ENABLE GAS TRANSMISSION, LLC — Notice of Probable Violation

party submissionOfficial PDF420131018_Operator Response to Notice_ 01202014.pdf#

420131018_Final Order_01292015_text.pdf, page 1Official PDFJanuary 29, 2015 Mr. Lynn L. Bourdon III President and CEO Enable Midstream Partners, LP One Leadership Square 211 N Robinson Ave., Suite 950 Oklahoma City, OK 73102 Re: CPF No. 4-2013-1018 Dear Mr. Bourdon: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation, assesses a civil penalty of $118,200, and specifies actions that need to be taken by your subsidiary, Enable Gas 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, OPS, 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. Rodrick M. Seeley, Director, Southwest Region, OPS Mr. Chris Bullock, Director, DOT Compliance, Enable Midstream Partners, LP CERTIFIED MAIL - RETURN RECEIPT REQUESTED#

420131018_Final Order_01292015_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. 4-2013-1018 ) Respondent. ) ____________________________________) FINAL ORDER On multiple dates in February and March, 2013, pursuant to 49 U.S.C. § 60117, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the facilities and records of Centerpoint Energy Gas Transmission Company, LLC (CEGT), in Arkansas, Louisiana, and Oklahoma. Since the date of that inspection, CEGT has been renamed Enable Gas Transmission, LLC (EGT or Respondent).1 EGT is one of two wholly-owned subsidiaries of Enable Midstream Partners, LP, which operates more than 8,000 miles of interstate pipeline located in Arkansas, Illinois, Kansas, Louisiana, Mississippi, Missouri, Oklahoma, Tennessee and Texas. 2 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Respondent, by letter dated November 5, 2013, a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice), which also included warnings pursuant to 49 C.F.R. § 190.205. In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that EGT had committed various violations of 49 C.F.R. Part 192 and assessing a civil penalty of $118,200 for the alleged violations. The Notice also proposed ordering Respondent to take certain measures to correct the alleged violations. The warning items required no further action, but warned the operator to correct the probable violations or face future potential enforcement action. EGT responded to the Notice by letter dated January 20, 2014 (Response). The company contested some of the allegations, offered additional information in response to the Notice, and requested that the proposed civil penalty be reduced. Respondent did not request a hearing and therefore has waived its right to one. 1 Centerpoint Energy Inc., Annual Report (Form 10-K), at 78 (Feb. 26, 2014), available at http://investors.centerpointenergy.com/annuals.cfm. 2 http://www.centerpointenergy.com/services/pipelines/egt/ (last accessed on July 28, 2014).#

420131018_Final Order_01292015_text.pdf, page 3CPF No: 4-2013-1018 Page 2 FINDINGS OF VIOLATION The Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows: Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 192.467(d), which states: § 192.467 External corrosion control: Electrical isolation. (a) Each buried or submerged pipeline must be electrically isolated from other underground metallic structures, unless the pipeline and the other structures are electrically interconnected and cathodically protected as a single unit. (b) . . . . (d) Inspection and electrical tests must be made to assure that electrical isolation is adequate. The Notice alleged that Respondent violated 49 C.F.R. § 192.467(d) by failing to inspect and electrically test each buried pipeline to assure that electrical isolation was adequate. Specifically, the Notice alleged that EGT’s corrosion control program procedure required testing of insulating devices at custody-transfer locations on both the foreign side and the EGT side of the line, but that the company had failed to take readings on the foreign side of insulating devices at 11 different locations for a total of 29 times during 2010, 2011, and 2012. In its Response, EGT stated that the company missed only eight of the required readings, and requested that PHMSA reduce the level of the proposed civil penalty and the scope of the proposed compliance order accordingly. EGT stated that 13 of the readings were at test points “categorized as ‘Normal’ rather than ‘Insulated’ and thus no ‘foreign side’ electric potential reading was required.”3 EGT stated that the eight missing readings were at test points that “had been mistakenly identified as ‘Insulated’ in EGT’s Maintenance Management System,” that EGT had already identified and corrected the data error prior to PHMSA’s inspection, and that therefore these missing readings should not be considered violations of the regulation. In support of this argument, EGT provided a report listing test-point inspection results.4 EGT’s Response and attached report, however, do not explicitly identify which test readings the company believes fall into each category. My review of the report shows the following: Test Point Location Dates of tests with test-point type listed as “Insulated” Dates of tests with test-point type listed as “Normal” TP 21250 5/6/2010 and 5/11/2011 TP 24316 5/6/2010 and 5/11/2011 5/15/2012 TP 26318 4/28/2010 and 4/18/2011 TP 27667 12/21/2010 and 4/18/2011 4/10/2012 TP 27668 12/21/2010 and 4/18/2011 4/10/2012 TP 27669 12/21/2010 4/18/2011 and 4/10/2012 3 Response at 5. 4 Response Attachment 2-1.#

420131018_Final Order_01292015_text.pdf, page 4CPF No: 4-2013-1018 Page 3 TP 27671 12/21/2010 4/18/2011 and 4/10/2012 TP 27672 12/21/2010 4/18/2011 and 4/10/2012 TP 27673 12/21/2010 4/18/2011 and 4/10/2012 TP 4085 6/18/2010 6/13/2011 and 6/14/2012 TP 8242 8/7/2010 This review does show eight locations where the test-point type was changed from “Insulated” to “Normal.” However, EGT did not provide an explanation as to why the test points that had been mistakenly identified as “Insulated” were later changed to “Normal” and why they were not corrected on the report at the time of the inspections if they were not, in fact, insulated. If EGT discovered during a test that a test point was identified incorrectly, the test record should have made a note of this data error. At least one test was conducted at each of the 11 test-point locations that had been identified as “Insulated,” but EGT neither conducted a “foreign-side” test at these sites nor corrected the identification of the test point. In each of these 11 locations, the company’s records fail to demonstrate that EGT was able to assure that electrical isolation was indeed adequate. Accordingly, based upon a review of all of the evidence and the legal issues presented, I find that Respondent violated 49 C.F.R. § 192.467(d) by failing to inspect and electrically test each buried pipeline to assure that electrical isolation was adequate. Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 192.605(a), 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. 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. The Notice alleged that Respondent violated 49 C.F.R. § 192.605(a) by failing to follow its own manual of written procedures for conducting operations and maintenance activities. Specifically, the Notice alleged that EGT’s procedures required it to periodically evaluate pipeline “dead legs” for corrosivity through gas sampling, coupons, and liquid sampling, but that the company failed to conduct evaluations at five such locations, at facilities with piping that was defined as “U- shaped” or “L-shaped.” In its Response, EGT stated that it had “complied with its procedures for evaluating the risk of corrosion in dead legs identified” in the Notice. 5 EGT explained that its Corrosion Control 5 Response at 8.#

420131018_Final Order_01292015_text.pdf, page 5CPF No: 4-2013-1018 Page 4 Program Procedure PS-03-02-002 did not require that the company inspect each dead leg. Rather, it argued that its procedure required that EGT “evaluate the risk of internal corrosion based on multiple factors and the presence of corrosive gas…. Applying these procedures, EGT ‘evaluates’ its entire system, of which the dead legs addressed in the [Notice] would be a part of [sic], based on these factors.”6 EGT went on to explain that the procedure also referenced the company’s Integrity Management Program to assess and evaluate the risk of internal corrosion. Finally, EGT stated that its “systematic evaluations showed no corrosive gas conditions upstream of the dead leg locations addressed in [the Notice], so no further evaluation within those dead leg locations was required by EGT’s procedures.”7 I disagree, for two reasons. First, EGT did not provide a copy of its evaluation or analysis of upstream conditions that supposedly determined there were no corrosive conditions and that the dead legs in question here did not need to be evaluated for internal corrosion. In fact, the procedure that was available during the OPS inspection and the version that EGT provided in its Response could readily support the opposite conclusion. It identified several factors that influence the formation of internal corrosion, including dead legs, and stated: “Because of the above factors, the Company will periodically evaluate gas pipelines for corrosivity through gas sampling, coupons, and liquid sampling as required.” Second, EGT stated that it complied with its procedure by performing system-wide evaluations, but did not identify how the company evaluated the “U-shaped” and “L-shaped” dead legs identified in the Notice. In its Response, EGT provided a copy of its 2009 Dead Leg Inspection Program – Final Summary Report, which states: “The typical dead leg configuration we are trying to evaluate is one of the following where a section of pipe has been stubbed or capped such that there is no/low flow gas conditions.” The report goes on: “Five or 6 representative dead legs were selected from each region with the intention of developing a diversified sampling of the dead legs across the company pipeline system. The location of these dead legs was identified based on feedback from personnel from each region.”8 While such a systematic approach is commendable, EGT still failed to follow its own procedures for evaluating each type of dead leg that existed on its system. Notably, the dead legs that were identified in the Notice were all oriented in the vertical plane, and there is no indication that EGT evaluated other dead legs with similar characteristics or considered the orientation of the dead legs as a factor to be considered in its inspection program As a consequence, EGT failed to demonstrate that it had evaluated all types of dead legs in its system, including “U-shaped” and “L-shaped” dead legs and those oriented in the vertical plane, for internal corrosion through gas sampling, coupons, and liquid sampling as required by its Corrosion Control Program Procedure PS-03-02-001. Accordingly, after considering all of the evidence and the legal issues presented, I find that Respondent violated 49 C.F.R. § 192.605(a) by failing to follow its manual of written procedures for conducting operations and maintenance 6 Response at 9. 7 Id. 8 Response, Attachment 7-4, at 1.#

420131018_Final Order_01292015_text.pdf, page 6CPF No: 4-2013-1018 Page 5 activities. Item 10: The Notice alleged that Respondent violated 49 C.F.R. § 192.739(a), which states: § 192.739 Pressure limiting and regulating stations: Inspection and testing. (a) Each pressure limiting station, relief device (except rupture discs), and pressure regulating station and its equipment must be subjected at intervals not exceeding 15 months, but at least once each calendar year, to inspections and tests to determine that it is— (1) In good mechanical condition; (2) Adequate from the standpoint of capacity and reliability of operation for the service in which it is employed; (3) Except as provided in paragraph (b) of this section, set to control or relieve at the correct pressure consistent with the pressure limits of § 192.201(a); and (4) Properly installed and protected from dirt, liquids, or other conditions that might prevent proper operation. The Notice alleged that Respondent violated 49 C.F.R. § 192.739(a) by failing to inspect and test each pressure regulating station at least once each calendar year to determine that it is set to control or relieve at the correct pressure consistent with the pressure limits of § 192.201(a). Specifically, the Notice alleged that from 2007 to 2011, EGT failed to inspect regulating station MSM11007 to ensure it was set to control or relieve pressure consistent with the pressure limits of the downstream plastic pipeline RM-5. Respondent did not contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 192.739(a) by failing to inspect and test each pressure regulating station to determine that it is set to control or relieve at the correct pressure consistent with the pressure limits of § 192.201(a). These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed $200,000 per violation for each day of the violation, up to a maximum of $2,000,000 for any related series of violations.9 In determining the amount of a civil penalty under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature, circumstances, and gravity of the violation, including adverse impact on the environment; the degree of Respondent’s culpability; the history of Respondent’s prior offenses; and any effect 9 The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, Pub. L. No. 112-90, § 2(a)(1), 125 Stat. 1904, January 3, 2012, increased the civil penalty liability for violating a pipeline safety standard to $200,000 per violation for each day of the violation, up to a maximum of $2,000,000 for any related series of violations.#

420131018_Final Order_01292015_text.pdf, page 7CPF No: 4-2013-1018 Page 6 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 $118,200 for the violations cited above. Item 2: The Notice proposed a civil penalty of $72,700 for Respondent’s violation of 49 C.F.R. § 192.467(d), for failing to inspect and electrically test each buried pipeline to assure that electrical isolation was adequate. The Notice alleged that Respondent failed to take readings on the foreign side of insulating devices at 11 different locations a total of 29 times, and accordingly proposed a civil penalty based on 11 violations of the regulation. In its Response, EGT stated that the company missed only eight of the required readings and requested that the civil penalty be reduced accordingly. However, as discussed above, I found that at all 11 test point locations, at least one test was conducted during a time when it was identified as “Insulated,” yet neither a “foreign-side” test was conducted nor was the identification of the test point corrected. I have reviewed the original penalty that was proposed and find that it was reasonably based on the 11 test sites in question, not the total number of tests that were allegedly missed. Electrical isolation is necessary to protect against external corrosion, which can cause pipeline failure if left unchecked. Respondent was fully culpable for its failure to conduct the tests according to its own procedures and records. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $72,700 for violation of 49 C.F.R. § 192.467(d). Item 10: The Notice proposed a civil penalty of $45,500 for Respondent’s violation of 49 C.F.R. § 192.739(a), for failing to inspect and test each pressure regulating station to determine that it is set to control or relieve at the correct pressure consistent with the pressure limits of § 192.201(a). Respondent did not contest either the allegation or the proposed penalty. Pressure limiting devices are necessary to prevent over-pressurization, which can cause a pipeline failure. Respondent’s failure to inspect this pressure regulating station for five years could have resulted in a serious pipeline accident. Respondent was fully aware of the requirement and fully culpable for the violation. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $45,500 for violation of 49 C.F.R. § 192.739(a). In summary, having reviewed the record and considered the assessment criteria for each of the Items cited above, I assess Respondent a total civil penalty of $118,200. 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 (AMK-325), Federal Aviation Administration, Mike Monroney Aeronautical Center, P. O. Box 269039, Oklahoma City, Oklahoma 73125. The#

420131018_Final Order_01292015_text.pdf, page 8CPF No: 4-2013-1018 Page 7 Financial Operations Division telephone number is (405) 954-8845. Failure to pay the $118,200 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 2 and 7 in the Notice for violations of 49 C.F.R. §§ 192.467(d) and 192.605(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, Respondent is 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 § 192.467(d) (Item 2), Respondent must evaluate its pipeline system and locate all custody-transfer electrical isolation points. At each such location, Respondent must confirm that electrical isolation is adequate and take prompt action to correct any deficiencies. Respondent must complete this item and provide a report detailing any deficiencies and remediation to the Director within 180 days after receipt of this Final Order. 2. With respect to the violation of § 192.605(a) (Item 7), Respondent must develop a plan to locate and evaluate all types of dead legs within its pipeline system for internal corrosion, and must submit this plan to the Director within 90 days after receipt of this Final Order. Respondent must document the evaluation of each dead leg location and any corrective actions taken as a result of these evaluations, and submit the results to the Director within one year after receipt of this Final Order. 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 and demonstrating good cause for an extension. Failure to comply with this Order may result in the administrative assessment of civil penalties not to exceed $200,000 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.#

420131018_Final Order_01292015_text.pdf, page 9CPF No: 4-2013-1018 Page 8 WARNING ITEMS With respect to Items 1, 3, 4, 5, 6, 8, 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. § 192.476(d) (Item 1) ─ Respondent’s alleged failure to maintain records demonstrating compliance with § 192.476(d) regarding internal corrosion control in the design and construction of transmission lines; and 49 C.F.R. § 192.491(a) (Item 3) ─ Respondent’s alleged failure to maintain records or maps showing the location of anodes used to provide cathodic protection to an isolated section of its pipeline; and 49 C.F.R. § 192.731(c) (Item 4) ─ Respondent’s alleged failure to inspect and test each remote control shutdown device at intervals not exceeding 15 months, but at least once each calendar year; and 49 C.F.R. § 192.605(a) (Items 5 and 6) ─ Respondent’s alleged failure to follow its manual of written procedures for conducting operations and maintenance activities;10 49 C.F.R. § 192.709(b) (Item 8) ─ Respondent’s alleged failure to maintain records associated with the replacement of a safety valve for at least five years; and 49 C.F.R. § 192.719(a) (Item 9) ─ Respondent’s alleged failure to test replacement pipe used to repair a segment of transmission line, to the pressure required for a new line installed in the same location. EGT presented information in its Response showing that it had taken certain actions to address the cited items. If OPS finds a violation of any of these items in a subsequent inspection, Respondent may be subject to future enforcement action. Under 49 C.F.R. § 190.215, Respondent has a right to submit a Petition for Reconsideration of this Final Order. The petition must be 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 10 In its Response to Item 6, EGT noted that it had identified and corrected this violation prior to the OPS inspection, and requested that PHMSA take such efforts into account as a mitigating factor to reduce a proposed civil penalty or proposed compliance order requirement. The NOPV did not propose a civil penalty or compliance order for this alleged violation, so no mitigation or revision is needed. See Response at 2-3.#

420131018_Final Order_01292015_text.pdf, page 10CPF No: 4-2013-1018 Page 9 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#

420131018_Closure Letter_04252016_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED April 25, 2016 Mr. Paul Brewer Senior VP Operations and EH&S Enable Gas Transmission, LLC One Leadership Square 211 N Robinson Ave., Suite 150 Oklahoma City, OK 7310 CPF 4-2013-1018 Dear Mr. Brewer: From February through March 2013, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to Enable Gas Transmission, LLC a Final Order in the above- referenced case. This Order included a Compliance Order and Civil Penalty assessment. Based on our review of the documentation you provided and confirmation of payment of the civil penalty, it has been determined that you have complied with the terms of this Order. Accordingly, this case is now closed and no further action is contemplated with respect to the matters involved in this case. Thank you for your cooperation in this matter. Sincerely, R. M. Seeley Director, SW Region Pipeline and Hazardous Materials Safety Administration#

420131018_NOPV PCP PCO_11052013_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED November 5, 2013 Mr. Pete Kirsch Sr. VP - Pipeline Operations and Engineering Enable Gas Transmission, LLC 1111 Louisiana Street Houston, TX 77002 CPF 4-2013-1018 Dear Mr. Kirsch: On multiple dates in February and March, 2013, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49 United States Code inspected portions of Centerpoint Energy Gas Transmission Co (CEGT) pipeline system located in Arkansas, Louisiana, and Oklahoma. PHMSA understands that CEGT is now known as Enable Gas Transmission, LLC. As a result of the inspections, it appears that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violations are: 1. §192.303 Compliance with specifications or standards. Each transmission line or main must be constructed in accordance with comprehensive written specifications or standards that are consistent with this part. §192.476 Internal corrosion control: Design and construction of transmission line. (d) Records. An operator must maintain records demonstrating compliance with this section. Provided the records show why incorporating design features addressing paragraph (a)(1), (a)(2), or (a)(3) of this section is impracticable or unnecessary, an#

420131018_NOPV PCP PCO_11052013_text.pdf, page 22. operator may fulfill this requirement through written procedures supported by as- built drawings or other construction records. Centerpoint Energy Gas Transmission Co. (CEGT) failed to demonstrate compliance with their procedure and did not complete Form PS8256 (9-2009) or file the form in the design and line files. CEGT Corrosion Control Program Procedure PS-06-01-205 Design and Construction of New Pipeline or Replacement Sections - to Reduce the Risk of Internal Corrosion, section 2.7 Record Keeping states, “The design for new gas transmission and/or new gas transmission pipeline segments shall be documented on Form PS8256 Design and Construction of New Pipeline or Replacement Sections - to reduce the risk of internal corrosion, including at least one selection under each of the following parts -...” It further states, “This documentation will be filed in the design file and line file…” While reviewing CEGT project AFE #11583, Line F-625, the PHMSA inspector learned that CEGT did not complete the Form PS8256 (9-2009). CEGT completed and provided this document on 2/6/2013 only after the PHMSA inspector requested a copy at the time of the inspection. §192.467 External corrosion control: Electrical isolation. (d) Inspection and electrical tests must be made to assure that electrical isolation is adequate. CEGT failed to conduct electrical tests on the foreign pipeline side at custody transfer points to assure adequate electrical isolation. According to the CEGT Corrosion Control Program, Procedure PS-03-02-232 Installation of Insulating Devices, section 2.2 Locations states, “Typical locations where electrical insulating devices may be installed include the following: … Point at which facilities change ownership, such as meter stations and well heads. …” Section 2.4 Compressor Station Piping, Insulating flanges and Solid State Decouplers (SSD): states, 2#

420131018_NOPV PCP PCO_11052013_text.pdf, page 3“… The required monitoring of cathodic protection systems and the evaluation of test data is sufficient to ensure that electrical isolation is adequate and the SSD are functioning properly… … If the potentials are more than 100 mv apart, this is generally an indication that the device is functioning properly. If the potentials are within 100mv of each other, additional evaluations are required to determine the condition of the insulation and for possible repair.” The CEGT Corrosion Control Program Procedure PS-03-02-230 Pipe-to-Soil Potential Survey, revised date 02/02/2011, section 2.5 Electrode Placement states, “… Insulating devices: (See Figure 4) - Place the electrode in a position where both the foreign-side and the pipeline side of the insulating fittings can be reached to ensure isolation. Do not move the electrode during this test. Take and document the potential readings for storage in the MMS.…” During the inspection, the PHMSA inspector noted CEGT failed to take potential readings on the foreign-side of insulating devices at the following sites during the calendar years 2010, 2011, and 2012: TP 21250 on 5/6/2010 and 5/11/2011 - STEEL SCAPE. TP 24316 on 5/6/2010, 5/11/2011, 5/15/2012 - PRAT. TP 26318 on 4/28/2010, 4/18/2011 - REGENCY. TP 27667 on 12/21/2010, 4/18/2011, 4/10/2012 - SWEPCO POWER PLANT. TP 27668 on 12/21/2010, 4/18/2011, 4/10/2012 - SWEPCO POWER PLANT. TP 27669 on 12/21/2010, 4/18/2011, 4/10/2012 - SWEPCO POWER PLANT. TP 27671 on 12/21/2010, 4/18/2011, 4/10/2012 - SWEPCO POWER PLANT. TP 27672 on 12/21/2010, 4/18/2011, 4/10/2012 - SWEPCO POWER PLANT. TP 27673 on 12/21/2010, 4/18/2011, 4/10/2012 - SWEPCO POWER PLANT. TP 4085 on 6/18/2010, 6/13/2011, 6/14/2012 - LIEBERMAN POWER PLANT. TP 8242 on 8/7/2010 - IP DOMINO. 3. §192.491 Corrosion control records. (a) Each operator shall maintain records or maps to show the location of cathodically protected piping, cathodic protection facilities, galvanic anodes, and neighboring structures bonded to the cathodic protection system. Records or maps showing a stated number of anodes, installed in a stated manner or spacing, need not show specific distances to each buried anode. CEGT did not maintain maps or records showing the anode locations or note the number of anodes and the spacing used to provide cathodic protection to an isolated section of Line 634-2. 3#

420131018_NOPV PCP PCO_11052013_text.pdf, page 44. 5. CEGT’s Line 634-2 has a section of 2 inch steel pipeline that is isolated from the impressed current cathodic protection system by a section of 2 inch plastic pipe. The isolated section of Line 634-2 is protected by galvanic anodes. CP records for 2009, 2010, 2011, and 2012 verified that the isolated section of pipeline had adequate cathodic protection. Per §192.491(a), CEGT records and/or maps should state the number of anodes installed in a stated manner or spacing. §192.731 Compressor stations: Inspection and testing of relief devices. (c) Each remote control shutdown device must be inspected and tested at intervals not exceeding 15 months, but at least once each calendar year, to determine that it functions properly. CEGT personnel failed to inspect and test at intervals not exceeding 15 months, but at least once each calendar year, the Remote Control Shutdown devices (ESD) at the Allen Compressor Station in calendar year 2010. PHMSA reviewed the ESD maintenance and testing records for Allen Compressor Station for the years 2008 through 2012 during this inspection of the Ada Team area. The 2008 and 2009 ESD maintenance was performed in December of each year. The 2010 ESD maintenance should have been completed by December 31, 2010. No maintenance was performed in the calendar year 2010 for the 9 ESD activation locations at the compressor station. The 2011 ESD maintenance was performed in January and the 2012 ESD maintenance was performed in February. §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. CEGT failed to follow their procedure and ensure that no permanent structure will be allowed on the Company’s pipeline right-of-ways that may obstruct maintenance or immediate access to the pipeline. There are two (2) permanent structures on the pipeline right-of-way placed directly over Line JM-19. CEGT Operating and Maintenance Plan Procedure No.: 244 Encroachment, section A. Permanent Structures states, “No permanent structure will be allowed on the Company’s pipeline right- of-ways that may obstruct maintenance or immediate access to the 4#

420131018_NOPV PCP PCO_11052013_text.pdf, page 56. pipeline. These structures include (but are not limited to) houses, trailer houses, mobile homes, camp houses, camping structures, patios, carports, sheds, barns, silos, chicken houses, water wells and non-skidded auxiliary buildings.” Furthermore section J. Reimbursement, 3. states, “The following form shall be completed where applicable: Form PS-7989 – Report of Encroachment on Pipeline Right of Way.” During the Wynne Team area inspection, PHMSA visited a small commercial/industrial area along Line JM-19, a 12 inch pipeline. At 334 Phillips Road 311, the pipeline traverses the parking lot in front of NORAC, one of the businesses in the area. The pipeline is approximately 15 feet to the east side of Phillips Road 311. Situated on NORAC property along each side property line (perpendicular to Phillips Rd 311) and directly over Line JM-19, there are two enclosed structures housing water metering facilities. On March 11, 2013, the PHMSA inspector checked with the CEGT Compliance Specialist for the Northern Business area to see if past patrolling records would have noted the sheds. CEGT personnel stated that the structures were in place for approximately 8 years. Patrolling records from 2004 to the present date were checked and did not note the structures over the pipeline. Also, CEGT was unable to locate completed forms 7989, Report of Encroachment on Pipeline Right of Way, for these locations. Report of Encroachment on Pipeline Right of Way forms were initiated for the two encroachments along Phillips Road 311 on March 4, 2013 following this inspection. §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. §192.745 Valve maintenance: Transmission lines. (a) Each transmission line valve that might be required during any emergency must be inspected and partially operated at intervals not exceeding 15 months, but at least once each calendar year. CEGT failed to follow their procedures and maintain valve BV82309 as required by §192.745(a). According to CEGT, this valve is an essential valve that would be necessary in an emergency situation. 5#

420131018_NOPV PCP PCO_11052013_text.pdf, page 67. CEGT Operations and Maintenance Plan Procedure No. 232, Emergency Valve Operation and Maintenance, A. Requirement, states “1. The following are designated as emergency valves: … d. Valves at branches or intracompany pipeline connections. … Each of these valves shall be partially operated at intervals not exceeding 15 months, but at least once each calendar year.” During this inspection, PHMSA noted that CEGT failed to maintain valve BV82309 (4” tie-in for Line 1-F-7) and could not provide the records indicating the valve was inspected prior to 2011. According to the documents provided, the valve was first inspected on 3/1/2011. CEGT advised the PHMSA inspector that the valve was operated numerous times since the valve was installed, but could not provide any documentation to indicate that it was inspected. §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. §192.605 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. (2) Controlling corrosion in accordance with the operations and maintenance requirements of Subpart I of this part. CEGT failed to follow their procedures and periodically evaluate gas pipelines for corrosivity through gas sampling, coupons, and liquid sampling as required where deadlegs occur in the pipeline system. The CEGT Corrosion Control Program Procedure PS-03-02-001 Corrosion Control Program, section Internal Corrosion Control states, “Factors that influence the formation of internal corrosion include the following: … Pipeline locations (especially drips, deadlegs, and sags) which are on- line segments that are not cleaned by pigging or other methods 6#

420131018_NOPV PCP PCO_11052013_text.pdf, page 78. … Because of the above factors, the Company will periodically evaluate gas pipelines for corrosivity through gas sampling, coupons, and liquid sampling as required…” During the field inspections in both the Ada Team and the Wynne Team areas, the PHMSA inspector observed regulation/metering facilities that were defined as ‘U’ shaped and ‘L’ shaped. The facilities are used as Residential Extension (RE) or Town Border (TB) facilities. These facilities serve several customers as an RE station to a small community/town as a TB station. In the Ada Team area, the Bowlegs TB station, a ‘U’ shaped facility was observed. In the Wynne Team area the following facilities were observed: RE 559 (MS 180700) ‘U’ shaped; Palestine TB station ‘U’ shaped; Arby Moro TB station ‘U” shaped; and RE 597 Extension ‘L’ shaped. In the design of these facilities there are 2 deadlegs in the ‘U’ shaped facility and one deadleg in the ‘L’ shaped facility. The deadlegs are of the same pipe size as the regulation/meter/relief valve runs and serve as supports. The supports provide stability to the facility. The deadlegs are gassed and pressurized. CEGT was asked whether periodic evaluations for identifying the possible presence of internal corrosion and/or the accumulation of liquids were performed on these deadlegs. CEGT personnel stated that they do not transport corrosive gas and have not evaluated the noted deadlegs for corrosivity through gas sampling, coupons, and liquid sampling. §192.709 Transmission lines: Record keeping. (b) The date, location, and description of each repair made to parts of the pipeline system other than pipe must be retained for at least 5 years. However, repairs generated by patrols, surveys, inspections, or tests required by subparts L and M of this part must be retained in accordance with paragraph (c) of this section. CEGT failed to maintain records associated with the replacement of a safety valve located at the Ruston Storage facility. The CEGT Operations and Maintenance Plan Procedure No. 102 General (Ref. 192.605(a)), section B. Requirement, 2. Recordkeeping states, “… The Company will maintain the following records for transmission lines for the periods specified: … b. The date, location and description of each repair made to parts of the pipeline system other than pipe must be retained for at least 5 years. However, repairs generated by patrols, surveys, inspections, or tests required by subparts L and M of Part 192 must be retained in accordance with paragraph (c) below. …” 7#

420131018_NOPV PCP PCO_11052013_text.pdf, page 8While reviewing records, CEGT informed the PHMSA inspector that the safety valve located at station 20+30 on Well line 1-F-5 was replaced in September or October of 2012 due to a leak. When the PHMSA inspector requested the associated records for review, CEGT was unable to provide them. Also, a work order to replace this valve was not found. 9. §192.719 Transmission lines: Testing of repairs. (a) Testing of replacement pipe. If a segment of transmission line is repaired by cutting out the damaged portion of the pipe as a cylinder, the replacement pipe must be tested to the pressure required for a new line installed in the same location. This test may be made on the pipe before it is installed. CEGT failed to ensure that the section of emergency stock 12 inch pipe used to make a repair to Line NT-1 was properly tested and documented. On January 11, 2011, CEGT had an incident with a release of gas from Line NT-1 in DeBerry, TX. A pipe replacement was performed on January 12, 2011 using 26 feet of pipe from Joint 2 of the 12 inch emergency stock pipe. PHMSA conducted an incident inspection to review records and to visit the pipe yard in November 2011. The PHMSA inspector requested to review the pressure test records for Joint 2 of the 12 inch emergency stock pipe. CEGT personnel were unable to provide pressure test documentation to verify that the emergency stock pipe that was used in the repair had been properly tested. The hydrostatic test charts provided by CEGT did not have any numbers, labels, or references to link the hydrostatic test to Joint 2 of the emergency stock pipe. As a result of the PHMSA investigation, CEGT developed a process of labeling and tracking emergency pipe. The emergency pipe will be stenciled and labeled with the pipe size, grade, wall thickness, hydrostatic test date and the tested pressures, length, inventory number, and heat number. Each emergency pipe size folder will include separate sub-folders of joints and documenting the pipe usage. Once the pipe is no longer classified as an emergency pipe, it will be documented and placed in the junk pipe folder. This failure to have the proper test documentation for the replacement prompted CEGT to remove the section of 12 inch pipe installed on January 12, 2011, and replace it with 38 feet of 12 inch pipe that was properly tested and documented on June 26, 2012. 10. §192.739 Pressure limiting and regulating stations: Inspection and testing. (a) Each pressure limiting station, relief device (except rupture discs), and pressure regulating station and its equipment must be subjected at intervals not exceeding 15 months, but at least once each calendar year, to inspections and tests to determine that it is- 8#

420131018_NOPV PCP PCO_11052013_text.pdf, page 9(3) Except as provided in paragraph (b) of this section, set to control or relieve at the correct pressure consistent with the pressure limits of §192.201(a) CEGT failed to ensure that the regulation/metering station, MSM11007, is set to control or relieve at the correct pressure consistent with the pressure limits of the downstream plastic pipeline RM-5 at least once each calendar year, but at intervals not exceeding 15 months. CEGT Measurement and Control Procedure 1400: Interconnect Policy, section 1 states, “The Company will be notified at least 2 weeks before any testing is done, and has the right to witness all foreign measurement tests”. During the Buckley Team inspection, PHMSA requested maintenance records for the regulation/metering station, MSM11007. The facility regulates and meters the gas flow from Line R (steel), 300 psig MAOP, through a pair of Fisher 627 regulators into Line RM-5 (plastic). The first and second cuts are to 70 psig and 5 psig respectively. CEGT stated that the regulation/metering station, MSM11007, and downstream pipeline, RM-5, were owned by Centerpoint Energy Gas Distribution (SGO). CEGT had transferred ownership to SGO in 2006. PHMSA requested that CEGT provide the transfer documentation for review. CEGT provided a copy of the Transfer Documentation listing the referenced regulation/metering station, MSM11007, in the Bill of Sale to SGO on 6/30/2006. Upon review of this document, it was discovered that the downstream piping was not transferred. The PHMSA inspector confirmed that pipeline RM-5 is owned and operated by CEGT. CEGT was unable to provide records demonstrating that the regulation/metering station, MSM11007, was set to control or relieve at the correct pressure consistent with the pressure limits of the downstream plastic pipeline RM-5 for the calendar years 2007 – 2011. The facility, MSM11007, was inspected on 6/17/2006 and not again until 4/13/2012. The PHMSA inspector visited this site during the field portion of the audit and found proper setting and functionality. 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 $118,200 as follows: 9#

420131018_NOPV PCP PCO_11052013_text.pdf, page 10Item number PENALTY 2 $72,700 10 $45,500 Warning Items With respect to items 1, 3, 4, 5, 6, 8, 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 2, and 7 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to CEGT. 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 4-2013-1018 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#

420131018_NOPV PCP PCO_11052013_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 Company a Compliance Order incorporating the following remedial requirements to ensure the compliance of CEGT with the pipeline safety regulations: 1. In regard to Item Number 2 of the Notice pertaining to CEGT’s failure to conduct electrical tests on the foreign pipeline side at custody transfer electrical isolation points, CEGT must: • Evaluate their pipeline system and locate all custody transfer electrical isolation points, and determine whether the electrical isolation is adequate; • If electrical isolation is deficient, CEGT must take prompt action to remediate the situation; • If not otherwise noted, this item shall be completed and a report to PHMSA SW Region listing each location where the electrical isolation was inadequate within 180 days after receipt of the Final Order. 2. In regard to Item Number 7 of the Notice pertaining to the failure to follow Procedure PS-03-02-001 Internal Corrosion Control and perform periodic evaluation of deadlegs for identifying the possible presence of internal corrosion and/or the accumulation of liquids, CEGT must: • Develop a plan to locate and evaluate deadlegs within the CEGT pipeline system to identify all deadleg locations. Submit this plan to PHMSA - SW Region for review within 90 days after the receipt of the Final Order; • Document each evaluation of each deadleg location. Provide PHMSA the inspection documentation and any corrective actions taken as a result of these evaluations; • If not otherwise noted, this item shall be completed within one year after receipt of the Final Order. 3. It is requested (not mandated) that CEGT 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#