ALYESKA PIPELINE SERVICE CO — Notice of Probable Violation

party submissionOfficial PDF520135008_Operator Response_11042013.pdf#

520135008_Closure Letter_07132017_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED July 13, 2017 Mr. Rod Hanson Senior Vice President, Operations and Maintenance Alyeska Pipeline Service Company 3700 Centerpoint Drive Anchorage, Alaska 99503 CPF 5-2013-5008 Closure Letter Dear Mr. Hanson: On October 8, 2015, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to the Alyeska Pipeline Service Company 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, 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, Dustin B. Hubbard Acting Director, Western Region Pipeline and Hazardous Materials Safety Administration cc: PHP-60 Compliance Registry PHP-500 H. Marlowe (#132739)#

520135008_Final Order_10082015_text.pdf, page 1Official PDFOctober 8, 2015 Mr. Tom Barrett, President Alyeska Pipeline Service Company 3700 Centerpoint Drive P.O. Box 196660 Anchorage, AK 99503 Re: CPF No. 5-2013-5008 Dear Mr. Barrett: Enclosed please find the Final Order issued in the above-referenced case. It makes one finding of violation, assesses a civil penalty of $145,000, and specifies actions that need to be taken by Alyeska Pipeline Service Company 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 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, OPS Mr. Michael W. Joynor, Senior Vice President, Operations, Alyeska Pipeline Service Company CERTIFIED MAIL - RETURN RECEIPT REQUESTED#

520135008_Final Order_10082015_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. 5-2013-5008 ) Respondent. ) ____________________________________) FINAL ORDER On January 8, 2011, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), responded to and began an investigation of a crude-oil release at Pump Station 1 (PS-01) of the Trans-Alaska Pipeline System (TAPS) operated by Alyeska Pipeline Service Company (Alyeska). TAPS transports crude oil from Alaska’s North Slope across 800 miles of varied Alaskan terrain to Valdez, Alaska, North America’s northernmost ice-free port.1 On that same date, Alyeska had discovered crude oil flowing into the PS-01 booster pump basement under insulation at the 4th Unit Booster Pump discharge line basement wall penetration (2011 Failure). As a result of PHMSA’s subsequent investigation, the Director, Western Region, OPS (Director), issued to Respondent, by letter dated August 1, 2013, a Notice of Probable Violation, Proposed Compliance Order, and Proposed Civil Penalty (Notice or NOPV). In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that Alyeska had violated 49 C.F.R. § 195.579 and proposed assessing a civil penalty of $145,000 for the alleged violation. The Notice also proposed ordering Respondent to take certain measures to correct the alleged violation. Alyeska responded to the Notice by letter dated November 4, 2013 (Response). The company contested the allegation for Item 1, offered additional information in response to the Notice, and requested that the proposed civil penalty be reduced and the Proposed Compliance Order be withdrawn. It also submitted supplemental information in a subsequent letter dated August 26, 2014 (Supplemental Response). Respondent did not request a hearing and therefore has waived its right to one. 1 http://www.alyeska-pipe.com/TAPS/PipelineOperations (last accessed on June 4, 2015).#

520135008_Final Order_10082015_text.pdf, page 3CPF No. 5-2013-5008 Page 2 FINDING OF VIOLATION The Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows: Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.579(a), which states: § 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. The Notice alleged that Respondent violated 49 C.F.R. § 195.579(a) by failing to take adequate steps to mitigate internal corrosion in “deadlegs” (i.e., process piping sections that have been isolated and no longer maintain a flow of liquid or gas) and areas of low flow on TAPS, which transports a hazardous liquid that would corrode the pipeline. Specifically, the Notice alleged that Alyeska had been aware since at least 2008 that TAPS faced the risk of internal corrosion but failed to take adequate steps to control it. It alleged that the 2011 Failure was directly caused by internal corrosion. According to PHMSA, Alyeska hired a contractor, Det Norske Veritas (DNV), in 2011 to conduct a root cause analysis of the 2011 Failure. DNV’s final report determined that the direct cause of the leak was microbiologically influenced corrosion (MIC) and noted five causal factors, all related to inhibit internal corrosion.2 Finally, PHMSA alleged that Alyeska had installed a sleeve on piping at Pump Station 9 in 2013 to remediate internal corrosion that had been causing significant (approximately 40%) pipe wall loss and that such repair showed that the company’s internal corrosion program continued to be inadequate. Alyeska responded to the Notice in writing on November 4, 2013 (Response). Alyeska disputed PHMSA’s allegation that the company had been aware of internal corrosion problems on TAPS as early as 2008 but failed to take adequate steps to mitigate it.3 The company stated that “the [Notice] does not fully acknowledge the work that Alyeska has performed to improve its Integrity Management program beginning in 2008 until the present”4 and outlined five principal measures it had taken to address the problem. First, Alyeska contended that since 2008, it had optimized its procedures for microbiological monitoring, that it had used and assessed the effectiveness of appropriate biocide and corrosion 2 The Notice alleged that DNV specifically found five causal factors for the 2011 Failure: “a. [Pump Station 1] Booster #4 not added, b. No bio testing/ biocide injection, c. Non-biocide inhibitor began in mid-90s, d. Risk mitigation less than adequate on urgency to replace piping, and e. Lack of accessibility to inspect below ground deadleg/low flow pipe segments.” 3 Alyeska also challenged the Proposed Compliance Order and proposed civil penalty amount. I will address those arguments in the appropriate sections below. 4 Response, Attachment, at 2.#

520135008_Final Order_10082015_text.pdf, page 4CPF No. 5-2013-5008 Page 3 inhibitors, and that it had assessed chloride sources. The company further asserted that in 2008, it had contracted with Baker Petrolite, a nationally-recognized expert in the field, to perform a corrosivity study for the crude oil flowing into TAPS. Alyeska claimed that it had used the results of that study “to optimize the corrosion inhibition and biocide treatment programs and tested recommended inhibitors and biocides using actual TAPS crude-oil and water samples.”5 Alyeska further stated that it had subsequently hired Baker Hughes to assess the company’s internal corrosion inhibitor program and to assist Alyeska in improving its effectiveness. Alyeska received an independent evaluation of the crude oil and water for corrosive elements from Baker Hughes, which provided recommendations for a more effective internal corrosion inhibitor program. Alyeska claimed that it had re-evaluated and revised its inhibitor-injection program based on this report, had revised its procedures for biocide and inhibitor treatments in Fall 2010, and had begun biocide treatments at Pump Station Three and Pump Station Four in November 2010 and in pump station facility piping in February 2011. It also claimed that it had treated PS-01 crude tanks with biocide in May 2011 and begun system biocide-treatment monitoring of bacteria levels in April 2011, which showed locations where bacteria counts were decreasing, an indicator of biocide effectiveness.6 Alyeska also engaged DNV to perform a root cause analysis of the booster pump leak at PS-01, which was completed on December 7, 2011. Alyeska created a Management Action Plan to address the identified causes of the leak. This included a 2012 Baker Hughes “assessment of chlorides and their potential impact on corrosion acceleration.”7 Second, Alyeska argued that it had taken steps to replace or modify certain pipeline infrastructure that the company believed to be susceptible to internal corrosion. This included the removal of deadlegs and bringing certain facility piping above ground as part of the crude-oil piping assessment and replacement required under a 2011 Consent Agreement with PHMSA.8 Third, the company argued that it had been expanding its Pipeline Integrity Testing (PIT) program for internal inspections and assessments and researching new technologies that potentially allowed the inspection of previously-inaccessible piping. These included guided wave, electro-magnetic acoustic transducers, and robotic crawler “pigs.”9 Fourth, contrary to PHMSA’s allegation that the installation of a sleeve over corroded pipe at Pump Station 9 in April 2013 demonstrated the inadequacy of the company’s internal corrosion program, Alyeska asserted that this repair “does not demonstrate that the internal corrosion 5 Id, at 3. 6 Id. 7 Id. at 4. 8 In the Matter of Alyeska Pipeline Service Company, CPF 5-2011-5001S (August 17, 2011). Available at: http://primis.phmsa.dot.gov/comm/reports/enforce/CONOEvent opid 0.html?nocache=3154# TP 1 tab 5. 9 Response, at 4-5.#

520135008_Final Order_10082015_text.pdf, page 5CPF No. 5-2013-5008 Page 4 inhibitor program is inadequate. The purpose of the program is to provide monitoring, prevention, and repair to maintain pipeline integrity…Installing any sleeve enhances the effectiveness of the overall, system integrity management program and is not a measure of the effectiveness of the corrosion inhibitor.”10 Fifth, in its Supplemental Response, Alyeska provided further information regarding the adequacy of its internal-corrosion mitigation efforts. Alyeska stated that it was currently performing flow studies, which indicated that “[l]aminar flow conditions are not reached until TAPS flow rates are in the 200,000 barrels per day (BPD) range.” This rate is not expected to be reached for several more years.11 Alyeska stated that although bacteria levels and corrosion rates were shown to be increasing at some corrosion-coupon locations in its previously-submitted Bacteria Testing Analysis PowerPoint presentation, TAPS was primarily experiencing corrosion rates under 0.1 mils per year or less, which are considered low by NACE criteria. Additionally, Alyeska described its process for ensuring the integrity of TAPS valve bypasses, including visual inspections for evidence of external corrosion as well as non-destructive testing for evidence of internal corrosion.12 After careful consideration of all these arguments and all of the evidence in the record, I am unpersuaded that Alyeska took adequate steps from 2008 to 2011 to mitigate internal corrosion on TAPS deadlegs and in low-flow areas. While it is clear that the company did take a number of steps, particularly after the 2011 Failure, to deal with the company’s complex and longstanding problems with MIC, the fact remains that the 2011 Failure itself constitutes strong evidence that the efforts Alyeska had been making prior to that time were inadequate to mitigate internal corrosion in low-flow piping. As stated in the Notice, DNV’s root cause analysis of the 2011 Failure concluded that the direct cause of the oil leak was MIC and five other generic causes, including “[l]ess than adequate process for corrosion inhibitor selection.” Alyeska was aware of these inadequacies several years before the 2011 release. In 2008, Alyeska released a risk assessment report, titled “Removing Concrete from PS-01 Buried Piping for Internal Corrosion Investigation.” Alyeska’s evaluation concluded that in order to deal with the active corrosion problems affecting the PS01 below-ground piping, it was necessary to obtain corrosion data for the welds on this buried piping. The report stated that if no data were available, [A]lyeska assumes a high probability of significant, active corrosion associated with the belowground welds. . . Due to the high risks of interrupting crude oil supply, every scenario the team evaluated recommends replacing the buried pipe (i.e., the booster pump suction line, over and short line, suction and discharge relief lines) and 10 Id. at 5. 11 Laminar, as opposed to turbulent, flow could allow a corrosive environment to accumulate near the walls of the pipeline and possibly contribute to internal corrosion or enhance existing internal corrosion. 12 Supplemental Response, at 3.#

520135008_Final Order_10082015_text.pdf, page 6CPF No. 5-2013-5008 Page 5 possible replacement or modification of the related facilities. 13 Despite such warnings from its own study, the company chose to continue using the existing piping without taking appropriate steps to mitigate the internal corrosion that eventually resulted in a release . In essence, Alyeska addressed the corrosion problem on the below-ground piping symptomatically, contracting a corrosivity study with Baker Petrolite and an evaluation of the internal corrosion inhibitor program with Baker Hughes but not taking action that would properly correct the corrosion that led to the 2011 Failure. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.579(a) by failing to take adequate steps to mitigate internal corrosion in deadlegs and areas of low flow in TAPS. This finding of violation will be considered a prior offense in any subsequent enforcement action taken against Respondent. Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed $100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any related series of violations. In determining the amount of a civil penalty under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature, circumstances, and gravity of the violation, including adverse impact on the environment; the degree of Respondent’s culpability; the history of Respondent’s prior offenses; 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 $145,000 for the violation cited above. Item 1: The Notice proposed a civil penalty of $145,000 for Respondent’s violation of 49 C.F.R. § 195.579(a), for failing to take adequate steps to mitigate internal corrosion in deadlegs and areas of low flow in TAPS. Alyeska objected to the proposed civil penalty on several grounds. First, it argued that a comparison with other NOPVs issued by PHMSA to other operators in 2013 “demonstrates that similar violations related to corrosion control, integrity assessment programs, cathodic protection programs, and inline inspection requirements, all regulatory requirements under Pipeline Integrity Management or Subpart H, Corrosion Control resulted in lower penalty amounts.”14 Specifically, it argued that Buckeye Partners received three NOPVs in 2013 alleging violations of corrosion-related regulations. Each had proposed penalties of less than $100,000; two of the ASSESSMENT OF PENALTY 13 Pipeline Safety Violation Report (August 1, 2013) (on file with PHMSA), at Exhibit 7, at 4. 14 Response, at 5-6.#

520135008_Final Order_10082015_text.pdf, page 7CPF No. 5-2013-5008 Page 6 three were multiple-violation notices. Similarly, Texas Eastern Transmission was issued an NOPV with three probable violations, only one of which was corrosion-related, with a proposed penalty of $33,700. Centerpoint Energy Gas Transmission had an NOPV with 10 alleged violations, five of which were integrity- or corrosion-related. Although the total proposed penalty in that case was $137,200, the proposed penalties for the integrity-related alleged violations totaled only $87,900. PHMSA issued an NOPV to Jayhawk Pipeline for four alleged violations of regulations involving high consequence areas (HCAs), yet the proposed penalty was only $82,400. BP Pipeline (North America) received an NOPV in 2013 with alleged violations of integrity management programs, including HCA regulations. Although there were six probable violations, the proposed penalty was $100,000. According to Alyeska, each of these cases had similar probable violations, yet all had proposed penalties that were less, some significantly less, than the $145,000 proposed in this case.15 Alyeska further argued that because 49 C.F.R. § 190.225 is “silent on the consideration of potential harm,….PHMSA should be considering only actual harm, such as personal injury or adverse impact on the environment when assessing the gravity of an alleged violation.” The company cited another 2013 case in which Kinder Morgan Liquids Terminals, LLC, received an NOPV in 2013 for an accident in which an employee had been injured and yet the proposed penalty was only $100,000. In contrast, Alyeska argued that in the current case, no harm occurred. Therefore, Alyeska argued, the proposed penalty is unsupported by the nature, circumstances and gravity of the violation when compared to other cases involving personal injury or damage to the environment.16 Second, the company argued, with regard to culpability, that it had acted diligently, not recklessly or negligently, in taking remedial action to mitigate internal corrosion. Alyeska contended that its internal corrosion inhibitor program was designed to create an awareness of, and to address, the consequences of moving hazardous liquid in TAPS. Third, Alyeska argued, with regard to its history of prior offenses, that it had four prior enforcement actions alleging violations of § 195.579, but three did not have any proposed penalties. The remaining NOPV had a proposed penalty of only $11,000 for each of the applicable probable violations. Fourth, Alyeska argued, with respect to the lack of a penalty reduction for good faith, that it had indeed demonstrated good-faith efforts to achieve compliance with § 195.579, through the various measures discussed above. According to the company, these various efforts should serve as “a mitigating factor” that would support a reduction of the proposed civil penalty.17 Fifth, Alyeska argued that while the proposed penalty would not affect the company’s ability to continue in business, the proposed penalty could be more effectively spent on the company’s continuing program to mitigate internal corrosion. 15 Id, at 5. 16 Id, at 6. 17 Id, at 7.#

520135008_Final Order_10082015_text.pdf, page 8CPF No. 5-2013-5008 Page 7 I have carefully reviewed the record, considered Alyeska’s five arguments for a penalty reduction, and evaluated the proposed penalty in this case relative to other recent enforcement cases cited by Respondent. I find the company’s arguments unpersuasive. Specifically, I find the proposed penalty to be reasonable and consistent with PHMSA’s civil penalty assessment criteria. Alyeska has put great store in comparing the proposed penalty in the present case with those proposed against other operators in 2013. While PHMSA strives for consistency in its analysis and calculation of proposed civil penalties, the wide range in penalty amounts among the cases cited by Respondent is directly attributable to material differences in the facts that serve as the underlying basis for considering each penalty factor. The greatest shortcoming in Respondent’s analysis is that none of the other 2013 NOPVs cited by Alyeska involved an accident. 18 In the present case, there was an actual release of crude oil from TAPS that was a reportable incident causally related to the alleged violation. Additionally, Alyeska cited one of its own cases where it was cited $11,000 for the same violation. Again, that particular case did not involve an accident. Further, it is misleading to compare a penalty assessed against one operator with one assessed against another operator for the same regulatory violation, since PHMSA’s assessment criteria do not depend upon the substantive content or subject matter of a regulation (e.g., internal corrosion, welding, or valve inspections) to determine a proposed penalty, but, rather, rely upon the nature, circumstances, gravity of the violation and other factors. These penalty factors and the factual basis for each one are set forth in detail in PHMSA’s standardized Violation Report and serve as the actual framework for proposing penalties. These factors are applied consistently to all operators across all regions of the country. In summary, I find nothing in the assessment of the proposed penalty in this case that is inconsistent or out of line with those assessed in the other recent cases cited by Respondent. Accordingly, having reviewed the record and considered the assessment criteria, I assess the Respondent a total civil penalty of $145,000 for violation of 49 C.F.R. § 195.579(a). Payment of the civil penalty must be made within 20 days of service. Federal regulations (49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed instructions are contained in the enclosure. Questions concerning wire transfers should be directed to: Financial Operations Division (AMK-325), Federal Aviation Administration, Mike Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, Oklahoma 73125. The Financial Operations Division telephone number is (405) 954-8845. 18 As noted earlier, Alyeska cited a case involving Kinder Morgan Liquids Terminals, LLC [CPF 1-2013-5004], “in which an employee was injured and yet the proposed penalty was only $100,000.” This is incorrect. The Kinder Morgan case actually involved five probable violations arising out of an accident, but the total proposed (and uncontested) penalty in the case was $500,000, not $100,000, as stated by Alyeska. The Kinder Morgan case actually reinforces the large difference that exists between penalties for violations that constitute causal factors in accidents and those that do not.#

520135008_Final Order_10082015_text.pdf, page 9CPF No. 5-2013-5008 Page 8 Failure to pay the $145,000 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 district court of the United States. COMPLIANCE ORDER The Notice proposed a compliance order with respect to Item1 in the Notice, for a violation of 49 C.F.R. § 195.579(a). 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. Alyeska stated that the Proposed Compliance Order should be withdrawn because the work that was proposed has already been completed. The Director has reviewed the Response and acknowledges that Respondent has completed most of the Proposed Compliance Order items. However, Alyeska has not demonstrated that it has completed Item (1)(a) of the Proposed Compliance Order by optimizing its procedures for microbiological monitoring or biocide-dosing protocols for current and anticipated future flow rates. Therefore, 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 action to ensure compliance with the pipeline safety regulations applicable to its operations: 1. With respect to the violation of § 195.579(a) (Item 1), Respondent must optimize procedures for microbiological monitoring, especially effectiveness in deadlegs and low-flow areas, as well as biocide-dosing protocols to mitigate MIC for current and anticipated future flow rates. Such work must be completed no later than 180 days following receipt of this Order. 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 $200,000 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. Under 49 C.F.R. § 190.243, 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 will accept petitions received no later than 20 days after receipt of service of this Final Order by#

520135008_Final Order_10082015_text.pdf, page 10CPF No. 5-2013-5008 Page 9 the Respondent, provided they contain a brief statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.243. The filing of a petition automatically stays the payment of any civil penalty assessed. Unless the Associate Administrator, upon request, grants a stay, all other terms and conditions of this Final Order are effective upon service in accordance with 49 C.F.R. § 190.5. ___________________________________ __________________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety#

520135008_NOPV PCO PCP_08012013_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED COMPLIANCE ORDER and PROPOSED CIVIL PENALTY CERTIFIED MAIL – RETURN RECEIPT REQUESTED August 1, 2013 Mr. Tom Barrett President Alyeska Pipeline Service Company 3700 Centerpoint Drive P.O. Box 196660 Anchorage, AK 99503 CPF 5-2013-5008 Dear Mr. Barrett: On January 8, 2011, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), pursuant to Chapter 601 of 49 United States Code, responded to and began an investigation of a crude oil release at Pump Station 1 (PS-01) of the Trans-Alaska Pipeline System (TAPS) operated by Alyeska Pipeline Service Company (Alyeska). Background TAPS is an 800 mile, 48-inch diameter pipeline. Alyeska has operated TAPS since 1977, transporting crude oil from Prudhoe Bay to the Valdez Marine Terminal in Alaska. The unique environment and circumstances under which TAPS operates pose many challenges for the pipeline. The challenges Alyeska faces include seismic instability, permafrost, cold temperatures, the vast distance of land the pipeline travels, mountainous and rugged terrain, remote locations along the pipeline, and internal and external corrosion. In 1988, Alyeska discovered internal corrosion in sections of pipe known as deadlegs which experienced only occasional or low flow movement of oil. Alyeska reported that the cause of this internal corrosion was water that was deposited by the crude oil and settled in the bottom of the pipe.1 1 GAO Report to the Chairman, Subcommittee on Water, Power, and Offshore Energy Resources, Committee on Interior and Insular Affairs, House of Representatives, RCED91-89, Trans-Alaska Pipeline, July 1991, page 24.#

520135008_NOPV PCO PCP_08012013_text.pdf, page 2In 2007, Alyeska discovered internal corrosion in the heat-affected zone of girth welds in sections of pipe that were being removed from PS-01. An Alyeska summary of the corrosion noted that this section of the piping system at PS-01 has low oil flow compared to the mainline pipe, that low flow rates can increase the potential for water and sediment to settle at the bottom of the pipe and provide a corrosive environment, and that the facility piping systems are not piggable by either cleaning pigs or in-line inspection pigs.2 On April 1, 2008, PHMSA issued a Notice of Probable Violation alleging that Alyeska had failed to provide any records to demonstrate that it had investigated the corrosive effects of the hazardous liquids transported and that it had not taken adequate steps to mitigate internal corrosion in the TAPS mainline.3 In Alyeska’s written response, the company stated “Alyeska has not analyzed the crude oil transported in TAPS.”4 Alyeska asserted that it mitigated internal corrosion through the use of an aggressive maintenance pigging program, chemical inhibitors, and corrosion coupons. Nonetheless, Alyeska agreed in a Compromise Agreement dated November 16, 2011, that the company had committed these violations. The Compromise Agreement also stated that the company had developed and implemented an internal corrosion mitigation program. In September 2008, Alyeska discovered internal corrosion adjacent to girth welds in tank lines at PS-01 and filed a Safety-Related Condition Report with the Office of Pipeline Safety. The flow rate in these tank lines is significantly less than the flow rate on the mainline pipe. Alyeska installed five sleeves over areas with significant pipe wall loss, including two areas with over 80% wall loss.5 In February 2010, PHMSA inspectors noted in the Safety-Related Condition Report that “Alyeska has completed a conceptual engineering study of the active below ground DOT covered piping. This study identified piping that was… difficult to inspect due to structural interference. Alyeska is currently conducting a preliminary engineering study to determine project details for the subset of this work at PS01.” Alyeska’s 2008 Annual Report for Pipeline and Valdez Marine Terminal Facilities Corrosion Monitoring was sent to the Joint Pipeline Office (JPO) on April 17, 2009. This report shows that the company questioned the effectiveness of a corrosion inhibitor that it was using on TAPS: “The use of RU248, which is formulated for corrosion caused by dissolved acid gases, may no longer be effective in APSC system due to changing crude oil characteristic. This is because corrosion induced bacteria has been identified in several locations at the facilities…. IME [Alyeska’s Integrity Management Engineering department] recommends and will be conducting an evaluation of current corrosion inhibitor effectiveness by conducting a study on all segments of the facilities; a recommendation and implementation of the most effective chemical that inhibits corrosion will be completed.”6 In 2009, the JPO requested information on the internal corrosion at PS-01. Alyeska responded 2 GL 17088, Exhibit 5, page 1. 3 Notice of Probable Violation, CPF No. 5-2008-5008. 4 See GL 16053, May 22, 2008, Finding 5, pages 2-3. 5 PHMSA OPS Safety Related Condition Report 20080077. 6 Trans Alaska Pipeline System 2008 Annual Report for Pipeline and Valdez Marine Terminal Facilities Corrosion Monitoring, page 20, Appendix A, Table 5. 2#

520135008_NOPV PCO PCP_08012013_text.pdf, page 3that they had performed a risk assessment on October 6, 2008, and decided not to excavate the concrete boxes at PS-01 to inspect for corrosion on the below ground piping.7 In addition, Baker Petrolite, a contractor Alyeska selected to evaluate the corrosivity of TAPS crude oil, reported “significant levels of bacteria in the Alyeska system which have the potential to cause corrosion.”8 Specifically, Baker Petrolite noted that “[b]ased on the current test results, it appears that facility piping which is not in turbulent flow and able to be pigged has the potential for bacteria corrosion problems.”9 In December of 2009, Baker Petrolite reported to Alyeska the results of a bacteria enumeration survey that it conducted in fall of 2009 on the pipeline deadlegs. The report stated: “The basic conclusion from this survey is that Pipeline and the Valdez Marine Terminal have bacteria in numbers that can and will degrade the integrity of the measured systems.”10 On June 24, 2010, Alyeska met with PHMSA and made a presentation regarding its internal corrosion program. The materials Alyeska provided during that presentation indicated that it had been analyzing the corrosivity of the crude oil and water in TAPS since 2007, that the internal corrosion inhibitor that it had been using was ineffective for the type of bacteria found in TAPS, and that the company planned to begin using a new corrosion inhibitor treatment program by September 15, 2010.11 The company also planned to treat all deadlegs in the system according to the new inhibitor program in September and October of 2010.12 On January 8, 2011, crude oil was discovered flowing into the PS-01 booster pump basement under the insulation at the 4th Unit Booster Pump discharge line basement wall penetration. Alyeska contracted with Det Norske Veritas (DNV) to perform the metallurgical analysis of the removed pipe segment. DNV produced a report, “PS01 Booster Pump Manifold Failure Investigation: Laboratory Analysis September 12, 2011,” which concluded: “High levels of bacteria were found in solids and swabs taken from the area of pitting associated with the leak location…. The presence of microorganisms on the pipe surfaces combined with the undercutting pit morphology observed in the metallographic cross-sections indicates that microbiologically influenced corrosion (MIC) is likely the primary corrosion mechanism.”13 In 2011, Alyeska contracted with DNV to perform a Root Cause Analysis of the PS-01 crude oil release. The final Root Cause Analysis report, dated December 7, 2011, concludes that the direct cause of the oil leak was Microbiologically Influenced Corrosion (MIC), and that five causal factors were: “a. PS01 Booster #4 not added, b. No bio testing/ biocide injection, c. Non-biocide inhibitor began in mid-90s, d. Risk mitigation less than adequate on urgency to replace piping, and e. Lack of accessibility to inspect below ground deadleg/low flow pipe segments.” The report states, “Some of the causal factors have a very long historical influence on the potential 7 GL 18303, Exhibit 7, Removing Concrete from PS01 Buried Piping for Internal Corrosion Investigation, page 16. 8 GL 18303, Exhibit 5, Baker Petrolite letter to Alyeska dated February 9, 2009, page 1. 9 GL 18303, Exhibit 5, Baker Petrolite letter to Alyeska dated February 9, 2009, page 5 10 Baker Petrolite Letter to Alyeska dated December 10, 2009, pages 1-2. 11 Alyeska Internal Corrosion Program, Integrity Management Engineering, presentation dated June 24, 2010, slide 14. 12 Id. at slide 23 13 DNV, PS01 Booster Pump Manifold Failure Investigation: Laboratory Analysis, September 12, 2011, page 19. 3#

520135008_NOPV PCO PCP_08012013_text.pdf, page 4for MIC to develop (e.g., a. and b. above).”14 DNV’s Root Cause Analysis noted six generic causes of the accident, including “Less than adequate process for corrosion inhibitor selection.”15 In response to the January 2011 release at PS-01, PHMSA issued a Notice of Proposed Safety Order (CPF 5-2011-5001S) on February 1, 2011, which proposed requiring Alyeska to implement certain safety actions to address factors involved in the release of crude oil and difficulties associated with safely restarting the pipeline. That proposed safety order resulted in a Consent Order on August 17, 2011. Once PHMSA believed the primary causal factors of the January 2011 release had been addressed, PHMSA began to focus on whether any regulatory violations had contributed to the release by reviewing the DNV metallurgical analysis and root cause analysis and the PHMSA Accident Investigation Report. In 2013, Alyeska installed a sleeve over a pipe with approximately 40% wall loss caused by internal corrosion in the 36” high-pressure (discharge) relief header at PS-9.16 This pipe has a low flow rate compared to the mainline pipe, similar to the low flow conditions in the PS-01 deadleg prior to the January 2011 release. It appears that you have committed a probable violation of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The probable violation is: 1. §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. Alyeska did not take adequate steps to mitigate internal corrosion in deadlegs and areas of low flow in TAPS. Alyeska was aware of this problem by 2008, but failed to adequately mitigate internal corrosion. PHMSA, the Joint Pipeline Office, and Alyeska’s contractors voiced numerous concerns regarding Alyeska’s internal corrosion mitigation efforts, including those being taken at PS-01, between 2008 and 2010. The leak that began at PS-01 on January 8, 2011, was caused by internal corrosion; DNV’s final Root Cause Analysis report concluded that the direct cause of the oil leak was Microbiologically Influenced Corrosion (MIC), and noted six generic causes of the accident, including “Less than adequate process for corrosion inhibitor selection.” In 2013, Alyeska installed a sleeve at PS-9 to remediate internal corrosion that was causing significant pipe wall loss, which shows that the internal corrosion program continued to be inadequate. 14 DNV, Alyeska Root Cause Analysis – PS01 Booster Pump, December 7, 2011, pages 24-25. 15 Id. at 25. PHMSA). 16 Email from Joseph P. Robertson, Alyeska, to Bill Flanders, PHMSA (May 30, 2013, 2:49pm) (on file with 4#

520135008_NOPV PCO PCP_08012013_text.pdf, page 5Proposed 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 and has recommended that you be preliminarily assessed a civil penalty of $145,000 as follows: Item number PENALTY 1 $145,000 Proposed Compliance Order With respect to item 1 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Alyeska. 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 5-2013-5008 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 cc: PHP-60 Compliance Registry PHP-Alaska (#132739) 5#

520135008_NOPV PCO PCP_08012013_text.pdf, page 6PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Alyeska Pipeline Service Company a Compliance Order incorporating the following remedial requirements to ensure the compliance of Alyeska Pipeline Services Company with the pipeline safety regulations: 1) With regard to Item Number 1 of the Notice of Probable Violation, pertaining to 49 CFR § 195.579, Alyeska must contract with a third party approved by PHMSA to complete the following: a) Optimize procedures for microbiological monitoring, especially effectiveness in deadlegs and low flow areas, as well as biocide dosing protocols to mitigate MIC for current and anticipated future flow rates no later than 180 days following receipt of the Final Order; b) Assess chloride sources and their potential impact on corrosion acceleration no later than 180 days following receipt of the Final Order; c) Determine and use the appropriate biocide and corrosion inhibitors in TAPS to mitigate the corrosive effects of the hazardous liquids on the pipeline no later than 180 days following receipt of the Final Order; d) Assess the effectiveness of item (c) no later than 270 days following receipt of the Final Order. e) Submit to PHMSA a copy of all procedures, analyses, reports, evaluations, etc., related to items (a), (b), (c), and (d) within 300 days following receipt of the Final Order. 2) PHMSA requests that Alyeska 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 should be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses, and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. 6#