# HOLLY ENERGY PARTNERS - OPERATING, L.P. — Notice of Probable Violation - **operation:** document - **citation:** CPF 420105005 - **title:** HOLLY ENERGY PARTNERS - OPERATING, L.P. — Notice of Probable Violation - **source type:** enforcement - **agency:** Pipeline and Hazardous Materials Safety Administration - **status:** historical - **official:** true - **published on:** 2010-01-20 - **effective on:** Not available - **summary:** CLOSED notice of probable violation citing 195.310(a), 195.402(c)(13), 195.402(c)(6), 195.410(a)(1), 195.432(d), 195.571, 195.573(e). - **machine formats:** - **json:** https://regulus.evalyn.ai/document/phmsa-enforcement-420105005.json - **markdown:** https://regulus.evalyn.ai/document/phmsa-enforcement-420105005.md - **app url:** https://regulus.evalyn.ai/document/phmsa-enforcement-420105005 - **source url:** https://primis.phmsa.dot.gov/enforcement-data/case/420105005 **body:** Notice of Probable Violation involving HOLLY ENERGY PARTNERS - OPERATING, L.P.. PHMSA's enforcement data identifies the cited regulations as 195.310(a), 195.402(c)(13), 195.402(c)(6), 195.410(a)(1), 195.432(d), 195.571, 195.573(e). The case was opened on 2010-01-20 and is reported as closed as of 2011-04-15. Proposed civil penalty: $92,500. Assessed civil penalty: $92,500. Open the official case record for notices, responses, orders, and the latest status. Official case documents: 420105005_FinalOrder_03302011.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420105005/420105005_FinalOrder_03302011.pdf 420105005_FinalOrder_03302011_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420105005/420105005_FinalOrder_03302011_text.pdf 420105005_NOPV PCP PCO_01202010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420105005/420105005_NOPV%20PCP%20PCO_01202010.pdf 420105005_NOPV PCP PCO_01202010_text.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420105005/420105005_NOPV%20PCP%20PCO_01202010_text.pdf 420105005_Response to NOPV PCP PCO_02222010.pdf: https://primis.phmsa.dot.gov/enforcement-documents/420105005/420105005_Response%20to%20NOPV%20PCP%20PCO_02222010.pdf 420105005_NOPV PCP PCO_01202010_text.pdf NOTICE OF PROBABLE VIOLATION PROPOSED CIVIL PENALTY and PROPOSED COMPLIANCE ORDER CERTIFIED MAIL - RETURN RECEIPT REQUESTED January 20, 2010 Mr. Mark Cunningham, P. E. Vice President, Operations Holly Energy Partners 100 Crescent Court, Suite 1600 Dallas, TX 75201-6927 CPF 4-2010-5005 Dear Mark Cunningham: On November 30 though December 3, 2009, representatives of the Pipeline and Hazardous Materials Safety Administration (PHMSA) inspected your River and Trust Pipelines in Big Spring, Abilene, and Wichita Falls, TX, pursuant to Chapter 601 of 49 United States Code. 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. §195.310 Records. (a) A record must be made of each pressure test required by this subpart, and the record of the latest test must be retained as long as the facility tested is in use. Holly Energy Partners (HEP) informed PHMSA representatives that records of the pressure test for three of eleven pipeline segments were missing, and that HEP was attempting to locate them. HEP is required to retain these records for as long as the facility tested is in use. A spreadsheet titled Pipeline Maximum Operating Pressures summarizing the pipeline segment test pressures and MOPs was provided by HEP to the PHMSA representatives during the records review at the HEP Big Springs office location on November 30, 2009. The spreadsheet listed eleven Trust Pipeline System pipeline segments and relevant materials and testing information for use in the calculation of the MOP. The spreadsheet indicated the following three segments had no test records: System Segment X-6 Big Spring to Hawley 6 / 8 Colorado City to Merkel 6 / 8 Throckmorton to Archer The operator voluntarily reduced the operating pressure to 80% of the normal operating pressure prior to the PHMSA inspection. Additionally, HEP indicated that they were continuing to attempt to locate these records, and that if they were not located, it was their intention to re-test these three pipeline segments. HEP must have records conforming to 49 CFR 195.310 that demonstrate the three segments identified above have been pressure tested in accordance with Subpart E of 49 CFR 195. 2. §195.402 Procedural manual for operations, maintenance, and emergencies. (c) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following to provide safety during maintenance and normal operations: (5) Analyzing pipeline accidents to determine their causes. (6) Minimizing the potential for hazards identified under paragraph (c)(4) of this section and the possibility of recurrence of accidents analyzed under paragraph (c)(5) of this section. HEP had two accidents that were reportable to PHMSA, one in 2005 and a second in 2006. Both accidents were a result of second party excavation by the same contractor performing remediation work on HEP’s pipeline. HEP was unable to produce a written accident investigation and could not demonstrate revisions to their damage prevention program resulting from any investigations related to either accident. 2 HEP could not demonstrate that an investigation for the accident reported under PHMSA Hazardous Liquid Accident Report ID 20050342 occurred. HEP could not produce documents related to the determination of the cause and minimizing the recurrence, and the procedures failed to achieve the desired results as demonstrated by the second event reported under PHMSA Hazardous Liquid Accidents Report ID 20060309. Similarly, HEP could not demonstrate that an investigation had occurred for this accident. 3. §195.402 Procedural manual for operations, maintenance, and emergencies. (13) Periodically reviewing the work done by operator personnel to determine the effectiveness of the procedures used in normal operation and maintenance and taking corrective action where deficiencies are found. Two second party excavation accidents occurred in 2005 and 2006, but HEP was unable to demonstrate that a procedural review or revision to the damage prevention procedure 23.1 HEP- O&M-195.442(Damage Prevention Program) had occurred. The excavation accidents were by the same contractor, performing similar work and occurred a year apart. These events indicate potential procedural deficiencies in multiple areas relating to Contractor Oversight, Operator Qualifications, Excavation and Trenching, Damage Prevention, and Accident Investigation, yet no documentation of procedural reviews for any of these procedures could be provided, and the change log maintained to document that procedures are reviewed indicated no revisions to these procedures resulting from an accident investigation or effectiveness review. 4. §195.410 Line markers. (a) Except as provided in paragraph (b) of this section, each operator shall place and maintain line markers over each buried pipeline in accordance with the following: (1) Markers must be located at each public road crossing, at each railroad crossing, and in sufficient number along the remainder of each buried line so that its location is accurately known. HEP has placed line markers along fence lines at road crossings, but has not consistently placed them in the right of ways of rural locations. Looking from the roadway in several locations identified in the field inspection, the PHMSA inspector, and the HEP Compliance Manager were unable to identify the location of the pipeline, or its route. This was particularly noticeable in remote locations. The requirement of 49 CFR 195.410 does not make a distinction between rural or populated areas and the pipeline should be accurately markers so that its location is known. 3 5. §195.432 Inspection of in-service breakout tanks. (b) Each operator shall inspect the physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according to section 4 of API Standard 653. However, if structural conditions prevent access to the tank bottom, the bottom integrity may be assessed according to a plan included in the operations and maintenance manual under §195.402(c)(3). (d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator's last recorded date of the inspection, whichever is earlier. HEP acquired the Wichita Falls Terminal facilities in 2005. Internal inspection summary reports were provided to HEP from the previous owner that indicated an API Standard 653 (API 653) internal inspection was performed on tanks 8 and 9 at the Wichita Falls Terminal in 1996. HEP relied upon these inspection reports to establish the next internal inspection intervals and set the internal inspection intervals to the API 653 maximum of 20 years for Tanks 8 and 9. Based upon this interval, HEP has not performed an internal inspection of these two tanks since 1996, and an internal inspection was scheduled for both tanks for the year 2016. The inspection report of Tank 8, dated 03-04-96, indicated the inspection was due to suspected tank bottom leakage. Additionally, a change of product from the product that had been stored in this tank from diesel to jet fuel was anticipated at the time of the 1996 internal inspection. The report included a sketch of the floor inspection results and indicated 8 holes in the tank bottom. The report did not indicate whether the holes were from topside or bottom-side corrosion. Also, the inspection did not establish a topside or bottom-side corrosion rate, and HEP could not provide the inspectors with a corrosion rate for the calculation of the inspection interval. Repairs to the tank bottom were recommended in the report, but documentation demonstrating the recommended repairs had been made was not available. The report recommended installation of a tank bottom topside coating to prevent further corrosion. Records of the product, its installation or service life were not available. API 653 Section 6.4.2 describes the method for establishing the inspection intervals for internal inspections. Section 6.4.2 requires the calculation of the internal inspection intervals in accordance with Section 4.4.7 of the standard, with a maximum internal inspection interval of 20 years. If, however, the corrosion rates are unknown, the maximum inspection interval is not to exceed 10 years, unless similar service experience is available to estimate the bottom plate thickness at the next inspection. HEP failed to demonstrate that they had established a corrosion rate for the tank bottoms of Tanks 8 and 9, and exceeded the 10 year maximum internal inspection interval for unknown corrosion rates in 2007. Additionally, HEP did not have similar service experience, or procedures to apply similar service experience available to make this inspection interval determination. 4 HEP failed to inspect Tanks 8 and 9 at the Wichita Falls Terminal within the maximum 10 year interval in accordance with API 653. 6. §195.571 What criteria must I use to determine the adequacy of cathodic protection? Cathodic protection required by this subpart must comply with one or more of the applicable criteria and other considerations for cathodic protection contained in paragraphs 6.2 and 6.3 of NACE Standard RP 0169 (incorporated by reference, see §195.3). The records for the pipe to soil readings on the River and Trust pipelines for the years 2005 to 2009 were reviewed by the PHMSA representatives. During this review, the following readings were observed to not meet the minimum criteria established by HEP for cathodic protection. Additionally, when further questioned, HEP indicated that there was no other criteria that applied to establishing the minimum acceptable values for the River and Trust specific pipe to soil readings than a pipe to soil reading of -0.850 V ON because they had not performed a depolarized survey to establish the criteria that would allow application of the 250 millivolt criteria in their procedure. HEP’s procedures for corrosion control adopt two criteria for the cathodic protection of its pipelines. HEP’s procedure number O&M – 195.563 Cathodic Protection states that: “Sufficient current must flow from soil to pipe to maintain a constant voltage difference at the soil-metal interface of 0.25 volt (approximately -0.85 volt between pipe and copper sulfate electrode in contact with soil) or more.” The following readings failed to meet criteria: Reading Date Milepost Location Pipe to Soil (V) Read 10/27/2005 103.200 TEPPCO X-ing -0.794 12/08/2006 -0.776 12/28/2007 -0.799 09/30/2008 -0.593 10/27/2005 103.400 Co. Rd Rectifier TR #103 -0.843 12/08/2006 -0.829 12/28/2007 -0.823 09/30/2008 -0.608 11/02/2005 103.401 TEX-NEW MEX X-ING -0.841 12/08/2006 -0.832 12/28/2007 -0.825 109/30/2008 T/L Destroyed 11/02/2005 103.900 Conoco X-ing -0.810 12/08/2006 -0.852 5 12/28/2007 -0.795 09/30/2008 -0.502 11/02/2005 110.000 Conoco X-ing -0.772 12/09/2006 -0.751 12/28/2007 -0.795 11/02/2005 110.001 Co. Rd. -0.768 12/09/2006 -0.746 11/02/2005 110.400 Conoco X-ing (Field) -0.844 12/09/2006 -0.811 11/02/2005 111.000 FM Road (South) -0.779 12/09/2006 -0.776 11/02/2005 111.700 FM 1954 -0.859 12/09/2006 -0.764 HEP failed to demonstrate adequate cathodic protection levels were maintained for the locations identified above by failing to meet the criteria specified in their corrosion control procedures. HEP has corrected the conditions identified herein with the installation of two additional rectifiers and all readings taken in 2009 were at or above the minimum specified criteria. 7. §195.573 What must I do to monitor external corrosion control? e) Corrective action. You must correct any identified deficiency in corrosion control as required by §195.401(b). During the interview at the Big Spring office on December 1, 2009, HEP indicated that their criteria for effective cathodic protection on the River and Trust Pipelines was – 0.850 V ON, and that the system had not had electrical surveys preformed to establish the native potentials for use with -250 mV criteria. This was confirmed by PHMSA’s review of HEP’s procedure HEP-H- 195-002 - Corrosion Control. During the discussion of these readings, HEP also stated that the appropriate timing for corrective actions related to deficient pipe to soil readings was one year, or prior to the next annual inspection, and the corrective action was that the pipe to soil reading level should be brought up to the minimum criteria. HEP could not demonstrate information contained within their corrosion procedures that specified the timing of corrective actions or the definition of “prompt” as it pertained to the correction of pipe to soil readings that failed to meet minimum criteria. The records for all test post pipe to soil readings on the River and Trust for the years 2005 to 2009 were reviewed by PHMSA representatives. During this review, the following locations were observed to not meet the minimum criteria established by HEP for cathodic protection for more than one inspection cycle. The readings that are shown in the following list are included to establish when these locations were brought into compliance with the minimum criteria necessary to demonstrate adequate cathodic protection. 6 Reading Date Milepost Location Pipe to Soil (V) Read 11/03/2009 103.200 TEPPCO X-ing -1.522 11/03/2009 103.400 Co. Rd Rectifier TR #103 -1.974 11/03/2009 103.401 TEX-NEW MEX X-ING -1.845 11/03/2009 103.900 Conoco X-ing -1.434 09/30/2008 110.000 Conoco X-ing -1.246 12/28/2007 110.001 Co. Rd. -1.412 12/28/2007 110.400 Conoco X-ing (Field) -1.929 12/28/2007 111.000 FM Road (South) -1.801 12/28/2007 111.700 FM 1954 -1.768 HEP failed to promptly evaluate and correct the deficiencies in corrosion control indicated by the pipe to soil readings listed above. All readings appeared have been brought up to minimum levels as demonstrated by the readings taken during the 2009 annual survey. Warning Items With respect to items 3 and 4, we have reviewed the circumstances and supporting documents involved in this case and have decided not to conduct additional enforcement action or penalty assessment proceedings at this time. We advise you to promptly correct these item(s). Be advised that failure to do so may result in HEP being subject to additional enforcement action. 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 $92,500 as follows: Item number PENALTY 2 $22,500 6 $35,000 7 $35,000 Proposed Compliance Order With respect to items 1 and 5 above, pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration proposes to issue a Compliance Order to Holly Energy Partners. Please refer to the Proposed Compliance Order, which is enclosed and made a part of this Notice. 7 Response to this Notice Enclosed as part of this Notice is a document entitled Response Options for Pipeline Operators in Compliance Proceedings. Please refer to this document and note the response options. Be advised that all material you submit in response to this enforcement action is subject to being made publicly available. If you believe that any portion of your responsive material qualifies for confidential treatment under 5 U.S.C. 552(b), along with the complete original document you must provide a second copy of the document with the portions you believe qualify for confidential treatment redacted and an explanation of why you believe the redacted information qualifies for confidential treatment under 5 U.S.C. 552(b). If you do not respond within 30 days of receipt of this Notice, this constitutes a waiver of your right to contest the allegations in this Notice and authorizes the Associate Administrator for Pipeline Safety to find facts as alleged in this Notice without further notice to you and to issue a Final Order. In your correspondence on this matter, please refer to CPF 4-2010-5005 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 8 PROPOSED COMPLIANCE ORDER Pursuant to 49 United States Code § 60118, the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposes to issue to Holly Energy Partners (HEP) a Compliance Order incorporating the following remedial requirements to ensure the compliance of HEP with the pipeline safety regulations: 1. In regard to Item Number 1 of the Notice pertaining to missing pressure testing records, HEP shall maintain the 20% pressure reduction for the segments identified below until such time HEP provides records to PHMSA that conform to the requirements of 49 CFR 195.310 and demonstrate the three segments identified below have been pressure tested in accordance with Subpart E of 49 CFR 195. System Segment X-6 Big Spring to Hawley 6 / 8 Colorado City to Merkel 6 / 8 Throckmorton to Archer Additionally, HEP’s relevant pressure testing and record retention procedures should be expanded to include the accountabilities, process and storage location to ensure that critical records are retained for as long as the facility tested is in use. 2. In regard to Item Number 5 of the Notice pertaining to exceeding the maximum API Standard 653 internal inspection interval for breakout tanks numbers 8 and 9 at Wichita Falls Terminal, HEP shall remove the tanks from service until such time that an API 653 internal inspection has been performed by a qualified party, and all deficiencies identified during the inspection requiring action have been addressed. 3. The timing for Items 1 and 2 is proposed as follows: Item 1: Provide pressure test records to PHMSA, SW Region Director no later than 180 days from the Final Order. Item 5: Remove tanks 8 and 9 from service no later than 30 days from the Final Order. These tanks shall remain out of service until the inspection has been performed and documentation submitted to the SW region Director and approval to return to service has been granted. 4. HEP shall maintain documentation of the safety improvement costs associated with fulfilling this Compliance Order and submit the total to R. M. Seeley, Director, SW Region, Pipeline and Hazardous Materials Safety Administration. Costs shall 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. 9 420105005_FinalOrder_03302011_text.pdf MAR 30 2011 Mr. Mark Cunningham Vice President – Operations Holly Energy Partners, L.P. 100 Crescent Court Suite 1600 Dallas, TX 75201 Re: CPF No. 4-2010-5005 Dear Mr. Cunningham: Enclosed please find the Final Order issued in the above-referenced case. It makes findings of violation and assesses a civil penalty of $92,500. It further finds that Holly Energy Partners, L.P. has completed the actions specified in the Notice to comply with the pipeline safety regulations. When the civil penalty has been paid, this enforcement action will be closed. Service of the Final Order by certified mail is deemed effective upon the date of mailing, or as otherwise provided under 49 C.F.R. § 190.5. Thank you for your cooperation in this matter. Sincerely, Jeffrey D. Wiese Associate Administrator for Pipeline Safety Enclosure cc: Mr. Rod M. Seeley, Director, Southwest Region, PHMSA CERTIFIED MAIL - RETURN RECEIPT REQUESTED [7005 1160 0001 0077 5503] U.S. DEPARTMENT OF TRANSPORTATION PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION OFFICE OF PIPELINE SAFETY WASHINGTON, D.C. 20590 ____________________________________ In the Matter of ) Holly Energy Partners, L.P., ) CPF No. 4-2010-5005 ) ) ) Respondent. ) ____________________________________) FINAL ORDER Between November 30, 2009 and December 3, 2009, pursuant to 49 U.S.C. § 60117, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS), conducted an on-site pipeline safety inspection of the facilities known as the River and Trust pipelines in Big Springs, Abilene, and Wichita Falls, Texas. The River and Trust pipelines system is approximately 273 miles long and transports refined products.1 These pipeline facilities are owned and operated by Holly Energy Partners, L.P. (Holly Energy or Respondent), which through its subsidiaries, owns or leases approximately 2,500 miles of petroleum product pipelines.2 As a result of the inspection, the Director, Southwest Region, OPS (Director), issued to Respondent, by letter dated January 20, 2010, a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (Notice). In accordance with 49 C.F.R. § 190.207, the Notice proposed finding that Holly Energy had committed various violations of 49 C.F.R. Part 195, proposed assessing a civil penalty of $92,500 for the alleged violations, and proposed ordering Respondent to take certain measures to correct two of the alleged violations. The Notice also proposed finding that Respondent had committed certain other probable violations of 49 C.F.R. Part 195 and warning Respondent to take appropriate corrective action or be subject to future enforcement action. Holly Energy responded to the Notice by letters dated February 22, 2010, March 19, 2010, and April 16, 2010, April 26, 2010, and April 28, 2010 (collectively, Response). Holly Energy initially contested two of the allegations, presented information seeking mitigation of the proposed penalty, and requested a hearing. By letter dated March 19, 2010, Respondent 1 Pipeline Safety Violation Report (Violation Report), (November 30, 2009 through December 3, 2009), at 1. 2 Holly Corporation, http://www.hollycorp.com (last visited February 17, 2011). See also SEC Form 10-K, Holly Energy Partners, L.P., February 16, 2011, at 5. 2 withdrew its request for a hearing and thereby authorized the entry of this Final Order without further notice.3 FINDINGS OF VIOLATION In its Response, Holly Energy did not contest the allegations in the Notice that it violated 49 C.F.R. Part 195 as follows: Item 1: The Notice alleged that Respondent violated 49 C.F.R. § 195.310(a), which states: § 195.310 Records. (a) A record must be made of each pressure test required by this subpart, and the record of the latest test must be retained as long as the facility tested is in use. The Notice alleged that Respondent violated 49 C.F.R. § 195.310(a) by failing to retain records of the latest pressure tests for three of its eleven pipeline segments. Holly Energy was required to retain these records for as long as the facility tested is in use. Specifically, the Notice alleged that during the November 30, 2009 inspection at the Big Springs office location, Holly Energy informed the PHMSA inspector that the records of the pressure test for three of eleven pipeline segments were missing. Although Holly Energy took precautionary action by reducing the maximum operating pressure by 20%, it could not produce documentation of the test charts and readings for the following pipeline system segments: Trust X-6 – Big Spring to Hawley, Trust 6/8 – Colorado City to Merkel, and Trust 6/8 – Throckmorton to Archer. Holly Energy must retain these records to demonstrate that these segments have been pressure tested in accordance with Subpart E of Part 195. In its Response, Holly Energy did not contest this allegation of violation and instead noted its intent to retest these pipeline segments. On April 16, 2010, Holly Energy sent a subsequent response confirming that they had retested these pipeline segments and providing the hydrostatic test report for PHMSA’s review. PHMSA has confirmed that the results were satisfactory. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.310(a) by failing to retain records of the latest pressure tests for three of its eleven pipeline segments. Item 2: The Notice alleged that Respondent violated 49 C.F.R. § 195.402(c)(6) which states: 3 In its Response dated February 22, 2010, Holly Energy initially requested a hearing to address Items 1 and 5 contained in the Notice. By letter dated March 19, 2010, Respondent withdrew its request for a hearing and thereby authorized the entry of this Final Order without further notice. 3 § 195.402 Procedural manual for operations, maintenance, and emergencies. (a) …. (c) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following to provide safety during maintenance and normal operations…. (6) Minimizing the potential for hazards identified under paragraph (c)(4) of this section and the possibility of recurrence of accidents analyzed under paragraph (c)(5) of this section. The Notice alleged that Respondent violated 49 C.F.R. § 195.402(c)(6) by failing to have procedures to minimize the potential for hazards identified under paragraph (c)(4) and reduce the possibility of the recurrence of accidents analyzed under paragraph (c)(5). Section 195.402(c)(4) requires an operator to determine which pipelines would require an immediate response to prevent hazards to the public if a failure occurred and § 195.402(c)(5) requires an operator to analyze pipeline accidents to determine the cause. Although Holly Energy reported the 2005 and 2006 accidents under PHMSA Hazardous Liquid Accident Report IDs 20050342 – 5586 and 20060309 – 5584, Respondent was unable to produce documents related to an investigation to determine the cause and minimize the recurrence of these events. Further, Holly Energy was unable to demonstrate that it reviewed its damage prevention program after these two failures which were a result of second-party excavation by the same contractor. Respondent did not contest this allegation of violation but noted that the company was in the process of implementing detailed company procedures for incident investigations. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.402(c)(6) by failing to have procedures to minimize the potential for facilities hazards and the possibility of recurrence of accidents. Item 5: The Notice alleged that Respondent violated 49 C.F.R. § 195.432(d) which states: § 195.432 Inspection of in-service breakout tanks. (a) …. (b) Each operator shall inspect the physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according section 4 of API Standard 653. However, if structural conditions prevents access to the tank bottom, the bottom integrity may be assessed according to a plan included in the operations and maintenance manual under § 195.402(c)(3)…. 4 4 This regulation was amended on August 11, 2010, after the inspection occurred and the Notice was issued. The amendment eliminated the reference to Section 4 of API Standard 653. In addition, when this inspection occurred, API 653, 3rd edition, December 2001, including addendum 1 (2003) was incorporated by reference into the pipeline safety regulations. Effective October 1, 2010, PHMSA replaced this edition with API 653, 3rd edition, December 2001, including addendum 1 (September 2003), addendum 2 (November 2005), addendum 3 (February 2008), and errata (April 2008). The former edition is the version that applies in this case since it was controlling at the time of the inspection. 4 (d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator’s last recorded date of the inspection, whichever is earlier. The Notice alleged that Respondent violated 49 C.F.R. § 194.432(d) by failing to inspect in- service aboveground breakout tanks within the inspection intervals set forth in the API Standard 653 (“the Standard”), incorporated by reference in the pipeline safety regulations. Specifically, API 653, Section 6.4.2.1, requires that operators calculate internal inspection intervals “by corrosion rates measured during previous inspections or anticipated based on experience with tanks in similar service….in no case, however, shall internal inspection intervals exceed 20 years. ”5 However, if the corrosion rates are unknown and similar service experience is not available to estimate the bottom plate minimum thickness, the maximum inspection interval is not to exceed 10 years.6 The Notice alleged that Holly Energy could not provide a corrosion rate to establish the inspection interval for Tanks 8 and 9. Yet, it had set the internal inspection intervals at a maximum of 20 years for Tanks 8 and 9, scheduling the next inspection for 2016. Since the corrosion rate was unknown, the 10 year maximum interval for inspections of the tank bottom applies. Internal inspection summary reports provided to Holly Energy from the previous owner indicated that an API 653 internal inspection was performed on Tanks 8 and 9 at the Wichita Falls Terminal in 1996. Therefore, the next inspection should have occurred in 2006. In its Response dated February 22, 2010, Holly Energy did not contest the allegation. Instead, the company stated that it had emptied Tank 9 and removed it from service during the third quarter of 2009.7 In addition, Respondent stated that it removed Tank 8 from service in January 2010 to begin the inspection process and determine the corrosion rate in accordance with Section required to inspect these tanks in 2006 and failed to do so. 4.4.7 of API Standard 653.8 These facts are not relevant to the violation since Respondent was Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.432(d) by failing to inspect the in-service aboveground breakout tanks at the Wichita Falls Terminal within the inspection intervals set forth in the API Standard 653. Item 6: The Notice alleged that Respondent violated 49 C.F.R. § 195.571, which states: 5 AM. PETROLEUM INST, “TANK INSPECTION, REPAIR, ALTERATION, AND RECONSTRUCTION,” API STANDARD 653 §6.4.2.1 (December 2001). 6 API STANDARD 653 § 6.4.2.2. 7 Response dated February 22, 2010, at 2. 8 The repairs on Tank 8 were completed on February 17, 2010 and the tank was returned to service on April 15, 2010. 5 § 195.571 What criteria must I use to determine the adequacy of cathodic protection? Cathodic protection required by this subpart must comply with one or more of the applicable criteria and other considerations for cathodic protection contained in paragraphs 6.2 and 6.3 of NACE Standard RP 0169 (incorporated by reference, see § 195.3).9 The Notice alleged that Respondent violated 49 C.F.R. § 195.571 by failing to demonstrate adequate cathodic protection at multiple locations on its pipeline system. Specifically, Holly Energy was required to maintain adequate cathodic protection on its pipeline system to meet the minimum criteria established by its corrosion control procedures. Paragraph 6.1 of Holly Energy’s procedures, 6.0 HEP-O&M-195.563 (Cathodic Protection), states, in relevant part, that “[s]ufficient current must flow from soil to pipe to maintain a constant voltage difference at the soil-metal interface of 0.25 volt (approximately -0.85 volt between pipe and copper sulfate electrode in contact with soil) or more.”10 However, the Notice alleged that the PHMSA inspector reviewed pipe to soil readings for the annual survey periods for 2005-2008 for Mile Posts 103.2 to 111.7 of the Trust pipeline and the inspector found twenty-seven readings that did not meet this minimum criteria.11 In its Response, Holly Energy acknowledged that the records provided at the time of the inspection demonstrated that the minimum criteria were not met for the 2005-2008 annual surveys. The company noted that it corrected these conditions for the specified locations prior to the 2009 inspection by installing two additional rectifiers and all readings taken in 2009 were above or at the minimum criteria. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.571 by failing to demonstrate adequate cathodic protection at multiple locations on its pipeline system during the 2005-2008 survey periods. Item 7: The Notice alleged that Respondent violated 49 C.F.R. § 195.573(e), which states, in relevant part: § 195.573 What must I do to monitor external corrosion control? (a) …. (e) Corrective action. You must correct any identified deficiency in corrosion control as required by § 195.401(b)…. 9 When this inspection occurred, NACE Standard RP 0169-2002, “Control of External Corrosion on Underground or Submerged Metallic Piping Systems” was incorporated by reference into the pipeline safety regulations. Effective October 1, 2010, PHMSA replaced this edition with NACE SP0169-2007, Standard Practice, “Control of External Corrosion on Underground or Submerged Metallic Piping Systems”, reaffirmed March 15, 2007. The former edition is the version that applies in this case since it was controlling at the time of the inspection. 10 O&M Manual, Volume 2 – Section H-195-002 (Reviewed July 2009), 6.0 HEP-O&M-195.563 (Cathodic Protection), Paragraph 6.1, page 12. 11 Violation Report, at 5-6. 6 The Notice alleged that Respondent violated 49 C.F.R. § 195.573(e) by failing to correct deficiencies in corrosion control as required by § 195.401(b). The latter regulation requires operators to correct any condition that could adversely affect the safe operation of its pipeline within a reasonable time.12 Specifically, the Notice alleged that Holly Energy did not correct the deficiencies in corrosion control identified in Item 6 within a reasonable time. During the inspection, Respondent stated that the appropriate timing for these corrective actions was one year or before the next inspection, however, PHMSA inspectors confirmed that the corrosion control deficiencies persisted beyond one inspection cycle.13 Respondent did not contest this allegation of violation. In its Response, Holly Energy acknowledged that the corrosion control deficiencies were not corrected within the timeframes set forth in the company procedures. Respondent recognized and corrected this issue prior to the inspection by completing a test point survey on June 30, 2009. Accordingly, based upon a review of all of the evidence, I find that Respondent violated 49 C.F.R. § 195.573 by failing to timely correct deficiencies in corrosion control. Under 49 U.S.C. § 60122, Respondent is subject to an administrative civil penalty not to exceed $100,000 per violation for each day of the violation, up to a maximum of $1,000,000 for any related series of violations. In determining the amount of a civil penalty under 49 U.S.C. § 60122 and 49 C.F.R. § 190.225, I must consider the following criteria: the nature, circumstances, and gravity of the violation, including adverse impact on the environment; the degree of Respondent’s culpability; the history of Respondent’s prior offenses; the Respondent’s ability to pay the penalty and any effect that the penalty may have on its ability to continue doing business; and the good faith of Respondent in attempting to comply with the pipeline safety regulations. In addition, I may consider the economic benefit gained from the violation without any reduction because of subsequent damages, and such other matters as justice may require. The Notice proposed a total civil penalty of $92,500 for the violations cited above. Item 2: The Notice proposed a civil penalty of $22,500 for Respondent’s violation of 49 C.F.R. § 195.402(c)(6), for by failing to have procedures to minimize the potential for hazards identified under paragraph (c)(4) and reduce the possibility of the recurrence of accidents analyzed under paragraph (c)(5). In its Response dated February 22, 2010, Holly Energy argued that it recognized the deficiency in its process and has recognized that more in-depth procedural steps and a formalized process are required to ensure that documentation is maintained. While Holly Energy has proposed modifications to its accident investigation and damage prevention programs under the NOA that was issued at the same time as this Notice, and the company’s response to the NOA proposes revisions to its procedures, these changes occurred after the 2005 and 2006 accidents and therefore do not cure the violation. Holly Energy’s two ASSESSMENT OF PENALTY 12 See 49 C.F.R. § 195.401(b). 13 Notice, at 6. 7 excavation accidents posed significant risk to public safety and the environment. Accordingly, having reviewed the record and considered the assessment criteria, I assess Respondent a civil penalty of $22,500 for violation of 49 C.F.R. § 195.402(c)(6). Item 6: The Notice proposed a civil penalty of $35,000 for Respondent’s violation of 49 C.F.R. § 195.571, for failing to demonstrate adequate cathodic protection at multiple locations on its pipeline system. In its Response dated February 22, 2010, Holly Energy indicated that it recognized the deficiencies in its cathodic protection procedures and corrected the conditions in 2009, prior to the inspection. Specifically, Holly Energy installed two additional rectifiers on the affected segments which provided adequate cathodic protection. Although Holly Energy corrected this Item prior to PHMSA’s inspection, the violation persisted for four years. Holly Energy’s pipe-to-soil readings for the Trust pipeline between Mile Posts 103.2 and 111.7 failed to meet the minimum criteria for the 2005, 2006, 2007, and 2008 annual surveys. Therefore, the corrective actions taken in the year 2009 do not cure the violation. Holly Energy’s failure to adequately protect the pipeline from external corrosion by cathodic protection increases the risk of corrosion failures and increases the likelihood of active corrosion occurring. Additionally, Holly Energy’s failure to maintain adequate cathodic protection can lead to metal loss and possible through-wall corrosion failures that could have resulted in a release of product into the environment. Ac - **truncated:** true - **body characters:** 46567