ALYESKA PIPELINE SERVICE CO — Notice of Probable Violation

party submissionOfficial PDF520055023_Operator Petition for Reconsideration_08242009.pdf#

520055023_FinalOrder_07282009_text.pdf, page 1Official PDFJUL 28 2009 Mr. Mike Joyner Senior Vice President Pipeline and Oil Movements Alyeska Pipeline Service Company 900 E. Benson Blvd. P.O. Box 196660 Anchorage, AK 99519-6660 Re: CPF No. 5-2005-5023 Dear Mr. Joyner: Enclosed is the Final Order issued in the above-referenced case. It makes findings of violation and assesses a civil penalty of $84,000. The Final Order also specifies actions to be taken by Alyeska to comply with the pipeline safety regulations and the revision of certain operating and maintenance procedures. The penalty payment terms are set forth in the Final Order. When the civil penalty has been paid and the terms of the compliance order and amendment of procedures completed, as determined by the Director, Western Region, this enforcement action will be closed. Your receipt of the Final Order constitutes service of that document 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 CERTIFIED MAIL – RETURN RECEIPT REQUESTED [7005 0390 0005 6162 5630]#

520055023_FinalOrder_07282009_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 ) ) Alyeska Pipeline Service Company, ) CPF No. 5-2005-5023 ) Respondent. ) _______________________________) FINAL ORDER On September 13-16 and 27-30, 2004, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of Respondent’s facilities, manuals and records in Alaska. Alyeska Pipeline Service Company (Alyeska or Respondent) operates the Trans Alaska Pipeline System (TAPS), an 800-mile pipeline that transports crude oil from the North Slope of Alaska to the Valdez Marine Terminal. As a result of the inspection, the Director, Western Region, OPS (Director), issued to Respondent, by letter dated July 19, 2005, a Notice of Probable Violation, Proposed Civil Penalty, Proposed Compliance Order, and Notice of Amendment (Notice). In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that Respondent had committed certain violations of 49 C.F.R. Part 195, proposed assessing civil penalties of $84,000 for the alleged violations, and proposed ordering Respondent to take certain measures to correct the alleged violations. The Notice also proposed, in accordance with 49 C.F.R. § 190.237, that Respondent amend its written procedures for Operations, Maintenance and Emergencies. Respondent requested an extension of the deadline to respond to the Notice by letter dated August 12, 2005. The Director granted the request and extended the deadline to October 24, 2005. Respondent requested a second extension by email dated October 4, 2005. The Director also granted this request and extended the deadline to December 2, 2005. Respondent explained that both of its extension requests were based on a need to gather additional information and develop amended procedures to respond to the Notice. Respondent responded to the Notice by letter dated December 2, 2005 (Response). The company contested all of the allegations of violation and many of the allegations that its procedures were inadequate, and requested a hearing. A hearing was held on March 28, 2006, in Lakewood, Colorado, with an attorney from the Office of Chief Counsel, PHMSA, presiding. Respondent was represented by counsel at the hearing. After the hearing, Respondent provided a closing response (Closing) by letter dated May 26, 2006.#

520055023_FinalOrder_07282009_text.pdf, page 32 FINDINGS OF VIOLATION Items 5(b) and 5(c): Items 5(b) and 5(c) of the Notice alleged that Respondent violated 49 C.F.R. § 195.404(a), which states: § 195.404 Maps and records. (a) Each operator shall maintain current maps and records of its pipeline systems that include at least the following information: (1) Location and identification of the following pipeline facilities: (i) Breakout tanks; (ii) Pump stations; (iii) Scraper and sphere facilities; (iv) Pipeline valves; (v) Facilities to which § 195.402(c)(9) applies; (vi) Rights-of-way; and (vii) Safety devices to which § 195.428 applies Items 5(b) and 5(c) alleged similar violations and are therefore discussed together. Item 5(b) alleged that Respondent’s “G-100” alignment drawings did not accurately reflect the current location and identification of certain facilities at the TAPS Pump Station 8 (PS8) and the North Pole Metering Facility. Specifically, Item 5(b) alleged that Alyeska’s drawings did not reflect that the PS8 piping was blinded off at the TAPS mainline in 1996, and did not reflect that 6-inch and 8-inch supply and return lines from TAPS to the North Pole Metering Facility had been replaced with two 16-inch lines. In its Response and at the hearing, Respondent argued that the G-100 drawings were in fact accurate because the connections to the mainline still existed, even though Respondent admitted they were blinded off in 1996. This argument is unpersuasive. Pump Station 8 is no longer in service. The G-100 drawings reviewed by the OPS inspector incorrectly indicated that the PS8 pumps remained connected to the mainline and did not reflect the out-of-service status of PS8. Item 5(c) also alleged that Respondent’s G-100 drawings did not accurately reflect that the pig launcher and receiver, reducing flanges, and associated pipeline components had been removed from Pump Station 10 (PS10) in 1997. In its Response and at the hearing, Respondent indicated that it had other sets of records that correctly reflected the piping configuration at PS8, PS10, and the North Pole Metering Facility. Respondent argued that the G-100 drawings for these facilities are for reference purposes only and are not maintained as “as-built” records. Respondent indicated it would mark the drawings to indicate that they are “intended for general pipeline and facility location purposes only,” and are not the most current detailed information on the pipeline system. In each instance, Respondent argued that it had different records, available to its employees, that were more current than the G-100 drawings and that therefore it was in compliance with § 195.404(a).#

520055023_FinalOrder_07282009_text.pdf, page 43 Regarding both Items, Respondent provided OPS with one set of drawings at the inspection but later indicated that other drawings were the current records required by § 195.404. When Respondent maintains inconsistent maps and records, Respondent’s employees, emergency responders, regulators and others viewing the drawings could be left with an incorrect understanding of the configuration of the pipeline. One purpose of maintaining current maps and records is to ensure that Respondent’s employees and others have accurate and consistent documents upon which they can rely when conducting normal operations and maintenance, responding to emergencies, and in other circumstances. Inconsistent records therefore pose a threat to pipeline safety. After considering all of the evidence and issues presented, I find that Respondent violated § 195.404(a) as alleged in Items 5(b) and 5(c) when it failed to keep its G-100 drawings updated to accurately reflect the current configuration of TAPS at PS8, PS10 and the North Pole Metering Facility. Item 6(c): Item 6(c) of the Notice alleged that Respondent violated 49 C.F.R. § 195.406(b), which states: § 195.406 Maximum operating pressure. (a) …. (b) No operator may permit the pressure in a pipeline during surges or other variations from normal operations to exceed 110 percent of the operating pressure limit established under paragraph (a) of this section. Each operator must provide adequate controls and protective equipment to control the pressure within this limit. Background Item 6(c) alleged that Respondent did not provide adequate controls and protective equipment to control the pressure on the discharge side of the TAPS Pump Station 9 (PS9) of TAPS within the limits prescribed in §195.406(a). Specifically, the Notice alleged that from November 30, 2002, to October 21, 2003, both of the pressure safety valves (PSVs) on the discharge side of PS9 (i.e., 39-PICV-905A and 39-PICV-905B) were out of service and therefore could not provide pressure control for the pump station. PSVs (also called discharge relief valves) are important safety devices that are used to prevent the overpressure of TAPS. The purpose of a PSV is to relieve pressure inside the pipeline before the pressure reaches an unsafe level. When pipeline pressure reaches a predetermined set point, the PSV is designed to open and allow oil to flow into a relief system so that the pipeline pressure can be reduced to a safe level. An OPS inspector observed that records provided during the inspection for PSV 39-PICV-905A (Valve A) indicated that Valve A was blocked in and taken out of service on January 18, 2002, and returned to service on April 25, 2004. Respondent does not dispute that Valve A was out of service during this period. The OPS inspector also observed that the records for PSV 39-PICV-#

520055023_FinalOrder_07282009_text.pdf, page 54 905B (Valve B) indicated that Valve B was out of service on November 30, 2002, through October 21, 2003. In its Response, at the hearing, and in its Closing, Respondent presented evidence and arguments in defense of OPS’ allegation of violation regarding Valve B. Respondent requested withdrawal of the allegation of violation in Item 6(c), and the associated proposed penalty and compliance order. Discussion In its Response, Alyeska argued that Valve B was in service during the time in question. The company explained that the records it provided to OPS during the inspection erroneously indicated that Valve B was out of service.1 Alyeska further explained that the technician who performed maintenance on Valve A, which Respondent acknowledged was out of service, incorrectly associated his Valve A field notes with those for Valve B. Respondent stated that these “maintenance record keeping errors in the field […] could lead to the conclusion that both discharge relief valves were simultaneously out of service for the referenced time period.”2 In its Response, the company provided documents from its electronic work order system and documents indicates, however, that they only refer to maintenance activities; the documents do not indicate whether Valve B was actually in service. Therefore, I find that these documents do not constitute sufficient evidence to prove that Valve B was actually in service. argued that they showed Valve B was actually in service in 2002 and 2003.3 A review of the During the hearing, Alyeska stated that it would supply additional records and explanation on this issue in its Closing. In support of its position, Respondent provided an explanation of its electronic work order system for inspection and maintenance tasks. Respondent explained that this system automatically generates work orders for inspection and maintenance tasks for each PSV and that each order contains instructions, called Safe Maintenance Procedures (SMPs), for performing that specific task. Respondent explained that when its electronic system creates a work order, an instrument technician takes the SMP form into the field to conduct the PSV test, initialing each step on the form as the test is performed. Respondent provided the initialed and signed SMP documents for 2002 and 2003 as evidence that Valve B was actually in service.4 Upon review of these 2002-2003 documents, I find that they do not support Respondent’s contention that Valve B was actually in service during this time period. Alyeska’s 2002 SMP contains 62 steps that an instrument technician must perform to complete the PSV function test 1 Response, Finding No. 6c at 2 (Dec. 2, 2005). 2 Id. 3 Id., Ex. 17 and 18. These exhibits include “Work Orders” and “Task Completion Processing” documents for Valve B for 2002 and 2003. 4 Closing at 4 (May 26, 2006). See Ex. 67, SMP-I19-043, signed and dated 11/30/02, and Ex. 68, SMP-I19-043 signed and dated 10/21/03.#

520055023_FinalOrder_07282009_text.pdf, page 65 and other related tests.5 Steps 1 through 34 involve testing of the PSV and include procedures for testing preparation, pre-test, function testing and returning the valve to service. Steps 33 and 34 cover returning the PSV to service after testing.6 For the 2002 function test, nearly all steps, but not steps 33 and 34, were initialed as having been completed.7 Therefore, the 2002 SMP documentation shows that Valve B was apparently not placed into service after the function test was performed. If anything, Alyeska’s own documentation supports the allegation that Valve B was out of service in 2002.8 During the hearing, Alyeska invited the OPS inspector to PS9 to meet with company staff for another review of Valve B-related documents. Although there may be situations in which it is necessary for OPS personnel to make site visits to clarify issues regarding an alleged violation, this is not one of them. The evidence relevant to this allegation is contained in Respondent’s records, which it had ample opportunity to provide to OPS at the inspection and before, during and after the hearing. In its Response, Alyeska also argued that even if both PSVs were out of service, the company still had adequate controls and protective equipment to prevent overpressure at PS 9.9 Respondent explained that it had an Operations Control Center procedure that, if triggered, would require adjustment of pressure control equipment set points all along TAPS if that relief equipment at any given pump station were out of service.10 I reject Respondent’s argument. Section 195.406(b) requires that Respondent have adequate controls and protective equipment to control the pressure on the discharge side of PS 9 within the limits established under § 195.406(a). While Respondent argued that it had procedures to keep the pipeline safe even with both discharge PSVs out of service, it provided no evidence that such procedures would have served as adequate controls. Furthermore, even if Respondent had provided such evidence, the company still failed to have the necessary protective equipment when both valves were out of service. Summary Findings PHMSA provided Alyeska several opportunities to submit evidence to refute OPS’ allegation and evidence regarding this issue. However, none of the documents that Respondent provided 5 Response, Ex. 67. 6 Id. at 4. 7 Id. All steps leading up to those involved in returning the valve to service were initialed, except for step 22. Though the Respondent did fill in blanks within step 22 with technical data. 8 The 2003 SMP documentation shows that after the October 21, 2003 Valve B test was conducted, the technician put Valve B back into service. (Response, Ex. 68). This is consistent with the allegation in the Notice that Valve B was out of service until October 21, 2003. 9 Response, Finding No. 6(c) at 2. 10 Id. and see Ex.19 “Department Operating Procedure Operations Control Center, OCC-3.01 Pressure Control Set Points.”#

520055023_FinalOrder_07282009_text.pdf, page 76 constitute adequate proof that Valve B was actually in service during the time in question. Accordingly, upon considering all of the evidence, I find that Valve A and Valve B were out of service from November 30, 2002 to October 21, 2003 and that, as a result, Alyeska did not have adequate controls and protective equipment during that period to control the pressure on the discharge side of PS9 within the limits established according to § 195.406(a). I also find that Respondent’s procedures and controls do not constitute an acceptable alternative or substitute for providing adequate protective equipment. Item 8: Item 8 of the Notice alleged that Respondent violated 49 C.F.R. § 195.430, which states: § 195.430 Firefighting equipment. Each operator shall maintain adequate firefighting equipment at each pump station and breakout tank area. The equipment must be- (a) In proper operating condition at all times; (b) Plainly marked so that its identity as firefighting equipment is clear; and, (c) Located so that it is easily accessible during a fire. Item 8 alleged that Alyeska violated § 195.430 by failing to maintain adequate firefighting equipment at each pump station and breakout tank area. Specifically, the Notice alleged that the company had removed all incipient firefighting equipment from the PS8 manifold building. The Notice explained that the lack of such equipment would hinder Respondent’s ability to extinguish fires within the manifold building. It also explained that the manifold building housed a portion of the TAPS 48-inch mainline pipe, two 48-inch ball valves, and 42-inch and 36-inch blind flanges. In its Response, Alyeska contested the allegation and argued that because the manifold building was unheated, unoccupied, and did not contain combustible materials, fire extinguishers in the building would be “superfluous.”11 exception for non-operational pump stations or unheated or unoccupied pump station buildings, nor does compliance with the regulation turn on the presence of combustible materials. Section 195.430 requires Respondent to maintain adequate firefighting equipment at each pump station and breakout tank area. This argument is unconvincing. Section 195.430 contains no At the hearing, the company indicated that it would comply with the proposed compliance order associated with Item 8 by installing fire extinguishers in the enclosed manifold building at PS8 and in all other enclosed manifold buildings at non-operational pump stations. After the hearing, OPS confirmed that fire extinguishers had been installed at PS8. Accordingly, upon consideration of all of the evidence, I find that Respondent violated § 195.430 by failing to have fire extinguishers in the manifold building at PS8. 11 Response, Finding No. 8 at 2.#

520055023_FinalOrder_07282009_text.pdf, page 87 Items 10(a) and 10(b): Items 10(a) and 10(b) of the Notice alleged that Respondent violated 49 C.F.R. § 195.573(a), which states: § 195.573 What must I do to monitor external corrosion control? (a) Protected pipelines. You must do the following to determine whether cathodic protection required by this subpart complies with § 195.571: (1) Conduct tests on the protected pipeline at least once each calendar year, but with intervals not exceeding 15 months. However, if tests at those intervals are impractical for separately protected short sections of bare or ineffectively coated pipelines, testing may be done at least once every 3 calendar years, but with intervals not exceeding 39 months. Background Items 10(a) and 10(b) concern similar allegations and are therefore discussed together. Item 10(a) alleged that Respondent violated § 195.573(a)(1) by failing to conduct tests in 2003 of the cathodic protection system on TAPS at cased road crossings at Mile Posts 449.46, 449.53, 455.33, 455.37, 460.24, 460.26, and 474.51. The Notice alleged that the last survey at these locations was conducted on June 1, 2002, 29 months before the date of the inspection and beyond the maximum 15-month testing interval set out in § 195.573(a)(1). Item 10(b) alleged that Respondent violated § 195.573(a)(1) by failing to conduct tests in 2003 of the cathodic protection system on TAPS at cased road crossings at Mile Posts 573.81, 538.56, 541.33, 545.79, 545.83, 552.25, 561.86, 570.63, 579.48 and 606.19. The Notice alleged that the last survey at these locations was conducted on June 4, 2002, 27 months before the date of the inspection and beyond the maximum 15-month testing interval set out in § 195.573(a)(1). As OPS and Respondent discussed at the hearing, both 10(a) and 10(b) alleged that Respondent failed to conduct tests of road casings at the cited locations for electrical isolation from the TAPS mainline. The Notice alleged that the omission of such tests constituted a failure to comply with § 195.573(a)(1). At the hearing, OPS took the position that § 195.573(a)(1) requires casing isolation testing on the same annual frequency as that of testing of the cathodic protection levels on the mainline pipe. At the hearing, in its Response and Closing, Alyeska took the position that casing isolation tests are covered solely by § 195.575 and that, therefore, the annual interval set out in § 195.573(a)(1) does not apply. Casings are buried metal pipes through which the TAPS mainline passes beneath roads and other obstacles. Alyeska installs casings so that they are electrically isolated from the TAPS mainline pipe. There is good reason for this. The purpose of electrical isolation is to allow the cathodic protection system on the mainline pipe to function effectively. If a casing is not electrically isolated from the mainline pipe (i.e., if it is “shorted”) the mainline cathodic protection system will supply current to the casing, rather than the mainline pipe as intended.#

520055023_FinalOrder_07282009_text.pdf, page 98 Inadequate cathodic protection is a threat to pipeline safety because it increases the likelihood of external corrosion. External corrosion threatens pipeline safety because, if it progresses unchecked, it may cause the failure of the mainline pipe and increase the risk of harm to life, property and the environment. The allegations in the Notice and the discussions at the hearing raise the issue of what testing interval applies, if any, to the testing of casings for electrical isolation. Discussion The Notice alleged that Respondent failed to comply with § 195.573(a)(1) when it failed to test annually whether its road casings were electrically isolated from the TAPS mainline. Respondent’s procedures in place at the time of the inspection required the company to test road casings for isolation from the mainline pipe once each year but with intervals not to exceed fifteen (15) months.12 Respondent agreed that it did not conduct annual casing isolation tests as required by its own procedure.13 However Respondent argued that the one-year testing procedure was based on Respondent’s “incorrect interpretation of the regulations.”14 Respondent argued that § 195.575, not § 195.573(a)(1), applies to the testing of casings for isolation. Respondent argued that isolation testing is “separate and distinct from testing to assure adequate levels of CP required by § 195.573(a)(1).”15 Respondent then asserted that it could select the testing interval of its choice because § 195.575 does not specify an interval for casing road casings on a triennial rather than annual basis. In its Closing, Respondent also argued that no finding of violation is appropriate because it was not on notice of the annual isolation testing requirement. isolation tests.16 On that basis, Respondent indicated that it had changed its procedures to test I reject Respondent’s legal argument regarding the regulatory requirements applicable to casings. Section 195.573(a)(1) requires Respondent to test its pipeline for compliance with the cathodic protection criteria requirements set forth in § 195.571 on an annual basis, but not to exceed 15 months. The main purpose of this annual testing requirement is to provide Respondent with information about the effectiveness of its cathodic protection system such that it can correct deficiencies within a reasonable time and prevent pipeline safety risks associated with external corrosion. If Alyeska fails to test annually the road casings to determine if they are isolated from the mainline pipe, the company does not get an accurate picture of the effectiveness of its cathodic protection system on the mainline pipe inside the casing. Annual cathodic protection testing on the mainline may not reveal a shorted casing and could give the impression that the cathodic 12 Id. 13 Response, Finding No. 10(a) at 2. 14 Id. 15 Response, Finding No. 10(a) at 4. 16 Response, Finding No. 10(a) at 2.#

520055023_FinalOrder_07282009_text.pdf, page 109 protection on the mainline pipe meets the requirements of §195.571, when, in fact, protection may not be adequate. For example, testing of the cathodic protection on the mainline pipe at either end of a cased crossing may show adequate protection, but a short may be present inside the casing. If the casing itself is not tested for isolation, a short could persist, resulting in inadequate cathodic protection on the mainline pipe at the location of the short and increasing the likelihood of external corrosion at that location. External corrosion could occur undetected, particularly in years between Respondent’s periodic in-line inspection (ILI) runs. The preamble to the 2001 amendments to the Part 195 corrosion control regulations explains why the casing requirements in § 195.575 do not include an inspection frequency.17 The discussion supports the position that the annual testing requirement in § 195.573(a)(1) was intended to apply also to casing isolation tests. In the Final Rule preamble to the electrical isolation regulations, PHMSA discussed a commenter’s suggestion that § 195.575 should include a specified testing frequency for casing isolation.18 PHMSA explained that the purpose of the inspection required by § 195.575 was to ensure that electrical isolation is adequate when the isolation is first installed.19 PHMSA elaborated that “all post-installation inspections and tests of test for casing isolation can undermine effectiveness of cathodic protection and the accuracy of mainline cathodic protection test results, the preamble supports the inclusion of casing isolation testing in the annual testing requirement. cathodic protection facilities are covered by final § 195.573.”20 In light of the fact that failure to In its Closing, Alyeska took the position that during the hearing OPS had agreed to convert Items 10(a) and 10(b) to Notice of Amendment (“NOA”) Items. There was discussion at the hearing about Respondent having changed its procedures since the inspection from annual to triennial testing. OPS had encouraged Respondent to change its procedures back to testing once every calendar year but not to exceed 15 months. As discussed above, this change must be made to comply with the regulations. Furthermore, OPS did not concede that a finding of violation and civil penalty was not warranted for exceeding the maximum 15-month interval for conducting isolation tests of the road casings as required by § 195.573(a)(1). However, based on discussions at the hearing, the proposed compliance order associated with Items 10(a) and 10(b) is hereby reduced to a Notice of Amendment and will be addressed in the Amendment of Procedures section of this Final Order. In its Closing, Respondent committed to amending its procedures in accordance with the proposed compliance order.21 Accordingly, based upon consideration of all of the evidence in the record and the legal issues raised, I find that Respondent failed to comply with § 195.573(a)(1) when it failed to test 17 See Final Rule, Controlling Corrosion on Hazardous Liquid and Carbon Dioxide Pipelines, 66 FR 66994, Dec. 27, 2001. 18 Id. at 67000. 19 Id. 20 Id. 21 Closing at 5.#

520055023_FinalOrder_07282009_text.pdf, page 1110 annually its road casings for isolation at the cited locations. I also find that the annual testing requirement set out in § 195.573(a)(1) includes annual electrical isolation testing of all casings. Item 10(c): Item 10(c) of the Notice alleged that Respondent violated 49 C.F.R. § 195.573(c), which states: § 195.573 What must I do to monitor external corrosion control? (a) …. (c) Rectifiers and other devices. You must electrically check for proper performance each device in the first column at the frequency stated in the second column. Device Check Frequency Rectifier At least six times each calendar year, but with intervals not exceeding 2½ months. Other interference bond At least once each calendar year, but with intervals not exceeding 15 months. Item 10(c) alleged that Respondent violated § 195.573(c) by failing to electrically check for proper performance each rectifier on TAPS at least six times each calendar year, but with intervals not exceeding 2½ months. Specifically, the Notice alleged that Alyeska failed to timely inspect the 40-EEQ-86 cathodic protection rectifier for Tank 200 at PS10. In its Response and at the hearing, Alyeska explained that because PS10, including Tank 200, was no longer operational and had been cleaned and disconnected from TAPS in 1996, the 40-EEQ-86 rectifier was no longer in use.22 In its Response and at the hearing, the company explained that it had no intention of using Tank 200 in the future and that it would eventually be dismantled. Because Tank 200 was cleaned, removed from service and disconnected from TAPS in 1996, I find that, at the time of the inspection, the 40-EEQ-86 cathodic protection rectifier associated with Tank 200 was not subject to the requirements of § 195.573(c). Accordingly, upon consideration of all of the evidence, I order that the allegation of violation in Item 10(c) and the associated proposed compliance order be withdrawn. Respondent is reminded that if it chooses to place Tank 200 back into service in the future, it must verify the integrity of the tank and the associated cathodic protection system and comply with all other applicable provisions of the Pipeline Safety Laws and regulations. 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 22 Hearing Presentation, Item 10(c) at 5.#

520055023_FinalOrder_07282009_text.pdf, page 1211 related series of violations. 49 U.S.C. § 60122 and 49 C.F.R. § 190.225 require that, in determining the amount of a civil penalty, I 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 $84,000 for violations of §§ 195.404(a), 195.406(b), 195.430, and 195.573(a)(1). Items 5(b) and 5(c) proposed penalties of $1,000, respectively, for two violations of §195.404(a). Respondent requested that PHMSA eliminate the proposed civil penalties for these Items on the basis of its argument that it did not violate the regulation. As discussed in the findings of violation, I found that Alyeska violated § 195.404(a) when it failed to keep and provide accurate maps of PS8, PS10, and the North Pole Metering Facility. Respondent provided no information that would warrant reduction of the proposed penalties. Having reviewed the record and considered the assessment criteria, I assess Respondent civil penalties of $1,000 for Item 5(b) and $1,000 for Item 5(c). Item 6(c) proposed a penalty of $55,000 for violation of § 195.406(b). Respondent requested that PHMSA eliminate the proposed civil penalty for this Item on the basis of its argument that it did not violate the regulation. The regulation requires Respondent to provide adequate controls and protective equipment to control pressure within the limits established under § 195.406(a). Respondent submitted numerous documents at the inspection and before, during and after the hearing to show that it had adequate controls and protective equipment in place at the time of the inspection. However, none of these documents were sufficient to prove Respondent’s argument. As a result, I have found that Respondent failed to have adequate controls and protective equipment to control pressure in TAPS. Compliance with this regulation is a key means of preventing pipeline failures due to overpressure. Respondent has provided no information that would warrant reduction or elimination of the penalty. Having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $55,000 for Item 6(c). Item 8 proposed a penalty of $1,000 for violation of § 195.430. Respondent requested that PHMSA eliminate the proposed civil penalty for this Item on the basis of its argument that it did not violate the regulation. The regulation requires Respondent to maintain adequate firefighting equipment at each pump station and breakout tank area. Respondent did not have firefighting equipment in the PS8 manifold building. Respondent has provided no information that would warrant reduction or elimination of the penalty. Having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $1,000 for Item 8. Items 10(a) and 10(b) proposed penalties of $14,000 and $12,000, respectively, for violations of § 195.573(a)(1). Respondent requested that PHMSA withdraw the proposed civil penalties for#

520055023_FinalOrder_07282009_text.pdf, page 1312 these Items. First, Respondent argued that it committed no violation of the regulation. As discussed in the Findings of Violation, 49 C.F.R. § 195.573(a)(1) requires Respondent to conduct annual tests of the adequacy of its cathodic protection system, including tests to determine whether pipeline casings are electrically isolated from the mainline pipe. Electrically shorted casings may interfere with cathodic protection and result in inadequate protection. An operator does not have a full and accurate picture of the adequacy of its cathodic protection unless it conducts annual casing isolation tests. Respondent’s failure to annually test casing isolation could result in significant threats to pipeline safety. Second, Respondent argued that the penalty for this Item should be withdrawn for procedural reasons. It argued that because OPS decided to treat these Items as more appropriate for resolution through an NOA rather than a compliance order, then no penalties should be imposed. Respondent indicated that the regulations “do not include proposed civil penalties in conjunction with NOAs.”23 The Final Order makes findings that Respondent violated § 195.573(a)(1) for failing to test annually the electrical isolation of road casings at the cited locations. Civil penalties may also be imposed on the basis of such findings of violation.24 The Final Order also treats the proposed compliance order proposing to require Respondent to amend its procedures for compliance with § 195.573(a)(1) as an NOA. The regulations permit the use of an NOA in addition to, and in conjunction with, the appropriate enforcement actions in 49 C.F.R. Part 190, Subpart B.25 Third, Respondent argued that it should not be subject to a penalty because the “plain language of 49 C.F.R. § 195.575 does not require isolation testing on a one-year interval.”26 Respondent argued that it was not on notice that annual isolation testing was required. As discussed in the findings of violation, Respondent was on notice of the annual casing isolation testing requirement. Notice was provided in the 2001 amendments to the Part 195 corrosion control regulations, which explained the lack of a specific testing interval in § 195.575 and the applicability of the annual testing interval in § 195.573 to all “post-installation testing of cathodic protection facilities.”27 Finally, Respondent argued that a civil penalty “arguably violates procedural due process” presumably because of a lack of notice that PHMSA interpreted § 195.575 as requiring annual testing.28 Beyond this statement, Respondent has stated no legal or factual basis for its 23 Closing at 4. 24 49 C.F.R. § 190.223(a). 25 49 C.F.R. § 190.237(b) states: “The amendment of an operator’s plans or procedures prescribed in paragraph (a) of this section is in addition to, and may be used in conjunction with, the appropriate enforcement actions prescribed in this subpart.” 26 Closing at 5. 27 Supra note 19, at 67000. 28 Closing at 5.#

520055023_FinalOrder_07282009_text.pdf, page 1413 “arguable” procedural due process claim and none is apparent from a thorough review of the record. Respondent provided no information that would warrant reduction of the proposed penalty. Having reviewed the record and considered the assessment criteria, I assess Respondent civil penalties of $14,000 for Item 10(a) and $12,000 for Item 10(b). Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a total civil penalty of $84,000. Respondent has provided no information that indicates payment of this penalty would adversely affect its ability to continue in business. Payment of the civil penalty must be made within 20 days of service. Federal regulations (49 C.F.R. § 89.21(b)(3)) require this payment be made by wire transfer, through the Federal Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed instructions are contained in the enclosure. Questions concerning wire transfers should be directed to: Financial Operations Division (AMZ-341), Federal Aviation Administration, Mike Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, OK 73125; (405) 954-8893. Failure to pay the $84,000 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 United States District Court. COMPLIANCE ORDER The Notice proposed a compliance order with respect to Items 5(b), 5(c), 6(c), 8, 10(a), 10(b), allegation of violation was withdrawn. Therefore, the proposed compliance order for Item 10(c) is no longer necessary. With respect to Items 10(a) and 10(b), on the basis of discussions between OPS and Respondent at the hearing, the proposed compliance order related to these Items will be treated as a Notice of Amendment, addressed in the Amendment of Procedures and 10(c) in the Notice for violations of 49 C.F.R. Part 195.29 With respect to Item 10(c), the section of this Final Order. The Director has indicated that Respondent has taken the actions specified in the proposed compliance order to address Item 8. Accordingly, since compliance has been achieved with respect to this violation, the compliance terms are not included in this Order. Under 49 U.S.C. § 60118(a), each person who engages in the transportation of hazardous liquids or who owns or operates a pipeline facility is required to comply with the applicable safety standards established under chapter 601. Pursuant to the authority of 49 U.S.C. § 60118(b) and 49 C.F.R. § 190.217, Respondent is ordered to take the following actions to ensure compliance with the pipeline safety regulations applicable to its operations. 29 A typographical error in the Notice indicated that several other Items also warranted a compliance order, when these Items were, in fact, associated with the Notice of Amendment.#

520055023_FinalOrder_07282009_text.pdf, page 1514 Respondent must: 1. Regarding Items 5(b) and 5(c), update its G-100 drawings to accurately reflect the current configuration of its pipeline system. 2. Regarding Item 6(c), ensure that there is always adequate, operational protective equipment located on the suction and discharge sides of operational TAPS pump stations to prevent pressures from exceeding 100% of MOP during normal operations and from exceeding 110% of MOP during surges. 3. Regarding the requirements numbered 1 through 3 above, within sixty (60) days of receipt of this Final Order, Respondent must complete the required actions and submit documentation of completion, including revised procedures, maps, records and other materials, to the Director, Western Region, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 12300 West Dakota Avenue, Suite 110, Lakewood, Colorado 80228. The Director may grant a written extension of time to comply with any of the required items upon a written request timely submitted by the Respondent demonstrating good cause for an extension. AMENDMENT OF PROCEDURES 1. Notice of Amendment: Inadequacies Addressed Items 1(a), 1(b), 2, 3, 6(a), 6(b), 11 and 13 of the Notice alleged inadequacies in Respondent’s Operations, Maintenance and Emergencies, Pressure Testing, and Corrosion Control procedures. These Items proposed to require amendment of Respondent’s procedures to comply with the requirements of 49 C.F.R. §§ 195.55, 195.306, 195.308, 195.406(b), 195.575 and 195.589(c). In its Response and at the hearing, Alyeska submitted copies of its amended procedures, which the Director has reviewed. Accordingly, based on the results of this review, I find that Respondent’s original procedures as described in the Notice were inadequate to ensure safe operation of its pipeline system, but that the company has corrected the identified inadequacies. Therefore, no need exists to issue an Order Directing Amendment for these Items. 2. Notice of Amendment: Items Withdrawn Item 4: Item 4 of the Notice alleged that Respondent’s procedure for compliance with § 195.310(b)(9) was inadequate. The regulation states:#

520055023_FinalOrder_07282009_text.pdf, page 1615 § 195.310 Records. (a) A record must be made of each pressure test required by this subpart, and the record of the latest test must be retained as long as the facility tested is in use. (b) The record required by paragraph (a) of this section must include: (1) … (9) Where elevation differences in the section under test exceed 100 feet (30 meters), a profile of the pipeline that shows the elevation and test sites over the entire length of the test section; … Item 4 of the Notice alleged that Respondent’s procedure, Specification P307-Facility Piping Pressure Testing, did not address elevation differences within sections of pipe that were hydrostatically tested, as required by § 195.310(b)(9). In its Response and at the hearing, Alyeska presented credible information indicating that its Specification P307 procedure did, in fact, address elevation differences. Based upon the foregoing, I order that the allegation of procedural inadequacy contained in Item 4 of the Notice be withdrawn. Item 5(a): Item 5(a) of the Notice alleged that Respondent’s procedure for compliance with § 195.404(a) was inadequate. The regulation, as quoted above, provides that an operator must maintain current maps and records of its pipeline systems containing certain basic information. The Notice alleged that Respondent’s OM-1 manual did not list the North Pole Metering Dan flow valve as a safety device requiring inspection as required by § 195.404(a). In its Response and at the hearing, Respondent explained that the Dan flow valve does not protect TAPS. Respondent explained that it protects the Golden Valley Electric Association residuum return pipeline coming from the Flint Hills Resources and Petro Star refineries. Diagrams provided by Respondent confirm that the Dan flow valve is upstream of the custody transfer metering for the refinery supply and return lines. At the hearing, OPS agreed to withdraw this Item. Item 5(a) also alleged that Respondent’s OM-1 manual did not state where the maximum operating pressure (MOP) of each line segment could be found, as required by § 195.404(a). In the Notice, OPS explained that the knowledge of MOP, particularly in areas in which MOP has been reduced or de-rated due to corrosion, is critical to determining pipeline operating parameters, such as SCADA and relief device settings. In its Response, Alyeska argued that § 195.404(a) did not require that the MOP of each line segment be listed in OM-1. At the hearing, OPS agreed to withdraw this Item. Respondent must list the MOP for each pipeline in its OM-1 manual. However, Respondent is correct that § 195.404(a) does not require that Respondent list the MOP of each line segment in its OM-1 manual.#

520055023_FinalOrder_07282009_text.pdf, page 1716 Based upon the foregoing, I order that the allegations of procedural inadequacy contained in Item 5(a) of the Notice be withdrawn. Item 7: Item 7 of the Notice alleged that Respondent’s procedure for compliance with § 195.412(a) was inadequate. The regulation states: § 195.412 Inspection of rights-of-way and crossings under navigable waters. (a) Each operator shall, at intervals not exceeding 3 weeks, but at least 26 times each calendar year, inspect the surface conditions on or adjacent to each pipeline right-of-way. Methods of inspection including walking, driving, flying or other appropriate means of traversing the right-of-way. Item 7 alleged that Respondent did not adequately inspect the TAPS right-of-way south of the Chena Hot Springs Road crossing because excessive vegetation on the right-of-way precluded direct observation. The vegetation consists of small clusters of birch and willow trees that Respondent indicates were deliberately maintained for aesthetic reasons. In its Response and at the hearing, Alyeska provided photographic documentation showing that the vegetation in question did not obscure the right-of-way at the indicated location. Respondent explained that the vegetation would continue to be managed in such a way as to not obscure the right-of-way. Based upon the foregoing, I order that the allegation of procedural inadequacy contained in Item 7 of the Notice be withdrawn. 3. Notice of Amendment: Remaining Inadequacies. Item 9: Item 9 of the Notice alleged inadequacies in Respondent’s procedures for compliance with § 195.555. The regulation states: § 195.555 What are the qualifications for supervisors? You must require and verify that supervisors maintain a thorough knowledge of that portion of the corrosion control procedures established under § 195.402(c)(3) for which they are responsible for insuring compliance. Item 9 alleged inadequacies in Respondent’s Operating and Maintenance (O&M) Manual and proposed to require amendment of the company’s procedures to comply with the Subpart H Corrosion Control requirements of 49 C.F.R. § 195.555. Specifically, the Notice alleged that Respondent’s OM-1 manual did not include procedures for verifying supervisor training in the area of corrosion control.#

520055023_FinalOrder_07282009_text.pdf, page 1817 In its Response, at the hearing and in its Closing, Respondent argued that the regulations do not require that its O&M manual contain procedures to verify supervisor training. I disagree. Section 195.402(c)(3) specifically requires that Respondent’s O&M manual must contain procedures for operating, maintaining, and repairing the pipeline system in accordance with Subpart H. Section 195.555 is part of Subpart H and sets forth a requirement directly related to the operation, maintenance and repair of the pipeline. Therefore, Respondent’s O&M manual must have procedures for verifying supervisor training in the area of corrosion control. In its Response, at the hearing and in its Closing, Respondent offered several of its existing and updated procedures as evidence that its supervisors have knowledge of the corrosion control procedures.30 described in the Notice. Alyeska’s procedures appear to address only supervisor training in the general requirements of the regulations, not in the specifics of corrosion control procedures. Respondent’s procedures must specifically require that supervisors maintain a thorough knowledge of corrosion control procedures, and must provide a specific mechanism for ensuring that Respondent’s supervisors meet and maintain this training obligation. The procedures offered by Respondent, however, do not address the inadequacies Item 12: § 195.579 What must I do to mitigate internal corrosion? (a) General. If you transport any hazardous liquid or carbon dioxide that would corrode the pipeline, you must investigate the corrosive effect of the hazardous liquid or carbon dioxide on the pipeline and take adequate steps to mitigate internal corrosion. Item 12 of the Notice alleged inadequacies in Respondent’s O&M Manual and proposed to require amendment of the company’s procedures to comply with the requirements of 49 C.F.R. § 195.579(a). Specifically, the Notice alleged that Respondent did not have adequate procedures for investigating and tracking internal corrosion on TAPS mainline pipe. Respondent did not contest the alleged inadequacy and submitted amended procedures to the Director in its Closing. Respondent amended its procedures to include the following language: Inline inspection (ILI) tools are used to detect, identify, measure and assess internal corrosion affecting the safety of the pipeline. Any internal corrosion feature discovered by ILI with dimensions exceeding those specified in Procedures Manual MP 166-3.04, “Pipeline Integrity Pigging” will be examined and repaired if necessary.” The added language, however, does not address the inadequacies described in the Notice. Alyeska’s procedure still does not discuss different types of internal corrosion, investigation beyond the initial identification by ILI testing, or how corrosion features are tracked. Respondent’s practice of ILI testing, taken alone, is inadequate to effectively investigate internal corrosion because injurious corrosion may also occur between Respondent’s triennial ILI runs. 30 Response, Finding No. 9 at 1-3. Closing at 6-7.#

520055023_FinalOrder_07282009_text.pdf, page 1918 Items 10(a) and 10(b): Items 10(a) and 10(b) are discussed in detail in the Findings of Violation section above. In short, Respondent changed its casing isolation test procedures from annual to triennial testing. Section 195.573(a)(1) requires Respondent to conduct casing isolation tests on an annual basis, with maximum intervals not to exceed 15 months. Respondent’s triennial testing procedure does not comply with § 195.573(a)(1). Order Directing Amendment of Inadequate Procedures Based upon the foregoing, I find that certain of Respondent’s procedures remain inadequate to assure safe operation of its pipeline system. Pursuant to 49 U.S.C. § 60108(a) and 49 C.F.R. § 190.237, Respondent is ordered to make the following changes to its procedures. Regarding Items 9, 12, 10(a) and (b) Respondent must: 1. Regarding its written procedures for compliance with 49 C.F.R. § 195.555, amend its written procedure to require that supervisors maintain a thorough knowledge of that portion of Alyeska’s corrosion control procedures for which they are responsible for ensuring compliance. 2. Regarding its written procedures for compliance with 49 C.F.R. § 195.579, amend its written procedures to include, at a minimum: • provisions for investigating internal corrosion, including provisions for the regular use of internal corrosion investigation processes and tools that Respondent must use in addition to, and in between, the periodic ILI testing Respondent already conducts; and • provisions for monitoring, tracking and recording the growth of existing internal corrosion during the time between ILI runs. 3. Regarding its written procedures for compliance with 49 C.F.R. § 195.573, amend its procedures to require testing of road casings for electrical isolation once each year, but not to exceed 15 months. 4. Submit all amended procedures for approval to the Director within thirty (30) days following receipt of this Final Order. Once approval is given in whole or in part, pursuant to the requirements set forth below in the section of this Order entitled “Submissions,” Respondent must implement the procedures. The Director may grant a written extension of time to comply with any of the required items upon a written request timely submitted by the Respondent demonstrating good cause for an extension.#

520055023_FinalOrder_07282009_text.pdf, page 2019 Submissions For any of the items required to be submitted in the Order Directing Amendment, the Director may: (a) approve, in whole or part, the submission; (b) approve the submission on specified conditions; (c) modify the submission to cure the deficiencies; (d) disapprove in whole or in part, the submission, directing that Respondent modify the submission; or (e) any combination of the above. In the event of approval, approval upon conditions, or modification by the Director, Respondent must proceed to take all action required by the submission as approved or modified by the Director. If the Director disapproves all or any portion of the submission, Respondent must correct all deficiencies within the time specified by the Director, and resubmit it for approval. If a resubmitted item is disapproved in whole or in part, the Director may again require Respondent to correct the deficiencies in accordance with the foregoing procedure, and/or the Director may otherwise proceed to enforce the terms of this Final Order. Failure to Comply In accordance with 49 U.S.C. § 60122 and 49 C.F.R. § 190.223, failure to comply with this Final Order may result in the assessment of administrative civil penalties of not more than $100,000 per violation per day pursuant to 49 U.S.C. § 60122, or in the imposition of civil judicial penalties and other appropriate relief pursuant to 49 U.S.C. § 60120. Right to Petition for Reconsideration 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 received within 20 days of Respondent’s receipt of this Final Order and must contain a brief statement of the issue(s). The filing of the petition automatically stays the payment of any civil penalty assessed. All other terms of the order, including any required corrective action and amendment of procedures, remain in full force and effect unless the Associate Administrator, upon request, grants a stay. The terms and conditions of this Final Order shall be effective upon receipt. ____________________ ___________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety#

520055023_Decision on the Petition for Reconsideration_12162009_text.pdf, page 1Official PDFDEC 16 2009 Mr. Mike Joynor Senior Vice President Pipeline and Oil Movements Alyeska Pipeline Service Company 900 E. Benson Blvd. P.O. Box 196660 Anchorage, AK 99519-6660 Re: CPF No. 5-2005-5023 Dear Mr. Joynor: Enclosed is this agency’s decision granting, in part, and denying, in part, your company’s Petition for Reconsideration in this case. Payment of the reduced civil penalty in the amount of $27,000 shall be made in accordance with the terms set forth in the Final Order. This enforcement action closes automatically upon payment. Service of this decision via certified mail is complete upon mailing 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 Shelia Doody Bishop, Counsel CERTIFIED MAIL – RETURN RECEIPT REQUESTED [7005 0390 0005 6162 5074]#

520055023_Decision on the Petition for Reconsideration_12162009_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 ) ) Alyeska Pipeline Service Company, ) CPF No. 5-2005-5023 ) Respondent. ) ______________________________ ) DECISION ON PETITION FOR RECONSIDERATION Alyeska Pipeline Service Company (Petitioner or Alyeska) is the operator of the Trans Alaska Pipeline System (TAPS), an 800-mile-long pipeline that transports crude oil from Prudhoe Bay to Valdez, Alaska.1 On August 24, 2009, Alyeska filed this Petition for Reconsideration (Petition)2 of a July 28, 2009 Final Order, which found that Petitioner had violated Part 195 of the Pipeline Safety Regulations in several respects and assessed the company a total Civil Penalty of $84,000 for those violations.3 Petitioner argues on reconsideration that all of the Findings of Violation in the Final Order that warranted a Civil Penalty must be withdrawn. For the reasons stated in Part I of this Decision, I agree that the Civil Penalty for Items 5(b) and 5(c) should be withdrawn and that a warning should be issued for both of those Findings of Violation. I further agree that the Finding of Violation, Civil Penalty, and Compliance Order for Item 6(c) should be withdrawn for lack of sufficient evidence. I do not, however, find Petitioner’s remaining arguments persuasive. Accordingly, as noted in Part II of this Decision, I am granting this Petition, in part, by modifying Items 5(b), 5(c), and 6(c) of the Final Order. The Final Order is otherwise affirmed without modification. I. Discussion A. Findings of Violation for Items 5(b) and 5(c) 1 http://www.alyeska-pipe.com/pipelinefacts.html (accessed Oct. 20, 2009). 2 49 C.F.R. § 190.215 (authorizing the filing of petitions for reconsideration of a final order). 3 49 C.F.R. § 190.213 (authorizing issuance of Final Orders by Associate Administrator).#

520055023_Decision on the Petition for Reconsideration_12162009_text.pdf, page 32 In the July 2009 Final Order, I found that Alyeska committed two violations of 49 C.F.R. § 195.404(a), the regulation that requires “each operator” of a hazardous liquid pipeline facility to “maintain current maps and records of its pipeline systems,” including “information” on the “[l]ocation and identification of . . . [b]reakout tanks[,] [p]ump stations, [s]craper and sphere facilities[,] [p]ipeline valves[,] [f]acilities to which § 195.402(c)(9) applies[,] [r]ights-of-way[,] had presented alignment drawings of the TAPS to an Office of Pipeline Safety (OPS) inspector in September 2004, drawings which did not accurately depict the location of certain facilities and regulation. and [s]afety devices to which § 195.428 applies.”4 equipment at two pump stations and a metering station. I also noted that Petitioner argued that those documents were for reference purposes only—and thus not subject to § 195.404(a)—and that the company maintained other sets of accurate records for purposes of satisfying that In making that finding, I noted that Alyeska However, I rejected those arguments and stated that by “maintain[ing] inconsistent maps and records, Respondent’s employees, emergency responders, regulator and others viewing the drawings could be left with an incorrect understanding of the configuration of the pipeline.” I further emphasized that “[o]ne purpose of maintaining current maps and records is to ensure that Respondent’s employees and others have accurate and consistent documents upon which they can rely when conducting normal operations and maintenance, responding to emergencies, and in other circumstances[,] . . . [and that] [i]nconsistent records therefore pose a threat to pipeline safety.” For those reasons, I found that Alyeska had violated § 195.404(a). On reconsideration, Alyeska acknowledges that these alignment drawings “were and are still used by TAPS employees as a rough guide to the pipeline[,]” even though those records are “not updated frequently enough” to comply with § 195.404(a). Nevertheless, Petitioner argues that an operator can “designate which records are kept” for purposes of complying with the Pipeline Safety Regulations, and that the company had accurate maps and records of its pipeline system on-file at the time of the OPS inspection. Alyeska also notes that the OPS inspectors asked for the alignment drawings, rather than the “official record[s]” that the company keeps for compliance purposes. I do not find Petitioner’s arguments in favor of withdrawing these Findings of Violation persuasive. Legitimate reasons may exist for maintaining and using maps and records that do not comply with the requirements of § 195.404(a), including for informational or historical purposes. That does not, however, preclude the Findings of Violation in this case. There is no dispute that Alyeska’s alignment sheets were not marked as § 195.404(a) 4 § 195.404(a). Section 195.402(c)(9) requires operators to include a procedure in their operations and maintenance manuals for “facilities [that are] not equipped to fail safe,” id., and which “are located in areas that would require an immediate response by the operator to prevent hazards to the public if the facilities failed or malfunctioned,” 49 C.F.R. § 195.402(c)(4), or “that control receipt and delivery of the hazardous or carbon dioxide, detecting abnormal operating conditions by monitoring pressure, temperature, flow or other appropriate operational data and transmitting this data to an attended location.” § 195.402(c)(9). Section 195.428 applies inspection, testing, and installation requirements to certain overpressure safety devices and overfill protection systems. § 195.428.#

520055023_Decision on the Petition for Reconsideration_12162009_text.pdf, page 43 noncompliant at the time of the OPS inspection.5 There is also no indication that Petitioner had a procedure in place for limiting the use and handling of those records. the absence of such precautions, OPS determined that someone who viewed the alignment sheets could mistakenly assume that they were fully compliant with § 195.404(a). Moreover, Petitioner’s use of those records as a “rough guide” to the TAPS increases the likelihood of someone making that erroneous assumption. 6 In In other words, while there are circumstances that justify an operator’s maintenance and use of maps or records that do not comply with § 195.404(a), this fact must be made conspicuously known to those who might reasonably be expected to view or use those documents. As Alyeska failed to take such precautions in this case, I am rejecting Petitioner’s request for reconsideration of the Findings of Violation for Items 5(b) and 5(c). Nonetheless, I recognize that the assessment of a monetary penalty might not be appropriate in this case as a matter of policy. Civil Penalties for Items 5(b) and 5(c) and issuing a warning for each of those Findings of Violation. 7 For that reason, I am withdrawing the B. Finding of Violation for Item 6(c) In the July 2009 Final Order, I also found that Alyeska violated 49 C.F.R. § 195.406(b), the regulation that prohibits an operator from “permit[ting] the pressure in a pipeline during surges or other variations from normal operations to exceed 110 percent of [maximum operating pressure (MOP)] . . .” and which requires “[e]ach operator” to “provide adequate controls and protective equipment to control the pressure within this limit.”8 As explained in the Final Order, the basis for that finding was Petitioner’s failure to provide adequate overpressure controls and protective equipment for a pipeline segment located on the discharge-side of a TAPS pump station for an 11-month period of time. 5 After receiving the Notice of Probable Violation in this case, Alyeska sought to accomplish the former objective by marking the disputed drawings as “intended for general pipeline and facility location purposes only.” Response to Probable Violations 5(b) and 5(c) at 2. However, there is still no indication that the company has adequate procedures in place for the safe handling and use of those maps and records. 6 49 C.F.R. § 195.402(c)(1) (stating that an operator’s manual for operations, maintenance, and emergencies “must include procedures” for “[m]aking construction records, maps, and operating history available as necessary for safe operation and maintenance”). 7 In the Matter of Butte Pipeline Co. (Butte), Final Order, CPF No. 5-2007-5008, p.4 (Aug. 17, 2009) (http://primis.phmsa.dot.gov/comm/reports/enforce/documents/520075008/520075008_Final%20Order_08172009.p df?nocache=1644) (explaining that the “fair notice” requirement limits an agency’s ability to assess criminal or civil penalties for novel regulatory interpretations in enforcement proceedings). 8 49 C.F.R. § 195.404(b). The MAOP of a hazardous liquid pipeline is determined by applying the formula prescribed in § 195.406(a). That formula uses several factors in making that determination, including internal design pressure of the line pipe and of any component, certain test pressures, and, in some circumstances, prior operating pressure. Id.#

520055023_Decision on the Petition for Reconsideration_12162009_text.pdf, page 54 More specifically, I observed that the record showed that the pipeline on the discharge- side of that pump station had two pressure safety valves (PSVs), 39-PICV-905A (Valve A) and 39-PICV-905B (Valve B). I further noted that the undisputed evidence confirmed that Valve A was not in-service from January 2002 through April 2004, and that the OPS inspector reviewed field notes from an Alyeska technician which indicated that Valve B was also not in-service from November 2002 through October 2003. I also stated that, according to Petitioner, the technician who prepared those field notes worked on both Valve A and Valve B and had erroneously marked the latter as out-of- service after working on the former. I also indicated that Alyeska sought to substantiate that argument by submitting documentation from its electronic records system, namely, the automatically-generated work order forms provided to the technician who worked on Valve A and Valve B in 2002 and 2003. However, I concluded that Petitioner’s evidence failed to establish the in-service status of Valve B during the disputed 11-month period. With regard to the work order forms Alyeska submitted from its electronic records system, I pointed out that the technician initialed all of the steps on the 2002 work order form for Valve B as complete, except for the two that specifically related to returning that valve to service. That omission, I explained, corroborated the allegation that Valve B was out of service. Moreover, I rejected Petitioner’s argument that even if Valve A and Valve B were both out of service for an 11-month period, its procedures still provided adequate overpressure protection. After noting that the regulation explicitly requires “adequate controls and protective equipment, could, or actually did, accomplish both of those objectives. For those reasons, I found that Alyeska violated § 195.406(b). ”9 I determined that Alyeska had not shown that its procedures On reconsideration, Petitioner argues that I erred in failing to acknowledge that its electronic records for valve maintenance comply with Part 195 of the Pipeline Safety Regulations. Alyeska further argues that I erred in failing to find that those electronic records establish that Valve B was in-service from November 2002 through October 2003. Petitioner’s first argument is not persuasive. Nothing in the Final Order suggests that I refused to consider Alyeska’s electronic valve maintenance records for lack of compliance with the Pipeline Safety Regulations. To the contrary, I carefully examined and discussed those records at length. Nonetheless, I find on further review of the record that Petitioner’s second argument has merit. OPS bears the burden of persuasion in an enforcement proceeding and must prove, by a preponderance of the evidence, that the facts necessary to sustain a probable violation actually occurred. 10 Moreover, the party which bears the burden of persuasion 9 49 C.F.R. § 195.406(b). 10 Butte at p.2, n.3 (Aug. 17, 2009); see also, Schaeffer v. Weast, 546 U.S. 49, 56-58 (2005).#

520055023_Decision on the Petition for Reconsideration_12162009_text.pdf, page 65 on a material issue of fact in a proceeding “loses if the evidence is closely balanced[.]”11 Thus, if the evidence for and against the occurrence of a fact necessary to show a violation of the Pipeline Safety Regulations is essentially equal, OPS cannot meet its burden of persuasion and the allegation of probable violation must be withdrawn. The material issue of fact in this case is the operational (or nonoperational) status of Valve B from November 2002 through October 2003. The evidence in favor of OPS’s position is the failure of Alyeska’s technician to initial the steps on the 2002 work order form for returning that valve to service. However, Petitioner’s official electronic records indicate that Valve B was in-service from November 2002 through October 2003, which tends to disprove the allegation in the Notice. I am ultimately responsible for assessing the credibility and weight that should be against this material issue of fact here—i.e., whether or not Valve B was in-service for the 11-month period—is essentially equal. I must, therefore, find that OPS has not met its burden of persuasion. For that reason, I am withdrawing the Finding of Violation and afforded to the evidence of record in a proceeding.12 However, the evidence for and Civil Penalty for Item 6(c) and modifying the Final Order to reflect that determination. C. Finding of Violation for Item 8 In the July 2009 Final Order, I found that Alyeska violated the regulation that requires “[e]ach operator” of a hazardous liquid pipeline facility to “maintain adequate firefighting equipment at each pump station and breakout tank area,” and to ensure that such equipment is “[i]n proper operating condition at all times[,] [p]lainly marked so that its identity as firefighting equipment is clear[,] and [l]ocated so that it is easily accessible during a fire.”13 Specifically, I stated that Petitioner removed all of the firefighting equipment from a manifold building at one of the TAPS pump stations; that this manifold building contained a portion of the TAPS 48-inch mainline pipe, as well as two 48-inch ball valves and 42-inch and 36-inch blind flanges; and that the absence of any firefighting equipment would hinder Alyeska’s ability to extinguish a fire within that building. I also noted that Petitioner argued that the pump station was not operational; that the manifold building was not heated and generally not occupied, and contained no combustible materials and few, if any sources ignition sources; and that Alyeska had, therefore, determined that the provision of fire extinguishers in the manifold building would be “superfluous”. 11 Schaeffer, 546 U.S. at 56. 12 See Federal Trade Commission v. Pacific States Paper Trade Association, 273 U.S. 52, 63 (1927) (“The weight to be given to the facts and circumstances admitted as well as the inferences reasonably to be drawn from them is for the Commission.”). 13 49 C.F.R. § 195.430(a)-(c).#

520055023_Decision on the Petition for Reconsideration_12162009_text.pdf, page 76 On reconsideration, Alyeska argues that PHMSA acted arbitrarily and capriciously in applying § 195.430 to the manifold building at this TAPS pump station. More specifically, Petitioner contends that while PHMSA could regulate such a facility under the Pipeline Safety Laws, Part 195 of the Pipeline Safety Regulations only applies to pump stations that are “used in the transportation of hazardous liquids” or “through which a hazardous liquid moves in transportation . . . ” Citing the fact that this facility was taken out of service in 1996, a process that included physically disconnecting the station piping and tanks from the 48-inch mainline, Petitioner asserts that from that date forward this TAPS pump station was no longer used in the transportation of hazardous liquids or subject to any of the requirements of Part 195 Pipeline Safety Regulations. I do not find this argument persuasive. The Office of Pipeline Safety (OPS) inspected the TAPS in September 2004, and the Director, Western Region, OPS, issued Alyeska this Notice by letter dated July 19, 2005. One day later, on July 20, 2005, the Joint Pipeline Office (JPO) sent Petitioner a letter responding to the company’s prior request “to rescind the 180-day restart requirement” for several “rampdown pump stations,” including the one identified in the Notice. JPO explained it had imposed a 180-day restart requirement on those rampdown pump stations “to ensure that TAPS was capable of transporting increased North Slope production, if necessary.” However, after reviewing Petitioner’s recent reconfiguration of its pipeline operations, the JPO determined that the TAPS could maintain the necessary throughput without the rampdown pump stations. Therefore, the JPO agreed to rescind the 180-day restart requirement and ordered Alyeska to submit “a demobilization plan for the rampdown pump stations.” The foregoing confirms that the Pipeline Safety Regulations applied to the pump station and manifold building identified in the Notice at the time of the OPS inspection. Once a hazardous liquid pipeline facility is placed in service, that facility is subject to the requirements of Part 195 until it is abandoned, i.e., “permanently removed from service.”14 The JPO letter confirms that the disputed pump station was subject to a 180- day restart requirement through July 20, 2005, and thus only temporarily—but by no means permanently—removed from service prior to that time. In other words, that pump station and the manifold building were still “pipeline facilities used in the transportation of hazardous liquids” at the time of the OPS inspection. 15 14 49 C.F.R. § 195.2; see In the Matter of Equistar Chemicals, LP, PHMSA Interp. No. 08-003 (Apr. 6, 2009) (available at www.phmsa.dot.gov/pipeline/regs/interps) ( “ceasing normal operation of a pipeline does not remove the pipeline from PHMSA’s jurisdiction[;] [but] [i]f you have abandoned a Part 195 jurisdictional pipeline according to 195.402(c)(10), the requirements no longer apply[;] [however,] [t]he abandoned pipeline may not be returned to service unless the pipeline was maintained according to Part 195 requirements while it was abandoned, or meets the requirements of a newly designed and constructed pipeline.”) 15 49 C.F.R. § 195.0 (prescribing the scope of Part 195).#

520055023_Decision on the Petition for Reconsideration_12162009_text.pdf, page 87 For these reasons, I find that the requirements of Part 195 of the Pipeline Safety Regulations, including § 195.430, applied to the pump station and manifold building at all times relevant to this proceeding. I am, therefore, denying Petitioner’s request for reconsideration of the Finding of Violation for Item 8 and affirming that part of the Final Order without modification. D. Findings of Violation for Items 10(a) and 10(b). Finally, I found in the July 2009 Final Order that Alyeska violated 49 C.F.R. 195.573(a)(1), the regulation that requires an operator to monitor the external corrosion control on cathodically-protected pipelines by “[c]onducting tests on the protected pipeline at least once each calendar year, but with intervals not exceeding 15 months.”16 Specifically, I stated that Petitioner’s records showed that the company had not tested the cathodic protection on the TAPS mainline at numerous cased-road crossings for more than two years, i.e., from June 2002 until September 2004, the date of the OPS inspection. I also noted that Alyeska conceded the allegation that no cathodic protection testing had occurred during the 27-month period, but argued that § 195.575 was the only regulation that applied to cased pipeline segments and therefore, it could not have violated § 195.573(b). I further observed that Alyeska argued, in the alternative, that §195.573 requires that buried pipelines be electrically isolated, but does not prescribe a specific interval for testing the adequacy of that electrical isolation. Consequently, Petitioner argued it had the discretion to adopt and follow a three-year test interval, rather than an annual test interval. However, I found neither of these arguments persuasive. First, I observed that at the time of the OPS inspection, Petitioner’s written procedures called for annual testing of the electrical isolation of the TAPS mainline at cased-road crossings, and that company’s decision to adopt a triennial testing interval only occurred after the inspection. I further stated that the adequacy of a pipeline’s cathodic protection cannot be determined without annual testing of the actual pipeline within the casing. In particular, I explained that simply testing the cathodic protection of the pipeline at either end of a casing may not reveal an inadequacy affecting the segment within that casing, and that this situation if left undetected, increased the likelihood of external corrosion and a resulting failure. Moreover, I also stated that the purpose of § 195.575 is to the ensure adequacy of electrical isolation at initial installation, but that “all post-installation inspections and tests that the annual testing requirement of 49 C.F.R. 195.573(a)(1) applies to pipeline of cathodic protection facilities are covered by final § 195.573.”17 Accordingly, I found segments at cased-road crossing, and that Alyeska failed to comply with that requirement. 16 49 C.F.R. § 195.573(a)(1). 17 66 Fed. Reg. 66994, 67000 (Dec. 27, 2001).#

520055023_Decision on the Petition for Reconsideration_12162009_text.pdf, page 98 On reconsideration, Petitioner argues that the latter finding is arbitrary and capricious, as the evidence of record shows that the company checked the corrosion-control coupons “in the vicinity of the[se] cased road crossings . . . in 2003.” As noted in the Final Order, simply testing the cathodic protection of a pipeline “in the vicinity” of a cased road crossing does not establish compliance with § 195.753(a)(1). To the contrary, an operator must actually test the cathodic protection for the pipeline within the casing on annual basis, and the evidence of record does not show that such testing occurred. Accordingly, I am denying Petitioner’s request for reconsideration of the Findings of Violation for Items 10(a) and 10(b) and affirming that part of the Final Order without modification. II. Conclusion For the reasons stated in Part I of this decision, I am modifying the Final Order in the following respects: the $1,000 Civil Penalty for Item 5(b) and the $1,000 Civil Penalty for Item 5(c) are withdrawn; a Warning is issued for Item 5(b) and Item 5(c); and the Finding of Violation, $55,000 Civil Penalty, and Compliance Order for Item 6(c) are all withdrawn. Petitioner must pay the reduced civil penalty in the amount of $27,000 in accordance with the terms set forth in the Final Order. The Final Order is affirmed in all other respects without modification. This decision on reconsideration is the final administrative action in this proceeding. _____________________________ __________________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety#