSA will accept petitions received no later than 20 days after receipt of service of this Final Order by the Respondent, provided they contain a brief statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.215. The filing of a petition automatically stays the payment of any civil penalty assessed. Unless the Associate Administrator, upon request, grants a stay, all other terms and conditions of this Final Order are effective upon service in accordance with 49 C.F.R. § 190.5. ___________________________________ __________________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety#

420071004_Notice Letter_03292007.pdf, page 1Official PDF@ U.S. Deportment of Tronsportotlon Plpeline qnd Hozordous rtioterlols sofely AdmlnBlrotlon 8701 South Gessnel, Suite 1110 Houston, TX 77074 NOTICE OF PROBABLE VIOLATION, PROPOSED CIVIL PENALW and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL. RETURN RECEIPT REQUESTED March 29, 2007 Walter Ferguson, Senior V.P and C.O.O. Pipeline Services CenterPoint Energy Gas Transmission 525 Milam Shreveport, LA 71101 cPF 4-2007-1004 Dear Mr. Ferguson: Duringtheweeksof September 12-16, and Novemberl4-18,2005, representativesof the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected your integrity management program in Shreveport, Louisiana. 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 orobable violations are: 1. S 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 831.8S (ibr, see 5192.7), section 2, which are as follows:#

420071004_Notice Letter_03292007.pdf, page 2Department of Transportation Pipeline and Hazardous Materials Safety Administration Gompliance Registry: Anitra Brown 4OO 7'n Street, SW Room 2103 Washington, DC 20590#

420071004_Notice Letter_03292007.pdf, page 32. 3. (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. CenterPoint Energy Gas Transmission (CE) did not identify or evaluate the potential for interactive threats to each covered pipeline segment. The regulation specifically requires that CE identify and evaluate the threats listed in ASME/ANSI 831.85, section 2, which includes the following: ASME 83'1 .85 2.2Integrity Threat Classification 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. While CE's procedure PS-03-01-216, "Threat ldentification and Risk Assessment," Section 2.2 states that, "The results from the evaluation together with the criteria used to evaluate the significance of this threat or interaction of threats to the covered pipe segment shall be used to prioritize the integrity assessment," there is not a process to ensure the evaluation of interactive threats is accomolished. S 192.917 (see above) (c) Risk assessment. An operator must conduct a risk assessment that follows ASME/ANSI 831.8S, section 5, and considers the identified threats for each covered segment. CE did not provide specific documentation requirements or documentation to support conclusions to eliminate threats from HCAs in accordance with the minimum requirements specified by each of the relevant sections of ASME 831.8S. At the time of the inspection, CE did not provide the inspection team with any documentation in support of this requirement. The regulations require that threats be identified and that a risk assessment based on those threats be oerformed accordinq to section 5 of ASME 831.85. S 192.917 (see above) (e) Actions to address particular threats. lf an operator identifies any of the following threats, the operator must take the following actions to address the threat. (1) Third pafi damage. An operator must utilize the data integration required in paragraph (b) of this section and ASME/ ANSI 831.8S, Appendix A7 to determine the susceptibility of each covered segment to the threat of third party damage. lf an operator identifies the threat of third party damage, the operator must implement comprehensive additional preventive measures in accordance with 5192.935 and monitorthe effectiveness of the preventive measures. lf, in#

420071004_Notice Letter_03292007.pdf, page 44. 5. conducting a baseline assessment under $192.921, or a reassessment under 5192.937, an operator uses an internal inspection tool or external corrosion direct assessment, the operator must integrate data from these assessments with data related to any encroachment or foreign line crossing on the covered segment, to define where potential indications of third party damage may exist in the covered segment. An operator must also have procedures in its integrity management program addressing actions it will take to respond to findings from this data integration. CE does not have a formal procedure or process by which it integrates inspection tool or external corrosion direct assessment data with data related to encroachments or foreign line crossings to define where potential indications of third party damage may exist in covered sections. CE procedures PS-03-01-1 10, "Gather, Review, and Integrate Data," and section 2.4 of PS-03-01-216, "Threat ldentification and Risk Assessment," describe the collection and evaluation of data for the risk analysis. However, neither procedure describes requirements for data integration of lLl and ECDA data with data related to encroachments of foreign line crossings prior to any post assessment review. Addltionally, the inspection team did not identify any evidence that this data integration had been performed. S 192.917 (e)(1) (see above) CE did not integrate ECDA and lLl data with data related to encroachment and foreign line crossing data to evaluate the covered segment for the threat of third party damage. CE procedures PS-03-01-232, "External Corrosion Direct Assessment," and PS-03-01- 230, "Direct Assessment Plan," describe how ECDA assessments are to be conducted, the data to be collected, and what documentation needs to be retained. PS-03-01-268, "lMP Quality Assurance", Appendix A requires that the data elements used for ECDA be gathered and integrated. These plans and procedures reference the NACE RP 0502- 2002 ECDA assessment standard but do not reference the need to integrate encroachment and foreign line data as required in $192.917 (eX1) and $192.925 (b) for Pre-assessments, Indirect Inspections and Direct Examinations undertaken on ECDA for a region or a segment. Three ECDA assessments were reviewed (line ALE, line BT-1 , and 4-206); and in each case, there was no documentation that this data integration was performed. S 192.917 (e) (see above) (4) ERW pipe. lf a covered pipeline segment contains low frequency electric resistance welded pipe (ERW), lap welded pipe or other pipe that satisties the conditions specified in ASME/ANSI 831 ,8 S, Appendices A4.3 and A4.4, and any covered or non covered segment in the pipeline system with such pipe has experienced seam failure, or operating pressure on the covered segment has increased over the maximum operating pressure experienced during the preceding five years, an operator must select an assessment technology or technologies with a proven application capable of assessing seam integrity and seam corrosion anomalies. The operator must prioritize the covered segment as a high risk segment for the baseline assessment or a subsequent reassessment.#

420071004_Notice Letter_03292007.pdf, page 5CE's Baseline Assessment Plan (BAP) did not consistently specify an assessment method(s) for each covered segment that is appropriate for identifying anomalies associated with specific threats identified for the segment. The rule requires that an operator must select an assessment technology or technologies with a proven application capable of assessing seam integrity and seam corrosion anomalies. Further, ASME B31.8S states in section A4, "Manufacturing Threat (Pipe Seam and Pipe), A4.4 Integrity Assessment," "...pressure testing must be performed to address the seam issue." CE allows for either a Hydrotest or the use of TFI based on their "BAP - Integrity Assessment Selection Guide." However, according to ASME 831 .85, a TFI tool is not an acceptable method of integrity assessment for this threat. CE describes the various assessment methods in PS-03-01-224, "Assessment Methods Selection Process" which references CE's, "BAP - Integrity Assessment Selection Guide." The assessment path on the flow chart in the Guide allows for a hydrotest, pipe replacement, or use of a TFI tool. The ASME 831.8S guidance states that only a hydrotest is appropriate. A pipe replacement is an acceptable approach to eliminate the seam integrity threat, but for those instances where CE does not elect to replace the pipe, only the performance of a hydrotest would satisfy the requirements of the rule and the ASME guidance document. S 192.925 What are the requirements for using External Corrosion Direct Assessment (ECDA)? (b) General requirements. An operator that uses direct assessment to assess the threat of external corrosion must follow the requirements in this section, in ASME/ANSI 831.8S (ibr, see 5192.7), section 6.4, and in NAGE RP 0502-2002 (ibr, see $192.7). An operator must develop and implement a direct assessment plan that has procedures addressing preassessment, indirect examination, direct examination, and post-assessment. lf the EGDA detects pipeline coating damage, the operator must also integrate the data from the EGDA with other information from the data integration ($192.917(b)) to evaluate the covered segment for the threat of third party damage, and to address the threat as required by $1e2.e17(e)(1). (1) Preassessment. In addition to the requirements in ASME/ANSI 831.8S section 6.4 and NACE RP 0502-2002, section 3, ... CE's plan did not adhere to the requirements of NACE RP 0502-2002, Section 3 by not defining minimum data requirements. CE procedures PS-03-01-232, "External Corrosion Direct Assessment," PS-03-0'1-230, "Direci Assessment Plan," and PS8'140 'ECDA Data Elements" describe what data elements should be considered to perform an ECDA. However, the minimum data elements that are needed to determine if an ECDA can be conducted are not documented as required by NACE RP 0502, Section 3.2.1.1 which states, "The pipeline operator shall define minimum data requirements based on the history and condition of the pipeline segment. In addition, the pipeline operator shall identify data elernents that are critical to the success of the ECDA process." CE's plan did not adhere to the requirements of NACE RP 0502-2002, Section 3 by not documenting conservative assumptions. CE procedures allow conservative assumptions be made where data is not available to address data sufficiency#

420071004_Notice Letter_03292007.pdf, page 67. requirements. Three ECDA assessments (completed through the third step, Direct Examination, at the time of the inspection) were reviewed (lines ALE, BT-1 , and 4-206); and in each case, there was no documentation on the minimum required data, what the basis was for any of the conservative assumptions, and if the ECDA was feasible with the data elements available. CE stated that they only have 10 years of data available for integrity management but that additional historic data may be at field locations. Past cathodic protection data is needed to determine if active corrosion is taking place or if corrosion was the result of past inadequate cathodic protection. Under other sections of $192, much of the cathodic protection data should have been retained for the life of the pipeline and thus should be available for these ECDA purposes. NACE RP 0502, Section 3.2.4 states, "ln the event that the pipeline operator determines that sufficient data for some ECDA regions comprising a segment are not available or cannot be collected to support the Pre-Assessment Step, ECDA shall not be used for those ECDA regions." CE's plan did not adhere to the requirements of their own procedures and NACE RP 0502-2002, Section 3 by not documenting that a feasibility assessment was undertaken. CE procedures PS-03-01-232 S4.0, "External Corrosion Direct Assessment," PS-03-01- 230, "Direct Assessment Plan," and PS-03-01-268, "lMP Quality Assurance", Appendix A require that the feasibility of each ECDA conducted be assessed and documented. ln the three ECDAs reviewed by the inspection team (lines BT-1, ALE, and A-206) that CE started and completed through the Direct Examination step, there was no documentation that a feasibility assessment was undertaken. Documentation on what was considered during the feasibility review is critical to determine the appiicability of the ECDA process to other covered segments and for feedback as required by NACE RP 0502, 5192.925 and CE procedures PS-03-01-232, "External Corrosion Direct Assessment," and PS-03- 01-268, "lMP Quality Assurance", Appendix A. CE's plan did not adhere to the requirements of their own procedures and NACE RP 0502-2002, Section 3 by not documenting the specific indirect inspections tools chosen and if they were complementary to each other. CE procedures PS-03-01-232, "External Corrosion Direct Assessment," PS-03-01-230, "Direct Assessment Plan," and PS-03-01- 268, "lMP Quality Assurance", Appendix A require that the indirect tool selection for each ECDA conducted be verified and documented. In the three ECDAs reviewed by the inspection team (lines BT-1, ALE, and 4-206), there was no documentation regarding why the specific indirect inspections tools were chosen and if they were complementary to each other. NACE RP 0502, Section 3.4.1.1 states, "The pipeline operator shall select indirect inspection tools based on their ability to detect corrosion activity andlorl coating holidays reliably under the specific pipeline conditions to be encountered." NACE RP 0502, Section 3.4.1.2 states, "The pipeline operator should endeavor to select indirect inspection tools that are complementary. That is, the operator should select tools such that the strengths of one tool compensate for the limitations of another." S 192.925 (b) (see above) (1) Preassessment. In addition to the requirements in ASME/ANSI 831.8S section 6.4 and NACE RP 0502-2002, section 3, the plan's procedures for preassessment must include- i. Provisions for applying more restrictive criteria when conducting EGDA for the first time on a covered segment;#

420071004_Notice Letter_03292007.pdf, page 7(2) lndirect Examination. In addition to the requirements in ASME/ANSI 831.8S section 6.4 and NACE RP 0502-2002, section 4, the plan's procedures for indirect examination of the EGDA regions must include - i. Provisions for applying more restrictive criteria when conducting EGDA for the first time on a covered segment; (b)(3) Direct Examination- In addition to the requirements in ASME/ANSI 831.8S section 6.4 and NACE RP 0502-2002, section 5, the plan's procedures for direct examination of indications from the indirect examination must include - i. Provisions for applying more restrictive criteria when conducting EGDA for the first time on a covered segment; CE, in their ECDA plan, did not document the more restrictive criteria, as required by S192.925, when they conducted ECDA for the first time on a covered segment. These more restrictive criteria are for pre-assessment, indirect inspection, and direct examination steps of the ECDA process. CE did not document for each specific assessment how the more restrictive criteria were applied. CE procedures PS-03-01- 232,"External Corrosion Direct Assessment," and PS-03-01-230, "Direct Assessment Plan," describe how ECDA assessments are to be conducted, the data to be collected and what documentation needs to be retained. These plans and procedures reference the NACE RP 0502-2002 ECDA assessment standard but do not reference the need to document the more restrictive criteria as required in $192.925(bX1) subparts (i), (ii) and (iii) for Pre-assessments, Indirect Inspections and Direct Examinations undertaken on an initial ECDA on a region or a segment. Three ECDA assessments were reviewed by the inspection team (line ALE, line BT-1, and A-206), and in each case there was no documentation of the more restrictive criteria for this initial ECDA on these segments. 8. S 192.927 What are the requirements for using Internal Gorrosion Direct Assessment (IGDA)? (c) The ICDA plan. An operator must develop and follow an ICDA plan that provides for preassessment, identification of IGDA regions and excavation locations, detailed examination of pipe at excavation locations, and post- assessment evaluation and monitoring. (1) Preassessment. In the preassessment stage, an operator must gather and integrate data and information needed to evaluate the feasibility of IGDA for the covered segment, and to support use of a model to identify the locations along the pipe segment where electrolyte may accumulate, to identify IGDA regions, and to identify areas within the covered segment where liquids may potentially be entrained. This data and information includes, but is not limited to . i. All data elements listed in Appendix A2 of ASME/ANSI 831.8S; CE's ICDA plan did not adhere to the requirements of their own procedures and Appendix A2 of ASME/ANSI 831.8S. CE procedures PS-03-01-238, "Dry Gas - Intemal Corrosion Direct Assessment," PS-03-01-230. "Direct Assessment Plan," and PS-03-01- 268, "lMP Quality Assurance", Appendix A require ICDA feasibility be performed in the pre-assessment step; and no feasibility evaluation results were documented on the ICDA pre-assessments performed on lines FT-l 1 and ADT-8 that were completed prior to the inspection. CE did not document the results of the feasibility analysis, and there#

420071004_Notice Letter_03292007.pdf, page 8was not sufficient evidence to conclude that the lines selected for ICDA met the ICDA criteria. CE did not provide sufficient documentation to support the use of ICDA on the lines reviewed. CE did nol document the basis for selecting the feasibility criteria for pigging, water upsets, and introduction of sludge. In Figure 2, "DG-ICDA Feasibility Filter'' of procedure PS-03-01-238, "Dry Gas - Internal Corrosion Direct Assessment," there are several numerical values for some of the feasibility issues, such as "Routine pipeline pigging (more than 3 times per year)," etc. but there is no explanation on where these values come from or how they are to be generated. Based on a review during the inspection of the data elements for lines FT-'l 1 and ADT-8, the data was of poor quality, and CE did not review the data as required in their procedures. During the review of several ICDA pre-assessments, data quality was determined to be poor or data was missing. CE procedures PS-03-01-238, "Dry Gas - lnternal Corrosion Direct Assessment," PS-03-01-23O, "Direct Assessment Plan," and PS-03-01-268, "lMP Quality Assurance", Appendix A require that the data elements used for ICDA be gathered. This poor quality data could lead to the incorrect critical angles being calculated and to ICDA regions being improperly determined. 9. S 192.927 (c) (see above) (5) Other requirements. The IGDA plan must also include - ii. provisions for applying more restrictive criteria when conducting IGDA for the first time on a covered segment and that become less stringent as the operator gains experience; CE did not document where the more restrictive criteria were used in their ICDA plan, as required by $192.927, and which are required when conducting ICDA for the first time on a covered segment. These more restrictive criteria are for pre-assessment, indirect inspection, direct examination, and post assessment steps of the ICDA process. CE procedures PS-03-01-238, "Dry Gas - Internal Corrosion Direct Assessment," PS-03-01- 230, "Direct Assessment Plan," and PS-03-01-268, "lMP Quality Assurance", Appendix A describe how ICDA assessments are to be conducted. the data to be collected and what documentation needs to be retained. These plans and procedures reference the ASME 831.8S for ICDA assessment requirements and 5192327. Although not referenced, the draft NACE RP on Dry-Gas ICDA was also utilized. The CE procedures do not document the more restrictive criteria as required in $192.927(b)(5)(iii) for each of the four steps undertaken on an initial ICDA on a region or a segment. The rule is clear that these criteria must be documented. CE also did not document how the more restrictive criteria were applied in ICDAs for lines FT-1 1 and ADT-8. 10. S 192.929 What are the requirements for using Direct Assessment for Stress Gorrosion Gracking (SCCDA)? (b) General Requirements. An operator using direct assessment as an integrity assessment method to address stress corrosion cracking in a covered pipeline segment must have a plan that provides, at minimum, for - (1) Data gathering and integration. An operator's plan must provide for a systematic process to collect and evaluate data for all covered segments to identify whether the conditions for SGC are present and to prioritize the covered#

420071004_Notice Letter_03292007.pdf, page 9segments for assessment. This process must include gathering and evaluating data related to SGC at all sites an operator excavates during the conduct of its pipellne operations where the criteria in ASME/ANSI 831.8S, Appendix A3.3 indicate the potential for SCG. This data includes at minimum, the data specified in ASME/ANSI 831.8S, Appendix A3. CE's SCCDA plan does not require the gathering and evaluating of data related to SCC at all sites it excavates during the conduct of its pipeline operations (not just covered segments) where the criteria indicate the potential for SCC. CE procedures PS-03-01- 240, "Stress Corrosion Cracking Direct Assessment," PS-03-01-230, "Direct Assessment Plan," and PS-03-01-268, "lMP Quality Assurance", Appendix A describe how SCCDA assessments are to be conducted, the data to be collected and what documentation needs to be retained. None of these procedures mandate that CE obtain data on non- covered pipelines that may be susceptible to SCC as required in $'192.929, Based on some of the data elements in CE's SCCDA program lhat were inspected, CE did not review the data as required in their procedures. CE procedures PS-03-01-240, "Stress Corrosion Cracking Direct Assessment," P5-03-01-230, "Direct Assessment Plan," and PS-03-01-268, "lMP Quality Assurance", Appendix A require that the data elements used for SCCDA be gathered. During the review of SCCDA pre-assessments, data quality was determined to be poor or missing. 831.8S, Section A3.3 states, "Where the operator is missing data, conseryative assumptions shall be used when performing the risk analysis or alternatively the segment shall be prioritized higher." CE's IMP does not provide for notification to PHMSA regarding its near-neutral SCC plan. ASME 831.8S, Section A3.1 states, "Near-neutral type of SCC similar$ would require an inspection and alternative mitigation plan." CE procedures PS-03-01-240, "Stress Corrosion Cracking Direct Assessment," and PS-03-01-230, "Direct Assessment Plan," require CE to notify PHMSA and/or local regulatory authorities if CE plans to use "Other Technology" as defined in $192.921 (a)(4) (and follow the notification procedure in $192.949). ASME 831.8S for SCCDA covers only high pH SCC and requires operators to develop a plan for near neutral pH SCC, which CE has done by following the procedure in NACE RP 0204 for near neutral SCC. This recommended practice is not referenced in the rule and thus is considered an "Other Technology". As such, CE must notify PHMSA and/or local regulatory authorities 180 days before proposing to use the technology. CE has not yet used its near neutral pH SCCDA process nor has it notified any regulatory authority. CE's IMP does not specify the performance of a spike test, per ASME 831.8S, when it has experienced an in-service leak or rupture attributable to SCC. ASME B31.8S, Section A3.4 states, "lf the pipeline experiences an in-service leak or rupture, which is attributed to SCC, the particular segment shall be subjected to a hydrostatic test (as described below) within 12 months." CE procedures PS-03-01-240, "Stress Corrosion Cracking Direct Assessment," and PS-03-01-230, "Direct Assessment Plan," state that CE can use a pressure test to check for SCC. There is no procedure requirement to perform a spike test following an in-service leak or rupture attributable to SCC. ASME 83'1.85 specifically mandates lhat operators use a spike hydrostatic pressure test following an in-service leak or rupture attributable to SCC.#

420071004_Notice Letter_03292007.pdf, page 1011. S 192.935 What additional preventive and mitigative measures must an operator take? (c) Automatic shut-off valves (ASV) or Remote control valves (RCV). lf an operator determines, based on a risk analysis, that an ASV or RCV would be an efficient means of adding protection to a high consequence area in the event of a gas release, an operator must install the ASV or RGV. ln making that determination, an operator must, at least, consider the following factors - swiftness of leak detection and pipe shutdown capabilities, the type of gas being transported, operating pressure, the rate of potential release, pipeline profile, the potential for ignition, and location of nearest response personnel. CE did not follow its procedure requiring that an analysis completed in conjunction with the annual assessment inspection shall result in documentation of results from any feasibility analysis of alternatives, including the installation of ACVs and RCVs. The operator did not provide any documented technical justification either to install or not to install ACVs or RCVs. CE's procedure PS-03-01-258, "Preventive and Mitigative Measures," specifies that the operator shall document all actions considered and taken to enhance public safety and/or environmental protection as identified from the risk assessment and/or specific threat factors on each of the HCA pipeline segments. The flow charts provided to the inspection team for preventive and mitigative evaluations did not take into consideration segment specific risk data when determining measures to implement. CE confirmed in discussions that rather than reviewing each segment individually for preventive and mitigative measures that they applied more "global" preventive and mitigative decisions across their system. Proposed Civil Penaltv Under 49 United States Code, $ 60122, you are subject to a civil penalty not to exceed $100,000 for each violation for each day the violation persists up to a maximum of $1 ,000,000 for any related series of violations. The Compliance Officer has reviewed the circumstances and supporting documentation involved in the above probable violations and has recommended that you be preliminarily assessed a civil penalty of $95,000 as follows: Item number PENALTY 1. $17,000 2. $17,000 4. $22,000 $17,000 7. $22,000 Proposed Compliance Order With respect to items 1 through 11 pursuant to 49 United States Code S 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to CenterPoint Energy Gas Transmission. Please refer to the Proposed Compliance Order, which is enclosed and made a part of this Notice. Response to this Notice Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in Compliance Proceedings. Please refer to this document and note the#

420071004_Notice Letter_03292007.pdf, page 11response options. Be advised that all material you submit in response to this enforcement action is subject to being made publicly available. lf you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). lf 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. ln your correspondence on this matter, please refer to CPF 4-2007-1004 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, 4wrM.$ R. M. Seeley Lt Director, Southwest Region Pioeline and Hazardous Materials Safety Administration Enclosures: Proposed Compliance Order Response Options for Pipeline Operators in Compliance Proceedings 10#

420071004_Notice Letter_03292007.pdf, page 12PROPOSED COMPLIANGE ORDER Pursuant to 49 United States Code S 601 18, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to CenterPoint Energy Gas Transmission a Compliance Order incorporating the following remedial requifements to ensure the compliance of CenterPoint Energy Gas Transmission with the pipeline safety regulations: 1. In regard to ltem Number 1 of the Notice pertaining to potential threats to pipeline integrity and specifically interactive threats, CE must implement their procedure PS-03- 01-216 and develop and implement a process to ensure that the evaluation of interactive threats is addressed. CE must orovide an evaluation of the threat of interactive threats for all covered segments. 2. In regard to ltem Number 2 of the Notice pertaining to ASME 831.8S, Section 5 and the requirement to develop minimum data requirements, CE must implement their procedure PS-03-01-216 for all of the described threats and develop and implement a procedure that also addresses Cyclic Fatigue. CE must develop specific documentation requirements and provide documentation to support conclusions to eliminate threats from HCAs in accordance with the minimum requirements specified by each of the relevant ASME 831.8S section. In regard to ltem Number 3 and 4 of the Notice pertaining to third party damage and requirements of ASME 831.85, CE must develop the appropriate procedure(s) to integrate inspection tools or external corrosion direct assessment data with data related to encroachments or foreign line crossings to define potential indications of third party damage in covered sections. CE must integrate ECDA data and lLl data with data related to encroachment and foreign line crossing to evaluate the covered segment for the threat of third party damage and provide documentation that those procedures have been implemented related to each of the covered segments. 4. In regard to ltem Number 5 of the Notice pertaining to ERW pipe and requirements of ASME 831.8S, CE must revise its procedures to address the manufacturing threat by specifying an assessment method(s) for each covered segment that is best suited for identifying anomalies associated with specific threats for the segment. CE must identify those locations where it may have used TFI technology for the identification of the manufacturing threat; and where CE used TFI technology for the assessment of the manufacturing threat, CE must reassess the segment using appropriate and approved technologies. 6 In regard to ltem Number 6 of the Notice pertaining to ECDA general requirements, CE must modify its procedures where appropriate; it must define and provide minimum data requirements; it must document its conservative assumptions; it must document all required feasibility assessments; and it must provide documentation for all indirect inspection tools chosen relative to each of the HCAs in all covered sections. 6. In regard to ltem Number 7 of the Notice pertaining to ECDA more restrictive criteria, CE must document the requirement for more restrictive criteria required for pre-assessment, indirect inspection, and direct examination when ECDA is applied for the first time. CE must provide documentation for the application of more restrictive criteria on all locations where ECDA was implemented. 11#

420071004_Notice Letter_03292007.pdf, page 137. In regard to ltem Number I of the Notice pertaining to the implementation of ICDA procedures, CE must document the results of its feasibility analysis related to the ICDA process and procedures, and CE must review the quality of pre-assessment data for all completed lC direct assessments and develop quality controls for use of data in future pre-assessments. CE must provide documentation of its feasibility analysis and it must provide documentation to ensure that the application of the ICDA procedure to HCAs in covered segments was adequate to ensure that the procedures were followed and that the critical angles were properly calculated and evaluated. a In regard to ltem Number 9 of the Notice pertaining to more restrictive criteria required for first time ICDA use, CE must provide documentation for the application of more restrictive criteria required for pre-assessment, indirect inspection, direct examination, and post assessment on all locations where ICDA was implemented. CE must document for each specific assessment how the more restrictive criteria were applied. o In regard to ltem Number '10 of the Notice pertaining to using DA for Stress Corrosion Cracking, CE's procedures must require the gathering and evaluating of data related to SCC at all sites it excavates. CE must review the quality of pre-assessment data for all completed SCC direct assessment and develop quality controls for the use of the data in future pre-assessments. CE must provide for notification to PHMSA of its intent to use its near-neutral SCC plan as a use of "Other Technology". CE must specify the performance of a hydrostatic spike pressure test per ASME 83'l .8S for the event of an in-service leak or rupture. CE must provide documentation to ensure that SCC is being properly evaluated for all HCAs in covered segments. 10. In regard to ltem Number 11 of the Notice pertaining to preventive and mitigative measures, CE develop documentation associated with their technical justification either to install or not to install ACVs or RCVs and provide the required documentation to support its technical justifications with regard to ACVs or RCVs. 11. CE must address the issues within this compliance order within 90 days after receipt of a Final Order and submit to R. M. Seeley, Director, Southwest Region, Pipeline and Hazardous Materials Safety Administration. 12. CE shall maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to R. M. Seeley, Director, Southwest 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. t2#