TENNESSEE GAS PIPELINE COMPANY — Notice of Probable Violation

party submissionOfficial PDF420081008_Operator_Response_and_Request_for_Hearing__06262008.pdf#

420081008_NOPV PCP PCO_05192008_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED May 19, 2008 Mr. Bill Cope Vice President Eastern Operations Tennessee Gas Pipeline Co PO Box 2563 Birmingham AL 35202 CPF 4-2008-1008 Dear Mr.Cope: During January, February, March, April, May, September and October 2006, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected your Tennessee Gas Pipeline facilities and records 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. §192.163 Compressor stations: Design and construction. (d) Fenced areas. Each fence around a compressor station must have at least two gates located so as to provide a convenient opportunity for escape to a place of safety, or have other facilities affording a similarly convenient exit from the area. Each gate located within 200 feet (61 meters) of any compressor plant building must open outward and, when occupied, must be openable from the inside without a key. It was observed during the field portion of the inspection that Alamo compressor station had a locked personnel gate approximately 50’ west of the compressor. The operator later supplied PHMSA with pictures showing that a crash bar was installed on this gate.#

420081008_NOPV PCP PCO_05192008_text.pdf, page 22. §192.179 Transmission line valves. (b) Each sectionalizing block valve on a transmission line, other than offshore segments, must comply with the following: (1) The valve and the operating device to open or close the valve must be readily accessible and protected from tampering and damage. During the inspection it was observed that, a 16" block valve [507G-106] and a 24" valve [512-1] at Hwy 332 and valve 404 were not protected against damage and were accessible to vehicular traffic. Inadequate protection from damage was also observed at some other valve locations: Lirette on line 523R100 were only enclosed by a 4 foot high fence; Fences were unlocked and downed (due to Katrina) at the Mississippi River crossing. Also during the inspection it was observed that valves were not protected from tampering. The operator installs locks on its valves to prevent tampering but these locks were not present at some locations: valves at Lirette on line 523R100; valves at LaRose, Delta Duck and Mississippi River crossing. 3. §192.317 Protection from hazards. (b) Each above ground transmission line or main, not located offshore or in inland navigable water areas, must be protected from accidental damage by vehicular traffic or other similar causes, either by being placed at a safe distance from the traffic or by installing barricades. Tennessee Gas is not protecting their pipeline from accidental damage where lateral 14D-100 takes off from line 1 and line 2. During the inspection it was observed that there was evidence of the above ground piping being struck by agricultural equipment. 4. §192.475 Internal corrosion control: General (b) Whenever any pipe is removed from a pipeline for any reason, the internal surface must be inspected for evidence of corrosion. If internal corrosion is found- (1) The adjacent pipe must be investigated to determine the extent of internal corrosion: (2) (3) Replacement must be made to the extent required by the applicable paragraphs of §192.485, §192.487, or§ 192,489; and, Steps must be taken to minimize the internal corrosion. During the inspection it was identified that two 4 inch hot taps were installed on July 14-22, 2005 on Morales line. As a part of this activity hot tap coupons were removed. Records were requested during the inspection but Tennessee Gas Pipeline did not provide a record of an internal inspection as required by 192.475 (b). 5. §192.475 Internal corrosion control: General 2#

420081008_NOPV PCP PCO_05192008_text.pdf, page 3(a) Corrosive gas may not be transported by pipeline, unless the corrosive effect of the gas on the pipeline has been investigated and steps have been taken to minimize internal corrosion. §192.477 Internal corrosion control: Monitoring. If corrosive gas is being transported, coupons or other suitable means must be used to determine the effectiveness of the steps taken to minimize internal corrosion. Each coupon or other means of monitoring internal corrosion must be checked two times each calendar year, but with interval not exceeding 7 1/2 months. As part of TGP’s overall corrosion control program, they install internal corrosion monitoring coupons to evaluate the corrosive effect of their product. TGP’s procedures specify that they install coupons for short periods of time (usually 1 month) and then the coupons are evaluated. Specific response and remediation actions are established depending on the condition of the coupon. Per §192.477 and accepted industry standards these coupons should remain in the gas stream continuously, then removed and evaluated two times per year. TGP’s conduct and written procedures do not follow the prescriptive requirement of these regulations. At TGP’s Kinder station the internal corrosion monitoring coupon [S4504] was installed on 12/14/04 and removed on 01/19/05. Records provided during the inspection and TGP’s procedures require (based on the condition of the coupon) that TGP “re-evaluate immediately”. A replacement monitoring coupon [S5340] was not installed at that location until 01/20/06. TGP did not comply with applicable requirements and could not demonstrate that it followed its own procedures. During the inspection it was observed that TGP’s coupons used to investigate internal corrosion are not always placed in effective locations. It is unlikely that installations such as can be found on platform Ship Shoal 167A (where the coupon is held off to the side of a vertical riser) will be able to provide meaningful results. The coupons should be placed such that they are near the area where corrosive constituents accumulate most (bottom of the pipe). 6. §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: Onshore Offshore Then the frequency of inspection is: At least once every 3 calendar years, but with intervals not exceeding 39 months. At least once each calendar year, but with intervals not exceeding 15 months. The Tennessee Gas Pipeline/Nautilus interchange was installed January 2002. Tennessee Gas could not provide documentation at the inspection to demonstrate that subsequent atmospheric corrosion control monitoring and inspection had occurred. 3#

420081008_NOPV PCP PCO_05192008_text.pdf, page 47. 8. §192.706 Transmission lines: Leakage surveys. Leakage surveys of a transmission line must be conducted at intervals not exceeding 15 months, but at least once each calendar year. However, in the case of a transmission line which transports gas in conformity with §192.625 without an odor or odorant, leakage surveys using leak detector equipment must be conducted- (a) In Class 3 locations, at intervals not exceeding 7 1/2 months, but at least twice each calendar year; and (b) In Class 4 locations, at intervals not exceeding 4 1/2 months, but at least four times each calendar year. Tennessee Gas class 3 leak survey on lines 409A - 101 and 409A - 102 exceeded 7.5 months in 2005. The survey was conducted on March 8, 2005 and not again until November 9, 2005. §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. According to records reviewed during the inspection, valve maintenance on "El Banito." line exceeded 15 months between January 26, 2004 to August 17, 2005. Proposed Civil Penalty Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $100,000 for each violation for each day the violation persists up to a maximum of $1,000,000 for any related series of violations. The Compliance Officer has reviewed the circumstances and supporting documentation involved in the above probable violation(s) and has recommended that you be preliminarily assessed a civil penalty of $28,000 as follows: Item number PENALTY 5 $18,000 6 $10,000 Proposed Compliance Order With respect to items 2, 3, 5 and 6 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Tennessee Gas Pipeline. Please refer to the Proposed Compliance Order, which is enclosed and made a part of this Notice. We have reviewed the circumstances and supporting documents involved in this case, pertaining to items 1, 4, 7 and 8 and have decided not to conduct additional enforcement action or penalty assessment proceedings at this time. We advise you to correct the items identified in this letter. Failure to do so will result in Tennessee Gas Pipeline being subject to additional 4#

420081008_NOPV PCP PCO_05192008_text.pdf, page 5enforcement action. 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. Be advised that all material you submit in response to this enforcement action is subject to being 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 4-2008-1008 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 5#

420081008_NOPV PCP PCO_05192008_text.pdf, page 6PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Tennessee Gas Pipeline Co (TGP) a Compliance Order incorporating the following remedial requirements to ensure the compliance of Tennessee Gas Pipeline Co with the pipeline safety regulations: 1. 2. 3. 4. 5. 6. In regard to Item Number 2 of the Notice, TGP should review their procedures related to §192.179. TGP should survey their valve locations and install adequate protection from tampering and damage. In regard to Item Number 3 of the Notice, TGP should review their procedures related to §192.317. TGP should take the necessary steps to ensure that their facilities are protected from accidental damage. In regard to item 5 of the Notice, TGP should review their procedures related to use and evaluation of internal corrosion coupons and make necessary changes to be in compliance. In regard to Item Number 6 of the Notice, TGP should review their procedures related to §192.481. TGP shall conduct the appropriate inspection and perform any required remediation. The operator should complete these items within 60 days after receipt of a Final Order. Submit documentation to R. M. Seeley, Director, Southwest Region, Pipeline and Hazardous Materials Safety Administration. Tennessee Gas shall maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to R. M. Seeley, Director, Southwest Region, Pipeline and Hazardous Materials Safety Administration. Costs shall be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses, and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. 6#

420081008_Final Order_10282013_text.pdf, page 1Official PDFOCTOBER 28, 2013 Mr. Norman G. Holmes President Tennessee Gas Pipeline Company, LLC 1001 Louisiana Street Houston, Texas 77002 Re: CPF No. 4-2008-1008 Dear Mr. Holmes: Enclosed please find the Final Order issued in the above-referenced case. It partially withdraws one allegation of violation, makes findings of violation, assesses a civil penalty of $19,000, and specifies actions that need to be taken by Tennessee Gas Pipeline Company, LLC, to comply with the pipeline safety regulations. This is also to acknowledge receipt of the $10,000 payment Tennessee Gas made by wire transfer dated June 30, 2008. When the remaining $9,000 penalty amount is paid, and the terms of the compliance order have been completed, as determined by the Director, Southwest Region, this enforcement action will be closed. Service of the Final Order by certified mail is deemed effective upon the date of mailing, or as otherwise provided under 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Jeffrey D. Wiese Associate Administrator for Pipeline Safety Enclosure cc: Mr. Rod Seeley, Director, Southwest Region, OPS David M. Waterson, Jr., Esq., Counsel for Tennessee Gas Pipeline Company, LLC, 1001 Louisiana Street, Houston, TX 77002 CERTIFIED MAIL – RETURN RECEIPT REQUESTED#

420081008_Final Order_10282013_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, LLC, ) ) ) ) Respondent. ) ___________________________________ ) CPF No. 4-2008-1008 FINAL ORDER Between January and October 2006, pursuant to 49 U.S.C. § 60117, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the facilities and records of Tennessee Gas Pipeline Company, LLC (TGP or Respondent), in Texas and Louisiana.1 TGP operates the Tennessee Gas Pipeline, which consists of approximately 14,000 miles of pipeline extending from locations on the Gulf of Mexico to Canada. 2 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Respondent, by letter dated May 19, 2008, a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that TGP had committed three violations of 49 C.F.R. Part 192, assessing a civil penalty of $28,000 for the alleged violations, and ordering Respondent to take certain measures to correct the alleged violations. The Notice also proposed finding that Respondent had committed certain other probable violations of 49 C.F.R. Part 192 and warning TGP to take appropriate corrective action or be subject to future enforcement action. TGP responded to the Notice by letter dated June 26, 2008 (Response), and contested the allegations contained in Items 4 and 5. The company paid the proposed civil penalty of $10,000 for Item 6, as provided in 49 C.F.R. § 190.227. As for the proposed compliance order, the company provided information concerning the corrective actions it had taken and planned to take with respect to Items 2 and 3, but objected to the proposed compliance terms for Items 5 and 6. Although TGP did not specifically request a hearing, the Southwest Region recommended that a hearing be held. A hearing was subsequently held on November 13, 2008, in Houston, Texas, with an attorney from the Office of Chief Counsel, PHMSA, presiding. At the hearing, 1 Tennessee Gas Pipeline Company, LLC, is a wholly-owned subsidiary of El Paso Corporation, which owns and operates approximately 42,000 miles of interstate natural gas pipelines in the United States. See http://www.elpaso.com/pipelines (last accessed November 6, 2011). 2 SEC Form 10-K, Tennessee Gas Pipeline Company, March 1, 2010.#

420081008_Final Order_10282013_text.pdf, page 32 Respondent was represented by counsel. After the hearing, TGP provided additional written materials and a post-hearing statement for the record, by letter dated December 9, 2008 (Closing). FINDINGS OF VIOLATION Uncontested Items In its Response and at the hearing, TGP did not contest the allegations in the Notice that it violated 49 C.F.R. Part 192, as follows: Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 192.179(b)(1), which states: § 192.179 Transmission line valves. (a) . . . . (b) Each sectionalizing block valve on a transmission line, other than offshore segments, must comply with the following: (1) The valve and the operating device to open or close the valve must be readily accessible and protected from tampering and damage. The Notice alleged that Respondent violated 49 C.F.R. § 192.179(b)(1) by failing to protect several block valves from tampering and damage. Specifically, the Notice alleged that several valves were either accessible to vehicular traffic, not adequately protected by fences, or left unlocked. Respondent did not contest these allegations of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 192.179(b)(1) by failing to protect several block valves from tampering and damage. Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 192.317(b), which states: § 192.317 Protection from hazards. (a) . . . . (b) Each aboveground transmission line or main, not located offshore or in inland navigable water areas, must be protected from accidental damage by vehicular traffic or other similar causes, either by being placed at a safe distance from the traffic or by installing barricades. The Notice alleged that Respondent violated 49 C.F.R. § 192.317(b) by failing to protect an aboveground transmission line from accidental damage by vehicular damage or other similar causes. Specifically, the Notice alleged that there was evidence that a section of an aboveground transmission line had been struck by agricultural equipment. 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. § 192.317(b) by failing to protect an aboveground transmission line from accidental damage by vehicular traffic or other similar causes.#

420081008_Final Order_10282013_text.pdf, page 43 Item 6: 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 a portion of pipeline exposed to the atmosphere for evidence of atmospheric corrosion at least once every three calendar years, but with intervals not exceeding 39 months. Specifically, the Notice alleged that TGP could not provide documentation that a pipeline interchange installed in January 2002 had ever been inspected for atmospheric corrosion. 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 a portion of pipeline for atmospheric corrosion within the required intervals. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. Contested Item The Notice alleged that Respondent violated 49 C.F.R. Part 192, as follows: Item 5: The Notice alleged that Respondent violated 49 C.F.R. §§ 192.475(a) and 192.477, which state: § 192.475 Internal corrosion control: General. (a) Corrosive gas may not be transported by pipeline, unless the corrosive effect of the gas on the pipeline has been investigated and steps have been taken to minimize internal corrosion. § 192.477 Internal corrosion control: Monitoring. If corrosive gas is being transported, coupons or other suitable means must be used to determine the effectiveness of the steps taken to minimize internal corrosion. Each coupon or other means of monitoring internal corrosion must be checked two times each calendar year, but with intervals not exceeding 7½ months.#

420081008_Final Order_10282013_text.pdf, page 54 The Notice alleged that Respondent violated 49 C.F.R. §§ 192.475(a) and 192.477 by failing to conduct its internal corrosion control monitoring program in a manner that effectively determined that any internal corrosion was being minimized. Specifically, the Notice alleged that TGP’s use of corrosion coupons in its internal corrosion control monitoring program was not carried out in a manner that effectively monitored for corrosivity and that TGP did not always place its corrosion coupons in locations where they would be effective. In particular, the Notice cited the placement of Ship Shoal Coupon 167A as ineffective due to its location off to the side of a vertical riser, as opposed to nearer the bottom of the pipe where any corrosive constituents would be likely to accumulate. The Notice also alleged that TGP installed corrosion coupons for short, discontinuous periods of time which did not meet the requirements of § 192.477 that coupons be maintained in the gas stream and then removed and evaluated two times per year. In particular, the Notice cited Coupon S4504 as being removed on January 19, 2005, but not replaced until Coupon S5340 was installed at that location on January 20, 2006. At the hearing and in its Response and Closing, TGP contested these allegations. TGP argued broadly that it transported tariff quality gas, not corrosive gas, and that as a result it could not be found in violation for the manner or effectiveness of its use of corrosion coupons since corrosion control monitoring is only required for pipelines that transport corrosive gas.3 TGP also argued that Ship Shoal Coupon 167A was placed in a location that is effective for determining the corrosivity of a gas/liquid hydrocarbon (two phase) stream.4 TGP also contended that its use of electron microscope (EM) coupons in a discontinuous manner was permissible under the regulations because this type of coupon was intended to be used differently from standard weight-loss coupons and that it considered them to be corrosion-detection coupons rather than corrosion-monitoring coupons. 5 With respect to Coupon S4504, TGP explained that Hurricanes Katrina and Rita impacted the timing of the installation of the next coupon.6 Federal gas pipeline safety regulations7 were promulgated under the Natural Gas Pipeline Safety Act of 19688 to provide adequate protection against risks to life and property posed by pipeline transportation and pipeline facilities.9 The corrosion control regulations,10 which include §§ 192.475 and 192.477, were issued to ensure that gas pipeline operators identify and address 3 Closing at 2-6. 4 Response at 9. 5 Id. at 5-6. Weight-loss coupons, as the name implies, indicate corrosion rates by being weighed upon removal. The difference between the original weight of the coupon and the weight when removed is recorded and compared with the series of coupons in the same pipe location for multiple time periods of similar length. This allows an operator to determine whether corrosion begins accelerating. 6 Id. at 7. 7 49 C.F.R. Part 192. 8 Pub. L. No. 90-481, 82 Stat. 720 (Aug. 12, 1968). 9 49 U.S.C. § 60102(a)(1) (2012). 10 49 C.F.R. pt. 192, subpt. I.#

420081008_Final Order_10282013_text.pdf, page 65 internal corrosion risks before they become pipeline failures. The regulations require pipeline operators to monitor their pipelines for internal corrosion when the potential for corrosive effects exists, and to take measures when necessary to ensure any such effects are minimized. Notably, the regulations do not prescribe corrosion coupons as the only permissible means of conducting corrosion control monitoring. If coupons are used, however, the regulations expressly require that they be checked “two times each calendar year, but with intervals not exceeding 7½ months.”11 With respect to TGP’s argument that it transported tariff quality gas, not corrosive gas, and that as a result it was not in violation of the cited regulations regardless of the manner or effectiveness of its use of coupons, it should first be noted that previous PHMSA enforcement cases have described the factors relevant to whether an operator should consider gas in a given pipeline to be corrosive for purposes of making decisions about the need for corrosion control monitoring. In the Consumers Energy case, I found that the presence of substances found in the natural gas transported by U.S. pipelines such as carbon dioxide, hydrogen sulfide, and certain microbes and bacteria, in the presence of water and condensates, can corrode the internal surface of a pipeline. 12 In addition, certain pipe areas, such as low spots and locations where the gas stream does not have sufficient velocity and/or turbulence to carry away condensates, may also create environments conducive to internal corrosion and must be monitored.13 At the hearing and in its Closing, TGP argued that “tariff quality gas is dry gas under normal operating conditions and is not corrosive.”14 TGP expressed the view that even when water or liquids are introduced, “the potential for corrosion is minimal if the condition is temporary.”15 TGP further explained that liquid water can be removed through maintenance pigging and liquid removal devices such as pipeline drips, or can be reabsorbed into the gas stream. TGP also explained that its Subject Matter Experts (SMEs) take into account various factors such as gas quality monitoring, liquid and soil sampling, on-site testing for water, and other factors in determining whether to “develop a monitoring program…”.16 To the extent that TGP argued for the proposition that tariff quality gas transported by pipeline need not be monitored for any potential corrosivity, I do not agree. As TGP itself acknowledged, tariff quality gas, which can already have a moisture vapor content of seven pounds of water vapor per million cubic feet of natural gas, can experience “short term upsets” during which “liquid water or water vapor that could condense is introduced into the pipeline...”.17 The fact 11 49 C.F.R. § 192.477. 12 See In the Matter of Consumers Energy, Final Order, CPF No. 3-1999-1001. (Mar. 5, 2009) (available at www.phmsa.dot.gov/pipeline/enforcement). See also In the Matter of BP Pipelines (North America), Inc., Final Order, CPF No. 4-2007-5003. (July 19, 2010). 13 Id. at 2. 14 Closing at 2. 15 Id. 16 Id. at 6. 17 Id. at 3.#

420081008_Final Order_10282013_text.pdf, page 76 that liquid water can be removed through maintenance pigging or liquid removal devices such as pipeline drips only underscores the fact that liquids susceptible to interacting with other constituents in the gas can be present at times, even if not continuously or at all locations. More to the point, this case does not present a scenario where an operator conducted a technical study at the time its pipeline system was designed and began operating that provided a sound basis for concluding that a corrosion coupon monitoring program was completely unnecessary. Here, the pipeline designers or TGP itself decided long before the OPS inspection that a corrosion coupon monitoring program was needed and installed corrosion-monitoring coupons on this pipeline system. 18 Given that TGP (or its predecessors) originally made this judgment about the need for a coupon monitoring program, OPS is acting within its regulatory authority in conducting inspections to determine whether this coupon monitoring program is being conducted effectively. With respect to the allegation in the Notice that TGP’s coupons were not always placed in effective locations, OPS provided only one alleged example of a problematic location in the Notice, that being Ship Shoal 167A. As described in detail at the hearing, TGP placed this coupon in a sample chamber along a short section of vertical pipe that was downstream from liquid re-injection and upstream from chemical inhibitor injection.19 TGP contended that this location was “the most effective location on the platform to measure the corrosion potential of the commingled liquid prior to chemical injection and that these conditions exist[ed] over only 4½ feet of piping which is all in the vertical position. . .”20 . OPS maintained that the coupon needed to be located nearer the bottom of the pipe where any corrosive constituents would be likely to accumulate. As TGP correctly noted at the hearing, the corrosion control regulations do not require the “most effective” coupon placement. Both parties did point out that TGP’s own written operating and maintenance procedures require that “As a general rule, coupons should be placed in…the most severe location with respect to corrosion.”21 However, while it could have done so, OPS did not cite the regulation that requires an operator to follow its own written operating and maintenance procedures and did not present evidence that TGP’s alleged coupon misplacement was significant or systemic. Moreover, OPS was able to cite only a single example of alleged inadequate coupon placement, which I find to be insufficient to support the general allegation that TGP’s coupons were not always placed in effective locations. Accordingly, having considered all of the information and arguments presented on this issue, I find that OPS did not prove the allegation that TGP’s coupons were not placed in effective locations. The extent to which this finding warrants a reduction in the penalty amount proposed in the Notice will be addressed in the Assessment of Penalty section below. With respect to the allegation that TGP’s corrosion monitoring coupons were not maintained in the gas stream continuously and checked twice per calendar year, TGP argued at the hearing and in its Response and Closing that its use of EM coupons in a discontinuous manner was 18 It appears that corrosion inhibitor was also determined necessary to be injected into the pipeline. 19 Hearing Presentation at 67-71. 20 Id. 21 Response at 8.#

420081008_Final Order_10282013_text.pdf, page 87 permissible under the regulations because this type of coupon was intended to be used differently from standard weight-loss coupons and that it considered them to be corrosion-detection coupons rather than corrosion-monitoring coupons.22 TGP stated that its electron microscope (EM) coupons were typically exposed for a 30 to 45 day period and that additional exposure would actually render the readings unusable.23 TGP contended that EM coupons offer some advantages over traditional weight-loss coupons in terms of precision of measurement.24 OPS noted that section 5.2 of National Association of Corrosion Engineers (NACE) RP0775-2005 industry standard states that “Continuous monitoring is essential so that changes in the corrosion rate in a system may be detected as soon as possible after they occur.” 25 This ensures that corrosivity is detected promptly, as opposed to being detected by infrequent EM coupon monitoring only after it has potentially reached harmful levels. TGP is correct that the regulations do not expressly state that corrosion coupons are required to remain in the gas stream continuously. The regulations do, however, state that if coupons are used they must be checked twice per calendar year and the regulations must be applied in a manner that gives a logical effect to this twice yearly requirement. At the hearing, TGP acknowledged that the period between coupon installations ranged from 4 months to nearly 21 months.26 Pipeline gas characteristics, however, are dynamic. Over time the flow within a pipeline may transition between corrosive and non-corrosive. If the requirement to determine corrosivity were not continuous, the use of a coupon in a manner that provides only a “snapshot” observation of a few weeks with year-long gaps in between would fail to capture temporary increases in corrosivity during the inter-observation period and may not capture cumulative corrosive rates and trends over time. Similarly, while the company’s use of additional monitoring technology27 may have provided additional information on corrosivity, it too was non-continuous. With respect to Coupon S4504, TGP acknowledged that it was removed on January 19, 2005, and not replaced at that location until January 20, 2006. At the hearing, TGP stated that on May 19, 2005, its SME evaluated the first coupon, on September 20, 2005 the company scheduled a replacement coupon for installation the next month, and sometime later the “re- evaluate immediately” marking inadvertently and erroneously overwrote the SME’s conflicting recommendation.28 Therefore, in this instance TGP did not execute its EM coupon monitoring in 22 Id. at 5-6. 23 Hearing Presentation at 49. 24 Id. 25 This NACE standard is not incorporated by reference into Part 192 and is therefore not enforceable. It does, however, shed some light on the industry consensus about the technical basis underlying the need for continuous monitoring. 26 Hearing Presentation at 39-43. 27 Id. at 41. 28 Id. at 59-61.#

420081008_Final Order_10282013_text.pdf, page 98 accordance with its own schedule in place at the time. Having considered TGP’s arguments, I am not persuaded that any advantages of using EM coupons on a short-term basis obviate the need for continuous monitoring if coupons are being used in a corrosion control monitoring program.29 It should be noted, however, that nothing in this decision forbids the use of EM coupons. For example, EM coupons could be used continuously (of course they would have to be replaced more frequently than weight-loss coupons) or a one month EM coupon could be used in-between a series of weight-loss coupons as long as there are no periods in which no coupon is installed at a location where the operator has previously determined a coupon is needed. Accordingly, after considering all the evidence and the legal issues presented, I find that Respondent violated 49 C.F.R. §§ 192.475(a) and 192.477 by failing to use the corrosion coupons in its internal corrosion control monitoring program in a manner that effectively monitored for potential corrosive effects insofar as Coupon S4504 was removed on January 19, 2005, and not replaced until January 20, 2006, and as a result Respondent did not meet the requirement that if coupons are used they must be checked two times per year. To the extent that Respondent’s explanation about the impact of Hurricanes Katrina and Rita on the timing of the coupon replacement may constitute mitigating circumstances, it will be discussed in the Assessment of Penalty section below. ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed $100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any related series of violations. In determining the amount of a civil penalty under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature, circumstances, and gravity of the violation, including adverse impact on the environment; the degree of Respondent’s culpability; the history of Respondent’s prior offenses; Respondent’s ability to pay the penalty and any effect that the penalty may have on its ability to continue doing business; and the good faith of Respondent in attempting to comply with the pipeline safety regulations. In addition, I may consider the economic benefit gained from the violation without any reduction because of subsequent damages, and such other matters as justice may require. The Notice proposed a total civil penalty of $28,000 for the violations cited above. Item 5: The Notice proposed a civil penalty of $18,000 for Respondent’s violation of 49 C.F.R. §§ 192.475(a) and 192.477, for failing to conduct its internal corrosion control monitoring program in a manner that effectively determined that any internal corrosion was being minimized. As set forth above, I found that with respect to the allegation that Respondent failed to place its corrosion coupons in locations where they would be effective, OPS did not meet its burden of proving this aspect of the allegations and I have withdrawn it. Accordingly, I find that a proportional reduction in the penalty amount proposed in the Notice is warranted for this aspect of the allegation. 29 TGP’s semantic distinction between “corrosion detection” and “corrosion monitoring” does not alter this conclusion.#

420081008_Final Order_10282013_text.pdf, page 109 This brings us to Respondent’s violation of 49 C.F.R. §§ 192.475(a) and 192.477 insofar as Coupon S4504 was removed on January 19, 2005, and not replaced until January 20, 2006. In its Response, TGP explained that a conflict between the immediate replacement recommendation generated by its software program and a subsequent determination made by its SME contributed to the failure to replace the coupon immediately.30 TGP also noted that Hurricanes Katrina and Rita struck the Gulf of Mexico respectively on August 29, 2005, and September 24, 2005, and that this contributed to coupon S5340 not being installed until January 20, 2006.31 With respect to the nature, circumstances, and gravity of this violation, when a corrosion control monitoring program is put in place, failure to carry it out in an effective manner can have a significant impact on safety. Respondent is culpable for this violation despite the subsequent improvements in its internal software system; such subsequent actions do not constitute a good- faith effort to comply prior to the violation. I recognize that Hurricanes Katrina and Rita occurred in 2005, but both occurred over seven months after the previous coupon was removed and does not diminish Respondent’s culpability at the time of the violation. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a reduced civil penalty of $9,000 for violation of 49 C.F.R. §§ 192.475(a) and 192.477. Item 6: The Notice proposed a civil penalty of $10,000 for Respondent’s violation of 49 C.F.R. § 192.481(a), for failing to inspect a pipeline interchange within the required interval. TGP neither contested the allegation nor presented any evidence justifying a reduction in the proposed penalty. Respondent attributed its failure to conduct inspections to a “breakdown in the process of transferring project completion information into tracking tools used for scheduling periodic inspections and maintenance tasks.”32 Regular inspections for atmospheric corrosion are crucial to ensure pipeline safety because corrosion can lead to failures that result in harm to life, property and the environment. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $10,000 for violation of 49 C.F.R. § 192.481(a). As noted above, Respondent paid this civil penalty by wire transfer dated June 30, 2008. 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 $19,000, of which amount $10,000 has already been paid. Accordingly, I find that Respondent owes a remaining balance of $9,000. COMPLIANCE ORDER The Notice proposed a compliance order with respect to Items 2, 3, 5, and 6 in the Notice for violations of 49 C.F.R. §§ 192.179(b)(1), 192.317(b), 192.475(a), 192.477, and 192.481(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 30 Response at 7. 31 Id. 32 Id. at 11.#

420081008_Final Order_10282013_text.pdf, page 1110 standards established under chapter 601. The Director has indicated that Respondent has taken the following action to address one of the cited violations: With respect to the violation of § 192.317(b) (Item 3), TGP has installed barricades to protect the section of pipeline discussed in Item 3 and provided documentation to this effect. Accordingly, the compliance terms proposed for Item 3 are not included in this Order. As for the remaining compliance terms, 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 § 192.179(b)(1) (Item 2), Respondent must review its procedures related to § 192.179. Respondent must survey its valve locations and install adequate protection from tampering and damage. Respondent must complete these requirements within 60 days. 2. With respect to the violation of 49 C.F.R. §§ 192.475(a) and 192.477 (Item 5), Respondent must review its procedures related to the use and evaluation of internal corrosion coupons and make necessary changes to achieve compliance. 3. With respect to the violation of § 192.481(a) (Item 6), Respondent must report to the Director the steps it has taken to review its procedures related to this regulation. Respondent must also explain the corrections and enhancements it has made to these procedures. Respondent must provide documentation confirming that the required inspections have been performed and describing the findings of these inspections. Respondent must complete these requirements within 60 days. 4. Respondent is requested to maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit that total to the Director. Costs shall be reported in two categories: (1) total cost associated with preparation and revision of plans, procedures, studies, and analyses; and (2) total cost associated with replacements, additions, and other changes to pipeline infrastructure. The Director may grant an extension of time to comply with any of the required items upon a written request timely submitted by the Respondent and demonstrating good cause for an extension. Failure to comply with this Order may result in the administrative assessment of civil penalties not to exceed $100,000 for each violation for each day the violation continues or in referral to the Attorney General for appropriate relief in a district court of the United States.#

420081008_Final Order_10282013_text.pdf, page 1211 WARNING ITEMS With respect to Items 1, 4, 7, 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. § 192.163(d) (Item 1) ─ Respondent’s alleged failure to ensure that each gate located within 200 feet of any compressor plant building be “openable” from the inside without a key, when occupied; 49 C.F.R. § 192.475(b) (Item 4) ─ Respondent’s alleged failure to perform an internal inspection after “hot tap coupons” were removed from a pipeline; 49 C.F.R. § 192.706 (Item 7) ─ Respondent’s alleged failure to conduct leakage surveys of two transmission lines at intervals not exceeding 7½ months; and 49 C.F.R. § 192.745(a) (Item 8) ─ Respondent’s alleged failure to inspect and partially operate transmission line valves on a specific pipeline at intervals not exceeding 15 months. TGP presented information in its Response showing that it had taken certain actions to address Items 1, 4, 7, and 8, but still contested Item 4. On this Item, TGP contended that 49 C.F.R. § 192.475(b)33 was never intended to require operators to inspect the inside surface of a hot tap coupon since a coupon does not fall within the definition of the term “pipe” in 49 C.F.R. Part 192. The company acknowledged, however, that its own procedures required an ultrasonic and visual inspection of the hot tap coupon but that such an inspection was never documented in this instance. Having considered such information, I find, pursuant to 49 C.F.R. § 190.205, that probable violations of 49 C.F.R. § 192.163(d) (Notice Item 1), 49 C.F.R. § 192.475(b) (Notice Item 4), 49 C.F.R. § 192.706 (Notice Item 7), and 49 C.F.R. § 192.745(a) (Notice Item 8) have occurred, and Respondent is hereby advised to correct such conditions. In the event that OPS finds a violation of any of these provisions in a subsequent inspection, TGP 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. Should Respondent elect to do so, the petition must be sent to: Associate Administrator, Office of Pipeline Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC 20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address. PHMSA will accept petitions received no later than 20 days after receipt of 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, 33 49 C.F.R. § 192.475(b) states: “Whenever any pipe is removed from a pipeline for any reason, the internal surface must be inspected for evidence of corrosion……”#

420081008_Final Order_10282013_text.pdf, page 1312 grants a stay, all other terms and conditions of this Final Order are effective upon service in accordance with 49 C.F.R. § 190.5. ___________________________________ __________________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety#

420081008_Closure_11192014_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED November 19, 2014 Mr. Gary Buchler Vice President, Engineering/Operations Tennessee Gas Pipeline, LLC 1001 Louisiana Street Houston, Texas 77002 CPF 4-2008-1008 Dear Mr. Buchler: On October 28, 2013, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to Tennessee Gas Pipeline, LLC (TGP) a Final Order in the above-referenced case. TGP is a subsidiary of Kinder Morgan Energy Partners, LP. 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, Southwest Region Pipeline and Hazardous Materials Safety Administration#