ENTERPRISE PRODUCTS OPERATING LLC — Notice of Probable Violation

party submissionOfficial PDF120185003_Operator Amended Written Response and Withdrawal of Hearing Request_07222019.pdf#

party submissionOfficial PDF120185003_Operator Request for Hearing_04202018.pdf#

party submissionOfficial PDF120185003_Operator Response and Request Hearing_04202018.pdf#

120185003_Final Order_04062020_text.pdf, page 1Official PDFVIA EMAIL TO: ajteague@eprod.com, zlcraft@eprod.com, gbacon@eprod.com, and robert.hogfoss@troutman.com Mr. A. J. Teague Director and Co-Chief Executive Officer Enterprise Products Partners, LP 1100 Louisiana Street, 10th Floor Houston, Texas 77002 Re: CPF No. 1-2018-5003 Dear Mr. Teague: Enclosed please find the Final Order issued in the above-referenced case to your subsidiary, Enterprise Products Operating, LLC (Enterprise). It withdraws seven of the 18 original allegations of violation, reduces two allegations of violation to warning items, makes nine other findings of violation, assesses a reduced civil penalty of $286,600, and specifies actions that need to be taken by Enterprise to comply with the pipeline safety regulations. The penalty payment terms are set forth in the Final Order. When the civil penalty has been paid and the terms of the compliance order completed, as determined by the Director, Eastern Region, this enforcement action will be closed. Service of the Final Order by e-mail is effective upon the date of mailing, 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. Robert Burrough. Director, Easter Region, Office of Pipeline Safety, PHMSA Mr. Zachary Craft, Counsel, Enterprise Products Operating, LLC Mr. Graham Bacon, Executive Vice President and Chief Operating Officer, Enterprise Products Operating, LLC Mr. Robert E. Hogfoss, Counsel for Respondent, Troutman Sanders, LLP VIA EMAIL – CONFIRMATION OF RECEIPT REQUESTED#

120185003_Final Order_04062020_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 ) Enterprise Products Operating, LLC, ) CPF No. 1-2018-5003 a subsidiary of Enterprise Products Partners, LP, ) Respondent. ) ) ) ) ) FINAL ORDER From March 21, 2016, through December 2, 2016, 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 Enterprise Products Operating, LLC (Enterprise or Respondent), in Houston, Texas; Greensburg, Pennsylvania; Dubois, Pennsylvania; Lebanon, Ohio; Morgantown, Pennsylvania; Sorrento, Louisiana; Monee, Illinois; Seymour, Illinois; and Little Rock, Arkansas. Respondent is a wholly-owned subsidiary of Enterprise Products Partners, LP, which operates approximately 49,200 miles of natural gas, natural gas liquid, crude oil, refined products, and petrochemical transmission and gathering pipelines throughout the United States.1 As a result of the inspection, the Director, Eastern Region, OPS (Director), issued to Respondent, by letter dated January 29, 2018, 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 Enterprise had committed 18 violations of 49 C.F.R. Part 195 and proposed assessing a civil penalty of $703,900 for the alleged violations. The Notice also proposed ordering Respondent to take certain measures to correct the alleged violations. After requesting and receiving an extension of time to respond, Enterprise responded to the Notice by letter dated April 20, 2018 (Response). Enterprise contested all of the allegations and requested a hearing, but asked that it not be scheduled until the parties could informally meet in an attempt to resolve or narrow the issues of the Notice. On July 31, 2018, Enterprise met with PHMSA personnel in Trenton, New Jersey. The informal meeting resulted in a tentative agreement, subject to PHMSA’s review of additional documentation to be provided by Enterprise, of the issues raised in the Notice. Enterprise memorialized this tentative agreement by letter to PHMSA dated August 28, 2018. Enterprise and PHMSA subsequently engaged in 1 Enterprise Products Partners, LP website, available at https://www.enterpriseproducts.com/about-us/business- profile (last accessed February 26, 2020).#

120185003_Final Order_04062020_text.pdf, page 3CPF No. 1-2018-5003 Page 2 further discussions regarding the additional documentation provided by Enterprise and further narrowed the issues. On May 23, 2019, Enterprise filed a “Joint Status Report” with the PHMSA hearing official, stating that the parties had resolved 12 of the 18 issues presented in the Notice and that it expected “to confirm shortly whether there will be a need for a hearing on the remaining six items.” By letter dated July 22, 2019, to the Director, Enterprise withdrew its request for a hearing, thereby authorizing the entry of this Final Order without further proceedings (Amended Response). 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. § 195.310(a), which states: § 195.310 Records. (a) A record must be made at each pressure test required by this subpart, and the record of the latest test must be retained as long as the facility tested is in use. The Notice alleged that Enterprise violated 49 C.F.R. § 195.310(a) by failing to maintain a record of each pressure test required by Subpart E, “Pressure Testing,” of Part 195. Specifically, the Notice alleged that Enterprise failed to maintain hydrostatic test records for four breakout tanks (PHMSA Unit 12232) in Little Rock, Arkansas, per the requirements of § 195.310(b). Paragraph (b) of § 195.310 requires that an operator’s records include the following information: pressure-recording charts; test-instrument calibration data; date and time of the test; minimum test pressure; test medium; a description of the facility tested and the test apparatus; an explanation of any pressure discontinuities, including test failures, that appear on the pressure- recording charts; where elevation differences in the section under test exceed 100 feet (30 meters), a profile of the pipeline that shows the elevation and test sites over the entire length of the test section; and the temperature of the test medium or pipe during the test period. None of the records provided by Enterprise for the referenced units contained this information. In its Amended Response, Enterprise withdrew its objection to this item. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.310(a) by failing to maintain a record of each pressure test required by Subpart E. Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), which states: § 195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to#

120185003_Final Order_04062020_text.pdf, page 4CPF No. 1-2018-5003 Page 3 insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. The Notice alleged that Enterprise violated 49 C.F.R. § 195.402(a) by failing to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, the Notice alleged that Enterprise failed to follow its computational pipeline monitoring (CPM) manual for providing leak detection on four pipelines located in High Consequence Areas (HCAs). During the inspection of Enterprise’s written procedures in Houston, Texas, the PHMSA inspector reviewed Enterprise’s CPM Operations and Maintenance Manual (O&M Manual), dated 3/1/11. The O&M Manual stated: “…[A]ll regulated pipelines operated by Enterprise Products control centers will be targeted for implementation of this baseline CPM system. If this baseline leak detection application cannot be implemented on targeted line, then alternative technologies will be evaluated ….” The PHMSA inspector noted that four Enterprise pipelines located in HCAs lacked leak-detection systems: 1. Line ID P84, PODS ID 1357, total miles 0.945, HCA miles 0.047; 2. Line ID P79, PODS ID 6427, total miles 0.409, HCA miles 0.409; 3. Line ID P29B, PODS ID 7201936, total miles 0.53, HCA miles 0.53; and 4. Line ID P29A, PODS ID 7201937, total miles 0.53, HCA miles 0.53. By email dated January 12, 2017, Enterprise acknowledged that it did not have records regarding an evaluation of alternative leak-detection technologies for these pipelines. As a result, the Notice alleged that Enterprise failed to follow its own procedures for leak detection for each of the four referenced pipelines. In its Amended Response, Enterprise withdrew its objection to Item 2 with respect to two of the four instances of violation, i.e., violations relevant to Line ID P79 and Line ID P29A. With regard to the other two instances (Line ID P84 and Line ID P29B), Enterprise provided information regarding the operational status of these two segments but that had not been previously submitted to PHMSA. Upon review of this additional material, the Region concluded that the lines were exempt from leak detection, as one was a low-stress line and the other was idled, and therefore not subject to the company’s procedures for leak detection.2 Accordingly, after considering all of the evidence, I find that Enterprise violated 49 C.F.R. § 195.402(a) by failing to follow a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies with respect to Line ID P79 and Line ID P27A. Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.583(a), which states in relevant part: 2 Region Recommendation, at 2 (on file with PHMSA).#

120185003_Final Order_04062020_text.pdf, page 5CPF No. 1-2018-5003 Page 4 § 195.583 What must I do to monitor atmospheric corrosion control? (a) You must inspect each pipeline or portion that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows: If the pipeline is located: Then the frequency of inspection is: Onshore At least once every 3 calendar years, but with intervals not exceeding 39 months. . . . The Notice alleged that Respondent violated 49 C.F.R. § 195.583(a) by failing to conduct an inspection of each pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion at least once every three calendar years, but with intervals not exceeding 39 months. Specifically, the Notice alleged that Enterprise’s atmospheric corrosion records, titled “EPROD Survey Report Atmospheric,” from 1/1/11 to 12/30/15, revealed that the inspection interval exceeded 39 months in two instances for the following pipelines: 1. Segment Code: 03 Mundys to Duncansville with the following inspection dates: 6/18/11 and 9/25/14 – six days past due; and 2. Segment Code: 04 Duncansville to Jacks with the following inspection dates: 6/25/12 and 10/6/15 – 10 days past due. In its Amended Response, Enterprise withdrew its objection to Item 5.3 Accordingly, after considering all of the evidence, I find that Enterprise violated 49 C.F.R. § 195.583(a) by failing to conduct an inspection of each pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion at least once every three calendar years, but with intervals not exceeding 39 months. Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), as quoted above, by failing to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, the Notice alleged that Enterprise failed to follow its own written procedures for performing inspections of overpressure-protection devices for inspection Unit 2464-Lou Tex in Sorrento, Louisiana (Unit 2464); Unit 3051-Greensburg in Greensburg, Pennsylvania (Unit 3051); and Unit 3071-Dubois in Watkins Glen, New York (Unit 3071). Enterprise’s O&M Miscellaneous Operating Procedures – Over Pressure Safety Devices, Section 1305, dated 11/12/13 (Section 1305) stated: “In addition, the overpressure protection system must be inspected and tested, either actual or simulated, at the required overpressure protection set point…” The records reviewed during the PHMSA inspection of Unit 2464, dated 2014 and 2015, showed that the pressure-relief valve data did not indicate a “Set Pressure (PSI)” for nine pressure-relief valves in 2014 and six in 2015. According to the Notice, Enterprise was unable to justify why the data was missing from these records. 3 Amended Response, at 2 (on file with PHMSA).#

120185003_Final Order_04062020_text.pdf, page 6CPF No. 1-2018-5003 Page 5 In addition, the Notice alleged that Enterprise failed to adequately document the “set pressure (PSI)” for relief valve settings on its 2015 and 2016 pressure safety valve (PSV) inspection records on its Appalachia-to-Texas (ATEX) pipeline segments. The Notice further alleged that records reviewed during the inspection of Unit 3051 did not record a “set pressure (PSI)” for the pressure safety valves (PSVs). According to the Notice, Enterprise was unaware of what value (PSI) at which these PSVs were tested, or at what pressure values these PSVs were left. The PHMSA inspector noted two instances of violation in 2015 and two instances of violation in 2016 for this inspection unit. Finally, during the inspection of Unit 3071, the PHMSA inspector reviewed Section 1305, which stated in relevant part: “…[E]ach inspection and repair is documented on the appropriate form to determine that it is functioning properly, in good mechanical/electrical condition, adequate from the standpoint of capacity and reliability of operation for the service in which it is used, set to function at the correct pressure and properly installed and protected from foreign materials or other conditions that might prevent proper operation.” Overpressure-protection records from 2014 through 2016 for the Moshannon, Pennsylvania pump station and the “Maintenance Work Order Detail Report” for the spring 2014 inspection interval were reviewed during the inspection. According to the Notice, these records failed to contain specific information required by Section 1305. Specifically, the following information was omitted: valve mechanical/electrical condition; adequacy of capacity and reliability of operation; functionality at the correct pressure; proper installation and protection from foreign materials or other conditions that might prevent proper operation; and the set pressure of the device and set pressure as found. The PHMSA inspector noted two instances of violation in 2015 and two instances of violation in 2016 for this inspection unit. In its Response, Enterprise contested this item and stated that it had records associated with Unit 3051 and a portion of the records associated with Unit 3071. In addition, Enterprise challenged the item on the grounds that it should have been brought as an alleged violation of § 195.428(a), and the violation therefore failed as a matter of law for a lack of specificity in the pleadings. Finally, Enterprise argued that this item should have been combined with Item 7 of the Notice, as there was significant overlap in the allegations, and should be converted to a Notice of Amendment without any assessed penalty. Subsequent to the inspection, Enterprise engaged in informal discussions with PHMSA on this item and provided additional records for review. As a result of those discussions and a review of the additional records, the Director agreed that six of the instances of alleged violation should be withdrawn. Specifically, the Director reviewed the records associated with Units 3051 and 3071 and agreed that the alleged violations for those units should be withdrawn. Respondent thereupon withdrew its challenge to this item and requested that the civil penalty associated with this item be reduced to reflect 17, rather than 23, instances of violation. Because Enterprise withdrew its challenge to this item, I need not decide the legal issues raised by Enterprise in its Response. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.402(a) by failing to follow for each pipeline system a manual of written procedures for#

120185003_Final Order_04062020_text.pdf, page 7CPF No. 1-2018-5003 Page 6 conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(c), which states, in relevant part: § 195.402 Procedural manual for operations, maintenance, and emergencies. (a) …. (c) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following to provide safety during maintenance and normal operations: . . . (3) Operating, maintenance, and repairing the pipeline system in accordance with each of the requirements of this subpart and subpart H of this part. The Notice alleged that Respondent violated 49 C.F.R. § 195.402(c)(3) by failing to ensure that its written procedures were adequate for operating, maintaining and repairing its pipeline system in accordance with the requirements of Subparts F and H of Part 195. Specifically, it alleged that Enterprise’s procedures failed to provide sufficient instructions on how its employees were to conduct and document relief-valve inspections under § 195.428(a). In its Amended Response, Enterprise withdrew its challenge to this item.4 Accordingly, after considering all of the evidence, I find that Enterprise violated 49 C.F.R. § 195.402(c)(3) by failing to ensure that its written procedures were adequate for operating, maintaining and repairing its pipeline system in accordance with the requirements of Subparts F and H of Part 195. Item 13: The Notice alleged that Respondent violated 49 C.F.R. § 195.428(a), which states: § 195.428 Overpressure safety devices and overfill protection systems. (a) Except as provided in paragraph (b) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, or in the case of pipelines used to carry highly volatile liquids, at intervals not to exceed 7½ months, but at least twice each calendar year, inspect and test each pressure limiting device, relief valve, pressure regulator, or other item of pressure control equipment to determine that it is functioning properly, is in good working condition, and is adequate from the standpoint of capacity and reliability of operation for the service in which it is used. The Notice alleged that Respondent violated 49 C.F.R. § 195.428(a) by failing to conduct an inspection and test of each overpressure-protection device at intervals not to exceed 7½ months, but at least twice each calendar year. Specifically, the Notice alleged that Enterprise failed to conduct an inspection and test of its highly volatile liquid (HVL) overpressure-protection valves at its Moshannon, Pennsylvania pump station during the following periods: 4 Id., at 3 (on file with PHMSA).#

120185003_Final Order_04062020_text.pdf, page 8CPF No. 1-2018-5003 Page 7 1. Device # MOS377 Thermal bypass valve 001 receiving barrel – 1st inspection 2014, 1st inspection 2015, and 2nd inspection 2015; and 2. Device # MOS377 Thermal bypass valve 002 launching barrel – 1st inspection 2014, 1st inspection 2015, and 2nd inspection 2015. In its Response, Enterprise challenged two of the six instances of violation alleged in this Item. Enterprise stated that it had produced certain records of inspection during the PHMSA inspection and, subsequent to the inspection, had located other records associated with the 2015 inspections at the Moshannon, Pennsylvania pump station. As an exhibit to its Response, Enterprise provided documentation of the 2015 inspections that PHMSA alleged had not occurred. In its Amended Response, Enterprise stated that it did not contest the four allegations of violation associated with the 2014 inspections. Accordingly, after considering all of the evidence, I find that Respondent violated 49 C.F.R. § 195.428(a) by failing to conduct an inspection and test of its HVL overpressure-protection valves at its Moshannon, Pennsylvania pump station during the first and second inspections of 2014, for a total of four instances of violation. Item 15: The Notice alleged that Respondent violated 49 C.F.R. § 195.404(c), which states, in relevant part: § 195.404 Maps and records. (a) …. (c) Each operator shall maintain the following records for the period specified: . . . (3) A record of each inspection and test required by this subpart shall be maintained for at least 2 years or until the next inspection or test is performed, whichever is longer. The Notice alleged that Respondent violated 49 C.F.R. § 195.404(c)(3) by failing to maintain a record of each inspection and test required under Subpart F of Part 195 for at least two years or until the next inspection or test is performed, whichever is longer. Specifically, the Notice alleged that Enterprise failed to maintain its monthly breakout-tank records for breakout tank DOT-T-1301 during March 2014, April 2014, and April 2015, per the requirements of API Standard 653, Section 6.3.1.2, which is incorporated by reference into Subpart F under § 195.3(b)(19). In its Response, Enterprise contested two of the three instances of alleged violation. Specifically, Enterprise argued that the two alleged instances from 2014 should be withdrawn because the regulation requires retention of records until the time of the next inspection or two years, whichever is longer, and that two years had already passed as of the time of the PHMSA inspection. Enterprise is correct that it was required to retain the inspection records from 2014 for a period of two years, and that such period had expired at the time of the PHMSA inspection. Enterprise did not challenge the alleged violation for 2015 and has therefore waived its right to do so.#

120185003_Final Order_04062020_text.pdf, page 9CPF No. 1-2018-5003 Page 8 Accordingly, after considering all of the evidence, I find that Enterprise violated 49 C.F.R. § 195.404(c)(3) by failing to maintain a record of its April 2015 monthly breakout tank inspection for breakout tank DOT-T-1301 for at least two years or until the next inspection or test was performed, whichever is longer. Item 17: The Notice alleged that Respondent violated 49 C.F.R. § 195.579(d), which states: § 195.579 What must I do to mitigate internal corrosion? (a) …. (d) Breakout tanks. After October 2, 2000, when you install a tank bottom lining in an aboveground tank built to API Spec 12F (incorporated by reference, see 195.3), API Std 620 (incorporated by reference, see 195.3), or API Std 650’s predecessor, Standard 12C, you must install the lining according to API RP 652 (incorporated by reference, see 195.3). However, you don’t need to comply with API RP 652 when installing any tank in which you note for the corrosion control procedures established under § 195.402(c)(3) why compliance with all or certain provisions of API RP 652 is not necessary for the safety of the tank. The Notice alleged that Respondent violated 49 C.F.R. § 195.579(d) by failing to install certain breakout-tank linings in accordance with API RP 652, as required by the regulation. Specifically, Enterprise failed to produce any records or documentation showing compliance with the requirement for the following breakout tanks with a thin-film lining, namely, tank DOT- T-1301, and tank DOT-T-1302. In its Response, Enterprise contested the allegation of violation for both tanks. Enterprise stated that it had fully complied with all requirements of API RP 652. In its Amended Response, however, Enterprise withdrew its challenge to the allegation of violation with respect to tank DOT-T-1301, but still challenged the allegation of violation with respect to tank DOT-T-1302. In subsequent discussions between Enterprise and the Director, Enterprise provided PHMSA with additional breakout tank-lining installation records for tank DOT-1-1302, which were not provided at the time of the PHMSA inspection. The additional records provided evidence of compliance with the regulation for tank DOT-1-1302, and the Director has recommended that the allegation of violation for that tank be withdrawn. Accordingly, after considering all of the evidence, I find that Enterprise violated 49 C.F.R. § 195.579(d) by failing to install certain breakout-tank linings for tank DOT-1-1302 in accordance with API RP 652. Item 18: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), as quoted above, by failing to prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, the Notice alleged that Enterprise failed to provide instructions to its employees on how to inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion pursuant to § 195.583(a), and to maintain#

120185003_Final Order_04062020_text.pdf, page 10CPF No. 1-2018-5003 Page 9 sufficient records of each atmospheric-corrosion inspection to demonstrate the adequacy of corrosion-control measures pursuant to § 195.589(c). The Notice stated that a PHMSA inspector had reviewed an Enterprise document, titled “Enterprise’s Atmospheric Corrosion Inspection Procedure CPP-PCL-01, Revision date 12/3/15” (Procedure CPP-PCL-01), and had identified numerous deficiencies. According to the Notice, sections 1.1, 3.2.1, 3.3.1, 3.3.2, 3.3.3, 3.3.3.1, 3.3.3.6, 3.3.4, 3.3.8, 3.3.8.1, 3.3.8.3, and 3.4.2 failed to contain sufficient information or instructions to ensure that Procedure CPP-PCL- 01 could be followed properly by Enterprise personnel to address operations and maintenance activities on pipeline segments that were exposed to the atmosphere. The Notice further alleged that the PHMSA inspector verified the deficiencies by reviewing records from 2013 and 2016 associated with breakout tanks 3013 and 3014 that were inconsistent with the requirements of the procedure. In its Amended Response, Enterprise stated that it did not object to the finding of violation alleged in this Item, but noted that since the date of the PHMSA inspection, it had provided the agency with updated procedures and revised records sufficient to satisfy the proposed compliance terms. Upon review of Enterprise’s revised procedures and records, I find that the allegations regarding the deficiencies in sections 1.1, 3.2.1, 3.3.4, 3.3.8, 3.3.8.3, and 3.4.2 of Procedure CPP-PCL-01 should be withdrawn. The remaining allegations of the Notice regarding this Item are not challenged by Enterprise. Accordingly, after considering all of the evidence, I find that Enterprise violated 49 C.F.R. § 195.402(a) by failing to prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. I further find that Enterprise has completed all proposed compliance order actions set forth in the Notice for this Item and that no further action is required. These findings of violation will be considered prior offenses in any subsequent enforcement action taken against Respondent. WITHDRAWAL OF ALLEGATIONS OF VIOLATIONS Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 194.402(a), as quoted above, by failing to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, the Notice alleged that Enterprise failed to follow its manual of written procedures, CPM O&M Manual – Liquid Pipelines Operated by Houston OCC, dated 3/1/11, which required, inter alia, that “[p]ipelines will be ranked into three (3) tiers based upon HCA impact and the Pipeline Integrity Risk model ‘consequence score.’”#

120185003_Final Order_04062020_text.pdf, page 11CPF No. 1-2018-5003 Page 10 During the inspection, the PHMSA inspector requested copies of the company’s 2014, 2015, and 2016 CPM performance-evaluation records for the following inspection units: 1. IU 3051 – Greensburg o(Greensburg, Pennsylvania office); 2. IU 3071 – Dubois (Watkins Glen, New York office); 3. IU 4213 – Allegheny (Lebanon, Ohio office); 4. IU 3061 – Eagle (Morgantown, Pennsylvania Office); 5. IU 2464 – Lou Tex (Sorrento, Louisiana Office); 6. IU 18043 – TEPPCO Chicago (Monee, Illinois Office); and 7. IU 12232 – AR1 (Little Rock, Arkansas Office). The records provided by Enterprise, however, did not show that the pipelines had been ranked into the tiers as required by Enterprise’s procedure. In its Response, Enterprise contested this Item on the grounds that the records provided showed that the relevant CPM reviews had been completed. Enterprise further stated that the Notice had alleged that the records provided to the PHMSA inspector had shown insufficient detail, notwithstanding the fact that the documentation was deemed sufficient in prior PHMSA inspections. Enterprise stated that it would have provided additional detail during or at any time after the inspection before the Notice was issued had the inspector requested such additional documentation. In follow-up discussions with the Director, Enterprise provided CPM Performance Review records for years 2014 through 2016 for the relevant inspection units, which had not previously been provided to PHMSA inspectors. In its Amended Response, Enterprise stated that PHMSA had reviewed the additional documentation provided and agreed to withdraw this item. The record supports Enterprise’s statement in its Amended Response that PHMSA had reviewed the additional documentation and that the Director had informally agreed to withdraw this item. Accordingly, after considering all of the evidence, I hereby order that Item 3 be withdrawn. Item 4: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), as quoted above, by failing to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, the Notice alleged that Enterprise failed to follow its abnormal operating condition (AOC) procedure for documenting AOC actions taken prior to a supervisory close-out of the AOCs. During the inspection of Unit 12232-AR1 in Little Rock, Arkansas, the PHMSA inspector noted that one record for Enterprise’s McRae terminal contained no information for “AOC conditions found” and “AOC actions taken.” Enterprise’s O&M Manual Abnormal Operation Procedures Section 801, dated 11/12/13, required the retention of records that could be used to reconstruct the sequence of events surrounding an abnormal operating condition. According to the Notice, Enterprise was unable to provide any such additional records upon request from the PHMSA inspector.#

120185003_Final Order_04062020_text.pdf, page 12CPF No. 1-2018-5003 Page 11 In its Response, Enterprise contested this allegation of violation and stated that the information alleged to be missing from the records was contained in the notes section of the AOC work order. Enterprise further stated that the information allegedly missing would have been brought to the attention of the PHMSA inspector had the PIPES Act-mandated follow-up to the inspection occurred. Enterprise noted that in this particular instance, the AOC was a temporary loss of power that had been corrected and the alarms cleared. Enterprise subsequently provided PHMSA with the work orders showing the missing information. In its Amended Response, Enterprise stated that PHMSA had informally agreed to withdraw this Item based upon its review of the additional information provided. The record supports Enterprise’s statement in its Amended Response that the Director had reviewed the additional documentation and tentatively agreed to withdraw this Item. Accordingly, after considering all of the evidence, I hereby order that Item 4 be withdrawn. Item 8: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), as quoted above, by failing to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, the Notice alleged that Enterprise failed to follow its Pipeline Hydrostatic Testing procedure for conducting pressure testing according to the requirements of § 195.305. The Notice alleged that Enterprise’s Hydrostatic Test Report, Form 4507, with a Start of Test Period dated 4/4/2013 for inspection Unit 2703-Seymour, in Seymour, Indiana, failed to include the following information: 1. End time and date of “off” test with final pressure; 2. The name of the person responsible for making the test; 3. The Company Representative who recorded the test and date; and 4. The Test Director who approved the test and date. In its Response, Enterprise contested this item and stated that the documentation alleged to be missing was located either in a central office or online, and not at the field office where the inspection occurred, and that nothing in the regulations or in its procedures required all of this information to be stored in a single location. Enterprise stated that it had provided the missing information to PHMSA prior to the Notice being issued and requested that the item be withdrawn. The additional information provided by Enterprise was reviewed by the Director, who confirmed that it contained the four categories of information at issue in this item and requested that the item be withdrawn. Accordingly, after considering all of the evidence, I hereby order that Item 8 be withdrawn. Item 9: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(a), as quoted above, for failing to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and#

120185003_Final Order_04062020_text.pdf, page 13CPF No. 1-2018-5003 Page 12 emergencies. Specifically, the Notice alleged that Enterprise failed to follow its own procedure for maintaining records for emergency-response training conducted in accordance with § 195.403(b)(1). The Notice alleged that the records for Unit 3051 failed to contain certain information regarding emergency-response training that had been conducted for two years at that facility, as required by both § 195.403(b)(1) and Enterprise’s own written procedures. In its Response, Enterprise contested this Item and stated that it believed this issue had been resolved through the records produced during the PHMSA inspection and in communications with PHMSA following the inspection. The company nevertheless provided the Form 905A records that had been allegedly missing and requested that this Item be withdrawn. The Director reviewed the additional documentation and concluded that it provided sufficient evidence to demonstrate compliance with Enterprise’s procedures and requested that this Item be withdrawn. Accordingly, after considering all of the evidence, I hereby order that Item 9 be withdrawn. Item 12: The Notice alleged that Respondent violated 49 C.F.R. § 195.420(b), which states: § 195.420 Valve maintenance. (a) …. (b) Each operator shall, at intervals not exceeding 7½ months, but at least twice each calendar year, inspect each mainline valve to determine that it is functioning properly. The Notice alleged that Respondent violated 49 C.F.R. § 195.420(b) by failing to inspect each mainline valve at intervals not exceeding 7½ months, but at least twice each calendar year, to determine that it is functioning properly. Specifically, the Notice alleged that Enterprise’s records for the mainline valves for 2013-2016 for inspection Unit 2464 and PHMSA Unit 12232- AR1 in Little Rock, Arkansas, showed that in six instances, Enterprise failed to inspect mainline valves twice per year, and in two instances failed to inspect mainline valves at intervals not exceeding 7½ months. In its Response, Enterprise contested this Item and stated that some of the valves identified in the Notice were located on idled or abandoned lines, and that others were not mainline valves but hand valves inspected on a different inspection frequency. Further, Enterprise provided records demonstrating that the relevant mainline valves had been inspected in accordance with the regulation. On these grounds, Enterprise requested that the Item be withdrawn. Subsequent to the inspection, the Director reviewed the additional information provided by Enterprise and determined that the Item should be withdrawn. Accordingly, after considering all of the evidence, I hereby order that Item 12 be withdrawn.#

120185003_Final Order_04062020_text.pdf, page 14CPF No. 1-2018-5003 Page 13 Item 14: The Notice alleged that Respondent violated 49 C.F.R. § 195.428(a), as quoted above, for failing to inspect and test each pressure-limiting device, relief valve, pressure regulator, or other item of pressure-control equipment at intervals not exceeding 15 months, but at least once each calendar year to determine that it is functioning properly, is in good mechanical condition, and is adequate from the standpoint of capacity and reliability of operation for the service in which it is used. Specifically, the Notice alleged that Enterprise failed in 11 instances to inspect and test pressure-relief valves in 2015. During the inspection of PHMSA Unit 12232-AR1 in Little Rock, Arkansas, the PHMSA inspector reviewed Line P77 pressure-relief valve inspection records for 2013 and 2014. Enterprise did not have records for P77 for 2015. In its Response, Enterprise contested this Item, arguing that it was based on the same regulation as Item 13 (§ 195.428), so the two sets of allegations were not combined as one, which would have resulted in a greatly reduced penalty computation. In addition, Enterprise stated that all alleged instances of violation in Item 14 related to an idled line, namely, Line P77 – the same idled pipeline addressed in Items 11 and 12. For these reasons, Enterprise requested that Item 14 be withdrawn. During discussion with the Director after the inspection, Enterprise provided additional records showing that it had acquired Line P77 in a non-operative state and that it was formally abandoning the pipeline. Based on this, the Director recommended that this Item be withdrawn. Accordingly, after considering all of the evidence, I hereby order that Item 14 be withdrawn. Item 16: The Notice alleged that Respondent 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 APT 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). The risk-based internal inspection procedures in API Std 653, section 4.3.2 cannot be used to determine the internal inspection interval. The Notice alleged that Respondent violated 49 C.F.R. § 195.432(b) by failing to inspect the physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks in accordance with API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, incorporated by reference in § 195.3(b)(19). Specifically, the Notice alleged that Enterprise failed to inspect seven breakout tanks (BOTs) in accordance with the intervals required by API Standard 653 (API 653). The Notice stated that at the time of construction (2000-2004) of the tanks in question, they were all initially incorporated into Enterprise’s Risk Based Inspection#

120185003_Final Order_04062020_text.pdf, page 15CPF No. 1-2018-5003 Page 14 Program (RBIP), which is permitted under API 653, Section 6.4.3, as an alternative approach to API 653, Section 6.4.2, which requires inspection intervals of not more than 10 years. However, according to the Notice, Enterprise claimed that as a result of a previous enforcement proceeding arising out of PHMSA’s Southwest Region (CPF 4-2012-5008M), Enterprise had transitioned to the non-risk-based approach for certain BOTs, and instead followed API 653, Section 6.4.2, to establish inspection intervals of 10 years for each of the BOTs. The Notice alleged, on the contrary, that none of the BOTs at issue in this Item were included in or related to the prior enforcement proceeding. As a result, the Notice alleged the seven BOTs were out of compliance by a range of two to seven years because they had not been inspected within 10 years from the relevant construction dates (2000-2004). In its Response, Enterprise contested the allegation of violation, stating that four of the BOTs in question were inspected or decommissioned within the applicable intervals under API 653, and that the three remaining tanks were subject to an inspection-interval schedule that had been previously negotiated with PHMSA’s Southwest Region Director in the earlier enforcement proceeding. Enterprise further stated that the agreed-upon schedule for the inspection of the remaining three BOTs was discussed, in person, with the Director and representations were made to Enterprise personnel that those tanks would be outside the scope of the inspection at issue in this case. Finally, Enterprise argued that PHMSA was precluded, as a matter of law, from invoking the regulation inconsistently across regions. I find that Enterprise did not violate the regulation as alleged in the Notice. First, PHMSA does not rebut Enterprise’s defense that four of the seven BOTs in question were inspected or decommissioned within the requisite inspection intervals. Second, the alleged violation is based on an allegation that Enterprise was required to complete inspection intervals not later than 10 years from the date of construction of each of the seven BOTs, which were all constructed between January 1, 2010, and October 10, 2004. Based on these dates of construction, and the maximum inspection interval of 10 years permitted under API 653, Section 6.4.2, the Notice alleged that Enterprise was out of compliance for a period or two to seven years for the relevant BOTs. However, on April 2, 1999, the Research and Special Programs Administration (RSPA), PHMSA’s predecessor agency, amended 49 CFR § 195.432(b) to require integrity inspection under Section 4 of API 653 for all breakout tanks.5 All of the relevant BOTs were constructed after this amendment to § 195.432(b). On August 11, 2010, PHMSA again amended § 195.432(b) to delete references to Section 4 of API 653 and instead incorporated by reference all sections of API 653 relating to the inspection of in-service atmospheric and low-pressure steel aboveground breakout tanks, like the ones in question in this case.6 Finally, on January 5, 2015, PHMSA further amended § 195.432(b) to eliminate use of API 653, section 6.4.3, when establishing inspection intervals. Further, the amended (and current) rule states that if internal inspection intervals were established prior to March 6, 2015, by using the risk-based approach 5 Pipeline Safety: Adoption of Consensus Standards for Breakout Tanks, 64 Federal Register 15,936 (April 2, 1999). 6 Pipeline Safety: Periodic Updates of Regulatory References to Technical Standards and Miscellaneous Edits, 75 Federal Register 48,607 (August 11, 2010).#

120185003_Final Order_04062020_text.pdf, page 16CPF No. 1-2018-5003 Page 15 permitted by API 653, section 6.4.3, the operator must re-establish the intervals pursuant to API 653, section 6.4.2, which caps intervals at 10 years, and complete the inspection by January 5, 2017. The record reflects that Enterprise established the inspection intervals prior to March 6, 2015, using API 653, section 6.4.3, and later re-established 10-year inspection intervals under API 653, section 6.4.3. The allegation in this case is that Enterprise should have completed its inspections not more than 10 years from the date of construction. Enterprise, however, was not required to establish inspection intervals of not more than 10 years until the most recent amendment to the regulation, which was January 5, 2015. Further, although Enterprise was required to complete a new internal inspection on the BOTs at issue prior to January 5, 2017, the Notice in this case does not allege a failure to do so as the basis for the alleged violation. Accordingly, I find that PHMSA failed to meet its burden of proving the violation alleged in the Notice. I need not reach the legal question presented of whether PHMSA is precluded from making a finding of violation where the finding could be viewed as contrary to an agreement made between the operator and a PHMSA regional director because this allegation of violation is withdrawn on separate grounds. Based upon the foregoing, I hereby order that Item 16 be withdrawn. WARNING ITEMS With respect to Items 10 and 11, the Notice alleged probable violations of Part 195 but, for the reasons summarized below, the Director requested that the proposed civil penalty for each Item be withdrawn and that the Items be reduced to warning items. Based on the Director’s request, and my review of the evidence, I hereby order that Items 10 and 11 be reduced to warning items, as follows: 49 C.F.R. § 195.402(a) (Item 10) ─ Respondent’s alleged failure to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, the Notice alleged that Enterprise failed to follow its procedures for maintaining records for fire-extinguisher inspections conducted in accordance with § 195.430; and 49 C.F.R. § 195.404(a)(3) (Item 11) ─ Respondent’s alleged failure to maintain records of its pipeline systems that include the maximum operating pressure (MOP) of each pipeline. Enterprise presented information in its Response, and during follow-up meetings with the Director, showing that it had taken certain actions to address the cited items. In response to Item 10, Enterprise explained that a third-party inspector performs its annual fire- extinguisher inspections and uses its own forms to record the results that are not always identical to the form identified in Enterprise’s procedures. Further, Enterprise provided records of the last#

120185003_Final Order_04062020_text.pdf, page 17CPF No. 1-2018-5003 Page 16 and next hydrotest dates for the four fire extinguishers addressed in Item 10, which had not previously been provided to PHMSA In response to Item 11, Enterprise provided records showing that it had acquired the pipelines at issue in a non-operational status, and that it had properly abandoned two of the 13 lines prior to the PHMSA inspection, and seven of the 13 lines were properly abandoned after the inspection. OPS requests that, in the future, Enterprise coordinate deferral of maintenance activities on any lines that are purged and considered “idle” in advance of such work, as detailed in PHMSA’s Advisory Bulletin, Pipeline Safety: Clarification of Terms Relating to Pipeline Operational Status, 81 Fed. Reg. 54,512 (August 16, 2016). If OPS finds a violation of any of these provisions in a subsequent inspection, Enterprise may be subject to future enforcement action. 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. 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; 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 $703,900 for the violations cited above. Item 1: The Notice proposed a civil penalty of $27,500 for Respondent’s violation of 49 C.F.R. § 195.310(a), for failing to maintain a record of each pressure test required by Subpart E. In its Amended Response, Enterprise waived its objection to the proposed penalty. I find that the record shows that the civil penalty was appropriately calculated based on the assessment considerations set forth in § 190.225. Based upon the foregoing, I assess Respondent a civil penalty of $27,500 for violation of 49 C.F.R. § 195.310(a). Item 2: The Notice proposed a civil penalty of $53,600 for Respondent’s violation of 49 C.F.R. § 195.402(a), for failing to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. In its Amended Response, Enterprise stated that it was withdrawing its challenge to two of the four instances of violation for this Item and that it had provided evidence to the Director demonstrating that two of the identified segments were not subject to regulation under Part 195 at the time of the PHMSA inspection. The Director agreed with this assertion after reviewing the records and requested that the civil penalty be reduced to reflect two, rather than four, instances of violation. I find that the record reflects that Enterprise violated the regulation in two instances, not four as alleged in the Notice, and that the civil penalty was otherwise#

120185003_Final Order_04062020_text.pdf, page 18CPF No. 1-2018-5003 Page 17 appropriately calculated based on the assessment considerations set forth in § 190.225. Based upon the foregoing, I assess Respondent a reduced civil penalty of $51,400. Item 3: The Notice proposed a civil penalty of $72,000 for Respondent’s violation of 49 C.F.R. § 195.402(a), for failing to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. For the reasons set forth above, this Item is withdrawn, along with the proposed penalty. Item 4: The Notice proposed a civil penalty of $27,300 for Respondent’s violation of 49 C.F.R. § 195.402(a), for failing to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. For the reasons set forth above, this item is withdrawn, along with the proposed penalty. Item 5: The Notice proposed a civil penalty of $8,800 for Respondent’s violation of 49 C.F.R. § 195.583(a), for failing to conduct an inspection of each pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion at least once every three calendar years, but with intervals not exceeding 39 months. In its Amended Response, Enterprise withdrew its objection to the proposed civil penalty for this Item. I find that the record shows that the proposed penalty was appropriately calculated based on the assessment considerations set forth in § 190.225. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $8,800 for violation of 49 C.F.R. § 195.583(a). Item 6: The Notice proposed a civil penalty of $72,500 for Respondent’s violation of 49 C.F.R. § 195.402(a), for failing to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. As stated above, Enterprise withdrew its objection to 17 of the 23 instances of violation as alleged in the Notice. With respect to the remaining six, Enterprise stated that it had records demonstrating compliance. Those records were provided to the Director subsequent to the inspection, and, after reviewing them, the Director agreed that six of the instances of alleged violation associated with the Greensburg, Pennsylvania and Watkins Glen, New York inspection units should be withdrawn.7 Accordingly, I find that the record supports a reduction in the number of instances of violation from 23 to 17 but that the proposed civil penalty was otherwise appropriately calculated based on the assessment considerations set forth in § 190.225. Based upon the foregoing, I assess Respondent a reduced civil penalty of $67,600. Item 8: The Notice proposed a civil penalty of $33,100 for Respondent’s violation of 49 C.F.R. § 195.402(a), for failing to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. For the reasons set forth above, this item is withdrawn, along with the proposed penalty. Item 9: The Notice proposed a civil penalty of $27,300 for Respondent’s violation of 49 C.F.R. § 195.402(a), for failing to follow for each pipeline system a manual of written procedures for 7 Region Recommendation, at 3 (on file with PHMSA).#

120185003_Final Order_04062020_text.pdf, page 19CPF No. 1-2018-5003 Page 18 conducting normal operations and maintenance activities and handling abnormal operations and emergencies. For the reasons set forth above, this item is withdrawn, along with the proposed penalty. Item 10: The Notice proposed a civil penalty of $12,900 for Respondent’s violation of 49 C.F.R. § 194.402(a), for failing to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. For the reasons set forth above, this item is converted to a Warning Item and the proposed penalty withdrawn. Item 11: The Notice proposed a civil penalty of $60,400 for Respondent’s violation of 49 C.F.R. § 195.404(a)(3), for failing to maintain records of its pipeline systems that include the MOP of each pipeline. For the reasons set forth above, this item is converted to a Warning Item and the proposed penalty withdrawn. Item 12: The Notice proposed a civil penalty of $55,800 for Respondent’s violation of 49 C.F.R. § 195.420(b), for failing to inspect each mainline valve at intervals not exceeding 7½ months, but at least twice each calendar year, to determine that it is functioning properly. For the reasons set forth above, this item is withdrawn and the proposed penalty withdrawn. Item 13: The Notice proposed a civil penalty of $55,800 for Respondent’s violation of 49 C.F.R. § 195.428(a), for failing to conduct an inspection and test of each overpressure- protection device at intervals not to exceed 7½ months, but at least twice each calendar year, as specified per § 195.428. In its Amended Response, Enterprise withdrew its challenge to this item but reaffirmed its challenge to the number of instances of alleged violation, and requested that the penalty be reduced to reflect the four, not six, instances of violation. Specifically, Enterprise stated that subsequent to the inspection, it located records associated with the Moshannon Station, which represent two of the alleged six instances of violation. I find that the record supports Enterprise’s position that the instances of violation be reduced from six to four. I further find that the record shows that the civil penalty was otherwise appropriately calculated based on the assessment considerations set forth in § 190.225. Based upon the foregoing, I assess Respondent a reduced civil penalty of $53,600. Item 14: The Notice proposed a civil penalty of $61,200 for Respondent’s violation of 49 C.F.R. § 195.428(a), for failing to inspect and test each pressure-limiting device, relief valve, pressure regulator, or other item of pressure-control equipment at intervals not exceeding 15 months, but at least once each calendar year, to determine that it is functioning properly, is in good mechanical condition, and is adequate from the standpoint of capacity and reliability of operation for the service in which it is used. For the reasons set forth above, this item is withdrawn, along with the proposed penalty. Item 15: The Notice proposed a civil penalty of $27,500 for Respondent’s violation of 49 C.F.R. § 195.404(c)(3), for failing to maintain a record of each inspection and test for at least two years or until the next inspection or test is performed. In its Amended Response, Enterprise withdrew its challenge to one of the three instances of violation alleged in the Notice. With respect to the other two, Enterprise argued that it was not required to maintain its 2014 tank-#

120185003_Final Order_04062020_text.pdf, page 20CPF No. 1-2018-5003 Page 19 inspection records for more than two years, as alleged in the Notice. For the reasons described more fully above, I agree with Enterprise and find that the record reflects only one instance of violation and that the civil penalty was otherwise appropriately calculated based on the assessment considerations set forth in § 190.225. Based upon the foregoing, I assess Respondent a reduced civil penalty of $27,300. Item 16: The Notice proposed a civil penalty of $56,800 for Respondent’s violation of 49 C.F.R. § 195.432(b), for failing to inspect the physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks in accordance with API Standard 653, Tank Inspection, Repair, Alteration, and Reconstruction, incorporated by reference in § 195.3(b)(19). For the reasons set forth above, this item is withdrawn, along with the proposed penalty. Item 17: The Notice proposed a civil penalty of $51,400 for Respondent’s violation of 49 C.F.R. § 195.579(d), for failing to demonstrate that its breakout-tank linings were installed in accordance with API RP 652, as required by the regulation. In its Amended Response, Enterprise withdrew its challenge to one of the two instances of violation alleged in the Notice for this item. With respect to the one remaining allegation of violation, Enterprise relied on additional breakout-tank liner installation records, which had not been provided to PHMSA until after the inspection, to demonstrate compliance for tank DOT-T-1302. I find that the record reflects that Enterprise did not violate the regulation with regard to tank DOT-T-1302. I further find that the record shows that the civil penalty was otherwise appropriately calculated based on the assessment considerations set forth in § 190.225. Based upon the foregoing, I assess Respondent a reduced civil penalty of $50,400. In summary, having reviewed the record and considered the assessment criteria for each of the Items cited above, I assess Respondent a total civil penalty of $286,600. Payment of the civil penalty must be made within 20 days of service. Federal regulations (49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed instructions are contained in the enclosure. Questions concerning wire transfers should be directed to: Financial Operations Division (AMK-325), Federal Aviation Administration, Mike Monroney Aeronautical Center, 6500 S MacArthur Blvd, Oklahoma City, Oklahoma 79169. The Financial Operations Division telephone number is (405) 954-8845. Failure to pay the $286,600 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 Items 3, 7, and 18 in the Notice for#

120185003_Final Order_04062020_text.pdf, page 21CPF No. 1-2018-5003 Page 20 violations of 49 C.F.R. §§ 195.402(a), 195.402(c)(3), and 195.402(a), respectively. 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. With regard to the violation of § 195.402(a) (Item 3), this item was withdrawn and therefore the proposed compliance terms associated with this item are also hereby withdrawn. With regard to the violation of § 195.402(c)(3) (Item 7), Enterprise withdrew its challenge to this item and associated proposed compliance order.8 With regard to the violation of § 195.402(a) (Item 18), Enterprise argued that the proposed compliance terms should be withdrawn because the company had already provided amended procedures to the Director relative to this item, and the amended procedures had been deemed adequate by the Director. I find that compliance has been achieved with respect to this item. For the above reasons, the Compliance Order is modified as set forth below. Pursuant to the authority of 49 U.S.C. § 60118(b) and 49 C.F.R. § 190.217, Respondent is ordered to take the following actions to ensure compliance with the pipeline safety regulations applicable to its operations: 1. With respect to the violation of § 195.402(a) (Item 7), Respondent must: a. Amend its procedures to include sufficient guidance per § 195.428(a) within 60 days of receipt of the Final Order. The Director may grant an extension of time to comply with any of the required items upon a written request timely submitted by the Respondent and demonstrating good cause for an extension. It is requested (not mandated) that Respondent maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to the Director. 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. Failure to comply with this Order may result in the administrative assessment of civil penalties not to exceed $200,000, as adjusted for inflation (49 C.F.R. § 190.223), for each violation for each day the violation continues or in referral to the Attorney General for appropriate relief in a district court of the United States. Under 49 C.F.R. § 190.243, Respondent may submit a Petition for Reconsideration of this Final Order to the Associate Administrator, Office of Pipeline Safety, PHMSA, 1200 New Jersey Avenue, SE, East Building, 2nd Floor, Washington, DC 20590, with a copy sent to the Office of 8 Amended Response, at 3 (on file with PHMSA).#

120185003_Final Order_04062020_text.pdf, page 22CPF No. 1-2018-5003 Page 21 Chief Counsel, PHMSA, at the same address, no later than 20 days after receipt of service of this 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. April 6, 2020 ___________________________________ __________________________ Alan K. Mayberry Date Issued Associate Administrator for Pipeline Safety#

120185003_Closure Letter_07102020_text.pdf, page 1Official PDFOVERNIGHT EXPRESS DELIVERY July 10, 2020 Mr. A. J. Teague Director and Co-Chief Executive Officer Enterprise Products Partners, LP 1100 Louisiana Street, 10th Floor Houston, Texas 77002 CPF 1-2018-5003 Dear Mr. Teague: On April 6, 2020, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to Enterprise Products Partners, LP a Final Order in the above-referenced case. This Order included a Compliance Order and Civil Penalty assessment. Based on our review of the documentation you provided and confirmation of payment of the civil penalty, it has been determined that you have complied with the terms of this Order. Accordingly, this case is now closed and no further action is contemplated with respect to the matters involved in this case. Thank you for your cooperation in this matter. Sincerely, Robert Burrough Director, Eastern Region Pipeline and Hazardous Materials Safety Administration#

120185003_NOPV PCP PCO_01292018_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER OVERNIGHT EXPRESS DELIVERY January 29, 2018 Mr. Graham Bacon Group SVP, Operations & EHS&T Enterprise Products Operating, LLC 1100 Louisiana Street Houston, TX 77002 CPF 1-2018-5003 Dear Mr. Bacon: From March 21, 2016 – December 2, 2016, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), pursuant to Chapter 601 of 49 United States inspected Enterprise Products Operating, LLC (Enterprise) procedures, records and pipeline facilities in Houston, Texas; Greensburg, Pennsylvania; Dubois, Pennsylvania; Lebanon, Ohio; Morgantown, Pennsylvania; Sorrento, Louisiana; Monee, Illinois; Seymour, Indiana; and Little Rock, Arkansas. As a result of the inspection, it is alleged that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violations are: 1. §195.310 Records. (a) A record must be made of each pressure test required by this subpart, and the record of the latest test must be retained as long as the facility tested is in use. (b) The record required by paragraph (a) of this section must include: (1) The pressure recording charts; (2) Test instrument calibration data;#

120185003_NOPV PCP PCO_01292018_text.pdf, page 2CPF 1-2018-5003 (3) The name of the operator, the name of the person responsible for making the test, and the name of the test company used, if any; (4) The date and time of the test; (5) The minimum test pressure; (6) The test medium; (7) A description of the facility tested and the test apparatus; (8) An explanation of any pressure discontinuities, including test failures, that appear on the pressure recording charts; and, (9) Where elevation differences in the section under test exceed 100 feet (30 meters), a profile of the pipeline that shows the elevation and test sites over the entire length of the test section. (10) Temperature of the test medium or pipe during the test period. Enterprise failed to maintain a record of each pressure test required by this subpart. Specifically, Enterprise failed to maintain hydrostatic test records for 4 breakout tanks (PHMSA Unit 12232), per the requirements of §195.310(b). §195.305 states, each pressure test under §195.302 must test all pipe and attached fittings, including components, unless otherwise permitted by paragraph (b) of this section. §195.310 states, a record must be made of each pressure test required by this subpart, and the record of the latest test must be retained as long as the facility tested is in use. During the inspection of inspection unit 12232-AR1 in Little Rock, Arkansas, the PHMSA inspector requested hydrostatic testing records for breakout tanks at the McRae and North Little Rock, Arkansas facilities. Enterprise provided records for tanks DOT-T_1301, DOT-T-1302, DOT-T-1304, and DOT-T-1305 as follows: 1. Tank 1301 Hydro Email, dated 07/19/2007 2. Tank 1302 Hydro Email, dated 07/26/2007 3. Tank 1304 Testing Form dated 3/30/2007 4. Tank 1304 hydro information email dated 7/2/2007 5. Tank 1305 Elevations - undated 6. Tank 1305 Settlement results dated 4/3/2008 None of the records provided by Enterprise included the information below that is required by §195.310(b): 1. Pressure recording charts 2. Test instrumentation calibration data 3. Date and time of the test 4. Minimum test pressure 5. Test medium 6. A description of the facility tested and the test apparatus 7. An explanation of any pressure discontinuities, including test failures, that appear on the pressure recording charts 8. Where elevation differences in the section under test exceed 100 feet (30 meters), a profile of the pipeline that shows the elevation and test sites over the entire length of the test section. 9. Temperature of the test medium or pipe during the test period 120185003_NOPV PCP PCO_01292018_text Page 2 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 3CPF 1-2018-5003 2. §195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. Enterprise failed to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, Enterprise failed to follow its computational pipeline monitoring (CPM) manual for providing a means of leak detection on its pipeline system. During the inspection of Enterprise procedures in Houston, Texas, the PHMSA inspector reviewed Enterprise’s CPM O&M Manual, dated 03/01/11, and “Audit List of Lines” record which showed Enterprise pipelines with leak detection. The Enterprise procedure stated, “…All regulated pipelines operated by Enterprise Products control centers will be targeted for implementation of this baseline CPM system. If this baseline leak detection application cannot be implemented on targeted line, then alternative technologies will be evaluated…” The “Audit List of Lines” record showed four pipelines with no leak detection in high consequence areas (HCAs). 1. 2. 3. 4. Line ID P84, PODS ID 1357, total miles 0.945, HCA miles 0.047 Line ID P79, PODS ID 6427, total miles 0.409, HCA miles 0.409 Line ID P29B, PODS ID 7201936, total miles 0.53, HCA miles 0.53 Line ID P29A, PODS ID 7201937, total miles 0.53, HCA miles 0.53 The PHMSA inspector asked why these pipelines were not covered by the Enterprise leak detection program and Enterprise stated, “they observe leaks by means of the normal patrolling activities on these lines.” The PHMSA inspector asked Enterprise for relevant records regarding alternative technologies used for these pipelines. Enterprise was not able to provide any records. In an email dated 1/12/17, Enterprise stated, “The technology review (LDCE study) for the 2.41 miles not currently in CPM is budgeted and scheduled to be performed in 2017.” Thus, Enterprise failed to follow its procedures for leak detection. 3. § 195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. 120185003_NOPV PCP PCO_01292018_text Page 3 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 4CPF 1-2018-5003 This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. Enterprise failed to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, Enterprise failed to follow its manual of written procedures for its leak detection measures. During the inspection of Enterprise procedures in Houston, Texas, the PHMSA inspector reviewed Enterprise procedure – CPM O&M manual – Liquid Pipelines Operated by Houston OCC, dated 3/1/11. The procedure states in part that: “Performance Evaluations – Annual analysis of existing pipeline CPM systems will be performed to determine if a pipeline system is meeting appropriate leak detection targets as defined in the company leak detection strategy (Appendix A) …” Appendix A states that: “Risk ranking and target threshold (60 min): Pipelines will be ranked into three (3) tiers based upon HCA impact and the Pipeline Integrity Risk model ‘consequence score’. Pipeline systems that include multiple line assessments with different rankings will assume the highest ranking. Tier III lines will be lines that have “No HCA Impact”. Tier III target leak threshold will be 12% leak detection in 60 minutes. Tier II lines will be lines that have “HCA Impact”. Tier III [sic] target leak threshold will be 5% leak detection in 60 minutes. Tier I lines will be lines that have “HCA Impact” and consequence score above TBD. Tier I target leak threshold will be 2% leak detection in 60 minutes.” Risk Level of Pipeline Target Threshold Tier I 2% leak detection in 60 minutes Tier II 5% leak detection in 60 minutes Tier III 12% leak detection in 60 minutes The PHMSA inspector requested the 2014, 2015 and 2016 CPM performance evaluation records for the following inspection units: 1. 2. 3. 4. 5. 6. 7. IU 3051 – Greensburg (Greensburg, Pennsylvania office) IU 3071 – Dubois (Watkins Glen, New York office) IU 4213 – Allegheny (Lebanon, Ohio office) IU 3061 – Eagle (Morgantown, Pennsylvania Office) IU 2464 – Lou Tex (Sorrento, Louisiana Office) IU 18043 – TEPPCO Chicago (Monee, Illinois Office) IU 12232 – AR1 (Little Rock, Arkansas Office) Enterprise provided leak detection budget request emails for 2014, 2015 and 2016. Each of the emails stated in part: “We have developed the attached Leak Detection Budget Request items for the liquid pipelines in your area… 120185003_NOPV PCP PCO_01292018_text Page 4 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 5CPF 1-2018-5003 To prepare this budget we have: 1. 2. 3. 4. 5. Reviewed our current leak detection implementation status Pulled the latest pipeline data from the Asset Integrity PODS database Performed a high‐risk/low‐performing analysis of our current implementation Established budgetary plan for implementation of Enhanced Leak Detection Systems Identified all the “orphan laterals” which are not covered by leak detection today. Attached is the budget request for your area, as well as a list of orphan laterals where the Control Center is unable to perform leak detection because of a lack of sufficient instrumentation. The orphan laterals need to be monitored by Field Operations until we can address the instrumentation deficiency.” The emails provided by Enterprise did not provide any details to support that Pipelines were ranked into three tiers or that target thresholds were met. Therefore, Enterprise failed to follow its manual of written procedures. 4. §195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. Enterprise failed to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, Enterprise failed to follow its abnormal operation procedure (AOC) O&M Manual requirements for documenting any AOC actions taken, prior to a supervisory close out of the AOCs. During the inspection of inspection unit 12232-AR1 in Little Rock, Arkansas, the PHMSA inspector requested AOC records for the McRae and North Little Rock, Arkansas terminals. The PHMSA inspector reviewed, “TEC AOC RESPONDER” report that provided 10 records from January through November 2016. One Enterprise McRae terminal record, contained no information under the subheadings – “AOC conditions found” and “AOC actions taken.” The “Manager Review” and “Manager Confirmed AOC” were both closed out with no indications of what AOC condition was found or AOC actions were taken. Furthermore, Enterprise O&M Manual Abnormal Operation Procedures Section 801, dated 11/12/13 states, “Control Room Operations Supervision and/or the Location Supervisor will retain any available records that may be used to reconstruct the sequence of events surrounding an abnormal operation as defined in this section.” The PHMSA inspector asked for additional information on the AOC record, but Enterprise was not able to provide any. The Enterprise Location Supervisor responded, “this was a glitch in the system and we are working to fix it.” 120185003_NOPV PCP PCO_01292018_text Page 5 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 6CPF 1-2018-5003 Therefore, Enterprise failed to follow its abnormal operation procedures in their O&M Manual. 5. §195.583 What must I do to monitor atmospheric corrosion control? (a) You must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows: If the pipeline is located: Then the frequency of inspection is: Onshore At least once every 3 calendar years, but with intervals not exceeding 39 months Enterprise failed to conduct an inspection of each pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion at least once every 3 calendar years, but with intervals not exceeding 39 months. During the inspection, the PHMSA inspector reviewed Enterprise’s “EPROD Survey Report Atmospheric” atmospheric corrosion records from 1/1/11 to 12/30/15. The records for the pipeline segments below show that the interval between inspections exceeded the 39-month interval in two instances. 1. 2. Segment Code: 03 Mundys to Duncansville” with the following inspection dates: 6/18/11 and 9/25/14 – 6 days’ past due Segment Code: 04 Duncansville to Jacks” with the following inspection dates: 6/25/12 and 10/6/15 – 10 days’ past due Therefore, Enterprise failed to inspect each pipeline for atmospheric corrosion, per §195.583(a). 6. §195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. Enterprise failed to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Enterprise failed to follow its written procedures for performing its pressure limiting and relief device inspections, per §195.428(a). Enterprise O&M Miscellaneous Operating Procedures – Over Pressure Safety Devices Section 1305, dated 11/12/13 states, “In addition, the overpressure protection system must be inspected and tested, either actual or simulated, at the required overpressure protection set point…” During the inspection of inspection unit 2464- Lou Tex, in Sorrento, Louisiana, the PHMSA inspector reviewed Enterprise TEC PSV INSP – Fagus Pressure Safety records, dated 2014 and 120185003_NOPV PCP PCO_01292018_text Page 6 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 7CPF 1-2018-5003 2015. The records showed the pressure relief valve data did not indicate a “Set Pressure (PSI)” for (9) pressure relief valves in 2014 and (6) in 2015. The PHMSA inspector asked Enterprise why the data was blank on the applicable records and Enterprise did not have a response. Additionally, Enterprise failed to adequately document the “set pressure (PSI)” for relief valve settings on its 2015 and 2016 pressure safety valve (PSV) inspection records on the ATEX pipeline segments. During the inspection of inspection unit 3051-Greensburg in Greensburg, Pennsylvania, the PHMSA inspector reviewed Enterprise O&M section 1305 – Miscellaneous Operating Procedures (Procedure) and “TEN PSV Insp” records for 2015 and 2016 (Records). The Records did not record a “set pressure (PSI)” for the PSVs. Additionally, these records were not consistent with Enterprise A1 and A3 PSV inspection records reviewed during the inspection as they did not contain all data per the record forms. During the inspection, Enterprise was unaware of what value (PSI) these PSVs were tested at, or what pressure values these PSVs were left at. During the inspection of inspection unit 3071-Dubois, in Watkins Glen, New York, the PHMSA inspector reviewed the following: 1. Enterprise O&M section 1305 – Miscellaneous Operating procedure, dated 11/12/13. (Procedure) 2. Enterprise 2014 through 2016 overpressure protection records for Moshannon, PA pump station 3. Enterprise “Maintenance Work Order Detail Report” for the spring 2014 inspection interval The Procedure states in part: “…each inspection and repair is documented on the appropriate form to determine that it is functioning properly, in good mechanical/electrical condition, adequate from the standpoint of capacity and reliability of operation for the service in which it is used, set to function at the correct pressure and properly installed and protected from foreign materials or other conditions that might prevent proper operation.” Neither the overpressure protection record nor the “Maintenance Work Order Detail Report” provided the following information required by the Procedure: 1. Valve mechanical/electrical condition 2. Adequacy of capacity and reliability of operation 3. Functionality at the correct pressure 4. Proper installation and protection from foreign materials or other conditions that might prevent proper operation 5. Set pressure of device and set pressure as found Enterprise stated, “we are unable to produce a copy of the formal report (as shown in other pump stations/years) but the record is shown on the Maintenance Work Order Detail Report.” 120185003_NOPV PCP PCO_01292018_text Page 7 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 8CPF 1-2018-5003 Therefore, at inspection unit 2464-Lou Tex, inspection unit 3051-Greensburg, and inspection unit 3071-Dubois, Enterprise failed to follow its written procedures for performing inspections of overpressure protection devices. 7. §195.402 Procedural manual for operations, maintenance, and emergencies. (c) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following to provide safety during maintenance and normal operations: (3) Operating, maintaining, and repairing the pipeline system in accordance with each of the requirements of this subpart and subpart H of this part. Enterprise’s procedures for operating, maintaining and repairing the pipeline system in accordance with the requirements of this subpart and subpart H of this part are inadequate. Specifically, Enterprise procedures fail to provide sufficient guidance on how to conduct and document relief valve inspections as per §195.428(a). During the inspection, the PHMSA inspector reviewed Enterprise’s Miscellaneous Operating Procedures Section 1305 Over Pressure Safety Devices, dated 11/12/13 (Procedure), and their pressure control inspection and testing records. The Procedure states in part that: “Each pressure limiting device, relief valve, pressure regulator, and other types of pressure control equipment (pressure transmitters, switches, PCVs) shall be inspected and tested at intervals not exceeding 15 months, but at least once each calendar year for crude oil and other non-HVL products and not exceeding seven and a half months, but at least twice each calendar year for HVL products, and each inspection and repair is documented on the appropriate form to determine that it is: 1. Functioning properly 2. In good mechanical/electrical condition 3. Adequate from the standpoint of capacity and reliability of operation for the service in which it is used. 4. 5. Set to function at the correct pressure Properly installed and protected from foreign materials or other conditions that might prevent proper operation.” Enterprise’s procedure Miscellaneous Operating Procedures Section 1305 does not provide sufficient guidance on conducting and documenting a relief valve inspection. In order to ensure that a relief valve will relieve at the specified set pressure when needed, data is necessary on the condition of the valve prior to the inspection (“as found”), as well as on the condition of the valve after the inspection is completed (“as left”). Information typically documented includes: 1. Relief pressure of the valve in the “as found” condition 2. Relief pressure of the valve in the “as left” condition 3. The “set pressure” 120185003_NOPV PCP PCO_01292018_text Page 8 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 9CPF 1-2018-5003 The Procedure did not include any requirements for capturing either the “as found” or “as left” pressure of a relief device. In addition, the procedure lacked details such as: 1. 2. The criteria for determining acceptable “as-found” / “as left” relief pressures The actions that must be taken if the relief valve “as-found” pressure does not meet the criteria 3. 4. a. b. 5. The definition of the term “set pressure” The documentation required and where it must be recorded, for example: The information that must be captured in the records Where the “as-found” and “as-left” pressures are recorded How to ensure that the MOP will not be exceeded during testing of the relief device Additionally, Enterprise failed to include guidance in its written procedures for overpressure safety devices. During the inspection of inspection unit 3071-Dubois, in Watkins Glen, New York, the PHMSA inspector reviewed Enterprise overpressure protection records for Gaines, PA pump station from 2014 through 2016. The records for the (2) overpressure valves inspections that were conducted in May and October, 2014 were inadequate as the set pressure was approximately +/- 200 PSI higher/lower than the set pressure as found. Enterprise O&M section 1305 – Miscellaneous Operating Procedures states, “…the overpressure protection system must be inspected and tested, either actual or simulated, at the required overpressure protection set point.” Enterprise records stated, all overpressure protection valves were marked “Y” for “Set Pressure Good” on the 2014 records. The procedure, however, provided no guidance as to the criteria for determining the set pressure as well as the “as found” / “as left” relief pressures to assure the valves are in good mechanical condition and functioning properly. Therefore, Enterprise procedure failed to provide sufficient guidance on how to conduct and document relief valve inspections as per §195.428(a). 8. §195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted Enterprise failed to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, Enterprise failed to follow its Pipeline Hydrostatic Testing procedure for conducting pressure testing according to the requirements of §195.305. During the inspection of inspection unit 2703-Seymour, in Seymour, Indiana, the PHMSA inspector reviewed the following: 120185003_NOPV PCP PCO_01292018_text Page 9 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 10CPF 1-2018-5003 1. Enterprise’s procedure for pressure testing (Pipeline Hydrostatic Testing - Standard 4507, dated November, 2012 (Procedure) 2. Pipeline Hydrostatic Testing Documentation- Form 4507 Hydrostatic Test Report, for project name “P/L Integrity Assessment – AID 2453, LID P84- 4” Seymour to HWRT.” (Form 4507) The Procedure states in part: Section 11.1 (6): “All data shall be recorded on Form 4507. Pressures, temperatures, stroke counts, time, and all other data on the test section shall be clearly recorded, legible, and understandable…” Section 15.1: “(2) The following information shall be included and clearly labeled with the test report: … h. End time and date of “off” test with final pressure. … m. The name of the operator, the name of the person responsible for making the test and the name of the test company used (contractor – where applicable).” Enterprise’s Hydrostatic Test Report, Form 4507, with a Start of Test Period dated 4/4/2013 failed to include the following: 1. 2. 3. 4. End time and date of “off” test with final pressure The name of the person responsible for making the test The Company Representative who recorded the test and date The Test Director who approved the test and date Therefore, Enterprise failed to follow its written procedure. 9. §195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted Enterprise failed to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, Enterprise failed to follow its procedure for maintaining records for emergency response training conducted in accordance with § 195.403(b)(1). During the inspection of inspection unit 3051-Greensburg, Pennsylvania, the PHMSA inspector reviewed the following: 1. Enterprise’s O&M manual Section 905 – Emergency Procedures (Procedure) 120185003_NOPV PCP PCO_01292018_text Page 10 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 11CPF 1-2018-5003 2. Emergency response training performance records for Greensburg, PA personnel for 2014 and 2015. The Procedure states in part that: “The Company provides emergency response training utilizing internally approved instructors and/or approved third party emergency response training instructors/schools… This review is documented on form 905A and retained by Local Area Operations.” The emergency response training for 2014 was documented in a spreadsheet and did not include the following information that is required on Form 905A: 1. Training topics 2. Employee signature and date 3. Supervisor signature and date Form 905A requires the following information to be completed: 1. Employee’s emergency response training checkboxes for (5) topical areas 2. Employee signature and date 3. Supervisor signature and date In email communication dated June 1, 2016, Enterprise stated, “Training form 905A and 905B are not available for IU 3051 for 2014. The Oracle Learning Management report is the only available record of the employees completing the annual emergency response training.” Therefore, Enterprise failed to follow its Procedure. 10. § 195.402(a) Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Enterprise failed to follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, Enterprise failed to follow its procedures for maintaining records for fire extinguisher inspections conducted in accordance with §195.430. During the inspection of inspection unit 2464- Lou Tex in Sorrento, Louisiana, the PHMSA inspector reviewed the following: 1. Enterprise’s procedure, “EH&S Management System – Safety Policies Manual Section 5.2 – Fire Protection”, dated 3/9/12 (Procedure) 2. Annual and monthly fire extinguisher records from 2013-2015 for the Laplace, LA. pump station. The Procedure states in part that: “a. …Arrange for a State licensed contractor/representative to perform annual maintenance and recharging of fire extinguishers… b. The annual inspection shall be documented on the "Annual Fire Extinguisher Guidelines" (SF01) form or an equivalent report provided by outside service.” 120185003_NOPV PCP PCO_01292018_text Page 11 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 12CPF 1-2018-5003 The annual fire extinguisher inspections were documented as follows: 1. 1/4/2013 and 3/8/2015 - Form SF01. 2. 12/4/2013 – United Fire and Safety Form. The United Fire and Safety form (UFS Form) was used to document the December 2013 inspections was not equivalent to the Enterprise Form SF01 that is required by the procedure. The UFS Form did not include the following information that was included on form SF01.: 1. Last hydrostatic testing date 2. Next hydrostatic testing date In addition, the UFS Form dated 12/4/2013 did not include United Fire and Safety technician signature, or the Customer representative signature. Therefore, Enterprise failed to follow its procedures for maintaining records for fire extinguisher inspections conducted in accordance with §195.430 for its 2014 annual fire extinguisher records. 11. § 195.404(a)(3) Maps and records. (a) Each operator shall maintain current maps and records of its pipeline systems that include at least the following information; … (3) The maximum operating pressure of each pipeline Enterprise failed to maintain records of its pipeline systems that include the maximum operating pressure (MOP) of each pipeline. During the inspection of Enterprise records and procedures in Houston, Texas and at field locations, the PHMSA inspector reviewed records for the MOP of jurisdictional pipeline segments. Enterprise’s idle line list dated 1/9/2017 included 32 pipelines. 1. 2. The “Last Known MOP” was missing for 13 pipelines The “Install Date” was missing for 5 pipelines Enterprise stated, “the MOP is not calculated for idle pipelines.” Enterprise provided, “Idle Pipeline List”, dated 01/09/17. The record showed that there were 32 different pipeline line IDs identified as idle. The record stated, the “Last Known MOP”, “Install Date” and “Date Idle” were unknown for several pipeline segments. Furthermore, 13/32 pipeline line IDs have an unknown/missing MOP. In an email dated 1/13/17, the PHMSA inspector requested a data list related to the MOP of all affected idle pipelines within the system inspection. Enterprise stated, “There are no further updates available to the Enterprise Idle Pipeline List provided on 1/10/17.” Therefore, Enterprise failed to maintain records of its pipeline systems that included the MOP of each pipeline. 120185003_NOPV PCP PCO_01292018_text Page 12 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 13CPF 1-2018-5003 12. § 195.420(b) Valve Maintenance. … (b) Each operator shall, at intervals not exceeding 7½ months, but at least twice each calendar year, inspect each mainline valve to determine that it is functioning properly. Enterprise failed to inspect each mainline valve at intervals not exceeding 7 ½ months, but at least twice each calendar year, to determine that it is functioning properly. During the inspection of inspection unit 2464-Lou Tex in Sorrento, Louisiana and inspection unit 12232-AR1 in Little Rock, Arkansas, the PHMSA inspector reviewed mainline valve records for the years 2013 – 2016. The records show that in 6 instances, Enterprise failed to inspect mainline valves twice per year and in 2 instances failed to inspect mainline valves at intervals not exceeding 7 ½ months. Details for the mainline valve inspections conducted by Enterprise are as follows: Inspection Unit 2464-Lou Tex (PHMSA inspection conducted on 9/15/16). Beaumont 6” Lateral 155MLV4-2B (152142): 4 instances 1. 2013 and 2014 – No records – Enterprise failed to inspect twice in 2013 and twice in 2014 2. Inspections were completed on the following dates a. 3/20/2015 b. 9/17/2015 c. 3/19/2016 d. 9/15/2016 Inspection Unit 12232-AR1 (PHMSA inspection conducted on 12/1/16). P77 VA04: 2 instances 1. Inspections were completed on the following dates a. 4/15/2014 b. 11/5/2014 c. 5/7/2015 2. Inspection Due in 7.5 months from 5/7/2015 = 12/22/2015 – No Record – Therefore they failed to inspect twice in 2015 3. Inspection Due in 7.5 months from 1/1/2016 = 8/16/2016 – No Record – Therefore they failed to perform the first inspection of 2016 4. During the inspection, Enterprise stated, “the mainline valves were removed from service in July, 2016 however we do not have inspection records for missing 2015 and 2016 time periods P77 VA05: 2 instances (Unit 12232-AR1) 1. Inspections were completed on the following dates 2. 4/15/2014 3. 11/5/2014 4. 5/7/2015 5. Inspection Due in 7.5 months from 5/7/2015 = 12/22/2015 – No Record – Therefore 120185003_NOPV PCP PCO_01292018_text Page 13 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 14CPF 1-2018-5003 they failed to inspect twice in 2015 6. Inspection Due in 7.5 months from 1/1/2016 = 8/16/2016 – No Record – Therefore they failed to perform the first inspection of 2016. 7. During the inspection, Enterprise stated, “the mainline valves were removed from service in July, 2016 however we do not have inspection records for missing 2015 and 2016 time periods Therefore, Enterprise failed to inspect its mainline valves per the requirements of §195.420(b). 13. §195.428 Overpressure safety devices and overfill protection systems. (a) Except as provided in paragraph (b) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, or in the case of pipelines used to carry highly volatile liquids, at intervals not to exceed 7½ months, but at least twice each calendar year, inspect and test each pressure limiting device, relief valve, pressure regulator, or other item of pressure control equipment to determine that it is functioning properly, is in good mechanical condition, and is adequate from the standpoint of capacity and reliability of operation for the service in which it is used. Enterprise failed to conduct an inspection and test of each overpressure protection device at intervals not to exceed 7 ½ months, but at least twice each calendar year, as specified per §195.428. Specifically, Enterprise did not conduct an inspection and test of its HVL overpressure protection valves at Moshannon, PA pump station during the following periods: 1. Device # MOS377 Thermal bypass valve 001 receiving barrel – 1st inspection 2014, 1st inspection 2015, 2nd inspection 2015 2. Device # MOS377 Thermal bypass valve 002 launching barrel – 1st inspection 2014, 1st inspection 2015, 2nd inspection 2015 During the inspection of inspection unit 3071-Dubois, in Watkins Glen, New York, the PHMSA inspector reviewed Enterprise 2014 through 2016 overpressure protection records for Moshannon, PA pump station. Enterprise was not able to provide any documentation of an inspection or test on each of the (2) overpressure protection valves for the 1st 2014 inspection, 1st 2015 inspection and 2nd 2015 inspection time intervals. The PHMSA inspector requested records and Enterprise stated, “Due to an issue with the work order system, the system failed to produce reports for the fall.” Enterprise provided, “Maintenance Work Order Detail Report” for the Moshannon, PA pump station overpressure protection valves; however, these records were dated March, 2016 and April, 2014, and therefore were not applicable to the time periods requested. Enterprise had no records which detailed the inspection and testing of the overpressure protection devices. Therefore, Enterprise failed to conduct an inspection and test of each overpressure protection valve at intervals not to exceed 7 ½ months but at least twice each calendar year, per the requirements of §195.428. 14. §195.428 Overpressure safety devices and overfill protection systems. (a) Except as provided in paragraph (b) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, or in the case 120185003_NOPV PCP PCO_01292018_text Page 14 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 15CPF 1-2018-5003 of pipelines used to carry highly volatile liquids, at intervals not to exceed 7½ months, but at least twice each calendar year, inspect and test each pressure limiting device, relief valve, pressure regulator, or other item of pressure control equipment to determine that it is functioning properly, is in good mechanical condition, and is adequate from the standpoint of capacity and reliability of operation for the service in which it is used. Enterprise failed to inspect and test each pressure limiting device, relief valve, pressure regulator, or other item of pressure control equipment at intervals not exceeding 15 months, but at least once each calendar year to determine that it is functioning properly, is in good mechanical condition, and is adequate from the standpoint of capacity and reliability of operation for the service in which it is used. Specifically, Enterprise failed in 11 instances to inspect and test pressure relief valves in 2015. During the inspection of inspection unit 12232-AR1 in Little Rock, Arkansas, the PHMSA inspector reviewed P77 pressure relief valve inspections for 2013 and 2014. Enterprise did not have records for P77 for 2015. In an email dated 1/10/2017 PHMSA requested pressure relief records for 2015. Enterprise stated, “There are no PSV records for the P77 pipeline for 2015…” and “Enterprise does not have PSV inspection records for the P77 pipeline for 2015…” Therefore, Enterprise failed to inspect and test each pressure relief valve in accordance with §195.428. 15. §195.404(c)(3) Maps and Records. (c) Each operator shall maintain the following records for the periods specified: … (3) A record of each inspection and test required by this subpart shall be maintained for at least 2 years or until the next inspection or test is performed, whichever is longer. Enterprise failed to maintain a record of each inspection and test for at least 2 years or until the next inspection or test is performed. Specifically, Enterprise failed to maintain its monthly breakout tank records per the requirements of API Standard 653 Section 6.3.1.2, incorporated by reference §195.3(b)(19). API Standard 653 Section 6.3.1 provides requirements for conducting Routine In-Service Inspections and Section 6.3.1.2 states that “The interval of such inspections shall be consistent with conditions at the particular site, but shall not exceed one month.” During the inspection of inspection unit 12232-AR1 in Little Rock, Arkansas, the PHMSA inspector reviewed breakout tank monthly inspection records for the years 2013 to 2016 for the McRae, Arkansas breakout tank facility. There were no monthly inspection records for DOT-T- 1301 for January, February, March and April 2014. In an email dated December 20, 2016, the PHMSA inspector asked Enterprise to provide the missing records. Enterprise responded in an email, dated January 3, 2017, stating “These records are missing.” 120185003_NOPV PCP PCO_01292018_text Page 15 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 16CPF 1-2018-5003 Enterprise failed to maintain documentation of monthly tank inspections for breakout tank DOT- T-1301 during March 2014, April 2014, and April 2015. Therefore, Enterprise failed to inspect its breakout tanks per the requirements of API Standard 653 Section 6.3.1.2, incorporated by reference §195.3(b)(19). 16. §195.432 Inspection of in-service breakout tanks. … (b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks according to API Std 653 (except section 6.4.3, Alternative Internal Inspection Interval) (incorporated by reference, see §195.3). However, if structural conditions prevent access to the tank bottom, its integrity may be assessed according to a plan included in the operations and maintenance manual under §195.402(c)(3). The risk-based internal inspection procedures in API Std 653, section 6.4.3 cannot be used to determine the internal inspection interval. Enterprise failed to inspect the physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks in accordance with API Standard 653, - Tank Inspection, Repair, Alteration, and Reconstruction, incorporated by reference in §195.3(b)(19). Specifically, Enterprise failed to inspect seven breakout tanks (BOTs) in accordance with API Standard 653. API Standard 653 Section 6.4.2 provides requirements for conducting Internal Inspections. Section 6.4.2.2, “When corrosion rates are not known and similar service experience is not available to estimate the bottom plate minimum thickness at the next inspection, the internal inspection interval shall not exceed 10 years.” During the inspection the PHMSA inspector reviewed Enterprise records and procedures for internal inspections of breakout tanks located at Texas, Illinois and Indiana facilities. Enterprise provided a spreadsheet titled PHMSA Break-Out Tank Data Form V3 which showed that seven tanks below were not internally inspected since the date of construction according to the table below: Tank Location Tank Number Date of Construction 1. Baytown, TX #DOT-T-643 1/1/2000 2. Beaumont, TX #752 1/1/2002 3. Beaumont, TX #757 1/1/2003 4. Creal Springs, IL #DOT-T-17213 1/1/2001 5. Creal Springs, IL #DOT-T-17261 1/1/2001 6. Creal Springs, IL #DOT-T-17262 1/1/2001 7. Indianapolis, IN #DOT-T-5106 10/12/2004 During the inspection, the PHMSA inspector asked for the internal inspection records for the seven specified breakout tanks. Enterprise stated, “there are no records for these breakout tanks as they are part of the final rule tanks.” Enterprise cited information from a prior PHMSA case, CPF #4- 2012-5008M. From CPF #4-2012-5008M Enterprise’s amended procedure, “STD. 9503 – Inspection and Testing of Atmospheric and Low-Pressure DOT Breakout Tanks, dated October 120185003_NOPV PCP PCO_01292018_text Page 16 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 17CPF 1-2018-5003 2014”, as part of the Final Order, Enterprise stated it is following in accordance with Section 8.4(7) - “NOTE: All existing tanks for which the Enterprise Risk Based Inspection Program (RBIP) had previously been used to determine inspection intervals will be assessed for conversion to time/condition based intervals.” In subsequent follow-up communication with Enterprise, Enterprise stated: “In reference to the tanks in question, at the time of their construction (2000 – 2004) they were incorporated into the Enterprise RBI program as described in API Standard 653, 3rd Edition, Section 6.4.3, which states, ‘As an alternative to the procedures in 6.4.2, an owner-operator may establish the internal inspection interval using risk-based inspection (RBI) procedures.’ Accordingly, Enterprise did not plan a 10-year interval (as referenced in API Standard 653, 3rd Edition, Section 6.4.2.2) for the initial internal inspection. As a result of the Final Order negotiated with PHMSA, Enterprise transitioned to the non-RBI approach described in API 653, 3rd Edition, Section 6.4.2 and the tanks were assigned the maximum initial interval (10 years) permitted by API 653, 3rd Edition, Section 6.4.2.2, for tanks with unknown corrosion rates and no similar service experience. In all cases, the new 10-year interval resulted in internal inspection due dates being past due. The tentative inspection schedule below represents the feasible operational availability of the tanks and will be adhered to as closely as possible…” The seven specified breakout tanks are neither included, nor related to the final order (Order Directing Amendment) referenced by Enterprise (CPF #4-2012-5008M). Enterprise failed to conduct the initial internal inspection on the seven breakout tanks within the required timeframe. The seven breakout tanks are out-of-compliance by a range of 2 – 7 years. Tank Number Date of Construction Time Out of Compliance #DOT-T-643 1/1/2000 >7 years #752 1/1/2002 >5 years #757 1/1/2003 >4 years #DOT-T-17213 1/1/2001 >6 years #DOT-T-17261 1/1/2001 >6 years #DOT-T-17262 1/1/2001 >6 years #DOT-T-5106 10/12/2004 >2 years Thus, Enterprise failed to inspect seven breakout tanks at the required intervals, per the requirements of API Standard 653, 3rd Edition, Section 6.4.2 17. §195.579 What must I do to mitigate internal corrosion? … (d) Breakout tanks. After October 2, 2000, when you install a tank bottom lining in an aboveground breakout tank built to API Spec 12F (incorporated by reference, see §195.3), API Std 620 (incorporated by reference, see §195.3), API Std 650 (incorporated by reference, see §195.3), or API Std 650's predecessor, Standard 12C, you must install the lining in accordance with API RP 652 (incorporated by reference, see §195.3). However, you don't need to comply with API RP 652 when installing any 120185003_NOPV PCP PCO_01292018_text Page 17 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 18CPF 1-2018-5003 tank for which you note in the corrosion control procedures established under §195.402(c)(3) why compliance with all or certain provisions of API RP 652 is not necessary for the safety of the tank. Enterprise failed to demonstrate that its breakout tank linings were installed, per the requirement §195.579(d). Enterprise did not maintain records and documentation that showed compliance with the requirement. During the inspection of inspection unit 12232-AR1, in Little Rock, Arkansas, the PHMSA inspector requested records for breakout tank lining installations for all applicable McRae and North Little Rock, Arkansas breakout tanks. Enterprise provided, PHMSA breakout tank data form, received 05/21/16. The record showed the following breakout tanks with a thin-film lining: 1. DOT-T-1301 2. DOT-T-1302 The regulation §195.579(d) states, “when you install a tank bottom lining in an aboveground breakout tank built to API Spec 12F, API Std 620, API Std 650, or API Std 650's predecessor, Standard 12C, you must install the lining in accordance with API RP 652.” Enterprise provided, “McRae Tank 1302 INT Lining” record, dated 2006. Additionally, Enterprise provided, “Tank 1301 API-653 Post Job Inspection Report”, dated 6/25/07 and “Tank 1301 Recommended Repair Checklist”, dated 6/14/06. These records however, failed to provide any documentation that the installation was performed in accordance with API RP 652. In an email dated 10/21/16, Enterprise stated, “There is no additional documentation related to determining the suitability of the breakout tank lining installation for breakout tank 1301 (IU 12232 McRae facility).” Therefore, Enterprise failed to provide adequate records to demonstrate that the tank linings on breakout tanks DOT-T-1301 and DOT-T-1302 were installed, per the requirement of §195.579(d). 18. §195.402 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Enterprise failed to prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. Specifically, Enterprise failed to provide adequate guidance to inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion as per §195.583(a) and provide records of each atmospheric corrosion inspection in sufficient detail to demonstrate the adequacy of corrosion control measures as per §195.589(c). During the inspection, the PHMSA inspector reviewed procedures that addressed atmospheric corrosion inspections (Enterprise’s Atmospheric Corrosion Inspection Procedure CPP-PCL-01, Revision date 12/3/15). The procedure stated in part that: 120185003_NOPV PCP PCO_01292018_text Page 18 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 19CPF 1-2018-5003 1. “1.1 The purpose of this procedure is to establish a standardized method for monitoring, inspecting, and reporting atmospheric corrosion of aboveground facilities.” The term “aboveground facilities” is broad. Particularly, it is unclear if this references to pipelines, equipment, and/or breakout tanks. 2. “3.2.1 All atmospheric corrosion inspections must be conducted by or under the guidance of the Corrosion Prevention Group. Atmospheric corrosion inspections shall be conducted at time intervals in accordance with DOT 49 CFR, Part 195.583 as found in Subpart H – Corrosion Control and DOT 49 CFR, Part 192.481 as found in Subpart I – Requirements for Corrosion Control. These frequencies are states as follows: ‘At least once every 3 calendar years, but with intervals not exceeding 39 months’ for assets located onshore and ‘At least once every calendar year, but with intervals not exceeding 15 months’ for assets located offshore.” The term “assets” is broad. It is unclear if this references pipelines, equipment, and/or breakout tanks. Particularly, §195.583 references pipe, breakout tanks refer to a different code section that may calculate to different inspection interval frequencies. 3. “3.3.1 Inspection locations must be carefully chosen in an effort to provide for a thorough assessment that is most representative of the entire piping system. Identify all above ground or above waterline structures/facilities that are subject for atmospheric corrosion inspection and maintain a listing of these subject areas as a checklist in the appropriate form or a Company database. For extensive inspections, it may be necessary to record inspection locations on existing piping diagrams. 3.3.2 Where to conduct atmospheric corrosion inspections: … 3.3.2.4 Storage Vessels and Tankage” The term “most representative of the entire piping system” is broad. It is unclear if the most representative area considers the condition of a smaller portion. The smaller portion that is not representative, may have a different condition that is overlooked. Additionally, §195.583 requires the inspection of each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion. 4. “3.3.3 During atmospheric corrosion inspections, particular attention must be given to the following locations: 3.3.3.1 Pipe and Associated Structures at Soil to Air Interfaces … 3.3.3.6 At Deck/Wall Penetrations” It is unclear if the most representative area is to considers these locations or if the locations are to be identified separately. 5. “3.3.4 Atmospheric corrosion inspections are to be conducted by visually examining 360° of the external surfaces of the pipeline and/or associated assets and determining: (1) the condition of coating system and, (2) the condition of the metal substrate if coating damage is found.” 120185003_NOPV PCP PCO_01292018_text Page 19 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 20CPF 1-2018-5003 It is unclear how 360° examinations is to be performed in instances that portion is covered with soil. 6. “3.3.8 The results of this defect evaluation, along with degree of rusting shall be documented in the following format: 3.3.8.1 Record the rust grade in the fields in the table below. (See the matrix in 3.4.2 for the rust grade selections) Note: This grade represents the condition of the coating only. … 3.3.8.3 Record the Metal Substrate Grade in the fields in the table below. … It is unclear if the most representative area is to considers these locations or if the locations are to be identified separately. Rust is an iron oxide formed by the redox reaction of iron and oxygen. Therefore, it is unclear how percent of surface rusted is a representation of the coating condition. 7. “3.4.2 Upon establishing the “rust grade”, refer to the “Scale and Description of Rust Grades Matrix” below to identify the recommended corrective action.” 120185003_NOPV PCP PCO_01292018_text Page 20 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 21CPF 1-2018-5003 The size of the most representative area is undefined, therefore the percent of surface rusted is variable. It is unclear, if a smaller area with a different condition becomes overlooked. The “Scale and Description of Rust Grades Matrix” identifies Rust Grade 0 as percent of surface rusted greater than 50 percent. In the Legend of Atmospheric Corrosion Repair, no recommendation is provided for rust grade 0. During the field inspection at Enterprise’s Seymour breakout tank Terminal in Indiana, a PHMSA inspector observed aboveground jurisdictional pipeline segments that were exposed to the atmosphere. The PHMSA inspector requested the atmospheric corrosion inspection records for these jurisdictional pipeline segments that were exposed to the atmosphere. Enterprise provided records relating to atmospheric corrosion inspections conducted at breakout tank 3013 and breakout tank 3014 on 4/27/2016 and 2/15/2013 respectively. The 2013 and 2016 records for breakout tank 3013 depict 11 observed locations: Locations 1-8: Tank 3013 N, NE, E, SE, S, SW, W, NW Location 9: Riser @ Tank 2013 Interface Area Location 10: Riser @ Tank 3013 Location 11: Pump for Tank 3013 120185003_NOPV PCP PCO_01292018_text Page 21 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 22CPF 1-2018-5003 The 2013 record for breakout tank 3014 depicts six observed locations: Locations 1-4: Tank 3013 N, E, S, W Location 5: Riser @ Tank 3014 Interface Area Location 6: Riser @ Tank 3014 The 2016 record for Tank 3014 depict nine observed locations: Locations 1-8: Tank 3013 N, NE, E, SE, S, SW, W, NW Location 9: Riser @ Tank 3014 The 2013 record for breakout tank 3014 did not document NE, SE, SW, nor NW locations. The 2016 record for breakout tank 3014 did not document Riser @ Tank 3014 Interface Area location. The records did not describe the overall area a location represented, nor was a pipeline diagram provided. The PHMSA inspector requested clarification and additional documentation that an atmospheric inspection of the following locations of exposed pipe was performed: 1. 2. 3. 4. two blind pipe flanged segments connected to breakout tank 3013 the drain valve located inside a valve box and connected to breakout tank 3013 the drain valve located inside a valve box and connected to breakout tank 3014 the riser at tank 3014 interface Enterprise again provided the same 2013 and 2016 atmospheric corrosion inspection records and replied in email correspondence dated January 11, 2017, “The atmospheric inspections for tanks include associated piping, they are not done separately”. The 2013 and 2016 records for breakout tank 3013 and 3014 had columns labeled:  General Coating Condition  General Corrosion  Soil to Air Coating Condition  Soil to Air Corrosion Per Enterprise’s procedure Atmospheric Coating Rust Grade Fields table in Section 3.3.8.1, the inspection is to “Record the rust grade in the fields in the table below”. The following fields were not indicated on the 2013 and 2016 records for breakout tanks 3013 and 3014:  Pipe Support Coating Condition  Span Over Water Coating Condition  Deck Wall Penetration Coating Condition  Pipe Under Thermal Insulation Coating Condition  Splash Zone Coating Condition Per Enterprise’s procedure Atmospheric Coating Rust Grade Fields table in Section 3.3.8.3, the inspection is to “Record the Metal Substrate Grade in the fields in the table below”. The following fields were not indicated on the 2013 and 2016 records for breakout tanks 3013 and 3014:  Pipe Support Corrosion  Span Over Water Corrosion  Deck Wall Penetration Corrosion  Pipe Under Thermal Insulation Corrosion 120185003_NOPV PCP PCO_01292018_text Page 22 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 23CPF 1-2018-5003  Splash Zone Corrosion  Pipe Under Disbonded Coating Corrosion The PHMSA inspector witnessed blind pipe flanged segments and drain valves on breakout tanks 3013 and 3014 that had a soil to air interface and wall penetration. Neither the 2013 nor 2016 records documented a result for fields Wall Penetration Coating Condition and Wall Penetration Corrosion, and the 2016 record for breakout tank 3013 did not document a result for Soil to Air Coating Condition and Soil to Air Corrosion. After the inspection, Enterprise provided remedial action taken based on their atmospheric inspection conducted on 4/27/2016 (email correspondence dated December 19, 2016). The three pipe segments connected to breakout tank 3013 were also coated during the remedial action. Enterprise did not provide information that addressed atmospheric corrosion of the two pipe segments connected to breakout tank 3014. Therefore, Enterprise failed to prepare and follow a manual of written procedures for conducting normal operations and maintenance activities, specifically pipeline segments that were exposed to the atmosphere. Proposed Civil Penalty Under 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil penalty not to exceed $209,002 per violation per day the violation persists up to a maximum of $2,090,022 for a related series of violations. For violations occurring prior to November 2, 2015, the maximum penalty may not exceed $200,000 per violation per day, with a maximum penalty not to exceed $2,000,000 for a related series of violations. The Compliance Officer has reviewed the circumstances and supporting documentation involved in the above probable violations and has recommended that you be preliminarily assessed a civil penalty of $ 703,900 as follows: 120185003_NOPV PCP PCO_01292018_text Page 23 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 24CPF 1-2018-5003 Item number PENALTY $ 27,500 $ 53,600 $ 72,000 $ 27,300 $ 8,800 $ 72,500 ∞ a $ 33,100 $ 27,300 10 $ 12,900 $ 60,400 $ 55,800 $ 55,800 $ 61,200 $ 27,500 16 $ 56,800 17 $ 51,400 Proposed Compliance Order With respect to item 3, item 7, 16 and item 18, pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Enterprise Products Operating, LLC. 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 submit in response to this enforcement action may be made publicly available. If you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order. Please submit all correspondence in this matter to Robert Burrough, Director, PHMSA Eastern Region, 820 Bear Tavern Road, Suite 103, West Trenton, New Jersey 08628. Please refer to CPF 1-2018-5003 on each document you submit, and whenever possible provide a signed PDF copy in electronic format. Smaller files may be emailed to robert.burrough@dot.gov. Larger files should be sent on a CD accompanied by the original paper copy to the Eastern Region Office. 120185003_NOPV PCP PCO_01292018_text Page 24 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 25CPF 1-2018-5003 Additionally, if you choose to respond to this (or any other case), please ensure that any response letter pertains solely to one CPF case number. Sincerely, Robert Burrough Director, Eastern Region Pipeline and Hazardous Materials Safety Administration Enclosure: Response Options for Pipeline Operators in Compliance Proceedings 120185003_NOPV PCP PCO_01292018_text Page 25 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 26CPF 1-2018-5003 PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Enterprise Products Operating, LLC (Enterprise) a Compliance Order incorporating the following remedial requirements to ensure the compliance of Ergon with the pipeline safety regulations: 1. In regard to Item 3 of the Notice pertaining to Enterprise’s failure to follow its manual of written procedures for its leak detection measures, per §195.402(a): a. Enterprise shall amend its procedures to specify actions required during the annual leak detection analysis and specifying how the analysis must be documented. The procedures shall be provided to PHMSA for review and acceptance within 60 days of issuance of the final order. b. Enterprise shall apply the revised procedures and perform its leak detection evaluations on the above mentioned seven inspection units (IU 3051 – Greensburg (Greensburg, Pennsylvania office, IU 3071 – Dubois (Watkins Glen, New York office), IU 4213 – Allegheny (Lebanon, Ohio office), IU 3061 – Eagle (Morgantown, Pennsylvania Office), IU 2464 – Lou Tex (Sorrento, Louisiana Office), IU 18043 – TEPPCO Chicago (Monee, Illinois Office), IU 12232 – AR1 (Little Rock, Arkansas Office) within 120 days of issuance of the final order. 2. In regard to Item 7 of the Notice pertaining to Enterprise’s procedures failing to provide sufficient guidance on how to conduct and document relief valve inspections as per §195.428(a): a. Enterprise shall amend its procedures to include sufficient guidance per §195.428(a) within 60 days of the Final Order. 3. In regard to Item 16 of the Notice pertaining to Enterprise’s failure to inspect seven breakout tanks at the required intervals, per the requirements of API Standard 653, 3rd Edition, Section 6.4.2: a. Enterprise shall inspect seven breakout tanks per API Standard 653 within 365 days of Final Order. 4. In regard to Item 18 of the Notice pertaining to Enterprise’s failure to provide adequate guidance to inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion as per §195.583(a): a. Enterprise shall prepare a written procedure addressing the apparent inadequacies found within Atmospheric Corrosion Inspection Procedure CPP-PCL-01 within 60 days after receipt of the Final Order and then submit those procedures to PHMSA for review and eventual approval by PHMSA. b. After PHMSA approves the procedures, Enterprise must then apply those approved procedures to conduct inspections and address atmospheric corrosion along PHMSA Unit ID #2703. Enterprise must make records available, as required by the 120185003_NOPV PCP PCO_01292018_text Page 26 of 27#

120185003_NOPV PCP PCO_01292018_text.pdf, page 27CPF 1-2018-5003 amended procedures, for PHMSA review. This must be accomplished within 180 days after the procedures are approved by PHMSA. 5. Enterprise Products Operating, LLC. must complete the requirements as outlined above. All documentation demonstrating compliance with each of the items outlined in this proposed compliance order must be submitted for review to Robert Burrough, Director, PHMSA Eastern Region, 820 Bear Tavern Road, Suite 103, West Trenton, NJ 08628. Smaller files may be emailed to robert.burrough@dot.gov. Larger files should be sent on a CD accompanied by the original paper copy to the Eastern Region Office. 6. It is requested (not mandated) that Enterprise maintains documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to Robert Burrough, Director, Eastern 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. 120185003_NOPV PCP PCO_01292018_text Page 27 of 27#