TENNESSEE GAS PIPELINE COMPANY — Notice of Probable Violation

case documentOfficial PDF420161004_Operator Post-Hearing Written Submittal_01232017.pdf#

case documentOfficial PDF420161004_Operator Pre-Hearing Written Submittal_12052016.pdf#

party submissionOfficial PDF420161004_Operator Response to Notice and Request for Hearing and Case Documents_07142016.pdf#

420161004_Final Order_05032018_text.pdf, page 1Official PDFMay 3, 2018 Mr. Thomas A. Martin President, Natural Gas Pipeline Group Kinder Morgan, Inc. 1001 Louisiana Street, Suite 1000 Houston, TX 77002 Re: CPF No. 4-2016-1004 Dear Mr. Martin: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation, assesses a reduced civil penalty of $62,900, and finds that the specified actions to be taken by Tennessee Gas Pipeline Company, a subsidiary of Kinder Morgan, Inc., to comply with the pipeline safety regulations have been completed. The penalty payment terms are set forth in the Final Order. When the civil penalty has been paid, this enforcement action will be closed. Service of the Final Order by certified mail is effective upon the date of mailing as provided under 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Alan K. Mayberry Associate Administrator for Pipeline Safety Enclosure cc: Director, Southwest Region, Office of Pipeline Safety, PHMSA Ms. Jessica Toll, Esq., Assistant General Counsel, Kinder Morgan, 370 Van Gordon Street, Lakewood, CO 80228 Ms. Catherine D. Little, Esq., Hunton & Williams, Bank of America Plaza, Suite 4100, 600 Peachtree Street, N.E., Atlanta, GA 30308 Mr. Kenneth W. Grubb, Chief Operating Officer, Tennessee Gas Pipeline Company, 1001 Louisiana Street, Houston, TX 77002-5089 CERTIFIED MAIL - RETURN RECEIPT REQUESTED#

420161004_Final Order_05032018_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 ) Tennessee Gas Pipeline Company, ) CPF No. 4-2016-1004 a subsidiary of Kinder Morgan, Inc., ) ) ) ) Respondent. ) ____________________________________) FINAL ORDER On multiple occasions between February 26, 2015 and August 20, 2015, 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 certain Tennessee Gas Pipeline Company (TGP or Respondent) pipeline assets in Texas and Louisiana. TGP operates approximately 13,900 miles of pipelines which run from the Gulf of Mexico coast in Texas and Louisiana through Arkansas, Mississippi, Alabama, Tennessee, Kentucky, Ohio, and Pennsylvania and deliver gas to various states in the Northeastern U.S. El Paso Natural Gas, owned by Kinder Morgan, Inc., is the parent company of TGP.1 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Respondent, by letter dated June 13, 2016, a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice), which also included a warning pursuant to 49 C.F.R. § 190.205. In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that TGP had committed five violations of 49 C.F.R. Part 192 and proposed assessing a civil penalty of $120,500 for two of the alleged violations. The Notice also proposed ordering Respondent to take certain measures to correct four of the alleged violations. The warning items required no further action, but warned Respondent to correct the alleged violations or face possible enforcement action. TGP responded to the Notice by letter dated July 14, 2016 (Response). TGP contested one of the allegations, disagreed with the amount of the proposed civil penalties, and requested a hearing. A hearing was subsequently held on December 14, 2016 in Houston, Texas, with an attorney from the Office of Chief Counsel, PHMSA, presiding. At the hearing, Respondent was represented by counsel. After the hearing, Respondent provided additional written materials including a post- hearing statement for the record, by letter dated January 23, 2017 (Closing). 1 Pipeline Safety Violation Report (Violation Report), (May 15, 2015) (on file with PHMSA), at 1; https://www.kindermorgan.com/business/gas pipelines/east/TGP (last accessed Dec. 8, 2017).#

420161004_Final Order_05032018_text.pdf, page 3CPF No. 4-2016-1004 Page 2 FINDINGS OF VIOLATION The Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows: Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 192.481(a), which states: § 192.481 Atmospheric corrosion control: Monitoring. (a) Each operator must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows: If the pipeline is located: Then the frequency of inspection is: Onshore At least once every 3 calendar years, but with intervals not exceeding 39 months Offshore At least once each calendar year, but with intervals not exceeding 15 months The Notice alleged that Respondent violated 49 C.F.R. § 192.481(a) by failing to inspect each pipeline or portion of pipeline exposed to the atmosphere for atmospheric corrosion at least once every 3 calendar years, but with intervals not exceeding 39 months. Specifically, the Notice alleged that TGP’s most recent documented atmospheric inspections on pipelines 100-1, 100-2, 100-3, and 100-4 crossing the Brazos River occurred in January of 2011. 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. § 192.481(a) by failing to inspect each pipeline or portion of pipeline exposed to the atmosphere for atmospheric corrosion at least once every 3 calendar years, but with intervals not exceeding 39 months. Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 192.605(a), which states: § 192.605(a) 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. (b) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following, if#

420161004_Final Order_05032018_text.pdf, page 4CPF No. 4-2016-1004 Page 3 applicable, to provide safety during maintenance and operations. (1)… (6) Maintaining compressor stations, including provisions for isolating units or sections of pipe and for purging before returning to service. The Notice alleged that Respondent violated 49 C.F.R. § 192.605(a) by failing to follow its written procedures for maintaining the gas detection and alarm equipment at the Cleveland Compressor Station to ensure proper functioning. Specifically, the Notice alleged that testing of the high-level gas detection at 30 to 40% lower explosive limit (LEL) observed by the PHMSA inspector did not trigger operation of the detection system. 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. § 192.605(a) by failing to follow its written procedures for maintaining the gas detection and alarm equipment at the Cleveland Compressor Station to ensure proper functioning. Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 192.613, which states: § 192.613 Continuing surveillance. (a) Each operator shall have a procedure for continuing surveillance of its facilities to determine and take appropriate action concerning changes in class location, failures, leakage history, corrosion, substantial changes in cathodic protection requirements, and other unusual operating and maintenance conditions. (b) If a segment of pipeline is determined to be in unsatisfactory condition but no immediate hazard exists, the operator shall initiate a program to recondition or phase out the segment involved, or, if the segment cannot be reconditioned or phased out, reduce the maximum allowable operating pressure in accordance with §192.619 (a) and (b). The Notice alleged that Respondent violated 49 C.F.R. § 192.613 by failing to initiate a program to recondition or phase out certain pipeline segments determined to be in unsatisfactory condition. Specifically, the Notice alleged that TGP failed to take timely corrective action to recondition 11 unsatisfactory items identified in Pipeline Bridge Examination Reports dated January 25 and 27, 2011. 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. § 192.613 by failing to initiate a program to recondition or phase out certain pipeline segments determined to be in unsatisfactory condition. Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 192.805(c), which states: § 192.805 Qualification program. Each operator shall have and follow a written qualification program. The program shall include provisions to: (a) … (c) Allow individuals that are not qualified pursuant to this subpart to perform a covered task if directed and observed by an individual that is qualified;#

420161004_Final Order_05032018_text.pdf, page 5CPF No. 4-2016-1004 Page 4 The Notice alleged that Respondent violated 49 C.F.R. § 192.805(c) by failing to follow its task specific span of control plan and thereby allowing an individual who was not qualified to perform a covered task to perform that task while not directed and observed by an individual that was qualified. Specifically, the Notice alleged that on numerous shifts during the September 2014 to March 2015 period, TGP had three consoles staffed by controllers, only one of which was qualified exceeding the one-to-one span of control ratio. 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. § 192.805(c) by failing to follow its task specific span of control plan and thereby allowing an individual who was not qualified to perform a covered task to perform that task while not directed and observed by an individual that was qualified. Item 9: The Notice alleged that Respondent violated 49 C.F.R. § 192.937(b), which states: § 192.937 What is a continual process of evaluation and assessment to maintain a pipeline's integrity? (a) … (b) Evaluation. An operator must conduct a periodic evaluation as frequently as needed to assure the integrity of each covered segment. The periodic evaluation must be based on a data integration and risk assessment of the entire pipeline as specified in §192.917. For plastic transmission pipelines, the periodic evaluation is based on the threat analysis specified in 192.917(d). For all other transmission pipelines, the evaluation must consider the past and present integrity assessment results, data integration and risk assessment information (§192.917), and decisions about remediation (§192.933) and additional preventive and mitigative actions (§192.935). An operator must use the results from this evaluation to identify the threats specific to each covered segment and the risk represented by these threats. The Notice alleged that Respondent violated 49 C.F.R. § 192.937(b) by failing to conduct periodic evaluations as frequently as needed to assure the integrity of each covered segment based on present data integration and risk assessments. Specifically, the Notice alleged that TGP did not conduct a periodic evaluation or analysis to determine if there was any need for additional preventive and mitigative measures such as automatic or remote shutoff valves following the identification of new high consequence areas (HCAs) along its pipelines that occurred after 2007. In its Response and at the hearing, TGP contested the allegation, arguing that it complied with the requirement to conduct a periodic evaluation or analysis to determine if there was any need for additional preventive and mitigative measures. TGP acknowledged that additional HCA segments had been newly identified along its pipelines after 2007, but cited § 192.935(c) in arguing that an evaluation and analysis of the need for remote controlled valves (RCVs) and automatic shut off valves (ASVs) was a separate “one time” determination and there was no requirement to update that determination.2 TGP cited the existence of two industry studies and 2 Closing at 3.#

420161004_Final Order_05032018_text.pdf, page 6CPF No. 4-2016-1004 Page 5 questioned whether RCVs and ASVs could ever be effective for any pipeline segment.3 TGP also produced a 2014 chart indicating, among other things, which of its segments did and did not have RCVs and/or ASVs and contended that this chart evidenced an annual review that it believed satisfied the § 192.937(b) periodic evaluation requirement.4 Analysis The gas pipeline integrity management regulations establish a risk management framework in which pipeline operators are required to conduct initial or baseline risk analyses on pipeline segments that could affect HCAs in the event of a release, and to periodically evaluate the HCA pipeline segments to maintain their integrity. One element of integrity management is determining the need for preventative and mitigative measures to ensure that the potential risks that are present can be appropriately mitigated.5 TGP cited § 192.935(c) in arguing that an evaluation and analysis of the need for RCVs and ASVs was a separate one time determination and there was no requirement to update that determination. The issue to be decided is whether this argument can overcome the actual code language of § 192.937(b). While § 192.935 and ASME/ANSI B31.8S referenced within are relevant to the type of analysis used for identifying preventive and mitigative measures, § 192.937(b) is controlling on the issue of whether it is a one time or periodic requirement. This regulation states, in relevant part, “An operator must conduct a periodic evaluation as frequently as needed…”6 Thus, the relevant language expressly makes this a periodic requirement, not a one-time requirement. In addition, § 192.937(b) references the entirety of § 192.935 with respect to preventative and mitigative measures, not just subsection (c) on RCVs and ASVs. Under subsection (a), preventive and mitigative measures also include, “…installing computerized monitoring and leak detection systems, replacing pipe segments with pipe of heavier wall thickness, providing additional training to personnel on response procedures, conducting drills with local emergency responders and implementing additional inspection and maintenance programs.”7 TGP correctly points out that the integrity management rules reflect the premise that each operator’s system is different.8 Different pipelines do have different attributes and run through different geographic areas. However, this is precisely why operators are obligated to conduct a risk evaluation, including considering the need for preventive and mitigative measures, on a segment-by-segment basis for every HCA segment. The fact that newly designated covered 3 Id. 4 Pre-Hearing Submittal, Exhibit 4. 5 49 C.F.R. Part 192, Subpart O. 6 49 C.F.R. 192.937(b). 7 49 C.F.R. § 192.935(a). While the need for RCVs and ASVs is part of the required periodic evaluation of the need for preventative and mitigative measures, the periodic evaluation required by § 192.937(b) is broader than RCVs and ASVs and the entire preventive and mitigative evaluation applies to newly designated covered segments. 8 Closing at 2.#

420161004_Final Order_05032018_text.pdf, page 7CPF No. 4-2016-1004 Page 6 segments will need such evaluations under the integrity management rules, a point not in dispute, is simply incompatible with the one-time approach advocated by TGP in this proceeding. Thus, all covered segments must have an individualized and full evaluation of the need for preventative and mitigative measures, including pipe segments that are newly classified as HCA segments. The regulations do not create an exception under which RCVs and ASVs need not be part of the evaluation when updating and extending it to newly covered segments. As TGP correctly noted, however, studies by Kiefner & Associates and Oak Ridge National Laboratory do cast doubt on the effectiveness of RCVs and ASVs in mitigating the consequences of a typical gas pipeline rupture.9 It may well be the case that an operator in Respondent’s position is likely to determine that, like the original HCA segments, the installation of RCVs and/or ASVs would not provide additional protection in the event of a release on the newly identified HCA segments. This does not, however, negate the code requirement that the operator undertake the periodic evaluation for its newly identified and uniquely situated covered pipeline segments. As for the 2014 chart indicating which segments did and did not have RCVs and/or ASVs, an annual review or update of this chart is not the same thing as conducting an actual risk analysis that included evaluating the need for preventive and mitigative measures on the newly designated covered segments like the analysis conducted in 2007 for the initial set of covered segments. Finally, TGP argued that in alleging this violation, OPS is articulating a “new interpretation” of § 192.937(b) that TGP believes is at odds with the Administrative Procedures Act and fair notice principles.10 TGP’s argument on this point, however, is unpersuasive. Including consideration of RCVs and/or ASVs as part of a broader periodic evaluation of the need for preventative and mitigative measures is not an “interpretation” or the creation of a new requirement. It comes from the direct language of § 192.937(b) of the code which, as noted above, unambiguously brings in § 192.935 on preventative and mitigative measures in its entirety and does so as a periodic requirement, not a one-time requirement. I would emphasize that the determination in this case means only that a broader evaluation of the need for any preventative and mitigative measures, including but not limited to RCVs and/or ASVs, is an integral part of the periodic evaluation requirement of § 192.937(b). It does not presuppose the outcome of such evaluation. In particular, this determination is not intended to drive TGP or any other operator to install RCVs and/or ASVs where they would not provide additional protection to a HCA in the event of a release. Accordingly, after considering all of the evidence and the legal issues presented, I find that Respondent violated 49 C.F.R. § 192.937(b) by failing to conduct periodic evaluations as frequently as needed to assure the integrity of each covered segment following the identification of new HCAs along its pipelines that occurred after 2007. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. 9 Closing at 3. 10 Closing at 4.#

420161004_Final Order_05032018_text.pdf, page 8CPF No. 4-2016-1004 Page 7 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.11 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 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 $120,500 for the violations cited in Items 1 and 7 above. Item 1: The Notice proposed a civil penalty of $37,000 for Respondent’s violation of 49 C.F.R. § 192.481(a). As discussed above, I found that TGP failed to inspect each pipeline or portion of pipeline exposed to the atmosphere for atmospheric corrosion at least once every 3 calendar years, but with intervals not exceeding 39 months. In its Response and at the hearing, Respondent did not contest the violation, but disagreed with the amount of the proposed civil penalty and questioned whether it was supported by the penalty consideration factors in the Pipeline Safety Act and § 190.225 regulations. PHMSA’s method of determining the proposed civil penalty for an alleged violation involves the use of a worksheet that assigns point value from a given range of points for each statutory penalty assessment factor. The points assignment is based on factual input from the Violation Report. The OPS regional office provided both of these documents to Respondent prior to the hearing. PHMSA is bound by the proposed civil penalty amount in the Notice in the sense that the final penalty I assess cannot be higher than the proposed amount, although it can be reduced if the operator provides information or arguments showing that a lower gradation of one of the factors such as gravity or culpability is appropriate. With respect to the nature and circumstances of TGP’s violation of § 192.481(a), performing atmospheric corrosion inspections is a basic code requirement and the non-compliance was discovered by the OPS inspector. With respect to the gravity of the offense, performing timely atmospheric corrosion inspections is a key part of safety. If surface corrosion begins to occur on the exposed steel pipe, appropriate remediation and recoating must be completed promptly to avoid further deterioration and greater threats to pipe integrity. With respect to culpability, there were no circumstances beyond Respondent’s control (such as flooding) that prevented it from complying with the regulation and action was not taken to achieve compliance until after the violation was discovered by OPS. I further find that the record supports the points assigned for prior offenses and good faith. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $37,000 for violation of 49 C.F.R. § 192.481(a). 11 These amounts are adjusted annually for inflation. See, e.g., Pipeline Safety: Inflation Adjustment of Maximum Civil Penalties, 82 Fed. Reg. 19325 (April 27, 2017).#

420161004_Final Order_05032018_text.pdf, page 9CPF No. 4-2016-1004 Page 8 Item 7: The Notice proposed a civil penalty of $83,500 for Respondent’s violation of 49 C.F.R. § 192.805(c). As discussed above, I found that Respondent failed to follow its task specific span of control plan and thereby allowing an individual who was not qualified to perform a covered task to perform that task while not directed and observed by an individual that was qualified. In its Response and at the hearing, Respondent did not contest the violation, but disagreed with the amount of the proposed civil penalty and questioned whether it was supported by the penalty consideration factors in the Pipeline Safety Act and § 190.225 regulations. With respect to the nature and circumstances of TGP’s violation of § 192.805(c), ensuring that the performance of covered tasks, particularly pipeline control functions, is properly directed and observed by a qualified individual is a basic code requirement and the non-compliance was discovered by the OPS inspector. With respect to the gravity of the offense, OPS assigned a mid-level point value on the basis that pipeline safety was compromised and a high consequence area was involved. In its response and at the hearing, TGP explained that pipeline safety was minimally affected because the configuration of its consoles allowed all three controllers to monitor the entire pipeline—meaning that the one qualified controller was monitoring the entire pipeline.12 Respondent further explained that while its one-to-one control ratio was exceeded, three controllers was more than typical for the system type. Respondent was persuasive that pipeline safety was minimally affected and I find that a corresponding reduction under the gravity factor is warranted. With respect to culpability, there were no circumstances beyond Respondent’s control that prevented it from adhering to its span of control plan, the offense was ongoing for a period of approximately seven months, and action was not taken to achieve compliance until after the violation was discovered by OPS. I further find that the record supports the points assigned for prior offenses and good faith. With respect to other matters as justice may require, TGP explained that its span of control procedures exceeded the regulatory requirements. TGP pointed out that the worksheet provided for a penalty reduction in circumstances where the non-compliance was against the requirements of the procedure that exceeded the regulation but that this reduction had not been applied.13 Respondent is correct. Therefore, in addition to the reduction in gravity, I find that a reduction for other matters as justice may require is warranted. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a reduced civil penalty of $25,900 for violation of 49 C.F.R. § 192.805(c). 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 $62,900. 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, 6500 S MacArthur Blvd, Oklahoma City, Oklahoma 79169. The Financial Operations Division telephone number is (405) 954-8845. 12 Closing at 7. 13 Closing at 8.#

420161004_Final Order_05032018_text.pdf, page 10CPF No. 4-2016-1004 Page 9 Failure to pay the $62,900 civil penalty will result in accrual of interest at the current annual rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to those same authorities, a late penalty charge of six percent (6%) per annum will be charged if payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty may result in referral of the matter to the Attorney General for appropriate action in a district court of the United States. COMPLIANCE ORDER The Notice proposed a compliance order with respect to Items 1, 3, 4, and 9 in the Notice for violations of 49 C.F.R. §§ 192.481(a), 192.605(a), 192.613, and 192.937(b), 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. The Director indicates that Respondent has taken the following actions specified in the proposed compliance order: 1. With respect to the violation of § 192.481(a) (Item 1), Respondent completed atmospheric corrosion inspections for pipelines 100-1, 100-2, 100-3, and 100-4 in November 2015 and subsequently completed remediating the identified areas. 2. With respect to the violation of § 192.605(a) (Item 3), Respondent completed inspections of the gas detection and alarm system for the Cleveland Compressor Station in September 2015 and ensured proper functioning. 3. With respect to the violation of § 192.613 (Item 4), Respondent completed a program to recondition the 11 unsatisfactory items identified on the specified segments. 4. With respect to the violation of § 192.937(b) (Item 9), Respondent completed an evaluation in November 2016 to analyze the need for any additional preventative and mitigative measures such as automatic or remote shutoff valves following the identification of new HCAs along its pipelines. Accordingly, I find that compliance has been achieved with respect to these violations. Therefore, the compliance terms proposed in the Notice are not included in this Order. WARNING ITEMS With respect to Items 2, 5, 6, and 8, 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. § 192.605(a) (Item 2) ─ Respondent’s alleged failure to follow section 3.1 of its Management of Change procedures for documenting a pressure reduction taken in connection with a pipeline repair;#

420161004_Final Order_05032018_text.pdf, page 11CPF No. 4-2016-1004 Page 10 49 C.F.R. § 192.705(b) (Item 5) ─ Respondent’s alleged failure to conduct transmission line patrolling within the required interval at the Highway 77 crossing; 49 C.F.R. § 192.739(a) (Item 6) ─ Respondent’s alleged failure to inspect the pressure relief device for Unit No. 6 at the Robstown Station prior to placing it back in service in January 2014; and 49 C.F.R. § 192.805(b) (Item 8) ─ Respondent’s alleged failure to ensure through evaluation that an employee was qualified to perform a covered task: the annual relief valve inspection on a segment of pipeline 100-3 in September 2014. TGP 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. § 190.243, Respondent may submit a petition for reconsideration of this Final Order to the 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, no later than 20 days after receipt of service of this Final Order by Respondent. Should Respondent elect to submit a petition, it must contain a statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.243. The filing of a petition automatically stays the payment of any civil penalty assessed. The terms and conditions of this Final Order are effective upon service in accordance with 49 C.F.R. § 190.5. May 3, 2018 ___________________________________ __________________________ Alan K. Mayberry Date Issued Associate Administrator for Pipeline Safety#

420161004_NOPV PCP PCO_06132016_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED June 13, 2016 Mr. Gary Buchler Vice President, Operations and Engineering Tennessee Gas Pipeline Company 1001 Louisiana Street Houston, TX 77002-5089 CPF 4-2016-1004 Dear Mr. Buchler: Between February 26, 2015 and August 20, 2015, 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 your Tennessee Gas Pipeline system (TGPL/KM) records and facilities located in Texas and Louisiana. As a result of the inspection, it appears that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violation(s) are: 1. §192.481 Atmospheric corrosion control: Monitoring (a) Each operator must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows: If the pipeline is located: Then the frequency of inspection is: Onshore At least once every 3 calendar years, but with intervals not exceeding 39 months#

420161004_NOPV PCP PCO_06132016_text.pdf, page 2TGPL/KM did not inspect portions of pipeline exposed to the atmosphere for evidence of atmospheric corrosion at least once every 3 calendar years, but with intervals not exceeding 39 months. During the inspection TGPL/KM was asked to present the documentation of their Atmospheric Inspections. In the specific instance related to pipelines 100-1, 100-2, 100-3 and 100-4 located over the Brazos River, TGP/KM provided PHMSA with two reports dated 1/25/2011 and 1/27/2011 both created by Acuren. No additional documentation was provided. From this information PHMSA concludes that these pipeline segment’s atmospheric corrosion inspections exceeded the regulatory interval. 2. §192.605 Procedural manual for operations, maintenance, and emergencies Each operator shall include the following in its operating and maintenance plan: (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. TGPL/KM failed to follow their O&M 155: Management of Change, Revised 2013-09-01, Section 3.1 during the repair operations. §192.713(b) requires operating pressure must be at a safe level during repair operations. KM's Procedure O&M 155: Management of Change, Revised 2013-09-01, Section 3.1: When Management of Change is Needed, states, "All employees may propose changes. This procedure must be followed for all changes that are beyond or outside normal condition limits or that modify the existing IMP to ensure that changes are adequately reviewed. Examples of changes that may need to be reviewed are:  Reduction of the MOP of a pipeline due to Pipeline Integrity Assessment results..." TGPL/KM performed an In-Line inspection on their pipeline 407A-100 between 407A-103 to 407A- 103A on 4/11/2012. One of the non-immediate anomalies was repaired on 8/22/2014 with a replacement sleeve. When the PHMSA inspector requested Management of Change request for the reduction of the MOP of a pipeline, TGPL/KM was unable to provide it. TGPL/KM also failed to provide documentation on the pipeline operating pressure for the day of the repair. 2#

420161004_NOPV PCP PCO_06132016_text.pdf, page 33. §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. (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. (6) Maintaining compressor stations, including provisions for isolating units or sections of pipe and for purging before returning to service. TGPL/KM failed to follow their procedure and maintain the gas detection and alarm equipment at the Cleveland Compressor Station to function properly as required by §192.736(c). Kinder Morgan Procedure O&M 550: Testing Gas and Fire Detection Systems, section 3.1.2 (Low- Level Detection in Compressor Buildings) states, “Set detectors at a low-level set point of no more than 25% LEL (1.25% methane by volume). Low-level gas detection shall activate and alarm and a callout. The fire and gas detection system shall remain energized….” Kinder Morgan Procedure O&M 550: Testing Gas and Fire Detection Systems, section 3.1.3 (High- Level Detection in Compressor Buildings) states, “Set detectors at a high-level set point of 30 to 40% LEL (1.5% to 2% methane by volume). High-level gas detection shall trigger a compressor building blowdown and activate an alarm and a callout. The fire and gas detection system shall remain energized….” On July 30, 2015, the PHMSA inspector witnessed the inspection test of gas detectors, 45-HAT-2 & 45-HAT-1 at the Cleveland Compressor Station # 25 building “C”. During the test, the gas detectors were activated by applying a known concentration of gas in air to the respective sensor. At 20% LEL, the alarm was activated as per the O&M 550, Section 3.1.2. However, the TGPL/KM employee was unable to demonstrate to the PHMSA inspector that the test at high level gas detection of 30 to 40% LEL was operational. The test was repeated three times and it was observed that it was not operational. 3#

420161004_NOPV PCP PCO_06132016_text.pdf, page 44. § 192.613 continuing surveillance. (a) Each operator shall have a procedure for continuing surveillance of its facilities to determine and take appropriate action concerning changes in class location, failures, leakage history, corrosion, substantial changes in cathodic protection requirements, and other unusual operating and maintenance conditions. (b) If a segment of pipeline is determined to be in unsatisfactory condition but no immediate hazard exists, the operator shall initiate a program to recondition or phase out the segment involved, or, if the segment cannot be reconditioned or phased out, reduce the maximum allowable operating pressure in accordance with § 192.619 (a) and (b). TGPL/KM did not initiate a program to recondition or phase out the pipeline segment with other unusual operating and maintenance conditions found during the Brazos River Span Inspection on the TGPL/KM’s pipelines. KM O&M 218, Section 3.4: Pipeline in Unsatisfactory Condition states, “When a pipeline is determined to be in an unsatisfactory condition by inspection or record review, but no immediate hazard exists, action must be taken to recondition or phase out the segment, or reduce the maximum allowable operating pressure in conformance with Company procedures”. TGPL/KM provided the Pipeline Bridge Examination Reports dated January 25 and 27, 2011 which describe the crossing of natural gas pipelines 100-1, 100-2, 100-3 and 100-4 (cable supported and H shaped towers) located at 3 miles north east of Wallis, Texas. While reviewing these reports performed by the pipeline bridge inspection contractor, ACUREN, the PHMSA inspector noted that there are seven items to be corrected within the next year and additional four items to be corrected within the next two years. As of August 31, 2015, TGPL/KM failed to create work orders or take corrective actions to recondition the pipeline segments within the prescribed timeframe. 5. § 192.705 Transmission lines: Patrolling. (a) Each operator shall have a patrol program to observe surface conditions on and adjacent to the transmission line right-of-way for indications of leaks, construction activity, and other factors affecting safety and operation. (b) The frequency of patrols is determined by the size of the line, the operating pressures, the class location, terrain, weather, and other relevant factors, but intervals between patrols may not be longer than prescribed in the following table: 4#

420161004_NOPV PCP PCO_06132016_text.pdf, page 5Maximum interval between patrols Class location of line At highway and railroad crossings At all other places 1, 2 7 1/2 months; but at least twice each calendar year 15 months; but at least once each calendar year. 3 4 1/2 months; but at least four times each calendar year 7 1/2 months; but at least twice each calendar year. 4 4 1/2 months; but at least four times each calendar year 4 1/2 months; but at least four times each calendar year. During the review of the TGPL/KM patrolling Class I & II @ Railroad/Highway Crossing District 9 records, the PHMSA inspectors found that during the calendar year 2013, TGPL/KM exceeded the required patrolling interval on one occasion at the Highway 77 crossing. This crossing was patrolled for leaks on 12/19/2013 and it was not patrolled for leaks again until 9/17/2014. 6. § 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. TGPL/KM failed to inspect the relief device which is required to prevent an actual overpressure situation for Unit # 6 at the Robstown Station to determine that it met the requirement of § 192.739 (a) -(1), (2), (3) and (4) prior to placing it back in service in January 2014. During the inspection, TGPL/KM provided records documenting the inspections. The records showed the inspections as having occurred in September 2012 and September 2014, but no inspections were documented in the calendar year of 2013 for the Unit # 6 relief valve. Further inquiry revealed that Unit # 6 relief valve was locked out/tagged out (LOTO) in October 2013 due to broken pistons. It was placed back in-service in January 2014. However, no documentation was provided indicating this relief valve was tested in January 2014. 5#

420161004_NOPV PCP PCO_06132016_text.pdf, page 67. §192.805 Qualification program. Each operator shall have and follow a written qualification program. The program shall include provisions to: (c) Allow individuals that are not qualified pursuant to this subpart to perform a covered task if directed and observed by an individual that is qualified; TGPL/KM allowed individuals that are not qualified pursuant to this subpart to perform a covered task even though they were not directed and observed by a qualified individual. TGPL/KM did not follow the task specific span of control ratio for a qualified individual to direct and observe a non-qualified employee. The Kinder Morgan OQ Program section 1 Scope, second paragraph states, “…KM’s OQ Program is designed to ensure that all individuals working on KM’s DOT- regulated pipeline facilities are OQ-qualified to perform specific covered tasks, to document that qualification and to reduce the probability and consequences of incidents and accidents…” Also, KM OQ Program, section 4 Use of Non-OQ Qualified Workers states, “...The Span of Control (the number of Non-OQ qualified persons a single OQ qualified person can effectively observe to meet the intent of this Section) is listed in Appendix A: Table of Gas Covered Tasks and Appendix B: Hazardous Liquids List of Covered Tasks. The OQ qualified individual can reduce the task span of control depending upon work conditions and complexity of the task." The PHMSA inspector reviewed Appendix A: Table of Gas Covered Tasks (revised 7/30/2015) and learned covered task 27.01.01: Gas Control has span of control of a one to one. TGPL/KM has three Consoles at the primary control center located in Houston. While reviewing records associated with the Controllers’ qualifications related to the three Consoles, the PHMSA inspector observed that of the three controllers, two were not qualified during multiple shifts. This situation existed beginning September 1, 2014 until March 2015. Having two non-qualified controllers on shift with only one qualified controller exceeds the stated span of control. 8. §192.805 Qualification program. (b) Ensure through evaluation that individuals performing covered tasks are qualified; On the following two occasions, TGPL/KM failed to ensure through evaluation that an employee was qualified to perform covered tasks. Specifically task 018.01.01: Pressure Regulating, Limiting, & Relief Device – O&M and 002PIP: Perform Pressure Test. 6#

420161004_NOPV PCP PCO_06132016_text.pdf, page 7A TGPL/KM employee conducted the annual relief valve inspection on September 16, 2014. The PHMSA inspector reviewed the qualification record for this individual, and it indicated that his qualification is not current for this covered task on that day. The individual was not qualified on covered task, 018.01.01 until January 30, 2015. At the time of the inspection, TGPL/KM failed to provide documentation indicating the employee was qualified prior to performing the covered task on September 16, 2014. If covered task 018.01.01 is performed by a non-qualified individual, TGPL/KM’s OQ Plan requires a span of control of one to one. According to the annual relief valve inspection report documentation for the calendar year 2014 provided by TGPL/KM, a qualified employee was not present to observe or direct this individual at the work site. The PHMSA inspector reviewed the records for the pressure test conducted on October 14, 2011 on pipeline 100-3, segment 32-3D to 40-3S (AFE 154482). According to the document reviewed, the test was witnessed by William Deshotel. When the PHMSA inspector requested the qualification record for performance of covered task 002PIP, TGPL/KM provided a response via email which states, “William Deshotel was the field inspector on the project. Mike Lirette is the Chief Inspector and has the OQ Qualification 002PIP. You will see that Mike Lirette signed off on the submission of all the pressure test.” The PHMSA inspector did not find Mike Lirette’s signature on the Test Specification, pressure chart and temperature chart. As a result, it appears that Mike Lirette was not at the job sire witnessing the pressure test and a qualified employee was not present to observe or direct William Deshotel at the work site. 9. §192.937 What is a continual process of evaluation and assessment to maintain a pipeline's integrity? (b) Evaluation. An operator must conduct a periodic evaluation as frequently as needed to assure the integrity of each covered segment. The periodic evaluation must be based on a data integration and risk assessment of the entire pipeline as specified in § 192.917. For plastic transmission pipelines, the periodic evaluation is based on the threat analysis specified in § 192.917(d) For all other transmission pipelines, the evaluation must consider the past and present integrity assessment results, data integration and risk assessment information (§ 192.917), and decisions about remediation (§ 192.933) and additional preventive and mitigative actions (§ 192.935). An operator must use the results from this evaluation to identify the threats specific to each covered segment and the risk represented by these threats. TGPL/KM did not conduct periodic evaluations as frequently as needed to assure the integrity of each covered segment based on present data integration and risk assessments. The periodic evaluations will help to identify and take additional preventative and mitigative (P&M) measures to reduce or eliminate the consequences of a pipeline failure in a High Consequence Area (HCA) and enhance public safety. 7#

420161004_NOPV PCP PCO_06132016_text.pdf, page 8Kinder Morgan’s Integrity Management Program, Section 11: Preventive and Mitigative Measures (Revised 2013-04-22) states: “Risk Engineering will conduct a risk analysis to determine whether an automatic shutoff valve (ASV) or remote control valve (RCV) would be an efficient means of adding protection to a covered segment in the event of a gas release. The review includes, at a minimum: swiftness of leak detection speed and pipe shutdown capabilities, the type of gas transported, operating pressure, rate of potential release, pipeline profile, potential for ignition, and nearest response personnel location. Risk Engineering, with the assistance of System Design, evaluates the installation feasibility.” The same section also states, “P&MM evaluations are completed for covered sections in response to the following events:  New information providing substantial changes to identified threats or relative risk ranking” In 2007, El Paso Pipeline Group (EPPG) utilized their risk analysis to identify additional P&M measures which included study and conclusions related to automatic shut-off valves (ASV) or remote control valves (RCV). The conclusion of this study was that the application of ASVs or RCVs will not significantly reduce the damage impact of a pipeline rupture or provide an efficient means of additional safety. El Paso Corporation, the parent company of TGPL was acquired by Kinder Morgan in May, 2012. El Paso Natural Gas (EPNG) is now owned by Kinder Morgan. Since 2007, there have been several changes to High Consequence Area (HCA) for example, HCA boundaries and addition of new HCA. At the time of the inspection, TGPL/KM failed to provide documentation that indicates TGPL/KM reanalyzed and/or reevaluated the need for RCV and ASV locations to determine if they would mitigate or enhance public safety in current HCA segment. 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 violation(s) and has recommended that you be preliminarily assessed a civil penalty of $ 120,500 as follows: 8#

420161004_NOPV PCP PCO_06132016_text.pdf, page 9Item number PENALTY 1 $ 37,000 7 $ 83,500 Warning Items With respect to items 2, 5, 6 and 8 and we have reviewed the circumstances and supporting documents involved in this case and have decided not to conduct additional enforcement action or penalty assessment proceedings at this time. We advise you to promptly correct these item(s). Failure to do so may result in additional enforcement action. Proposed Compliance Order With respect to items 1, 3, 4, and 9 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Tennessee Gas Pipeline Co (TGPL/KM). 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 4-2016-1004 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, R. M. Seeley Director, Southwest Region Pipeline and Hazardous Materials Safety Administration Enclosures: Proposed Compliance Order Response Options for Pipeline Operators in Compliance Proceedings 9#

420161004_NOPV PCP PCO_06132016_text.pdf, page 10PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Tennessee Gas Pipeline Company (TGPL/KM) a Compliance Order incorporating the following remedial requirements to ensure the compliance of TGPL/KM with the pipeline safety regulations: 1. 2. 3. 4. 5. 6. In regard to Item Number 1 of the Notice pertaining to TGPL/KM failure to inspect for evidence of atmospheric corrosion of cable-supported overhead pipelines, TGPL/KM must conduct atmospheric inspection required by §192.481 (a). If atmospheric corrosion is found during an inspection, TGPL/KM must provide protection against the corrosion required by §192.479. In regard to Item Number 3 of the Notice pertaining to TGPL/KM failing to follow procedure and maintain the gas detection and alarm equipment at Cleveland Compressor Station, TGPL/KM must follow the procedure O&M 550 and properly inspect the gas detection and alarm system to function properly as required by §192.736(c). In regard to Item Number 4 of the Notice pertaining to TGPL/KM for failing to initiate a program to recondition or phase out the segment with other unusual operating and maintenance condition found during Brazos River Span inspection, TGPL/KM must take corrective action to repair the items found during the contractor inspection report and recondition the segment. In regard to Item Number 9 of the Notice pertaining to TGPL/KM for failure to perform an adequate risk analysis to identify and take additional preventative and mitigative (P&M) measures to mitigate the consequences of a pipeline failure in a High Consequence Area (HCA) identified post 2007, TGPL/KM must perform study based on current HCA list to enhance public safety. TGPL/KM must complete item 1 and 2 within 30 days; item 3 within 90 days; item 4 within 120 days of receipt of the Final Order. It is requested (not mandated) that TGPL/KM 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. 10#