CENTURION PIPELINE L.P. — Notice of Probable Violation

party submissionOfficial PDF420145028_Operator Petition for Reconsideration_04242017.pdf#

party submissionOfficial PDF420145028_Operator Response to Notice and Request for Hearing_12172014_.pdf#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 1Official PDFJune 27, 2019 Mr. Mike Prince Chief Executive Officer Lotus Midstream, LLC 2150 Town Square Place, Ste 395 Sugar Land, Texas 77479 Re: CPF No. 4-2014-5028 Dear Mr. Prince: Enclosed please find the Decision on the Petition for Reconsideration filed by your subsidiary, Centurion Pipeline, LP, in the above-referenced case. For the reasons explained therein, the Decision affirms the violations in the Final Order but reduces the total civil penalty to $122,700. When the civil penalty has been paid, this enforcement action will be closed. The Decision constitutes the final administrative action in this proceeding. Service of the Decision is made pursuant to 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: Ms. Mary McDaniel, Director, Southwest Region, Office of Pipeline Safety, PHMSA Mr. Scott Janoe, Esq., Baker Botts, LLP, 910 Louisiana Street, Houston, Texas 77002 Mr. Mike Morgan, General Manager – Operations, Centurion Pipeline, LP, 5 Greenway Plaza, Suite 110, Houston, Texas 77046 CERTIFIED MAIL – RETURN RECEIPT REQUESTED#

420145028_Decision on Petition for Reconsideration_06272019_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 ) Centurion Pipeline, LP, ) CPF No. 4-2014-5028 a subsidiary of Lotus Midstream, LLC, ) ) ) ) Petitioner. ) __________________________________________) DECISION ON PETITION FOR RECONSIDERATION Between April 2013 and February 2014, 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 Centurion Pipeline, LP (Centurion or Petitioner),1 in Texas, New Mexico, and Oklahoma. Centurion operates approximately 2,500 miles of pipeline transporting crude oil in Texas, Oklahoma, and New Mexico.2 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Petitioner, by letter dated November 10, 2014, 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 Centurion had committed six violations of 49 C.F.R. Part 195 and proposed a civil penalty of $165,900 for the alleged violations. The Notice also proposed ordering certain compliance measures to correct one of the alleged violations. Centurion responded to the Notice by letter dated December 17, 2014 (Response), contested the allegations, and requested a hearing. Centurion submitted additional materials on April 20, 2015 (Supplemental Response). An informal hearing was held on April 30, 2015, in Houston, Texas, before a Presiding Official from the Office of Chief Counsel, PHMSA. After the hearing, Petitioner provided post-hearing statements for the record, dated June 26, 2015 (Closing), and September 4, 2015 (Supplemental Closing). Pursuant to § 190.209(b)(7), the Director submitted a written evaluation of Petitioner’s response material on July 28, 2015 (Recommendation). 1 Centurion is a subsidiary of Lotus Midstream LLC. Lotus Midstream, LLC website, available at http://www.lotusmidstream.com/about-us (last accessed May 10, 2019). At the time of the inspection, Centurion was a subsidiary of Occidental Petroleum Corporation. 2 This information is reported by Centurion for 2015 pursuant to 49 C.F.R. § 195.49.#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 3CPF No. 4-2014-5028 Page 2 On March 30, 2017, pursuant to 49 C.F.R. § 190.213, PHMSA issued a Final Order in this proceeding, finding that Centurion had committed violations of §§ 195.432(b) (Items 1, 2, and 3), 195.202 and 195.264 (Item 4), 195.452(h)(2) (Item 5), and 195.452(h)(4) (Item 6), as alleged in the Notice. The Final Order assessed a reduced civil penalty of $137,100, and ordered corrective action with respect to Item 4, as set forth in the Compliance Order.3 In accordance with 49 C.F.R. § 190.243, Centurion filed a timely Petition for Reconsideration (Petition) of the Final Order on April 24, 2017, seeking reconsideration of Items 1-3, 5 and 6 and the civil penalties associated with them.4 Centurion did not seek reconsideration of Item 4 or the associated Compliance Order. The filing of the Petition automatically stayed payment of the assessed civil penalties pursuant to § 190.243(c), but did not stay the corrective actions required under the Compliance Order. The Compliance Order for Item 4 has been completed, so is not included in this Decision. Pursuant to 49 C.F.R. § 190.243, an operator may petition the Associate Administrator for reconsideration of a final order issued under § 190.213. A petition must be received no later than 20 days after receipt of the order by the respondent, and must contain a statement of the complaint and an explanation as to why the order should be reconsidered. If the operator requests consideration of additional facts or arguments that were not presented prior to issuance of the final order, the operator must submit the reasons why they were not previously presented. Reconsideration is not a right to appeal or to seek a de novo review of the record. A decision on a petition for reconsideration may be issued without further proceedings. Once issued, that decision becomes the final administrative action in the enforcement proceeding. In its Petition, Centurion continued to argue against PHMSA’s interpretations of 49 C.F.R. §§ 195.432 and 195.452 in Items 1-3, 5 and 6, repeating many of the same arguments and citing the same information contained in Petitioner’s previous submissions and addressed in the Final Order. Centurion also presented certain new information and new arguments, but failed to present a valid rationale for why this new information and arguments should be considered. PHMSA is not obliged to consider them and may dismiss those portions of the Petition without further consideration. However, despite these procedural grounds for dismissal, I have considered the substance of the Petition as discussed in greater detail below and still find it lacking. Finally, Centurion characterized the Petition as an attempt to clarify certain of its previous statements, which Petitioner asserted PHMSA “may have misinterpreted and/or misapplied.”5 Discussion A. Inspection of In-Service Breakout Tanks (49 C.F.R. 195.432) 3 Centurion Pipeline, LP CPF No. 4-2014-5028 (March 30, 2017), available at https://primis.phmsa.dot.gov/comm/reports/enforce/FOCPEvent opid 0 html?nocache=7530# TP 1 tab 3. 4 Petition, at 1. 5 Petition, at 2.#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 4CPF No. 4-2014-5028 Page 3 Item 1 in the Final Order found that Centurion violated 49 C.F.R. § 195.432(b), which states: § 195.432 Inspection of in-service breakout tanks. (a) …. (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 under § 195.402(c)(3)…6 The Final Order found that Petitioner violated 49 C.F.R. § 195.432(b) by failing to conduct monthly Routine In-Service Inspections of breakout Tanks 6832 and 6833 according to American Petroleum Institute Standard 653 (API 653) and assessed a civil penalty of $20,800 for the violation.7 At the time of its inspection, PHMSA requested tank-inspection reports for Petitioner’s breakout tanks for years 2010 through 2013; however, Centurion could not provide monthly inspection reports for breakout Tanks 6832 and 6833 for calendar year 2010, January 2011, February 2011, March 2011, April 2011, and August 2011. PHMSA found that the absence of records supported the finding of violation, particularly since Centurion was required to keep records of monthly breakout-tank inspections pursuant to § 195.404(c)(3).8 In the Petition, Centurion contended that Item 1 of the Final Order should be withdrawn for lack of sufficient evidence. Centurion acknowledged “in retrospect” that it may not have provided a sufficiently detailed explanation of the evidence it had provided at the hearing to show that the company had complied with the requirement to conduct monthly visual inspection of the tanks and that it did not have records for 37 of the 1,248 required inspections for the five tanks at the company’s Wasson Facility. Centurion presented four objections to the finding of violation: (1) that “standing alone, evidence of missing records is not proof that an inspection was not performed – only that a record was not kept;”9 (2) that the company had a robust pipeline inspection program, as well as other compliance inspection programs that looked for similar issues, and therefore it was “less likely” that a violation had occurred; (3) that Centurion’s breakout Tanks 6832 and 6833 were co-located with other tanks for which Centurion had records of the same Routine In-Service Inspections during the relevant time period; and (4) that Centurion had performed and documented visual inspections for breakout Tanks 6832 and 6833 6 API 653, Section 6.3.1.2, states that the length of time between Routine In-Service Inspections shall not exceed one month. 7 The Notice originally proposed civil penalty of $42,400 for Item 1, however, the penalty was reduced to $20,800 for the reasons set forth in the Final Order (at page 12). 8 Section 195.404(c)(3) requires operators to maintain a record for each required inspection. 9 Petition, at 11.#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 5CPF No. 4-2014-5028 Page 4 that “were essentially identical” to those that were required under API 653.10 Based on these assertions, Centurion contended that the preponderance of the evidence supported the conclusion that the company had conducted all of the required monthly Routine In-Service Inspections but had simply failed to maintain adequate records of those inspections.11 I disagree. Centurion previously raised argument (1) in response to the Notice and PHMSA rejected it in the Final Order. Specifically, PHMSA found that Petitioner’s failure to have any records of performing the required inspections constituted credible evidence that Centurion did not perform the inspections as required. As noted in the Final Order, the company “presented no evidence that the inspections actually took place.” If there had been affidavits or other evidence presented at the hearing that supported Centurion’s claim that the inspections had actually taken place, then perhaps there would be a closer question of whether PHMSA had met its burden of proving the violation. However, in the absence of such evidence, PHMSA was justified in relying upon a lack of records that Centurion was separately obliged to keep under § 195.404(c)(3) and Centurion’s own procedures.12 With regard to arguments (2), (3) and (4), Petitioner attempts to demonstrate compliance with § 195.432(b) and the API 653 inspection requirements by presenting evidence that is either unsubstantiated or not determinative of compliance. For example, the fact that Petitioner has procedures for the performance of tank inspections does not demonstrate the procedures were followed or that the tank inspections took place as required by the regulation. Just because an operator has procedures to perform a certain task is immaterial to whether such tasks were actually performed or performed properly. Similarly, the location of breakout Tanks 6832 and 6833 near other tanks for which Centurion conducted monthly Routine In-Service Inspections in January 2010 through April 2011 and August 2011 also does not demonstrate that the requisite API 653 inspection was performed on Tanks 6832 and 6833 during the period at issue. Having a “robust, systematic approach” to inspections also does not demonstrate that the required inspections were performed. Finally, with regard to Centurion’s argument that it performed and documented other visual inspections that were “essentially identical” to those required by API 653, I note that Section 6.3.1.3 of API 653 reads: This routine in-service inspection shall include a visual inspection of the tank's exterior surfaces. Evidence of leaks; shell distortions; signs of settlement; corrosion; and condition of the foundation, paint 10 When a civil penalty is assessed for more than one instance of a violation (e.g., 37 tanks with missed inspections), each additional instance beyond the first typically elevates the total penalty by less than the amount assessed for the first instance, with each additional instance representing a smaller increase in proportion to the total. See, e.g., Plains Pipeline, LP, CPF No. 4-2013- 5007, n.61, 2015 WL 4397455, at *17 (May 22, 2015) (explaining that each additional tank out of compliance elevated the civil penalty by less than the amount assessed for the first). 11 Petition, at 11. 12 Pipeline Safety Violation Report (Violation Report), (October 23, 2014) (on file with PHMSA), at 4.#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 6CPF No. 4-2014-5028 Page 5 coatings, insulation systems, and appurtenances should be documented for follow-up action by an authorized inspector. I have reviewed the Wasson Tank Inspection Records for Tanks 6832 and 6833 that have been provided by Petitioner and attached as Exhibit L to the Petition.13 These records, however, do not address the requirements of API 653, nor do they specify that an inspection was actually performed. The records also do not document the additional inspections such as environmental, health and safety reviews, monthly tank gauging, and mixer and thief-hatch checks that Centurion contends took place. In summary, the record supports, by a preponderance of the evidence, the finding that Petitioner failed to comply with § 195.432(b) and the API 653 Routine In-Service Inspection requirements. Petitioner also asked that the civil penalty of $20,000 for this Item either be eliminated or reduced. Centurion did not make any explicit argument in its Petition as to why the penalty should be reduced under PHMSA’s penalty assessment criteria, but I have nevertheless reviewed both the penalty criteria and how they were applied for this Item. Finally, I have reviewed the Final Order, which already reduced the civil penalty from the proposed amount of $42,400 down to $20,800 on the ground that the company “discovered the non-compliance and took documented action to address the issue” prior to the PHMSA inspection.14 Finding no reason to modify the findings or to reduce further the penalty assessed in the Final Order, PHMSA affirms the violation of § 195.432(b) and the reduced civil penalty of $20,800. Item 2 in the Final Order found that Centurion violated 49 C.F.R. § 195.432(b), as quoted above, by failing to conduct “External Inspections”15 of four breakout tanks (Tanks 6688, 6965, 6948, and 2722) within the required five-year interval, in accordance with API 653, and assessed a civil penalty of $23,600 for the violation. Specifically, it found that with respect to Tank 6688, Centurion had performed an External Inspection on February 5, 2008, but not again until March 7, 2014, exceeding the five-year interval by 394 days. With respect to Tank 6965, the Final Order found that Centurion had performed an External Inspection on August 7, 2008, but not again until October 10, 2013, exceeding the five-year interval by 63 days. With respect to Tank 6948, the Final Order found that Centurion had performed an External Inspection on June 10, 2008, but not 13 Exhibit L to the Petition. This new evidence was presented for the first time with the Petition. Under 49 C.F.R. § 190.243(b), if the Petitioner seeks consideration of additional facts or arguments, “the respondent must submit the reasons why they were not presented prior to issuance of the final order.” The Petitioner failed to present any plausible reason why this evidence was not presented earlier, except that “Centurion did not anticipate PHMSA’s interpretations on certain legal and factual issues.” Response, at 2. Such a rationale, of course, could be made for virtually any new evidence that an operator may seek to present for the first time in a petition. Nevertheless, this new evidence has been considered and is found to be irrelevant. 14 Final Order, at 12. 15 Section 6.3.2.1 of API 653 states: “All tanks shall be given a visual external inspection by an authorized inspector. This inspection shall be called the external inspection and must be conducted at least every 5 years or RCA/4N years (where RCA is the difference between the measured shell thickness and the minimum required thickness in mils, and N is the shell corrosion rate in mils per year) whichever is less. Tanks may be in operation during this inspection.”#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 7CPF No. 4-2014-5028 Page 6 again until March 7, 2014, exceeding the five-year interval by 258 days. Finally, with respect to Tank 2722, the Final Order found that Centurion had performed an External Inspection on October 23, 2007, but not again until June 21, 2013, exceeding the five-year interval by 240 days. In its Petition, Centurion stated that it did not seek reconsideration of the finding of violation for three of the four tanks (Tanks 6688, 6948, and 2722), but only for Tank 6965, on the basis that it had complied with § 195.432(b) and API 653 because the required External Inspection was performed within five “calendar years.” Petitioner argued: (1) that API 653 uses the colloquial term “year;” (2) that commentary from the API Committee (Committee) and legal precedent support the proposition that the term “year” may be understood to mean “calendar year” for compliance purposes; and (3) that PHMSA improperly interpreted API 653 as cited in a previously-issued administrative final order.16 Centurion previously raised arguments (1) and (2) in response to the Notice and PHMSA rejected them in the Final Order. Specifically, PHMSA found that in a 2010 enforcement action, the agency had determined that the five-year inspection period required by § 195.432(b) meant five periods of 365 days each. In that case, PHMSA found that a pipeline operator had violated § 195.432(b) when the company exceeded an inspection interval of five consecutive 365-day periods, even though the operator had performed an inspection within five calendar years.17 Petitioner’s contention regarding development of the API 653 consensus standard was also rejected. Petitioner had argued that a Committee-member representative from a pipeline operator had proposed changing the language in API 653 to make “years” effectively be “calendar years.”18 However, this proposed change from “years” to “calendar years” was not adopted, as seen by the plain language of Section 6.3.2.1 of API 653. Therefore, Centurion’s argument that API 653 should be read to mean “calendar years” fails because the proposal to make such a change was not accepted by the Committee. Moreover, a proposal by an API committee member in the development of a standard is not persuasive or controlling on PHMSA’s interpretation of its own regulations. Furthermore, I find Petitioner’s reliance on two federal cases in support of its argument for Centurion’s interpretation of the term “year” to be unpersuasive and irrelevant. Specifically, Petitioner argues that courts permit the construction of a term to its natural or ordinary meaning absence a statutory definition.19 While neither the Federal Pipeline Safety Laws nor 49 C.F.R. Parts 190-199 defines the term “year,” PHMSA has previously interpreted it to be 365 days in its adjudication of enforcement matters. Additionally, Black’s Law Dictionary defines “year” as “a consecutive 365-day period beginning at any point” or “a span of twelve months.”20 Similarly, 16 Enbridge Pipelines (Ozark), L.L.C., CPF No. 4-2010-5008, 2010 WL 65316*38 (Aug. 17, 2010). 17 Id. (finding violations of the five-year inspection interval for a number of tanks that were inspected within five calendar years, but not within five periods of 365 days). 18 Petition, at Exhibit C. See also Supplemental Response, at 8-9 and Appx. B. 19 Petition, at 10. 20 Black’s Law Dictionary (10th ed. 2014), which notably provides a separate definition for “calendar year.”#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 8CPF No. 4-2014-5028 Page 7 Merriam-Webster’s definition of “year” indicates that it is a period “required for one revolution of the earth around the sun.”21 Finally, with regard to argument (3), Petitioner argued that PHMSA should not rely on the 2010 Final Order because the operator in that case did not contest the violation and agreed to correct the noncompliance. Again, I disagree. I find no reason why an uncontested finding of violation in a published final order should somehow be discounted or dismissed as precedent just because an operator chose not to challenge the facts or law underlying an allegation of violation. Further, I find that even were PHMSA to conclude that the 2010 final order is merely informative, the earlier enforcement action still provided fair notice to Centurion and the regulated community that PHMSA has interpreted § 195.432(b) and API 653 to mean that the visual external- inspection interval must not exceed five consecutive periods of 365 days each, rather than five calendar years. Accordingly, finding no reason to modify the findings in the Final Order, PHMSA affirms the finding of violation of § 195.432(b) and the civil penalty of $23,600. Item 3 in the Final Order found that Centurion violated 49 C.F.R. § 195.432(b), as quoted above, by failing to make Ultrasonic Thickness (UT) measurements of breakout tanks at intervals not to exceed five years, in accordance with API 653, and assessed a civil penalty of $23,600 for the violation. As discussed above, with respect to Tank 6688, it found that Centurion had performed an External Inspection on February 5, 2008, but not again until March 7, 2014, exceeding the five-year interval by 394 days. With respect to Tank 6965, it found that Centurion had performed an External Inspection on August 7, 2008, but not again until October 10, 2013, exceeding the five-year interval by 63 days. With respect to Tank 6948, it found that Centurion had performed an External Inspection on June 10, 2008, but not again until March 7, 2014, exceeding the five-year interval by 258 days. Finally, with respect to Tank 2722, it found that Centurion had performed an External Inspection on October 23, 2007, but not again until June 21, 2013, exceeding the five-year internal by 240 days. In the Petition, Centurion argued that the finding of violation in Item 3 should be withdrawn because the company knew the corrosion rates for its tanks, therefore making them subject to the longer interval for UT testing found in Section 6.3.3.2.b of API 653, and not the five-year interval for tanks with unknown corrosions rates under Section 6.3.3.2.a.22 Specifically, Centurion contended that it had calculated the corrosion rates for the tanks at issue in accordance with API 653 by comparing the actual wall-thickness data for each tank with past and historical tank records. Centurion argued that its calculation method was consistent with API 653 Section 6.3.3.1, which states, in relevant part: “External, ultrasonic thickness measurements of the shell 21 Merriam Webster Dictionary website, available at https://www.merriam-webster.com/dictionary/year (last accessed on May 10, 2019). 22 Section 6.3.2.2(a) of API 653 states: “When used, the ultrasonic thickness measurements shall be made at intervals not to exceed the following: (a) When the corrosion rate is not known, the maximum interval shall be 5 years. Corrosion rates may be estimated from tanks in similar service based on thickness measurements taken at an interval not exceeding 5 years.”#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 9CPF No. 4-2014-5028 Page 8 can be a means of determining a rate of uniform general corrosion while the tank is in service.” Finally, Centurion contended that PHMSA had not cited to any evidence to show that Centurion’s methodology was inconsistent with API 653. With its Petition, Centurion supplemented the evidentiary record with an API 653 Internal Inspection Report for Tank 6688; the remaining records had been previously provided and considered by PHMSA in making its determination in the Final Order. Nevertheless, I have carefully reviewed all of the evidence and find that Centurion has again fallen short of providing PHMSA with evidence demonstrating that it had actually calculated the corrosion rates, and therefore knew the corrosion rates of the tanks at issue at the time of the PHMSA inspection. The records provided by Centurion show that Petitioner did not calculate the corrosion rates in 2007 and 2008 when it conducted those External Inspections. The records with calculated corrosion rates are from 2013 and 2014, and are only for Tanks 6965 and 2722.23 As a matter of fact, the API 653 In-Service Inspection Report with the calculated corrosion rate for Tank 6865 was dated March 7, 2014, which was after the PHMSA inspection. Additionally, these records show that Centurion did not calculate the corrosion rate for all the “courses” of the tank, even though the company had the necessary data to perform said calculations. Finally, Centurion conceded in its Petition that it does not have records of calculated corrosion rates.24 Therefore, since Centurion did not know the corrosion rates for Tanks 6688, 6968, 6948, and 2722 when it performed the External Inspections, those tanks were subject to the five-year interval of API 653 Section 6.3.3.2.a. Finding no reason to modify the findings in the Final Order, PHMSA affirms the violation of § 195.432(b) and the civil penalty of $23,600. B. Pipeline Integrity Management in High Consequence Areas (49 C.F.R. 195.452) Item 5 in the Final Order found that Centurion violated 49 C.F.R. § 195.452(h)(2), which states: § 195.452 Pipeline integrity management in high consequence areas. (a) …. (h) What actions must an operator take to address integrity issues?... (2) Discovery of condition. Discovery of a condition occurs when an operator has adequate information about the condition to determine that the condition presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than 180 days after an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator can demonstrate that the 180-day period is impracticable. The Final Order determined that Petitioner violated 49 C.F.R. § 195.452(h)(2) by failing to obtain sufficient information about an anomalous condition to determine, no later than 180 days after an integrity assessment, if the condition presented a potential threat to the integrity 23 Pre-Hearing Brief, at Appendix A. 24 Petition, at 9, FN 4.#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 10CPF No. 4-2014-5028 Page 9 of the pipeline and assessed a reduced civil penalty of $28,800. The record shows that on December 3, 2011, Petitioner completed an integrity assessment using a T.D. Williamson, Inc. (TDW) SpirALL Magnetic Flux Leakage Multi Data Set tool (SMFL MDS tool or the tool) as part of its continual reassessment of the 16-inch Bretch to Cushing #2 system. The 180-day deadline to obtain sufficient information was therefore May 31, 2012. Although Petitioner experienced a 40-day period prior to the 180-day deadline during which it believed the data might be unusable, the Final Order determined that such delay did not excuse it from compliance with § 195.452(h)(2). In the Petition, Centurion argued that the finding of violation for Item 5 should be withdrawn because (1) the data issues, overall complexity, and novelty of the tool run made it impracticable to discover the condition within 180 days, and (2) relevant PHMSA precedent supported Centurion’s position. With regard to argument (1), § 190.243 requires a petitioner to submit the reasons why any new facts or arguments were not presented prior to issuance of the final order. Centurion has offered no explanation as to why it failed to raise this impracticability argument previously, and, in fact, now expressly contradicts its earlier statements at the hearing and in its Post-Hearing Brief, which dismissed impracticability. For example, Centurion previously stated: This case does not turn on the “impracticability” provision in § 195.452(h)(2). At the time the 16-inch SMFL MDS was launched, no one at Centurion believed it would be impracticable to meet the 180-day deadline. At the time the pig was retrieved in a damaged condition leading to TDW’s declaration of a “Failed Run,” impracticability was not an issue because at that time the 180-day clock effectively reset, and Centurion had to consider a new run. When Centurion shared with TDW its approach to potentially utilize the data from the damaged tool and TDW determined there was “usable data” on January 27, 2012, impracticability ceased to be an issue because Centurion met the 180-day discovery timeframe. Thus, there was no point in this admittedly rare set of circumstances where Centurion believed that completing the discovery process within 180 days after the integrity assessment was impracticable. 25 Based on this prior representation, I find that Centurion has waived its right to raise the argument of impracticability. Notwithstanding this finding, I have reviewed and carefully considered Centurion’s new impracticability claim. PHMSA has previously held that “generally it is not an impracticability where the vendor delay could have been anticipated ahead of time.”26 Centurion states that the “impracticability of meeting the 180-day deadline stems from Centurion’s use of state of the art technology in its pipeline integrity program.”27 Centurion claims that it could not 25 Post-Hearing Brief, at 20; Hearing Transcript, at 107: 16-18. 26 ExxonMobil Pipeline Co., CPF 4-2013-5027, 2015 WL 7175715, at *20 (October 1, 2015). 27 Petition, at 7.#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 11CPF No. 4-2014-5028 Page 10 have foreseen the length of time it would take to gather and analyze the data from the in-line inspection (ILI) run. Centurion emphasized in the record that it used (1) a complex, newly- commercialized ILI technology tool;28 (2) the tool collected “the largest data set ever amassed in a single run by TDW;”29 and (3) the run was the longest in TDW’s history.30 PHMSA has previously concluded that while a “delay by a tool vendor might render discovery within 180 days impracticable, an operator's claim of impracticability requires considering all the relevant facts of the delay. Where an operator's own actions contributed to the delay, as in the present case, PHMSA does not consider that the operator is excused from compliance due to an impracticability.”31 Here, I find that Centurion could have predicted that the 180-day deadline would be problematic. Factors such as a new tool that had never been run before, the large amount of data to be collected by the vendor, and the longest run in the vendor’s history, on their face, contain enough uncertainty and the possibility of difficulties to persuade me that Centurion could have anticipated a delay ahead of time and taken appropriate measures in advance of the inspection to ensure timely discovery, as required by the regulation. Further, Centurion claims that the Final Order “misquotes and misapplies relevant precedent.” Petitioner cites to a lengthier quote from In the Matter of BP Pipelines (North America) Inc., which it alleges changes the application of PHMSA precedent.32 On the contrary, I find that the complete quote in BP Pipeline supports PHMSA’s reasoning that Centurion had useable data collected on the date of the tool run. Furthermore, PHMSA precedent has established that it is the operator’s responsibility to obtain sufficient information under § 195.452(h)(2), except where impracticable; in this case, however, Centurion fell short of doing so within the 180-day timeframe.33 Therefore, I reject this argument that PHMSA’s established precedent supports Centurion’s position. Finding no reason to modify the findings in the Final Order, PHMSA affirms the violation of § 195.452(h)(2). As for the civil penalty, I have reviewed the assessment criteria cited in the Violation Report, along with the evidence and arguments presented, and find that a reduction in 28 Post-Hearing Brief, at 20; Petition, at 6-7; Hearing Transcript, at 33:9-13 29 Post-Hearing Brief, at 20; Petition, at 6; Hearing Transcript, at 35:11-12, 47:12-21, 54:12-20. 30 Post-Hearing Brief, at 20; Petition, at 6; Hearing Transcript, at 46:5-12, 55:7-8. 31 ExxonMobil Pipeline Co., CPF 4-2013-5027 (Decision on Petition for Reconsideration), 2016 WL 2753318, at *9 (April 1, 2016). 32 “[D]iscovery is not tied solely to the date of the tool run but to the fact that at the completion of a tool run there are assessment results from which an operator can obtain sufficient information.” BP Pipelines (North America), Inc., CPF No. 3- 2005-5030, 2006 WL 7129217, at *6 (Sept. 6, 2006)). 33 “Even though § 195.452(h)(2) did not require Respondent to receive a final report within 180 days, it did require Respondent to obtain ‘sufficient information,’ which means enough information to allow an operator to accurately and reliably identify, locate, validate, and evaluate pipeline anomalies detected by the integrity assessment and to properly classify them for repair, if necessary, under § 195.452(h).” Alyeska Pipeline Service Company, CPF No. 5- 2006-5018, Final Order, at 4-5 (issued Jan. 13, 2010)#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 12CPF No. 4-2014-5028 Page 11 the penalty for good faith is warranted for this Item. Specifically, while Centurion’s use of new and innovative ILI technology does not excuse the company from failing to comply with § 195.452(h)(2), it does provide a reasonable rationale for Centurion’s delay in meeting the 180- day deadline for discovery. Accordingly, a reduced civil penalty of $14,400 is assessed for the violation. Item 6 in the Final Order found that Centurion violated 49 C.F.R. § 195.452(h)(4), which states: § 195.452 Pipeline integrity management in high consequence areas. (a) …. (h) What actions must an operator take to address integrity issues?... (4) Special requirements for scheduling remediation -- (i) Immediate repair conditions. An operators’ evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce the operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formulas referenced in paragraph (h)(4)(i)(B) of this section. If no suitable remaining strength calculation method can be identified, an operator must implement a minimum 20 percent or greater operating pressure reduction, based on actual operating pressure for two months prior to the date of inspection, until the anomaly is repaired. An operator must treat the following conditions as immediate repair conditions: (A) Metal loss greater than 80% of nominal wall regardless of dimensions. (B) A calculation of the remaining strength of the pipe shows a predicted burst pressure less than the established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (incorporated by reference, see § 195.3) and PRCI PR-3-805 (R-STRENG) (incorporated by reference, see § 195.3). (C) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) that has any indication of metal loss, cracking or a stress riser. (D) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 6% of the nominal pipe diameter. (E) An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action. The Final Order found that Petitioner violated 49 C.F.R. § 195.452(h)(4) by failing to lower the operating pressure or shutting down the pipeline upon discovering six immediate-repair conditions and assessed a civil penalty of $40,300 for the violation. Specifically, PHMSA found that upon discovering six immediate-repair conditions on July 11, 2012, Centurion failed to reduce the operating pressure or shut down the pipeline until it completed the repairs on August 3, 2012. The conditions were classified as immediate-repair conditions, which prompted Petitioner to schedule excavations to validate the conditions. However, the company failed either “to reduce operating pressure or shut down the pipeline” until the company could#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 13CPF No. 4-2014-5028 Page 12 complete the repair.34 Furthermore, Centurion had enough information to classify the conditions prior to excavation and did in fact classify them as immediate repairs, thereby obligating the company to reduce operating pressure or shut down the pipeline even if the classification turned out to be a conservative estimate. In the Petition, Centurion argued that the finding of violation in Item 6 should be withdrawn for the following reasons: (1) Centurion’s ANSI / ASME Standard B31.4 (Std B31.4) calculations yielded a safe operating pressure that was higher than the operating pressure in use at the time; and (2) the allegation of violation runs contrary to PHMSA’s own guidance contained in the preamble of the 2002 final rule amending 49 C.F.R. § 195.452(h)(4), which indicated that “pressure reductions should be based on an engineering evaluation…… Centurion performed that calculation and operated its pipeline at a safe operating pressure below the operating pressure yielded by the required calculation.”35 With regard to argument (1), Centurion now contends that it provided evidence of its Std B31.4 calculations for the record and that this evidence was not properly considered by PHMSA in the Final Order.36 But this argument was not presented prior to issuance of the final order.37 Despite being provided ample opportunity to raise this argument of its Std B31.4 calculations yielding a safe operating pressure prior to the Final Order, such as in its pre- and post-hearing submissions or at the hearing, Centurion failed to do so and is now raising this argument for the first time without explaining why it was not presented previously. Nevertheless, I find that Petitioner’s argument falls short of demonstrating compliance with § 195.452(h)(4). Section 195.452(h)(4)(i) requires an operator to temporarily reduce pressure or shut down the pipeline upon discovery of an immediate-repair condition, until the condition is repaired. The Final Order determined that Centurion should have reduced the operating pressure or shut down the affected pipeline when it identified six conditions as immediate-repair conditions on July 11, 2012. The records produced by Centurion fail to demonstrate that it took such action in accordance with § 195.452(h)(4). Centurion was required to reduce the operating pressure to a minimum pressure not less than twenty percent of the highest operating pressure occurring at the anomaly’s locations during the preceding sixty days.38 Pursuant to Centurion’s pressure-reading charts from the preceding two months, the highest discharge pressure occurred on June 5, 2012 at approximately 700 psi, which means Centurion was required to reduce pressure to 140 psi. However, the discharge operating pressure for the affected immediate-repair conditions from July 12, 2012, to August 3, 2012, ranged from approximately 480 psi to 620 psi, higher than the 34 Final Order, at 11. 35 Petition, at 3-4. 36 See Petitioner’s Exhibit F. I note that these records were previously attached to OPS’ Violation Report in support of Item 6. (See also PHMSA Violation Report, dated October 23, 2014, at 310-319.) 37 49 C.F.R. § 190.243(b). 38 Section 7.1.2, Action Required Upon Discovery of an Immediate Repair Condition, Centurion’s Integrity Management Plan (IMP).#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 14CPF No. 4-2014-5028 Page 13 safe pressure permitted by the regulation.39 Therefore, Centurion failed to reduce the operating pressure to a minimum pressure not less than twenty percent of the highest operating pressure occurring in the preceding sixty days in accordance with its IMP procedures or § 195.452(h)(4). With regard to argument (2), Centurion is again raising a new argument without indicating why it failed to previously raise it prior to issuance of the Final Order. Specifically, Centurion contends that PHMSA is acting contrary to its own guidance from the 2002 final rule that amended § 195.452(h)(4).40 Specifically, Petitioner relies on a limited statement within the preamble, without providing the full context of PHMSA’s statement, which reads as follows: [PHMSA] agree[s] that pressure reductions should be based on an engineering evaluation, and changed the final rule accordingly. Although it is appropriate to base the pressure reduction on the remaining wall thickness for corrosion, this may not be the best method on which to base a pressure reduction for dents and gouges. We modified the requirement so that an operator must calculate the temporary reduction in the operating pressure using the formula in section 451.7 of ASME/ANSI B31.4.41 As previously discussed, Petitioner does not demonstrate how the determination in the Final Order or the above analysis runs contrary to the preamble language, which dealt with the issue of the proper amount of a pressure reduction. The allegation of violation here does not involve the amount of a pressure reduction but whether one was taken at all. The evidence is clear in this case that Centurion neither took a pressure reduction nor shut down the pipeline in the face of a potentially serious safety risk. The language of the regulation is clear: the operator must take one action or the other. Additionally, Petitioner’s argument is contrary to the clear language in its own IMP procedures and the plain language of the code. Therefore, I conclude Centurion’s argument is without merit. Finding no reason to modify the findings in the Final Order or the amount of the assessed penalty, PHMSA affirms the violation of § 195.432(h)(4) and the civil penalty of $40,300. Conclusion Based on a review of the record and the information provided in the Petition, I hereby deny the Petition in part and grant it in part, for the reasons set forth above. Payment of the reduced civil penalty of $122,700 for Items 1, 2, 3, 5 and 6 is now due and must be made within 20 days of service of this Decision. The payment instructions were set forth in detail in the Final Order. Failure to pay the $122,700 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 39 Id. 40 67 FR 1650, 1654-1655. 41 Id.#

420145028_Decision on Petition for Reconsideration_06272019_text.pdf, page 15CPF No. 4-2014-5028 Page 14 annum will be charged if payment is not made within 110 days of service. Furthermore, failure to pay the civil penalty may result in referral of the matter to the Attorney General for appropriate action in a United States District Court. This Decision constitutes final agency action taken by PHMSA in the enforcement proceeding. The terms and conditions of this Decision are effective upon service in accordance with 49 C.F.R. § 190.5. June 27, 2019 _____________________________ __________________________ Alan K. Mayberry Date Issued Associate Administrator for Pipeline Safety#

420145028_Final Order_03302017_text.pdf, page 1Official PDFMarch 30, 2017 Mr. Mike Morgan General Manager - Operations Centurion Pipeline L.P. 5 Greenway Plaza, Suite 110 Houston, TX 77046 Re: CPF No. 4-2014-5028 Dear Mr. Morgan: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation and assesses a reduced civil penalty of $137,100. The penalty payment terms are set forth in the Final Order. This enforcement action closes automatically upon receipt of payment. Service of the Final Order by certified mail is effective as 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: Mr. R.M. Seeley, Director, Southwest Region, PHMSA, OPS Mr. Ahren Tryon, Tryon Law Firm, 4148 Hockaday Drive, Dallas, Texas 75229 CERTIFIED MAIL - RETURN RECEIPT REQUESTED#

420145028_Final Order_03302017_text.pdf, page 2CPF No. 4-2014-5028 Page 2 U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION OFFICE OF PIPELINE SAFETY WASHINGTON, D.C. 20590 ___________________________________ In the Matter of ) Centurion Pipeline, LP, ) a subsidiary of Occidental ) CPF No. 4-2014-5028 Petroleum Corporation, ) ) ) ) Respondent. ) ___________________________________ ) FINAL ORDER From April 2013 to February 2014, 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 Centurion Pipeline, LP (Centurion or Respondent) in Texas, New Mexico, and Oklahoma. Centurion operates approximately 2,500 miles of pipeline transporting crude oil in Texas, New Mexico, and Oklahoma.1 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Respondent, by letter dated November 10, 2014, 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 Centurion had committed six violations of 49 C.F.R. Part 195 and proposed a civil penalty of $165,900 for the alleged violations. The Notice also proposed certain corrective measures to correct one of the alleged violations. Centurion responded to the Notice by letter dated December 17, 2014. Centurion contested several of the allegations and requested a hearing. Centurion submitted an additional written response on April 20, 2015 (Supplemental Response). In accordance with 49 C.F.R. § 190.211, a hearing was held in Houston, Texas, on April 30, 2015, before a Presiding Official from the Office of Chief Counsel, PHMSA. After the hearing, Respondent provided a post-hearing statement for the record dated June 26, 2015 (Closing), as well as on September 4, 2015 (Supplemental Closing). Pursuant to § 190.209(b)(7), the Director submitted a written evaluation of Respondent’s response material on July 28, 2015 (Recommendation). 1 This information is reported by Centurion for calendar year 2015 pursuant to 49 C.F.R. § 195.49.#

420145028_Final Order_03302017_text.pdf, page 3CPF No. 4-2014-5028 Page 3 FINDINGS 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. § 195.432(b), which states in relevant part: § 195.432 Inspection of in-service breakout tanks. (a) . . . . (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).2 The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) by failing to conduct monthly Routine In-Service Inspections of breakout tanks 6832 and 6833 according to API Standard 653 (API 653). At the time of the inspection, inspection reports were requested for Respondent’s breakout tanks for the years 2010 through 2013. Respondent could not provide monthly inspection reports for breakout tanks 6832 and 6833 for calendar year 2010, January 2011, February 2011, March 2011, April 2011, and August 2011. In its Supplemental Response, Respondent claimed the evidence did not support finding the Company had failed to perform the inspections, but only that Respondent was unable to produce documentation of the inspections. Respondent admitted that it could not produce the inspection reports, but argued that it had identified recordkeeping issues on its own prior to the OPS inspection and had fixed the issue. Respondent argued that it “was in continual compliance with the regulation for all of its breakout tanks but two, and the administrative oversight happened over a limited time period.”3 Respondent presented no evidence that the inspections actually took place. The absence of records supports finding a violation, particularly since records of monthly breakout tank inspections are required to be kept pursuant to the pipeline safety regulations.4 Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.432(b) by failing to conduct monthly Routine In-Service Inspections of breakout tanks 6832 and 6833 according to API 653. 2 API 653, Section 6.3.1.2 states the time between Routine In-Service Inspections shall not exceed one month. 3 Supplemental Response at 7. 4 § 195.404(c)(3) (requiring an operator to maintain a record of each required inspection).#

420145028_Final Order_03302017_text.pdf, page 4CPF No. 4-2014-5028 Page 4 Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b), which states in relevant part: § 195.432 Inspection of in-service breakout tanks. (a) . . . . (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).5 The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) by failing to conduct External Inspections of four breakout tanks, 6688, 6965, 6948, and 2722 within the required five- year interval according to API 653. With respect to tank 6688, Respondent performed an External Inspection on February 5, 2008, and then March 7, 2014, which exceeded the five-year interval by 394 days. With respect to tank 6965, Respondent performed an inspection on August 7, 2008, and then October 10, 2013, which exceeded the five-year interval by 63 days. With respect to tank 6948, Respondent performed an inspection on June 10, 2008, and then March 7, 2014, which exceeded the five-year interval by 258 days. Finally, with respect to tank 2722, Respondent performed an inspection on October 23, 2007, and then June 21, 2013, which exceeded the five-year interval by 240 days. Respondent did not dispute that it exceeded the external inspection interval with respect to breakout tanks 6688, 6948 and 2722, but disputed breakout tank 6965.6 Respondent argued that “PHMSA’s inspectors may have cited Respondent because the time period between the external inspections was 1890 days, or 5 years and two months. However, this is not a violation of 49 CFR 195.432(b). The follow-up external inspection occurred within five calendar years of the previous external inspection.”7 Section 195.432(b) requires an operator to inspect a breakout tank according to API 653. One of the inspection requirements in the API Standard is Section 6.3.2.1, which requires a visual in- service inspection “conducted at least every 5 years.” Respondent argued that “every 5 years” means at least once every five calendar years. For example, under Respondent’s reasoning, an operator may inspect a tank in January 2010 and then again in December 2015. 5 API 653, Section 6.3.2.1 states, “All tanks shall be given a visual external inspection by an authorized inspector. This inspection shall be called the external inspection and must be conducted at least every 5 years or RCA/4N years (where RCA is the difference between the measured shell thickness and the minimum required thickness in mils, and N is the shell corrosion rate in mils per year) whichever is less. Tanks may be in operation during this inspection.” 6 Supplemental Response at 8. 7 Supplemental Response at 8 (emphasis added).#

420145028_Final Order_03302017_text.pdf, page 5CPF No. 4-2014-5028 Page 5 Respondent’s assertion is incorrect. PHMSA has previously determined the five-year inspection period required by § 195.432(b) means five periods of 365 days. In a previous final order, PHMSA found a pipeline operator had violated § 195.432(b) when the operator exceeded the inspection interval of five 365-day periods, even though the operator had performed the inspection within five calendar years.8 This means that if an operator inspects a tank in January 2010, the tank must be inspected again no later than January 2015. Respondent cited to another case in which PHMSA found a violation of § 195.432(b) after an operator “never conducted an external inspection in the 5-year period between 2001 and 2006.”9 It is not evident from that decision, however, when or if the operator actually conducted inspections in 2001 and 2006. Respondent also contended that during development of the API 653 consensus standard “both approaches [five 365-day periods and five calendar years] were accepted and used by the API committee member representatives.”10 I do not find this information persuasive or controlling, most notably because PHMSA has already determined the five-year inspection period means five periods of 365 days. Respondent exceeded the five-year external inspection period for each of the four tanks listed in the Notice. After considering the evidence, I find that Respondent violated 49 C.F.R. § 195.432(b) by failing to conduct External Inspections of four breakout tanks within the required five-year interval according to API 653. Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b), which states in relevant part: § 195.432 Inspection of in-service breakout tanks. (a) . . . . (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).11 8 Enbridge Pipelines (Ozark), L.L.C., CPF No. 4-2010-5008, Item 1, 2010 WL 6531638 (Aug. 17, 2010) (finding violations of the five-year inspection interval for a number of tanks that were inspected within five calendar years, but not within five periods of 365 days). 9 Belle Fourche Pipeline Co., CPF No. 5-2009-5042, Item 11, 2011 WL 7006607 (Nov. 21, 2011). 10 Supplemental Closing at 4. 11 API 653, Section 6.3.3.2(a) states, “When used, the ultrasonic thickness measurements shall be made at intervals not to exceed the following: (a) When the corrosion rate is not known, the maximum interval shall be 5 years. Corrosion rates may be estimated from tanks in similar service based on thickness measurements taken at an interval not exceeding 5 years.”#

420145028_Final Order_03302017_text.pdf, page 6CPF No. 4-2014-5028 Page 6 The Notice alleged that Respondent violated § 195.432(b) by failing to make Ultrasonic Thickness (UT) measurements of breakout tanks at intervals not to exceed five years according to API 653. Specifically, the Notice alleged that Respondent failed to perform the measurements within the maximum interval for breakout tanks 6688, 6965, 6948, and 2722. With respect to tank 6688, Respondent performed a UT inspection on February 5, 2008, and then March 7, 2014, which exceeded the five-year interval by 394 days. With respect to tank 6965, Respondent performed a UT inspection on August 7, 2008, and then October 10, 2013, which exceeded the five-year interval by 63 days. With respect to tank 6948, Respondent performed a UT inspection on June 10, 2008, and then March 7, 2014, which exceeded the five-year interval by 258 days. Finally, with respect to tank 2722, Respondent performed a UT inspection on October 23, 2007, and then June 21, 2013, which exceeded the five-year interval by 240 days. In its Supplemental Response, Respondent stated that the five-year interval only applies when the corrosion rate is unknown, and the five-year interval did not apply in this case because Centurion “was well aware of the corrosion rate for the cited breakout tanks.”12 Respondent explained that it had “adequate experience and UT inspection results with a large number of regulated and unregulated crude oil tanks to conclude that the corrosion rate on these tanks” justified “establishing a 10-year [UT] inspection interval.”13 It stressed that the thickness testing went beyond PHMSA’s requirements because Respondent “considers the single spot on each course with the minimum thickness for the course in its shell integrity evaluations, rather than averaging the readings to obtain the general thickness, and rate of general corrosion, of the shell.”14 For the breakout tanks at issue, based on its test results, Respondent determined that “a longer [UT] inspection interval was warranted based on the fact that these and all other tanks have experienced such a consistently low rate of internal corrosion since their installation.”15 OPS responded that Respondent’s claim of using Minimum Wall Thickness was invalid. OPS requested and discussed corrosion rates for these tanks on several occasions with Respondent during the inspection. Respondent did not provide any evidence that it had calculated corrosion rates or estimated corrosion rates from tanks in similar service based on thickness measurements. Instead, Respondent stated that it had adequate experience and many UT inspection results. In order to estimate corrosion rates from other tanks in similar service, OPS argued that Respondent needed to perform an adequate Similar Service Assessment of the tanks, as required by API 653. The evidence demonstrates Respondent did not properly calculate corrosion rates for the tanks at issue. Therefore, Respondent was required to comply with the five-year maximum interval for UT inspections. While Respondent repeated its assertion from Item 2 that the five-year inspection interval means five calendar years, that argument is rejected for the same reasons stated above. 12 Supplemental Response at 10. 13 Supplemental Response at 10. 14 Supplemental Response at 10. 15 Supplemental Response at 10.#

420145028_Final Order_03302017_text.pdf, page 7CPF No. 4-2014-5028 Page 7 Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.432(b) by failing to make UT measurements of breakout tanks at intervals not to exceed five years according to API 653. Item 4: The Notice alleged that Respondent violated 49 C.F.R. §§ 195.202 and 195.264 which state in relevant part: § 195.202 Compliance with specifications or standards. Each pipeline system must be constructed in accordance with comprehensive written specifications or standards that are consistent with the requirements of this part. § 195.264 Impoundment, protection against entry, normal/emergency venting or pressure/vacuum relief for aboveground breakout tanks. (a) A means must be provided for containing hazardous liquids in the event of spillage or failure of an aboveground breakout tank195.446 Control room management. (b) After October 2, 2000, compliance with paragraph (a) of this section requires the following for the aboveground breakout tanks specified: (1) For tanks built to API Specification 12F, API Standard 620, and others (such as API Standard 650 or its predecessor Standard 12C), the installation of impoundment must be in accordance with the following sections of NFPA 30: (i) Impoundment around a breakout tank must be installed in accordance with section 4.3.2.3.2; and (ii) Impoundment by drainage to a remote impounding area must be installed in accordance with section 4.3.2.3.1. The Notice alleged that Respondent violated 49 C.F.R. §§ 195.202 and 195.264 by failing to construct several breakout tanks in accordance with comprehensive written specifications or standards that are consistent with the requirements of this part. Specifically, the Notice alleged that Respondent failed to have specifications that demonstrated breakout tank containment impoundments met the requirements of NFPA 30 referenced in § 195.264. The Notice also alleged that Respondent failed to present documentation, such as surveys or calculations, for any of their breakout tanks constructed after October 2, 2000, to verify containment impoundment volumes met the requirements of NFPA 30. Respondent did not contest this allegation of violation. Accordingly, after considering the evidence, I find that Respondent violated 49 C.F.R. §§ 195.202 and 195.264 by failing to construct several breakout tanks in accordance with comprehensive written specifications or standards that are consistent with the requirements of this part. Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h)(2), which states in relevant part:#

420145028_Final Order_03302017_text.pdf, page 8CPF No. 4-2014-5028 Page 8 § 195.452 Pipeline integrity management in high consequence areas. (a) . . . . (h) What actions must an operator take to address integrity issues? . . . (2) Discovery of condition. Discovery of a condition occurs when an operator has adequate information about the condition to determine that the condition presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than 180 days after an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator can demonstrate that the 180-day period is impracticable. The Notice alleged that Respondent violated 49 C.F.R. § 195.452 by failing to obtain sufficient information no later than 180 days after an integrity assessment to determine if a condition presented a potential threat to the integrity of its pipeline. Specifically, the Notice alleged that on December 3, 2011, Respondent completed an assessment using a T.D. Williamson, Inc. (TDW) SpirALL Magnetic Flux Leakage Multi Data Set tool (SMFL MDS tool or the tool) as part of its continual reassessment of the 16-inch Bretch to Cushing #2 system. The Notice alleged the 180-day deadline to discover conditions was 180 days from the date of the tool run, or no later than May 31, 2012. The Notice alleged that Respondent discovered six immediate repair anomalies on July 11, 2012, which exceeded the 180-day deadline by 41 days. Respondent argued that it did not fail to meet the 180-day deadline because the 180-day assessment period had “reset” on December 15, 2011, when the Company was told the tool run had failed and would need to be rerun.16 Respondent explained that when the tool was retrieved on December 3, 2011, it had suffered extensive damage. The damage “called into question whether or not any salvageable data could be extracted from the ILI [inline inspection] tool much less whether such data would be reliable.”17 The tool vendor determined the tool had collected a large quantity of data, but warned Respondent on December 7, 2011, there was evidence that the data might be unreliable. On December 15, 2011, the vendor informed Respondent that the inline inspection (ILI) run was a “Failed Run” due to data quality issues and an inability to retrieve a sufficient data set from the tool for data evaluation and integration under the specified anomaly detection parameters.18 Respondent received over 500GB of data from TDW.19 Despite having “staffing capabilities to look at a very small portion of the data” and having issues with TDW’s technology for grading the full ILI run, Respondent was able to examine a sample of the raw data between December 15 and December 20, 2011.20 Respondent and TDW worked together throughout late December 2011 and January 2012. On January 27, 2012, TDW declared the tool run data usable and agreed 16 Closing at 3. 17 18 19 Closing at 3; TDW Aff. at ¶ 13. Closing at 3; TDW Aff. at ¶ 17. Closing at 3; TDW Aff. at ¶ 17. 20 Closing at 4.#

420145028_Final Order_03302017_text.pdf, page 9CPF No. 4-2014-5028 Page 9 to start grading the data.21 Respondent ultimately identified six anomalies that met its immediate repair criteria.22 Respondent claimed that “TDW’s acceptance of the data on January 27, 2012, was critical because before that time, Centurion was left with a ‘Failed Run’ designation and a data set that was of no use given that Centurion could not have fully processed and graded it.”23 Therefore, it argued, the “clock” had stopped on the 180-day assessment and did not reset until TDW agreed the data could be used. In response to OPS’s suggestion that Respondent could have processed the data itself,24 Respondent claimed that “Centurion would not and could not attempt to grade the SMFL Multi Data Set in-line inspection data from TDW.”25 Respondent further stated that its actions resulted in a “better outcome from a regulatory and safety standpoint than if Centurion had opted for the other legally permissible approach of adhering to the ‘Failed Run’ designation and conducting a new ILI run within the allotted reassessment interval (October 2012).”26 At the hearing, OPS disagreed the 180-day period ever stopped or reset. OPS argued that pursuant to guidance IMP FAQ 4.13, a “reset” is appropriate only when the “quality of the ILI data is suspect and an entire successful rerun of the ILI tool is performed.”27 Moreover, an assessment is considered complete “on the date which final field activities related to the assessment is performed.”28 Because Respondent did not perform a rerun of the assessment, OPS argued that no reset occurred.29 At the hearing, the Director claimed Respondent had usable data, which meant the 180-day deadline ran from the integrity assessment on December 15, 2011.30 Analysis Pursuant to the integrity management regulations, after an operator performs an integrity assessment, it must “obtain, within 180 days, the assessment data and determine whether conditions presented a threat to the pipeline.”31 Discovery is tied “to the fact that at the 21 Closing at 4; TDW Aff. at ¶ 22. 22 Closing at 5. 23 Closing at 12. 24 Closing at 14; Tr. at 87-88. 25 Closing at 15-16; Mitchell Aff. at ¶¶ 6 to 9, 13 to 14. 26 Closing at 15-16. 27 PHMSA IMP FAQ 4.13. 28 Recommendation at 6-7; PHMSA IMP FAQ 4.13. 29 Recommendation at 7. 30 Tr. at 89. 31 BP Pipelines (North America) Inc., CPF No. 3-2005-5030, Final Order, 2006 WL 4453895, aff’d, Decision on Petition for Reconsideration, at 2, 2006 WL 7129217 (Sep. 6, 2006); Alyeska Pipeline#

420145028_Final Order_03302017_text.pdf, page 10CPF No. 4-2014-5028 Page 10 completion of a tool run there are assessment results from which an operator can obtain sufficient information about the condition to determine that condition presents a potential threat to the integrity of the pipeline.”32 In a prior enforcement decision, PHMSA explained that: While it is usually evident when an integrity assessment is completed (e.g., at the conclusion of a pressure test or ILI tool run), PHMSA has issued guidance to assist operators in applying the regulation in less common situations. Among other things, FAQ 4.13 provides that if ILI tool run data is determined to be “suspect and an entire rerun is to be performed, then the evaluation will be expected within 180 days after the successful rerun.”33 In the current proceeding, Centurion performed an integrity assessment that was completed on December 3, 2011. The regulation required Respondent to analyze the data and determine whether the conditions in the pipe presented a threat within 180 days. Respondent did not perform a rerun and did not otherwise argue the 180-day requirement was impracticable. Following the tool run on December 3, 2011, there was approximately 40 days between December 15, 2011, and January 27, 2012, during which Respondent believed the tool data was unusable. But once Respondent understood the data was usable on January 27, 2012, Respondent had more than 120 days before the regulatory deadline to determine the conditions on the pipeline. Respondent has not contended, nor do I find, this constituted an impracticability. Respondent’s notable effort to salvage workable data from a potentially failed tool run is considered below in the penalty assessment section. After considering all of the evidence, however, I find that Respondent violated 49 C.F.R. § 195.452(h)(2) by failing to obtain sufficient information about a condition to determine if the condition presented a potential threat to the integrity of the pipeline no later than 180 days after the integrity assessment. Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h)(4), which states in relevant part: Service Co., CPF No. 5-2006-5018, Final Order at 2, 2010 WL 6500066, aff’d Decision on Petition for Reconsideration, 2010 WL 2228550 (Mar. 1, 2010) (finding that the operator violated 49 C.F.R. § 195.452(h)(2) by failing to promptly obtain, within 180 days after an integrity assessment, sufficient information about anomalous conditions on the pipeline to determine if they present a potential threat to integrity where vendor data was not provided until approximately 330 days after the integrity assessment). 32 BP Pipelines (North America) Inc., CPF No. 3-2005-5030, Decision on Petition for Reconsideration, at 4, 2006 WL 4453895 (Sep. 6, 2006). 33 ExxonMobil Pipeline Co., CPF No. 4-2011-5016, Final Order at 21, 2013 WL 4478404 (June 27, 2013) (citing PHMSA IMP FAQ 4.13), aff’d, Decision on Petition for Reconsideration, 2014 WL 4635422 (July 9, 2014).#

420145028_Final Order_03302017_text.pdf, page 11CPF No. 4-2014-5028 Page 11 § 195.452 Pipeline integrity management in high consequence areas. (a) . . . . (h) What actions must an operator take to address integrity issues? . . . (4) Special requirements for scheduling remediation—(i) Immediate repair conditions. An operator’s evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formula in Section 451.6.2.2 (b) of ANSI/ASME B31.4 (incorporated by reference, see § 195.3). An operator must treat the following conditions as immediate repair conditions: (A) Metal loss greater than 80% of nominal wall regardless of dimensions. (B) A calculation of the remaining strength of the pipe shows a predicted burst pressure less than the established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (“Manual for Determining the Remaining Strength of Corroded Pipelines” (1991) or AGA Pipeline Research Committee Project PR-3-805 (“A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe” (December 1989)). These documents are incorporated by reference and are available at the addresses listed in Sec. 195.3. (C) A dent located on the top of the pipeline (above the 4 and 8 o’clock positions) that has any indication of metal loss, cracking or a stress riser. (D) A dent located on the top of the pipeline (above the 4 and 8 o’clock positions) with a depth greater than 6% of the nominal pipe diameter. (E) An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action. The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h)(4) by failing to temporarily reduce operating pressure or shut down a pipeline until repairs of immediate conditions were completed. Specifically, the Notice alleged that Respondent discovered six immediate repair conditions on July 11, 2012, but failed to reduce operating pressure or shut down the pipeline until the completion of the repairs on August 3, 2012. Respondent argued that it did not violate the regulation for two reasons. First, Respondent argued there were no immediate repair conditions. Respondent stated that the locations were incorrectly identified as having dents with metal loss because the ILI tool “produced high- resolution data sets with such granularity that it was capable of picking up what Centurion found to be mill defects.”34 In other words, Respondent had acted on “preliminary information out of an abundance of caution” and upon digging up the conditions found only “very small dent[s] but 34 Respondent Post-hearing Brief at 25 (emphasis omitted).#

420145028_Final Order_03302017_text.pdf, page 12CPF No. 4-2014-5028 Page 12 no metal loss at each site.”35 Second, Respondent argued that even if the conditions were immediate repair conditions, Respondent complied with the regulation by repairing the defects within about two hours of digging up the conditions. Analysis Section 195.452(h)(4) requires a pipeline operator to remediate integrity issues according to a schedule. Certain conditions must be repaired immediately, including any dent on the top of the pipeline that has any indication of metal loss. An operator must immediately reduce pipeline operating pressure or shut down a pipeline that has an immediate repair condition until the repair is completed. Respondent identified six conditions on July 11, 2012. The conditions were classified as immediate repair conditions causing Respondent to schedule excavations to validate the conditions. Although Respondent may not have known for certain if the conditions met immediate repair criteria until their excavations, Respondent had enough information to classify the conditions and Respondent did in fact classify them as immediate repairs. This obligated Respondent to reduce operating pressure or shut down the pipeline even if classification of the conditions was a conservative estimate based on the information available.36 In prior enforcement proceedings, PHMSA has consistently determined that an operator must comply with § 195.452(h)(4) and reduce operating pressure or shut down the pipeline, even if the operator’s classification of a condition is a conservative estimate. PHMSA has also determined that § 195.452(h)(4) requires a pressure reduction or shutdown even if the condition meets immediate repair criteria only after factoring in conservative tool tolerances.37 After considering the evidence, I find that Respondent violated 49 C.F.R. § 195.452(h)(4) by failing to lower operating pressure or shut down the pipeline upon discovering six immediate repair conditions. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed $200,000 per violation for each day of the violation, up to a maximum of $2,000,000 for any related series of violations. 35 Respondent Post-hearing Brief at 25. 36 See, e.g., Alyeska Pipeline Service Co., CPF 5-2006-5018, Item 2, 2010 WL 6500066, at *4 (Jan. 13, 2010) (finding an anomaly must be treated as an immediate repair condition once the operator determines it could meet the immediate repair criteria, even if the operator's determination is a conservative estimate.) 37 ExxonMobil Pipeline Co., CPF No. 4-2013-5027, Item 5, 2015 WL 7175715, at *17 (Oct. 1, 2015).#

420145028_Final Order_03302017_text.pdf, page 13CPF No. 4-2014-5028 Page 13 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 $165,900 for the violations cited above. Item 1: The Notice proposed a civil penalty of $42,400 for Respondent’s violation of 49 C.F.R. § 195.432(b), for failing to conduct monthly inspections of two breakout tanks. Respondent requested that the penalty be eliminated due to the alleged insufficiency of the record compiled by PHMSA with respect to the assessment criteria requirements of 49 C.F.R. § 190.225. Having reviewed the record, including the Violation Report, which discusses each of the assessment factors for each of the violations, I find Respondent’s argument does not warrant elimination of the penalty. With regard to nature and circumstances, OPS noted in the Violation Report this violation concerned a failure to provide reports that documented monthly tank inspections. Respondent argued that the penalty should be reduced under these factors because the violation was simply a failure to keep records and only involved two tanks for a limited period of time. I reject this argument. Respondent failed to provide any evidence that the required monthly inspections were actually conducted and the time period in question is not insignificant. With regard to gravity, OPS noted in the Violation Report that safe operation was minimally affected. Respondent did not challenge this assessment. With regard to good faith, the Violation Report suggested no credit. Respondent argued that the penalty should be reduced under this factor because the violation only involved two tanks for a limited period of time, the Company complied with the regulation for other tanks, and the Company corrected the non-compliance before the inspection. I reject these arguments. The number of tanks and the period of non-compliance warrants the proposed civil penalty. With regard to culpability, OPS noted in the Violation Report that the operator failed to take appropriate steps to comply with a requirement that was clearly applicable. Respondent argued that the penalty should be reduced under this factor because it discovered the non-compliance and took documented action to address the issue. I find Respondent’s argument persuasive. The record reflects that Respondent had monthly inspection records for all breakout tanks after August 2011. Since Respondent discovered and corrected the non-compliance before the OPS inspection, a reduction to the penalty is appropriate. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a reduced civil penalty of $20,800 for violation of 49 C.F.R. § 195.432(b).#

420145028_Final Order_03302017_text.pdf, page 14CPF No. 4-2014-5028 Page 14 Item 2: The Notice proposed a civil penalty of $23,600 for Respondent’s violation of 49 C.F.R. § 195.432(b), for failing to conduct five-year external inspections of four breakout tanks. With regard to nature and circumstances OPS noted in the Violation Report that this violation concerned a failure to inspect the breakout tanks at the proper interval to evaluate suitability for continued service, which presented a risk to pipeline safety. Respondent argued that the penalty should be reduced because breakout tank 6965 was inspected within five calendar years. Since the finding of violation already explains how Respondent violated the regulation, this argument is rejected. With regard to gravity, OPS noted in the Violation Report that safe operation was minimally affected. Respondent did not challenge this assessment. The Violation Report suggested no credit under the culpability and good faith factors. In support of reduction of the penalty under these factors, Respondent only repeated arguments that have already been rejected. As operator of the pipeline facility, Respondent is culpable for this violation of the pipeline safety regulations. I have also weighed Respondent’s history of prior offenses and find that when viewed as a whole, it supports the proposed penalty and does not warrant reduction. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $23,600 for violation of 49 C.F.R. § 195.432(b). Item 3: The Notice proposed a civil penalty of $23,600 for Respondent’s violation of 49 C.F.R. § 195.432(b), for failing to make ultrasonic thickness measurements of four breakout tanks. With regard to nature and circumstances, OPS noted in the Violation Report that this violation concerned a failure to measure thickness of the tanks at the proper interval to evaluate suitability for continued service, which presented a risk to pipeline safety. Respondent argued that this item should be withdrawn because the Company was well aware of the corrosion rate for the cited breakout tanks based on thickness measurements over the service life of these and other tanks in similar service. Respondent argued that because of these estimates, the five-year interval did not apply. Since the finding of violation already explains how Respondent violated the regulation, these arguments are rejected. With regard to gravity, OPS noted in the Violation Report that safe operation was minimally affected. Respondent did not challenge this assessment. The Violation Report suggested no credit under the culpability and good faith factors. Respondent argued that if this item is not withdrawn, the penalty should be eliminated or significantly reduced. In support Respondent only repeated arguments that have already been rejected. As operator of the pipeline facility, Respondent is culpable for this violation of the pipeline safety regulations. I have also weighed Respondent’s history of prior offenses and find that when viewed as a whole, it supports the proposed penalty and does not warrant reduction. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $23,600 for violation of 49 C.F.R. § 195.432(b).#

420145028_Final Order_03302017_text.pdf, page 15CPF No. 4-2014-5028 Page 15 Item 5: The Notice proposed a civil penalty of $36,000 for Respondent’s violation of 49 C.F.R. § 195.452(h)(2) by failing to obtain sufficient information about a condition to determine if the condition presented a potential threat to the integrity of the pipeline no later than 180 days after an integrity assessment. Respondent argued that this item should be withdrawn because the Company did not fail to meet the 180-day deadline. Since the finding of violation already explains how Respondent violated the regulation, this argument is rejected. With regard to nature, OPS noted in the Violation Report that this violation concerned an activities violation. Respondent did not challenge this assessment. With regard to circumstances, OPS noted in the Violation Report that this violation began on June 1, 2012 and had a duration of 40 days. Respondent argued that there was no violation and that the June 1, 2012 date should be modified to reflect a start date for the “discovery period” of January 27, 2012. Since the finding of violation already explains how Respondent violated the regulation, this argument is rejected. With regard to gravity, OPS noted in the Violation Report that the failure to discover conditions within 180 days of an integrity assessment could result in a hazardous situation to the pipeline. Respondent argued that the penalty should be reduced because there is no evidence in the record that pipeline safety or integrity was compromised. I reject this argument. I find sufficient support in the record that violating the pipeline safety regulations by delaying discovery of unsafe conditions on the pipeline constituted an increased risk that compromised safety. With regard to culpability, I note that Respondent made an effort to salvage workable data from an initial tool run that had, at least at one point, been considered by the tool vendor to be a failed run. This eventually led to a data set that could be analyzed for potential threats to pipeline integrity in a shorter period of time than if Respondent had rerun the tool. Thus I find a reduction to the penalty is appropriate. Accordingly, having reviewed the record and considered the assessment criteria I assess Respondent a reduced civil penalty of $28,800 for violation of 49 C.F.R. § 195.452(h)(2). Item 6: The Notice proposed a civil penalty of $40,300 for Respondent’s violation of 49 C.F.R. § 195.452(h)(4) by failing to temporarily reduce operating pressure or shut down the pipeline until repairs of immediate conditions were completed. With regard to nature and circumstances, OPS noted in the Violation Report that this violation concerned a failure to temporarily reduce operating pressure or shut down the pipeline until classified immediate repairs were completed. Respondent argued that this item should be withdrawn because there were no immediate repair conditions and that the defects were repaired within two hours of digging up the conditions. Since the finding of violation already explains how Respondent violated the regulation, these arguments are rejected.#

420145028_Final Order_03302017_text.pdf, page 16CPF No. 4-2014-5028 Page 16 With regard to gravity, OPS noted in the Violation Report that the failure to reduce pressure upon discovery of immediate repair conditions may result in the release of product into the environment. Respondent argued that the penalty should be reduced because there is no evidence in the record that pipeline safety or integrity was compromised. I reject this argument. I find sufficient support in the record that Respondent’s failure to comply with the pipeline safety regulations that required the Company to immediately reduce pressure or shut down the pipeline due to unsafe conditions constituted an increased risk that compromised safety. The Violation Report suggested no credit under the culpability and good faith factors. Respondent only repeated arguments that have already been rejected. As operator of the pipeline facility, Respondent is culpable for this violation of the pipeline safety regulations. I have also weighed Respondent’s history of prior offenses and find that when viewed as a whole, it supports the proposed penalty and does not warrant reduction. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $40,300 for violation of 49 C.F.R. § 195.452(h)(4). In summary, Respondent is assessed a total civil penalty of $137,100. 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, 6500 S MacArthur Blvd., Oklahoma City, Oklahoma 79169. The Financial Operations Division telephone number is (405) 954-8845. Failure to pay the $137,100 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 Item 4 in the Notice for violations of 49 C.F.R. §§ 195.202 and 195.264. 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. The Director indicated that Respondent has taken the following actions specified in the proposed compliance order:#

420145028_Final Order_03302017_text.pdf, page 17CPF No. 4-2014-5028 Page 17 With respect to the violations of §§ 195.202 and 195.264 (Item 4), Respondent evaluated its tank dike areas and ensured that the dike areas meet the impoundment criteria. Centurion has provided documentation to PHMSA in the form of current surveys, drawings, and calculations that show the containment is in compliance with the applicable requirements. I find that compliance has been achieved with respect to this violation. Therefore, the compliance terms proposed in the Notice are not included in this Order. Under 49 C.F.R. § 190.243, Respondent may submit a petition for reconsideration of this Final Order to the Associate Administrator for Pipeline Safety, PHMSA, 1200 New Jersey Avenue SE, East Building, 2nd Floor, Washington, D.C. 20590, no later than 20 days after receipt of the Final Order by Respondent. Any petition submitted must contain a 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. The other terms of the order, including corrective action, remain in effect unless the Associate Administrator, upon request, grants a stay. The terms and conditions of this Final Order are effective upon service in accordance with 49 C.F.R. § 190.5. March 30, 2017 ___________________________________ ________________________ Alan K. Mayberry Date Issued Associate Administrator for Pipeline Safety#

420145028_Closure Letter_08292019_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED August 29, 2019 Mike Prince Chief Executive Officer Lotus Midstream, LLC 2150 Town Square, Ste 395 Houston, Texas 77046-7570 CPF 4-2014-5028 Dear Mr. Prince: On June 27, 2019, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to Centurion Pipeline, LP a Decision on the Petition for Reconsideration in the above-referenced case. This Decision affirmed the violations in the Final Order with a reduced Civil Penalty. Based on our review of the documentation you have 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, Mary L. McDaniel, P.E. Director, Southwest Pipeline and Hazardous Materials Safety Administration Enclosure: cc: Mr. Mike Morgan, General Manager-Operations, Centurion Pipeline, LP, 5 Greenway Plaza, Suite 110, Houston, Texas 77046#

420145028_NOPV PCP PCO_11102014_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED November 10, 2014 Mr. Bill Moyer President Centurion Pipeline, L.P. 5 Greenway Plaza, Suite 110 Houston, TX 77046 CPF 4-2014-5028 Dear Mr. Moyer: On April 2013 to February 2014, 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 in Texas, New Mexico, and Oklahoma. 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:#

420145028_NOPV PCP PCO_11102014_text.pdf, page 21. 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). Centurion did not inspect the physical integrity of in-service atmospheric breakout tanks according to API Standard 653. API Standard 653, Section 6.3.1.2 states the Routine In-Service Inspections shall not exceed one month. Centurion’s Liquid Operations Manual, procedure P- 195.432, Inspection of In-Service Breakout Tanks, also states the frequency for Routine In- service Inspection is monthly. Their Monthly Inspection of In-service Breakout Tanks Form F- 195.432(b) states the inspection form will be retained for five years. At the time of the inspection, inspection reports were requested for Centurion’s breakout tanks for the years 2010 through 2013. Breakout tanks 6832 and 6833 are located in Centurion’s Wasson Facility along with three other breakout tanks, 6719, 6830, and 6831. Monthly inspection reports were provided for tanks 6719, 6830, and 6831 for the time period as requested. Centurion failed to provide monthly Routine In-Service Inspection reports for breakout tanks 6832 and 6833 to demonstrate the tanks were inspected as required by 49 CFR 195 and API Standard 653, Section 6.3.1.2, incorporated by reference. Specifically, Centurion did not provide monthly inspection reports for breakout tanks 6832 and 6833 for all of year 2010, January 2011, February 2011, March 2011, April 2011, and August 2011. 2. 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). Centurion did not inspect the physical integrity of in-service atmospheric breakout tanks according to API Standard 653. API 653, Section 6.3.2.1 states, “All tanks shall be given a visual external inspection by an authorized inspector. This inspection shall be called the external inspection and must be conducted at least every 5 years or RCA/4N years (where RCA is the difference between the measured shell thickness and the minimum required thickness in mils, and N is the shell corrosion rate in mils per year) whichever is less. Tanks may be in operation during this inspection.” Centurion’s Liquid Operations Manual, procedure P-195.432, Inspection of In-Service Breakout Tanks, also states the frequency for External Inspections is “Every 5 years”. Their Monthly 2#

420145028_NOPV PCP PCO_11102014_text.pdf, page 3Inspection of In-service Breakout Tanks Form F-195.432(b) states the inspection form will be retained for five years. The following table summarizes the tanks that exceeded the 5 year interval. Tank Nominal API 653 API 653 Capacity (bbl.) Date Built Roof Type Construction Shell Bottom External Previous External Current External Lining Interval 6688 | 85000 1950 EFR Welded None 2/5/2008 3/7/2014 >5 6965 111000 1950 EFR Welded Claymax 8/7/2008 10/10/2013 >5 6948 30000 1950 EFR Welded None 06/10/08 3/7/2014 >5 2722 | 80000 1957 EFR Welded Claymax 10/23/2007 | 6/21/2013 >5 The previous External Inspection for tank 6688 was performed on February 5, 2008, during an out of service internal inspection. The final out of service inspection report demonstrates there was no corrosion rate calculated or established for Tank 6688. According to API 653, Section 6.3.2.1., the External Inspection interval is 5 years since the corrosion rate is unknown. The following External Inspection was performed on March 7, 2014, which exceeded the 5 year interval by 394 days. The previous External Inspection for tank 6965 was performed on August 7, 2008, during an out of service internal inspection. Centurion did not provide documentation or reports demonstrating a corrosion rate was calculated of established for Tank 6965. According to API 653, Section 6.3.2.1., the External Inspection interval is 5 years since the corrosion rate is unknown. The following External Inspection was performed on October 10, 2013, which exceeded the 5 year interval by 63 days. The previous External Inspection for tank 6948 was performed on June 10, 2008, during an in- service inspection. Centurion did not provide documentation or reports demonstrating a corrosion rate was calculated or established for Tank 6948. According to API 653, Section 6.3.2.1., the External Inspection interval is 5 years since the corrosion rate is unknown. The following External Inspection was performed on March 7, 2014, which exceeded the 5 year interval by 258 days. The previous External Inspection for tank 2722 was performed on October 23, 2007, during an out of service inspection. Centurion did not provide documentation or reports demonstrating a corrosion rate was calculated or established for Tank 2722. According to API 653, Section 6.3.2.1., the External Inspection interval is 5 years since the corrosion rate is unknown. The following External Inspection was performed on June 21, 2013, which exceeded the 5 year interval by 240 days. 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 3#

420145028_NOPV PCP PCO_11102014_text.pdf, page 4(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). Centurion did not inspect the physical integrity of in-service atmospheric breakout tanks according to API Standard 653. API 653, Section 6.3.3.2 states, API 653, Section 6.3.3.2(a) states, "When used, the ultrasonic thickness measurements shall be made at intervals not to exceed the following: a) When the corrosion rate is not known, the maximum interval shall be 5 years. Corrosion rates may be estimated from tanks in similar service based on thickness measurements taken at an interval not exceeding 5 years." Centurion's Liquid Operations Manual, procedure P-195.432, Inspection of In-Service Breakout Tanks, states the frequency for Ultrasonic Thickness Inspections is "Every 5 years". Their Monthly Inspection of In-service Breakout Tanks Form F-195.432(b) states the inspection form will be retained for five years. Centurion failed to perform "Ultrasonic Thickness Inspections" within the maximum interval of five years prescribed by API 653 Section 6.3.3.2, for the following breakout tanks that have unknown corrosion rates: Tank Nominal (bbl.) Capacity Built Date Roof Shell Bottom API 653 API 653 Type Construction Lining Previous External External Current External Interval 6688 85000 1950 EFR Welded None 2/5/2008 317/2014 >5 6965 111000 1950 EFR Welded Claymax 8/7/2008 10/10/2013 >5 6948 30000 1950 EFR Welded None 06/10/08 3/7/2014 >5 2722 80000 1957 EFR Welded Claymax 10/23/2007 | 6/21/2013 >5 The previous Ultrasonic Thickness Inspection (UTI) for tank 6688 was performed on February 5, demonstrates there was no corrosion rate calculated or established for Tank 6688. According to 2008 during an out of service internal inspection. The final out-of-service inspection report API 653, Section 6.3.3.2., the UTI interval is 5 years since the corrosion rate is unknown. The current UTI was performed on March 7, 2014, which exceeded the 5 year interval by 394 days. The previous UTI for tank 6965 was performed on August 7, 2008, during an out of service internal inspection. The final out-of-service inspection report demonstrates there was no corrosion rate calculated or established for Tank 6965. According to API 653, Section 6.3.3.2., the UTI interval is 5 years since the corrosion rate is unknown. The current UTI was performed on October 10, 2013, which exceeded the 5 year interval by 63 days. The previous UTI for tank 6948 was performed on June 10, 2008, during an in-service inspection. Centurion did not provide documentation or reports demonstrating a corrosion rate 4#

420145028_NOPV PCP PCO_11102014_text.pdf, page 5was calculated or established for Tank 6948. According to API 653, Section 6.3.3.2., the UTI interval is 5 years since the corrosion rate is unknown. The current UTI was performed on March 7, 2014, which exceeded the 5 year interval by 258 days. The previous UTI for tank 2722 was performed on October 23, 2007, during an out of service inspection. The final out-of-service report demonstrates there was no corrosion rate calculated or established for Tank 2722. According to API 653, Section 6.3.3.2., the UTI interval is 5 years since the corrosion rate is unknown. The current UTI was performed on June 21, 2013, which exceeded the 5 year interval by 240 days. 4. §195.202 Compliance with specifications or standards. Each pipeline system must be constructed in accordance with comprehensive written specifications or standards that are consistent with the requirements of this part. 195.264 Impoundment, protection against entry, normal/emergency venting or pressure/vacuum relief for aboveground breakout tanks. Impoundment, protection against entry, normal/emergency venting (b) After October 2, 2000, compliance with paragraph (a) of this section requires the following for the aboveground breakout tanks specified: (1) For tanks built to API Specification 12F, API Standard 620, and others (such as API Standard 650 or its predecessor Standard 12C), the installation of impoundment must be in accordance with the following sections of NFPA 30: (i) Impoundment around a breakout tank must be installed in accordance with section 4.3.2.3.2; and (ii) Impoundment by drainage to a remote impounding area must be installed in accordance with section 4.3.2.3.1. Centurion failed to construct several breakout tanks in accordance with comprehensive written specifications or standards that are consistent with the requirements of this part. Centurion failed to provide comprehensive written specifications or standards to demonstrate breakout tank containment impoundments met the requirements of NFPA 30 referenced in §195.264. Centurion also failed to present documentation (surveys, calculations) for any of their breakout tanks constructed after October 2, 2000, that verified the containment impoundment volumes met the requirements of NFPA 30. Centurion owns several breakout tanks throughout west Texas, New Mexico, and Oklahoma. Ten of them were constructed from 2009 to 2012. Tanks 6693, 6832, 6692, 160100, 160101, 6691, 6833, were constructed in 2009, and tanks 6991, 7101, and 160102 were constructed in 2012. The impoundment requirements are contained in several paragraphs throughout the NFPA 30 standard. 5#

420145028_NOPV PCP PCO_11102014_text.pdf, page 65. 195.452 Pipeline integrity management in high consequence areas. (h) What actions must an operator take to address integrity issues? (2) Discovery of condition. Discovery of a condition occurs when an operator has adequate information about the condition to determine that the condition presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than 180 days after an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator can demonstrate that the 180-day period is impracticable. Centurion failed to obtain sufficient information about a condition to determine if the condition presented a potential threat to the integrity of the pipeline no later than 180 days after an integrity assessment. On December 3, 2011, Centurion completed a TDW Spirall Magnetic Flux Tool run as part of their continual reassessment of their 16-inch Bretch to Cushing #2 system. This would place the 180 day deadline on or about May 31, 2012. Centurion determined six anomalies met the immediate repair criteria on July 11, 2012, which is 220 days after the tool run was completed. Centurion was unable to demonstrate that the 180 day requirement was impracticable. 6. 195.452 Pipeline integrity management in high consequence areas. (h) What actions must an operator take to address integrity issues? (4) Special requirements for scheduling remediation Immediate repair conditions. An operator's evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formula in Section 451.6.2.2 (b) of ANSI/ ASME B31.4 (incorporated by reference, see § 195.3). An operator must treat the following conditions as immediate repair conditions: Metal loss greater than 80% of nominal wall regardless of dimensions. (B) A calculation of the remaining strength of the pipe shows a predicted burst pressure less than the established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (``Manual for Determining the Remaining Strength of Corroded Pipelines'' (1991) or AGA Pipeline Research Committee Project PR-3- 805 (``A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe'' (December 1989)). These documents are incorporated by reference and are available at the addresses listed in Sec. 195.3. (C) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) that has any indication of metal loss, cracking or a stress riser. 6#

420145028_NOPV PCP PCO_11102014_text.pdf, page 7(D) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 6% of the nominal pipe diameter. (E) An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action. Centurion failed to maintain safety by temporarily reducing operating pressure or shutting down the pipeline until repairs of immediate conditions that they identified were completed. Centurion failed to reduce the operating pressure, shut down the pipeline or make repairs and evaluations of six immediate repair conditions in an HCA segment that met the immediate repair condition criteria. Centurion conducted an assessment using TDW’s ILI tool on their 16-inch Bretch to Cushing #2 system. There were six anomalies identified, in an HCA segment, by TDW as “deformation (above 4 and 8”oclock positions) … w/associated Metal Loss” which meets the definition of an immediate repair condition per 195.452(h)(4)(i)(C). These determinations were accepted by Centurion. These immediate repairs were located in an HCA segment between the El Reno facility and Cushing segment at MP’s 73.53, 74.57-A, B, C, D (four at this location). The immediate repair at MP 84.54 was located approximately three miles upstream of the El Reno facility, on the Bretch to El Reno segment. The six anomalies were identified and were sent to operations for rehab repairs on July 12, 2012. The repairs on the six immediate repairs began 15 days after on July 27, 2012 and were completed 22 days later, on August 3, 2012. Centurion did not reduce the operating pressure after six immediate repair anomalies were discovered. Pressure charts provided by Centurion demonstrate the El Reno discharge pressure from July 12, 2012 to the end of repairs (August 3, 2012) that affected the immediate repair anomalies at MP 73.52, 74.57A, B, C, and D. The discharge operating pressure readings range from approximately 540 psi to approximately 620 psi, which demonstrates there was no pressure reduction. Centurion’s Integrity Management Plan Section 7.1.2 -Action Required Upon Discovery of an Immediate Repair Condition states, “Upon discovery of an immediate Repair condition, the Manager, Pipeline Integrity will notify the Regional Manager of the need to either shut down the line or reduce the operating pressure as possible until the Immediate Repair Condition is repaired or remediated. The Regional Manager will make operating pressure changes as directed by the Manager, Pipeline Integrity. The Manager, Pipeline Integrity will use guidance in ASME B31.4 for determining the reduction in operating pressure for corrosion anomalies. For all other types of anomalies or if the formula yields a higher operating pressure, the minimum pressure reduction will not be less than twenty percent of the highest operating pressure occurring at the anomaly’s location during the preceding sixty days.” ASME B31.4 is not applicable for calculating the temporary pressure reduction required for top- side dents with metal loss. Pressure must be reduced for other types of immediate repair conditions, but operators must develop appropriate engineering justification for the amount of pressure reduction. A reduction in operating pressure is intended to provide an additional safety margin until the defect can be remediated. To assure that additional margin is provided, the 7#

420145028_NOPV PCP PCO_11102014_text.pdf, page 8pressure reduction must be based upon pressures that the pipe has actually experienced, with the defect present (i.e., pressures for which safety has been demonstrated). These may be well below the ‘maximum operating pressure’ for the pipe. Pressure charts provided by Centurion via email, shows pressures from the preceding two months of the day of discovery. The El Reno discharge pressure chart affecting the immediate repair anomalies at MP 73.52, 74.57A, B, C, and D, shows the highest discharge pressure was approximately 700 psi which occurred on approximately June 5, 2012. Centurion needed to take a minimum of a 20% pressure reduction of the highest operating pressure in the preceding two months as per their IMP procedure 7.1.2. 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 violation(s) and has recommended that you be preliminarily assessed a civil penalty of $165,900 as follows: Item number PENALTY 1 $42,400 2 $23,600 3 $23,600 5 $36,000 6 $40,300 Proposed Compliance Order With respect to items 4 pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Centurion 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 8#

420145028_NOPV PCP PCO_11102014_text.pdf, page 9treatment 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 4-2014-5028 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 9#

420145028_NOPV PCP PCO_11102014_text.pdf, page 10PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Centurion a Compliance Order incorporating the following remedial requirements to ensure the compliance of Centurion with the pipeline safety regulations: Item 1: In regard to Item Number 4 of the Notice pertaining to verifying the containment dike volume for the various breakout tanks, Centurion must evaluate its tank dike areas and ensure that the dike areas meet the impoundment criteria. Centurion must provide documentation to PHMSA in the form of current surveys, drawings, and/or calculations that show the containment complies with the applicable requirements of NFPA 30, incorporated by reference into Part 195. Item 2: Pertaining to Item 1 of the Proposed Compliance Order, Centurion must complete the required documentation within 90 days of the date of the Compliance Order. Item 3: It is requested (not mandated) that Centurion 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 Hazardous 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. 10#