SUNOCO PIPELINE L.P. — Notice of Probable Violation

party submissionOfficial PDF420165020_Operator Response to Notice_07112016.pdf#

420165020_Final Order_09152017_text.pdf, page 1Official PDFSeptember 15, 2017 Mr. Kelcy L. Warren Chief Executive Officer Sunoco Pipeline, LP 8111 Westchester Drive Dallas, TX 75225 Re: CPF No. 4-2016-5020 Dear Mr. Warren: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation, assesses a reduced civil penalty of $141,700, and specifies actions that need to be taken by Sunoco Pipeline, LP, to comply with the pipeline safety regulations. This is to acknowledge partial payment of the civil penalty in the amount of $33,700 by wire transfer dated July 13, 2016, leaving a balance due of $108,000. The payment terms for the remaining penalty 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, Southwest Region, this enforcement action will be closed. Service of the Final Order by certified mail is deemed effective upon the date of mailing, or as otherwise provided under 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Alan K. Mayberry Associate Administrator for Pipeline Safety Enclosure cc: Director, Southwest Region, Office of Pipeline Safety, PHMSA Mr. Ryan Coffey, Executive Vice-President – Operations, Sunoco Pipeline, LP, 800 E. Sonterra Boulevard, San Antonio, TX 78258 Mr. Todd Nardozzi, Senior Manager, DOT Compliance, Sunoco Pipeline, LP CERTIFIED MAIL - RETURN RECEIPT REQUESTED#

420165020_Final Order_09152017_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 ) ) Sunoco Pipeline, LP, ) CPF No. 4-2016-5020 ) Respondent. ) ____________________________________) FINAL ORDER From March 24, 2014, to July 1, 2015, 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 the facilities and records of Sunoco Pipeline, LP (Sunoco or Respondent), throughout Texas. Sunoco is now an indirect subsidiary of Energy Transfer Partners, LP, and operates approximately 6,800 miles of pipeline transporting primarily crude oil and refined products in Texas, Oklahoma, Pennsylvania, Michigan, and several other states.1 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Respondent, by letter dated June 2, 2016, a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that Sunoco had committed various violations of 49 C.F.R. Part 195 and proposed assessing a civil penalty of $169,200 for the alleged violations. The Notice also proposed ordering Respondent to take certain measures to correct the alleged violations and included a warning pursuant to 49 C.F.R. § 190.205. The warning item required no further action but warned the operator to correct the probable violation or face future potential enforcement action. Sunoco responded to the Notice by letter dated July 11, 2016 (Response). The company contested several of the allegations, offered additional information in response to the Notice, and requested that the proposed civil penalty be reduced. Respondent did not request a hearing and therefore has waived its right to one. 1 See Sunoco Logistics Partners, LP, website, at http://www.sunocologistics.com/ (last accessed August 18, 2017). On April 28, 2017, Sunoco’s general partner, Sunoco Logistics Partners, LP, announced a merger with Energy Transfer Partners, LP,which Sunoco Logistics Partners, LP, has changed its name to Energy Transfer Partners, LP.#

420165020_Final Order_09152017_text.pdf, page 3CPF No. 4-2016-5020 Page 2 FINDINGS OF VIOLATION UNCONTESTED In its Response, Sunoco did not contest the allegations in the Notice that it violated 49 C.F.R. Part 195, as follows: Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.56(a), which states: § 195.56 Filing safety-related condition reports. (a) Each report of a safety-related condition under §195.55(a) must be filed (received by OPS) within five working days (not including Saturday, Sunday, or Federal Holidays) after the day a representative of the operator first determines that the condition exists, but not later than 10 working days after the day a representative of the operator discovers the condition. Separate conditions may be described in a single report if they are closely related. Reports may be transmitted by electronic mail to InformationResourcesManager@dot.gov, or by facsimile at (202) 366- 7128. The Notice alleged that Respondent violated 49 C.F.R. § 195.56(a) by failing to file safety- related condition reports with PHMSA within five working days after determining conditions existed that met the criteria of a safety-related condition. Specifically, the Notice alleged that on December 3, 2013, Sunoco discovered nine anomalies in high consequence areas (HCAs), including KLLR-CORS 13-2A, KLLR-CORS 13-3A, KLLR-CORS 13-4A, and 13-4B, and documented the anomalies as “immediate conditions” due to physical damage to the pipeline. The KLLR-CORS 13-3A, KLLR-CORS 13-4A, and 13-4B conditions were repaired on December 18, 2013, which exceeded five working days from December 4, 2013, the date Sunoco determined safety-related conditions existed. Further, the KLLR-CORS 13-2A condition was repaired on December 19, 2013, which also exceeded five working days after the December 4, 2013 determination of the condition. Respondent did not contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.56(a) by failing to file safety- related condition reports with PHMSA within five working days after determining conditions existed that met the criteria of a safety-related condition. Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), which states: § 195.402 emergencies. Procedural manual for operations, maintenance, and (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made#

420165020_Final Order_09152017_text.pdf, page 4CPF No. 4-2016-5020 Page 3 as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. The Notice alleged that Respondent violated 49 C.F.R. § 194.402(a) by failing to follow its own written procedures for tank maintenance. Specifically, the Notice alleged that Sunoco failed to follow Subpart F, § 195.432 of its Operations and Maintenance Manual, Inspection of In-Service Breakout Tanks procedure, by not documenting conditions that could affect safe operation of its breakout tanks. The requisite documentation was allegedly not completed in the following instances: 1. During the PHMSA field inspection at Sunoco’s Ringgold facility in September 2014, the PHMSA inspector found a crack on the Tank 2703 ringwall that had been discovered by Sunoco in February 2014. Sunoco’s monthly inspection reports for Tank 2703 from February 2014 to September 2014 demonstrated that Sunoco failed to document the crack on the ringwall. 2. Tank 5 at Sunoco’s Colorado City facility was found to have approximately 10 feet of the ringwall foundation severely damaged, which was noted on the tank’s post-inspection repair report in December 2011. Sunoco’s monthly inspection reports for Tank 5 demonstrated that personnel failed to document the tank’s ringwall damage on its monthly reports from August 2012 to December 2013. The damage was repaired in 2014 after the PHMSA inspector inquired about the damage. 3. During a PHMSA field inspection at Sunoco’s Corsicana facility in September 2014, Tank 2602 was found to have a half-inch crack on the ringwall foundation. Tank 2602 monthly reports from September 2013 to August 2014 showed that Sunoco had failed to document any ringwall damage during that time. The crack was repaired in October 2014 after the PHMSA inspector inquired about the damage. Respondent did not contest these allegations of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.402(a) by failing to follow its own written procedures for tank maintenance. Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.432, which states, in relevant part: § 195.432 (a)… Inspection of in-service breakout tanks. (b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks according to API Std 653 (except section 6.4.3, Alternative Internal Inspection Interval) (incorporated by reference, see §195.3). However, if structural conditions prevent access to the tank bottom, its integrity may be assessed according to a plan included in the operations and maintenance manual#

420165020_Final Order_09152017_text.pdf, page 5CPF No. 4-2016-5020 Page 4 under §195.402(c)(3). The risk-based internal inspection procedures in API Std 653, section 6.4.3, cannot be used to determine the internal inspection interval . . . . (d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator's last recorded date of the inspection, whichever is earlier. The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) and (d) by failing to perform internal inspections of in-service breakout tanks within the maximum interval of 10 years prescribed by API 653, Section 6.4.2.2, which states: “When corrosion rates are not known and similar service experience is not available to estimate the bottom plate minimum thickness at the next inspection, the internal inspection interval shall not exceed 10 years.” Specifically, the Notice alleged that Sunoco could not provide the out-of-service internal inspection reports for tanks 2601, 2603, 42, and 2720 to confirm that an internal inspection had been performed and corrosion rates had been established. According to the Notice, if the date of the last inspection cannot be determined based on available records, an operator should perform an API 653 inspection immediately after acquiring a breakout tank from another operator. Since Sunoco acquired ownership of tanks 2601, 2603, and 2720 on August 1, 2005, and tank 42 on February 17, 2006, and could not determine when the last internal inspections were performed, and the corrosion rates of the tanks were not known, an internal inspection allegedly should have been performed immediately upon acquisition and then at an interval not exceeding 10 years. The aforementioned internal-inspection reports had also been requested by PHMSA during a 2007 inspection but Sunoco had been unable to provide them at that time. In addition, the Notice alleged that Tank 44 had been constructed in 1992 but had not had its first out-of-service internal inspection performed until 2012. Since Tank 44 did not have a corrosion rate established, Sunoco needed to perform an internal inspection on Tank 44 in 2009, 10 years after PHMSA adopted API 653 in 1999. Sunoco allegedly failed to perform an internal inspection within this required time frame. Finally, the type of liner for Tank 2703 was unknown. The last internal inspection of the tank was performed on September 15, 1995, by the previous owner. The 1995 inspection report stated that there was internal corrosion found on the tank bottom, but no corrosion rate had been established. Sunoco scheduled the next internal inspection for 2015, an interval of 20 years, even though Sunoco did not know what liner was applied during the tank’s repairs. Since the material and thickness of the liner were not known and the corrosion rate was also unknown, the inspection interval could not be more than 10 years and therefore Sunoco needed to perform an internal inspection by 2005. Sunoco failed to perform an internal inspection within this 10-year interval. Respondent did not contest these allegations of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.432(b) and (d) by failing to perform internal inspections within the maximum interval of 10 years prescribed by API 653.#

420165020_Final Order_09152017_text.pdf, page 6CPF No. 4-2016-5020 Page 5 Item 7: 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 have procedures for mitigating internal corrosion by identifying the potential for internal corrosion at low points, changes in elevation, sharp bends, infrequently-used piping, pump stations, and “dead legs” and by assessing, monitoring, and, mitigating the effects of internal corrosion at those identified locations. Specifically, the Notice alleged that Sunoco’s procedures addressing internal corrosion were developed and implemented in 2011 and were designed to “mitigate facility releases and improve asset reliability and availability.” The procedures specifically mentioned that the purpose of the plan was to assess and learn the general condition of both active and idle piping within the facility. While this manual was put in place to require internal- corrosion assessments, the plan allegedly lacked specific and detailed information regarding the actions necessary to perform adequate assessments on the facility piping. The procedure was under revision at the time of the PHMSA inspection and a draft had been prepared to expand the scope and application of the procedure. The procedure had not, however, been finalized or implemented. Finally, the Notice alleged that Sunoco’s existing procedure that addressed internal corrosion in dead legs and low-flow pipelines was issued in 2013. The Dead Leg Removals and Line Flushing Procedure OPER-PR-0008 was created to determine the extent of lines that would require attention as part of the integrity program based on operating conditions. The procedure required identification of dead legs and actions necessary to manage those identified pipelines. The procedure, as written, allegedly did not include provisions for reevaluation after changes or modifications had been made within a station or on the pipelines that could affect its operating conditions. According to the Notice, Sunoco’s pipeline system had had several accidents where releases occurred due to internal corrosion, including several in dead legs and low spots in its facilities, with eight reportable accidents occurring on terminal piping since 2010. Respondent did not contest this allegation of violation. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.579(a) by failing to have procedures for mitigating internal corrosion, by identifying the potential for internal corrosion at low points, changes in elevation, sharp bends, infrequently-used piping, pump stations, and dead legs and by assessing, monitoring and, mitigating the effects of internal corrosion at those identified locations. CONTESTED The Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows: Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.401(b)(1), which states:#

420165020_Final Order_09152017_text.pdf, page 7CPF No. 4-2016-5020 Page 6 § 195.401 General requirements. (a)… (b) An operator must make repairs on its pipeline system according to the following requirements: (1) Non Integrity management repairs. Whenever an operator discovers any condition that could adversely affect the safe operation of its pipeline system, it must correct the condition within a reasonable time. However, if the condition is of such a nature that it presents an immediate hazard to persons or property, the operator may not operate the affected part of the system until it has corrected the unsafe condition. The Notice alleged that Respondent violated 49 C.F.R. § 195.401(b)(1) by failing to correct, within a reasonable time, conditions that could adversely affect the safe operation of its pipeline system. Specifically, the Notice alleged that Sunoco failed to correct or repair two conditions that could adversely affect the safe operation of its breakout tanks. First, during the PHMSA field inspection of Sunoco’s Colorado City facility in July 2014, Tank 5 was allegedly found to have approximately 10 feet of the ringwall foundation severely damaged. The ringwall had been damaged during the tank’s out-of-service repairs in 2011, which was noted on Sunoco’s “Tank 5 Out of Service Post-Repair Report” in December 2011. Sunoco, however, did not repair the ringwall foundation until August 2014, after the PHMSA inspector had inquired during the 2014 field inspection about the ringwall’s damage. The Notice alleged that Sunoco did not correct the condition “within a reasonable time” because it waited two years and seven months to conduct the repair. Second, during the PHMSA field inspections at Sunoco’s Ringgold and Corsicana facilities in September 2014, Tank 2703 and Tank 2602 were allegedly found to have half-inch cracks on their ringwall foundations. The crack on Tank 2703 had been discovered by Sunoco during the tank’s In-Service Inspection in February 2014. The cracks were repaired on October 25, 2014, after being noted during the PHMSA field inspection in September 2014. The Notice alleged that Sunoco had failed to correct these conditions that could adversely affect the safe operation of its pipeline system “within a reasonable time” because it waited eight months to complete the repair. In its Response, Sunoco acknowledged that the damage to the concrete ringwalls was not addressed at the time of the inspections in July and September 2014, respectively. However, it contended that the damage to the ringwalls was superficial in nature and did not pose any significant or adverse risk to the safe operation of its pipeline system. The company further stated that at the time of the 2011 post-repair inspection of Tank 5, the damage to the tank’s ringwall did not pose a concern to the structural integrity or the safe operation of the tank. A review of the tank-settlement measurements from inspection reports conducted on Tank 5 in 2006 and again in 2011 indicated that there was no evidence of active settlement and that the deflection and settlement readings were within API allowable limits. The#

420165020_Final Order_09152017_text.pdf, page 8CPF No. 4-2016-5020 Page 7 shell-settlement survey was again confirmed as having no unacceptable settlement or deflection during the January 2016 inspection report. With respect to the ringwall cracks observed on Tanks 2703 at Ringgold and 2602 at Corsicana, Sunoco likewise contended that the cracks in the ringwalls did not pose a concern to the structural integrity or safe operation of the tanks. Sunoco argued that, in general, surface cracks on concrete ringwalls do not pose a serious threat to the stability of a tank unless enough of a ringwall section is missing so as to create a large enough area where the downward forces of the tank shell can cause a significant out-of-plane deflection. Although the company’s “API 653 In-Service Inspection Report for Tank 2703” noted a crack in the ringwall, the condition was noted to be appropriate for “consideration” for repair, not as a compliance deficiency. Sunoco stated that consideration was given to the nature of the crack, and it was determined that it did not pose a serious threat to the stability or the continued safe operation of the tank. Sunoco further argued that it took steps to remediate the conditions of the ringwall of each tank and provided documentation to OPS subsequent to the repairs while the inspection was ongoing. It argued that the phrase “within a reasonable time” is subjective and discretionary, and that based on its evaluation of the seriousness of the cracks, it took appropriate action in compliance with the pipeline safety regulations. Sunoco stated that its internal subject-matter experts at no time concluded that the ringwall damage posed any significant or adverse risk to the safe operation of the pipeline system. Accordingly, Sunoco requested that this Item and the associated Proposed Compliance Order be withdrawn, as well as the associated proposed civil penalty. In its recommendation, OPS disagreed with Sunoco’s response that the damage and cracks found on the tanks were “superficial in nature and did not pose any significant or adverse risk to the safe operation of its pipeline system,” and that the phrase “reasonable time” was subjective and discretionary with respect to the timing of the repairs. OPS stated that a “reasonable time” needed to be defined in an operator’s procedures, and that, as seen in Item 1 of the Notice, Sunoco’s procedures failed to do so. According to OPS, Sunoco acknowledged that its DOT Maintenance Manual Procedure 195.432 should define the term “reasonable” with respect to the timing of repairs for conditions found during tank inspection, including monthly, external, ultrasound (UT), and internal inspections.2 Moreover, Sunoco’s own “In-Service Inspection Report for Tank 2703” stated: “There was moderate to severe cracking in the concrete,” contradicting Sunoco’s claim that the damage was superficial. Analysis I have reviewed the record and find that Sunoco failed to repair the two conditions within a reasonable time. Section 195.401(b)(1) requires each operator to correct a discovered condition 2 Response, at 3.#

420165020_Final Order_09152017_text.pdf, page 9CPF No. 4-2016-5020 Page 8 within a reasonable time if the condition could adversely affect the safe operation of its pipeline system. In this case, for Tank 5, the “HMT Final API 653 Out-of-Service Inspection Report, Tank No. 5” included photographs demonstrating the damage to the ringwall foundation.3 The company’s inspection report also noted that “minor cracks should be sealed to minimize further degradation.”4 Photographs by the PHMSA inspector of Tank 5 taken on July 30, 2014, 5 Tank 2703 at the Ringold facility taken on September 17, 2014,6 and Tank 2602 taken on September 18, 2014,7 all reveal the extent of the damage to the ringwall. Section 3.2.1 of Sunoco’s own “In-Service Inspection Report for Tank 2703” stated: “There was moderate to severe cracking in the concrete. Consider repairing the cracks in the concrete.” 8 The report included a photograph showing the severity of the crack.9 I find the contemporaneous photographs and Sunoco’s own “In-Service Inspection Report for Tank 2703” persuasive as to the severity of the damage to the ringwall. The report also characterized the cracks as “moderate to severe,” not superficial. The evidence in the photographs and Sunoco’s own reports all support a finding that the cracks were not insignificant or insubstantial. Cracks in a ringwall can be potential access points for moisture and water seepage that could eventually result in corrosion of the reinforcing steel and further damage to the ringwall. Accordingly, I find the damage to ringwalls at issue in this matter could adversely affect the safe operation of Respondent’s pipeline system and therefore needed to be repaired within a reasonable time frame to prevent them from becoming an even bigger safety issue. Sunoco knew about the damaged ringwalls but failed to make repairs for a time period ranging from almost a year to over two-and-a-half years. Given the extent of the cracking, I find that it was not reasonable for Sunoco to wait this amount of time before making these repairs. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.401(b)(1) by failing to correct within a reasonable time conditions that could adversely affect the safe operation of its pipeline system. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. 3 Violation Report, Ex. B, at 115 (“HMT Final API 653 Out-of-Service Inspection Report, Tank No. 5, January 2001 and December 7, 2011, Section 8 Post Repair Photographs”). 4 Id., Ex. B, at 6 (“HMT Final API 653 Out-of-Service Inspection Report, Tank No. 5, January 2001 and December 7, 2011). 5 Id.,, Ex. B, at 127-28. 6 Id., Ex. B, at 135-36. 7 Id., Ex. B, at 189. 8 Id., Ex. B, at 143 (Tank 2703 API 653 In-Service Inspection Report by Mott Tank (Feb. 26, 2014)). 9 Id., Ex. B, at 185 (Tank 2703 API 653 In-Service Inspection Report by Mott Tank (Feb. 26, 2014)).#

420165020_Final Order_09152017_text.pdf, page 10CPF No. 4-2016-5020 Page 9 WITHDRAWN Pipeline integrity management in high consequence areas. (l) What records must an operator keep to demonstrate compliance? (1) An operator must maintain, for the useful life of the pipeline, records that demonstrate compliance with the requirements of this subpart. At a Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(l), which states, in relevant part: § 195.452 (a)… minimum, an operator must maintain the following records for review during an inspection: (i) A written integrity management program in accordance with paragraph (b) of this section. (ii) Documents to support the decisions and analyses, including any modifications, justifications, deviations and determinations made, variances, and actions taken, to implement and evaluate each element of the integrity management program listed in paragraph (f) of this section. . . . The Notice alleged that Respondent violated 49 C.F.R. § 195.452(l) by failing to maintain records to support actions taken to implement and evaluate each element of its integrity management program established under 49 C.F.R. Subpart F. Specifically, the Notice alleged that Sunoco failed to provide records of the field changes made to the safety-related set points when a 20 percent pressure reduction took place because of anomalies identified by in-line inspection runs. In its Response, Sunoco submitted Management of Change records (MOCs), along with Action Items and Point-to-Point Short Forms for each MOC referenced in Item 6. Sunoco indicated the creation of the MOC, along with the completion of the associated Field and SCADA Action Items, served as the documentation required to show that field-related set points had been changed and Point-to-Point verification with the field device and SCADA screen had taken place. OPS reviewed Sunoco’s submitted Action Items and Point-to-Point Short Forms for each MOC, which had not been provided during the PHMSA inspection. The documentation was reviewed and accepted by OPS as demonstrating that the changes to safety-related set points that had been verified. OPS therefore recommended that this Item be withdrawn. Accordingly, Item 6 is withdrawn from the Notice, along with the associated compliance order and proposed civil penalty. ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed#

420165020_Final Order_09152017_text.pdf, page 11CPF No. 4-2016-5020 Page 10 $200,000 per violation for each day of the violation, up to a maximum of $2,000,000 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; 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 $169,200 for the violations cited above. Item 1: The Notice proposed a civil penalty of $33,700 for Respondent’s violation of 49 C.F.R. § 195.56(a), for failing to file safety-related condition reports with PHMSA within five working days after determining conditions existed that met the criteria of a safety-related condition. Respondent neither contested the allegation nor presented any evidence or argument justifying elimination of the proposed penalty. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $33,700 for violation of 49 C.F.R. § 195.56(a), which amount has already been paid. Item 2: The Notice proposed a civil penalty of $33,500 for Respondent’s violation of 49 C.F.R. § 195.401(b)(1), for failing to correct conditions that could adversely affect the safe operation of its pipeline system within a reasonable time. As noted above, I found that Sunoco failed to repair cracks in the ringwall foundations of two breakout tanks in a timely manner. With regard to the penalty assessment criteria noted in the Violation Report, I find that the nature, circumstances, gravity, and culpability factors have been considered appropriately and I confirm the proposed penalty. In particular, cracks in a ringwall can be potential access points for moisture and water seepage that could eventually result in corrosion of the reinforcing steel and further damage to the ringwall. Damage to ringwalls need to be repaired in a reasonable time frame to prevent them from becoming an even bigger safety issue. The Violation Report acknowledged that pipeline safety was minimally affected by Respondent’s violation; as a result, this mitigating factor was already taken into account in the proposed penalty. Based upon the foregoing, I assess Respondent a civil penalty of $33,500 for violation of 49 C.F.R. § 195.401(b). Item 3: The Notice proposed a civil penalty of $36,700 for Respondent’s violation of 49 C.F.R. § 195.402(a), for failing to follow its written procedures for tank maintenance. Sunoco argued that the proposed penalty should be reduced because the proposed civil penalty “does not appropriately reflect assessment considerations.”10 Sunoco argued that, compared to Item 2 of the Notice, the proposed civil penalty for Item 3 was disproportionately higher and that the violation resulted in “no injuries or fatalities, no explosion(s), no wildlife impact, and no water contamination and, accordingly, no impact on health, and little (if any) impact on the environment, which was short term and promptly remediated.”11 10 Response, at 5. 11 Id.#

420165020_Final Order_09152017_text.pdf, page 12CPF No. 4-2016-5020 Page 11 I disagree. Having reviewed the record, I find that the penalty amount proposed in the notice is warranted, considering the nature, circumstances, and gravity of the violation and Respondent’s level of culpability. PHMSA calculates each penalty individually, based on the unique facts and circumstances of the specific violation, using the same penalty criteria and logarithm. The higher penalty for this violation, as opposed to Item 2, is based, at least in part, on the fact that this violation compromised pipeline safety or integrity to a greater extent. A more serious gravity factor warrants a higher penalty amount. Sunoco has failed to provide any justification for reducing the proposed penalty based on the assessment criteria. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $36,700 for violation of 49 C.F.R. § 195.402(a). Item 4: The Notice proposed a civil penalty of $37,800 for Respondent’s violation of 49 C.F.R. § 195.432(b) and (d), for failing to perform internal inspections within the maximum interval of 10 years prescribed by API 653. Sunoco did not contest this allegation of violation but argued that the penalty should be reduced because the out-of-service internal inspection reports for Tanks 2720 and 42 were not available during the PHMSA inspection, but were included as part of the Response. Sunoco stated that Tank 2720’s 2005 internal inspection report established a corrosion rate on the prior tank bottom. Sunoco also stated that when the new tank bottom was installed in 2005, a new internal inspection interval was calculated to be 20 years, using the established corrosion rate of the old bottom that had been replaced. As for Tank 42, Sunoco stated that it was evaluating repair records “associated with the December 14, 1995 internal inspection…..to validate the internal inspection interval of 20 years.”12 I reject Sunoco’s argument for a penalty reduction. As for Tank 2720, Sunoco set a new inspection rate of 20 years that was based on the established corrosion rate for the old tank bottom. Since Sunoco replaced the tank bottom with a new bottom, the corrosion rate from the old bottom could not be used for calculating the internal inspection interval. The new tank bottom, however, had an unknown corrosion rate, so the internal inspection interval would be 10 years and the internal inspection for Tank 2720 should have been performed in 2005. As for Tank 42, the Response did not include any documentation that would validate a 20-year internal inspection interval. Considering that the Notice listed nine breakout tanks, for which Sunoco admittedly failed to perform internal inspections within the maximum interval of 10 years, as prescribed by API 653, I see no basis for a penalty reduction. Having reviewed the record, I find that the penalty amount proposed in the notice is warranted considering the nature, circumstances, and gravity of the violation and Respondent’s level of culpability. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $37,800 for violation of 49 C.F.R. § 195.432(b) and (d). Item 6: The Notice proposed a civil penalty of $27,500 for Respondent’s violation of 49 C.F.R. § 195.452(l) by failing to maintain documents to support actions taken to implement and 12 Response, at 7.#

420165020_Final Order_09152017_text.pdf, page 13CPF No. 4-2016-5020 Page 12 evaluate each element of its integrity management program. This item has been withdrawn and, therefore, there is no penalty associated with it. In summary, having reviewed the record and considered the assessment criteria for each of the Items cited above, I assess Respondent a total reduced civil penalty of $141,700, of which $33,700 has already been paid. Payment of the remaining 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, 6500 S MacArthur Blvd, Oklahoma City, OK 79169. The Financial Operations Division telephone number is (405) 954-8845. Failure to pay the remaining penalty of $108,000 will result in accrual of interest at the current annual rate in accordance with 31 U.S.C. § 3717, 31 C.F.R. § 901.9 and 49 C.F.R. § 89.23. Pursuant to those same authorities, a late penalty charge of six percent (6%) per annum will be charged if payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty may result in referral of the matter to the Attorney General for appropriate action in a district court of the United States. COMPLIANCE ORDER The Notice proposed a compliance order with respect to Items 2, 4, 6, and 7 in the Notice for violations of 49 C.F.R. §§ 195.401(b)(1), 195.432(b) and (d), 195.452(l), and 195.579(a), respectively. Since Item 6 has been withdrawn, the associated provisions in the Proposed Compliance Order for that item are not included. 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: 1. With respect to the violation of § 195.401(b)(1) (Item 2), Respondent must further define in its procedures reasonable time frames for the repair of conditions that may be found during tank inspections, including monthly, external, UT, and internal inspections of tanks. Sunoco submitted procedure 195.432 Inspection of In-Service Breakout Tanks to address part of this item in the Compliance Order. Sunoco addressed the integrity inspection plan for tanks with concrete bottoms or liners in Section 195.432(3)(VII).#

420165020_Final Order_09152017_text.pdf, page 14CPF No. 4-2016-5020 Page 13 OPS reviewed Sunoco’s submitted 195.432 procedure, which addresses part of the Compliance Order for Item 2. The Section 195.432(3)(VII) Sunoco submitted was unchanged from the previous procedure PHMSA had reviewed during the inspection, and is not acceptable. Therefore, Sunoco must resubmit amended procedures to comply with this Order. 2. With respect to the violation of § 195.432(b), (d) (Item 4), Respondent must perform internal inspections on its breakout tanks that have exceeded 10 years, as required by § 195.432, and must also perform internal inspections on tanks 2601, 2603, 42, and 2720 as soon as possible or provide the previous actual internal inspection reports to verify internal inspections were performed. Sunoco must also develop and implement a bottom-integrity inspection plan for its tanks that have concrete liners and reevaluate the time interval for tanks with unknown corrosion rates. Sunoco must provide the Southwest Region with the integrity inspection plan, and a plan and time frame for performing internal inspections as required. Since the time of the PHMSA inspection, Sunoco stated that it had made revisions to its Dead Leg Removals and Line Flushing, and its Facility Integrity Program procedures. Sunoco submitted to OPS a copy of its Facility Integrity Program, Pipeline internal Corrosion Control Guideline, and Dead Leg Removals and Line Flushing Procedure. Sunoco must also determine if any other existing procedures should be considered for revision or any new procedures developed. Any additional revised procedures or newly developed procedures must be submitted to PHMSA for review within 90 days of the Final Order. 3. With respect to the violation of § 195.579(a) (Item 7), Respondent must develop procedures to assess the integrity of its facility piping and to include provisions for monitoring and mitigating the effects of internal corrosion on all of its pipelines. Sunoco must perform an assessment to fully determine the corrosive effect of the transported products on its pipeline system to include consideration of low points, changes in elevation, sharp bends, infrequently used pump stations, and dead legs. 4. Sunoco must submit documentation and procedures required by this Compliance Order within 90 days of the date of the Final Order and perform the required internal inspections of the tanks within 180 days of the Final Order. It is requested (not mandated) that Sunoco Pipeline L.P., maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to the Director, Southwest Region, Pipeline and 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. 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.#

420165020_Final Order_09152017_text.pdf, page 15CPF No. 4-2016-5020 Page 14 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. WARNING ITEM With respect to Item 5, the Notice alleged probable violations of Part 199 but did not propose a civil penalty or compliance order for this item. Therefore, this is considered to be a warning item. The warning is for: 49 C.F.R. § 199.202 (Item 5) ─ Respondent’s alleged failure to follow its written alcohol misuse plan by failing to perform a post-accident alcohol test on a covered employee as soon as practicable after the employee’s performance of a covered task allegedly contributed to an accident. If OPS finds a violation of this provision in a subsequent inspection, Respondent may be subject to future enforcement action. 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 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. September 15, 2017 ___________________________________ __________________________ Alan K. Mayberry Date Issued Associate Administrator for Pipeline Safety#

420165020_Closure Letter_01082018_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED January 8, 2018 Mr. Ryan Coffey Executive Vice President of Operations Sunoco Pipeline, LP 800 East Sonterra Blvd. San Antonio, TX 78258 CPF 4-2016-5020 Dear Mr. Coffey: On September 15, 2017, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to Sunoco Pipeline, L.P. a Final Order in the above-referenced case. This Final 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, Terri J. Binns Acting Director, Southwest Region Pipeline and Hazardous Materials Safety Administration#

420165020_NOPV PCP PCO_06022016_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED June 2, 2016 Mr. David Chalson Vice President of Operations Sunoco Pipeline L.P. 4041 Market Street Aston, PA 19014 CPF 4-2016-5020 Dear Mr. Chalson: From March 24, 2014 to July 1, 2015, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49 United States Code inspected your procedures, records and pipeline facilities throughout Texas. As a result of the inspection, it appears that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violations are: 1. §195.56 Filing safety-related condition reports. (a) Each report of a safety-related condition under § 195.55(a) must be filed (received by the Administrator) in writing within 5 working days (not including Saturdays, Sundays, or Federal holidays) after the day a representative of the operator first determines that the condition exists, but not later than 10 working#

420165020_NOPV PCP PCO_06022016_text.pdf, page 2conditions may be described in a single report if they are closely related. To file a report by facsimile (fax), dial (202) 366-7128. Sunoco failed to file safety-related condition reports with PHMSA within five working days after determining conditions existed that met the criteria of a safety-related condition as per 195.55(a) (б). Beginning on September 20, 2013, Sunoco performed an integrity assessment on their Keller to Corsicana segment using a deformation and magnetic flux leakage (MFL) internal tool. On December 3, 2013, Sunoco discovered nine anomalies in high consequence areas (HCAs), including KLLR-CORS 13-2A, KLLR-CORS 13-3A, KLLR-CORS 13-4A and 13-4B, and documented the anomalies as immediate conditions due to physical damage to the pipeline. On December 4, 2013, Sunoco issued a 20% operating pressure reduction due to the immediate conditions through a Management of Change 6328 on the 16" Ringgold to Corsicana segment. The 20% operating pressure reduction established December 4, 2013 as the date Sunoco determined a safety-related condition existed The KLLR-CORS 13-3A, KLLR-CORS 13-4A and 13-4B conditions were repaired on December 18, 2013, which exceeded five working days from December 4, 2013 to the date Sunoco determined safety-related conditions existed. Further, the KLLR-CORS 13-2A condition was repaired on December 19, 2013, which also exceeded five working days after the date of determination of the condition. Accordingly, Sunoco failed to file timely safety-related condition reports in violation of § 195.56.. The following table gives additional details regarding each condition: Date Determined Business Days Dig Number Condition Date (Day of 20% Repair Date after 20% Discovered Pressure Determination Pressure Reduction) /Discovery Reduction KLLR-CORS 13-2A Top Dent w/ Metal Loss 12/3/2013 12/4/2013 12/19/2013 11/12 MOC 6328 KLLR-CORS 13-3A Top Dent w/ 12/3/2013 12/4/2013 12/18/2013 10/11 MOC Metal Loss 6328 KLLR-CORS 13-4A Top Dent w/ 12/3/2013 12/4/2013 12/18/2013 10/11 MOC Metal Loss 6328 KLLR-CORS 13-4B Top Dent w/ 12/3/2013 12/4/2013 12/18/2013 10/11 MOC Metal Loss 6328 2#

420165020_NOPV PCP PCO_06022016_text.pdf, page 32. §195.401 General Requirements. (b) An operator must make repairs on its pipeline system according to the following requirements: (1) Non Integrity management repairs. Whenever an operator discovers any condition that could adversely affect the safe operation of its pipeline system, it must correct the condition within a reasonable time. However, if the condition is of such a nature that it presents an immediate hazard to persons or property, the operator may not operate the affected part of the system until it has corrected the unsafe condition. Sunoco failed to correct conditions that could adversely affect the safe operation of its pipeline system within a reasonable time. Specifically, Sunoco failed to correct or repair within a reasonable time, several conditions that could adversely affect the safe operation of its breakout tanks as follows: During the PHMSA field inspection at Sunoco’s Colorado City facility in July 2014, Tank 5 was found to have approximately 10 feet of the ring wall foundation severely damaged. The Ring wall had been damaged during the tank’s out of service repairs in 2011 and was noted during Sunoco’s Tank 5 Out of Service Post Repair report in December 2011. Sunoco, however, did not repair the ring-wall foundation until August 2014, after the PHMSA inspector had inquired about the ring- wall’s damage during the field inspection in July 2014. Sunoco failed to correct a condition that could adversely affect the safe operation of its pipeline system within a reasonable time. Two years and seven months was not a reasonable time for repairing the condition of Tank 5. During the PHMSA field inspections at Sunoco’s Ringgold and Corsicana facilities in September 2014, Tank 2703 and Tank 2602, were found to have a half-inch crack on their ringwall foundation. The crack on Tank 2703 had been discovered by Sunoco during the tank’s In-Service Inspection in February 2014. Section 3.2.1 of the In-Service Inspection Report for Tank 2703 states, “There was moderate to severe cracking in the concrete. Consider repairing the cracks in the concrete.” Sunoco did not repair the crack as per API Standard 653 “Tank Inspection, Repair, Alteration, and Reconstruction”, 3rd edition which states 4.5.2.2 Concrete pads, ringwalls, and piers, showing evidence of spalling, structural cracks, or general deterioration, shall be repaired to prevent water from entering the concrete structure and corroding the reinforcing steel. Sunoco did not repair the condition on either tank at a reasonable time. The cracks were repaired on October 25, 2014, after they were noted during the PHMSA field inspections in September 2014. Sunoco failed to correct conditions that could adversely affect the safe operation of its pipeline system within a reasonable time. 3. §195.402 Procedure manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance 3#

420165020_NOPV PCP PCO_06022016_text.pdf, page 4reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. Sunoco did not follow their written procedure for tank maintenance. Specifically, Sunoco failed to follow Subpart F, Section 195.432 of their Operations and Maintenance Manual, Inspection of In-Service Breakout Tanks procedure, by not documenting conditions that could affect safe operation of its breakout tanks. Section 195.432, Section 1. I. of the manual, states, “All above ground breakout tanks shall be given a visual inspection on a monthly basis. Results of the visual inspection shall be recorded on form (Sun-42446-A Monthly Aboveground Storage Tank Inspection Report and maintained in the appropriate DOT file” and Section 1. III states “Evidence of leaks; shell distortion; signs of settlement; corrosion; and damage or deterioration of the foundation, paint coatings, insulation systems, and appurtenances or other potential problems shall be documented for review by the facility manager or a designated engineer or authorized inspector.” The requisite documentation was not completed in the following instances: During the PHMSA field inspection at Sunoco’s Ringgold facility in September 2014, the PHMSA inspector found a crack on Tank 2703’s ringwall. The crack on Tank 2703 had been previously discovered during the tank’s In-Service Inspection in February 2014. The Sunoco’s monthly inspection reports for Tank 2703 from February 2014 to September 2014 demonstrated Sunoco failed to document the crack on the ring wall. Tank 5 at Sunoco’s Colorado City facility, was found to have approximately 10 feet of the ring wall foundation severely damaged and was noted on the tank’s post inspection repair report in December 2011. Sunoco’s monthly inspection reports for Tank 5 demonstrate personnel failed to document the tank’s ring wall damage on their monthly reports from August 2012 to December 2013. The damage was repaired in 2014 after the PHMSA inspector inquired about the damage. During a PHMSA field inspection at Sunoco’s Corsicana facility in September 2014, Tank 2602 was found to have a half-inch crack on the ring wall foundation. Tank 2602 monthly reports from September 2013 to August 2014 where reviewed and Sunoco failed to document any ring wall damage during that time. The crack was repaired in October 2014 after the PHMSA inspector inquired about the damage. 4. §195.432 Inspection of in-service breakout tanks. (b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according to API Standard 653 (incorporated by reference, see § 195.3). However, if structural conditions prevent access to the tank bottom, the bottom integrity may be assessed according to a plan included in the operations and maintenance manual under § 195.402(c)(3). 4#

420165020_NOPV PCP PCO_06022016_text.pdf, page 5(d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator's last recorded date of the inspection, whichever is earlier. Sunoco failed to perform internal inspections within the maximum interval of 10 years prescribed by API 653, Section 6.4.2.2 which states, "[w]hen corrosion rates are not known and similar service experience is not available to estimate the bottom plate minimum thickness at the next inspection, the internal inspection interval shall not exceed 10 years." and §195.432 for the following breakout tanks: Tank Built Date Bottom API 653 API 653 Next API 653 Sunoco's Sunoco's Lining Applied by Internal required API 653 API 653 operator Inspection Internal Internal Internal Previous Inspection Inspection Current Inspection Performed Schedule Interval by year: 2601 1947 Concrete 1997 Unknown* 2005 2017 (scheduled) > 10 2602 1947 Concrete 2007 5/10/2007 2017 2027 (scheduled) > 10 2603 1947 Fiberglass Epoxy 2000 Film Unknown* 2005 2/1/2020 > 10 Thin 44 2032 1992 Epoxy 2012 1/1/2012 2009 (scheduled) >10 15 1953 2028 Concrete 2008 2/1/08 2018 (scheduled) >10 17 2027 1953 Concrete 2007 2/1/07 2017 (scheduled) >10 42 1953 Concrete 1996 Unknown* 2005 2016 (scheduled) > 10 2703 1954 UNKNOWN 1995 1/1/1995 2005 2015 (scheduled) > 10 2720| 1956| EPOXY 2004 Unknown* 2005 / 2025 > 10 * NOTE: Out-of-service internal inspection reports were not provided. Sunoco could not provide the out-of-service internal inspection reports for tanks 2601, 2603, 42, 2720 to confirm an internal inspection had been performed and corrosion rates had been established. If the date of the last inspection cannot be determined based on the available records, an operator should perform an API 653 inspection immediately after acquiring a breakout tank from another operator. Since Sunoco acquired ownership of tanks 2601, 2603 and 2720 on August 1, 2005, and tank 42 on February 17, 2006, and could not determine when the last internal inspections were performed, and the corrosion rates of the tanks are not known, the internal inspection interval should not have exceeded 10 years. The aforementioned internal inspection reports were also asked for by PHMSA during a 2007 inspection and Sunoco was unable to provide them at that time. 5#

420165020_NOPV PCP PCO_06022016_text.pdf, page 6Tank 44 was constructed in 1992 and had its first out-of-service internal inspection performed in 2012. Since Tank 44 did not have a corrosion rate established, Sunoco needed to perform an internal inspection on Tank 44 in 2009, 10 years after PHMSA adopted API 653 in 1999. Sunoco failed to perform an internal inspection within the required time frame. Finally, the type of liner for Tank 2703 is unknown. The last internal inspection of the tank was performed on September 15, 1995 by the previous owner. The 1995 inspection report states there was internal corrosion found on the bottom, but no corrosion rate was established. Sunoco has scheduled the next internal inspection for 2015, an interval of 20 years, even though Sunoco did not know what liner was applied during the tank’s repairs. Since the material and thickness of the liner is not known and the corrosion rate is unknown, the inspection interval should have been 10 years and Sunoco needed to perform an internal inspection in 2005. Sunoco failed to perform an internal inspection within the 10 year interval. 5. §199.202 Alcohol misuse plan. Each operator must maintain and follow a written alcohol misuse plan that conforms to the requirements of this part and DOT Procedures concerning alcohol testing programs. The plan shall contain methods and procedures for compliance with all the requirements of this subpart, including required testing, recordkeeping, reporting, education and training elements. Sunoco failed to follow their written alcohol misuse plan by failing to perform a post-accident alcohol test on a covered employee as soon as practicable, after the employee’s performance of a covered function contributed to an accident. On September 24, 2013, at 1:08 p.m., a Sunoco employee was performing a maintenance covered task on a mainline block valve when an accident, reportable under 49 CFR Part 195, occurred. The cause was found to be the employee’s failure to follow Sunoco’s maintenance procedure which led to a suspension of the employee’s OQ qualifications. A post-accident alcohol test was performed on September 25, 2013 at 2:20 p.m., approximately 23 hours after the accident. Sunoco failed to conduct post-accident alcohol testing within 8 hours of an accident employee whose performance of a covered task caused the accident as per their procedure. Sunoco’s Substance Abuse Policy Appendix D Alcohol Misuse Prevention Plan and Procedures (AMPPP), Section II, B, 3. Post-Accident Testing, states a post-accident test will occur as soon as possible but no later than 8 hours following an accident. It also states each employee shall be required to submit to an alcohol test within 2 hours of the accident. 6. §195.452 Pipeline integrity management in high consequence areas. (l) What records must be kept? (1) An operator must maintain for review during an inspection: 6#

420165020_NOPV PCP PCO_06022016_text.pdf, page 7(i) A written integrity management program in accordance with paragraph (b) of this section. (ii) Documents to support the decisions and analyses, including any modifications, justifications, deviations and determinations made, and actions taken, to implement and evaluate each element of the integrity management program listed in paragraph (f) of this section. Sunoco failed to provide documents to support actions taken to implement and evaluate each element of the integrity management program. Specifically, Sunoco failed to provide the records of the field changes made to the safety related set points when a 20% pressure reduction took place as a result of anomalies identified by ILI runs. During the inspection in May 2014, PHMSA identified four (4) instances where a 20% pressure reduction took place. As per Sunoco’s Management of Change (MOC) procedure, PR-11-0039, 2.1 Facilities or Equipment Affected states ‘This procedure is designed to manage permanent or temporary changes to all pipeline and terminal facilities and the operations that affect these facilities. This procedure is intended for changes to the following, but is not limited to: 1. Pipelines and pipeline components; 2. Pump station equipment and pipeline; 3. Instrumentation and Control equipment and program;’ and etc. From Sunoco’s MOC procedure, Section 6.0 Examples, a MOC is required for ‘Changes to pipeline operating conditions based on Inline Inspection Results’. During the review in May 2014, of the MOC documentation, inspectors requested Sunoco to provide documentation to demonstrate that the field changes to the safety related set points had been documented due to the pressure reductions. Sunoco responded that field documentation was not required as all the field changes were part of Management of Change (MOC) process. A review of the MOC documentation does not indicate that adjustments to devices or safety related set points were made in the field. The following instances of the Management of Changes due to the pressure reductions are: a) MOC ID# 5003 Date Created: 12/13/2012; Date Required: 12/13/2012 Location: F-Colo-Colorado City WTG (facility) b) MOC ID# 6257 Date created: 12/6/2013; date required: 12/6/2013 Location: F-Ring-Ringgold (Facility) c) MOC ID# 6328 Date created: 12/4/2013; Date required: 12/4/2013 Location: F-Ring- Ringgold Facility d) MOC ID # 6411 7#

420165020_NOPV PCP PCO_06022016_text.pdf, page 8Date created: 12/20/2013; Date required: 12/20/2013 Location: F-Ring-Ringgold Facility The inspectors also reviewed Sunoco’s Operation and Maintenance Manual, Section 195.446: Control Room Management which states: “SPLP Requirements / Process description 1. Field maintenance technical groups are responsible for ensuring the accuracy of field instrumentation exchanging data with the SCADA systems……… Testing and calibration of each type of instrument will be done in accordance with these schedules and to accuracies as defined within the Eastern area CMMS maintenance Management system…….. Implement API RP 1165 whenever a SCADA system is added, expanded or replaced, unless it is determined that certain provisions of API RP 1165 are not practical. Conduct point to point verification between SCADA displays and related field equipment when field equipment is added or moved and when other changes that affect pipeline safety are made to field equipment or SCADA displays Field personnel shall contact the appropriate control room when emergency conditions exist and when making field changes that affect control room operations.” While in the field, PHMSA requested Sunoco to provide documentation to demonstrate the field changes to the safety related set points had been documented due to the pressure reductions. Sunoco was unable to provide documentation to indicate that this was performed. 2. 3. 4. 7. §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. Sunoco does not have procedures for mitigating internal corrosion to identify the potential for internal corrosion at low points, changes in elevation, sharp bends, infrequently used piping, pump stations, and dead legs or assessing, monitoring and mitigating the effects of internal corrosion at those identified locations. Sunoco’s procedures that address internal corrosion include: Pipeline Internal Corrosion Control Guideline CORR-TG-0501, Facility Integrity Program OPER-PR- 0003, Dead Leg Removals and Line Flushing Procedure OPER-PR-0008. Sunoco’s Facility Integrity Program OPER-PR-003 was developed and implemented in 2011 and was designed to “mitigate facility releases and improve asset reliability and availability.” The procedures specifically mention that the purpose of the plan is to assess and learn the general8#

420165020_NOPV PCP PCO_06022016_text.pdf, page 9condition of both active and idle piping within the facility. While this manual was put in place to include assessments including internal corrosion, the plan lacks specific and detailed information regarding the actions necessary to performed adequate assessments on the facility piping. The procedure is currently under revision and a draft has been prepared to expand the scope and application of the procedure. The procedure has not, however, been finalized or implemented. Sunoco’s final procedure that addresses internal corrosion in dead legs and low flow pipelines was issued in 2013. Sunoco’s Dead Leg Removals and Line Flushing Procedure OPER-PR-0008 was created to determine the extent of lines that would require attention as part of the integrity program based on the operating conditions. The procedure requires identification of dead legs and then actions necessary to manage those identified pipelines. The procedure as written does not include provisions for reevaluation after changes or modifications are made within a station or on the pipelines that could affect their operating conditions. Sunoco’s pipeline system has had several accidents where releases occurred due to internal corrosion, including several in dead legs and low spots in their facilities. Sunoco has experienced eight reportable accidents on terminal piping since 2010 involving internal corrosion. Proposed Civil Penalty Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $200,000 per violation per day the violation persists up to a maximum of $2,000,000 for a related series of violations. For violations occurring prior to January 4, 2012, the maximum penalty may not exceed $100,000 per violation per day, with a maximum penalty not to exceed $1,000,000 for a related series of violations. The Compliance Officer has reviewed the circumstances and supporting documentation involved in the above probable violations and has recommended that you be preliminarily assessed a civil penalty of $169,200 as follows: Item number PENALTY 1 $33,700 2 $33,500 3 $36,700 4 $37,800 6 $27,500 Warning Items With respect to item 5 we have reviewed the circumstances and supporting documents involved in this case and have decided not to conduct additional enforcement action or penalty assessment proceedings at this time. We advise you to promptly correct these item. Failure to do so may result in additional enforcement action. 9#

420165020_NOPV PCP PCO_06022016_text.pdf, page 10Proposed Compliance Order With respect to items 2, 4, 6, and 7 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Sunoco Pipeline L.P. 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. All material you submit in response to this enforcement action may be made publicly available. If you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order. In your correspondence on this matter, please refer to CPF 4-2016-5020 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, R. M. Seeley Director, Southwest Region Pipeline and Hazardous Materials Safety Administration Enclosures: Proposed Compliance Order Response Options for Pipeline Operators in Compliance Proceedings 10#

420165020_NOPV PCP PCO_06022016_text.pdf, page 11PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Sunoco Pipeline L.P., a Compliance Order incorporating the following remedial requirements to ensure the compliance of Sunoco Pipeline L.P. with the pipeline safety regulations: 1. 2. 3. 3. 4. 5. In regard to Item Number 2 of the Notice pertaining to failing to correct or repair conditions found during tank inspections within a reasonable time. Sunoco must define in their procedures a reasonable time frame to repair conditions found during tank inspection, including monthly, external, UT, and internal inspections of tanks. In regard to Item Number 4 of the Notice pertaining to exceeding the internal inspection interval of 10 years, Sunoco must perform internal inspections on its breakout tanks that have exceeded 10 years as required by §195.432 and must also perform internal inspections on tanks 2601, 2603, 42, 2720 as soon as possible or provide the previous actual internal inspection reports to verify internal inspections were performed. Sunoco must also develop and implement a bottom integrity inspection plan for their tanks that have concrete liners and reevaluate the time interval for tanks with unknown corrosion rates. Provide to this office the integrity inspection plan, and a plan and time frame for performing internal inspections as required. In regard to Item Number 6 of the Notice, Sunoco must revise its management of change (MOC) procedures to include actions taken to implement the integrity management program, specifically when a pressure reduction is to take place. MOC procedures must include documentation of field activities taken and their potential impact prior to implementation. The documentation should include the changes made to specific devices and safety-related set points made in the field due to pressure reductions. In regard to Item Number 7 of the Notice, Sunoco must develop procedures to assess the integrity of their facility piping and to include provisions for monitoring and mitigating the effects of internal corrosion in all of their pipelines. Sunoco must perform an assessment to fully determine the corrosive effect of the transported products on their pipeline system to include consideration of low points, changes in elevation, sharp bends, infrequently used pump stations, and dead legs. Pertaining to items above of the Proposed Compliance Order, Sunoco must complete the required documentation within 90 days of the date of the Compliance Order and perform the required internal inspections of the tanks within 180 days of the Compliance Order. It is requested (not mandated) that Sunoco Pipeline L.P., maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to R. M. Seeley, Director, Southwest Region, Pipeline and 11#

420165020_NOPV PCP PCO_06022016_text.pdf, page 12Hazardous Materials Safety Administration. It is requested that these costs be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses, and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. 12#