ENSTAR NATURAL GAS CO — Warning Letter

520080010w_warning letter_04232008_text.pdf, page 1Official PDFU. S Department of Transportation Pipeline and Hazardous Materials Safety Administration 12300 W Dakota Ave, Suite 110 Lakewood, CO 80228 WARNING LETTER CERTIFIED MAIL - RETURN RECEIPT RE UESTED April 23, 2008 Mr. John Lau Director, Transmission Operations Alaska Pipehne Company 401 E International Airport Road P 0 Box 190288 Anchorage, AK 99519-0288 CPF 5-2008-0010W Dear Mr Lau On May 7-11, 2007, representatives of the Pipehne and Hazardous Materials Safety Administration (PHMSA), pursuant to Chapter 601 of 49 United States Code, inspected Alaska Pipehne Company's Integrity Management program m Anchorage, Alaska. As a result of the inspection, it appears that you have committed probable violations of the Pipehne Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violations are. g 192. 903 What definitions apply to this subpart? The following definitions apply to this subpart: High consequence area means an area established by one of the methods described in paragraphs (1) or (2) as follows: (2) The area within a potential impact circle containing — (ii) An identified site. Identified site means each of the following areas: (b) A building that is occupied by twenty (20) or more persons on at least five (5) days a week for ten (10) weeks in any twelve (12)-month period. (The days and weeks need not be consecutive. )#

520080010w_warning letter_04232008_text.pdf, page 2Examples include, but are not limited to, religious facilities, office buildings, community centers, general stores, 4-H facilities, or roller skating rinks. $ 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 g 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. ) (b)(1) Identified sites. An operator must identify an identified site, for purposes of this subpart, from information the operator has obtained from routine operation and maintenance activities and from public officials with safety or emergency response or planning responsibilities who indicate to the operator that they know of locations that meet the identified site criteria. These public officials could include officials on a local emergency planning commission or relevant Native American tribal officials. An HCA was added on 11/30/05 to the BAP as a new HCA, however this was identified as the Beluga Power Plant which was m existence and should have been identified as an origmal HCA by the December 17, 2004 date iiEvidence i APC Annual HCA Report for 2005 g 192. 907 What must an operator do to implement this subpart'? (a) General. No later than December 17, 2004, an operator of a covered pipeline segment must develop and follow a written integrity management program that contains all the elements described in g 192. 911 and that addresses the risks on each covered transmission pipeline segment. (b) Implementation Standards. In carrying out this subpart, an operator must follow the requirements of this subpart and of ASME/ANSI B31. 8S (ibr, see g 192. 7) and its appendices, where specified. An operator may follow an equivalent standard or practice only when the operator demonstrates the alternative standard or practice provides an equivalent level of safety to the public and property. In the event of a conflict between this subpart and ASME/ANSI B31. 8S, the requirements in this subpart control. $ Bl. 91'l How t4es an operator i6enti4y potential threats to pipeline integrity and use the threat identification in its integrity program?#

520080010w_warning letter_04232008_text.pdf, page 3(a) Threat identification. An operator must identify and evaluate all potential threats to each covered pipeline segment. Potential threats that an operator must consider include, but are not limited to, the threats listed in ASME/ANSI B31. 8S (ibr, see g 192. 7), section 2, which are grouped under the following four categories: (1) Time dependent threats such as internal corrosion, external corrosion, and stress corrosion cracking; (2) Static or resident threats, such as fabrication or construction defects; (3) Time independent threats such as third party damage and outside force damage; and (4) Human error. APC has no documented evaluation for mteractmg threats and there are no program procedures to define how an evaluation is to be performed iiEvidence i APC IMP Plan, Section 4. 10 3 g 192. 933 What actions must be taken to address integrity issues? (a) General requirements An operator must take prompt action to address all anomalous conditions that the operator discovers through the integrity assessment. In addressing all conditions, an operator must evaluate all anomalous conditions and remediate those that could reduce a pipeline's integrity. An operator must be able to demonstrate that the remediation of the condition will ensure that the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment of the covered segment. If an operator is unable to respond within the time limits for certain conditions specified in this section, the operator must temporarily reduce the operating pressure of the pipeline or take other action that ensures the safety of the covered segment. If pressure is reduced, an operator must determine the temporary reduction in operating pressure using ASME/ANSI B31G (ibr, see g 192. 7) or AGA Pipeline Research Committee Project PR — 3 — 805 ("RSTRENG", ibr, see g 192. 7) or reduce the operating pressure to a level not exceeding 80% of the level at the time the condition was discovered. (See appendix A to this part 192 for information on availability of incorporation by reference information). A reduction in operating pressure cannot exceed 365 days without an operator providing a technical justification that the continued pressure restriction will not jeopardize the integrity of the pipeline. Two anomahes were identified m HCAs during ILI of the City Gate pipehne that met the criteria for immediate conditions Pressure reductions were not taken by APC upon discovery of these two anomahes and repairs were completed approximately one month and approximately 5 months after discovery of these conditions, respectively. (Evidence l Excavation Inspection Forms — East City Gate — 5/16/05 & 9/13/05, and other excavation report data. 4. g 192, . 907%hat must an operator do to implement this subpart?#

520080010w_warning letter_04232008_text.pdf, page 4(a) General. No later than December 17, 2004, an operator of a covered pipeline segment must develop and follow a written integrity management program that contains all the elements described in g 192. 911 and that addresses the risks on each covered transmission pipeline segment. (b) Implementation Standards. In carrying out this subpart, an operator must follow the requirements of this subpart and of ASMK/ANSI B31. 8S (ibr, see g 192. 7) and its appendices, where specified. An operator may follow an equivalent standard or practice only when the operator demonstrates the alternative standard or practice provides an equivalent level of safety to the public and property. In the event of a conflict between this subpart and ASMK/ANSI B31. 8S, the requirements in this subpart control. g 192. 933 What actions must be taken to address integrity issues? (d) Special requirements for scheduling remediation. — (1) Immediate repair conditions. An operator's evaluation and remediation schedule must follow ASME/ ANSI B31. 8S, section 7 in providing for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure in accordance with paragraph (a) of this section or shut down the pipeline until the operator completes the repair of these conditions. An operator must treat the following conditions as immediate repair conditions: (i) A calculation of the remaining strength of the pipe shows a predicted failure pressure less than or equal to 1. 1 times the maximum allowable operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, ASME/ANSI B31G; RSTRENG; or an alternative equivalent method of remaining strength calculation. These documents are incorporated by reference and available at the addresses listed in appendix A to part 192. (ii) A dent that has any indication of metal loss, cracking or a stress riser. (iii) An indication or anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action. The two immediate repair conditions on the City Gate pipehne noted m 3 above, were not scheduled for repair m accordance with the requirements of ASME B31. 8S-2001, Section 7. (Evidence i Excavation Inspection Forms — East City Gate — 5/16/05 R, 9/13/05, and other excavation report data g 192. 907 What must an operator do to implement this subpart? (a) General. No later than December 17, 2004, an operator of a covered pipeline segment must develop anh follow a written integrity management yrogram that#

520080010w_warning letter_04232008_text.pdf, page 5contains all the elements described in g 192. 911 and that addresses the risks on each covered transmission pipeline segment. g 192. 945 What methods must an operator use to measure program effectiveness? (a) General. An operator must include in its integrity management program methods to measure, on a semi-annual basis, whether the program is effective in assessing and evaluating the integrity of each covered pipeline segment and in protecting the high consequence areas. These measures must include the four overall performance measures specified in ASME/ANSI B31. SS (ibr, see $192. 7), section 9. 4, and the specific measures for each identified threat specified in ASME/ANSI B31. 8S, Appendix A. APC had not collected data as of the inspection on the threat-specific measures listed in Table 9 of ASME B31. 8S and has no process to do so. (Evidence l APC IMP Plan, Section 10. 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. 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 correct the items identified in this letter. Failure to do so will result in Alaska Pipeline Company being subject to additional enforcement action. No reply to this letter is required. If you choose to reply, in your correspondence please refer to CPF 5-2008-0010W. 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). Sincerely, Chris Hoidal Director, Western Region Pipeline and Hazardous Materials Safety Administration cc: PHP-60 Compliance Registry PHP-500 J. Strawn (4118987)#