ENABLE GAS TRANSMISSION, LLC — Notice of Probable Violation

party submissionOfficial PDF420131010_Operator Response to Notice and Request for Time Extension_07172013.pdf#

party submissionOfficial PDF420131010_Operator Response to Notice_09182013.pdf#

420131010_Closure Letter_12292015_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED December 29, 2015 Mr. Paul Brewer Senior VP Operations and EH&S Enable Gas Transmission, LLC Enable Mississippi River Transmission, LLC One Leadership Square 211 N Robinson Ave., Suite 150 Oklahoma City, OK 73102 CPF 4-2013-1010 Dear Mr. Brewer: From January 30 through October 19, 2012, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected the Enable Gas Transmission, LLC/Enable Mississippi River Transmission, LLC (Enable) procedures/records for Operations and Maintenance, Integrity Management, Emergency Response, Operator Qualification, and Construction Specifications in Shreveport, LA. As a result of the inspection, Enable was issued a Notice of Probable Violation, Probable Civil Penalty, and Probable Compliance Order on June 17, 2013. On May 29, 2015 Enable submitted a response to the Final Order. Enable provided the requested documentation and completed the Compliance Order Items on December 7, 2015. The penalty payment was made on September 26, 2014. My staff reviewed the submitted documentation, and it appears that the inadequacies outlined in the Notice of Probable Violation have been corrected. This letter is to inform you no further action is necessary and this case is now closed. Thank you for your cooperation. Sincerely, R. M. Seeley Director, Southwest Region Pipeline and Hazardous Materials Safety Administration#

420131010_Final Order_09022014_text.pdf, page 1Official PDFSEPTEMBER 2, 2014 Mr. Scott Prochazka President Centerpoint Energy, Inc. 1111 Louisiana Street Houston, Texas 77002 Re: CPF No. 4-2013-1010 Dear Mr. Prochazka: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation, assesses a reduced civil penalty of $131,600, issues warnings, and specifies actions that need to be taken by Enable Gas Transmission, LLC, and Enable Mississippi River Transmission, LLC, to comply with the pipeline safety regulations. The penalty payment terms are set forth in the Final Order. When the civil penalty has been paid and the terms of the compliance order completed, as determined by the Director, 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. Chris Bullock, Enable Midstream Partners, Midstream Pipeline Safety, 525 Milam St., Shreveport, Louisiana 71101 CERTIFIED MAIL - RETURN RECEIPT REQUESTED#

420131010_Final Order_09022014_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 ) Enable Gas Transmission, LLC, ) CPF No. 4-2013-1010 and ) Enable Mississippi River Transmission, LLC, ) ) ) ) ) ) Respondents. ) ____________________________________________) FINAL ORDER Between January 30 and October 19, 2012, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the facilities and records of CenterPoint Energy Gas Transmission Company, LLC (now Enable Gas Transmission, LLC), and Mississippi River Transmission Company (now Enable Mississippi River Transmission, LLC) in Shreveport, Louisiana. 1 Both companies (EGT/MRT or Respondents) are indirect, wholly- owned interstate pipeline subsidiaries of Enable Midstream Partners, LP, and together operate more than 8,000 miles of interstate pipe located in Arkansas, Illinois, Kansas, Louisiana, Mississippi, Missouri, Oklahoma, Tennessee and Texas, as well as six storage facilities.2 Enable Midstream Partners, LP, is a subsidiary of Centerpoint Energy, Inc. As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Respondents, by letter dated June 17, 2013, 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 EGT/MRT had committed various violations of 49 C.F.R. Parts 191 and 192 and proposed assessing a civil penalty of $137,200 for the alleged violations. The Notice also proposed ordering Respondents to take certain measures to correct the alleged 1 Subsequent to the issuance of the Notice and effective July 30, 2013, CenterPoint Energy – Mississippi River Transmission, LLC, changed its name to Enable Mississippi River Transmission, LLC. On the same date, CenterPoint Energy Gas Transmission Company, LLC, changed its name to Enable Gas Transmission, LLC. A response to the Notice was filed in this proceeding by Enable Midstream Partners, LP, on behalf of both companies. See Response, at 1. Enable Midstream Partners, LP, is a subsidiary of Centerpoint Energy, Inc. http://www.centerpointenergy.com/services/pipelines/egt/ (last accessed on April 18, 2014). 2 http://www.centerpointenergy.com/services/pipelines/egt/ (last accessed on April 18, 2014).#

420131010_Final Order_09022014_text.pdf, page 32 violations. On July 17, 2013, EGT/MRT requested a 60-day extension to submit their response to PHMSA and it was granted. Respondents then responded to the Notice by letter dated September 18, 2013 (Response). The companies contested Items 3, 4, 5 and 7, offered additional information in response to the Notice, and requested that the proposed civil penalty be reduced. Respondents did not request a hearing and therefore have waived their right to one. FINDINGS OF VIOLATION The Notice alleged that Respondents violated 49 C.F.R. Parts 191 and 192, as follows: Item 3: The Notice alleged that Respondents violated 49 C.F.R. § 191.17(a), which states: § 191.17 Transmission systems; gathering systems; and liquefied natural gas facilities: Annual report. (a) Transmission or Gathering. Each operator of a transmission or a gathering pipeline system must submit an annual report for that system on DOT Form PHMSA 7100.2.1. This report must be submitted each year, not later than March 15, for the preceding calendar year, except that for the 2010 reporting year the report must be submitted by June 15, 2011. The Notice alleged that Respondents violated 49 C.F.R. § 191.17(a) by failing to submit annual reports for calendar years 2007-2010 that included the companies’ entire transmission or gathering pipeline systems. Specifically, the Notice alleged that the 2011 Annual Report showed that EGT/MRT operated approximately 22.3 mile of unprotected steel pipe, but the 2008, 2009, and 2010 Annual Reports omitted all quantities of bare unprotected steel pipe. The Notice further alleged that the 2007 Annual Report listed a quantity of only three miles of bare unprotected steel pipe, an amount different than the quantity reported for the other years. In their Response, EGT/MRT claimed to operate three segments of bare unprotected pipe: 1) 16.63 miles of Line 9, 2) 0.3 miles of line FT-3, and 3) 5.35 miles of line KM-26. Respondents contended that they did not omit the 22.3 miles of pipe at issue but, rather, had “inadvertently categorized” these 22.3 miles of pipe at issue as either bare protected pipe or coated protected pipe instead of bare unprotected pipe.3 Upon discovering that the 22.3 miles had not been listed under the correct category, EGT/MRT corrected the error in their 2011 Annual Report. Therefore, Respondents argued that this Item should be withdrawn or the penalty substantially reduced. Upon review of the attachment that Respondents submitted, the total mileage incorrectly reported in the 2007-2010 Annual Reports for Lines 9, FT-3, and KM-26 is 18.5 miles. According to the 2011 Annual Report, there are actually 22.3 miles of bare unprotected steel pipe. Accordingly, based upon a review of all of the evidence, I find that Respondents violated 49 C.F.R. § 191.17(a) by failing to submit annual reports for the calendar years 2007-2010 that 3 Response at 3.#

420131010_Final Order_09022014_text.pdf, page 43 included their entire pipeline systems by omitting to report bare unprotected steel pipe. As for Respondents’ argument that the inaccurate reporting for years prior to 2011 should be treated as a warning or a Notice of Amendment, I see no reason why this Item should not be treated as a violation, since the Annual Reports in question did not involve inadequate procedures and contained significant errors over several years. Item 4: The Notice alleged that Respondents violated 49 C.F.R. § 192.463(a), which states: § 192.463 External corrosion control: Cathodic protection. (a) Each cathodic protection system required by this subpart must provide a level of cathodic protection that complies with one or more of the applicable criteria contained in appendix D of this part. If none of these criteria is applicable, the cathodic protection system must provide a level of cathodic protection at least equal to that provided by compliance with one or more of these criteria. The Notice alleged that Respondents violated 49 C.F.R. § 192.463(a) by failing to provide a cathodic protection system for their pipeline that complied with one or more of the applicable criteria contained in Appendix D of Part 192. Section II of Appendix D requires an operator to fully consider voltage (IR) drop for a valid interpretation of the voltage measurement when utilizing the criteria of a negative voltage of at least 0.85 volts (-850 mV).4 Specifically, the Notice alleged that Respondents’ practice was to add an additional -50mV to the -850 mV criteria and look for a minimum of -900 mV. This approach of assuming an IR drop of 0.50 V everywhere along the system failed to account for areas where the IR drop exceeded 50 mV. According to the Notice, EGT/MRT could not demonstrate that the IR drop was limited to 0.5 V along their entire pipeline systems. In addition, the Notice alleged that Respondents’ Corrosion Control Program procedure, PS-03-02-400 Cathodic Protection: Centerpoint Energy Midstream Operations Use of -0.85 Volt Criteria and IR Drop, was not referenced by the company’s other key procedure for executing cathodic protection electrical checks, PS-03-02-210, Cathodic Protection Criteria. Respondents contested this allegation of violation on a number of grounds. First, they argued that in response to a previous Notice of Amendment issued by PHMSA in 2006,5 the company had submitted a procedure change that included a voltage drop to 0.900 V.6 According to 4 “IR drop” is the difference between the voltage at the top of the pipe and the voltage at the surface of the earth caused by the electrical resistance of the soil in which the pipeline is buried. 5 In the Matter of Centerpoint Energy [4-2006-1015M] (issued October 27, 2006). 6 The Response contended that Procedure PS-03-02-210, Section 2.2-0.850 Volts Pipe-to-Soil (P/S) Criteria, had been amended to read: Voltage (IR) drops shall be considered per section 2.6 below. Where P/S potentials below -0.900 volts (current applied) are measured, further evaluation is required as follows: • Perform test to confirm proper operation of cathodic protection systems • Consider use of current interruption test methods • Consider adjustments for cathodic protection systems.#

420131010_Final Order_09022014_text.pdf, page 54 Respondents, this procedure was reviewed by PHSMA staff and on May 3, 2007, the agency “confirmed that this procedure was adequate….”7 Second, they argued that because Section II of Appendix D does not specify the method or procedure that must be used for considering IR drop, the regulations require only that the pipeline operator develop and document a process for how IR drop will be considered and nothing more. Under the companies’ procedure, PS-03-02-210, they take IR drops into consideration because the -0.900 mV trigger accounts for an IR drop of -0.50 mV, as compared to the -0.850 benchmark used in Section I.A.(1) of Appendix D. Third, Respondents argued that the regulation does not specify a standard for determining IR drop; instead, it appears that the standard applied during PHMSA’s inspection was NACE Standard SP0169, which has not been incorporated into the regulations. Therefore, Respondents argued that PHMSA was attempting to impose a requirement beyond the scope of the regulations. Fourth, the companies argued that PS-03-02-210, Sections 2.2 and 2.6, and PS-03-02-400 together established “sound engineering practices in determining the significance of voltage (IR) drops.”8 Finally, they argued that the Notice alleged that company “personnel acknowledged that IR Drop was not considered if the read is more negative than -900mV.” Respondents contended that any such acknowledgment was not correct and should not be the basis for a finding of violation. I reject the arguments presented by Respondents. The crux of the matter here is that sound engineering practice does not support the approach actually used by the companies to ensure cathodic protection. Although EGT/MRT cited procedure PS-03-02-210 Cathodic Protection Criteria, they actually used another procedure, PS-03-02-400 Cathodic Protection: Centerpoint Energy Midstream Operation’s Use of -0.85 Volt Criteria and IR Drop, to address the IR drops. Their practice was to add a factor of -0.050 volts to the -0.850 volts and use the resulting -0.900 volts as a determining factor for the consideration of an IR drop. This approach mistakenly assumed that the IR drop everywhere along their pipelines would be equal to or more positive than a -0.050 volts. However, Respondents could not demonstrate that the IR drop was, in fact, limited to -0.050 volts along their entire system. In fact, their own records establish that there were instances where the IR drop exceeded the -0.050 volts they had set. The Respondents’ procedures that Response at 7. 7 Id. 8 Under these procedures, personnel must: (i) Measure or calculate voltage drop(s); (ii) Review the historical performance of the cathodic protection system; (iii) Evaluate the physical and electrical characteristics of the pipe and its environment; and (iv) Determine whether or not there is physical evidence of corrosion. Response at 10.#

420131010_Final Order_09022014_text.pdf, page 65 were reviewed by PHMSA in response to the NOA may have been sufficient before the companies’ own records established instances where the IR drop exceeded -0.050 volts. If an assumed value for IR drop is to be used, it must be greater than any measured results to assure a valid interpretation of the voltage measurement when utilizing the criteria of a negative voltage of at least 0.85 volts (-850 mV). Accordingly, based upon a review of all of the evidence, I find that Respondents violated 49 C.F.R. § 192.463(a) by failing to provide a cathodic protection system for their pipelines that complied with one or more of the applicable criteria contained in Appendix D of part 192. Item 6: The Notice alleged that Respondents violated 49 C.F.R. § 192.605(b)(8), which states: § 192.605 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least once each calendar year. . . . (b) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following, if applicable, to provide safety during maintenance and operations. (1) . . . (8) Periodically reviewing the work done by operator personnel to determine the effectiveness, and adequacy of the procedures used in normal operation and maintenance and modifying the procedures when deficiencies are found. The Notice alleged that EGT/MRT violated 49 C.F.R. § 192.605(b)(8) by failing to prepare a manual of written procedures for periodically reviewing the effectiveness and adequacy of the procedures used in normal operation and maintenance and modifying them when deficiencies were found. Specifically, the Notice alleged that the procedure in place was insufficient insofar as it did not require a periodic and actual review of the company’s procedures but merely encouraged personnel to comment on the adequacy of those procedures on an ad hoc basis.9 In its Response, EGT/MRT argued that the proposed finding of violation should be withdrawn because its Procedure 102 (General), Procedure 200 (Abnormal Operations) and Procedure 600 (Emergency Plan) already required the review of procedures for effectiveness and adequacy. EGT/MRT further contended that the Notice addressed the adequacy of the company’s 9 The language found in Respondent’s Procedure 102 General, Section A – Scope, Item 6, reads: Operator personnel are encouraged to comment on the adequacy of the procedures found in the manuals as they are used in normal operations. When a procedure is thought to be deficient, operator personnel will inform the Region Director. The Region Director will notify Compliance & Support Services of the deficiency and Compliance and Support Services will modify the procedure as required by the Company’s Management of Change process.#

420131010_Final Order_09022014_text.pdf, page 76 procedures, rather than a violation of the pipeline safety regulations, and therefore, a Notice of Amendment would be the more appropriate vehicle for addressing any deficiency in procedures. I disagree. While EGT/MRT’s existing procedures for the periodic review of abnormal operations and emergencies may well be adequate, those procedures are not at issue here. The only issue raised in the Notice was the allegation that the company failed to prepare a procedure for the periodic and systematic review of its normal operation and maintenance procedures. I find that Procedure 102 (General) does not require a periodic review of work performed by personnel during normal operations to determine the effectiveness and adequacy of the procedures used during the work. Merely encouraging personnel to comment on such procedures on an ad hoc basis does not meet the regulatory requirement that an operator periodically analyze the work performed during normal operations to determine the effectiveness of its procedures, and document these periodic reviews by showing what modifications were made. Accordingly, after considering all of the evidence, I find that Respondents violated 49 C.F.R. § 192.605(b)(8) by failing to prepare procedures for periodically reviewing the effectiveness and adequacy of the procedures used in normal operation and maintenance and modifying those procedures when deficiencies were found. Item 7: The Notice alleged that Respondents violated 49 C.F.R. § 192.605(a), as quoted above, by failing to follow for each pipeline a manual of written procedures for conducting operations and maintenance activities and for emergency response. Specifically, the Notice alleged that EGT/MRT failed to follow their own established procedure, PS-03-01-272, IMP Personnel Qualifications Requirements, Section 2.6, which required Integrity Management supervisory personnel to complete, at a minimum, five training modules designed to ensure they had a thorough knowledge of the company’s Integrity Management Program (IMP) and the elements of that program for which each supervisor was responsible, as required under 49 C.F.R. § 192.915. Respondents identified thirty-five (35) employees within their IMP who were required to complete these courses. All 35 of these individuals were responsible for supervision, oversight, analysis and interpretation of external corrosion direct assessments, internal corrosion direct assessments, in-line inspection (ILI), stress corrosion cracking direct assessments, and other technologies used as assessment methods. Respondents argued that the investigators’ misunderstanding of the chart that EGT used to track course completion resulted in a miscalculation of the number of employees who had not completed one or more of the five training modules.10 Sixteen employees, rather than the 25 cited in the Notice, had not completed the training. This discrepancy was due to the fact that one of the training modules, identified by its course number 8000IMP, was tracked under two course numbers. Since the numbers were listed separately, it looked like many employees had failed to complete either the 8000IMP course or the 8000IMP-E course. In their Response, EGT/MRT did not dispute that the violation had occurred but did not agree with the Notice as to the number of employees affected. Accordingly, based upon a review of all of the evidence, I find that Respondents violated 49 C.F.R. § 192.605(a) by failing to follow for each pipeline a manual of written procedures for conducting operations and maintenance activities and for emergency response. 10 Response at 17.#

420131010_Final Order_09022014_text.pdf, page 87 Item 8: The Notice alleged that Respondents violated 49 C.F.R. § 192.605(a), as quoted above, by failing to follow for each pipeline a manual of written procedures for conducting operations and maintenance activities and for emergency response. Specifically, the Notice alleged that EGT/MRT failed to follow their own established procedure requiring company personnel to provide the ILI vendor with feature information (feedback) based on the excavation and evaluation of immediate and non-immediate (scheduled or monitored) conditions.11 The Notice alleged that for the following ILI runs and the associated monitored or scheduled condition digs, EGT/MRT were unable to provide verification that they had provided feedback to the vendor for possible tool calibration purposes: 1. 2. 3. 4. 5. 11-3 East of Pumpkin Center HCA; ML-2 Fountain Hill to Perryville; ML-3 Carlisle to West Point; BT-1-AS Jessieville to Perla Station; and F-185 Willow Springs to Coal Barn Trap. Respondents did not contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that Respondents violated 49 C.F.R. § 192.605(a) by failing to follow for each pipeline a manual of written procedures for conducting operations and maintenance activities and for emergency response. Item 10: The Notice alleged that Respondents violated 49 C.F.R. § 192.805(a), which states: § 192.805 Qualification program. Each operator shall have and follow a written qualification program. The program shall include provisions to: (a) Identify covered tasks: . . . . The Notice alleged that Respondents violated 49 C.F.R. § 192.805(a) by failing to have and follow a written qualification program that included provisions to identify covered tasks. Specifically, it alleged that EGT/MRT had failed to include as covered tasks in its Operator Qualification Plan the loading, launching, receiving and unloading of ILI tools used to perform integrity assessments under § 192.937(c)(1) and to perform cleaning, batching, etc. According to the Notice, EGT/MRT had identified covered tasks for CT-10: Internal Corrosion Monitoring- Sampling; CT-14: Valve Maintenance; CT-19: Visual External and Internal Pipe Inspection; CT- 26: Blow Down, Purge and Return a Pipeline to Service; and CT-47: Responding & Investigating Abnormal Operating Conditions, but these covered tasks did not encompass the training and qualification requirements specific to loading, launching, receiving, and unloading ILI tools from both in-service and out-of-service pipelines. 11 CEGT IMP Procedure PS-03-01-248 ILI Vendor Performance Specification, Section 2.4.3 Reported Anomalous Conditions, states: Non-Immediate Conditions: The Company shall provide the ILI vendor any feature information, based on the excavation and evaluation, for possible tool calibration.#

420131010_Final Order_09022014_text.pdf, page 98 Respondents did not contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that Respondents violated 49 C.F.R. § 192.805(a) by failing to have and follow a written qualification program that included provisions to identify covered tasks. 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 $200,000 per violation for each day of the violation, up to a maximum of $2,000,000 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; the history of Respondents’ prior offenses; and any effect that the penalty may have on their 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 $137,200 for the violations cited above. Item 3: The Notice proposed a civil penalty of $8,100 for Respondents’ violation of 49 C.F.R. § 191.17, for failing to submit annual reports for the calendar years 2007-2010 that included their entire pipeline systems by failing to report all bare unprotected steel pipe. The operators noted that upon discovering that 22.3 miles of pipe had not been listed under the correct category, EGT/MRT corrected the error on their next Annual Report. EGT/MRT argued that operators should not be fined for proactively taking steps to ensure the accuracy of their records, and then reporting on the basis of such corrected information.12 Although Respondents are to be commended for correcting their errors, it does not change the fact that they had incorrectly reported bare unprotected steel pipe in previous years. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondents a civil penalty of $8,100 for violation of 49 C.F.R. § 191.17. Item 7: The Notice proposed a civil penalty of $60,900 for Respondents’ violation of 49 C.F.R. § 192.605(a), for failing to follow for each pipeline a manual of written procedures for conducting operations and maintenance activities and for emergency response. Respondents argued that because almost twice as many employees were trained on all five training modules as PHMSA believed at the time the Notice was issued, PHMSA should reduce the penalty by 50 percent. Due to the discrepancy in the records with the number of affected employees, I have lowered the proposed penalty but not by 50 percent as requested, since the application of PHMSA’s penalty assessment criteria is not based on an equal penalty amount for each instance of violation. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondents a reduced civil penalty of $55,300 for violation of 49 C.F.R. § 192.605(a). 12 Response at 4.#

420131010_Final Order_09022014_text.pdf, page 109 Item 8: The Notice proposed a civil penalty of $27,000 for Respondents’ violation of 49 C.F.R. § 192.605(a), for failing to follow for each pipeline a manual of written procedures for conducting operations and maintenance activities and for emergency response. Respondents did not contest this allegation of violation or the proposed penalty. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondents a civil penalty of $27,000 for violation of 49 C.F.R. § 192.605(a). Item 10: The Notice proposed a civil penalty of $41,200 for Respondents’ violation of 49 C.F.R. § 192.805(a), for failing to develop and include a covered task or tasks in its Operator Qualification Plan for loading, launching, receiving and unloading in-line tools used to perform integrity assessment, to meet the requirements of § 192.937(c)(1), and other in-line tools used for cleaning, batching, etc. Respondents did not contest this allegation of violation or the proposed penalty. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondents a civil penalty of $41,200 for violation of 49 C.F.R. § 192.805(a). In summary, having reviewed the record and considered the assessment criteria for each of the Items cited above, I assess Respondents a total civil penalty of $131,600. 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-325), Federal Aviation Administration, Mike Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, Oklahoma 73125. The telephone number is (405) 954-8845. Failure to pay the $131,600 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 4, 6, 7, and 10 in the Notice for violations of 49 C.F.R. §§ 192.463(a), 192.605(b), 192.605(a) and 192.805(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 its operations: 1. With respect to the violation of § 192.463(a) (Item 4), Respondents must amend their procedures to properly consider IR drop. Where the -0.85 V criteria is utilized, EGT/MRT must record the Instant Off Reading to show the IR drop associated with#

420131010_Final Order_09022014_text.pdf, page 1110 this test point. The companies must provide a summary report to PHMSA Southwest Region detailing areas where IR drop was in excess of 50 mV and any remedial action required by further investigation at these locations, as required by § 192.463(a). 2. With respect to the violation of § 192.615(b)(3) (Item 6), Respondents must develop procedures to require an effectiveness review and analysis of procedures used during normal operations and maintenance activities. This review/analysis must show that some analysis has been performed to determine the adequacy of a procedure and, if found to be inadequate, and that appropriate modifications are made. The effectiveness review and analysis of procedures should be directed toward procedure refinement, not employee evaluation. 3. With respect to the violation of § 192.605(a) (Item 7), Respondents must ensure that all Integrity Management Program employees required to complete these training modules successfully complete this task. EGT/MRT must provide PHMSA with records that verify successful completion of the 5 modules by the IM supervisory personnel. 4. With respect to the violation of § 192.805(a) (Item 10), Respondents must develop covered tasks for loading, launching, receiving and unloading ILI smart tools for both in-service and out-of-service pipelines and incorporate them into their Operator Qualification program. 5. Provide PHMSA with documentation that verifies completion of numbers 1-4 above within 45 days following the receipt of the Final Order. 6. It is requested that EGT/MRT 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. It is requested that these costs be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses; and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. The Director may grant an extension of time to comply with any of the required items upon a written request timely submitted by the Respondents and demonstrating good cause for an extension. WARNING ITEMS With respect to Items 1, 2, 5 and 9, the Notice alleged probable violations of Part 192 but did not propose a civil penalty or compliance order for these items. Therefore, these are considered to be warning items. The warnings were for: 49 C.F.R. § 191.5(a) (Item 1) Respondents’ alleged failure to give notice at the earliest practicable moment following discovery of Incident No. 20070063-5058#

420131010_Final Order_09022014_text.pdf, page 1211 at approximately 10:30 a.m. on May 25, 2007. During the disassembly of an unloader involving compressor #3 on unit 2, an employee was struck in the abdomen when the pressurized equipment blew out and resulted in the employee’s in-patient hospitalization. 49 C.F.R. § 191.15(a) (Item 2) ─ Respondents’ alleged failure to submit DOT Form RSPA 7100.2 as soon as practicable but not more than 30 days after an incident that occurred on August 31, 2010, in Fouke, Arkansas. Specifically, the Notice alleged that on August 31, 2010, an incident involving a lightning strike resulted in a fire at the Fouke Town Border station, but EGT/MRT did not submit Form 7100.2 for this incident until October 5, 2010, five days past the filing deadline. 49 C.F.R. § 192.491(c) (Item 5) ─ Respondents’ alleged failure to maintain records of each test, survey, or inspection required by Subpart I in sufficient detail to demonstrate the adequacy of corrosion control measures or that a corrosive condition does not exist for the Carlisle Team Area for the January 2009 to June 2012 period. Respondents contend that the records that were kept were accurate and complete but PHMSA misinterpreted the information pertaining to completion of the inspections; and 49 C.F.R. § 192.605(a) (Item 9) ─ Respondents’ alleged failure to follow their own written procedures for analysis of ILI data by failing to identify a foreign metal object in close proximity to the pipe. EGT/MRT presented information in their Response showing they had taken certain actions to address the cited items. If OPS finds a violation of any of these items in a subsequent inspection, Respondents may be subject to future enforcement action. Under 49 C.F.R. § 190.215, Respondents have 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 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#

420131010_NOPV PCP PCO_06172013_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED June 17, 2013 Mr. Pete Kirsch Sr. VP - Pipeline Operations and Engineering Centerpoint Energy Gas Transmission Co Mississippi River Transmission Co 1111 Louisiana Street Houston, TX 77002 CPF 4-2013-1010 Dear Pete Kirsch: On multiple occasions between January 30 and October 19, 2012, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49 United States Code conducted an onsite inspection of Centerpoint Energy Gas Transmission Co. and Mississippi River Transmission Co. (together, CEGT) procedures and records for Operations and Maintenance, Integrity Management, Emergency Response, Operator Qualification, and Construction Specifications in Shreveport, LA. As a result of the inspection, it appears that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violations are:#

420131010_NOPV PCP PCO_06172013_text.pdf, page 21. 2. 3. §191.5 Immediate notice of certain incidents. (a) At the earliest practicable moment following discovery, each operator shall give notice in accordance with paragraph (b) of this section of each incident as defined in §191.3. CEGT failed to give notice at the earliest practicable moment following discovery of Incident No. 20070063-5058: At approximately 10:30 a.m. on May 25, 2007, during disassembly of an unloader involving compressor #3 on unit 2 (Unionville CS), an employee was struck in the abdomen when the pressurized equipment caused an actuator to blow out and this required immediate hospitalization for several days. CEGT did not report the incident to the National Response Center (NRC) until May 30, 2007 despite the absence of any circumstances that would have prevented it from making the telephonic report at or about the time the employee was hospitalized. §191.15 Transmission systems, gathering systems, and liquefied natural gas facilities. Incident report. (a) Transmission or Gathering. Each operator of a transmission or a gathering pipeline system must submit DOT Form PHMSA F 7100.2 as soon as practicable but not more than 30 days after detection of an incident required to be reported under § 191.5 of this part. CEGT failed to submit a Form 7100.2 incident report as soon as practicable but not more than 30 days after an incident required to be reported under §191.5 occurred on August 31, 2010 in Fouke, AR. On August 31, 2010 an incident occurred involving a lightning strike resulting in a fire at the Fouke Town Border Station that required an incident report to be filed within 30 days. CEGT submitted the Form 7100.2 for this incident on October 5, 2010. As a result, CEGT exceeded the maximum 30 day time frame by five (5) days. §191.17 Transmission systems, gathering systems, and liquefied natural gas facilities. Annual report. (a) Transmission or Gathering. Each operator of a transmission or a gathering pipeline system must submit an annual report for that system on DOT Form PHMSA 7100.2.1. This report must be submitted each year, not later than March 15, for the preceding calendar year, except that for the 2010 reporting year the report must be submitted by June 15, 2011. CEGT failed to submit annual reports for the years 2007-2010 that included its entire pipeline system by omitting to report bare unprotected steel pipe for OPID 602.1 1 OPID 602 consists of approximately 6140 miles of pipeline located in the following states: Arkansas, Kansas, Louisiana, Mississippi, Missouri, Oklahoma, Tennessee and Texas. 2#

420131010_NOPV PCP PCO_06172013_text.pdf, page 3The 2008, 2009 and 2010 Annual Reports (AR, LA, and OK) for OPID 602 omitted all quantities of Bare ‘Unprotected’ steel pipe. The 2007 Annual Report (LA) for OPID 602 listed a quantity of 3 miles of Bare ‘Unprotected’ steel pipe. During its inspection, PHMSA reviewed the 2011 Annual Report confirming that there was actually 22.3 miles of Bare ‘Unprotected’ steel pipe. The quantities are as follows: 16.63 miles (Line 9 in the Western Region-OK); 0.3 miles (Line FT-3 in Southern Region-LA); and 5.35 miles (Line KM-26 in Southern Region-AR). CEGT personnel said that they had been unaware that the pipeline mileage had been omitted until it conducted a verification of its pipeline data in accordance with Advisory Bulletin ADB-12-06. 4. § 192.463 External corrosion control: Cathodic protection. (a) Each cathodic protection system required by this subpart must provide a level of cathodic protection that complies with one or more of the applicable criteria contained in appendix D of this part. If none of these criteria is applicable, the cathodic protection system must provide a level of cathodic protection at least equal to that provided by compliance with one or more of these criteria. 49 CFR Part 192 Appendix D: I. Criteria for cathodic protection— A. Steel, cast iron, and ductile iron structures. (1) A negative (cathodic) voltage of at least 0.85 volt, with reference to a saturated copper-copper sulfate half cell. Determination of this voltage must be made with the protective current applied, and in accordance with sections II and IV of this appendix. (2) A negative (cathodic) voltage shift of at least 300 millivolts. Determination of this voltage shift must be made with the protective current applied, and in accordance with sections II and IV of this appendix. This criterion of voltage shift applies to structures not in contact with metals of different anodic potentials. (3) A minimum negative (cathodic) polarization voltage shift of 100 millivolts. This polarization voltage shift must be determined in accordance with sections III and IV of this appendix. (4) A voltage at least as negative (cathodic) as that originally established at the beginning of the Tafel segment of the E-log-I curve. This voltage must be measured in accordance with section IV of this appendix. (5) A net protective current from the electrolyte into the structure surface as measured by an earth current technique applied at predetermined current discharge (anodic) points of the structure. II. Interpretation of voltage measurement. Voltage (IR) drops other than those across the structure-electrolyte boundary must be considered for valid interpretation of the voltage measurement in paragraphs A(1) and (2) and paragraph B(1) of section I of this appendix. III. Determination of polarization voltage shift. The polarization voltage shift must be determined by interrupting the protective current and measuring the polarization decay. When the current is initially interrupted, an immediate 3#

420131010_NOPV PCP PCO_06172013_text.pdf, page 4voltage shift occurs. The voltage reading after the immediate shift must be used as the base reading from which to measure polarization decay in paragraphs A(3), B(2), and C of section I of this appendix. CEGT is utilizing the Appendix D(I)(A)(1) criteria of a negative (cathodic) voltage of at least 0.85 volts (-850 mV) but fails to fully consider IR drop as required under section II of the Appendix for a valid interpretation of the voltage measurement. CEGT’s Corrosion Control Program Procedure PS-03-02-210 Cathodic Protection Criteria section 2.2 states: “Where P/S potentials below -0.900 volts (current applied) are measured, further evaluation is required.” Where CEGT utilizes the Appendix D section (I)(A)(1) criteria of -850 mV, CEGT personnel acknowledged that IR drop was not considered if the read is more negative than -900 mV. CEGT’s practice is to add an additional -50 mV to the -850 mV criteria and look for a minimum of -900 mV criteria. However, this approach of assuming an IR drop of 0.50 V everywhere along the system fails to account for areas where IR drop exceeds 50 mV. CEGT could not demonstrate that the IR drop was limited to .50 V along their pipeline system. In fact recors show that is some areas the IR drop exceeded 50mV. Therefore, CEGT’s use of a 50 mV buffer and only taking action when ‘On’ potentials are more positive than -900 mV does not give a valid interpretation of the voltage measurement that would meet the applicable requirement. In addition, CEGT’s Corrosion Control Program Procedure PS-03-02-400 Cathodic Protection: Centerpoint Energy Midstream Operation’s Use Of -0.85 Volt Criteria and IR Drop was not referenced by PS-03-02-210, the functional procedure for executing cathodic protection electrical checks. 5. §192.491 Corrosion control records. (c) Each operator shall maintain a record of each test, survey, or inspection required by this subpart in sufficient detail to demonstrate the adequacy of corrosion control measures or that a corrosive condition does not exist. These records must be retained for at least 5 years, except that records related to §§192.465(a) and (e) and 192.475(b) must be retained for as long as the pipeline remains in service. CEGT failed to maintain records of each test, survey, or inspection required by Subpart I in sufficient detail to demonstrate the adequacy of corrosion control measures or that a corrosive condition does not exist for the Carlisle Team Area for the January 2009 to June 2012 period. CEGT procedure PS-03-02-001 Corrosion Control Program section 2.12 Corrosion Control Records states: 4#

420131010_NOPV PCP PCO_06172013_text.pdf, page 56. “The Company will maintain records for a minimum of five years for each analysis, check, demonstration, examination, inspection, investigation, review, survey and test required by this Program in sufficient detail to demonstrate the adequacy of corrosion control measures or that corrosion requiring control measures does not exist.” PHMSA reviewed the ‘Digout of Buried Pipe’ inspection reports for the Buckley, Chickasha and Carlisle Team Areas dated between January 2009 and June 2012. In the Carlisle Area report, there were 4 specific Work Orders (WO) Nos. 718482, 718484, 718485 and 718486 that contained inacurrate or incomplete information such as whether external inspections were applicable and whether the disposition of each inspection reflected the completion of all field work needed including closed work orders having comments to the effect that the work was still in progress. PHMSA reviewed the raw data driving the reports and verified that it wasn’t a data output issue but a failure to complete the documentation accurately. §192.605 Procedural manual for operations, maintenance, and emergencies (b) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following, if applicable, to provide safety during maintenance and operations. (8) Periodically reviewing the work done by operator personnel to determine the effectiveness and adequacy of the procedures used in normal operation and maintenance and modifying the procedure when deficiencies are found. CEGT has failed to develop procedures that require a periodic effectiveness review and analysis of procedures used during normal operations and maintenance activities. PHMSA reviewed the CEGT O&M Manual, Procedure 102 General, section A - Scope, item 6 which states: “Operator personnel are encouraged to comment on the adequacy of the procedures found in the manuals as they are used in normal operations. When a procedure is thought to be deficient, operator personnel will inform the Region Director. The Region Director will notify Compliance & Support Services of the deficiency and Compliance & Support Services will modify the procedure as required by the Company’s Management of Change process.” Encouraging personnel to comment does not meet the regulatory requirement to periodically analyze incident data, near miss data, meetings to discuss the procedures, job safety analysis, etc., to determine effectiveness and document these periodic reviews and their findings on whether the procedures analyzed were adequate or inadequate. 5#

420131010_NOPV PCP PCO_06172013_text.pdf, page 67. 8. §192.605 Procedural manual for operations, maintenance, and emergencies (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least one each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. §192.915 What knowledge and training must personnel have to carry out an integrity management program? (a) Supervisory personnel. The integrity management program must provide that each supervisor whose responsibilities relate to the integrity management program possesses and maintains a thorough knowledge of the integrity management program and of the elements for which the supervisor is responsible. The program must provide that any person who qualifies as a supervisor for the integrity management program has appropriate training or experience in the area for which the person is responsible. (b) Persons who carry out assessments and evaluate assessment results. The integrity management program must provide criteria for the qualification of any person-- (1) Who conducts an integrity assessment allowed under this subpart; or (2) Who reviews and analyzes the results from an integrity assessment and evaluation; or (3) Who makes decisions on actions to be taken based on these assessments. CEGT has failed to follow its established procedures that require Integrity Management Supervisory personnel to complete, as a minimum, the 5 training modules noted in section 2.6 of Procedure PS-03-01-272 IMP Personnel Qualification Requirements. CEGT identified thirty-five (35) employees within the Integrity Management Program that were required to complete these courses. All 35 of these individuals are responsible for supervision, oversight, analysis and interpretation of ECDA, ICDA, ILI, SCCDA and Other Technology used as assessment methods within the Integrity Management Program. As of 5/21/2012, twenty-five (25) of the thirty-five (35) employees lacked completing one (1) or more of the modules. §192.605 Procedural manual for operations, maintenance, and emergencies (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least one each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. 6#

420131010_NOPV PCP PCO_06172013_text.pdf, page 79. §192.921 How is the baseline assessment to be conducted? (a) Assessment methods. An operator must assess the integrity of the line pipe in each covered segment by applying one or more of the following methods depending on the threats to which the covered segment is susceptible. An operator must select the method or methods best suited to address the threats identified to the covered segment (See §192.917). (1) Internal inspection tool or tools capable of detecting corrosion, and any other threats to which the covered segment is susceptible. An operator must follow ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.2 in selecting the appropriate internal inspection tools for the covered segment. CEGT failed to follow its established procedures to provide the ILI Vendor with feature information (feedback) based on the excavation and evaluation of Immediate and Non- Immediate (Scheduled or Monitored) Conditions as follows: CEGT IMP Procedure PS-03- 01-248 ILI Vendor Performance Specification, section 2.4.3 Reported Anomalous Conditions: states: “ Non-Immediate Conditions:The Company shall provide the ILI Vendor any feature information, based on the excavation and evaluation, for possible tool calibration.” PHMSA reviewed the following ILI runs: 11-3 East of Pumpkin Center HCA, 8/13/2011; ML-2 Fountain Hill to Perryville, 7/26/2011; ML-3 Carlisle to West Point, 4/28/2011; BT-1- AS Jessieville to Perla Station, 4/21/2010; and F-185 Willow Springs to Coal Barn Trap, 6/18/2009. These were only a sampling of ILI runs and the associated monitored/scheduled condition digs. For all the runs that were reviewed, CEGT did not provide verification that feedback was provided to the vendor for possible tool calibration purposes. §192.605 Procedural manual for operations, maintenance, and emergencies (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least one each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. §192.933 What actions must be taken to address integrity issues? (b) Discovery of condition. Discovery of a condition occurs when an operator has adequate information about a condition to determine that the condition presents a potential threat to the integrity of the pipeline. A condition that presents a potential threat includes, but is not limited to, those conditions that require remediation or monitoring listed under paragraphs (d)(1) through (d)(3) of this section. An operator must promptly, but no later than 180 days after conducting an integrity assessment, obtain sufficient information 7#

420131010_NOPV PCP PCO_06172013_text.pdf, page 8about a condition to make that determination, unless the operator demonstrates that the 180-day period is impracticable. CEGT failed to follow its established procedure for analysis of in-line inspection data by failing to identify a foreign metal object in close proximity to the pipe. The CEGT IMP Procedure, PS-03-01-244 In-Line Inspection and Analysis, section 2.5 Analysis of Inspection Data: states: ‘2.5.2 Ensure the vendor’s ILI Final Report contains at a minimum, the main features requested by the Company. F. The location of any foreign metal objects in close proximity to the pipe.’ In 2007, an ILI was performed on Line CP which intersected with the El Paso Exploration and Production 6-inch pipeline. The El Paso 6 inch pipeline had been installed by horizontal directional drill (HDD) during the construction of Line CP on January 31, 2007. On December 11, 2007, an MFL/TFI In-Line Inspection was run on Line CP. The ILI identified an unknown feature with metal loss at station 1976+31. Although there was metal loss associated with the anomaly, the site was not chosen as a dig site due to the low level of severity and a foreign line crossing was not identified in the Pipeline Open Data Standards (PODS) at this location. CEGT had failed to update the PODS system with the new 6 inch pipeline installed in January 2007. In December 2010, a second ILI of Line CP resulted in the same feature at station 1976+31 as indicated in 2007. The location was placed on the dig site schedule as a verification dig and excavated and inspected on April 8, 2011. It was discovered that the El Paso pipeline was installed in contact with the bottom of CEGT’s 42” Line CP. During the directional drilling, Line CP was struck by the pilot bit of the drilling machine on the North bottom side and struck with the reamer bit on the South bottom side resulting in the removal of the El Paso 6 inch pipeline and the installation of a Type B Weld Sleeve on Line CP on April 9, 2011. 10. §192.805 Qualification program. Each operator shall have and follow a written qualification program. The program shall include provisions to: (a) Identify covered tasks; §192.801 Scope. (b) For the purpose of this subpart, a covered task is an activity, identified by the operator, that: (1) Is performed on a pipeline facility; (2) Is an operations or maintenance task; (3) Is performed as a requirement of this part; and (4) Affects the operation or integrity of the pipeline. 8#

420131010_NOPV PCP PCO_06172013_text.pdf, page 9CEGT has failed to develop and include a covered task or tasks in its Operator Qualification Plan for loading, launching, receiving and unloading in-line inspection (ILI) smart tools used to perform integrity assessments to meet the requirements of §192.937(c)(1) and other in-line tools used for cleaning, batching, etc. Loading, launching, receiving, and unloading in-line tools are covered maintenance tasks and meet the four part test required by §192.801(b). While CEGT has identified covered tasks for: CT-10: Internal Corrosion Monitoring- Sampling; CT-14: Valve Maintenance; CT-19: Visual External and Internal Pipe Inspection; CT-26: Blow Down, Purge and Return a Pipeline to Service; and CT-47: Responding & Investigating Abnormal Operating Conditions, these covered tasks do not encompass the training and qualification requirements specific to loading ILI tools, launching, receiving, and unloading these tools from both in-service and out of service lines. Specifically, CT10, 14, 19, 26 and 47 include the following pertinent Knowledge Requirements (Training Modules) 400: Valve Operators, 401: Valve Maintenance, 411: Pipeline Purging, 416 Pipeline Shutdown and Startup Planning, 1010 Abnormal Operating Conditions (AOC). When PHMSA staff reviewed these “Training Modules” they did not encompass those steps required for pigging operations. Specifically they did not have requirements for identifying the procedures, practices, and equipment needed for conducting pigging operations; the identification of associated valves; steps for associated isolation and lockout/tagout (LOTO) procedures (isolating the barrel from pipeline); relieving pressure within the barrel and/or, inserting or removing internal devices into/from the barrel, pressurizing the barrel to pipeline pressures; launching, monitoring, and/or receiving/removing ILI tools; nor realigning all identified valves to normal operations. These modules also did not reflect the marked differences in pigging operations on in-service and out-of-service lines such as when the use of product is used to propel the ILI tool and specific Abnormal Operating Conditions that individuals performing loading, launching, receiving, and unloading need to be qualified in. Proposed Civil Penalty Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $200,000 per violation per day the violation persists up to a maximum of $2,000,000 for a related series of violations. For violations occurring prior to January 4, 2012, the maximum penalty may not exceed $100,000 per violation per day, with a maximum penalty not to exceed $1,000,000 for a 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 $137,200 as follows: Item number PENALTY 3 $8,100 7 $60,900 8 $27,000 10 $41,200 9#

420131010_NOPV PCP PCO_06172013_text.pdf, page 10Warning Items With respect to items 1, 2, 5, and 9, we have reviewed the circumstances and supporting documents involved in this case and have decided not to conduct additional enforcement action or penalty assessment proceedings at this time. We advise you to promptly correct these items. Failure to do so may result in additional enforcement action. Proposed Compliance Order With respect to items 4, 6, 7, and 10 pursuant to 49 United States Code § 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 response options. All material you submit in response to this enforcement action may be made publicly available. If you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order. In your correspondence on this matter, please refer to CPF 4-2013-1010 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, R. M. Seeley Director, SW Region Pipeline and Hazardous Materials Safety Administration Enclosures: Proposed Compliance Order Response Options for Pipeline Operators in Compliance Proceedings 10#

420131010_NOPV PCP PCO_06172013_text.pdf, page 11PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Centerpoint Energy Gas Transmission a Compliance Order incorporating the following remedial requirements to ensure the compliance of Centerpoint Energy Gas Transmission: 1. 2. 3. 4. 5. 6. In regard to Item Number 4 of the Notice pertaining to CEGT failing to properly considering for IR drop where they are utilizing the Appendix D(I)(A)(1)Criteria of a negative (cathodic) voltage of at least 0.85 volts (-850 mV), CEGT must amend their procedures to properly consider IR drop. Where the -0.85 V criteria is utilized, CEGT must record the Instant Off Reading to show the IR drop associated with this test point. CEGT must provide a summary report to PHMSA Southwest Region detailing areas where IR drop was in excess of 50 mV and any remedial action required by further investigation at these locations as required by 192.463(a). In regard to Item Number 6 of the Notice pertaining to CEGT failing to develop procedures that require an effectiveness review and analysis of procedures used during normal operations and maintenance activities, CEGT must develop procedures to require an effectiveness review and analysis of procedures. This review/analysis must show that some analysis has been performed to determine the adequacy of a procedure and, if found to be inadequate, the appropriate modifications are made. The effectiveness review and analysis of procedures should be directed toward procedure refinement, not employee evaluation. In regard to Item Number 7 of the Notice pertaining to CEGT failing to follow their procedures that require Integrity Management Supervisory personnel to complete, as a minimum, the 5 training modules noted in section 2.6 of Procedure PS-03-01-272 IMP Personnel Qualification Requirements, CEGT must ensure that all Integrity Management Program employees required to complete these training modules successfully complete this task. CEGT must provide PHMSA with records that verify successful completion of the 5 modules by the IM supervisory personnel. In regard to Item Number 10 of the Notice pertaining to CEGT failing to develop and include a covered task or tasks in the Operator Qualification Plan for loading, launching, receiving and unloading ILI smart tools for both in-service and out-of- service pipelines, CEGT must develop covered tasks) for loading, launching, receiving and unloading ILI smart tools for both in-service and out-of-service pipelines and incorporate them into the OQ Program. Provide PHMSA with documentation that verifies completion of numbers 1-4 above within 45 days following the receipt of the Final Order. It is requested (not mandated) that Centerpoint Energy Gas Transmission 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. It is requested that these costs be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses, and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. 11#