AMAROQ RESOURCES, LLC — Warning Letter

520190012W_Warning Letter_02252019_text.pdf, page 1Official PDFWARNING LETTER CERTIFIED MAIL - RETURN RECEIPT REQUESTED February 25, 2019 Mr. Scott Pfoff President and CEO Aurora Exploration LLC 4645 Sweetwater Blvd., Suite 200 Sugarland, Texas 77479 CPF 5-2019-0012W Dear Mr. Pfoff: On August 20 through 22, 2018, a representative of the Pipeline and Hazardous Materials Safety Administration (PHMSA), pursuant to Chapter 601 of 49 United States Code (U.S.C.), inspected Aurora Exploration, LLC’s (Aurora’s) Nicolai Creek Pipeline System in west side of Cook Inlet, Alaska. As a result of the inspection, it is alleged that you have committed probable violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations (CFR). The items inspected and the probable violations are: 1. § 192.179 Transmission line valves. (a) .… (c) Each section of a transmission line, other than offshore segments, between main line valves must have a blowdown valve with enough capacity to allow the transmission line to be blown down as rapidly as practicable. Each blowdown discharge must be located so the gas can be blown to the atmosphere without hazard and, if the transmission line is adjacent to an overhead electric line, so that the gas is directed away from the electrical conductors.#

520190012W_Warning Letter_02252019_text.pdf, page 2The 6-inch Nicolai Creek South B pipeline lacks appropriate blow-down valves required by § 192.179(c). Although the segment could be blown down through the pig traps, this is not adequate to minimize the hazards during blow-down. Other valves installed on the segment are small diameter valves for instruments (e.g. pressure gauges) which are not sufficient in size to blow-down the pipe as quickly as practicable and do not discharge in locations that minimize the hazards of blow-down. 2. § 192.465 External corrosion control: Monitoring. (a) .… (c) Each reverse current switch, each diode, and each interference bond whose failure would jeopardize structure protection must be electrically checked for proper performance six times each calendar year, but with intervals not exceeding 21∕2 months. Each other interference bond must be checked at least once each calendar year, but with intervals not exceeding 15 months. The operator failed to inspect each impressed current power source six times per calendar year at intervals not exceeding 2-1/2 months. The Nicolai Creek pipeline system’s impressed current power source is from a bond to another operator’s pipeline. Records indicate that the operator tested this bond on the following dates: 6/11/18; 4/10/18; 2/12/18, 4/2/17; 2/7/17; 10/14/16, and 8/15/16. 3. § 192.475 Internal corrosion control: General (a) .… (b) Whenever any pipe is removed from a pipeline for any reason, the internal surface must be inspected for evidence of corrosion. If internal corrosion is found— (1) The adjacent pipe must be investigated to determine the extent of internal corrosion; (2) Replacement must be made to the extent required by the applicable paragraphs of §§192.485, 192.487, or 192.489; and (3) Steps must be taken to minimize the internal corrosion. The operator failed to inspect the internal surface of the pipe whenever pipe was removed as required by § 192.475(b). The operator stated that in 2015 a new pig trap was installed on the Nicolai Creek South B Pipeline and during that time the internal surfaces of the pipeline were exposed. However, the operator failed to conduct (or failed to document) an evaluation of the interior of the pipeline for internal corrosion. 4. § 192.481 Atmospheric corrosion control: Monitoring. (a) Each operator must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows: 2#

520190012W_Warning Letter_02252019_text.pdf, page 3If the pipeline is located: Then the frequency of inspection is: Onshore At least once every 3 calendar years, but with intervals not exceeding 39 months Offshore At least once each calendar year, but with intervals not exceeding 15 months The operator failed to conduct atmospheric corrosion inspections as required by § 192.481(a). The operator stated that they had not conducted atmospheric corrosion inspections, which is consistent with their lack of records. 5. § 192.481 Atmospheric corrosion control: Monitoring. (a) .… (c) If atmospheric corrosion is found during an inspection, the operator must provide protection against the corrosion as required by § 192.479. The operator failed to remediate atmospheric corrosion and general coating failures as required by § 192.481(c). During the inspection, PHMSA observed external corrosion and coating failures on the insulated piping spools at the pigging facility where the Nicolai Creek South A (4-inch) pipeline ends and the Nicolai Creek South B (6-inch) pipeline begins. 6. § 192.605 Procedural manual for operations, maintenance, and emergencies. (a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least once each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. The operator failed to review and update their procedures for operations and maintenance activities and emergency response at intervals not exceeding 15 months, but at least once each calendar year: • Operations and Maintenance tasks are described in a series of procedures. The operator's officials approved these various procedures in late 2014 through early 2015. For example, the procedure AG-15-OM-Rev1 “Valve Inspection & Maintenance” was approved by the two Production Supervisors and the Manager of Production Operations and Engineering on 1/29/15, 12/18/14, and 12/18/14 respectively. Since then, the operator has not documented a review or revision of these procedures. During the inspection, the operator stated that they have not reviewed or updated the procedures, which is consistent with the lack of records. • Company officials approved Emergency Response Plan (AG-71-EP-REV1, "ERP") in late 2014 through early 2015. The ERP was approved by the two Production 3#

520190012W_Warning Letter_02252019_text.pdf, page 4Supervisors and the Manager of Production Operations and Engineering on 1/29/15, 12/18/14, and 12/18/14 respectively. Since then, the operator has not documented a review or revision of the plan. During the inspection, the operator stated that they have not reviewed or updated the procedures, which is consistent with the lack of records. 7. § 192.705 Transmission lines: Patrolling. (a) .… (b) The frequency of patrols is determined by the size of the line, the operating pressures, the class location, terrain, weather, and other relevant factors, but intervals between patrols may not be longer than prescribed in the following table: Maximum interval between patrols Class location of line At highway and railroad At all other places crossings 1, 2 71∕2 months; but at least twice 15 months; but at least once each each calendar year calendar year. 3 41∕2 months; but at least four 71∕2 months; but at least twice each times each calendar year calendar year. 4 41∕2 months; but at least four 41∕2 months; but at least four times times each calendar year each calendar year. The operator failed to adequately document patrols of the pipeline surface at the required intervals. The operator stated that field personnel regularly patrol the right of way and surfaces adjacent to the pipeline, but that they only document the patrols annually in conjunction with their annual leakage survey. The operator provided records of the patrol and leakage survey for 2016 and 2018, but the operator stated they did not conduct the required patrol in the 2017 calender year. 8. § 192.706 Transmission lines: Leakage surveys. Leakage surveys of a transmission line must be conducted at intervals not exceeding 15 months, but at least once each calendar year. However, in the case of a transmission line which transports gas in conformity with § 192.625 without an odor or odorant, leakage surveys using leak detector equipment must be conducted— (a) In Class 3 locations, at intervals not exceeding 71∕2 months, but at least twice each calendar year; and (b) In Class 4 locations, at intervals not exceeding 41∕2 months, but at least four times each calendar year. The operator failed to conduct leakage surveys at intervals not exceeding 15 months, but at least once per calendar year. The operator completed and documented leakage surveys in March of 2016 and 2018 but failed to do so in 2017. The operator stated they did not conduct the required leakage survey in the 2017 calender year. 4#

520190012W_Warning Letter_02252019_text.pdf, page 59. § 192.739 Pressure limiting and regulating stations: Inspection and testing. (a) Each pressure limiting station, relief device (except rupture discs), and pressure regulating station and its equipment must be subjected at intervals not exceeding 15 months, but at least once each calendar year, to inspections and tests to determine that it is— (1) In good mechanical condition; (2) Adequate from the standpoint of capacity and reliability of operation for the service in which it is employed; (3) Except as provided in paragraph (b) of this section, set to control or relieve at the correct pressure consistent with the pressure limits of § 192.201(a); and (4) Properly installed and protected from dirt, liquids, or other conditions that might prevent proper operation. The operator failed to inspect and test each pressure relief device at intervals not exceeding 15 months, but at least once each calendar year. The operator stated during the inspection that it is their practice to replace pressure safety valves (PSVs) instead of testing and repairing them, but the operator had no records showing that replacement or inspection/testing had ever been done. The operator also could not specify which PSVs protect each pipeline segment and are subject to the requirements of 192.739. 10. § 192.745 Valve maintenance: Transmission lines. (a) Each transmission line valve that might be required during any emergency must be inspected and partially operated at intervals not exceeding 15 months, but at least once each calendar year. The operator failed to identify which valves are "emergency valves" that need to be maintained in accordance with 192.745. Their O&M Procedure (AG-15-OM-Rev 1) states that "[t]he Manager of Production Operations and Engineering shall determine which valves may be required in an emergency." However, during the inspection, the operator was unable to produce a list or valve maintenance worksheet or otherwise identify which valves are subject to § 192.745. The operator stated that field personnel occasionally service valves but they are not doing so in accordance with a documented process and have not produced records of such services. 11. § 192.807 Recordkeeping. Each operator shall maintain records that demonstrate compliance with this subpart. (a) .… (b) Records supporting an individual's current qualification shall be maintained while the individual is performing the covered task. Records of prior qualification and records of individuals no longer performing covered tasks shall be retained for a period of five years. The operator failed to retain records of individuals performing tasks for a period of five years. When PHMSA requested Operator Qualification (OQ) records during the inspection, the 5#

520190012W_Warning Letter_02252019_text.pdf, page 6operator stated that the vendor that previously provided OQ training and associated record keeping refused to release the records. Under 49 U.S.C. § 60122 and 49 CFR § 190.223, you are subject to a civil penalty not to exceed $213,268 per violation per day the violation persists, up to a maximum of $2,132,679 for a related series of violations. For violations occurring on or after November 2, 2015 and before November 27, 2018, the maximum penalty may not exceed $209,002 per violation per day, with a maximum penalty not to exceed $2,090,022. For violations occurring prior to November 2, 2015, the maximum penalty may not exceed $200,000 per violation per day, with a maximum penalty not to exceed $2,000,000 for a related series of violations. 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 correct the items identified in this letter. Failure to do so will result in Aurora Exploration, LLC being subject to additional enforcement action. No reply to this letter is required. If you choose to reply, in your correspondence please refer to CPF 5-2019-0012W. 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). Sincerely, Chris Hoidal Acting Director, Western Region Pipeline and Hazardous Materials Safety Administration cc: George Pollock, Senior Operations Consultant, gpollock@aurorapower.com PHP-60 Compliance Registry PHP-500 J. Gano (#160487) 6#