TRANSCONTINENTAL GAS PIPE LINE COMPANY — Notice of Probable Violation

party submissionOfficial PDF520091003_operator request for hearing and request for time extension_05192009.pdf#

520091003_closure letter_11172010_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED November 17, 2010 Mr. Phillip D. Wright President Williams Gas Pipeline Company, LLC 2800 Post Oak Boulevard Houston, TX 77056 CPF 5-2009-1003 Dear Mr. Wright: On October 14, 2010, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to Williams Gas Pipeline Company, LLC a Final Order in the above-referenced case. This Order included a Compliance Order and Civil Penalty assessment. Based on our review of the documentation you provided and confirmation of payment of the civil penalty paid on October 20, 2010, 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, Chris Hoidal Director, Western Region Pipeline and Hazardous Materials Safety Administration cc: PHP-60 Compliance Registry PHP-500 R. Reineke#

520091003_Final Order_10142010_text.pdf, page 1Official PDFOCT 14 2010 Mr. Phillip D. Wright President Williams Gas Pipeline Company, LLC 2800 Post Oak Boulevard Houston, TX 77056 Re: CPF No. 5-2009-1003 Dear Mr. Wright: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation and assesses a civil penalty of $192,600. It further finds that Williams Gas Pipeline Company, LLC, has completed certain actions specified in the Notice to comply with the pipeline safety regulations. The penalty payment terms are set forth in the Final Order. When the civil penalty has been paid and the remaining terms of the compliance order completed, as determined by the Director, Western Region, this enforcement action will be closed. Service of the Final Order by certified mail is deemed effective upon the date of mailing, or as otherwise provided under 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Jeffrey D. Wiese Associate Administrator for Pipeline Safety Enclosure cc: Mr. Chris Hoidal, Director, Western Region, PHMSA Ms. Marie Sotak, Manager, Pipeline Safety, Williams Gas Pipeline Company, LLC 2800 Post Oak Boulevard, Houston, TX 77056 CERTIFIED MAIL – RETURN RECEIPT REQUESTED [7009 1410 0000 2472 2841]#

520091003_Final Order_10142010_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 ) Williams Gas Pipeline Company, LLC, ) CPF No. 5-2009-1003 ) ) ) Respondent. ) ____________________________________) FINAL ORDER From June through August 2008, 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 Williams Gas Pipeline Company, LLC (Williams or Respondent), in Georgia, Idaho, New Jersey, Texas, Utah, and Washington. Respondent, a subsidiary of The Williams Companies, Inc., owns and operates over 14,000 miles of gas transmission and gathering lines across the United States, including the Northwest Pipeline, the Transcontinental (Transco) Pipeline, and the Gulfstream Pipeline. As a result of the inspection, the Director, Western Region, OPS, issued to Respondent, by letter dated April 20, 2009, 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 Williams had committed various violations of 49 C.F.R. Part 192 and proposed assessing a civil penalty of $192,600 for the alleged violations. The Notice also proposed ordering Respondent to take certain measures to correct the alleged violations. Williams responded to the Notice by letter dated May 19, 2009 (Response). Williams contested several of the allegations and contended that certain penalties should be eliminated. Respondent also requested a hearing. In accordance with 49 C.F.R. § 190.211, a hearing was held on October 6, 2009, in Lakewood, Colorado, with an attorney from the Office of Chief Counsel, PHMSA, presiding. After the hearing, Respondent provided additional written material for the record, by letter dated November 2, 2009 (Closing). FINDINGS OF VIOLATION The Notice alleged that Respondent committed violations of 49 C.F.R. Part 192, as follows:#

520091003_Final Order_10142010_text.pdf, page 32 Uncontested Items Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 192.323(d), which states: § 192.323 Casing. Each casing used on a transmission line or main under a railroad or highway must comply with the following: (a) . . . . (d) If vents are installed on a casing, the vents must be protected from the weather to prevent water from entering the casing. The Notice alleged that Respondent violated 49 C.F.R. § 192.323(d) by failing to protect casing vents from the weather to prevent water from entering the casing. Specifically, the Notice alleged that certain plastic casings in the Spokane North District were broken, which could allow water to enter the casing. In its Response and at the hearing, Respondent did not contest this allegation of violation. Accordingly, based upon a review of the evidence, I find that Respondent violated 49 C.F.R. § 192.323(d) by failing to protect casing vents from the weather. Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 192.463(a), which states: § 192.463 External corrosion control: Cathodic protection. (a) Each cathodic protection system required by this subpart must provide a level of cathodic protection that complies with one or more of the applicable criteria contained in appendix D of this part. If none of these criteria is applicable, the cathodic protection system must provide a level of cathodic protection at least equal to that provided by compliance with one or more of these criteria. The Notice alleged that Respondent violated 49 C.F.R. § 192.463(a) by failing to have a cathodic protection system that complied with one or more of the applicable criteria at the Franklin PUD, Spokane West, and Kettle Falls meter stations and at Mile Post (MP) 9747+36. Specifically, the Notice alleged that, for two consecutive years, the company’s cathodic protection system at those four specific locations did not have a negative voltage of at least 850 mV. In its Response and at the hearing, 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. § 192.463(a) by failing to have a cathodic protection system at those four locations that complied with one or more of the applicable criteria contained in appendix D of Part 192. Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 192.463(a), as quoted above, by failing to have a cathodic protection system that complied with one or more of the applicable criteria at eleven locations in the Redmond District. Specifically, the Notice alleged that, for two consecutive years, the company’s cathodic protection system at those locations did not have a negative voltage of at least 850 mV. In its Response and at the hearing, 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. § 192.463(a) by failing to have a cathodic protection system at those 11 locations that complied with one or more of the applicable criteria contained in appendix D of Part 192.#

520091003_Final Order_10142010_text.pdf, page 43 Item 9: The Notice alleged that Respondent violated 49 C.F.R. § 192.706(a), which states: § 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 7½ months, but at least twice each calendar year . . . . The Notice alleged that Respondent violated 49 C.F.R. § 192.706(a) by failing to conduct leakage surveys of an odorless gas transmission line in a Class 3 location at the required frequency. Specifically, the Notice alleged that Williams failed to conduct four required surveys of such a line in Texas between 2006 and 2008. In its Response and at the hearing, 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. § 192.706(a) by failing to conduct leakage surveys of a transmission line in a Class 3 location at the required frequency. Pipeline Repair Items Items 5, 6, and 7 in the Notice alleged that Respondent committed violations of 49 C.F.R. § 192.605(a) when it performed certain pipeline repairs. The regulation states: § 192.605 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least once each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 192.605(a) by failing to follow its written procedures for using composite sleeves for pipeline repairs. Specifically, the Notice alleged that Williams violated its operations and maintenance (O&M) procedures by using a Clock Spring sleeve to repair a crack on the Transco Pipeline at MP 1828.139–1828.143 in New Jersey.1 Paragraph 5.1.4 of Procedure 70.14.01.15 in the company’s operations manual provides, “CAUTION: Do not use composite sleeves to repair leaking defects or cracking.” Paragraph 6.1.7.1 of the same procedure provides, “Do not use composite sleeves to repair leaks, cracks, or weld imperfections.” The Notice alleged that Williams identified a crack on the 1 Respondent referred to this repair as “Dig # 6.”#

520091003_Final Order_10142010_text.pdf, page 54 Transco Pipeline while repairing two gouges, and that the company used a Clock Spring composite sleeve to repair the crack, in violation of its procedures.2 At the hearing and in its Closing, Respondent indicated that “Williams is in agreement that it violated written O&M procedures by applying a composite [sleeve] repair to a crack like indication caused from third party damage to the pipeline.”3 The company also provided information that it has since removed the Clock Spring repair and replaced it with new piping. 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 procedures by repairing a crack at MP 1828.139– 1828.143 with a Clock Spring composite sleeve. Item 6: The Notice similarly alleged that Respondent violated 49 C.F.R. § 192.605(a) by using a Clock Spring sleeve to repair a weld imperfection on the Transco Pipeline at MP 1829.836. noted above, Respondent’s Procedure 70.14.01.15 prohibits the use of composite sleeves to repair weld imperfections. 4 As At the hearing and in its Closing, Williams contested this allegation of violation on the grounds that the defect it repaired using a Clock Spring did not constitute a crack or “weld imperfection” as that term is defined in API Standard 1104. 5 Williams explained that it had originally excavated the pipe at this location to examine and repair corrosion defects, and while in the ditch, a technician identified what appeared to be possible incomplete fusion or a crack. In its Closing, Respondent stated that it now believes the defect was most likely incomplete fusion, not cracking, and that the defect was so small that it did not meet the company’s repair policy specified in O&M Policy 90.12.00.03.6 That policy, Williams contended, stated that the company would repair or remove any in-service weld that is found to be unacceptable according to API Standard 1104, which is a consensus standard that specifies incomplete fusion shall be defect was not a “crack or weld imperfection,” and the company did not violate its procedures by installing a composite sleeve. The company also provided information that it has since removed the Clock Spring repair and replaced it with new piping. considered a defect if its length exceeds one inch.7 For this reason, Respondent contended, the The evidence in the record includes section 6.1.7.1 of Respondent’s Procedure 70.14.01.15, which, as noted above, states: “Do not use composite sleeve to repair leaks, cracks, or weld imperfections.”8 The evidence also includes Form WGP-0092, “WGP Pipeline Inspection and Repair Report - 2006-TR-1170,” dated February 23, 2007, which Williams used to document the 2 Clock Spring® composite sleeves, also known as wraps, are used to repair corrosion defects and mechanical damage on the pipe. The composite sleeve operates by transferring the hoop stress from the defect to the sleeve. Wraps are not typical candidates for leaking defects and cracking because they do not provide a seal for the leak and do not address the risk of a crack spreading. 3 Closing at 1. 4 Respondent referred to this repair as “Dig # 14.” 5 American Petroleum Institute (API) Standard 1104, “Welding of Pipelines and Related Facilities.” 6 Closing at 2. 7 See Section 9.3.4 of API Standard 1104. 8 Violation report at 42.#

520091003_Final Order_10142010_text.pdf, page 65 investigation and repair of the defect. 9 On the form, Williams noted the areas of general corrosion on the pipe and “also through the weld # 6890 @9:30 found a .120" wall loss with a Incomplete Fussion [sic] or crack like indication, ” noting further that “Clock springs were then installed.” On the associated Defect Report, Williams further identified the defect under “Defect Record #2,” where the company noted the type was “Weld Defect. ” With regard to whether a “Repair [was] Required,” Williams indicated “Yes.”10 The method of repair was recorded as a “Sleeve – Composite.” Also included in the record are color pictures of the defect. While Williams has contended that it believes the defect at issue was not cracking or a weld imperfection longer than one inch, there is a lack of conclusive evidence demonstrating the size of the weld imperfection or that the defect was indeed not cracking. On the other hand, Respondent’s own records indicate that the defect was cracking or a weld imperfection resulting from incomplete fusion, that it was required to be repaired, and that a composite sleeve was used to make the repair. Ultimately, however, the size of the defect or whether it met the definition of a defect in API Standard 1104 is not the determinative factor. That is because the language of Respondent’s repair procedure 70.14.01.15, section 6.1.7.1, prohibits the use of composite sleeves to repair cracks and weld imperfections, without any reference to defect size or other industry standard or company policy. Neither the applicable safety regulations nor the company’s repair procedure 70.14.01.15, section 6.1.7.1, had adopted (or referenced) API Standard 1104 or even suggested that the prohibitions relating to the use of composite sleeves are to be interpreted with reference to that standard. Furthermore, Williams had already determined the weld imperfection required repair, and thus the API Standard did not overrule the company’s decision. inconsequential that the company had a policy of repairing defects meeting the API standard, because its repair procedure was not conditioned on that standard, and Williams still determined that the weld imperfection was required to be repaired. The evidence in the record also indicates that Williams did not consult the applicable procedures when deciding to repair the defect using a composite sleeve. 11 Therefore, it is Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 192.605(a) by failing to follow its procedures when it used a composite sleeve to repair a weld imperfection at MP 1829.836. Item 7: The Notice further alleged that Respondent violated 49 C.F.R. § 192.605(a) by using a Clock Spring sleeve to repair a weld imperfection on the Transco Pipeline at MP 1827.950. noted above, Respondent’s Procedure 70.14.01.15 prohibits the use of composite sleeves to repair weld imperfections. 12 As 9 Violation report at 58. 10 Violation Report at 60. 11 See Section 9.2 of API Standard 1104, which states: “The company may therefore reject any weld that appears to meet these acceptance standards if, in its opinion, the depth of an imperfection may be detrimental to the weld.” 12 Respondent referred to this repair as “Dig # 5.”#

520091003_Final Order_10142010_text.pdf, page 76 At the hearing and in its Closing, Williams contested this allegation of violation on the same grounds as Item 6, namely, that the defect did not constitute a crack or “weld imperfection,” as that term is defined in API Standard 1104. Williams gave a similar account that the location had been excavated to repair general corrosion, but that a technician also identified possible incomplete fusion or a crack. In its Closing, Respondent stated that it believes the defect was most likely incomplete fusion that did not meet the repair policy specified in O&M Policy 90.12.00.03 or API Standard 1104. For this reason, Respondent contended that it did not violate its procedures by installing a composite sleeve. The company also provided information that it has since removed the Clock Spring repair and replaced it with new piping. The evidence in the record includes Form WGP-0092, “WGP Pipeline Inspection and Repair Report - 2006-TR-1168,” dated February 23, 2007, which Williams used to document the investigation and repair of the defect.13 On the form, Williams noted the areas of general corrosion on the pipe and that it “found a crack like indication or Incomplete Fussion [sic] on G/W #3030 and Clock Springs were installed which also covered the areas of Corrosion that were in question.” On the associated Defect Report, Williams further identified the defect under “Defect Record #1,” where it noted the defect type was “Cracking.” With regard to whether a “Sleeve – Composite.” In a follow-up email from the technician, he stated that incomplete “Repair [was] Required,” Williams indicated “Yes.”14 The method of repair was recorded as a fusion was the likely defect. Also included in the record are color pictures of the defect. As with Item 6, there is a lack of conclusive evidence demonstrating the defect was indeed not cracking or a weld imperfection longer than one inch. Respondent’s own records indicate that the defect was required to be repaired, and that it was repaired using a composite sleeve. Ultimately, as noted above, it is inconsequential that the company had a policy of repairing defects meeting the API standard, because the company’s actual repair procedure 70.14.01.15, section 6.1.7.1, prohibited the use of composite sleeves for cracks and weld imperfections without regard to the API standard, and furthermore, Williams had determined that the weld imperfection required repair. Accordingly, after considering all of the evidence and the legal issues presented, I find that Respondent violated 49 C.F.R. § 192.605(a) by failing to follow its procedures when it used a composite sleeve to repair a weld imperfection at MP 1827.950. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed $100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any related series of violations. 13 Violation report at 68. 14 Violation Report at 72.#

520091003_Final Order_10142010_text.pdf, page 87 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; the Respondent’s ability to pay the penalty and any effect that the penalty may have on its ability to continue doing business; and the good faith of Respondent in attempting to comply with the pipeline safety regulations. In addition, I may consider the economic benefit gained from the violation without any reduction because of subsequent damages, and such other matters as justice may require. The Notice proposed a total civil penalty of $192,600 for Items 5, 6, and 7 ($64,200 for each). In its Response, Williams objected to “the assessment of three separate penalties for essentially the same violation” and asked that two of the three proposed penalties be eliminated. At the hearing, Williams repeated this argument and listed the factors that, in its view, supported a conclusion that the three violations were “essentially the same”: 1) the three defects repaired using Clock Springs were identified during the same inline inspection; 2) the Clock Springs were applied to segments of the same pipeline; 3) the repairs to the segments were carried out as a result of a single decision by Williams; 4) Williams ordered the three Clock Springs at the same time; and 5) the segments were repaired at nearly the same time. At the hearing, OPS contended that the violations should not be considered the same offense, because the repairs were made in separate locations and at separate times. As a legal matter, PHMSA is not precluded from assessing separate civil penalties for multiple violations that involve the same subject matter, so long as the penalties do not violate the maximum amounts established by Congress.15 Administrative civil penalty assessments by PHMSA are governed by the following provision of 49 U.S.C. § 60122(a)(1): A person that the Secretary of Transportation decides, after written notice and an opportunity for a hearing, has violated section 60114(b), 60114(d), or 60118(a) of this title or a regulation prescribed or order issued under this chapter is liable to the United States Government for a civil penalty of not more than $100,000 for each violation. A separate violation occurs for each day the violation continues. The maximum civil penalty under this paragraph for a related series of violations is $1,000,000. As set forth previously by this agency, certain violations in a Notice of Probable Violation may be so related that they constitute a single offense for which the agency should not assess combined penalties exceeding the applicable cap. In determining whether two or more violations are so closely related, PHMSA’s decision in Colorado Interstate Gas evaluated “whether each [Notice Item] can stand alone and has its own evidentiary basis, or whether any two or more are so closely related (i.e., same evidentiary basis) that they are not separate and should be considered one violation for purposes of applying the [penalty cap].”16 15 In the Matter of Enbridge Energy Partners, L.P., Final Order, CPF No. 3-2008-5011, at 14-15 (Aug. 17, 2010) (cases are available online at http://www.phmsa.dot.gov/pipeline/enforcement). 16 In the Matter of Colorado Interstate Gas Co., Final Order, CPF 5-2008-1005, 2009 WL 5538649, at 12 (Nov. 23, 2009).#

520091003_Final Order_10142010_text.pdf, page 98 In this case, the three Clock Spring repairs using composite sleeves were applied to three different locations on the pipeline to repair distinct and separate defects. Although the violations share the same evidence of the procedure that was violated, each item is based on separate evidence specific to the defect that was repaired and the act of repairing the defect using a composite sleeve. The fact that Williams excavated the three locations based on information obtained from a single inline inspection, that Williams ordered all the Clock Springs at the same time, or that the repairs were carried out as a result of a single decision by Williams does not make these violations a single offense. Furthermore, I note that even if all three were considered one “related series of violations,” the total civil penalty proposed ($192,600) does not exceed the statutory maximum of $1,000,000. Accordingly, I find that Items 5, 6, and 7 constituted separate violations of § 192.605(a), and that they should be considered separate violations for penalty purposes. Williams is culpable for the violations, meaning the company, as the operator of the pipeline, bears the blame for its violations of the unambiguous regulation, which requires the company to follow its written procedures for maintaining the pipeline. I have considered the company’s history of prior offenses, including the Final Order issued by PHMSA on July 30, 2007, which assessed a civil penalty of over $590,000 for violations that resulted in a pipeline incident in a populated area that forced the evacuation of more than 850 schoolchildren and area residents. proposed civil penalty in this case. 17 The history of prior offenses does not warrant reducing the Since Respondent did not provide any evidence suggesting the company is unable to pay the proposed civil penalty, I find Respondent is able to pay the proposed penalty without adversely affecting its ability to continue in business. In addition, I have considered any good faith in attempting to comply, but find that Williams did not demonstrate that it had consulted the company’s procedures before deciding to repair the crack and weld imperfections using composite sleeves. Item 5: The Notice proposed a civil penalty of $64,200 for Respondent’s violation of 49 C.F.R. § 192.605(a). This violation occurred when Williams failed to follow its procedures for repairing a crack on its pipeline at MP 1828.139–1828.143. The failure to follow such repair procedures created a safety risk, because installation of composite sleeves do not normally address the propensity for a crack to spread and would not provide sufficient protection from a leak. The repair location is in a high consequence area and Class 3 location. With respect to Items 5, 6, and 7, Williams argued that the use of Clock Springs did not pose an integrity or safety threat and provided evidence suggesting that Clock Springs may be appropriate for repairing some pipeline cracks and weld imperfections. This evidence largely consisted of materials issued by the manufacturer of Clock Springs. Notwithstanding this evidence, which is not conclusive, the operator’s adherence to its written procedures is vital to ensuring pipeline safety. This is particularly true in relation to procedures governing pipeline repairs. 17 In the Matter of Williams Gas Pipeline - Transco, Final Order, CPF 1-2005-1007, 2007 WL 2475903 (Jul. 30, 2007).#

520091003_Final Order_10142010_text.pdf, page 109 Fortunately, the violations described in Items 5, 6, and 7 did not result in any incidents and the company has removed and replaced the sections of pipe containing the defects and composite sleeves. Respondent also indicated at the hearing that it operates the pipeline at less than maximum allowable operating pressure. However, pipeline cracks and weld imperfections – and improper repair of such defects – can still cause pipeline failures and natural gas releases. All three of the violations took place in high consequence areas and Class 3 locations, and a release of natural gas would likely have caused adverse impacts on nearby populations and the environment. For this reason, I find the nature, circumstances, and gravity of the violation justify the proposed civil penalty. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $64,200 for the violation of 49 C.F.R. § 192.605(a) in Item 5. Item 6: The Notice proposed a civil penalty of $64,200 for Respondent’s violation of 49 C.F.R. § 192.605(a). This violation occurred when Williams failed to follow its procedures for repairing a weld imperfection on its pipeline at MP 1829.836. Williams argued that it was not required to repair the weld imperfections that are the subject of Items 6 and 7, and that it should not be penalized for taking extra precautions. At the time the repairs were made, however, Williams had determined that the repairs were necessary, and failed to consult its procedures that specified that sleeves were not to be used for such repairs. While it may be true that the weld imperfections were relatively small in size, the fact remains that the pipeline defects were improperly repaired based on the company’s procedures. Carrying out repairs safely is a vital part of ensuring the integrity of a pipeline system, and adherence to a company’s repair procedures is just as important in the context of repairs considered relatively minor. Therefore, the fact that the company violated its procedures in the course of repairing defects that are now considered relatively minor does not alter the nature or circumstances of the violations. Based on the foregoing, the nature, circumstances, and gravity of the violations support the proposed penalties. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $64,200 for the violation of 49 C.F.R. § 192.605(a) in Item 6. Item 7: The Notice proposed a civil penalty of $64,200 for Respondent’s violation of 49 C.F.R. § 192.605(a). This violation occurred when Williams failed to follow its procedures for repairing a weld imperfection on its pipeline at MP 1827.950. For all of the reasons set forth above, I find the nature, circumstances, and gravity of the violations support the proposed penalty. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $64,200 for the violation of 49 C.F.R. § 192.605(a) in Item 7. In summary, having reviewed the record and considered the assessment criteria for each of the Items above, I assess Respondent a total civil penalty of $192,600. Payment of the civil penalty must be made within 20 days of service. Federal regulations (49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed instructions are contained in the enclosure. Questions concerning wire transfers should be#

520091003_Final Order_10142010_text.pdf, page 1110 directed to: Financial Operations Division (AMZ-341), Federal Aviation Administration, Mike Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, Oklahoma 73125. The Financial Operations Division telephone number is (405) 954-8893. Failure to pay the $192,600 civil penalty will result in accrual of interest at the current annual rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to those same authorities, a late penalty charge of six percent (6%) per annum will be charged if payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty may result in referral of the matter to the Attorney General for appropriate action in a district court of the United States. COMPLIANCE ORDER The Notice proposed a compliance order with respect to Items 1, 3, 4, 5, 6, 7, and 9 in the Notice for the above violations. 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 has indicated that Respondent has taken the following actions to address some of the cited violations: With respect to the violation of § 192.323(a) (Item 1), Respondent has replaced the broken casing vents and has inspected and remediated, as necessary, all of the installed casings in Spokane North and South districts. Respondent has also submitted documentation to this effect. With respect to the violation of § 192.463(a) (Item 3), Respondent has tested, evaluated, and, where necessary, enhanced its cathodic protection system at the subject area to comply with the Appendix D criteria, and has submitted documentation to this effect. With respect to the violations of § 192.605(a) (Items 5, 6, and 7), Williams has repaired the pipeline defects by removing the damaged segments and replacing them with new pipe, and has submitted documentation to this effect. Accordingly, I find that compliance has been achieved with respect to these violations. Therefore, the compliance terms proposed in the Notice for Items 1, 3, 5, 6, and 7 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 § 192.463(a) (Item 4), Respondent must test, evaluate, and, where necessary, enhance its cathodic protection system at the subject area to comply with the Appendix D criteria, and submit to PHMSA documentation to this effect within 180 days of receipt of this Final Order. 2. With respect to the violation of § 192.706(a) (Item 9), Respondent must conduct a leak survey of the Class 3 area between MP 328 and MP 328.5, and must submit to PHMSA the results of this survey and any mitigation plans within 90 days of receipt of this Final Order.#

520091003_Final Order_10142010_text.pdf, page 1211 3. Complete each of the above items and submit documentation of compliance to the Director, Western Region, Office of Pipeline Safety, 12300 W. Dakota Ave. #110, Lakewood, CO 80228. 4. Maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and report the total cost as follows: (a) total cost associated with preparation and revision of plans and procedures, and performance of studies and analyses; and (b) total cost associated with physical changes, if any, to the pipeline infrastructure, including replacements and additions. 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 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. WARNING ITEMS With respect to Items 2, 8, and 10, 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. § 192.463(a) (Item 2) – Respondent’s alleged failure to provide adequate cathodic protection in Districts 120 and 130 of the Atlanta Division. Specifically, the Notice alleged that Respondent’s use of “reference cell placement,” as described in its written Procedure 20.06.02.06, did not properly consider the effects of “IR drop” to ensure a valid interpretation of the criteria set forth in § 192.463(a); 49 C.F.R. § 192.605(a) (Item 8) – Respondent’s alleged failure to follow its procedures for performing root cause failure analysis; and 49 C.F.R. § 192.905(a) (Item 10) – Respondent’s alleged failure to accurately identify a Class 3 high consequence area in its pipeline system. Williams presented information in its Response showing that it had taken certain actions to address the cited items. Accordingly, having considered such information, I find, pursuant to 49 C.F.R. § 190.205, that probable violations of §§ 192.463(a) (Notice Item 2), 192.605(a) (Notice Item 8), and 192.905(a) (Notice Item 10) have occurred and Respondent is hereby advised to correct such conditions as necessary. If OPS finds a violation of any of these items in a subsequent inspection, Respondent may be subject to future enforcement action. Under 49 C.F.R. § 190.215, Respondent has a right to submit a Petition for Reconsideration of this Final Order. The petition must be sent to: Associate Administrator, Office of Pipeline Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC 20590, with a copy sent to the Office of Chief Counsel, PHMSA, at the same address. PHMSA#

520091003_Final Order_10142010_text.pdf, page 1312 will accept a petition received no later than 20 days after receipt of this Final Order by the Respondent, provided it contains a brief statement of the issue(s) and meets all other requirements of 49 C.F.R. § 190.215. The filing of a petition automatically stays the payment of any civil penalty assessed. All other terms of the order, including any required corrective action, shall remain in full force and effect unless the Associate Administrator, upon request, grants a stay. The 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#

520091003_NOPV PCP PCO_04202009_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED April 20, 2009 Ms. Marie Sotak Manager Pipeline Safety Williams Gas Pipelines 2800 Post Oak Boulevard Houston, TX 77056 CPF 5-2009-1003 Dear Ms. Sotak: From June through August 2008, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected Williams Gas Pipeline’s (WGP’s) procedures, records and pipeline facilities in the states of Georgia, Idaho, New Jersey, Texas, Utah, and Washington. As a result of the inspections, it appears that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violations are:#

520091003_NOPV PCP PCO_04202009_text.pdf, page 21. §192.323 Casing Each casing used on a transmission line or main under a railroad or highway must comply with the following: (d) If vents are installed on a casing, the vents must be protected from the weather to prevent water from entering the casing. WGP (WGP) has not adequately protected casing vents from the weather to prevent water from entering the casing. The Spokane District recently replaced some casing vents with plastic casings. Plastic casings were installed at valves 34-2 and 34-1. Field visits at valves 34-2 and 34-1 revealed that casing vents at these locations had been severed. This damage could potentially allow water to enter the casing through the severed location. 2. § 192.463 External corrosion control: Cathodic protection. (a) Each cathodic protection system required by this subpart must provide a level of cathodic protection that complies with one or more of the applicable criteria contained in appendix D of this part. If none of these criteria is applicable, the cathodic protection system must provide a level of cathodic protection at least equal to that provided by compliance with one or more of these criteria. In Districts 120 and 130 of the Atlanta Division, the cathodic protection criteria of 0.85 volt is being used exclusively to evaluate annual pipe-to-soil potential values used to determine the adequacy of cathodic protection. The method used for consideration of IR drop was reference cell placement as described in William’s procedure Methods for IR Drop Consideration (Procedure 20.06.02.06). This method is being implemented by placing the reference cell directly over the pipeline or by burying permanent reference cells near the pipeline surface, both of which are intended to reduce the distance between the reference cell and the pipeline thereby in theory reducing IR drop through the soil. It was determined that at many locations throughout Districts 120 and 130, reference cell placement is not an adequate means of taking into consideration the effects of IR drop in pipe-to- soil potential measurements. Your procedure indicates that reference cell placement has the advantage of being “easy” but the disadvantage of being “in some cases, incompatible with multiple pipelines in one right-of-way”. In Districts 120 and 130, you have four pipelines running in the same right-of-way. Some of these pipelines have coating that is in poor condition resulting in a relatively high current requirement for cathodic protection. This appears to be the type of scenario your procedure refers to as being incompatible with the reference cell placement technique of considering IR drop. 2#

520091003_NOPV PCP PCO_04202009_text.pdf, page 3Your procedure also indicates that current interruption is the “best correction” for IR drop though it “requires installation of current interrupters, inconvenient”. PHMSA acknowledges that current interruption is the best technique for considering IR drop, where this method is feasible and practical. In Districts 120 and 130 and throughout the rest of the Atlanta Division, Transco has conducted an extensive amount of current interrupted, close interval pipe-to-soil potential surveys. Current interrupted data is available and should be used for considering IR drop in Districts 120 and 130. The following are examples of why reference cell placement was found to be an inadequate method of taking into consideration the effects of IR drop: 1. Mile Post 1023.424, Line B: Annual pipe-to-soil potentials are excessively high and not representative of the true potential; -7.165 volt on 1/9/2007 and -6.713 volt on 1/24/2008. These high values are apparently the result of reference cell placement within the voltage gradient of two continuous linear type anodes. 2. Mile Post 1137.666, Line C: Annual pipe-to-soil potentials exceed -0.85 volt but IR drop free “instant off” potentials from interrupted close interval survey (CIS) data indicate the -0.85 volt criterion is not being achieved. Recent annual data lists -0.854 volt on 1/13/2007 and -0.901 volt on 1/17/2008 with the most recent CIS data of 2/6/2004 showing -0.876 “on” and -0.513 “off” at this location. The CIS data demonstrates there is well over 300 mv of IR drop error in the measurements with current applied, making the “instant off” value of -0.513 more representative of the typical true pipe-to-soil potential at this location. 3. Mile Post 1073.393: This location has buried permanent reference cells as well as traditional above ground test stations. The following data was recorded during the field inspection: Pipeline Permanent Reference Cell Above Ground Test Station A -2.99 volt -2.469 volt B -4.36 volt -1.957 volt C -3.97 volt -2.587 volt D -3.51 volt -3.690 volt The potential values measured with the buried permanent reference cells are greater than those measured at the above ground test stations on three of the four pipelines. This data tends to indicate that there is a larger IR drop component in the buried permanent reference cell measurements than in the above ground test station measurements. This data does not support the concept of reference cell placement as a means of considering IR drop. It was also noted that the cathodic protection database does not distinguish between permanent reference cell data and above ground test station data, compounding the difficulty in interpreting this data for IR drop considerations. 3#

520091003_NOPV PCP PCO_04202009_text.pdf, page 4As another example, it was discovered during an inspection in Linden, NF, that in 2007, WGP performed an External Corrosion Direct Assessment on a portion of its 10 inch diameter Harrison Lateral. As part of this assessment, WGP conducted an instant-off close-interval survey that indicated several locations that had instant-off readings below the -0.850 volt criterion. In 2005, WGP performed a similar instant-off close-interval survey that also indicated there were several locations where the instant-off readings did not meet the criterion. Even though WGP data demonstrated inadequate cathodic protection readings when IR-drop errors were eliminated, it took no action to verify the locations met one of the other acceptable NACE criteria. In addition, WGP excavated and recoated a number of locations as a part of the assessment work, yet did not verify the instant-off potential readings met criteria upon completion of remediation activities. 3. §192.463 External Corrosion Control: Cathodic Protection Each cathodic protection system required by this subpart must provide a level of cathodic protection that complies with one or more of the applicable criteria contained in Appendix D of this part. If none of these criteria is applicable, the cathodic protection system must provide a level of cathodic protection at least equal to that provided by compliance with one or more of these criteria. Annual cathodic protection monitoring records showed that Appendix D criteria was not met for two consecutive years at the Franklin PUD meter Station at Mile post 30.58 (bypass outlet and outlet flange), Spokane West meter Station 7715+34 (Riser 6-inch regulator inlet), Milepost 9747+36 (Riser 6-inch header outlet, riser 6-inch outlet valve), and the Kettle Falls Meter station 8298+88. IR free readings were as follows: Location 2007 reading 2008 reading Franklin PUD Bypass outlet Outlet flange -0.806 V -0.824 V -0.793 V -0.468 V Spokane West Meter Station Riser 6-inch inlet -0.810 V -0.846 V Milepost 9747+36 Riser 6-inch outlet Riser 6-inch Valve -0.511 V -0.625 V -0.479 V -0.555 V Kettle Falls Meter Station Blow off 2-inch north inlet Riser 6-inch filter inlet Riser 6-inch heater outlet Riser 6-inch M/S inlet valve -0.717 V -0.627 V -0.606 V -0.576 V -0.777 V -0.643 V -0.620 V -0.582 V 4#

520091003_NOPV PCP PCO_04202009_text.pdf, page 5Riser 6-inch header outlet Riser 4-inch bypass outlet -0.567 V -0.578 V -0.521 V -0.599 V 4. §192.463 External Corrosion Control: Cathodic Protection Each cathodic protection system required by this subpart must provide a level of cathodic protection that complies with one or more of the applicable criteria contained in Appendix D of this part. If none of these criteria is applicable, the cathodic protection system must provide a level of cathodic protection at least equal to that provided by compliance with one or more of these criteria. In the Redmond District, cathodic protection does not comply with the criteria contained in Appendix D of Subpart I – Requirements for Corrosion Control. Pipe to soil readings in the following locations did not meet the negative 850 millivolt criteria for two consecutive years: Grays Harbor Meter station outside the entrance gate station 2588 + 30, 205 Ave SE station 15884+81, and City of Seattle Water line station 15962+62, and the Grays Harbor Lateral from Tilley Road station 736+48 to Thornberg Lane station 1056+00. WGP did not take any other data to determine if other Appendix D criteria such as 100 millivolt shift could be met in lieu of pipe to soil readings. IR free pipe to soil readings were as follows: Location 2007 reading 2008 reading Grays Harbor meter station ST outside M/S entrance gate -0.707 V -0.675 V 205 Ave SE -0.816 V -0.720 V City of Seattle water line -0.802 V -0.806 V Tilley Road west side -0.794 V -0.682 V Case Road SW west side -0.782 V -0.682 V Kimme Road SW west side -0.748 V -0.694 V I-5 East side -0.796 V -0.780 V I-5 West side -0.756 V -0.690 V 150 ft east of north emergency man gate @ Tumwater CS -0.673 V -0.820 V Gravel Quarry west side -0.793 V -0.794 V Thornberg Lane -0.738 V -0.802 V 5. § 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 emergency5#

520091003_NOPV PCP PCO_04202009_text.pdf, page 6response. 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. WGP personnel did not follow their written repair procedures to correct a pipeline defect. In the Linden District, on February 20, 2007, WGP personnel were repairing two gouges discovered in the 26 inch diameter Mainline A that were identified from an in-line inspection. The gouges were located within MP 1828.139 and MP 1828.143. One of the gouges was successfully ground out by removing approximately 0.088" of the pipe’s wall. While grinding out the second gouge, however, WGP personnel noted that “I attempted to feather out the second gouge, after removing 20-30 mils each time I would stop and check with NDT, somewhere between .160- .180 Mills I started to chase a hairline crack, it was then that we determined to clock spring this defect.” WGO written Procedure 70.14.01.15, Pipeline Repair, in Paragraph 5.1.4 states in bold type “CAUTION: Do not use composite sleeves to repair leaking defects or cracking.” Paragraph 6.1.7.1 of the same procedure further states: “Do not use composite sleeve to repair leaks, cracks, or weld imperfections.” WGP repaired a known crack in the pipeline body with a composite sleeve in direct violation of its written procedures. 6. § 192.605 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least once each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. WGP personnel did not follow their written repair procedures to correct a pipeline defect. WGP repaired a weld imperfection in the pipeline with composite sleeve in direct violation of its written procedures. On February 23, 2007, WGP area personnel excavated the 26 inch diameter Mainline A pipeline at MP 1829.836 to examine and assess an area of corrosion reported from an in-line inspection. In addition to describing the corrosion found, personnel performing the examination noted that “also through the weld #6890 @9:30 found a .120" wall loss with a Incomplete Fusion or crack 6#

520091003_NOPV PCP PCO_04202009_text.pdf, page 7like indication which failed Dye Penetrant and Mag Particle Test, Clock springs were then installed.” 7. § 192.605 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least once each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. WGP personnel did not follow their written repair procedures to correct a pipeline defect. WGP repaired a weld imperfection in the pipeline with composite sleeve in direct violation of its written procedures. On February 23, 2007, WGP personnel also excavated the 26 inch diameter Mainline A at MP 1827.950 to examine the pipeline for another area of ILI identified corrosion. In addition to describing the corrosion found, personnel performing the examination again noted that “however found a crack like indication or Incomplete Fusion on G/W #3030 and Clock Springs were installed which also covered areas of Corrosion that were in question.” WGP written Procedure 70.14.01.15, Pipeline Repair, in Paragraph 6.1.7.1 states: “Do not use composite sleeve to repair leaks, cracks, or weld imperfections.” 8. § 192.605 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least 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. WGP failed to follow its procedures with respect to root cause failure analysis. During an inspection of the Cypress Division it was noted that WGP filed Incident Report No. 20060154, dated December 21, 2006 related to an internal corrosion incident. WGP procedure 20.11.01.06 Internal Corrosion Control: Inspection Schedule and Remedial Actions, section 10.0 Performing Remedial Actions, requires other actions to be taken within 1 year ranging from additional 7#

520091003_NOPV PCP PCO_04202009_text.pdf, page 8remedial actions to no actions required. WGP policy 10.18.00.06 and procedure 10.18.01.08 Root Cause Analysis require that a RCA be conducted for all DOT Reportable incidents and assigns responsibility for the RCA to the V.P. Operations. No such actions were taken. The V.P., Larry Hjalmarson, responded to a query during this inspection that it was an error on their part. In another example,WGP did not adequately ensure that its procedures were followed to ensure that all OQ tasks are accounted for on the projects. At the Cypress Division, it was noted that WGP provided Williams Gas Handling Plan Forms for two parts of an overall project, Anomaly Investigation/Repairs on 30” M/L “A” between Station 40 and Station 45 – Procedures #3 and #4. Neither procedure was followed with regard to identifying the person responsible, planned time and actual time of each of the events described beginning on page 3 of 6. The information was obtained later but not filled out per the procedure. Further, the Approvals stipulated on page 6 of 6 include Gas Control, but on no form reviewed indicated a Gas Control sign off on the form. The form also indicates the OQ tasks required on page 1 of 4 of the Forms Matrix but does not include Skill Block 5654, Perform Specific Gravity Test, even though the use of a Ranerax Gravitometer was required and used as part of the operation Yet another example of procedures that are out of date follows: In Procedure 70.18.01 Minimizing, Mitigating and Monitoring Stress Corrosion Cracking, section 5.1.1.2 requires that each pipeline shall be monitored for SCC. Section 5.2.1.1 requires that when pipelines are exposed, a percentage of the excavated sites will be considered for magnetic particle inspection for cracking. However, the WGP Work Plan for the Anomaly Investigation/Repairs on 30” M/L “A” between Station 40 and Station 45 conducted in the fall of 2007 did not stipulate that Procedure 70.59.01 Stress Corrosion Cracking on page 7 needed to be followed related to the project. In addition, 70.59.01 has been revised and is now 70.18.01 so the WGP Work Plan was out of date. Further, this same procedure contains Appendix A with Table 1 SCC Integrity Program, which is badly out of date and needs to be updated on a regular basis. In a final example, WGP did not follow its procedures regarding patrols. In the Cypress Division, one location identified on the “Divison ROW Stabilization Spreadsheet – Pipeline Exposures” indicated the Exposure Status as C Line as, “covered by landowner.” Williams procedure 70.10.01.12, Performing Transmission Line Patrols, section 5.0 Encroachments, requires when excavation occurs without WGP monitoring, the location will either be excavated or an aboveground survey will be performed to determine the condition of the pipeline. Williams had not followed these procedures. 9. § 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— 8#

520091003_NOPV PCP PCO_04202009_text.pdf, page 9(a) In Class 3 locations, at intervals not exceeding 71/2months, but at least twice each calendar year; There is a Class 3 area between MP 328 and 328.5 that is not designated on the Williams drawing Sheet No. DOT-T-112, dated 9/19/2006. The photo on the drawing is from 9/1/2004. Based on WGP Land Patrol Reports, in 2006, the area was surveyed as part of their required Class 3 leak surveys only once on 11/28/2006 and not during their May surveys earlier in the year. The regulation requires that the area be surveyed twice each year not to exceed 7 ½ months. In 2007, the area was never surveyed as part of their required Class 3 leak surveys. Thus far in 2008, the area was not surveyed as part of their required Class 3 leak surveys on the 5/28/2008 survey. The operator has not performed its Class 3 leak surveys according to the required frequency. 10. § 192.905 How does an operator identify a high consequence area? (a) General. To determine which segments of an operator's transmission pipeline system are covered by this subpart, an operator must identify the high consequence areas. An operator must use method (1) or (2) from the definition in §192.903 to identify a high consequence area. An operator may apply one method to its entire pipeline system, or an operator may apply one method to individual portions of the pipeline system. An operator must describe in its integrity management program which method it is applying to each portion of the operator's pipeline system. The description must include the potential impact radius when utilized to establish a high consequence area. ( See appendix E.I. for guidance on identifying high consequence areas.) As described in Item 1 above, there is a Class 3 area between MP 328 and 328.5 that is not designated on the Williams drawing Sheet No. DOT-T-112, dated 9/19/2006. The photo on the drawing is from 9/1/2004. Per § 192.905 requirements, Williams needs to identify its high consequence areas. 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 $192,600 as follows: Item number PENALTY 5 $64,200 6 $64,200 7 $64,200 9#

520091003_NOPV PCP PCO_04202009_text.pdf, page 10Warning Items With respect to item numbers 2, 8, and 10 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 this item. Be advised that failure to do so may result in WGP being subject to additional enforcement action. Proposed Compliance Order With respect to item numbers 1, 3, 4, 5, 6, 7, and 9 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Williams Gas Pipeline (WGP). 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. 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 5-2009-1003 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, Chris Hoidal Director, Western Region Pipeline and Hazardous Materials Safety Administration Enclosure: Response Options for Pipeline Operators in Compliance Proceedings 10#

520091003_NOPV PCP PCO_04202009_text.pdf, page 11PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Williams Gas Pipeline (WGP) a Compliance Order incorporating the following remedial requirements to ensure the compliance of WGP with the pipeline safety regulations: 1. In regard to Item Number 1 of the Notice pertaining to the casing vents, WGP must repair or eliminate the casing vents installed near valves 34-2 and 34-1 and provide documentation of the repairs. Additionally, WGP must submit documentation demonstrating that a review all of the installed casings in the Spokane North and South Districts has been completed and all damaged casing vents have been repaired or eliminated such that §192.323(d) requirements are met. 2. In regard to Item Number 3 of the Notice pertaining to inadequate cathodic protection per § 192.463 requirements, WGP must test, evaluate and where necessary, enhance their cathodic protection system to comply with Appendix D criteria and submit to the Western Region Office adequate documentation to demonstrate compliance. 3. In regard to Item Number 4 of the Notice pertaining to inadequate cathodic protection per § 192.463 requirements, WGP must test, evaluate and where necessary, enhance their cathodic protection system to comply with Appendix D criteria and submit to the Western Region Office adequate documentation to demonstrate compliance. 4. WGP must complete Item Numbers 1, 3, and 4 within six months of receipt of a Final Order. 5. In regard to Item Number 5, within 30 days of receipt of the Final Order, WGP must submit a plan to repair the pipeline defect located within MP 1828.139 and MP 1828.143 on the 26 inch diameter Mainline A pipeline. The repair plan should reflect use of accepted industry standards for pipeline repair methods. WGP must complete the repair within 90 days or receipt of the final order. Once the repair is complete, WGP must submit documentation of the repair to the Western Region Office within 30 days thereafter. 6. In regard to Item Number 6, within 30 days of receipt of the Final Order, WGP must submit a plan to repair the pipeline defect located at approximately MP 1829.836 on the 26 inch diameter Mainline A pipeline. The repair plan should 11#

520091003_NOPV PCP PCO_04202009_text.pdf, page 12reflect use of accepted industry standards for pipeline repair methods. WGP must complete the repair within 90 days or receipt of the final order. Once the repair is complete, WGP must submit documentation of the repair to the Western Region Office within 30 days thereafter. 7. In regard to Item Number 7, within 30 days of receipt of the Final Order, WGP must submit a plan to repair the pipeline defect located at approximately MP 1827.950 on the 26 inch diameter Mainline A pipeline. The repair plan should reflect use of accepted industry standards for pipeline repair methods. WGP must complete the repair within 90 days or receipt of the final order. Once the repair is complete, WGP must submit documentation of the repair to the Western Region Office within 30 days thereafter. 8. In regard to Item Number 9 of the Notice pertaining to pertaining to the failure to conduct a leak survey per § 192.706 requirements, Williams Gas Pipeline must conduct a leak survey of the Class 3 area between MP 328 and 328.5. Upon completion of the survey Williams Gas Pipeline must submit documentation indicating the results of the survey and any mitigation plans to the Western Region Office. Item Number 9 of the Notice must be completed within three months of receipt of a Final Order. 10. WGP shall maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to Chris Hoidal, Director, Western 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. 12#