EXXONMOBIL PIPELINE CO — Notice of Probable Violation

party submissionOfficial PDF420115016_Operator Response to NOPV PCP PCO_12152011.pdf#

party submissionOfficial PDF420115016_Petition_for_Reconsideration_07222013.pdf#

420115016_Final Order_06272013_text.pdf, page 1Official PDFJUNE 27, 2013 Mr. Gary Pruessing President ExxonMobil Pipeline Company 800 Bell St., Room 741-D Houston, TX 77002 Re: CPF No. 4-2011-5016 Dear Mr. Pruessing: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation, assesses a reduced civil penalty of $112,300, withdraws several alleged violations, and specifies actions that need to be taken by ExxonMobil Pipeline Company to comply with the pipeline safety regulations. The penalty payment terms are set forth in the Final Order. When the civil penalty has been paid and the terms of the compliance order completed, as determined by the Director, Southwest Region, this enforcement action will be closed. Service of the Final Order is made pursuant to 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Jeffrey D. Wiese Associate Administrator for Pipeline Safety Enclosure cc: Mr. R.M. Seeley, Director, Southwest Region, OPS Mr. Alan Mayberry, Deputy Associate Administrator for Field Operations, OPS Ms. Catherine Little, Hunton & Williams LLP, Bank of America Plaza, Suite 4100 600 Peachtree Street, N.E., Atlanta, GA 30308 CERTIFIED MAIL – RETURN RECEIPT REQUESTED#

420115016_Final Order_06272013_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 ) ExxonMobil Pipeline Company, ) CPF No. 4-2011-5016 ) ) ) Respondent. ) ___________________________________ ) FINAL ORDER On March 31-April 1, 2011, pursuant to 49 U.S.C. § 60117, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the records and procedures of ExxonMobil Pipeline Company (EMPCo or Respondent) in Houston, Texas. EMPCo, a subsidiary of Exxon Mobil Corporation, operates approximately 4,000 miles of pipeline transporting crude oil, refined petroleum products, and highly volatile liquids in Texas, Louisiana, and Montana.1 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice) to Respondent on November 7, 2011. In accordance with 49 C.F.R. § 190.207, the Notice alleged that Respondent committed violations of the pipeline safety regulations in 49 C.F.R. Part 195 and proposed a total civil penalty of $151,100 for the alleged violations. The Notice also proposed corrective action to be completed. EMPCo responded to the Notice by letter dated December 15, 2011 (Response). In its Response, Respondent contested the alleged violations and requested a hearing. Respondent provided additional written explanations by letter dated April 16, 2012. A hearing was held in accordance with 49 C.F.R. § 190.211 on April 25, 2012, in Houston, Texas, before the Presiding Official from the Office of Chief Counsel, PHMSA. After the hearing, Respondent submitted additional written material by letters dated June 29 and August 30, 2012. FINDINGS OF VIOLATION The Notice alleged that Respondent violated 49 C.F.R. Part 195, as follows: 1 Pipeline system information for calendar year 2011 was reported by EMPCo pursuant to 49 C.F.R. § 195.49.#

420115016_Final Order_06272013_text.pdf, page 32 Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.302, which states, in relevant part: § 195.302 General requirements. (a) [N]o operator may operate a pipeline unless it has been pressure tested under this subpart without leakage . . . . (c) Except for pipelines . . . covered under § 195.303, the following compliance deadlines apply to pipelines . . . that have not been pressure tested under this subpart . . . (2) For pipelines scheduled for testing, each operator shall— (i) Before December 7, 2000, pressure test— (A) Each pipeline identified by name, symbol, or otherwise that existing records show contains more than 50 percent by mileage (length) of electric resistance welded pipe manufactured before 1970; and (B) At least 50 percent of the mileage (length) of all other pipelines; and (ii) Before December 7, 2003, pressure test the remainder of the pipeline mileage (length). The Notice alleged that Respondent violated § 195.302 by operating 27 pipeline segments that had not been pressure tested by the deadlines set forth in the regulation. OPS included in the record evidence of a spreadsheet prepared by Respondent titled, “Systems Lacking DOT Hydrotest Documentation” (Spreadsheet), which listed 27 pipeline segments totaling 615.7 miles. 2 In its written submissions prior to the hearing, Respondent explained that the Spreadsheet had been prepared in 1998 as part of its effort to comply with the deadline in 49 C.F.R. § 195.302. Respondent produced information regarding the current status of the 27 pipeline segments. Respondent contended that: (a) twelve were pressure tested; (b) five were purged of product and idled; (c) two were sold; (d) five were exempt from § 195.302 because they were covered under § 195.303; and (e) three were exempt from Part 195 altogether. 3 At the hearing, Respondent discussed in more detail the eight segments that it claimed were exempt. Respondent provided a post hearing submission with additional records regarding all 27 segments. Applicable safety standards Beginning in 1971, each newly constructed pipeline transporting hazardous liquids was required to undergo a pressure test in accordance with 49 C.F.R. Part 195, Subpart E. In 1994, the pressure testing requirements were extended to all hazardous liquid pipelines, including those constructed before 1971. Deadlines for testing older pipelines were established in § 195.302(c)(2). In 1998, § 195.303 was adopted to allow operators of older pipelines to elect an alternative testing and inspection program to evaluate the integrity of the lines based on individual risk factors. 2 OPS Pipeline Safety Violation Report, Exhibit 1-2 (Nov. 7, 2011) (Violation Report). 3 EMPCo letter dated April 16, 2012, p.2 (Pre-hearing Submittal).#

420115016_Final Order_06272013_text.pdf, page 43 Certain record keeping requirements were established to ensure that any pressure test or alternative program complied with the applicable requirements. Operators were required to make and retain for each pressure test documentation including, among other things: pressure recording charts; test instrument calibration data; date and time of the test; minimum test pressure; a description of the facility tested; and temperature of the test medium or pipe during the test period.4 If an operator elected to follow a risk-based alternative to pressure testing, § 195.303 required the operator to maintain records verifying the risk classifications, the plans and schedule for testing, the conduct of the testing, and ongoing review of risk classifications. Findings The following findings are made with regard to each of the 27 pipeline segments at issue. The segments are categorized by their alleged disposition according to Respondent. Next to each segment name is a number that corresponds to the order in which the segment was listed on the 1998 Spreadsheet. a. Segments that Respondent Claimed Were Pressure Tested PCU to Mt. Belvieu Poly Propylene (Segment 2) Respondent contended that the PCU to Mt. Belvieu Poly Propylene pipeline segment was pressure tested in 1981, 2004, and 2009, and therefore the segment was in compliance with § 195.302 at the time of the OPS inspection. Respondent submitted a diagram of the Baytown PCU Polymer Grade Propylene System and records from pressure tests that took place in 1980 on the system. 5 Hand-drawn diagrams attached to the test records depicted about 750 feet of tested pipe. Respondent did not submit any test records from 2004 or 2009. The 1998 Spreadsheet indicated the PCU to Mt. Belvieu Poly Propylene segment that did not have adequate pressure test documentation was 0.27 miles or approximately 1,427 feet in length. The evidence fails to demonstrate the entire 0.27-mile segment was pressure tested according to § 195.302. For this reason, I find the segment was not in compliance. St. James to Junction (Segment 4) Respondent contended that the St. James to Junction pipeline segment was pressure tested in 1968 and therefore the segment was in compliance with § 195.302 at the time of the OPS inspection. To support this contention, Respondent submitted a single page Pipeline Qualification Record dated 1968.6 4 § 195.310. 5 EMPCo letter dated June 29, 2012, Exhibits 9 and 10 (Post-hearing Submission). 6 Post-hearing Submission, Exhibit 18.#

420115016_Final Order_06272013_text.pdf, page 54 The record submitted by Respondent is not sufficient to demonstrate a pressure test was conducted in accordance with Subpart E because the record lacked necessary information such as a pressure recording chart. Without adequate documentation of a pressure test, I find this segment was not in compliance. Webster to Baytown #3 and #6-8 inch (Segment 11) Respondent contended that the Webster to Baytown #3 and #6-8 inch pipeline segment was pressure tested in 2000 and therefore was in compliance with § 195.302 at the time of the OPS inspection. Respondent also noted that this segment was idled after the OPS inspection. Respondent submitted records from a pressure test that occurred in 2000.7 These records are not sufficient to demonstrate a pressure test was conducted in accordance with Subpart E because the records did not include any pressure recording charts. In addition, the records did not reference the entire 1.08-mile Webster to Baytown #3 and #6-8 inch pipeline segment listed in the Spreadsheet. For these reasons, I find the segment was not in compliance. BOP to ITC Butadiene (Segment 12) Respondent contended that due to a naming discrepancy, this pipeline segment was either the BOP to ITC Crude Butadiene system, which was pressure tested in 1979 and 2003, or it was the BOP to ITC Product Butadiene system, which was pressure tested in 1981. Since both were pressure tested, Respondent contended the segment was in compliance with § 195.302 at the time of the OPS inspection. Respondent submitted records from a pressure test that took place in 1979 on the “Chocolate Bayou—BOP Cr[ude] Butadiene Sys[tem] (ITC Lateral).”8 Respondent also submitted records from a test that took place in 1980 on what appears to be a different pipeline, but not the product line referenced above. The segment tested in 1980 was the “Chocolate Bayou to Baytown Crude Butadiene.”9 Respondent did not submit any test records that could be identified for the BOP to ITC Product Butadiene system or any records from a pressure test in 2003. The records submitted by Respondent are not sufficient to demonstrate that the pipeline segment referenced on the Spreadsheet was pressure tested in accordance with § 195.302 because the records submitted did not include any pressure recording charts. Accordingly, I find this segment was not in compliance. 7 Post-hearing Submission, Exhibit 46. 8 Post-hearing Submission, Exhibit 53. Respondent submitted these records in duplicate for the Chocolate Bayou - BOP Crude Butadiene (Segment 24, see below), but did not explain why identical records were submitted for different pipeline segments. 9 Post-hearing Submission, Exhibit 54.#

420115016_Final Order_06272013_text.pdf, page 65 Boyce to Bunkie (Segment 14) Respondent contended that the Boyce to Bunkie pipeline segment was pressure tested in 2000 or 2001 and therefore was in compliance with § 195.302 at the time of the OPS inspection. Respondent also noted that the segment was renamed Melville to Boyce after a reversal in 2001. Respondent submitted records from two pressure tests that took place in 2001—one from Boyce to Chandler, which covered approximately 21 miles, and one from Chandler to Bunkie, which covered slightly less than 21 miles, for a total of about 42 miles.10 The evidence submitted by Respondent does not demonstrate the entire 46.3-mile segment listed in the Spreadsheet was pressure tested in accordance with Subpart E. Furthermore, the records were insufficient because they did not include any pressure recording charts. Accordingly, I find this segment was not in compliance. Bunkie to Anchorage (Segment 15) Respondent contended that the Bunkie to Anchorage pipeline segment was pressure tested in 2000 or 2001 and therefore the segment was in compliance at the time of the OPS inspection. Respondent noted this segment was renamed Anchorage to Melville and Melville to Boyce after a 2001 reversal. Respondent submitted records from two pressure tests that took place in 2001—one from Bunkie to Hwy 361, which covered approximately 12.31 miles, and one from Hwy 361 to AR Melville West, which covered approximately 19.48 miles, for a total of about 32 miles.11 The evidence submitted by Respondent does not demonstrate the entire 51.41-mile segment listed in the Spreadsheet was pressure tested. Furthermore, the records were insufficient because they did not include any pressure recording charts. Accordingly, I find this segment was not in compliance. Finney to Boyce (Segment 16) Respondent contended that the Finney to Boyce pipeline segment was pressure tested in 2000 or 2001 and therefore the segment was in compliance at the time of the OPS inspection. Respondent also noted the segment was renamed Boyce to Finney after the 2001 reversal. Respondent submitted records of pressure tests that took place in 2001.12 The records were insufficient because they did not include any pressure recording charts. Accordingly, I find this segment was not in compliance. 10 Post-hearing Submission, Exhibits 58 and 59. 11 Post-hearing Submission, Exhibits 62 and 63. Another record, Exhibit 64, appeared to concern a test on a different pipeline segment. 12 Post-hearing Submission, Exhibit 68.#

420115016_Final Order_06272013_text.pdf, page 76 Strang Road to Texas City (Segment 21) Respondent contended that the Strang Road to Texas City pipeline segment was pressure tested in 1997 and therefore the segment was in compliance at the time of the OPS inspection. Respondent also noted that this segment is now part of the Fairmont Junction to Texas City Propylene System. Respondent submitted records from a pressure test that took place in 1997 at “various locations” on the “Bayport Jct. to Texas City section.”13 An attachment to the test record indicated the test began at station 444+27 (valve 3506) and ended at station 1058+33 (valve 3524).14 Respondent also submitted several pipeline diagrams. 15 The station and valve identification numbers from the test record did not appear to correlate to any one diagram in a manner that clearly demonstrated the 2.86-mile Strang Road to Texas City segment referenced in the Spreadsheet had been pressure tested. In addition, the pressure test records were insufficient because they did not include any pressure recording charts. Accordingly, I find this segment was not in compliance. Texas Olefins Multi-Products Crossover (Segment 22) Respondent contended that the Texas Olefins Multi-Products Crossover pipeline segment was pressure tested in 1982 and therefore the segment was in compliance at the time of the OPS inspection. Respondent submitted records from a pressure test that took place in 1982 on the “BOP - Texas Olefins Spare Liquid Hydrocarbon Line.”16 Respondent submitted a duplicate of this record for the BOP to Texas Olefins Raffinate segment (Segment 23, see below). The station identification numbers from the 1982 test record did not appear to correlate to the diagram Respondent submitted for this segment. In addition, the records were insufficient because they did not include any pressure recording charts. Accordingly, I find this segment was not in compliance. Chocolate Bayou BOP Crude Butadiene (Segment 24) Respondent noted that due to a naming discrepancy, this pipeline segment is now part of the Chocolate Bayou - BPU Butylene System. Respondent contended that it was pressure tested in 1981 and therefore was in compliance at the time of the OPS inspection. Respondent submitted records from a pressure test that took place in 1979 on the “Chocolate Bayou-BOP Cr. Butadiene Sys (ITC Lateral).” This same record was submitted by Respondent 13 Post-hearing Submission, Exhibit 85. 14 Post-hearing Submission, Exhibit 86. 15 Post-hearing Submission, Exhibit 84. 16 Post-hearing Submission, Exhibit 90.#

420115016_Final Order_06272013_text.pdf, page 87 for the BOP to ITC Butadiene segment (Segment 12, see above). Several of the diagrams submitted for this segment were also duplicates. As I have already determined for these records in regard to the BOP to ITC Butadiene segment, the records were insufficient to demonstrate a pressure test had been conducted in accordance with Subpart E because they did not include any pressure recording charts. For these reasons, I find this segment was not in compliance. Clovelly to Raceland 16-inch Import (Segment 25) Respondent contended that this pipeline segment was pressure tested in 1966 and therefore the segment was in compliance at the time of the OPS inspection. Respondent submitted records from a pressure test that took place in 1966, which were attached to a report prepared in 1996. According to the report, the test “was performed on the 6.21 mile, #2-16[inch] pipeline segment from Clovelly Junction to LaRose Junction (Import System).”17 The evidence submitted by Respondent does not demonstrate the entire 16.79-mile segment listed in the Spreadsheet was pressure tested. For this reason, I find the segment was not in compliance. Viola to Hess Refinery #2 - 6 inch Line (Segment 27) Respondent contended that this pipeline segment was pressure tested in 1999 and 2011 and therefore it was in compliance at the time of the OPS inspection. Respondent submitted records from pressure tests that took place in 1999 on the “Corpus Christi to King Ranch Gas Plant Propane System-Coastal States to Viola 6[-inch]” and the “King Ranch to Coastal States Propane System Viola to Coastal States 6[-inch].”18 The records submitted were insufficient to demonstrate the pressure tests were conducted in accordance with Subpart E because they did not include any pressure recording charts. Respondent did not submit any records from a pressure test performed on this segment in 2011. Accordingly, I find this segment was not in compliance. b. Segments that Respondent Claimed Were Idled Prior to the Inspection19 Avery Island to Lydia (Segment 6) Respondent contended that the Avery Island to Lydia pipeline segment was idled in 2011, prior to the OPS inspection, and has since been abandoned. Respondent further contended that the 17 Post-hearing Submission, Exhibit 99. 18 Post-hearing Submission, Exhibit 104. 19 Respondent contended in its Pre-hearing Submittal that five segments were in compliance because they had been purged of product and idled; however, the evidence produced suggested Respondent intended to make this claim for four segments.#

420115016_Final Order_06272013_text.pdf, page 98 segment was pressure tested in 2000 and 2005. The pipeline safety regulations do not explicitly recognize a pipeline as “idled,” although the term is commonly used to refer to pipelines in which operations have been temporarily suspended.20 Respondent stated that it uses the term to mean “deactivated and filled with nitrogen.”21 The status of any one of the 27 pipeline segments as inactive or idled at the time of the OPS inspection does not by itself excuse noncompliance if Respondent had operated the pipeline without a pressure test in violation of § 195.302. Respondent submitted a report from a pressure test that took place in 2000 on the Avery Island pipeline.22 The test covered 49,210 feet of 6-inch pipe. Respondent also submitted some forms from a pressure test that was performed in 2005, although those records were incomplete. The Avery Island to Lydia segment listed on the Spreadsheet was 8.16 miles, or approximately 43,085 feet in length. That is approximately 6,000 feet less than the amount that was tested in 2000. The reason for the discrepancy in mileage was not apparent, but the additional mileage tested could have been part of the system depicted in a diagram Respondent produced showing 9.06 miles (47,837 feet) of 6-inch pipe, plus an additional 1.7 miles (8,976 feet) of mixed 6- and 4-inch pipe.23 Based on this evidence, I find the segment was pressure tested and Respondent has maintained the necessary documentation. Accordingly, this alleged violation is withdrawn. Weeks Island to Olivier (Segment 10) Respondent contended that the Weeks Island to Olivier pipeline segment was idled in 2010 and remains idled at this time. Respondent further contended that the segment was pressure tested in 2000 and 2005. Respondent submitted pressure test records from 2000 and 2005.24 The records submitted by Respondent were not sufficient to demonstrate the pipeline segment had been pressure tested in accordance with Subpart E because no pressure recording charts were included. Without adequate pressure test documentation, I find the pipeline was operated out of compliance with § 195.302. The status of the segment as idled at the time of the OPS inspection does not excuse noncompliance. BOP to Petrotex Mixed Butylene (Segment 19) Respondent contended that the BOP to Petrotex Mixed Butylene pipeline segment was idled at some point prior to the OPS inspection and remains idled at this time. Respondent further 20 Abandoned pipelines, by comparison, are recognized in the regulations as ones that have been permanently removed from service by safely disconnecting the line from the operating pipeline system, purging of combustibles, and sealing to minimize safety and environmental hazards if left in place. 21 Post-hearing Submission, Exhibit 6, p 2. 22 Post-hearing Submission, Exhibit 28. 23 Post-hearing Submission, Exhibit 27. 24 Post-hearing Submission, Exhibit 46.#

420115016_Final Order_06272013_text.pdf, page 109 contended that the segment was pressure tested in 1982. Respondent noted that the segment has been renamed BOP to TOP Junction. The records submitted by Respondent were from a pressure test in 1982 and appear to contain all of the information required by § 195.310, including pressure recording charts and test instrument calibration data. Based on this evidence, I find Respondent has demonstrated the segment was pressure tested. This alleged violation is withdrawn. BOP to Texas Olefins Raffinate (Segment 23) Respondent contended that the BOP to Texas Olefins Raffinate pipeline segment was idled in 2003 and remains idled at this time. Respondent further contended that the segment was pressure tested in 1982. Respondent submitted test records from 1982 for the “BOP - Texas Olefins Spare Liquid Hydrocarbon Line.”25 Some of the same records were also provided for the Texas Olefins Multi- Products Crossover (Segment 22, see above).26 The test record station identification numbers appear to correlate with the diagram of this pipeline segment and appear to contain all of the information required by § 195.310, including pressure recording charts and test instrument calibration data. Based on the evidence, I find Respondent has demonstrated the pipeline segment was pressure tested. This alleged violation is withdrawn. c. Segments that Respondent Claimed Were Sold Means to Ector (Segment 1) Respondent contended that the Means to Ector pipeline segment was sold in 2004. Respondent also stated that prior to the sale, the segment did not have to comply with the pressure testing requirement in § 195.302 because the segment had been “derated,” meaning the maximum operating pressure (MOP) was established under § 195.406(a)(5) based on 80 percent of the highest operating pressure to which the pipeline was subjected (see § 195.302(b)(1)). Respondent submitted a Bill of Sale showing this segment was sold in 2004.27 Based on this evidence, I find Respondent did not operate this pipeline during the time period relevant to this case, which is five years prior to issuance of the Notice. This alleged violation is withdrawn. Bullard to Gate Plant “C” (Segment 13) Respondent contended that the Bullard to Gate Plant “C” pipeline segment was sold in 2000. Respondent also stated that prior to the sale the segment did not have to comply with the 25 Post-hearing Submission, Exhibit 93. 26 Post-hearing Submission, Exhibit 90. 27 Post-hearing Submission, Exhibit 8.#

420115016_Final Order_06272013_text.pdf, page 1110 pressure testing requirement in § 195.302 because Respondent had elected the risk-based alternative to pressure testing under § 195.303 (see § 195.302(b)(4)). Respondent submitted a Purchase and Sale Agreement showing the segment was sold in 2000.28 Based on this evidence, I find Respondent did not operate this pipeline during the time period relevant to this case. This alleged violation is withdrawn. d. Segments that Respondent Claimed Were Exempt from § 195.302 Under a Risk-Based Alternative Program29 Pierce Junction to Luling (Segment 3) Respondent contended that the Pierce Junction to Luling pipeline segment did not have to comply with the pressure testing requirement in § 195.302 because Respondent had elected a risk-based alternative to pressure testing covered under § 195.303 (see § 195.302(b)(4)). In addition, Respondent contended that the segment was pressure tested in 1961, 1969, and 1992. As noted above, § 195.303 permitted operators to elect a risk-based program for older pipelines as an alternative to the pressure test deadlines set forth in § 195.302(c)(2). An operator electing this approach in 1998 was required to evaluate each pipeline segment according to a list of risk factors and to assign each pipeline segment a corresponding risk classification.30 Pressure tests were still required for pipelines constructed of electric resistance-welded (ERW) pipe manufactured prior to 1970 that were susceptible to longitudinal seam failures. Other segments, depending on risk classification, could be evaluated with an inline inspection (ILI). Pipelines in the lowest risk category were not subject to additional measures. Deadlines for testing and inspections under the alternative program were specified in § 195.303(f). In accordance with § 195.303(d), all pre-1970 ERW pipe was deemed susceptible to longitudinal seam failures unless an engineering analysis showed otherwise. In conducting an engineering analysis, an operator was required to consider among other things: (1) seam-related leak history of the pipe and pipe manufacturing information as available, including the pipe steel’s mechanical properties and fracture toughness; (2) the manufacturing process and controls related to seam properties, including whether the ERW process was high-frequency or low-frequency, whether the weld seam was heat treated, whether the seam was inspected, the test pressure and duration during mill hydrotest; (3) the quality control of the steel-making process; and (4) other factors pertinent to seam properties and quality. 28 Post-hearing Submission, Exhibit 56. 29 Respondent contended in its Pre-hearing Submittal that five segments were exempt from § 195.302 because they were covered by § 195.303; however, the evidence produced suggested Respondent intended to make this claim for six segments. 30 An operator electing to follow an alternative program was required to develop the plans and schedule for testing by December 7, 1998.#

420115016_Final Order_06272013_text.pdf, page 1211 According to Respondent’s record, the Pierce Junction to Luling pipeline segment was “[c]omposed almost exclusively of pre-1970 ERW pipe.”31 This means it was required to be deemed susceptible to longitudinal seam failures and pressure tested, unless an engineering analysis showed otherwise. Respondent produced an engineering analysis for the segment completed in 1999. The analysis concluded that the segment was not susceptible to seam failures based on an evaluation of leak history, design pressure, and pipe metallurgy. With regard to leak history, the analysis concluded there was no propensity to seam-related failures because only two failures were documented during pressure tests. In one failure, it was noted that “the weld seam provided a weak path along which to grow,” but the root cause of the crack was determined to be a gouge. Design pressure and pipe metallurgy were found to be within specification. The analysis did not contain any information about the manufacturing process and controls. Having reviewed the engineering analysis for the Pierce Junction to Luling segment, I find it did not give adequate consideration to the weakness along the longitudinal seam discovered at one of the failure sites. The weakness of the seam was a significant finding during the evaluation of seam integrity. Even though seam failure was not the root cause of the leak, there was an absence of analysis supporting a conclusion that there was no propensity for seam-related failure despite the weakness of the seam. In addition, there was no information regarding the manufacturing process and controls of the pipe. In accordance with the regulatory presumption that all pre-1970 ERW pipelines are susceptible to seam failure unless otherwise shown, these factors should have weighed in favor of a conservative conclusion regarding susceptibility. I find the engineering analysis did not have sufficient support for concluding the pre-1970 ERW segment was not susceptible to longitudinal seam failure. Under § 195.303, all pre-1970 ERW pipeline segments susceptible to seam failure covered by a risk-based alternative program were required to be pressure tested unless the analysis showed otherwise, which in this case it did not. Respondent contended that even though it believed a pressure test was not required, the Pierce Junction to Luling segment was pressure tested in 1961, 1969, and 1992. Respondent submitted certain pressure test records from 1961 and 1992.32 The records submitted by Respondent were not sufficient to demonstrate the entire pipeline segment had been pressure tested. The records from 1961 did not include pressure recording charts and the records from 1992 did not document a pressure test on the entire 140.9-mile segment. Without adequate pressure test documentation or an acceptable analysis showing a pressure test was not required, I find the pipeline was operated out of compliance. SMI 6A to South Bend (Segment 5) Respondent contended that this pipeline segment did not have to comply with the pressure testing requirement in § 195.302 because Respondent had elected the risk-based alternative to 31 Post-hearing Submission, Exhibit 12. 32 Post-hearing Submission, Exhibits 14-16.#

420115016_Final Order_06272013_text.pdf, page 1312 pressure testing covered under § 195.303. Respondent did not contend the SMI 6A to South Bend segment was ever pressure tested.33 The SMI 6A to South Bend pipeline segment was “[c]omposed almost exclusively of pre-1970 ERW pipe.”34 Respondent produced an engineering analysis completed in 1998, which concluded that the pre-1970 ERW pipe was not susceptible to seam failures. This conclusion was based on an evaluation of leak history, design pressure, pipe manufacturing, and pipe metallurgy. With regard to leak history, the analysis noted two leaks on the body of the pipe caused by outside force damage and no history of seam-related leaks. The vintage, manufacturer, and pipe mill were all considered. No manufacturing records were located from the mill, but the pipe specification license of the mill was considered. The license would have required the mill to perform pressure tests and nondestructive inspection of all ERW welded seams along with visual inspections. Analysis of the metallurgy noted that the pipe was manufactured using high-frequency ERW welding, but the analysis found there had been no normalization by post-weld heat treatment, which had caused “higher-than-normal microhardness tests.” As a result, the analysis found inadequate toughness tests and inadequate shear requirement. There is no further analysis of whether or to what extent those qualities could impact the susceptibility of the seam to failure. In addition, even though the mill’s pipe specification license was considered, there was an absence of manufacturing records for the segment to determine if these processes were actually followed. Under the presumption that all pre-1970 ERW pipelines are susceptible to seam failure unless otherwise shown, these issues should have weighed in favor of a conservative conclusion regarding susceptibility absent further analysis. Accordingly, I find the engineering analysis did not have sufficient support for concluding that the SMI 6A to South Bend segment was not susceptible to longitudinal seam failure. For the above reasons, I find the pipeline was operated out of compliance. New Iberia to Sunset (Segment 7) Respondent contended that this pipeline segment did not have to comply with the pressure testing requirement in § 195.302 because Respondent had elected a risk-based alternative to pressure testing under § 195.303. In addition, Respondent contended that the segment was pressure tested in 1971-1973, and again in 2011 after the OPS inspection. Respondent explained that the segment has now been purged of product and idled. The documentation submitted by Respondent consisted of MOP inventory data sheets and emails concerning a prospective tool run.35 These records do not demonstrate that Respondent had evaluated the segment according to the risk factors in § 195.303 or that Respondent had assigned a risk classification that exempted the segment from pressure testing. 33 Post-hearing Submission, Exhibit 6. 34 Post-hearing Submission, Exhibit 22. 35 Post-hearing Submission, Exhibits 32-35.#

420115016_Final Order_06272013_text.pdf, page 1413 No additional documentation was submitted to demonstrate the segment had been pressure tested prior to the OPS inspection. Accordingly, I find this segment was not in compliance. South Bend to New Iberia (Segment 8) Respondent contended that this pipeline segment did not have to comply with the pressure testing requirement in § 195.302 because Respondent had elected the risk-based alternative to pressure testing. In addition, Respondent contended that the segment was pressure tested in 1972 and again in 2011 after the OPS inspection. Respondent noted that a portion of the segment is currently idled. The documentation submitted by Respondent consisted of MOP inventory data sheets.36 These records do not demonstrate that Respondent had evaluated the segment according to the risk factors in § 195.303 or that Respondent assigned a risk classification that exempted the segment from pressure testing. Respondent did not submit any additional documentation to show the segment had been pressure tested prior to the OPS inspection. Accordingly, I find this segment was not in compliance. Sunset to Anchorage (Segment 9) Respondent contended that this pipeline segment did not have to comply with the pressure testing requirement in § 195.302 because Respondent had elected the risk-based alternative to pressure testing under § 195.303. In addition, Respondent contended that the segment was pressure tested in 1971 and 1998. Respondent noted that the segment is currently idled. The documentation submitted by Respondent consisted of MOP inventory data sheets and emails concerning a prospective tool run.37 The records do not demonstrate Respondent had evaluated the segment pursuant to § 195.303 or assigned a risk classification that exempted the segment from pressure testing. In addition, Respondent did not submit documentation to show the pipeline segment had been pressure tested prior to the OPS inspection. Accordingly, I find this segment was not in compliance. Borregas to Viola (Segment 20) Respondent contended that this pipeline segment did not have to comply with the pressure testing requirement because Respondent had elected the risk-based alternative to pressure testing. In addition, Respondent contended that the segment was pressure tested in 2006. Respondent did not submit any documentation to suggest Respondent had evaluated the segment pursuant to a risk-based program that complied with § 195.303. In addition, the pressure test 36 Post-hearing Submission, Exhibits 36-39. 37 Post-hearing Submission, Exhibits 40-44.#

420115016_Final Order_06272013_text.pdf, page 1514 records submitted were missing necessary data, such as test pressure, duration, and temperature.38 Accordingly, I find this segment was not in compliance. e. Segments that Respondent Claimed Were Exempt from Part 195 Sarita to Borregas (Segment 17) Respondent contended that the Sarita to Borregas pipeline segment is an unregulated gathering line exempt from Part 195 (see § 195.1). Respondent submitted supporting documentation to prove this segment is an unregulated gathering line. Accordingly, this alleged violation is withdrawn. SMI 6B to 6A (Segment 18) Respondent contended that this pipeline segment was exempt from Part 195 because it was an offshore pipeline located upstream of a production facility (see § 195.1(b)(5)). In addition, Respondent noted that this segment was abandoned in 2007. Respondent submitted supporting documentation to prove this segment was an offshore pipeline upstream of a production facility, which is not subject to the requirements in § 195.302. Accordingly, this alleged violation is withdrawn. Texaco 11C to SMI 6B (Segment 26) Respondent contended that this pipeline segment was exempt from Part 195 because it was an offshore pipeline located upstream of a production facility. In addition, Respondent noted that this segment was abandoned in 2007. Respondent submitted supporting documentation to prove this segment was an offshore pipeline upstream of a production facility, which is not subject to the requirements in § 195.302. Accordingly, this alleged violation is withdrawn. f. Additional Segment for Which Respondent Provided Records Hawkins to MidValley Junction This pipeline segment was not listed in the Spreadsheet, but Respondent introduced records for the segment and contended that pressure testing was not required because the segment had been “derated,” meaning MOP had been established under § 195.406(a)(5) based on 80 percent of the highest operating pressure to which the pipeline was subjected (see § 195.302(b)(1)). Since the Notice did not allege a violation with respect to this segment, no finding is made as to whether the segment was in compliance at the time of the OPS inspection. 38 Post-hearing Submission, Exhibits 82 and 83.#

420115016_Final Order_06272013_text.pdf, page 1615 Conclusion In summary, having reviewed the evidence in the record, I find Respondent violated § 195.302 by operating 19 pipeline segments identified above as Segments 2–5, 7–12, 14–16, 20–22, 24, 25 and 27, which had not been pressure tested as set forth in the regulation. For the reasons stated above, I withdraw the allegations that Respondent violated § 195.302 with regard to 8 pipeline segments identified above as Segments 1, 6, 13, 17–19, 23 and 26. Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h)(2), which states: § 195.452 Pipeline integrity management in high consequence areas. (a) . . . . (h) What actions must an operator take to address integrity issues?— (1) General requirements. An operator must take prompt action to address all anomalous conditions the operator discovers through the integrity assessment or information analysis . . . . (2) Discovery of condition. Discovery of a condition occurs when an operator has adequate information about the condition to determine that the condition presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than 180 days after an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator can demonstrate that the 180-day period is impracticable. The Notice alleged that Respondent failed on two occasions to timely discover conditions on its pipelines following an integrity assessment. In the first instance, the Notice alleged that Respondent failed to discover conditions promptly, but no later than 180 days after an integrity assessment on its LA-16A and 16B 20”/22” Melville to Boyce crude oil pipeline. In the second instance, the Notice alleged that Respondent failed to timely discover conditions on its West Delta 73 to Grand Isle Station offshore pipeline. a. Melville to Boyce pipeline With regard to the Melville to Boyce crude oil pipeline, the Notice alleged that Respondent completed an integrity assessment of the pipeline on October 25, 2007, making the deadline April 22, 2008 for obtaining adequate information and discovering conditions under § 195.452(h)(2). The Notice alleged that Respondent extended its own internal deadline for discovering conditions twice, first to June 21, 2008, and then again to September 30, 2008, due to the tool vendor taking 159 days to provide the preliminary report. The extensions were allegedly to allow Respondent additional time for data integration, information analysis, receipt of the final report, and development of a repair plan. The Notice alleged these reasons did not justify failure to comply with the 180-day deadline or render the regulatory deadline#

420115016_Final Order_06272013_text.pdf, page 1716 “impracticable.” Thus, the Notice alleged Respondent violated the regulation by failing to discover conditions by April 22, 2008. In its written submissions and at the hearing, Respondent argued that it was impracticable to discover conditions within 180 days of the integrity assessment because adequate information was not available. Since the preliminary inline inspection (ILI) data was received from the vendor less than 22 days before the 180-day deadline, Respondent argued that it needed additional time to perform the comprehensive data integration and analysis required by its procedures and the regulation. It was not until the data integration and analysis were complete that Respondent contended it had adequate information about the pipeline. Respondent explained that its integrity management program (IMP) “requires the integration of all available information about the integrity of the entire pipeline in conducting an integrity assessment and evaluation prior to declaring final discovery of a condition.”39 This includes comprehensive data integration and analysis, including analysis of the ILI results and overlay of the data with additional information, such as cathodic protection, pressure testing, previous ILIs, depth of cover, waterway crossings, aerial patrols, leak history, and previous repairs. Respondent stated that it was necessary to extend the discovery period by an initial 60 days to permit validation digs, receive the final report, analyze the results, complete data integration and develop a repair plan. Respondent then extended the period by an additional 60 days because it “needed additional ILI data and examination in order to perform the analysis required” for the remaining repairs that were identified. Respondent attributed these delays to the vendor and the “extensive” amount of information that needed to be integrated, noting there was “significant delay required by the vendor to integrate and overlay all of the integrity information for this pipeline segment.”40 Respondent further contended that its procedures were consistent with the requirements in § 195.452(g), PHMSA guidance at FAQs 7.19 and 4.13, a prior enforcement case, and a recommendation by the National Transportation Safety Board (NTSB). After the hearing, Respondent submitted additional documentation, including emails between EMPCo and the ILI vendor regarding the status of the ILI results and the delays. Applicable safety standards Pursuant to § 195.452(j)(3), pipeline operators must regularly assess their line pipe at specified intervals. 41 Following an integrity assessment, an operator must promptly, but within 180 days, obtain sufficient information to determine whether conditions on the pipeline present a potential threat to integrity, unless the 180-day period is impracticable.42 Operators must address all 39 Closing, p.3. 40 EMPCo letter dated August 30, 2012, p.4 (Closing). 41 § 195.452(j). 42 § 195.452(h)(2).#

420115016_Final Order_06272013_text.pdf, page 1817 anomalous conditions discovered through the integrity assessment according to a schedule set forth in the regulation.43 In addition to performing integrity assessments, operators must also periodically evaluate the integrity of each pipeline by analyzing “all available information about the integrity of the entire pipeline and the consequences of a failure.”44 Information required to be analyzed pursuant to § 195.452(j)(2) includes, among other things, data gathered though integrity assessments, other inspections and tests (such as corrosion control monitoring), and preventative and mitigative actions. The periodic evaluation must be conducted “as frequently as needed,”45 and operators must remediate any integrity issues raised by the information analysis that could reduce a pipeline’s integrity.46 Findings The extent to which an operator is required to perform comprehensive data integration under § 195.452(g) and (j)(2) before discovering conditions under § 195.452(h)(2) was central to Respondent’s position. Contrary to Respondent’s assertions, however, I find § 195.452(h)(2) does not explicitly require comprehensive data integration; rather it requires that sufficient information be obtained to determine whether conditions on the pipeline present a potential integrity threat. If an operator obtains information following a tool run showing conditions that could present a potential integrity threat, the operator is capable of discovering those conditions for purposes of § 195.452(h)(2) without the need to perform an evaluation under § 195.452(j)(2).47 In this case, Respondent had chosen to evaluate all available information about the integrity of the entire pipeline following each integrity assessment. That is permissible so long as Respondent complies with § 195.452(h)(2) by ensuring that it discovers conditions promptly, but within 180 days after the integrity assessment. Respondent may not delay discovery beyond the 180-day deadline just to complete data integration, if it already has information that conditions could present a potential integrity threat. I agree with Respondent that in some situations, a delay in receiving ILI results from a tool vendor may render the 180-day discovery period impracticable. If the 180-day period is justifiably exceeded, as it may have been here, an operator must still take action to ensure that discovery is completed as soon as practicable to comply with § 195.452(h)(2). 43 § 195.452(h)(1), (h)(3). 44 § 195.452(g) and (j)(2). 45 § 195.452(j)(2). 46 § 195.452(h). 47 Certain data integration, such as overlaying multiple tool runs, may be necessary to discover certain types of conditions (e.g., dents with metal loss). To ensure compliance with § 195.452(h)(2), PHMSA expects multiple tool runs to be completed in close proximity (see FAQ 6.6), but the 180-day discovery period for each run still begins when that specific tool reaches the receiver (see FAQ 4.13). The need to overlay data from a second or third tool run does not render it “impracticable” to discover conditions from the first run (so long as there is adequate information that conditions present a potential threat to integrity).#

420115016_Final Order_06272013_text.pdf, page 1918 Accordingly, I evaluate the evidence to decide whether Respondent discovered conditions as soon as practicable following receipt of the ILI vendor report. The evidence shows that Respondent received the preliminary ILI report on March 31, 2008, 159 days after the integrity assessment. Respondent expected the final report on April 15, 2008, 174 days after the integrity assessment, but extended the discovery deadline by 60 days to provide time for receiving the final report, analyzing the results, completing data integration including consideration of tool tolerances, analyzing risks and threats, and developing a repair plan.48 Then, after a repair plan had been completed, Respondent extended the discovery deadline by 60 days for a second time to request that the ILI vendor perform additional calculations to more accurately assess the number of required repairs and to produce an overlay report with several historical tool runs to get a more comprehensive view of the pipeline’s integrity.49 Having considered the evidence, I find Respondent has not demonstrated it was necessary to exceed the 180-day discovery period by 120 days. It would have been practicable for Respondent to discover conditions prior to the second 60-day extension, when it had already validated the ILI data, analyzed the results, considered tool tolerances, and developed a repair plan. Accordingly, I find even though it may have been impracticable for Respondent to discover conditions within 180 days of the integrity assessment, Respondent failed to discover conditions as soon as practicable thereafter. Guidance and prior enforcement With regard to Respondent’s contention that its procedures were consistent with PHMSA guidance and prior enforcement, I find the extent to which the procedures were consistent does not impact the finding that Respondent failed to discover conditions as soon as practicable. For example, Respondent cited FAQ 7.19 regarding the consideration of tool tolerances for determining if a detected anomaly meets the repair criteria in §195.452(h)(4).50 The guidance states that operators must integrate relevant information about the condition of the pipeline in making decisions on excavation timing and other mitigative actions. Respondent appropriately recognized the need to integrate relevant information about tool tolerances. As noted above, Respondent had already considered tool tolerances and developed a repair plan when it extended discovery for a second time. While Respondent may have considered tool tolerances as set forth in the guidance, it did not discover conditions as soon as practicable in accordance with § 195.452(h)(2). Similarly, guidance at FAQ 4.13 defines the completion of an integrity assessment for the purpose of calculating the 180-day discovery period. The guidance states that when an ILI tool 48 Violation Report, Exhibit 2-2. 49 Violation Report, Exhibit 2-4. 50 PHMSA publishes answers to FAQs concerning compliance with the integrity management regulations at: http://primis.phmsa.dot.gov/iim. These guidance materials do not constitute rules themselves but provide informal information about how to implement integrity management programs in accordance with applicable requirements.#

420115016_Final Order_06272013_text.pdf, page 2019 reaches the receiver, that is the date the assessment is considered complete, which in turn starts the discovery period. Since there is no question that the assessment in this case was completed on October 25, 2007, making the original deadline for discovery April 22, 2008, I find this guidance does not impact the finding that Respondent failed to discover conditions as soon as practicable. In the prior enforcement case cited by Respondent, PHMSA found an operator had violated § 195.452(j) by failing to perform a periodic evaluation that integrated results from prior corrosion and cracking integrity assessments. 51 In the present case, OPS has not alleged that Respondent violated § 195.452(j) by failing to perform data integration. Rather, the evidence demonstrates Respondent failed to discover conditions promptly after an integrity assessment under § 195.452(h)(2). Respondent may not delay discovery beyond the 180-day deadline just to complete its data integration process if it already has sufficient information that conditions could present a potential integrity threat. Finally, Respondent argued that it kept in communication with PHMSA regarding the delay, which is consistent with a recommendation issued by the NTSB to require greater operator communication when discovery is delayed.52 Respondent’s communication with PHMSA is noted, but does not preclude finding that discovery was not made in accordance with § 195.452(h)(2). For the above reasons, I find Respondent violated § 195.452(h)(2) by failing to discover conditions on its LA-16A and 16B 20”/22” Melville to Boyce crude oil pipeline as soon as practicable following receipt of the ILI data from the tool vendor. b. West Delta 73 to Grand Isle Station pipeline The Notice also alleged that Respondent failed to discover conditions promptly after an integrity assessment on its West Delta 73 to Grand Isle Station offshore pipeline. Specifically, the Notice alleged that Respondent completed an integrity assessment on February 2, 2010, making the 180-day discovery deadline August 1, 2010. Respondent received a preliminary report from the tool vendor on March 12, 2010. Respondent then invalidated the tool run and completed a subsequent integrity assessment on May 31, 2010, receiving the preliminary report from that run on November 26, 2010. At the hearing, OPS alleged that Respondent had invalidated the February 2010 tool run data based on “unity charts,” which are described in its IMP procedures at Section 4. OPS alleged that Respondent believed the unity charts demonstrated problems with the tool data. Based on its own review of the unity charts, however, OPS believed the charts showed the ILI data was within an acceptable range. For this reason, OPS alleged Respondent’s rationale for invalidating 51 See Enbridge Energy, LP, Final Order, CPF No. 3-2012-5013, Item 4, 2012 WL 5473686 (Sept. 7, 2012) (enforcement cases are also available online at http://www.phmsa.dot.gov/pipeline/enforcement). 52 See NTSB Accident Report PAR-12/01, Enbridge Inc., Hazardous Liquid Pipeline Rupture and Release, Marshall, Michigan, July 25, 2010 (adopted Jul. 10, 2012) (http://www.ntsb.gov/doclib/reports/2012/par1201.pdf).#

420115016_Final Order_06272013_text.pdf, page 2120 the February 2010 integrity assessment was not justified, and the operator violated § 195.452(h)(2) by failing to discover conditions on the line by August 1, 2010. In its written submissions and at the hearing, Respondent contended that it followed its procedures and the applicable regulations when it evaluated the quality of the data from the February 2010 tool run. Respondent explained that the tool in question failed to pass Respondent’s validation process on two separate occasions because it was not accurately sizing the type of anomalies indicated by the preliminary results. In other words, the data was potentially under-reporting anomalies on the line. The validation process is set forth in Respondent’s procedures at Section 2.0 of Appendix K of its IMP. The procedures require the use of “control charts” to validate tool run data. Control charts are a “statistical tool used to analyze the tool vs. field data.”53 Upon receiving preliminary data from an ILI run, the operator selects five to ten anomalies to excavate and measure. Tool data and field readings are then plotted on the control chart. If the number of points falling outside of the established boundaries for normal data exceeds a certain level, the test fails, which “is strong statistical evidence that the magnitude of error is unusual, and it may be necessary to reject the run.” The unity charts referenced in the Notice, Respondent explained, are not used for the purpose of validating ILI tool data. They are used after the data passes the control charts to adjust the repair plan as information gathered from 20 to 30 excavations suggests the data is more or less accurate than originally believed. Even though Respondent was concerned with the validity of the February 2010 data, it implemented mitigative steps to address the potential corrosion issues indicated by the data, including enhanced air and helicopter patrols, aggressive maintenance pigging, and increased biocide and corrosion mitigation treatments. Respondent also notified PHMSA of the issue it was having with the ILI data. Respondent scheduled two additional ILI tool runs on the pipeline: a different magnetic flux leakage tool and a more advanced ultrasonic thickness tool. The tool runs were completed on May 31, 2010. Data from the ultrasonic tool was successfully validated using the control charts and Respondent stated that it completed discovery within 180 days of the successful tool run. Following the hearing, Respondent provided additional documentation to substantiate its validation process and its decision concerning the failed tool run. Respondent submitted documents comparing its validation of the failed tool run with a validation of a successful tool run, as well as internal correspondence and correspondence with the tool vendor. Findings Section 195.452(h)(2) requires an operator to obtain sufficient information about conditions on its pipelines “promptly, but no later than 180 days after an integrity assessment.” While it is usually evident when an integrity assessment is completed (e.g., at the conclusion of a pressure 53 See Pre-Hearing Submittal, Exhibit (Tab) 18.#

420115016_Final Order_06272013_text.pdf, page 2221 test or ILI tool run), PHMSA has issued guidance to assist operators in applying the regulation in less common situations. 54 Among other things, FAQ 4.13 provides that if ILI tool run data is determined to be “suspect and an entire rerun is to be performed, then the evaluation will be expected within 180 days after the successful rerun.”55 Respondent has presented documentation to show that the data from the February 2010 tool run was suspect. Respondent reached this conclusion by following its procedures in Appendix K of its IMP manual to determine the validity of the data. The data failed the validation procedures two separate times.56 In the first instance, too many points on the control chart were more than one standard deviation from the mean. In the second instance, too many points were on the same side of the mean. Since the tool run data was suspect and Respondent decided to perform a rerun, the discovery period ended 180 days after the successful rerun in May 2010. Accordingly, I find Respondent did not violate § 195.452(h)(2) with respect to the February 2010 tool run on its West Delta 73 to Grand Isle Station pipeline. This alleged violation is withdrawn. Conclusion In summary, having reviewed the evidence in the record, I find Respondent violated § 195.452(h)(2) by failing to discover conditions on its Melville to Boyce pipeline as soon as practicable following receipt of ILI data. I further find the alleged violation with regard to the West Delta 73 to Grand Isle Station pipeline must be withdrawn. Item 3: The Notice alleged that Respondent violated 49 C.F.R. § 195.452(h)(4), which states: § 195.452 Pipeline integrity management in high consequence areas. (a) . . . . (h) What actions must an operator take to address integrity issues?— (1) General requirements. An operator must take prompt action to address all anomalous conditions the operator discovers through the integrity assessment or information analysis . . . . (i) Temporary pressure reduction. An operator must notify PHMSA, in accordance with paragraph (m) of this section, if the operator cannot meet the schedule for evaluation and remediation required under paragraph (h)(3) of this section and cannot provide safety through a temporary reduction in operating pressure. (ii) Long-term pressure reduction. When a pressure reduction exceeds 365 days, the operator must notify PHMSA in accordance with paragraph (m) of this section and explain the reasons for the delay. An operator must also take further remedial action to ensure the safety of the pipeline. 54 See FAQ 4.13. 55 FAQ 4.13. 56 See Pre-hearing Submittal, Exhibits 24 and 27.#

420115016_Final Order_06272013_text.pdf, page 2322 (3) Schedule for evaluation and remediation. An operator must complete remediation of a condition according to a schedule prioritizing the conditions for evaluation and remediation. If an operator cannot meet the schedule for any condition, the operator must explain the reasons why it cannot meet the schedule and how the changed schedule will not jeopardize public safety or environmental protection. (4) Special requirements for scheduling remediation.—(i) Immediate repair conditions. An operator’s evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formula in Section 451.6.2.2(b) of ANSI/ASME B31.4 (incorporated by reference, see § 195.3). An operator must treat the following conditions as immediate repair conditions: (A) Metal loss greater than 80% of nominal wall regardless of dimensions . . . . (D) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 6% of the nominal pipe diameter. The Notice alleged that Respondent failed on three occasions to address immediate repair conditions in accordance with the operator’s schedule for remediation. The Notice also alleged that Respondent failed to temporarily reduce operating pressure or shut down two pipelines until the repairs were completed. Two of the three conditions were on the West Delta 73 offshore pipeline and the third was on the South Marsh Island (SMI) 69B offshore pipeline. a. West Delta 73 pipeline The Notice alleged that Respondent repaired two West Delta 73 immediate repair conditions more than eight months after receiving a preliminary integrity assessment report and over four months after receiving a second report, even though Respondent’s procedures required immediate repairs to be confirmed and repaired within five business days. The Notice further alleged that Respondent did not reduce operating pressure on the West Delta 73 pipeline because the operator concluded there were low operational risk levels. In its Response, EMPCo explained that the pipeline is located offshore, which requires considerably more time to permit, plan, stage and execute repairs; therefore, it was not practicable for Respondent to complete the repairs within five days as set forth in its IMP. Respondent noted that PHMSA guidance on this issue states that immediate repairs should be made “as soon as practicable.”57 Respondent also explained that the lines were already operated at low pressures and the corrosion defect anomalies detected were rated as not needing further pressure reduction under the applicable calculations. In accordance with its IMP and the relevant requirements, Respondent stated that it filed a timely safety related condition report to notify PHMSA that the repairs were being evaluated and scheduled, and that additional pressure 57 FAQ 7.4.#

420115016_Final Order_06272013_text.pdf, page 2423 restrictions would not be necessary. Respondent submitted relevant documentation including evaluations, calculations, work procedures, and notifications. Applicable safety standards The integrity management standards in § 195.452 apply to each hazardous liquid pipeline that could affect a high consequence area (HCA). Section 195.452(h) requires operators to take prompt action to address anomalous conditions discovered through a pipeline integrity assessment.58 Each operator must remediate conditions according to a schedule that includes provisions for “immediate repair conditions.”59 Examples of immediate repair conditions are areas of corrosion with greater than 80% wall loss, or dents located on the top of the pipe with a depth greater than 6% of the pipe diameter.60 Upon discovering an immediate repair condition, an operator must temporarily reduce operating pressure or shut down the pipeline until the repair is completed.61 The pressure reduction must be calculated using the formula in Section 451.6.2.2(b) of consensus standard ASME B31.4-2006, Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids (incorporated by reference, see § 195.3).62 If an operator cannot meet its schedule for repair and cannot provide safety through a temporary reduction in operating pressure, the operator must notify PHMSA.63 The formula for calculating a pressure reduction in Section 451.6.2.2(b) of ASME B31.4-2006 refers to a secondary source, ASME B31G-2004, Manual for Determining the Remaining Strength of Corroded Pipelines (incorporated by reference, see § 195.3) for calculating safe operating pressure. The calculation is based on measurements of the longitudinal extent and maximum depth of the corroded areas, the outside diameter of the pipe, and wall thickness. In some situations, if the measured severity of the corroded area results in a safe maximum pressure for the corroded area that is higher than the maximum operating pressure (MOP) of the pipeline, the standards indicate the corroded region may be used for service without further reduction to the MOP.64 PHMSA has issued guidance that operators must still reduce operating pressure even if the calculated pressure is greater than the existing operating pressure, stating that in this “rare” situation operators “should determine the amount of such reduction based on their particular circumstances.”65 PHMSA also stated that a “reduction of 20 percent below the highest operating pressure actually experienced . . . may provide the necessary additional safety margin.”66 While 58 §195.452(h)(1). 59 § 195.452(h)(3) and (h)(4)(i). 60 § 195.452(h)(4)(i)(A) and (h)(4)(i)(B). 61 § 195.452(h)(4)(i). 62 § 195.452(h)(4)(i). 63 § 195.452(h)(1)(i) and (h)(3). 64 See, e.g., ASME B31G (2004), sections 1.5 and 4.3; ASME B31.4 (2006), sections 451.6.1(e)(3) and 451.6.2.2(b). 65 FAQ 7.22. 66 FAQ 7.20.#

420115016_Final Order_06272013_text.pdf, page 2524 this guidance provides informal information about how to implement integrity management programs, the guidance does not constitute a rule itself and therefore may not mandate a pressure reduction where it is not otherwise required by the applicable regulations and standards incorporated by reference.67 Respondent’s procedures The relevant procedures from Respondent’s IMP are included in the record.68 In particular, Figure 2.5: Discovery and SRC Review/Determination Process, dated September 30, 2010, states that upon receiving a final or preliminary inline inspection report that identifies potential immediate repair conditions, Respondent must follow the requirements in § 195.452(h)(4)(i) to calculate a potential pressure reduction. If a pressure reduction is necessary under the formula, Respondent must initiate the temporary reduction. Whether or not a reduction is necessary, Respondent must also determine if the repair can be completed in five days. If the repair can be completed in five days, Respondent must take action to complete the repair. If the repair cannot be completed in five days, Respondent must report the condition to PHMSA. Findings On March 15, 2010, Respondent discovered that two locations on its West Delta 73 offshore pipeline had indications of internal corrosion with wall loss potentially greater than 80%. These anomalies met the definition of an immediate repair condition. Respondent performed a calculation pursuant to § 195.452(h)(4)(i) and determined that no further pressure reduction was necessary on the line due to the pipeline already operating at a low stress level of 21% of the minimum yield strength and no susceptibility to a rupture type failure. In addition, Respondent had determined that if it reduced operating pressure any further, it would have impaired the ongoing corrosion mitigation treatments, which included injection of biocides and aggressive cleaning pigs. Respondent also determined that it would not be possible to repair the conditions within five days due to the location of the pipeline offshore at depths up to 50 feet and the difficulty securing offshore pipeline repair resources as a result of Deepwater Horizon oil spill and cleanup efforts. Accordingly, Respondent submitted a notification to PHMSA dated March 26, 2010.69 Both § 195.452(h)(1)(i) and Respondent’s procedures recognized that it may not always be possible for the operator to complete a repair of an anomalous condition according to the predetermined schedule set forth in the operator’s IMP.70 When this occurs, § 195.452(h)(3) and 67 In 2007, PHMSA attempted to amend § 195.452(h)(4) to provide flexibility in the methods an operator may use to calculate a pressure reduction “if the formula [in ASME/ANSI B31.4] results in a calculated pressure higher than the original operating pressure.” See Integrity Management Program Modifications and Clarifications, 72 Fed. Reg. 39012, 39015 (Jul. 17, 2007). The amendment was never incorporated into the code due to a technicality in the amendatory instructions. § 195.452 “Editorial Note” (2007). PHMSA currently has another rulemaking proposing to amend § 195.452(h)(4) for this purpose. See Miscellaneous Changes to Pipeline Safety Regulations, 76 Fed. Reg. 73570, 73581 (proposed Nov. 29, 2011). 68 See Violation Report, Exhibit 3-1. 69 Violation Report, Exhibit 3-2. 70 See FAQ 7.4 (stating that an immediate repair condition must be repaired “as soon as practicable”).#

420115016_Final Order_06272013_text.pdf, page 2625 Respondent’s procedures required the operator to notify PHMSA. Based on the evidence in the record, Respondent filed a timely safety related condition report in accordance with these requirements and notified PHMSA that the offshore repair was not practicable within five days. Respondent completed the repairs as soon as was practicable. Section 195.452(h)(4)(i) also required Respondent to temporarily reduce operating pressure, but the formula for calculating the pressure reduction recognized that when operating pressure is already low, a corroded region may sometimes be used for service without further reduction. In most cases, PHMSA still expects operators to reduce operating pressure to ensure an additional margin of safety. In the present case, however, Respondent has demonstrated there was sufficient justification for its decision to rely on the formula in Section 451.6.2.2(b) of ASME B31.4. Specifically, the operator’s effort to control internal corrosion justified its decision not to further reduce operating pressure beyond the already low pressure so that it could continue to use corrosion inhibiting treatments. Accordingly, I find Respondent was in compliance with its own procedures and with § 195.452(h)(4) when it notified PHMSA that repair of the two offshore conditions within five days was not practicable, and when Respondent determined, based on a calculation pursuant to § 195.452(h)(4)(i), that further pressure reduction would be contrary to pipeline safety due to the minimum flow required for internal corrosion mitigation treatments. For these reasons, I find the alleged violation regarding the West Delta 73 pipeline should be withdrawn. b. SMI 69B pipeline With regard to the third immediate repair condition, which was on the SMI 69B offshore pipeline, the Notice alleged that Respondent repaired the condition more than two months after receiving the preliminary report. The Notice further alleged that Respondent did not reduce operating pressure because the pipeline operated at less than 40% of the minimum yield strength. In response to this allegation, Respondent contended that § 195.452 did not apply to the condition because it was located on a pipeline segment that could not affect an HCA. Respondent stated that it nevertheless repaired the condition as soon as practicable and filed a safety related condition report merely “as [a] precautionary measure and to keep PHMSA informed.”71 Findings On December 8, 2010, Respondent discovered an anomalous condition on its SMI 69B offshore pipeline that appeared to be a dent located on the top of the pipe with a depth greater than 6% of the pipe diameter. Respondent recognized that the pipeline segment could not affect an HCA, but performed a calculation pursuant to § 195.452(h)(4)(i) and determined that no further pressure reduction was necessary due to the pipeline already operating at a low stress level. Respondent also determined that it would not be possible to repair the condition within five days due to the pipeline being located offshore at a depth of about 120 feet. Respondent submitted a 71 Response, p.5.#

420115016_Final Order_06272013_text.pdf, page 2726 notification to PHMSA on December 21, 2010. In the notification, Respondent stated that the “repair condition is not located within the boundaries of an HCA.”72 At the hearing and in its written submissions, Respondent confirmed that the repair condition was not located on a pipeline segment that could affect an HCA. By its terms, the integrity management regulations in § 195.452 apply to pipelines “that could affect a high consequence area.” Respondent has demonstrated the anomalous condition on its SMI 69B pipeline was not on a segment that could affect an HCA. Accordingly, this alleged violation must be withdrawn. Conclusion In summary, having reviewed the evidence in the record, I withdraw the alleged violations of § 195.452(h)(4). The findings of violation in this Final Order will be considered prior offenses in any subsequent enforcement action taken against Respondent. ASSESSMENT OF PENALTY Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed $100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any related series of violations.73 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 Respondent’s 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 $151,100 for the three violations cited above. Item 1: The Notice proposed a civil penalty of $109,500 for Respondent’s violation of 49 C.F.R. § 195.302. Respondent violated § 195.302 by operating 19 pipeline segments totaling 529.25 miles of pipe for years without a documented pressure test. 72 Pre-hearing Submission, Exhibit 36, p.2. 73 The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, Pub. L. No. 112-90, § 2(a), 125 Stat. 1905 (Jan. 3, 2012), increased the maximum administrative civil penalty for a pipeline safety violation to $200,000 per violation for each day, up to a maximum of $2,000,000 for a related series of violations.#

420115016_Final Order_06272013_text.pdf, page 2827 Pressure tests are important for pipeline safety because they ensure a margin of safety above a pipeline’s maximum operating pressure. This safety margin is essential to the prevention of accidents caused by hidden physical defects, such as those from the manufacturing or construction process, or from external forces. When properly performed, pressure tests will disclose physical defects that are large enough to cause the pipe to fail during operation and will provide a proven margin of safety against failure during operation from the growth of defects. Respondent’s operation of untested or inadequately tested pipelines constituted a safety threat and may have exposed persons and property to a heightened risk of an accident caused by unknown pipeline defects. Therefore, I find the nature, circumstances, and gravity of the violation justify a penalty with respect to the 19 pipeline segments. Respondent is culpable for the violations. I find nothing in the record to warrant adjustment of the penalty for reasons of history of prior offenses or good faith in attempting to achieve compliance. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a reduced civil penalty of $102,300 for the 19 instances of violating § 195.302. This penalty reflects a reduction of $7,200 to account for the eight instances of alleged violation that were withdrawn. 74 Item 2: The Notice proposed a civil penalty of $20,800 for Respondent’s violation of 49 C.F.R. § 195.452(h)(2). Respondent discovered conditions on the Melville to Boyce crude oil pipeline 120 days after the deadline in the regulation. The delay in discovering conditions was a result of Respondent performing a comprehensive data integration of all available information about the integrity of the entire pipeline after having received ILI data from the tool vendor only 22 days before the deadline. Timely discovery of conditions on a pipeline following an assessment is one of the cornerstones of integrity management. Prompt discovery of conditions ensures that operators will remediate the conditions in accordance with the schedule for repairs set forth in the regulation. Delays to the discovery of conditions can present a potential risk to pipeline safety by delaying repairs. Having considered the penalty assessment factors, I find several warrant reducing the proposed penalty for this violation. First, I find the delay of the tool vendor in providing ILI data reduces Respondent’s culpability for the violation. Although Respondent is ultimately responsible for compliance with the regulation, EMPCo provided documented communications with the tool vendor that demonstrate the operator was cognizant of the regulatory requirement and was taking steps to address the delay. Second, I find Respondent made a good faith attempt to comply with the regulation by following its procedures for data integration to ensure conditions will be considered and addressed and by 74 When a civil penalty is assessed for more than one instance of a violation (e.g., 27 instances of failing to perform pressure tests), the additional instances typically elevate the total penalty by less than the amount that is assessed for the first instance.#

420115016_Final Order_06272013_text.pdf, page 2928 keeping in communication with PHMSA regarding the delay. Finally, I have withdrawn the alleged violation concerning the West Delta 73 to Grand Isle Station pipeline. Accordingly, having reviewed the record and considered the assessment criteria I assess Respondent a reduced civil penalty of $10,000. Item 3: The Notice proposed a civil penalty of $20,800 for Respondent’s violation of 49 C.F.R. § 195.452(h)(4). Since this Item has been withdrawn, the proposed penalty is not assessed. 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 $112,300. This penalty will not affect Respondent’s ability to continue doing business. Payment of the civil penalty must be made within 20 days of service. Federal regulations (49 C.F.R. § 89.21(b)(3)) require 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 (AMZ-341), Federal Aviation Administration, Mike Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, Oklahoma 73125. The Financial Operations Division telephone number is (405) 954-8893. Failure to pay the $112,300 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 the three violations cited above. Under 49 U.S.C. § 60118(a), each person who engages in the transportation of hazardous liquids by pipeline or who owns or operates a pipeline facility is required to comply with the applicable safety standards established under chapter 601. In its Pre-hearing Submittal, Respondent requested that the proposed compliance terms associated with Item 1 be withdrawn because its IMP manual already requires a pressure test to be performed if certain lines are reactivated and returned to service. The terms of the compliance order outlined below are broader than merely testing idled pipelines before returning them to service. Accordingly, the compliance terms are not withdrawn. Respondent may, however, submit its procedures for reactivating idled pipelines to comply with that portion of the compliance order.#

420115016_Final Order_06272013_text.pdf, page 3029 In its Pre-hearing Submittal, Respondent contended that it has already complied with the proposed compliance terms associated with Item 2. Respondent submitted “proposed draft revisions to its IMP Manual” to demonstrate compliance.75 The submission of draft procedures, however, are not sufficient to satisfy the compliance order because they do not demonstrate Respondent has adopted the procedures that were submitted. Since Item 3 has been withdrawn, the proposed compliance terms in the Notice that were associated with that Item are not included in this Order. 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 § 195.302 (Item 1), Respondent must prepare a plan to perform pressure testing of the 19 pipeline segments identified in this Final Order as Segments 2–5, 7–12, 14–16, 20–22, 24, 25 and 27, which are also listed on the 1998 Spreadsheet (Exhibit 1-2 to the Violation Report, incorporated by reference). The plan must include a schedule for completing the pressure tests within 1 year from receipt of this Order. Any segments that are idled and that do not contain hazardous liquids may be pressure tested prior to resuming operations. The plan must meet applicable pipeline safety requirements in 49 C.F.R. Part 195, including those in Subpart E. Respondent must submit the plan to the Director for review and approval within 30 days of the receipt of this Order. 2. With respect to the violation of § 195.452(h)(2) (Item 2), Respondent must revise its written procedures to ensure timely discovery of conditions when there is an unexpected delay in receiving ILI data from the tool vendor following an integrity assessment. The revised procedures must explain what actions will be taken by the operator to ensure discovery as soon as practicable following a delay, and whenever circumstances render discovery within 180 day to be “impracticable.” The procedures must specify the acceptable grounds for any extension of a discovery date due to impracticability. Respondent must submit the revised procedures to the Director for review and approval within 30 days of the receipt of this Order. 3. It is requested 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. The Director may grant an extension of time to comply with any of the required items upon a written request timely submitted by Respondent and demonstrating good cause for an extension. 75 Pre-hearing Submittal, p.8 and Exhibit 19.#

420115016_Final Order_06272013_text.pdf, page 3130 Failure to comply with this Order may result in the administrative assessment of civil penalties not to exceed $200,000 for each violation for each day the violation continues or in referral to the Attorney General for appropriate relief in a district court of the United States. Under 49 C.F.R. § 190.215, Respondent may submit a petition for reconsideration of this Final Order to the Associate Administrator for Pipeline Safety, PHMSA, 1200 New Jersey Avenue SE, East Building, 2nd Floor, Washington, D.C. 20590, no later than 20 days after receipt of the Final Order by Respondent. Any petition submitted must contain a statement of the issue(s) and meet all other requirements of 49 C.F.R. § 190.215. The filing of a petition automatically stays the payment of any civil penalty assessed, however, the other terms of the order, including the 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. _____________________________ ____________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety#

420115016_Closure Letter_08262019_text.pdf, page 1Official PDFCERTIFIED MAIL - RETURN RECEIPT REQUESTED August 26, 2019 Caroline B. Henderson Safety, Security, Health and Environmental Manager ExxonMobil Pipeline Company 22777 Springwoods Village Parkway Spring, Texas 77389 CPF 4-2011-5016 Dear Ms. Henderson: On June 27, 2013, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued to ExxonMobil Pipeline Company (EMPCo) a Final Order in the above reference case. This Order included two Compliance Order items. Compliance Order Item 1 required the hydrostatic testing of nineteen (19) segments with submittal of the associated documentation with the testing results. Documents were provided to PHMSA on July 30, 2015 and September 1, 2015 to show compliance with the terms of the Compliance Order Item 1. Compliance Order Item 2 required revisions to EMPCo written procedures to ensure timely discovery of conditions when there an unexpected delay in receiving in-line inspection data from the tool vendor following an integrity assessment occurred. PHMSA representatives met with EMPCo on several occasions to discuss the revisions to the procedures provided on January 28, 2015 and March 12, 2019. PHMSA has reviewed the submissions by EMPCo. This case is now closed. PHMSA emphasizes the importance of EMPCo establishing and maintaining appropriate procedures for accurate and timely discovery of anomalous conditions on a pipeline following an in-line assessment. Thank you for your cooperation in this matter. Sincerely, Mary L. McDaniel, P.E. Director, Southwest Region Pipeline and Hazardous Materials Safety Administration#

420115016_NOPV PCP PCO_11072011_text.pdf, page 1Official PDFNOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED November 7, 2011 Geoffrey Craft Vice President Operations ExxonMobil Pipeline Company 800 Bell Street, Room 3180 H Houston, TX 77002 CPF 4-2011-5016 Dear Mr. Craft: On March 31 and April 1, 2011, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA) pursuant to Chapter 601 of 49 United States Code inspected issues related to previously filed Safety Related Condition Reports and portions of your integrity management program in Houston, Texas. As a result of the inspection, it appears that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The items inspected and the probable violation(s) are: 1. §195.302 General requirements. (a) Except as otherwise provided in this section and in §195.305(b), no operator may operate a pipeline unless it has been pressure tested under this subpart without leakage. In addition, no operator may return to service a segment of pipeline that has been replaced, relocated, or otherwise changed until it has been pressure tested under this subpart without leakage. (c) Except for pipelines that transport HVL onshore, low-stress pipelines, and pipelines covered under §195.303, the following compliance deadlines apply to pipelines under#

420115016_NOPV PCP PCO_11072011_text.pdf, page 2paragraphs (b)(1) and (b)(2)(i) of this section that have not been pressure tested under this subpart: (1) Before December 7, 1998, for each pipeline each operator shall– (i) Plan and schedule testing according to this paragraph; or (ii) Establish the pipelines maximum operating pressure under §195.406(a)(5). (2) For pipelines scheduled for testing, each operator shall– (i) Before December 7, 2000, pressure test– (A) Each pipeline identified by name, symbol, or otherwise that existing records show contains more than 50 percent by mileage (length) of electric resistance welded pipe manufactured before 1970; and (B) At least 50 percent of the mileage (length) of all other pipelines; and (ii) Before December 7, 2003, pressure tests the remainder of the pipeline mileage (length). ExxonMobil (operator) operated pipelines that have not been pressure tested. The operator did not establish a plan nor pressure test its South Bend to New Iberia 12-inch Crude pipeline by the deadline as required. The operator provided internal documentation assessing the South Bend to New Iberia 12 Inch Crude pipeline where the records indicate the operator had never hydrostatically tested the pipeline. One operator report titled “Long Seam Susceptibility Criteria for Baseline Assessment” dated 3/24/03 indicates that there was a known seam threat on this pipeline. A subsequent email from Erik M. Wimberly to Rikky D. Miller dated 3/31/04, further references the Baseline Assessment and the fact that “without a documented hydrostatic test record for the 1952 LW and ERW pipe, our process stipulates that a baseline seam integrity assessment is needed.” This indicates that as of 3/31/04, the operator had not hydrostatically tested the pipe according to the requirements of the regulations. At the time of the inspection, no hydrostatic test had been conducted. The operator did not pressure test numerous other pipelines in the Southwest Region by the deadline as required by the regulation. In the course of the inspection, the operator was asked if there were other systems which did not have appropriate test records. The operator provided the inspection team with a document titled, “Systems Lacking DOT Hydrotest Documentation Test Plans and Deadlines” dated 3/28/11 with an attached spreadsheet listing the subject systems. The spreadsheet lists a total of 27 systems which do not have pressure tests. All exceeded the operator’s stated deadline of December 7, 2002. A total of 615.7 miles of the operator’s system does not have pressure tests. In the alternative the operator was unable to provide the hydrostatic test records required by §195.310 Records, which requires that 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. 2. §195.452 Pipeline integrity management in high consequence areas. (h) What actions must an operator take to address integrity issues? (2) Discovery of condition. Discovery of a condition occurs when an operator has adequate information about the condition to determine that the condition presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than 180 days after an integrity assessment, obtain sufficient information about a condition to make that 2#

420115016_NOPV PCP PCO_11072011_text.pdf, page 3determination, unless the operator can demonstrate that the 180-day period is impracticable. The operator inappropriately extended discovery dates on at least two occasions. The operator’s procedure titled “Integrity Management Program in High Consequence Areas” Section 4. Repair Criteria, dated 9/30/10, contains the same language as the regulations related to the definition of “Discovery” but gives no direction in this procedures as to exactly what constitutes “impracticable” and the rationales used by the operator in order to establish that the subject events were “impracticable” are not acceptable. The first instance involves the LA-16A & 16B: 20”/22” Melville to Boyce Crude pipelines. The operator established criteria for evaluating tool runs and determined that it had a successful tool run on 10/25/2007 but it inappropriately extended the discovery date from the latest allowable date of 4/22/2008 to 9/30/2008. The operator’s document titled “Form 1.2: Integrity Management Program Manual Exception Request” Exception Request 2008-02: Extend the Discovery Period for 20”/22” allowed for an extension up to 6/21/2008. A second document titled “LA-16A & 16B: 20”/22” Melville to Boyce Crude” Revision 1: 9/30/2008 shows an additional request for extension on 6/12/08 with a final Discovery Date of 9/30/08. With regard to the first document mentioned above, the operator indicates the need for the extension as: “The tool vendor PII took 159 days of the 180 day Discovery period to provide the preliminary report for the October 24, 2007 TFI tool run… PII expects to deliver the final report on or around 4/15/2008. Therefore, an exception is being requested to extend the period of Discovery an additional 60 days until 6/21/2008 in order to provide time for receipt of the final report from the vendor, analysis of results, completing the Data Integration, and risk and threat analysis needed to develop the repair plan and meet Discovery for the line.” A Second Extension was implemented by the operator and is provided as “Exception 2008-02A” dated 6/12/08, where it indicates the second extension was approved with a Discovery Date of September 30, 2008. PHMSA’s FAQ 4.13, which addresses evaluation and problems with ILI runs says, “ …, in the event a series of ILI tool runs is used to complete an assessment, the 180 day discovery period for each individual tool run begins when that specific tool reaches the receiver if the tool provides sufficient information to determine if a particular repair criteria condition exists. These activities are considered to occur after the completion of the “assessment”. In those rare instances in which only a partial assessment is performed operators will be expected to evaluate the results that were obtained within 180 days of the early termination, in accordance with 195.452(h)(2). If however, the quality of the partial data is suspect and an entire rerun is to be performed, then the evaluation will be expected within 180 days after the successful rerun.” The fact that the vendor took 159 of the 180 is not sufficient to extend the deadline of discovery. The operator did not establish legitimately “impracticable” reasons why the 180-day discovery date needed to be extended. The second instance involves the West Delta 73 to Grand Isle Station. The operator first ran a Rosen ILI tool on 2/2/10 and received a preliminary report on 3/12/10. A subsequent GE ILI tool was run on 5/31/10 and the operator received a preliminary report on 6/21/10. Based off of the 3#

420115016_NOPV PCP PCO_11072011_text.pdf, page 4first ILI run and the fact that the preliminary report was received on 3/12/2010, discovery should have been made no later than 3/12/2010. The operator claimed discovery based on the successful tool run of 5/30/10 with a final Discovery date of 11/26/10. The operator utilized a statistical approach to invalidate the original tool run using data from a machined block of anomalies in the pipeline, specifically designed for calibration purposes. The operator claimed the machined block caused distorted signals on the ILI tool due to the machining of the block. The operator provided Unity Charts for both the Rosen and GE runs where the operator claimed the Unity Charts demonstrated the problems with the Rosen tool. In fact, the Unity Charts demonstrate the findings were within acceptable parameters. The operator’s own procedures titled, “Integrity Management Program in High Consequence Areas, 4. Repair Procedures, Section 4.3.1.4. Adjusting Repair Plans with Actual Data” dated 9/30/2010, page 109 – 110, describes the use of Unity Charts. The procedure states, “With a highly accurate tool, most of the indications should match up to the field excavations within the “error band” identified by the tool vendor (outlined in red on the unity chart).” The Unity Charts provided by the operator show the majority of indications within this acceptable band. The operator also provided a spreadsheet with a discreet sampling of 10 data points obtained from the initial ILI run indicates all 10 anomaly conditions range from 70% to 78% wall loss with the whereas the second ILI run indicates all 10 anomaly conditions range from 55% to 70% wall loss. The conditions identified would have been classified 180-day conditions for both ILI runs. The operator sold the system prior to addressing the 180-day conditions and only addressed two (2) conditions identified as immediate conditions. In this second instance, the operator did not prove the original tool run was defective justifying running the second tool run and delaying the discovery date. The operator was not able to provide concurrence from the tool vendor that the tool was in error for the length of the line. 3. §195.452 Pipeline integrity management in high consequence areas. (h) What actions must an operator take to address integrity issues? (4) Special requirements for scheduling remediation. (i) Immediate repair conditions. An operator's evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using the formula in Section 451.6.2.2 (b) of ANSI/ASME B31.4 (incorporated by reference, see § 195.3). etc. The operator failed to evaluate and repair immediate repair conditions in an acceptable amount of time for at least 3 immediate conditions. The operator provided a procedural flowchart titled, “Integrity Management Program in High Consequence Areas, Figure 2.5: Discovery and SRC Review/Determination Process” dated 9/30/2010. That flow chart indicates that the operator is supposed to “Confirm Immediate Repairs to be completed in 5 business days.” With regard to (i) Immediate repairs on the West Delta 73 pipeline the operator initially identified 31 immediate conditions, reran the tool and subsequently received a second preliminary report and finally conducted an assessment and repair of only two (2) immediate conditions, but did so 4#

420115016_NOPV PCP PCO_11072011_text.pdf, page 5over eight (8) months after the first preliminary report and over four (4) months after the second preliminary report was received. The operator only made two (2) immediate condition repairs, one on 11/2/2010 and the second on 11/4/2010, prior to the pipeline being sold. With regard to (i) Immediate repairs on the SMI 69B to South Bend pipeline the operator received the preliminary report back on 12/8/10 and did not make the only immediate repair until 2/17/11. PHMSA FAQ 7.4 clearly states that “repairs must be made as soon as practicable?” It is not reasonable to allow the operator to extend “what is practicable” beyond the 5 business days stated within the operator’s own procedure. This defeats the purpose of addressing “immediate” conditions immediately. Similarly, the operator failed to reduce pressure on the same two pipelines in a timely manner. The operator’s Safety Related Condition Report for the West Delta 73 pipeline states that “Due to low operational risk levels EMPCo does not plan on reducing operating pressure while the repairs are completed.” For the SMI 69B to South Bend pipeline the operator indicated “no pressure reduction; operates <40% SMYS.” This practice of the operator is contrary to the regulation and PHMSA’s FAQ 7.15 a. clearly states, “the pressure reduction must be based upon pressures that the pipe has actually experienced, with the defect present. These may be well below the “maximum operating pressure” for the pipe, which was the case in this situation.” Proposed Civil Penalty Under 49 United States Code, § 60122, you are subject to a civil penalty not to exceed $100,000 for each violation for each day the violation persists up to a maximum of $1,000,000 for any related series of violations. The Compliance Officer has reviewed the circumstances and supporting documentation involved in the above probable violation(s) and has recommended that you be preliminarily assessed a civil penalty of $151,100 as follows: Item number PENALTY 1. $109,500 2. $20,800 3. $20,800 Proposed Compliance Order With respect to each of the items pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to ExxonMobil Pipeline Company. Please refer to the Proposed Compliance Order, which is enclosed and made a part of this Notice. Response to this Notice Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in Compliance Proceedings. Please refer to this document and note the response options. Be advised that all material you submit in response to this enforcement action is subject to being made publicly available. 5#

420115016_NOPV PCP PCO_11072011_text.pdf, page 6If you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order. In your correspondence on this matter, please refer to CPF 4-2011-5016 and for each document you submit, please provide a copy in electronic format whenever possible. Sincerely, R. M. Seeley Director, Southwest Region Pipeline and Hazardous Materials Safety Administration Enclosures: Proposed Compliance Order Response Options for Pipeline Operators in Compliance Proceedings 6#

420115016_NOPV PCP PCO_11072011_text.pdf, page 7PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to ExxonMobil Pipeline Company a Compliance Order incorporating the following remedial requirements to ensure the compliance of ExxonMobil Pipeline Company with the pipeline safety regulations: 1. In regard to Item Number 1 of the Notice pertaining to a required hydrostatic test, the operator must as soon as possible pressure test the pipelines according to the requirements of 195 Subpart E – Pressure Testing. 2. In regard to Item Number 2 of the Notice pertaining to Discovery, the operator must revise its procedures to provide better guidance on acceptable rationales for extension of dates related to Discovery. 3. In regard to Item Number 3 of the Notice pertaining to immediate repair conditions, the operator must revise its procedures to ensure immediate repairs are implemented within 5 business days. 4. In regard to Item Number 3 of the Notice pertaining to required pressure reductions, the operator must revise its procedures to ensure any and all required pressure reductions occur within 5 business days. 5. The operator must revise its procedures within 30 days after receipt of a Final Order. The operator must complete all hydrostatic tests within 1 year after receipt of a Final Order. 6. It is requested (not mandated) that ExxonMobil Pipeline Company maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to R. M. Seeley, Director, Southwest Region, Pipeline and Hazardous Materials Safety Administration. It is requested that these costs be reported in two categories: 1) total cost associated with preparation/revision of plans, procedures, studies and analyses, and 2) total cost associated with replacements, additions and other changes to pipeline infrastructure. 7#

420115016_Decision on Petition_07092014_text.pdf, page 1Official PDFJULY 9, 2014 Mr. Gerald S. Frey Global Pipeline Manager & President ExxonMobil Pipeline Company 800 Bell St., Room 741-D Houston, TX 77002 Re: CPF No. 4-2011-5016 Dear Mr. Frey: Enclosed is the decision on the petition for reconsideration filed by ExxonMobil Pipeline Company in the above-referenced case. For the reasons explained therein, the decision affirms certain violations in the Final Order, withdraws other violations, and modifies the civil penalty and compliance terms. The penalty payment terms are set forth in the decision. When the civil penalty has been paid and the terms of the compliance order completed, as determined by the Director, Southwest Region, this enforcement action will be closed. This decision constitutes the final administrative action in this proceeding. Service of the decision is made pursuant to 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Jeffrey D. Wiese Associate Administrator for Pipeline Safety Enclosure cc: Mr. R. M. Seeley, Director, Southwest Region, OPS Ms. Catherine Little, Hunton & Williams LLP, Bank of America Plaza, Suite 4100 600 Peachtree Street, N.E., Atlanta, GA 30308 CERTIFIED MAIL – RETURN RECEIPT REQUESTED#

420115016_Decision on Petition_07092014_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 ) ExxonMobil Pipeline Company, ) CPF No. 4-2011-5016 ) ) ) Petitioner. ) ___________________________________ ) DECISION ON PETITION FOR RECONSIDERATION On March 31-April 1, 2011, pursuant to 49 U.S.C. § 60117, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the records and procedures of ExxonMobil Pipeline Company (EMPCo or Petitioner) in Houston, Texas.1 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice) on November 7, 2011, which alleged certain violations of the pipeline safety regulations and proposed a civil penalty of $151,100. The Notice also proposed corrective action to be completed. EMPCo requested a hearing on the Notice, which was held on April 25, 2012, in Houston, Texas. On June 27, 2013, pursuant to 49 C.F.R. § 190.213, PHMSA issued a Final Order in this proceeding. PHMSA determined that EMPCo had committed violations of § 195.302 (Item 1) and § 195.452(h)(2) (Item 2) as alleged in the Notice, and withdrew certain other allegations. The Final Order assessed a civil penalty of $112,300 and ordered corrective action set forth in a Compliance Order. In accordance with § 190.243, EMPCo filed a Petition for Reconsideration of the Final Order on July 22, 2013, seeking reconsideration of the violation, civil penalty, and Compliance Order for Item 1. EMPCo did not seek reconsideration of Item 2. On August 2, 2013, PHMSA stayed Item 1 of the Compliance Order pending issuance of this decision. Pursuant to 49 C.F.R. § 190.243, an operator may petition for reconsideration of a final order issued under § 190.213. Section 190.243 provides that PHMSA may consider additional facts or 1 EMPCo, a subsidiary of Exxon Mobil Corporation, operates approximately 3,800 miles of pipeline transporting crude oil, refined petroleum products, and natural gas liquids in Texas, Louisiana, and Montana as reported by EMPCo for calendar year 2012 pursuant to 49 C.F.R. § 195.49.#

420115016_Decision on Petition_07092014_text.pdf, page 32 arguments if the petitioner submits a valid reason explaining why such information was not presented prior to issuance of the final order. PHMSA may grant or deny, in whole or in part, a petition for reconsideration without further proceedings, but may request additional information or comment if deemed appropriate. Item 1 in the Final Order found EMPCo had violated 49 C.F.R. § 195.302, which states, in relevant part: § 195.302 General requirements. (a) [N]o operator may operate a pipeline unless it has been pressure tested under this subpart without leakage . . . . (c) Except for pipelines . . . covered under § 195.303, the following compliance deadlines apply to pipelines . . . that have not been pressure tested under this subpart . . . (2) For pipelines scheduled for testing, each operator shall— (i) Before December 7, 2000, pressure test— (A) Each pipeline identified by name, symbol, or otherwise that existing records show contains more than 50 percent by mileage (length) of electric resistance welded pipe manufactured before 1970; and (B) At least 50 percent of the mileage (length) of all other pipelines; and (ii) Before December 7, 2003, pressure test the remainder of the pipeline mileage (length). The Final Order determined EMPCo had violated § 195.302 by operating 19 pipeline segments without documentation demonstrating the segments had been pressure tested. The 19 pipelines segments were identified by number, corresponding to a spreadsheet prepared by EMPCo in 1998.2 For most of the 19 segments, PHMSA found either that EMPCo did not have complete pressure test records or that EMPCo’s records did not show the entire length of the segment had been tested. For a few segments, where EMPCo had asserted the company was not required to conduct pressure tests under § 195.303, PHMSA found the company did not have sufficient documentation to exempt those segments from testing. PHMSA also withdrew allegations that 8 additional segments were in violation. 3 In its Petition, EMPCo requested that PHMSA withdraw 16 of the 19 segments from the violation.4 The grounds provided by EMPCo for withdrawing the violations included: (1) submission of additional pressure test documentation; (2) arguments concerning the adequacy 2 See OPS Pipeline Safety Violation Report, Exhibit 1-2 (Nov. 7, 2011). The Final Order found violations with regard to Segment Numbers 2-5, 7-12, 14-16, 20-22, 24, 25 and 27. 3 The Final Order withdrew the alleged violations regarding Segment Numbers 1, 6, 13, 17-19, 23 and 26, finding either that adequate pressure test documentation was provided, the type of pipeline was exempt from pressure testing, or the segment had been sold prior to the time period in question. 4 EMPCo did not contest the violations for Segment Numbers 7-9, but did assert the pipelines were subsequently tested and “idled” and therefore do not need to be retested. In this case, “idled” means deactivated and purged.#

420115016_Decision on Petition_07092014_text.pdf, page 43 of alternative programs established under § 195.303; and (3) the status of several segments as intrastate pipelines.5 EMPCo also requested that the Compliance Order be modified and the civil penalty be further reduced. PHMSA considers these arguments below. Submission of Additional Pressure Test Documentation 1. In its Petition, EMPCo requested that PHMSA withdraw the violation for certain segments based on the submission of additional pressure test documentation.6 Petitioner contended that some of the additional information was not previously provided to OPS “in order to minimize the volume of the submission and in anticipation of further dialog with the Agency.”7 EMPCo explained that after the hearing it expected to confer with OPS about the documentation it had submitted, but OPS “did not avail itself of any opportunity to engage with the Company after the Hearing” and did not request any additional information.8 EMPCo contended that as a result, there was “unnecessary confusion with respect to pipeline nomenclature, testing mileage, and the pressure testing documentation” leading to findings of violation in the Final Order.9 EMPCo also explained that it recovered some additional pressure recording charts that were not previously available, and requested that PHMSA consider this new information. In summary EMPCo argued that 13 segments should be withdrawn because each segment had a valid pressure test performed in accordance with § 195.302. After reviewing the record, PHMSA confirms that at the hearing the Presiding Official granted EMPCo’s request for two post-hearing submission deadlines separated by 60 days. The briefing schedule was to allow EMPCo an opportunity to submit its records, confer with OPS about the submission, and then file any further information necessary. According to EMPCo, OPS did not raise any issues regarding its first submission and therefore EMPCo did not know until receipt of the Final Order that additional records would have been helpful. PHMSA will consider the additional information submitted by Petitioner. A. Segments found to be in compliance based on additional test documentation Upon reconsideration in light of the additional documentation, PHMSA finds EMPCo has demonstrated compliance with § 195.302 for the following segments: PCU to Mt. Belvieu Poly Propylene (Segment 2) – In response to the Notice, EMPCo initially stated this segment was pressure tested in 1981, 2004, and 2009. Prior to issuance of the Final Order, EMPCo submitted records from a pressure test that took place in 1980 on a portion of the system. The Final Order determined the records were not sufficient to demonstrate the entire 0.27-mile segment had been pressure tested. 5 See Petition, Exhibit 1 “Overview of Nineteen Segments.” 6 See Petition, Exhibit 2, identifying Segment Numbers 2, 4, 10-12, 14-16, 21, 22, 24, 25 and 27. 7 Petition at 4. 8 Petition at 3. 9 Petition at 4.#

420115016_Decision on Petition_07092014_text.pdf, page 54 In its Petition, EMPCo produced additional pressure test records from 2005. PHMSA finds the information demonstrates this segment was brought into compliance with § 195.302 in 2005, which is more than five years prior to commencement of this proceeding. Accordingly, PHMSA is withdrawing this violation. Weeks Island to Olivier (Segment 10) – In response to the Notice, EMPCo submitted test records for this segment dated 2000 and 2005. The Final Order determined the records were not sufficient to demonstrate compliance because no pressure recording charts were included.10 In its Petition, EMPCo provided additional information from pressure tests performed in 2000 and 2003, including pressure recording charts. PHMSA finds the additional information demonstrates compliance. Webster to Baytown #3 and #6-8 inch (Segment 11) – EMPCo initially submitted test records for this segment from 2000. The Final Order determined the records were not sufficient because they lacked pressure recording charts and did not otherwise demonstrate the entire 1.08-mile segment had been tested. In its Petition, EMPCo provided additional records from the pressure test, including pressure recording charts. PHMSA finds the additional information demonstrates compliance with regard to the 1.08-mile segment at issue. 11 BOP to ITC Butadiene (Segment 12) – EMPCo initially submitted pressure test records for this segment dated 1979 and 1980. The Final Order determined the records were not sufficient to demonstrate compliance because no pressure recording charts were included. In its Petition, EMPCo provided the pressure recording charts, which PHMSA finds demonstrate compliance. Boyce to Bunkie (Segment 14) – EMPCo initially submitted certain test records for this segment dated 2001. The Final Order determined the records were not sufficient because they lacked pressure recording charts and did not cover all 46.3 miles of the segment. In its Petition, EMPCo provided additional records from the pressure test, including pressure recording charts for the 46.3 miles of the segment. PHMSA finds the additional information demonstrates compliance for the segment. Bunkie to Anchorage (Segment 15) – EMPCo initially submitted records for this segment from a pressure test conducted in 2001. The Final Order determined the records were not sufficient because they lacked pressure recording charts and did not cover all 51.41 miles of the segment. In its Petition, EMPCo provided additional pressure test information including pressure recording charts for the 51.41 miles of the segment. PHMSA finds the additional information demonstrates compliance for the segment. Finney to Boyce (Segment 16) – EMPCo initially submitted test records for this segment from a pressure test conducted in 2001. The Final Order determined the records were not sufficient because no pressure recording charts were included. In its Petition, EMPCo provided the pressure test charts. PHMSA finds the new information demonstrates compliance. 10 Section 195.310 requires certain pressure test records to be kept, including pressure recording charts. 11 The diagram for this pipeline segment referenced other segments totaling almost 19 miles of pipeline, but only the 1.08-mile #3 and #6 8-inch lines were at issue in this case, as listed in the 1998 spreadsheet.#

420115016_Decision on Petition_07092014_text.pdf, page 65 Borregas to Viola (Segment 20)12 – EMPCo initially submitted pressure test records for this segment from 2005, but the test records were missing necessary data, including test pressure, duration, and temperature. In its Petition, EMPCo provided additional documentation from the pressure test. PHMSA finds the information demonstrates the segment was brought into compliance with § 195.302 in 2005, which is more than five years prior to commencement of this proceeding. Accordingly, PHMSA is withdrawing this violation. Strang Road to Texas City (Segment 21) – EMPCo initially submitted records from a 1997 pressure test that took place on this segment. The Final Order determined the records were not sufficient because they lacked pressure recording charts and did not demonstrate the entire 2.86- mile segment was tested. In its Petition, EMPCo provided additional records including pressure test charts. PHMSA finds the additional information demonstrates compliance for the entire 2.86-mile segment. Texas Olefins Multi-Products Crossover (Segment 22) – EMPCo initially submitted records from a 1982 pressure test on this segment. The Final Order determined the records were not sufficient to demonstrate the entire segment had been pressure tested. In addition, no pressure recording charts were included. In its Petition, EMPCo provided additional records including pressure recording charts. PHMSA finds the additional information demonstrates compliance. Chocolate Bayou BOP Crude Butadiene (Segment 24) – EMPCo initially submitted test records from 1981 for this segment, but the Final Order determined the records were not sufficient because no pressure recording charts were included. In its Petition, EMPCo provided additional pressure test records including pressure recording charts. PHMSA finds the additional information demonstrates compliance. Viola to Hess Refinery #2 - 6 inch Line (Segment 27) – EMPCo initially contended this segment was pressure tested in 1999 and 2011, but only submitted pressure test records from 1999. The Final Order determined the records were not sufficient because they did not include any pressure recording charts. In its Petition, EMPCo provided additional pressure test records from 1999, including pressure recording charts. Having reviewed the documentation, PHMSA finds the additional information demonstrates compliance with respect to the 1999 pressure test. In summary, PHMSA withdraws the violation for the following 12 segments based on the submission of additional pressure test documentation: Segment Numbers 2, 10-12, 14-16, 20-22, 24, and 27. The civil penalties and compliance terms associated with these segments are also withdrawn. B. Segments not found in compliance based on additional test documentation Upon reconsideration of the violations in light of the additional documentation submitted, PHMSA continues to find violations with regard to the following segments: 12 In its Petition, EMPCo argued Segment 20 should be withdrawn for other reasons, but PHMSA finds it is appropriate to address the segment here for the reasons stated.#

420115016_Decision on Petition_07092014_text.pdf, page 76 St. James to Junction (Segment 4) – In response to the Notice, EMPCo submitted a single page Pipeline Qualification Record for this segment from 1968. The Final Order determined the record was not sufficient because it lacked necessary pressure test information, such as pressure recording charts. In its Petition, EMPCo provided one additional page that consisted of a pressure recording chart. Section § 195.310 lists the records that must be kept of each pressure test for as long as the facility is in use. The records include, among other things: the pressure recording charts; test instrument calibration data; minimum test pressure; test medium; description of the facility tested and the test apparatus; explanation of any pressure discontinuities, including test failures, that appear on the pressure recording charts; and temperature of the test medium or pipe during the test period. The two pages produced by EMPCo from 1968 lack required information, including the temperature of the test medium or pipe during the test period. There is also a question about calibration of the test data. A note in the new record indicated that test pressure was calibrated, but there is no documentation or certification of the calibration. Also there is a note indicating the pressure recorder was not calibrated. Accordingly, PHMSA continues to find insufficient documentation to demonstrate a pressure test was performed on this segment in accordance with 49 C.F.R. Subpart E. Clovelly to Raceland 16-inch Import (Segment 25) – EMPCo initially contended this segment was pressure tested in 1966 and submitted records from that year that were attached to a report prepared in 1996. The Final Order determined the records were not sufficient because they did not demonstrate the entire 16.79-mile segment was pressure tested. Specifically, the 1996 report stated the pressure test covered 6.21 miles of the #2 16-inch pipeline. In its Petition, EMPCo provided an additional page of records that documented a leak during the pressure test. The additional record does not demonstrate a pressure test was performed in accordance with 49 C.F.R. Subpart E on the entire 16.69-mile 16-inch import pipeline segment. Accordingly, PHMSA continues to find insufficient documentation to demonstrate compliance. In summary, PHMSA confirms the violations for Segment Numbers 4 and 25. The civil penalty and compliance terms associated with the segments are discussed below. 2. Adequacy of Alternative Programs Established under § 195.303 In its Petition, EMPCo requested that PHMSA withdraw the finding of violation for two segments because the engineering judgments used by EMPCo in making conclusions to exempt the segments from testing were sound and reasonable.13 As explained in the Final Order, § 195.303 permitted operators to elect a risk-based program for older pipelines as an alternative to the pressure test deadlines set forth in § 195.302(c)(2). An operator electing this approach in 1998 was required to evaluate each pipeline segment according 13 See Petition at 5, identifying Segment Numbers 3 and 5.#

420115016_Decision on Petition_07092014_text.pdf, page 87 to a list of risk factors and to assign each pipeline segment a corresponding risk classification.14 Pressure tests were still required for any pipelines constructed of electric resistance-welded (ERW) pipe manufactured prior to 1970 if the pipeline was “susceptible to longitudinal seam failures.”15 Other segments could be evaluated with inline inspection (ILI) depending on risk classification. Pipelines in the lowest risk category were not subject to additional measures. Deadlines for testing and inspections under the alternative program were specified in § 195.303(f). Section 195.303(d) established that all pre-1970 ERW pipe were to be deemed “susceptible to longitudinal seam failures,” and thus were required to be pressure tested, unless an engineering analysis showed otherwise. In conducting an engineering analysis, an operator was required to consider among other things: (1) seam-related leak history of the pipe and pipe manufacturing information as available, including the pipe steel’s mechanical properties and fracture toughness; (2) the manufacturing process and controls related to seam properties, including whether the ERW process was high-frequency or low-frequency, whether the weld seam was heat treated, whether the seam was inspected, the test pressure and duration during mill hydrotest; (3) the quality control of the steel-making process; and (4) other factors pertinent to seam properties and quality. Pierce Junction to Luling (Segment 3) and SMI 6A to South Bend (Segment 5) – In response to the Notice, EMPCo argued that it had conducted engineering analyses under § 195.303 for both of these pre-1970 ERW pipeline segments. The Final Order determined the documented analyses did not justify EMPCo’s conclusion that the segments were not susceptible to longitudinal seam failure. In particular, Segment 3 had experienced documented failures during pressure tests, one of which had grown along the weld seam. The longitudinal seam of the pipe was referred to in a company record as the “weak path.”16 The Final Order determined the engineering analysis did not properly analyze the weakness of the longitudinal seam evidenced by the failure. In addition, there was no information regarding the manufacturing process and controls of the pipe. With respect to Segment 5, the Final Order found the engineering analysis did not address noted issues with the pipe’s manufacturing. The metallurgical analysis stated there had been no normalization by post-weld heat treatment, which caused “higher-than-normal microhardness tests.”17 The company’s analysis also found inadequate toughness tests and inadequate shear requirements. These issues were not addressed in the engineering analysis to determine the extent to which they could impact the susceptibility of the seam to failure. 14 An operator electing to follow an alternative program was required to develop the plans and schedule for testing by December 7, 1998. 15 § 195.303(c). 16 Final Order at 11. 17 Final Order at 12.#

420115016_Decision on Petition_07092014_text.pdf, page 98 Under the regulatory presumption that all pre-1970 ERW pipelines are susceptible to seam failure unless otherwise shown, the Final Order concluded pressure tests were required for Segment Numbers 3 and 5 in the absence of justified conclusions to the contrary. In its Petition, EMPCo requested that PHMSA withdraw this finding because the engineering judgments were sound and reasonable. Petitioner argued the regulation only required operators to consider pipe information that is “available.”18 EMPCo contended that it had considered all available information, including manufacturing records, process, and controls as required by the rule. Petitioner also argued that PHMSA’s weighting of certain factors favored a more conservative conclusion regarding susceptibility, which was “beyond the requirements of the plain language of the regulation, and is not established in any guidance or other interpretive document available.”19 Petitioner noted that PHMSA has never communicated to operators what constitutes a sufficient engineering assessment under § 195.303. PHMSA disagrees with the contention that § 195.303 does not prescribe the manner in which operators must conduct an engineering analysis. The regulation lists the information that must be considered. In addition, a reasonable reading of the regulation supports a conservative conclusion regarding seam susceptibility. The regulation establishes a presumption that all pre- 1970 ERW pipelines must be pressure tested unless an operator can demonstrate they are not susceptible to seam failure. PHMSA has reevaluated the engineering analyses that were the basis for EMPCo’s conclusion that the segments were not susceptible to seam failure. PHMSA continues to find information in the records that either suggested a susceptibility to seam failure (e.g., a leak that propagated along the seam of Segment 3) or that called seam integrity into question (e.g., inadequate toughness and shear of Segment 5). With regard to the leak that propagated along the seam of Segment 3 during a pressure test, there was no discussion in the engineering analysis of any reasons to discount this apparent weakness along the seam. Likewise for Segment 5, there was no discussion as to whether or not the manufacturing issues listed in the company’s record could affect seam integrity. There was an absence of sufficient discussion or analysis in the records to support a conclusion that the segments were not susceptible to seam failure given the issues noted. PHMSA finds no basis to modify its decision. Accordingly, PHMSA confirms the violations in Item 1 of the Final Order for Segment Numbers 3 and 5. The civil penalty and compliance terms associated with the segments are discussed below. 18 See § 195.303(d). EMPCo also cited “Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation” at 63, Michael Baker Jr., Inc. (Oct. 30, 2003) available at http://primis.phmsa.dot.gov/iim/techreports htm. 19 Petition at 6.#

420115016_Decision on Petition_07092014_text.pdf, page 109 3. Intrastate Pipelines In its Petition, EMPCo requested that PHMSA withdraw the finding of violation with regard to several segments because they are intrastate pipelines not subject to the regulatory authority of PHMSA. 20 Petitioner noted that under the Pipeline Safety Act, 49 U.S.C. § 60105(a), PHMSA “may not prescribe or enforce safety standards and practices for an intrastate pipeline facility or intrastate pipeline transportation to the extent that the safety standards and practices are regulated by a State authority [with a current certification].” Petitioner argued several segments identified in the Final Order are intrastate and regulated by the Texas Railroad Commission (TRRC), a State authority with a current certification for regulating intrastate hazardous liquid pipelines. Petitioner argued that because the pipeline segments fall under the TRRC, PHMSA may not impose a civil penalty or compliance order on the pipelines. EMPCo explained that it initially provided documentation to PHMSA regarding these pipelines solely in the spirit of cooperation. PHMSA has withdrawn most of these segments based on the submission of additional test documentation.21 Accordingly, PHMSA considers EMPCo’s argument only with regard to Segment Number 3. The question of whether this pipeline is interstate or intrastate was raised for the first time by EMPCo in its Petition. This issue was not briefed by the parties prior to issuance of the Final Order, nor was it discussed at the hearing. At this late stage of the proceeding, there is not sufficient evidence in the record to withdraw the violation on the sole basis that EMPCo now claims the segment is intrastate. Accordingly, PHMSA confirms the violation for Segment Number 3. The civil penalty and compliance terms associated with the segment are discussed below. 4. Compliance Order: Pipelines Subsequently Idled or Pressure Tested In its Petition, EMPCo requested several pipeline segments be withdrawn from the Compliance Order because they have either been idled or subsequently pressure tested. 22 EMPCo contended these segments do not need to be tested under the terms of the Compliance Order. PHMSA has already withdrawn the violations for many of these segments.23 Accordingly, PHMSA considers EMPCo’s argument only with regard to Segment Numbers 7, 8, and 9. New Iberia to Sunset (Segment 7), South Bend to New Iberia (Segment 8), and Sunset to Anchorage (Segment 9) – With regard to pipeline segments that have been idled, meaning they do not currently contain hazardous liquids, PHMSA confirms its statement in the Final Order 20 See Petition, Exhibit 3, identifying Segment Numbers 2, 3, 12, 20-22, 24 and 27. 21 Segment Numbers 2, 12, 20-22, 24 and 27 are withdrawn on the basis of additional documentation provided. 22 See Petition, Exhibit 4, identifying Segment numbers 2, 7-9, 12, 14-16, 20, 21 and 27 with subsequent pressure tests; and Exhibit 5, identifying Segment numbers 7-11 and 21 that have been idled. 23 Segment Numbers 2, 10-12, 14-16, 20, 21 and 27 were withdrawn on the basis of additional documentation.#

420115016_Decision on Petition_07092014_text.pdf, page 1110 that EMPCo may pressure test such segments when Respondent plans to reintroduce hazardous liquids. In the event hazardous liquid operations will be resumed on an idled segment, that segment must be pressure tested prior to resuming operations, unless EMPCo demonstrates the segment has already been tested in accordance with Subpart E. Accordingly, these pipelines remain subject to the Compliance Order as modified below. 5. Additional Penalty Considerations In its Petition, EMPCo requested reconsideration of the civil penalty assessed in the Final Order. EMPCo offered several reasons to reduce the penalty. First, EMPCo argued the penalty should be reduced because EMPCo provided additional pressure test documentation for many of the pipeline segments. PHMSA agrees that pressure test records were provided to warrant withdrawing 12 pipeline segments. Therefore the civil penalty is reduced to reflect the withdrawal of these segments from the violation. Second, EMPCo argued the penalty should be reduced because the engineering assessments conducted for two segments met applicable legal requirements under § 195.303. PHMSA disagrees as set forth above, and does not reduce the civil penalty for this reason. Third, EMPCo argued the penalty should be reduced because some segments are intrastate pipelines regulated by the TRRC. For the reasons discussed above, PHMSA is not withdrawing the violation or civil penalty for the one segment that implicates this issue. Fourth, EMPCo argued the penalty should be reduced because several additional segments were subsequently pressure tested. PHMSA does not find cause to reduce the penalty for corrective action taken after OPS identified the violations.24 Fifth, EMPCo argued the penalty should be reduced because several segments are presently idled. PHMSA does not find cause to reduce the penalty for idling pipelines after the violations already occurred. Sixth, EMPCo argued the penalty should be reduced because none of the segments pose a risk to safety or the environment. PHMSA already addressed the risks posed by the violations in the Final Order when it found the nature, circumstances, and gravity of the violations warranted the penalty. PHMSA finds no cause to reduce the penalty under these assessment considerations. Finally, EMPCo argued the penalty should be reduced because the company exhibited good faith in attempting to comply with the regulations. PHMSA confirms that EMPCo demonstrated it did not commit violations with respect to 12 of the 19 pipeline segments, and therefore those segment and associated civil penalties are withdrawn. PHMSA does not find sufficient justification to reduce the penalty further under the good faith consideration for the remaining violations. 24 See City of Richmond, Virginia, CPF No. 1-2011-0001, at 5, 2012 WL 4846325 (Aug. 1, 2012) (stating PHMSA does not generally find cause to reduce a civil penalty for corrective action taken after the operator has been notified of the deficiency through a compliance inspection).#

420115016_Decision on Petition_07092014_text.pdf, page 1211 In summary, PHMSA is reducing the civil penalty as set forth below to reflect the withdrawal of 12 of the 19 segments from the violation. ASSESSMENT OF PENALTY The Final Order assessed a total civil penalty of $112,300, which included $102,300 for the violation of § 195.302 (Item 1) and $10,000 for the violation of § 195.452(h)(2) (Item 2). EMPCo did not request reconsideration of the civil penalty for Item 2. The $102,300 civil penalty for Item 1 in the Final Order was based on 19 segments that were found in violation. In this Decision on Petition for Reconsideration, PHMSA is withdrawing 12 of the 19 segments from the violation. Accordingly, PHMSA is reducing the civil penalty for Item 1 from $102,300 to $91,500. The reduced penalty is for 7 segments that were in violation As explained in the Final Order, when a civil penalty is assessed for more than one instance of a violation, such as 7 segments without pressure tests, the majority of the penalty is for having one segment in violation with each additional segment increasing the penalty by a smaller amount. Accordingly, the total civil penalties due in this case for the violations of § 195.302 (Item 1) and § 195.452(h)(2) (Item 2) are $101,500. Payment of the civil penalty must be made within 20 days of service of this Decision. Federal regulations (49 C.F.R. § 89.21(b)(3)) require such payment to be made by wire transfer through the Federal Reserve Communications System (Fedwire), to the account of the U.S. Treasury. Detailed instructions are contained in the enclosure. Questions concerning wire transfers should be directed to: Financial Operations Division (AMK-325), Federal Aviation Administration, Mike Monroney Aeronautical Center, P.O. Box 269039, Oklahoma City, Oklahoma 73125. The Financial Operations Division telephone number is (405) 954-8845. Failure to pay the $101,500 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 Final Order included a Compliance Order requiring EMPCo to take certain corrective action to comply with the pipeline safety regulations. Based on the foregoing considerations, Item 1 of the Compliance Order is revised to read as follows: 1. With respect to the violation of § 195.302 (Item 1), Respondent must prepare a plan to perform pressure testing of the 7 pipeline segments identified in the Final Order as#

420115016_Decision on Petition_07092014_text.pdf, page 1312 Segment Numbers 3-5, 7-9, and 25, which are also listed on the 1998 Spreadsheet (Exhibit 1-2 of the Violation Report, incorporated by reference). Respondent must submit the plan to the Director for review and approval within 30 days of receipt of the Decision on Petition for Reconsideration. The plan must meet applicable pipeline safety requirements in 49 C.F.R. Part 195, including those in Subpart E, and must include a schedule for pressure testing each segment within 1 year from receipt of the Decision. A pipeline segment must be pressure tested under this Compliance Order unless the Director determines in writing to Respondent that one of the following conditions applies: a. Respondent demonstrates the segment has already been tested in accordance with b. c. Subpart E. Respondent demonstrates the segment contains no hazardous liquids, and Respondent has adopted written procedures to pressure test the pipeline prior to the reintroduction of hazardous liquids on the segment. Respondent demonstrates the segment is an intrastate pipeline subject to the regulatory responsibility of a State authority under 49 U.S.C. § 60105, and Respondent confirms the segment has been tested in accordance with the authority’s Subpart E equivalent. All other terms of the Final Order, including terms of the Compliance Order not otherwise modified in this Decision, remain in effect. The stay issued by PHMSA on August 2, 2013, is hereby terminated. This Decision constitutes final agency action taken by PHMSA in the enforcement proceeding. The terms and conditions of this Decision are effective upon service in accordance with 49 C.F.R. § 190.5. _____________________________ ____________________ Jeffrey D. Wiese Date Issued Associate Administrator for Pipeline Safety#