National Emission Standards for Hazardous Air Pollutants: Gasoline Distribution Technology Reviews and New Source Performance Standards Review for Bulk Gasoline Terminals

Michael S. Regan,

Administrator.

(b) Each facility under paragraph (a) of this section, the construction or modification of which is commenced after December 17, 1980, and on or before June 10, 2022, is subject to the provisions of this subpart.

Subpart XXa—Standards of Performance for Bulk Gasoline Terminals that Commenced Construction, Modification, or Reconstruction After June 10, 2022

60.500a

Applicability and designation of affected facility.

60.501a

Definitions.

60.502a

Standard for volatile organic compound (VOC) emissions from bulk gasoline terminals.

60.503a

Test methods and procedures.

60.504a

Monitoring requirements.

60.505a

Reporting and recordkeeping.

(a) You are subject to the applicable provisions of this subpart if you are the owner or operator of one or more of the affected facilities listed in paragraphs (a)(1) and (2) of this section.

(1) Each gasoline loading rack affected facility, which is the total of all the loading racks at a bulk gasoline terminal that deliver liquid product into gasoline cargo tanks including the gasoline loading racks, the vapor collection systems, and the vapor processing system.

(2) Each collection of equipment at a bulk gasoline terminal affected facility, which is the total of all equipment associated with the loading of gasoline at a bulk gasoline terminal including the lines and pumps transferring gasoline from storage vessels, the gasoline loading racks, the vapor collection systems, and the vapor processing system.

(b) Each affected facility under paragraph (a) of this section for which construction, modification (as defined in § 60.2 and detailed in § 60.14), or reconstruction (as detailed in § 60.15 and paragraph (e) of this section) is commenced after June 10, 2022, is subject to the provisions of this subpart.

(c) All standards including emission limitations shall apply at all times, including periods of startup, shutdown, and malfunction. As provided in § 60.11(f), this paragraph (c) supersedes the exemptions for periods of startup, shutdown, and malfunction in subpart A of this part.

(d) A newly constructed gasoline loading rack affected facility that was subject to the standards in § 60.502a(b) will continue to be subject to the standards in § 60.502a(b) for newly constructed gasoline loading rack affected facilities if they are subsequently modified or reconstructed.

(e) For purposes of this subpart:

(1) The cost of the following frequently replaced components of the gasoline loading rack affected facility shall not be considered in calculating either the “fixed capital cost of the new components” or the “fixed capital cost that would be required to construct a comparable entirely new facility” under § 60.15: pump seals, loading arm gaskets and swivels, coupler gaskets, overfill sensor couplers and cables, flexible vapor hoses, and grounding cables and connectors.

(2) Under § 60.15, the “fixed capital cost of the new components” includes the fixed capital cost of all depreciable components, except components specified in paragraph (e)(1) of this section which are or will be replaced pursuant to all continuous programs of component replacement which are commenced within any 2-year period following June 10, 2022. For purposes of this paragraph (e)(2), “commenced” means that an owner or operator has undertaken a continuous program of component replacement or that an owner or operator has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of component replacement.

The terms used in this subpart are defined in the Clean Air Act, in § 60.2, or in this section as follows:

3-hour rolling average means the arithmetic mean of the previous thirty-six 5-minute periods of valid operating data collected, as specified, for the monitored parameter. Valid data excludes data collected during periods when the monitoring system is out of control, while conducting repairs associated with periods when the monitoring system is out of control, or while conducting required monitoring system quality assurance or quality control activities. The thirty-six 5-minute periods should be consecutive, but not necessarily continuous if operations or the collection of valid data were intermittent.

Bulk gasoline terminal means any gasoline facility which receives gasoline by pipeline, ship, barge, or cargo tank and subsequently loads all or a portion of the gasoline into gasoline cargo tanks for transport to bulk gasoline plants or gasoline dispensing facilities and has a gasoline throughput greater than 20,000 gallons per day (75,700 liters per day). Gasoline throughput shall be the maximum calculated design throughput for the facility as may be limited by compliance with an enforceable condition under Federal, State, or local law and discoverable by the Administrator and any other person.

Continuous monitoring system is a comprehensive term that may include, but is not limited to, continuous emission monitoring systems, continuous parameter monitoring systems, or other manual or automatic monitoring that is used for demonstrating compliance on a continuous basis.

Equipment means each valve, pump, pressure relief device, open-ended valve or line, sampling connection system, and flange or other connector in the gasoline liquid transfer and vapor collection systems. This definition also includes the entire vapor processing system except the exhaust port(s) or stack(s).

Flare means a thermal combustion device using an open or shrouded flame (without full enclosure) such that the pollutants are not emitted through a conveyance suitable to conduct a performance test.

Gasoline means any petroleum distillate or petroleum distillate/alcohol blend having a Reid vapor pressure of 4.0 pounds per square inch (27.6 kilopascals) or greater which is used as a fuel for internal combustion engines.

Gasoline cargo tank means a delivery tank truck or railcar which is loading gasoline or which has loaded gasoline on the immediately previous load.

In gasoline service means that a piece of equipment is used in a system that transfers gasoline or gasoline vapors.

Loading rack means the loading arms, pumps, meters, shutoff valves, relief valves, and other piping and valves necessary to fill gasoline cargo tanks.

Submerged filling means the filling of a gasoline cargo tank through a submerged fill pipe whose discharge is no more than the 6 inches from the bottom of the tank. Bottom filling of gasoline cargo tanks is included in this definition.

Thermal oxidation system means an enclosed combustion device used to mix and ignite fuel, air pollutants, and air to provide a flame to heat and oxidize air pollutants. Auxiliary fuel may be used to heat air pollutants to combustion temperatures. Thermal oxidation systems emit pollutants through a conveyance suitable to conduct a performance test.

Total organic compounds (TOC) means those compounds measured according to the procedures in Method 25, 25A, or 25B of appendix A-7 to this part. The methane content may be excluded from the TOC concentration as described in § 60.503a.

Vapor collection system means any equipment used for containing total organic compounds vapors displaced during the loading of gasoline cargo tanks.

Vapor processing system means all equipment used for recovering or oxidizing total organic compounds vapors displaced from the affected facility.

Vapor recovery system means processing equipment used to absorb and/or condense collected vapors and return the total organic compounds for blending with gasoline or other petroleum products or return to a petroleum refinery or transmix facility for further processing. Vapor recovery systems include but are not limited to carbon adsorption systems or refrigerated condensers.

Vapor-tight gasoline cargo tank means a gasoline cargo tank which has demonstrated within the 12 preceding months that it meets the annual certification test requirements in § 60.503a(f).

(a) Each gasoline loading rack affected facility shall be equipped with a vapor collection system designed and operated to collect the total organic compounds vapors displaced from gasoline cargo tanks during product loading.

(b) For each newly constructed gasoline loading rack affected facility, the facility owner or operator must meet the applicable emission limitations in paragraph (b)(1) or (2) of this section no later than the date on which § 60.8(a) requires a performance test to be completed. A flare cannot be used to comply with the emission limitations in this paragraph (b).

(1) If a thermal oxidation system is used, maintain the emissions to the atmosphere from the vapor collection system due to the loading of liquid product into gasoline cargo tanks at or below 1.0 milligram of total organic compounds per liter of gasoline loaded (mg/L). Continual compliance with this requirement must be demonstrated as specified in paragraphs (b)(1)(i) and (ii) of this section.

(i) Conduct initial and periodic performance tests as specified in § 60.503a(a) through (c) and meet the emission limitation in this paragraph (b)(1).

(ii) Maintain combustion zone temperature of the thermal oxidation system at or above the 3-hour rolling average operating limit established during the performance test when loading liquid product into gasoline cargo tanks. Valid operating data must exclude periods when there is no liquid product being loaded. If previous contents of the cargo tanks are known, you may also exclude periods when liquid product is loaded but no gasoline cargo tanks are being loaded provided that you excluded these periods in the determination of the combustion zone temperature operating limit according to the provisions in § 60.503a(c)(8)(ii).

(2) If a vapor recovery system is used:

(i) Maintain the emissions to the atmosphere from the vapor collection system at or below 550 parts per million by volume (ppmv) of TOC as propane determined on a 3-hour rolling average when the vapor recovery system is operating;

(ii) Operate the vapor recovery system during all periods when the vapor recovery system is capable of processing gasoline vapors, including periods when liquid product is being loaded, during carbon bed regeneration, and when preparing the beds for reuse; and

(iii) Operate the vapor recovery system to minimize air or nitrogen intrusion except as needed for the system to operate as designed for the purpose of removing VOC from the adsorption media or to break vacuum in the system and bring the system back to atmospheric pressure. Consistent with § 60.12, the use of gaseous diluents to achieve compliance with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere is prohibited.

(c) For each modified or reconstructed gasoline loading rack affected facility, the facility owner or operator must meet the applicable emission limitations in paragraphs (c)(1) through (3) of this section no later than the date on which § 60.8(a) requires a performance test to be completed.

(1) If a thermal oxidation system is used, maintain the emissions to the atmosphere from the vapor collection system due to the loading of liquid product into gasoline cargo tanks at or below 10 mg/L. Continual compliance with this requirement must be demonstrated as specified in paragraphs (c)(1)(i) through (iii) of this section.

(i) Conduct initial and periodic performance tests as specified in § 60.503a(a) through (c) and meet the emission limitation in this paragraph (c)(1).

(ii) Maintain combustion zone temperature of the thermal oxidation system at or above the 3-hour rolling average operating limit established during the performance test when loading liquid product into gasoline cargo tanks. Valid operating data must exclude periods when there is no liquid product being loaded. If previous contents of the cargo tanks are known, you may also exclude periods when liquid product is loaded but no gasoline cargo tanks are being loaded provided that you excluded these periods in the determination of the combustion zone temperature operating limit according to the provisions in § 60.503a(c)(8)(ii).

(iii) As an alternative to the combustion zone temperature operating limit, you may elect to use the monitoring provisions as specified in paragraph (c)(3) of this section.

(2) If a vapor recovery system is used:

(i) Maintain the emissions to the atmosphere from the vapor collection system at or below 5,500 ppmv of TOC as propane determined on a 3-hour rolling average when the vapor recovery system is operating;

(ii) Operate the vapor recovery system during all periods when the vapor recovery system is capable of processing gasoline vapors, including periods when liquid product is being loaded, during carbon bed regeneration, and when preparing the beds for reuse; and

(iii) Operate the vapor recovery system to minimize air or nitrogen intrusion except as needed for the system to operate as designed for the purpose of removing VOC from the adsorption media or to break vacuum in the system and bring the system back to atmospheric pressure. Consistent with § 60.12, the use of gaseous diluents to achieve compliance with a standard which is based on the concentration of a pollutant in the gases discharged to the atmosphere is prohibited.

(3) If a flare is used or if a thermal oxidation system for which these provisions are specified as a monitoring alternative is used, meet all applicable requirements specified in § 63.670(b) through (g) and (i) through (n) of this chapter except as provided in paragraphs (c)(3)(i) through (ix) of this section.

(i) For the purpose of this subpart, “regulated materials” refers to “vapors displaced from gasoline cargo tanks during product loading”. If you do not know the previous contents of the cargo tank, you must assume that cargo tank is a gasoline cargo tank.

(ii) In § 63.670(c) of this chapter for visible emissions:

(A) The phrase “specify the smokeless design capacity of each flare and” does not apply.

(B) The phrase “and the flare vent gas flow rate is less than the smokeless design capacity of the flare” does not apply.

(C) Substitute “The owner or operator shall monitor for visible emissions from the flare as specified in § 60.504a(c)(4).” for the sentence “The owner or operator shall monitor for visible emissions from the flare as specified in paragraph (h) of this section.”

(iii) The phrase “and the flare vent gas flow rate is less than the smokeless design capacity of the flare” in § 63.670(d) of this chapter for flare tip velocity requirements does not apply.

(iv) Substitute “pilot flame or flare flame” for each occurrence of “pilot flame.”

(v) Substitute “gasoline distribution facility” for each occurrence of “petroleum refinery” or “refinery.”

(vi) As an alternative to the flow rate monitoring alternatives provided in § 63.670(i) of this chapter, you may elect to determine flare waste gas flow rate by monitoring the cumulative loading rates of all liquid products loaded into cargo tanks for which the displaced vapors are managed by the affected facility's vapor collection system and vapor processing system.

(vii) If using provision in § 63.670(j)(6) of this chapter for flare vent gas composition monitoring, you must comply with those provisions as specified in paragraphs (c)(3)(vii)(A) through (G) of this section.

(A) You must submit a separate written application to the Administrator for an exemption from monitoring, as described in § 63.670(j)(6)(i) of this chapter.

(B) You must determine the minimum ratio of gasoline loaded to total liquid product loaded for which the affected source must operate at or above at all times when liquid product is loaded into cargo tanks for which vapors collected are sent to the flare or, if applicable, thermal oxidation system and include that in the explanation of conditions expected to produce the flare gas with lowest net heating value as required in § 63.670(j)(6)(i)(C) of this chapter. For air assisted flares or thermal oxidation systems, you must also establish a minimum gasoline loading rate ( i.e., volume of gasoline loaded in a 15-minute period) for which the affected source must operate at or above at all times and include that in the explanation of conditions that ensure the flare gas net heating value is consistent and representative of the lowest net heating value as required in § 63.670(j)(6)(i)(C).

(C) As required in § 63.670(j)(6)(i)(D) of this chapter, samples must be collected at the conditions identified in § 63.670(j)(6)(i)(C) of this chapter, which includes the applicable conditions specified in paragraph (c)(3)(vii)(B) of this section.

(D) The first change from winter gasoline to summer gasoline or from summer gasoline to winter gasoline, whichever comes first, is considered a change in operating conditions under § 63.670(j)(6)(iii) of this chapter and must be evaluated according to the provisions in § 63.670(j)(6)(iii). If separate net heating values are determined for summer gasoline loading versus winter gasoline loading, you may use the summer net heating value for all subsequent summer gasoline loading operations and the winter net heating value for all subsequent winter gasoline loading operations provided there are no other changes in operations.

(E) You must monitor the volume of gasoline loaded and the total volume of liquid product loaded on a 5-minute block basis and maintain the ratio of gasoline loaded to total liquid product loaded at or above the value determined in paragraph (c)(3)(vii)(B) of this section and, for air assisted flares or thermal oxidation systems, maintain the gasoline loading rate at or above the value determined in paragraph (c)(3)(vii)(B) on a rolling 15-minute period basis, calculated based on liquid product loaded during 3 contiguous 5-minute blocks, considering only those periods when liquid product is loaded into gasoline cargo tanks for any portion of three contiguous 5-minute block periods.

(F) For unassisted or perimeter air assisted flares or thermal oxidation systems, if the net heating value determined in § 63.670(j)(6)(i)(F) of this chapter meets or exceeds 270 British thermal units per standard cubic feet (Btu/scf), compliance with the ratio of gasoline loaded to total liquid product loaded as specified in paragraph (c)(3)(vii)(E) of this section demonstrates compliance with the flare combustion zone net heating value (NHV_cz) operating limit in § 63.670(e) of this chapter.

(G) For perimeter air assisted flares or thermal oxidation systems, if the net heating value determined in § 63.670(j)(6)(i)(F) of this chapter meets or exceeds the net heating value dilution parameter (NHV_dil ) operating limit of 22 British thermal units per square foot (Btu/ft² ) at the flow rate associated with the minimum gasoline loading rate determined in paragraph (c)(3)(vii)(B) of this section at any air assist rate used, compliance with the minimum gasoline loading rate as specified in paragraph (c)(3)(vii)(E) of this section demonstrates compliance with the NHV_dil operating limit in § 63.670(f) of this chapter.

(viii) You may elect to establish a minimum supplemental gas addition rate and monitor the supplemental gas addition rate, in addition to the operating limits in paragraph (c)(3)(vii)(E) of this section, to demonstrate compliance with the flare combustion zone operating limit in § 63.670(e) of this chapter and, if applicable, flare dilution operating limit in § 63.670(f) of this chapter, as follows.

(A) Use the minimum flare vent gas net heating value prior to addition of supplemental gas as established in paragraph (c)(3)(vii) of this section.

(B) Determine the maximum flow rate based on the maximum cumulative loading rate for a 15-minute block period considering all loading racks at the affected facility and considering restrictions on maximum loading rates necessary for compliance with the maximum pressure limits for the vapor collection and liquid loading equipment specified in paragraph (h) of this section.

(C) Determine the supplemental gas addition rate needed to yield NHV_cz of 270 Btu/scf using equation in § 63.670(m)(1) of this chapter.

(D) For flares (or thermal oxidation systems) with perimeter assist air, determine the supplemental gas addition rate needed to yield NHV_dil of 22 Btu/ft² using equation in § 63.670(n)(1) of this chapter at the flare vent gas net heating value determined in paragraph (c)(3)(vii) of this section, the flare gas flow rate associated with the minimum gasoline loading rate as determined in paragraph (c)(3)(vii)(B) of this section, and the fixed air assist rate. If the air assist rate is varied based on total liquid product loading rates, you must use the air assist rate used at low flow rates and repeat the calculation using the minimum flow rate associated with each air assist rate setting and select the maximum supplemental gas addition rate across any of the air assist rate settings.

(E) Maintain the supplemental gas addition rate above the greater of the values determined in paragraphs (c)(3)(viii)(C) and, if applicable, (c)(3)(viii)(D) of this section on a 15-minute block period basis when liquid product is loaded into gasoline cargo tanks for at least 15-minutes.

(ix) As an alternative to determining the flare tip velocity rate for each 15-minute block to determine compliance with the flare tip velocity operating limit as specified in § 63.670(k)(2) of this chapter, you may elect to conduct a one-time flare tip velocity operating limit compliance assessment as provided in paragraphs (c)(3)(ix)(A) through (D) of this section. If the flare or loading rack configurations change ( e.g., flare tip modified or additional loading racks are added for which vapors are directed to the flare), you must repeat this one-time assessment based on the new configuration.

(A) Determine the unobstructed cross-sectional area of the flare tip, in units of square feet, as specified in § 63.670(k)(1) of this chapter.

(B) Determine the maximum flow rate, in units of cubic feet per second, based on the maximum cumulative loading rate for a 15-minute block period considering all loading racks at the gasoline loading racks affected facility and considering restrictions on maximum loading rates necessary for compliance with the maximum pressure limits for the vapor collection and liquid loading equipment specified in paragraph (h) of this section.

(C) Calculate the maximum flare tip velocity as the maximum flow rate from paragraph (c)(3)(ix)(B) of this section divided by the unobstructed cross-sectional area of the flare tip from paragraph (c)(3)(ix)(A) of this section.

(D) Demonstrate that the maximum flare tip velocity as calculated in paragraph (c)(3)(ix)(C) of this section is less than 60 feet per second.

(d) Each vapor collection system for the gasoline loading rack affected facility shall be designed to prevent any total organic compounds vapors collected at one loading rack from passing to another loading rack.

(e) Loadings of liquid product into gasoline cargo tanks at a gasoline loading rack affected facility shall be limited to vapor-tight gasoline cargo tanks according to the methods in § 60.503a(f) using the following procedures:

(1) The owner or operator shall obtain the vapor tightness annual certification test documentation described in § 60.505a(a)(3) for each gasoline cargo tank which is to be loaded at the affected facility. If you do not know the previous contents of a cargo tank, you must assume that cargo tank is a gasoline cargo tank.

(2) The owner or operator shall obtain and record the cargo tank identification number of each gasoline cargo tank which is to be loaded at the affected facility.

(3) The owner or operator shall cross-check each cargo tank identification number obtained in paragraph (e)(2) of this section with the file of gasoline cargo tank vapor tightness documentation specified in paragraph (e)(1) of this section prior to loading any liquid product into the gasoline cargo tank.

(f) Loading of liquid product into gasoline cargo tanks at a gasoline loading rack affected facility shall be conducted using submerged filling, as defined in § 60.501a, and only into gasoline cargo tanks equipped with vapor collection equipment that is compatible with the terminal's vapor collection system. If you do not know the previous contents of a cargo tank, you must assume that cargo tank is a gasoline cargo tank.

(g) Loading of liquid product into gasoline cargo tanks at a gasoline loading rack affected facility shall only be conducted when the terminal's and the cargo tank's vapor collection systems are connected. If you do not know the previous contents of a cargo tank, you must assume that cargo tank is a gasoline cargo tank.

(h) The vapor collection and liquid loading equipment for a gasoline loading rack affected facility shall be designed and operated to prevent gauge pressure in the gasoline cargo tank from exceeding 18 inches of water (460 millimeters (mm) of water) during product loading. This level is not to be exceeded and must be continuously monitored according to the procedures specified in § 60.504a(d).

(i) No pressure-vacuum vent in the gasoline loading rack affected facility's vapor collection system shall begin to open at a system pressure less than 18 inches of water (460 mm of water) or at a vacuum of less than 6.0 inches of water (150 mm of water).

(j) Each owner or operator of a collection of equipment at a bulk gasoline terminal affected facility shall perform leak inspection and repair of all equipment in gasoline service, which includes all equipment in the vapor collection system, the vapor processing system, and each loading rack and loading arm handling gasoline, according to the requirements in paragraphs (j)(1) through (8) of this section. The owner or operator must keep a list, summary description, or diagram(s) showing the location of all equipment in gasoline service at the facility.

(1) Conduct leak detection monitoring of all pumps, valves, and connectors in gasoline service using either of the methods specified in paragraph (j)(1)(i) or (ii) of this section.

(i) Use optical gas imaging (OGI) to quarterly monitor all pumps, valves, and connectors in gasoline service as specified in § 60.503a(e)(2).

(ii) Use Method 21 of appendix A-7 to this part as specified in § 60.503a(e)(1) and paragraphs (j)(1)(ii)(A) through (C) of this section.

(A) All pumps must be monitored quarterly, unless the pump meets one of the requirements in § 60.482-1a(d) or § 60.482-2a(d) through (g). An instrument reading of 10,000 ppm or greater is a leak.

(B) All valves must be monitored quarterly, unless the valve meets one of the requirements in § 60.482-1a(d) or § 60.482-7a(f) through (h). An instrument reading of 10,000 ppm or greater is a leak.

(C) All connectors must be monitored annually, unless the connector meets one of the requirements in § 60.482-1a(d) or § 60.482-11a(e) or (f). An instrument reading of 10,000 ppm or greater is a leak.

(2) During normal duties, record leaks identified by audio, visual, or olfactory methods.

(3) If evidence of a potential leak is found at any time by audio, visual, olfactory, or any other detection method for any equipment (as defined in § 60.501a), a leak is detected.

(4) For pressure relief devices, comply with the requirements in paragraphs (j)(4)(i) through (ii) of this section.

(i) Conduct instrument monitoring of each pressure relief device quarterly and within 5 calendar days after each pressure release to detect leaks by the methods specified in paragraph (j)(1) of this section, except as provided in § 60.482-4a(c).

(ii) If emissions are observed when using OGI, a leak is detected. If Method 21 is used, an instrument reading of 10,000 ppm or greater indicates a leak is detected.

(5) For sampling connection systems, comply with the requirements in § 60.482-5a.

(6) For open-ended valves or lines, comply with the requirements in § 60.482-6a.

(7) When a leak is detected for any equipment, comply with the requirements of paragraphs (j)(7)(i) through (iii) of this section.

(i) A weatherproof and readily visible identification, marked with the equipment identification number, must be attached to the leaking equipment. The identification on equipment may be removed after it has been repaired.

(ii) An initial attempt at repair shall be made as soon as practicable, but no later than 5 calendar days after the leak is detected. An initial attempt at repair is not required if the leak is detected using OGI and the equipment identified as leaking would require elevating the repair personnel more than 2 meters above a support surface.

(iii) Repair or replacement of leaking equipment shall be completed within 15 calendar days after detection of each leak, except as provided in paragraph (j)(8) of this section.

(A) For leaks identified pursuant to instrument monitoring required under paragraph (j)(1) of this section, the leak is repaired when instrument re-monitoring of the equipment does not detect a leak.

(B) For leaks identified pursuant to paragraph (j)(2) of this section, the leak is repaired when the leak can no longer be identified using audio, visual, or olfactory methods.

(8) Delay of repair of leaking equipment will be allowed according to the provisions in paragraphs (j)(8)(i) though (iv) of this section. The owner or operator shall provide in the semiannual report specified in § 60.505a(c), the reason(s) why the repair was delayed and the date each repair was completed.

(i) Delay of repair of equipment will be allowed for equipment that is isolated from the affected facility and that does not remain in gasoline service.

(ii) Delay of repair for valves and connectors will be allowed if:

(A) The owner or operator demonstrates that emissions of purged material resulting from immediate repair are greater than the fugitive emissions likely to result from delay of repair, and

(B) When repair procedures are effected, the purged material is collected and destroyed or recovered in a control device complying with § 60.482-10a or the requirements in paragraph (b) or (c) of this section, as applicable.

(iii) Delay of repair will be allowed for a valve, but not later than 3 months after the leak was detected, if valve assembly replacement is necessary, valve assembly supplies have been depleted, and valve assembly supplies had been sufficiently stocked before the supplies were depleted.

(iv) Delay of repair for pumps will be allowed if:

(A) Repair requires the use of a dual mechanical seal system that includes a barrier fluid system; and

(B) Repair is completed as soon as practicable, but not later than 6 months after the leak was detected.

(k) You must not allow gasoline to be handled at a bulk gasoline terminal that contains an affected facility listed under § 60.500a(a) in a manner that would result in vapor releases to the atmosphere for extended periods of time. Measures to be taken include, but are not limited to, the following:

(1) Minimize gasoline spills;

(2) Clean up spills as expeditiously as practicable;

(3) Cover all open gasoline containers and all gasoline storage tank fill-pipes with a gasketed seal when not in use; and

(4) Minimize gasoline sent to open waste collection systems that collect and transport gasoline to reclamation and recycling devices, such as oil/water separators.

(a) General performance test and performance evaluation requirements. (1) In conducting the performance tests or evaluations required by this subpart (or as requested by the Administrator), the owner or operator shall use the test methods and procedures as specified in this section, except as provided in § 60.8(b). The three-run requirement of § 60.8(f) does not apply to this subpart.

(2) Immediately before the performance test, conduct leak detection monitoring following the methods in paragraph (e)(1) of this section to identify leakage of vapor from all equipment, including loading arms, in the gasoline loading rack affected facility while gasoline is being loaded into a gasoline cargo tank to ensure the terminal's vapor collection system equipment is operated with no detectable emissions. The owner or operator shall repair all leaks identified with readings of 500 ppmv (as methane) or greater above background before conducting the performance test and within the timeframe specified in § 60.502a(j)(7).

(b) Performance test or performance evaluation timing. (1) For each gasoline loading rack affected facility subject to the mass emission limits in § 60.502a(b)(1) or (c)(1), conduct the initial performance test of the vapor collection and processing systems according to the timing specified in § 60.8(a). For each gasoline loading rack affected facility subject to the emission limits in § 60.502a(b)(2) or (c)(2), conduct the initial performance evaluation of the continuous emissions monitoring system (CEMS) according to the timing specified for performance tests in § 60.8(a).

(2) For each gasoline loading rack affected facility complying with the mass emission limits in § 60.502a(b)(1) or (c)(1), conduct subsequent performance test of the vapor collection and processing system no later than 60 calendar months after the previous performance test.

(3) For each gasoline loading rack affected facility complying with the concentration emission limits in § 60.502a(b)(2) or (c)(2), conduct subsequent performance evaluations of CEMS for the vapor collection and processing system no later than 12 calendar months after the previous performance evaluation.

(c) Performance test requirements for mass loading emission limit. The owner or operator of a gasoline loading rack affected facility shall conduct performance tests of the vapor collection and processing system subject to the emission limits in § 60.502a(b)(1) or (c)(1), as specified in paragraphs (c)(1) through (8) of this section.

(1) The performance test shall be 6 hours long during which at least 80,000 gallons (300,000 liters) of gasoline is loaded. If this is not possible, the test may be continued the same day until 80,000 gallons (300,000 liters) of gasoline is loaded. If 80,000 gallons (300,000 liters) cannot be loaded during the first day of testing, the test may be resumed the next day with another 6-hour period. During the second day of testing, the 80,000-gallon (300,000-liter) criterion need not be met. However, as much as possible, testing should be conducted during the 6-hour period in which the highest throughput of gasoline normally occurs.

(2) If the vapor processing system is intermittent in operation and employs an intermediate vapor holder to accumulate total organic compounds vapors collected from gasoline cargo tanks, the performance test shall begin at a reference vapor holder level and shall end at the same reference point. The test shall include at least two startups and shutdowns of the vapor processor. If this does not occur under automatically controlled operations, the system shall be manually controlled.

(3) The emission rate (E) of total organic compounds shall be computed using the following equation:

Equation 1 to paragraph (c)(3)

Where:

E = emission rate of total organic compounds, mg/liter of gasoline loaded.

V_esi = volume of air-vapor mixture exhausted at each interval “i”, scm.

C_ei = concentration of total organic compounds at each interval “i”, ppm.

L = total volume of gasoline loaded, liters.

n = number of testing intervals.

i = emission testing interval of 5 minutes.

K = density of calibration gas, 1.83 × 10⁶ for propane, mg/scm.

(4) The performance test shall be conducted in intervals of 5 minutes. For each interval “i”, readings from each measurement shall be recorded, and the volume exhausted (V_esi) and the corresponding average total organic compounds concentration (C_ei) shall be determined. The sampling system response time shall be accounted for when determining the average total organic compounds concentration corresponding to the volume exhausted.

(5) Method 2B of appendix A-1 to this part shall be used to determine the volume (V_esi) of air-vapor mixture exhausted at each interval.

(6) Method 25, 25A, or 25B of appendix A-7 to this part shall be used for determining the total organic compounds concentration (C_ei) at each interval. Method 25 must not be used if the outlet TOC concentration is less than 50 ppmv. The calibration gas shall be propane. If the owner or operator conducts the performance test using either Method 25A or Method 25B, the methane content in the exhaust vent may be excluded following the procedures in paragraphs (c)(6)(i) through (v) of this section. Alternatively, an instrument that uses gas chromatography with a flame ionization detector may be used according to the procedures in paragraph (c)(6)(vi) of this section.

(i) Measure the methane concentration by Method 18 of appendix A-6 to this part or Method 320 of appendix A to part 63 of this chapter.

(ii) Calibrate the Method 25A or Method 25B analyzer using both propane and methane to develop response factors to both compounds.

(iii) Determine the TOC concentration with the Method 25A or Method 25B analyzer on an as methane basis.

(iv) Subtract the methane measured according to paragraph (c)(6)(i) of this section from the concentration determined in paragraph (c)(6)(iii) of this section.

(v) Convert the concentration difference determined in paragraph (c)(6)(iv) of this section to TOC (minus methane), as propane, by using the response factors determined in paragraph (c)(6)(ii) of this section. Multiply the concentration difference in paragraph (c)(6)(iv) of this section by the ratio of the response factor for propane to the response factor for methane.

(vi) Methane must be separated by the gas chromatograph and measured by the flame ionization detector, followed by a back-flush of the chromatographic column to directly measure TOC concentration minus methane. Use a direct interface and heated sampling line from the sampling point to the gas chromatographic injection valve. All sampling components leading to the analyzer must be heated to greater than 110 °C. Calibrate the instrument with propane. Calibration error and calibration drift must be demonstrated according to Method 25A, and the appropriate procedures in Method 25A must be followed to ensure the calibration error and calibration drift are within Method 25A limits. The TOC concentration minus methane must be recorded at least once every 15 minutes. The performance test report must include the calibration results and the results demonstrating proper separation of methane from the TOC concentration.

(7) To determine the volume (L) of gasoline dispensed during the performance test period at all loading racks whose vapor emissions are controlled by the processing system being tested, terminal records or readings from gasoline dispensing meters at each loading rack shall be used.

(8) Monitor the temperature in the combustion zone using the continuous parameter monitoring system (CPMS) required in § 60.504a(a) and determine the operating limit for the combustion device using the following procedures:

(i) Record the temperature or average temperature for each 5-minute period during the performance test.

(ii) Using only the 5-minute periods in which liquid product is loaded into gasoline cargo tanks, determine the 1-hour average temperature for each hour of the performance test. If you do not know the previous contents of the cargo tank, you must assume liquid product loading is performed in gasoline cargo tanks such that you use all 5-minute periods in which liquid product is loaded into gasoline cargo tanks when determining the 1-hour average temperature for each hour of the performance test.

(iii) Starting at the end of the third hour of the performance test and at the end of each successive hour, calculate the 3-hour rolling average temperature using the 1-hour average values in paragraph (c)(8)(ii) of this section. For a 6-hour test, this would result in four 3-hour averages (averages for hours 1 through 3, 2 through 4, 3 through 5, and 4 through 6).

(iv) Set the operating limit at the lowest 3-hour average temperature determined in paragraph (c)(8)(iii) of this section. New operating limits become effective on the date that the performance test report is submitted to the U.S. Environmental Protection Agency (EPA) Compliance and Emissions Data Reporting Interface (CEDRI), per the requirements of § 60.505a(b).

(d) Performance evaluation requirements for concentration emission limit. The owner or operator shall conduct performance evaluations of the CEMS for vapor collection and processing systems subject to the emission limits in § 60.502a(b)(2) or (c)(2) as specified in paragraph (d)(1) or (2) of this section, as applicable.

(1) If the CEMS uses a nondispersive infrared analyzer, the CEMS must be installed, evaluated, and operated according to the requirements of Performance Specification 8 of appendix B to this part. Method 25B in appendix A-7 to this part must be used as the reference method, and the calibration gas must be propane. The owner or operator may request an alternative test method under § 60.8(b) to use a CEMS that excludes the methane content in the exhaust vent.

(2) If the CEMS uses a flame ionization detector, the CEMS must be installed, evaluated, and operated according to the requirements of Performance Specification 8A of appendix B to this part. As part of the performance evaluation, conduct a relative accuracy test audit (RATA) following the procedures in Performance Specification 2, section 8.4, of appendix B to this part; the relative accuracy must meet the criteria of Performance Specification 8, section 13.2, of appendix B to this part. Method 25A in appendix A-7 to this part must be used as the reference method, and the calibration gas must be propane. The owner or operator may exclude the methane content in the exhaust following the procedures in paragraphs (d)(2)(i) through (iv) of this section.

(i) Methane must be separated using a chromatographic column and measured by the flame ionization detector, followed by a back-flush of the chromatographic column to directly measure TOC concentration minus methane.

(ii) The CEMS must be installed, evaluated, and operated according to the requirements of Performance Specification 8A of appendix B to this part, except the target compound is TOC minus methane. As part of the performance evaluation, conduct a RATA following the procedures in Performance Specification 2, section 8.4, of appendix B to this part; the relative accuracy must meet the criteria of Performance Specification 8, section 13.2, of appendix B to this part.

(iii) If the concentration of TOC minus methane in the exhaust stream is greater than 50 ppmv, Method 25 in appendix A-7 to this part must be used as the reference method, and the calibration gas must be propane. If the concentration of TOC minus methane in the exhaust stream is 50 ppmv or less, Method 25A in appendix A-7 to this part must be used as the reference method, and the calibration gas must be propane. If Method 25A is the reference method, the procedures in paragraph (c)(6) of this section may be used to subtract methane from the TOC concentration.

(iv) The TOC concentration minus methane must be recorded at least once every 15 minutes.

(e) Leak detection monitoring. Conduct the leak detection monitoring specified in § 60.502a(j)(1) for the collection of equipment at a bulk gasoline terminal affected facility using one of the procedures specified in paragraph (e)(1) or (2) of this section. Conduct the leak detection monitoring specified in paragraph (a)(2) of this section using the procedures specified in paragraph (e)(1) of this section, except that the instrument reading that defines a leak is specified in paragraph (a)(2) for all equipment, including loading arms, in the gasoline loading rack affected facility and the calibration gas in paragraph (e)(1)(ii) must be at a concentration of 500 ppm methane.

(1) Method 21 in appendix A-7 to this part. The instrument reading that defines a leak is 10,000 ppmv (as methane). The instrument shall be calibrated before use each day of its use by the procedures specified in Method 21 of appendix A-7. The calibration gases in paragraphs (e)(1)(i) and (ii) of this section must be used. The drift assessment specified in paragraph (e)(1)(iii) of this section must be performed at the end of each monitoring day.

(i) Zero air (less than 10 ppm of hydrocarbon in air); and

(ii) Methane and air at a concentration of 10,000 ppm methane.

(iii) At the end of each monitoring day, check the instrument using the same calibration gas that was used to calibrate the instrument before use. Follow the procedures specified in Method 21 of appendix A-7 to this part, section 10.1, except do not adjust the meter readout to correspond to the calibration gas value. If multiple scales are used, record the instrument reading for each scale used. Divide the arithmetic difference of the initial and post-test calibration response by the corresponding calibration gas value for each scale and multiply by 100 to express the calibration drift as a percentage. If a calibration drift assessment shows a negative drift of more than 10 percent, then re-monitor all equipment monitored since the last calibration with instrument readings between the leak definition and the leak definition multiplied by (100 minus the percent of negative drift) divided by 100. If any calibration drift assessment shows a positive drift of more than 10 percent from the initial calibration value, then, at the owner/operator's discretion, all equipment with instrument readings above the leak definition and below the leak definition multiplied by (100 plus the percent of positive drift) divided by 100 monitored since the last calibration may be re-monitored.

(2) OGI according to all the requirements in appendix K to this part. A leak is defined as any emissions plume imaged by the camera from equipment regulated by this subpart.

(f) Annual certification test. The annual certification test for gasoline cargo tanks shall consist of the following test methods and procedures:

(1) Method 27 of appendix A-8 to this part. Conduct the test using a time period (t) for the pressure and vacuum tests of 5 minutes. The initial pressure (P_i) for the pressure test shall be 460 mm water (H₂ O) (18 in. H₂ O), gauge. The initial vacuum (V_i) for the vacuum test shall be 150 mm H₂ O (6 in. H₂ O), gauge. The maximum allowable pressure and vacuum changes (Δ p, Δ v) are as shown in table 1 to this paragraph (f)(1).

(2) Pressure test of the gasoline cargo tank's internal vapor valve as follows:

(i) After completing the tests under paragraph (f)(1) of this section, use the procedures in Method 27 to repressurize the gasoline cargo tank to 460 mm H₂ O (18 in. H₂ O), gauge. Close the gasoline cargo tank's internal vapor valve(s), thereby isolating the vapor return line and manifold from the gasoline cargo tank.

(ii) Relieve the pressure in the vapor return line to atmospheric pressure, then reseal the line. After 5 minutes, record the gauge pressure in the vapor return line and manifold. The maximum allowable 5-minute pressure increase is 65 mm H₂ O (2.5 in. H₂ O).

(3) As an alternative to paragraph (f)(1) of this section, you may use the procedure in § 63.425(i) of this chapter.

(a) Monitoring requirements for thermal oxidation systems complying with the combustion zone temperature operating limit. Install, operate, and maintain a CPMS for measuring the combustion zone temperature as specified in paragraphs (a)(1) through (5) of this section.

(1) Install the temperature CPMS in the combustion (flame) zone or in the exhaust gas stream as close as practical to the combustion burners in a position that provides a representative temperature of the combustion zone of the thermal oxidation system.

(2) The temperature CPMS must be capable of measuring temperature with an accuracy of ±1 percent over the normal range of temperatures measured.

(3) The temperature CPMS must be capable of recording the temperature at least once every 5 minutes and calculating hourly block averages that include only those 5-minute periods in which liquid product was loaded into gasoline cargo tanks.

(4) At least quarterly, inspect all components for integrity and all electrical connections for continuity, oxidation, and galvanic corrosion, unless the CPMS has a redundant temperature sensor.

(5) Conduct calibration checks at least annually and conduct calibration checks following any period of more than 24 hours throughout which the temperature exceeded the manufacturer's specified maximum rated temperature or install a new temperature sensor.

(b) Monitoring requirements for vapor recovery systems. Install, calibrate, operate, and maintain a CEMS for measuring the concentration of TOC in the atmospheric vent from the vapor recovery system as specified in paragraphs (b)(1) and (2) of this section. Locate the sampling probe or other interface at a measurement location such that you obtain representative measurements of emissions from the vapor recovery system.

(1) The requirements of Performance Specification 8 of appendix B to this part, or, if the CEMS uses a flame ionization detector, Performance Specification 8A of appendix B to this part, the quality assurance requirements in Procedure 1 of appendix F to this part, and the procedures under § 60.13 must be followed for installation, evaluation, and operation of the CEMS. For CEMS certified using Performance Specification 8A of appendix B, conduct the RATA required under Procedure 1 according to the requirements in § 60.503a(d). As required by § 60.503a(b)(3), conduct annual performance evaluations of each TOC CEMS according to the requirements in § 60.503a(d). Conduct accuracy determinations quarterly and calibration drift tests daily in accordance with Procedure 1 in appendix F.

(2) The span value of the TOC CEMS must be approximately 2 times the applicable emission limit.

(c) Monitoring requirements for flares and thermal oxidation systems for which flare monitoring alternative is provided. Install, operate, and maintain CPMS for flares used to comply with the emission limitations in § 60.502a(c)(3), including monitors used for gasoline and total liquid product loading rates, following the requirements specified in § 63.671 of this chapter as specified in paragraphs (c)(1) through (3) of this section and conduct visible emission observations as specified in paragraph (c)(4) of this section.

(1) Substitute “pilot flame or flare flame” for each occurrence of “pilot flame.”

(2) You may elect to determine compositional analysis for net heating value with a continuous process mass spectrometer without the use of a gas chromatograph. If you choose to determine compositional analysis for net heating value with a continuous process mass spectrometer, then you must comply with the requirements specified in paragraphs (c)(2)(i) through (vii) of this section.

(i) You must meet the requirements in § 63.671(e)(2) of this chapter. You may augment the minimum list of calibration gas components found in § 63.671(e)(2) with compounds found during a pre-survey or known to be in the gas through process knowledge.

(ii) Calibration gas cylinders must be certified to an accuracy of 2 percent and traceable to National Institute of Standards and Technology (NIST) standards.

(iii) For unknown gas components that have similar analytical mass fragments to calibration compounds, you may report the unknowns as an increase in the overlapped calibration gas compound. For unknown compounds that produce mass fragments that do not overlap calibration compounds, you may use the response factor for the nearest molecular weight hydrocarbon in the calibration mix to quantify the unknown component's net heating value of flare vent gas (NHV_vg).

(iv) You may use the response factor for n-pentane to quantify any unknown components detected with a higher molecular weight than n-pentane.

(v) You must perform an initial calibration to identify mass fragment overlap and response factors for the target compounds.

(vi) You must meet applicable requirements in Performance Specification 9 of appendix B to this part for continuous monitoring system acceptance including, but not limited to, performing an initial multi-point calibration check at three concentrations following the procedure in section 10.1 of Performance Specification 9 and performing the periodic calibration requirements listed for gas chromatographs in table 13 to part 63, subpart CC, of this chapter, for the process mass spectrometer. You may use the alternative sampling line temperature allowed under Net Heating Value by Gas Chromatograph in table 13 to part 63, subpart CC.

(vii) The average instrument calibration error (CE) for each calibration compound at any calibration concentration must not differ by more than 10 percent from the certified cylinder gas value. The CE for each component in the calibration blend must be calculated using the following equation:

Equation 1 to paragraph (c)(2)(vii)

Where:

C_m = Average instrument response (ppm).

C_a = Certified cylinder gas value (ppm).

(3) If you use a gas chromatograph or mass spectrometer for compositional analysis for net heating value, then you may choose to use the CE of net heating value (NHV) measured versus the cylinder tag value NHV as the measure of agreement for daily calibration and quarterly audits in lieu of determining the compound-specific CE. The CE for NHV at any calibration level must not differ by more than 10 percent from the certified cylinder gas value. The CE for NHV must be calculated using the following equation:

Equation 2 to paragraph (c)(3)

Where:

NHV_measured = Average instrument response (Btu/scf)

NHV_a = Certified cylinder gas value (Btu/scf).

(4) If visible emissions are observed for more than one continuous minute during normal duties, visible emissions observation using Method 22 of appendix A-7 to this part must be conducted for 2 hours or until 5-minutes of visible emissions are observed.

(d) Pressure CPMS requirements. The owner or operator shall install, operate, and maintain a CPMS to measure the pressure of the vapor collection system to determine compliance with the standard in § 60.502a(h) as specified in paragraphs (d)(1) through (4) of this section.

(1) Install a pressure CPMS (liquid manometer, magnehelic gauge, or equivalent instrument), capable of measuring up to 500 mm of water gauge pressure with ±2.5 mm of water precision on the terminal's vapor collection system at a pressure tap located as close as possible to the connection with the gasoline cargo tank. If necessary to obtain representative loading pressures, install pressure CPMS for each loading rack.

(2) Check the calibration of the pressure CPMS at least annually. Check the calibration of the pressure CPMS following any period of more than 24 hours throughout which the pressure exceeded the manufacturer's specified maximum rated pressure or install a new pressure sensor.

(3) At least quarterly, visually inspect components of the pressure CPMS for integrity, oxidation and galvanic corrosion, unless the system has a redundant pressure sensor.

(4) The output of the pressure CPMS must be reviewed each operating day to ensure that the pressure readings fluctuate as expected during loading of gasoline cargo tanks to verify the pressure taps are not plugged. Plugged pressure taps must be unplugged or otherwise repaired within 24 hours or prior to the next gasoline cargo tank loading, whichever time period is longer.

(e) Limited alternative requirements for vapor recovery systems. If the CEMS used for measuring the concentration of TOC in the atmospheric vent from the vapor recovery system as specified in paragraph (b) of this section requires maintenance such that it is off-line for more than 15 minutes, you may follow the requirements in paragraphs (e)(1) and (2) of this section and monitor product loading quantities and regeneration cycle parameters as an alternative to the monitoring requirement in paragraph (b) for no more than 240 hours in a calendar year.

(1) Determine the quantity of liquid product loaded in gasoline cargo tanks for the past 10 adsorption cycles prior to the CEMS going off-line and select the smallest of these values as your product loading quantity operating limit.

(2) Determine the vacuum pressure, purge gas quantities, and duration of the vacuum/purge cycles used for the past 10 desorption cycles prior to the CEMS going off-line. You must operate vapor recovery system desorption cycles as specified in paragraphs (e)(2)(i) through (iii) of this section.

(i) The vacuum pressure for each desorption cycle must be at or above the average vacuum pressure from the past 10 desorption cycles. Note: a higher vacuum means a lower absolute pressure.

(ii) Purge gas quantity used for each desorption cycle must be at or above the average quantity of purge gas used from the past 10 desorption cycles.

(iii) Duration of the vacuum/purge cycle for each desorption cycle must be at or above the average duration of the vacuum/purge cycle used from the past 10 desorption cycles.

(a) Recordkeeping requirements. For each affected facility listed under § 60.500a(a), keep records as specified in paragraphs (a)(1) through (9) of this section, as applicable, for a minimum of five years unless otherwise specified in this section. These recordkeeping requirements supersede the requirements in § 60.7(b).

(1) For each thermal oxidation system used to comply with the emission limitations in § 60.502a(b)(1) or (c)(1) by monitoring the combustion zone temperature as specified in § 60.502a(b)(1)(ii) or (c)(1)(ii), for each pressure CPMS used to comply with the requirements in § 60.502a(h), and for each vapor recovery system used to comply with the emission limitations in § 60.502a(b)(2) or (c)(2), maintain records, as applicable, of:

(i) The applicable operating or emission limit for the continuous monitoring system (CMS). For combustion zone temperature operating limits, include the applicable date range the limit applies based on when the performance test was conducted.

(ii) Each 3-hour rolling average combustion zone temperature measured by the temperature CPMS, each 5-minute average reading from the pressure CPMS, and each 3-hour rolling average TOC concentration (as propane) measured by the TOC CEMS.

(iii) For each deviation of the 3-hour rolling average combustion zone temperature operating limit, maximum loading pressure specified in § 60.502a(h), or 3-hour rolling average TOC concentration (as propane), the start date and time, duration, cause, and the corrective action taken.

(iv) For each period when there was a CMS outage or the CMS was out of control, the start date and time, duration, cause, and the corrective action taken. For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) is used, the corrective action taken shall include an indication of the use of the limited alternative for vapor recovery systems in § 60.504a(e).

(v) Each inspection or calibration of the CMS including a unique identifier, make, and model number of the CMS, and date of calibration check. For TOC CEMS, include the type of CEMS used ( i.e., flame ionization detector, nondispersive infrared analyzer) and an indication of whether methane is excluded from the TOC concentration reported in paragraph (a)(1)(ii) of this section.

(vi) For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) is used, also keep records of:

(A) The quantity of liquid product loaded in gasoline cargo tanks for the past 10 adsorption cycles prior to the CEMS outage.

(B) The vacuum pressure, purge gas quantities, and duration of the vacuum/purge cycles used for the past 10 desorption cycles prior to the CEMS outage.

(C) The quantity of liquid product loaded in gasoline cargo tanks for each adsorption cycle while using the alternative.

(D) The vacuum pressure, purge gas quantities, and duration of the vacuum/purge cycles for each desorption cycle while using the alternative.

(2) For each flare used to comply with the emission limitations in § 60.502a(c)(3) and for each thermal oxidation system using the flare monitoring alternative as provided in § 60.502a(c)(1)(iii), maintain records of:

(i) The output of the monitoring device used to detect the presence of a pilot flame as required in § 63.670(b) of this chapter for a minimum of 2 years. Retain records of each 15-minute block during which there was at least one minute that no pilot flame was present when gasoline vapors were routed to the flare for a minimum of 5 years. The record must identify the start and end time and date of each 15-minute block.

(ii) Visible emissions observations as specified in paragraphs (a)(2)(ii)(A) and (B) of this section, as applicable, for a minimum of 3 years.

(A) If visible emissions observations are performed using Method 22 of appendix A-7 to this part, the record must identify the date, the start and end time of the visible emissions observation, and the number of minutes for which visible emissions were observed during the observation. If the owner or operator performs visible emissions observations more than one time during a day, include separate records for each visible emissions observation performed.

(B) For each 2-hour period for which visible emissions are observed for more than 5 minutes in 2 consecutive hours but visible emissions observations according to Method 22 of appendix A-7 to this part were not conducted for the full 2-hour period, the record must include the date, the start and end time of the visible emissions observation, and an estimate of the cumulative number of minutes in the 2-hour period for which emissions were visible based on best information available to the owner or operator.

(iii) Each 15-minute block period during which operating values are outside of the applicable operating limits specified in § 63.670(d) through (f) of this chapter when liquid product is being loaded into gasoline cargo tanks for at least 15-minutes identifying the specific operating limit that was not met.

(iv) The 15-minute block average cumulative flows for flare vent gas or the thermal oxidation system vent gas and, if applicable, total steam, perimeter assist air, and premix assist air specified to be monitored under § 63.670(i) of this chapter, along with the date and start and end time for the 15-minute block. If multiple monitoring locations are used to determine cumulative vent gas flow, total steam, perimeter assist air, and premix assist air, retain records of the 15-minute block average flows for each monitoring location for a minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in subsequent calculations for a minimum of 5 years. If pressure and temperature monitoring is used, retain records of the 15-minute block average temperature, pressure and molecular weight of the flare vent gas, thermal oxidation system vent gas, or assist gas stream for each measurement location used to determine the 15-minute block average cumulative flows for a minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in subsequent calculations for a minimum of 5 years. If you use the supplemental gas flow rate monitoring alternative in § 60.502a(c)(3)(viii), the required minimum supplemental gas flow rate (winter and summer, if applicable) and the actual monitored supplemental gas flow rate for the 15- minute block. Retain the supplemental gas flow rate records for a minimum of 5 years.

(v) The flare vent gas compositions or thermal oxidation system vent gas specified to be monitored under § 63.670(j) of this chapter. Retain records of individual component concentrations from each compositional analyses for a minimum of 2 years. If an NHV_vg analyzer is used, retain records of the 15-minute block average values for a minimum of 5 years. If you demonstrate your gas streams have consistent composition using the provisions in § 63.670(j)(6) of this chapter as specified in § 60.502a(c)(3)(vii), retain records of the required minimum ratio of gasoline loaded to total liquid product loaded and the actual ratio on a 5-minute block basis. If applicable, you must retain records of the required minimum gasoline loading rate as specified in § 60.502a(c)(3)(vii) and the actual gasoline loading rate on a 5-minute block basis for a minimum of 5 years.

(vi) Each 15-minute block average operating parameter calculated following the methods specified in § 63.670(k) through (n) of this chapter, as applicable.

(vii) All periods during which the owner or operator does not perform monitoring according to the procedures in § 63.670(g), (i), and (j) of this chapter or in § 60.502a(c)(3)(vii) and (viii) as applicable. Note the start date, start time, and duration in minutes for each period.

(viii) An indication of whether “vapors displaced from gasoline cargo tanks during product loading” excludes periods when liquid product is loaded but no gasoline cargo tanks are being loaded or if liquid product loading is assumed to be loaded into gasoline cargo tanks according to the provisions in § 60.502a(c)(3)(i), records of all time periods when “vapors displaced from gasoline cargo tanks during product loading”, and records of time periods when there were no “vapors displaced from gasoline cargo tanks during product loading”.

(ix) If you comply with the flare tip velocity operating limit using the one-time flare tip velocity operating limit compliance assessment as provided in § 60.502a(c)(3)(ix), maintain records of the applicable one-time flare tip velocity operating limit compliance assessment for as long as you use this compliance method.

(x) For each parameter monitored using a CMS, retain the records specified in paragraphs (a)(2)(x)(A) through (C) of this section, as applicable:

(A) For each deviation, record the start date and time, duration, cause, and corrective action taken.

(B) For each period when there is a CMS outage or the CMS is out of control, record the start date and time, duration, cause, and corrective action taken.

(C) Each inspection or calibration of the CMS including a unique identifier, make, and model number of the CMS, and date of calibration check.

(3) The gasoline cargo tank vapor tightness documentation required under § 60.502a(e)(1) for each gasoline cargo tank loading at the affected facility shall be kept on file at the terminal in either a hardcopy or electronic form available for inspection. The documentation shall include, at a minimum, the following information:

(i) Test title: Annual Certification Test—EPA Method 27 or Railcar Bubble Leak Test Procedure.

(ii) Cargo tank owner's name and address.

(iii) Cargo tank identification number.

(iv) Test location and date.

(v) Tester name and signature.

(vi) Witnessing inspector, if any: Name, signature, and affiliation.

(vii) Vapor tightness repair: Nature of repair work and when performed in relation to vapor tightness testing.

(viii) Test results: Tank or compartment capacity, test pressure; pressure or vacuum change, mm of water; time period of test; number of leaks found with instrument; and leak definition.

(4) Records of each instance in which liquid product was loaded into a gasoline cargo tank for which vapor tightness documentation required under § 60.502a(e)(1) was not provided or available in the terminal's records. These records shall include, at a minimum:

(i) Cargo tank owner and address.

(ii) Cargo tank identification number.

(iii) Date and time liquid product was loaded into a gasoline cargo tank without proper documentation.

(iv) Date proper documentation was received or statement that proper documentation was never received.

(5) Records of each instance when liquid product was loaded into gasoline cargo tanks not using submerged filling, as defined in § 60.501a, not equipped with vapor collection equipment that is compatible with the terminal's vapor collection system, or not properly connected to the terminal's vapor collection system. These records shall include, at a minimum:

(i) Date and time of liquid product loading into gasoline cargo tank not using submerged filling, improperly equipped, or improperly connected.

(ii) Type of deviation ( e.g., not submerged filling, incompatible equipment, not properly connected).

(iii) Cargo tank identification number.

(6) A record [list, summary description, or diagram(s) showing the location] of all equipment in gasoline service at the collection of equipment at a bulk gasoline terminal affected facility and at the loading rack affected facility. A record of each leak inspection and leak identified under §§ 60.503a(a)(2) and 60.502a(j) as specified in paragraphs (a)(6)(i) through (iv) of this section:

(i) For each leak inspection, keep the following records:

(A) An indication if the leak inspection was conducted under § 60.502a(j) or § 60.503a(a)(2).

(B) Leak determination method used for the leak inspection.

(ii) For leak inspections conducted with Method 21 of appendix A-7 to this part, keep the following additional records:

(A) Date of inspection.

(B) Inspector name.

(C) Monitoring instrument identification.

(D) Identification of all equipment surveyed and the instrument reading for each piece of equipment.

(E) Date and time of instrument calibration and initials of operator performing the calibration.

(F) Calibration gas cylinder identification, certification date, and certified concentration.

(G) Instrument scale used.

(H) Results of the daily calibration drift assessment.

(iii) For leak inspections conducted with OGI, keep the records specified in section 12 of appendix K to this part.

(iv) For each leak detected during a leak inspection or by audio/visual/olfactory methods during normal duties, record the following information:

(A) The equipment type and identification number.

(B) The date the leak was detected, the name of the person who found the leak, the nature of the leak ( i.e., vapor or liquid), and the method of detection ( i.e., audio/visual/olfactory, Method 21 of appendix A-7 to this part, or OGI).

(C) The dates of each attempt to repair the leak and the repair methods applied in each attempt to repair the leak.

(D) The date of successful repair of the leak, the method of monitoring used to confirm the repair, and if Method 21 of appendix A-7 to this part is used to confirm the repair, the maximum instrument reading measured by Method 21 of appendix A-7. If OGI is used to confirm the repair, keep video footage of the repair confirmation.

(E) For each repair delayed beyond 15 calendar days after discovery of the leak, record “Repair delayed”, the reason for the delay, and the expected date of successful repair. The owner or operator (or designate) whose decision it was that repair could not be carried out in the 15-calendar-day timeframe must sign the record.

(F) For each leak that is not repairable, the maximum instrument reading measured by Method 21 of appendix A-7 to this part at the time the leak is determined to be not repairable, a video captured by the OGI camera showing that emissions are still visible, or a signed record that the leak is still detectable via audio/visual/olfactory methods.

(7) Records of each performance test or performance evaluation conducted on the affected facility and each notification and report submitted to the Administrator. For each performance test, include an indication of whether liquid product loading is assumed to be loaded into gasoline cargo tanks or periods when liquid product is loaded but no gasoline cargo tanks are being loaded are excluded in the determination of the combustion zone temperature operating limit according to the provision in § 60.503a(c)(8)(ii).

(8) Records of all 5-minute time periods during which liquid product is loaded into gasoline cargo tanks or assumed to be loaded into gasoline cargo tanks and records of all 5-minute time periods when there was no liquid product loaded into gasoline cargo tanks.

(9) Any records required to be maintained by this subpart that are submitted electronically via the EPA's Compliance and Emissions Reporting Interface (CEDRI) may be maintained in electronic format. This ability to maintain electronic copies does not affect the requirement for facilities to make records, data, and reports available upon request to a delegated authority or the EPA as part of an on-site compliance evaluation.

(b) Reporting requirements for performance tests and evaluations. Within 60 days after the date of completing each performance test and each CEMS performance evaluation required by this subpart, you must submit the results following the procedures specified in paragraph (e) of this section. As required by § 60.8(f)(2)(iv), you must include the value for the combustion zone temperature operating parameter limit set based on your performance test in the performance test report. Data collected using test methods supported by the EPA's Electronic Reporting Tool (ERT) and performance evaluations of CEMS measuring RATA pollutants that are supported by the EPA's ERT as listed on the EPA's ERT website ( https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert ) at the time of the test or performance evaluation must be submitted in a file format generated using the EPA's ERT. Alternatively, you may submit an electronic file consistent with the extensible markup language (XML) schema listed on the EPA's ERT website. Data collected using test methods that are not supported by the EPA's ERT and performance evaluations of CEMS measuring RATA pollutants that are not supported by the EPA's ERT as listed on the EPA's ERT website at the time of the test or performance evaluation must be included as an attachment in the ERT or an alternate electronic file.

(c) Reporting requirements for semiannual report. You must submit to the Administrator semiannual reports with the applicable information in paragraphs (c)(1) through (7) of this section by the dates specified in paragraph (d) of this section following the procedure specified in paragraph (e) of this section. For this subpart, the semiannual reports supersede the excess emissions and monitoring systems performance report and/or summary report form required under § 60.7. Beginning on July 8, 2024, or once the report template for this subpart has been available on the CEDRI website ( https://www.epa.gov/electronic-reporting-air-emissions/cedri ) for one year, whichever date is later, submit all subsequent reports using the appropriate electronic report template on the CEDRI website for this subpart and following the procedure specified in paragraph (e). The date report templates become available will be listed on the CEDRI website. Unless the Administrator or delegated State agency or other authority has approved a different schedule for submission of reports, the report must be submitted by the deadline specified in this subpart, regardless of the method in which the report is submitted.

(1) Report the following general facility information:

(i) Facility name.

(ii) Facility physical address, including city, county, and State.

(iii) Latitude and longitude of facility's physical location. Coordinates must be in decimal degrees with at least five decimal places.

(iv) The following information for the contact person:

(A) Name.

(B) Mailing address.

(C) Telephone number.

(D) Email address.

(v) Date of report and beginning and ending dates of the reporting period. You are no longer required to provide the date of report when the report is submitted via CEDRI.

(vi) Statement by a responsible official, with that official's name, title, and signature, certifying the truth, accuracy, and completeness of the content of the report. If your report is submitted via CEDRI, the certifier's electronic signature during the submission process replaces the requirement in this paragraph (c)(1)(vi).

(2) For each thermal oxidation system used to comply with the emission limitations in § 60.502a(b)(1) or (c)(1) by monitoring the combustion zone temperature as specified in § 60.502a(b)(1)(ii) or (c)(1)(ii), for each pressure CPMS used to comply with the requirements in § 60.502a(h), and for each vapor recovery system used to comply with the emission limitations in § 60.502a(b)(2) or (c)(2) report the following information for the CMS:

(i) For all instances when the temperature CPMS measured 3-hour rolling averages below the established operating limit or when the vapor collection system pressure exceeded the maximum loading pressure specified in § 60.502a(h) when liquid product was being loaded into gasoline cargo tanks or when the TOC CEMS measured 3-hour rolling average concentrations higher than the applicable emission limitation when the vapor recovery system was operating:

(A) The date and start time of the deviation.

(B) The duration of the deviation in hours.

(C) Each 3-hour rolling average combustion zone temperature, average pressure, or 3-hour rolling average TOC concentration during the deviation. For TOC concentration, indicate whether methane is excluded from the TOC concentration.

(D) A unique identifier for the CMS.

(E) The make, model number, and date of last calibration check of the CMS.

(F) The cause of the deviation and the corrective action taken.

(ii) For all instances that the temperature CPMS for measuring the combustion zone temperature or pressure CPMS was not operating or was out of control when liquid product was loaded into gasoline cargo tanks, or the TOC CEMS was not operating or was out of control when the vapor recovery system was operating:

(A) The date and start time of the deviation.

(B) The duration of the deviation in hours.

(C) A unique identifier for the CMS.

(D) The make, model number, and date of last calibration check of the CMS.

(E) The cause of the deviation and the corrective action taken. For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) is used, the corrective action taken shall include an indication of the use of the limited alternative for vapor recovery systems in § 60.504a(e).

(F) For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) is used, report either an indication that there were no deviations from the operating limits when using the limited alternative or report the number of each of the following types of deviations that occurred during the use of the limited alternative for vapor recovery systems in § 60.504a(e).

( 1) The number of adsorption cycles when the quantity of liquid product loaded in gasoline cargo tanks exceeded the operating limit established in § 60.504a(e)(1). Enter 0 if no deviations of this type.

( 2) The number of desorption cycles when the vacuum pressure was below the average vacuum pressure as specified in § 60.504a(e)(2)(i). Enter 0 if no deviations of this type.

( 3) The number of desorption cycles when the quantity of purge gas used was below the average quantity of purge gas as specified in § 60.504a(e)(2)(ii). Enter 0 if no deviations of this type.

( 4) The number of desorption cycles when the duration of the vacuum/purge cycle was less than the average duration as specified in § 60.504a(e)(2)(iii). Enter 0 if no deviations of this type.

(3) For each flare used to comply with the emission limitations in § 60.502a(c)(3) and for each thermal oxidation system using the flare monitoring alternative as provided in § 60.502a(c)(1)(iii), report:

(i) The date and start and end times for each of the following instances:

(A) Each 15-minute block during which there was at least one minute when gasoline vapors were routed to the flare and no pilot flame was present.

(B) Each period of 2 consecutive hours during which visible emissions exceeded a total of 5 minutes. Additionally, report the number of minutes for which visible emissions were observed during the observation or an estimate of the cumulative number of minutes in the 2-hour period for which emissions were visible based on best information available to the owner or operator.

(C) Each 15-minute period for which the applicable operating limits specified in § 63.670(d) through (f) of this chapter were not met. You must identify the specific operating limit that was not met. Additionally, report the information in paragraphs (c)(3)(i)(C)( 1) through ( 3) of this section, as applicable.

( 1) If you use the loading rate operating limits as determined in § 60.502a(c)(3)(vii) alone or in combination with the supplemental gas flow rate monitoring alternative in § 60.502a(c)(3)(viii), the required minimum ratio and the actual ratio of gasoline loaded to total product loaded for the rolling 15-minute period and, if applicable, the required minimum quantity and the actual quantity of gasoline loaded, in gallons, for the rolling 15-minute period.

( 2) If you use the supplemental gas flow rate monitoring alternative in § 60.502a(c)(3)(viii), the required minimum supplemental gas flow rate and the actual supplemental gas flow rate including units of flow rates for the 15-minute block.

( 3) If you use parameter monitoring systems other than those specified in paragraphs (c)(3)(i)(C)( 1) and ( 2) of this section, the value of the net heating value operating parameter(s) during the deviation determined following the methods in § 63.670(k) through (n) of this chapter as applicable.

(ii) The start date, start time, and duration in minutes for each period when “vapors displaced from gasoline cargo tanks during product loading” were routed to the flare or thermal oxidation system and the applicable monitoring was not performed.

(iii) For each instance reported under paragraphs (c)(3)(i) and (ii) of this section that involves CMS, report the following information:

(A) A unique identifier for the CMS.

(B) The make, model number, and date of last calibration check of the CMS.

(C) The cause of the deviation or downtime and the corrective action taken.

(4) For any instance in which liquid product was loaded into a gasoline cargo tank for which vapor tightness documentation required under § 60.502a(e)(1) was not provided or available in the terminal's records, report:

(i) Cargo tank owner and address.

(ii) Cargo tank identification number.

(iii) Date and time liquid product was loaded into a gasoline cargo tank without proper documentation.

(iv) Date proper documentation was received or statement that proper documentation was never received.

(5) For each instance when liquid product was loaded into gasoline cargo tanks not using submerged filling, as defined in § 60.501a, not equipped with vapor collection equipment that is compatible with the terminal's vapor collection system, or not properly connected to the terminal's vapor collection system, report:

(i) Date and time of liquid product loading into gasoline cargo tank not using submerged filling, improperly equipped, or improperly connected.

(ii) Type of deviation ( e.g., not submerged filling, incompatible equipment, or not properly connected).

(iii) Cargo tank identification number.

(6) Report the following information for each leak inspection required under §§ 60.502a(j)(1) and 60.503a(a)(2) and each leak identified under § 60.502a(j)(2).

(i) For each leak detected during a leak inspection required under §§ 60.502a(j)(1) and 60.503a(a)(2), report:

(A) The date of inspection.

(B) The leak determination method (OGI or Method 21 of appendix A-7 to this part).

(C) The total number and type of equipment for which leaks were detected.

(D) The total number and type of equipment for which leaks were repaired within 15 calendar days.

(E) The total number and type of equipment for which no repair attempt was made within 5 calendar days of the leaks being identified.

(F) The total number and type of equipment placed on the delay of repair, as specified in § 60.502a(j)(8).

(ii) For leaks identified under § 60.502a(j)(2), report:

(A) The total number and type of equipment for which leaks were identified.

(B) The total number and type of equipment for which leaks were repaired within 15 calendar days.

(C) The total number and type of equipment for which no repair attempt was made within 5 calendar days of the leaks being identified.

(D) The total number and type of equipment placed on the delay of repair, as specified in § 60.502a(j)(8).

(iii) The total number of leaks on the delay of repair list at the start of the reporting period.

(iv) The total number of leaks on the delay of repair list at the end of the reporting period.

(v) For each leak that was on the delay of repair list at any time during the reporting period, report:

(A) Unique equipment identification number.

(B) Type of equipment.

(C) Leak determination method (OGI, Method 21 of appendix A-7 to this part, or audio, visual, or olfactory).

(D) The reason(s) why the repair was not feasible within 15 calendar days.

(E) If applicable, the date repair was completed.

(7) If there were no deviations from the emission limitations, operating parameters, or work practice standards, then provide a statement that there were no deviations from the emission limitations, operating limits, or work practice standards during the reporting period. If there were no periods during which a CMS (including a CEMS or CPMS) was inoperable or out-of-control, then provide a statement that there were no periods during which a CMS was inoperable or out-of-control during the reporting period.

(d) Timeframe for semiannual report submissions. (1) The first semiannual report will cover the date starting with the date the source first becomes an affected facility subject to this subpart and ending with the last day of the month five months later. For example, if the source becomes an affected facility on April 15, the first semiannual report would cover the period from April 15 to September 30. The first semiannual report must be submitted on or before the last day of the month two months after the last date covered by the semiannual report. In this example, the first semiannual report would be due November 30.

(2) Subsequent semiannual reports will cover subsequent 6 calendar month periods with each report due on or before the last day of the month two months after the last date covered by the semiannual report.

(e) Requirements for electronically submitting reports. For reports required to be submitted following the procedures specified in this paragraph (e), you must submit reports to the EPA via CEDRI, which can be accessed through the EPA's Central Data Exchange (CDX) ( https://cdx.epa.gov/ ). The EPA will make all the information submitted through CEDRI available to the public without further notice to you. Do not use CEDRI to submit information you claim as confidential business information (CBI). Although we do not expect persons to assert a claim of CBI, if you wish to assert a CBI claim for some of the information in the report, you must submit a complete file in the format specified in this subpart, including information claimed to be CBI, to the EPA following the procedures in paragraphs (e)(1) and (2) of this section. Clearly mark the part or all of the information that you claim to be CBI. Information not marked as CBI may be authorized for public release without prior notice. Information marked as CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. All CBI claims must be asserted at the time of submission. Anything submitted using CEDRI cannot later be claimed CBI. Furthermore, under CAA section 114(c), emissions data are not entitled to confidential treatment, and the EPA is required to make emissions data available to the public. Thus, emissions data will not be protected as CBI and will be made publicly available. You must submit the same file submitted to the CBI office with the CBI omitted to the EPA via the EPA's CDX as described earlier in this paragraph (e).

(1) The preferred method to receive CBI is for it to be transmitted electronically using email attachments, File Transfer Protocol, or other online file sharing services. Electronic submissions must be transmitted directly to the OAQPS CBI Office at the email address oaqpscbi@epa.gov, and as described above, should include clear CBI markings. ERT files should be flagged to the attention of the Group Leader, Measurement Policy Group; all other files should be flagged to the attention of the Gasoline Distribution Sector Lead. If assistance is needed with submitting large electronic files that exceed the file size limit for email attachments, and if you do not have your own file sharing service, please email oaqpscbi@epa.gov to request a file transfer link.

(2) If you cannot transmit the file electronically, you may send CBI information through the postal service to the following address: U.S. EPA, Attn: OAQPS Document Control Officer, Mail Drop: C404-02, 109 T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. ERT files should be flagged to the attention of the Group Leader, Measurement Policy Group, and all other files should also be flagged to the attention of the Gasoline Distribution Sector Lead. The mailed CBI material should be double wrapped and clearly marked. Any CBI markings should not show through the outer envelope.

(f) Claims of EPA system outage. If you are required to electronically submit a report through CEDRI in the EPA's CDX, you may assert a claim of EPA system outage for failure to timely comply with that reporting requirement. To assert a claim of EPA system outage, you must meet the requirements outlined in paragraphs (f)(1) through (7) of this section.

(1) You must have been or will be precluded from accessing CEDRI and submitting a required report within the time prescribed due to an outage of either the EPA's CEDRI or CDX systems.

(2) The outage must have occurred within the period of time beginning five business days prior to the date that the submission is due.

(3) The outage may be planned or unplanned.

(4) You must submit notification to the Administrator in writing as soon as possible following the date you first knew, or through due diligence should have known, that the event may cause or has caused a delay in reporting.

(5) You must provide to the Administrator a written description identifying:

(i) The date(s) and time(s) when CDX or CEDRI was accessed and the system was unavailable;

(ii) A rationale for attributing the delay in reporting beyond the regulatory deadline to EPA system outage;

(iii) A description of measures taken or to be taken to minimize the delay in reporting; and

(iv) The date by which you propose to report, or if you have already met the reporting requirement at the time of the notification, the date you reported.

(6) The decision to accept the claim of EPA system outage and allow an extension to the reporting deadline is solely within the discretion of the Administrator.

(7) In any circumstance, the report must be submitted electronically as soon as possible after the outage is resolved.

(g) Claims of force majeure. If you are required to electronically submit a report through CEDRI in the EPA's CDX, you may assert a claim of force majeure for failure to timely comply with that reporting requirement. To assert a claim of force majeure, you must meet the requirements outlined in paragraphs (g)(1) through (5) of this section.

(1) You may submit a claim if a force majeure event is about to occur, occurs, or has occurred or there are lingering effects from such an event within the period of time beginning five business days prior to the date the submission is due. For the purposes of this section, a force majeure event is defined as an event that will be or has been caused by circumstances beyond the control of the affected facility, its contractors, or any entity controlled by the affected facility that prevents you from complying with the requirement to submit a report electronically within the time period prescribed. Examples of such events are acts of nature ( e.g., hurricanes, earthquakes, or floods), acts of war or terrorism, or equipment failure or safety hazard beyond the control of the affected facility ( e.g., large scale power outage).

(2) You must submit notification to the Administrator in writing as soon as possible following the date you first knew, or through due diligence should have known, that the event may cause or has caused a delay in reporting.

(3) You must provide to the Administrator:

(i) A written description of the force majeure event;

(ii) A rationale for attributing the delay in reporting beyond the regulatory deadline to the force majeure event;

(iii) A description of measures taken or to be taken to minimize the delay in reporting; and

(iv) The date by which you propose to report, or if you have already met the reporting requirement at the time of the notification, the date you reported.

(4) The decision to accept the claim of force majeure and allow an extension to the reporting deadline is solely within the discretion of the Administrator.

(5) In any circumstance, the reporting must occur as soon as possible after the force majeure event occurs.

(a) Prior to May 8, 2027, the affected source to which the provisions of this subpart apply is each bulk gasoline terminal, except those bulk gasoline terminals meeting either of the criteria listed in paragraph (a)(1) or (2) of this section. No later than May 8, 2027, the affected source to which the provisions of this subpart apply is each bulk gasoline terminal located at a major source as defined in § 63.2.

(1) Bulk gasoline terminals for which the owner or operator has documented and recorded to the Administrator's satisfaction that the result, E_T, of the following equation is less than 1, and complies with requirements in paragraphs (c), (d), (e), and (f) of this section:

(2) Bulk gasoline terminals for which the owner or operator has documented and recorded to the Administrator's satisfaction that the facility is not a major source, or is not located within a contiguous area and under common control of a facility that is a major source, as defined in § 63.2.

(b) Prior to May 8, 2027, the affected source to which the provisions of this subpart apply is each pipeline breakout station, except those pipeline breakout stations meeting either of the criteria listed in paragraph (b)(1) or (2) of this section. No later than May 8, 2027, the affected source to which the provisions of this subpart apply is each pipeline breakout station located at a major source as defined in § 63.2.

(1) Pipeline breakout stations for which the owner or operator has documented and recorded to the Administrator's satisfaction that the result, E_P, of the following equation is less than 1, and complies with requirements in paragraphs (c), (d), (e), and (f) of this section:

(2) Pipeline breakout stations for which the owner or operator has documented and recorded to the Administrator's satisfaction that the facility is not a major source, or is not located within a contiguous area and under common control of a facility that is a major source, as defined in § 63.2.

(c) Prior to May 8, 2027, a facility for which the results, E_T or E_P, of the calculation in paragraph (a)(1) or (b)(1) of this section has been documented and is less than 1.0 but greater than or equal to 0.50, is exempt from the requirements of this subpart, except that the owner or operator shall:

(2) Maintain records and provide reports in accordance with the provisions of § 63.428(l)(4).

(d) Prior to May 8, 2027, a facility for which the results, E_T or E_P, of the calculation in paragraph (a)(1) or (b)(1) of this section has been documented and is less than 0.50, is exempt from the requirements of this subpart, except that the owner or operator shall:

(2) Maintain records and provide reports in accordance with the provisions of § 63.428(l)(5).

(g) Each owner or operator of a bulk gasoline terminal or pipeline breakout station subject to the provisions of this subpart that is also subject to applicable provisions of part 60, subpart Kb, XX, or XXa, of this chapter shall comply only with the provisions in each subpart that contain the most stringent control requirements for that facility.

(i) A bulk gasoline terminal or pipeline breakout station with a Standard Industrial Classification code 2911 located within a contiguous area and under common control with a refinery complying with §§ 63.646, 63.648, 63.649, 63.650, and 63.660 is not subject to the standards in this subpart, except as specified in § 63.650.

(j) Notwithstanding any other provision of this subpart, the December 14, 1995, compliance date for existing facilities in §§ 63.424(e) and 63.428(a), (l)(4)(i), and (l)(5)(i) is stayed from December 8, 1995, to March 7, 1996.

(k) Each owner or operator of an affected source bulk gasoline terminal or pipeline breakout station must comply with the standards in this part at all times. At all times, the owner or operator must operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. The general duty to minimize emissions does not require the owner or operator to make any further efforts to reduce emissions if levels required by the applicable standard have been achieved. Determination of whether a source is operating in compliance with operation and maintenance requirements will be based on information available to the Administrator which may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source.

As used in this subpart, all terms not defined herein shall have the meaning given them in the Act; in subparts A, K, Ka, Kb, and Xxa of part 60 of this chapter; or in subpart A of this part. All terms defined in both subpart A of part 60 of this chapter and subpart A of this part shall have the meaning given in subpart A of this part. For purposes of this subpart, definitions in this section supersede definitions in other parts or subparts.

Bulk gasoline terminal means:

(1) Prior to May 8, 2027, any gasoline facility which receives gasoline by pipeline, ship or barge, and has a gasoline throughput greater than 75,700 liters per day. Gasoline throughput shall be the maximum calculated design throughput as may be limited by compliance with an enforceable condition under Federal, State, or local law and discoverable by the Administrator and any other person.

(2) On or after May 8, 2027, any gasoline facility which receives gasoline by pipeline, ship, barge, or cargo tank and subsequently loads all or a portion of the gasoline into gasoline cargo tanks for transport to bulk gasoline plants or gasoline dispensing facilities and has a gasoline throughput greater than 20,000 gallons per day (75,700 liters per day). Gasoline throughput shall be the maximum calculated design throughput for the facility as may be limited by compliance with an enforceable condition under Federal, State, or local law and discoverable by the Administrator and any other person.

Flare means a thermal combustion device using an open or shrouded flame (without full enclosure) such that the pollutants are not emitted through a conveyance suitable to conduct a performance test.

Gasoline means any petroleum distillate or petroleum distillate/alcohol blend having a Reid vapor pressure of 4.0 pounds per square inch (27.6 kilopascals) or greater, which is used as a fuel for internal combustion engines.

Pipeline breakout station means:

(1) Prior to May 8, 2027, a facility along a pipeline containing storage vessels used to relieve surges or receive and store gasoline from the pipeline for reinjection and continued transportation by pipeline or to other facilities.

(2) On or after May 8, 2027, a facility along a pipeline containing storage vessels used to relieve surges or receive and store gasoline from the pipeline for reinjection and continued transportation by pipeline to other facilities. Pipeline breakout stations do not have loading racks where gasoline is loaded into cargo tanks. If any gasoline is loaded into cargo tanks, the facility is a bulk gasoline terminal for the purposes of this subpart provided the facility-wide gasoline throughput (including pipeline throughput) exceeds the limits specified for bulk gasoline terminals.

Submerged filling means the filling of a gasoline cargo tank through a submerged fill pipe whose discharge is no more than the 6 inches from the bottom of the tank. Bottom filling of gasoline cargo tanks is included in this definition.

Thermal oxidation system means an enclosed combustion device used to mix and ignite fuel, air pollutants, and air to provide a flame to heat and oxidize hazardous air pollutants. Auxiliary fuel may be used to heat air pollutants to combustion temperatures. Thermal oxidation systems emit pollutants through a conveyance suitable to conduct a performance test.

(a) You must meet either the requirements in paragraph (a)(1) or (2) of this section, as applicable in paragraph (d) of this section.

(1) Each owner or operator of loading racks at a bulk gasoline terminal subject to the provisions of this subpart shall comply with the requirements in § 60.502 of this chapter except for paragraphs (b), (c), and (j) of that section. For purposes of this section, the term “affected facility” used in § 60.502 means the loading racks that load gasoline cargo tanks at the bulk gasoline terminals subject to the provisions of this subpart.

(2) Each owner or operator of loading racks at a bulk gasoline terminal subject to the provisions of this subpart shall comply with the requirements in § 60.502a of this chapter except for paragraphs (b) and (j) of that section and shall comply with the provisions in paragraphs (b) through (c) of this section. For purposes of this section, the term “gasoline loading rack affected facility” used in § 60.502a means “the loading racks that load gasoline cargo tanks at the bulk gasoline terminals subject to the provisions of this subpart.” For purposes of this subpart, the term “vapor-tight gasoline cargo tanks” used in § 60.502a(e) of this chapter shall have the meaning given in § 63.421. As an alternative to the pressure monitoring requirements in § 60.504a(d) of this chapter, you may comply with the requirements specified in § 63.427(f).

(b) You must meet either the emission limits in paragraph (b)(1) or (2) of this section, as applicable in paragraph (d) of this section.

(1) Emissions to the atmosphere from the vapor collection and processing systems due to the loading of gasoline cargo tanks shall not exceed 10 milligrams of total organic compounds per liter of gasoline loaded.

(2) You must comply with the provisions in § 60.502a(c) of this chapter for all loading racks that load gasoline cargo tanks at the bulk gasoline terminals subject to the provisions of this subpart, not just those that are modified or reconstructed.

(c) Each owner or operator of a bulk gasoline terminal subject to the provisions of this subpart shall discontinue loading any cargo tank that fails vapor tightness according to the test requirements in § 63.425(f), (g), and (h) until vapor tightness documentation for that gasoline cargo tank is obtained which documents that:

(1) The tank truck or railcar gasoline cargo tank has been repaired, retested, and subsequently passed either the annual certification test described in § 63.425(e) or the railcar bubble test described in § 63.425(i); or

(2) For each gasoline cargo tank failing the test in § 63.425(f) at the facility, the cargo tank meets the test requirements in either § 63.425(g) or (h); or

(3) For each gasoline cargo tank failing the test in § 63.425(g) at the facility, the cargo tank meets the test requirements in § 63.425(h).

(d) Each owner or operator shall meet the requirements in this section as expeditiously as practicable, but no later than the dates provided in paragraphs (d)(1) through (3) of this section.

(1) For facilities that commenced construction on or before February 8, 1994, each owner or operator shall meet the requirements in paragraphs (a)(1), (b)(1), and (c) of this section no later than December 15, 1997. Beginning no later than May 8, 2027, paragraphs (a)(1) and (b)(1) of this section no longer apply and each owner or operator shall meet the requirements in paragraphs (a)(2), (b)(2), and (c) of this section.

(2) For facilities that commenced construction after February 8, 1994, and on or before June 10, 2022, each owner or operator shall meet the requirements in paragraphs (a)(1), (b)(1), and (c) of this section upon startup. Beginning no later than May 8, 2027, paragraphs (a)(1) and (b)(1) of this section no longer apply and each owner or operator shall meet the requirements in paragraphs (a)(2), (b)(2), and (c) of this section.

(3) For facilities that commenced construction after June 10, 2022, each owner or operator shall meet the requirements in paragraphs (a)(2), (b)(2), and (c) of this section upon startup or July 8, 2024, whichever is later.

(e) As an alternative to § 60.502(h) and (i) or § 60.502a(h) and (i) of this chapter as specified in paragraph (a) of this section, the owner or operator may comply with paragraphs (e)(1) and (2) of this section.

(1) The owner or operator shall design and operate the vapor processing system, vapor collection system, and liquid loading equipment to prevent gauge pressure in the railcar gasoline cargo tank from exceeding the applicable test limits in § 63.425(e) and (i) during product loading. This level is not to be exceeded when measured by the procedures specified in § 60.503(d) of this chapter during any performance test or performance evaluation conducted under § 63.425(b) or (c).

(2) No pressure-vacuum vent in the bulk' gasoline terminal's vapor processing system or vapor collection system may begin to open at a system pressure less than the applicable test limits in § 63.425(e) or (i).

(a) Each owner or operator of a bulk gasoline terminal or pipeline breakout station subject to the provisions of this subpart shall equip each gasoline storage vessel according to the requirements in paragraph (a)(1) or (2) of this section, as applicable in paragraph (c) of this section.

(1) Equip each gasoline storage vessel with a design capacity greater than or equal to 75 m³ according to the requirements in § 60.112b(a)(1) through (4) of this chapter, except for the requirements in § 60.112b(a)(1)(iv) through (ix) and (a)(2)(ii) of this chapter.

(2) Equip each gasoline external floating roof storage vessel with a design capacity greater than or equal to 75 m³ according to the requirements in § 60.112b(a)(2)(ii) of this chapter if such storage vessel does not currently meet the requirements in paragraph (a)(1) of this section.

(b) Each owner or operator of a bulk gasoline terminal or pipeline breakout station subject to the provisions of this subpart shall equip each gasoline storage vessel according to the requirements in paragraphs (b)(1) of this section and, if a floating roof is used, either paragraph (b)(2) or (3) of this section, as applicable in paragraph (c) of this section.

(1) Equip, maintain, and operate each gasoline storage vessel with a design capacity greater than or equal to 75 m³ according to the requirements in § 60.112b(a)(1) through (4) of this chapter, except for the requirements in § 60.112b(a)(1)(iv) through (ix) of this chapter. Alternatively, you may elect to equip, maintain, and operate each affected gasoline storage vessel with a design capacity greater than or equal to 75 m³ according to the requirements in subpart WW of this part as specified in § 60.110b(e)(5) of this chapter.

(2) Equip, maintain, and operate each internal floating control system to maintain the vapor concentration within the storage vessel above the floating roof at or below 25 percent of the lower explosive limit (LEL) on a 5-minute rolling average basis without the use of purge gas. This standard may require additional controls beyond those specified in paragraph (b)(1) of this section. Compliance with this paragraph (b)(2) shall be determined using the methods in § 63.425(j). A deviation of the LEL level is considered an inspection failure under § 60.113b(a)(2) of this chapter or § 63.1063(d)(2) and must be remedied as such. Any repairs made must be confirmed effective through re-monitoring of the LEL and meeting the level in this paragraph (b)(2) within the timeframes specified in § 60.113b(a)(2) or § 63.1063(e), as applicable.

(3) Equip, maintain, and operate each gasoline external floating roof storage vessel with a design capacity greater than or equal to 75 m³ with fitting controls as specified in § 60.112b(a)(2)(ii) of this chapter.

(c) Each gasoline storage vessel at bulk gasoline terminals and pipeline breakout stations shall be in compliance with the requirements of this section as expeditiously as practicable, but no later than the dates provided in paragraphs (c)(1) through (3) of this section.

(1) For facilities that commenced construction on or before February 8, 1994, each gasoline storage vessel shall meet the requirements in paragraph (a) of this section no later than December 15, 1997. Beginning no later than May 8, 2027, paragraph (a) of this section no longer applies and each gasoline storage vessel shall meet the requirements in paragraphs (b)(1) and (2) of this section no later than May 8, 2027. If applicable, the fitting controls required in paragraph (b)(3) of this section must be installed the next time the storage vessel is completely emptied and degassed, or by May 8, 2034, whichever occurs first.

(2) For facilities that commenced construction after February 8, 1994, and on or before June 10, 2022, each gasoline storage vessel shall meet the requirements in paragraph (a) of this section upon startup. Beginning no later than May 8, 2027, paragraph (a) of this section no longer applies and each gasoline storage vessel shall meet the requirements in paragraphs (b)(1) and (2) of this section no later than May 8, 2027. If applicable, the fitting controls required in paragraph (b)(3) of this section must be installed the next time the storage vessel is completely emptied and degassed, or by May 8, 2034, whichever occurs first.

(3) For facilities that commenced construction after June 10, 2022, each owner or operator shall meet the requirements in paragraph (b) of this section upon startup or July 8, 2024, whichever is later.

(a) Each owner or operator of a bulk gasoline terminal or pipeline breakout station subject to the provisions of this subpart shall implement a leak detection and repair program for all equipment in gasoline service according to the requirements in paragraph (b) or (c) of this section, as applicable in paragraph (e) of this section and minimize gasoline vapor losses according to paragraph (d) of this section.

(b) Each owner or operator of a bulk gasoline terminal or pipeline breakout station subject to the provisions of this subpart shall perform a monthly leak inspection of all equipment in gasoline service. For this inspection, detection methods incorporating sight, sound, and smell are acceptable. Each piece of equipment shall be inspected during the loading of a gasoline cargo tank.

(1) A logbook shall be used and shall be signed by the owner or operator at the completion of each inspection. A section of the log shall contain a list, summary description, or diagram(s) showing the location of all equipment in gasoline service at the facility.

(2) Each detection of a liquid or vapor leak shall be recorded in the logbook. When a leak is detected, an initial attempt at repair shall be made as soon as practicable, but no later than 5 calendar days after the leak is detected. Repair or replacement of leaking equipment shall be completed within 15 calendar days after detection of each leak, except as provided in paragraph (b)(3) of this section.

(3) Delay of repair of leaking equipment will be allowed upon a demonstration to the Administrator that repair within 15 days is not feasible. The owner or operator shall provide the reason(s) a delay is needed and the date by which each repair is expected to be completed.

(4) As an alternative to compliance with the provisions in paragraphs (b)(1) through (3) of this section, owners or operators may implement an instrument leak monitoring program that has been demonstrated to the Administrator as at least equivalent.

(c) Comply with the requirements in § 60.502a(j) of this chapter except as provided in paragraphs (c)(1) through (3) of this section.

(1) The frequency for optical gas imaging (OGI) monitoring shall be semiannually rather than quarterly as specified in § 60.502a(j)(1)(i).

(2) The frequency for Method 21 monitoring of pumps and valves shall be semiannually rather than quarterly as specified in § 60.502a(j)(1)(ii)(A) and (B).

(3) The frequency of monitoring of pressure relief devices shall be semiannually and within 5 calendar days after each pressure release rather than quarterly and within 5 calendar days after each pressure release as specified in § 60.502a(j)(4)(i).

(d) Owners and operators shall not allow gasoline to be handled in a manner that would result in vapor releases to the atmosphere for extended periods of time. Measures to be taken include, but are not limited to, the following:

(1) Minimize gasoline spills;

(2) Clean up spills as expeditiously as practicable;

(3) Cover all open gasoline containers with a gasketed seal when not in use; and

(4) Minimize gasoline sent to open waste collection systems that collect and transport gasoline to reclamation and recycling devices, such as oil/water separators.

(e) Compliance with the provisions of this section shall be achieved as expeditiously as practicable, but no later than the dates provided in paragraphs (e)(1) through (3) of this section.

(1) For facilities that commenced construction on or before February 8, 1994, meet the requirements in paragraphs (b) and (d) of this section no later than December 15, 1997. Beginning no later than May 8, 2027, paragraph (b) of this section no longer applies and facilities shall meet the requirements in paragraphs (c) and (d) of this section no later than May 8, 2027.

(2) For facilities that commenced construction after February 8, 1994, and on or before June 10, 2022, meet the requirements in paragraphs (b) and (d) of this section upon startup. Beginning no later than May 8, 2027, paragraph (b) of this section no longer applies and facilities shall meet the requirements in paragraphs (c) and (d) of this section no later than May 8, 2027.

(3) For facilities that commenced construction after June 10, 2022, meet the requirements in paragraph (c) and (d) of this section upon startup or July 8, 2024, whichever is later.

(a) Performance test and evaluation requirements. Each owner or operator subject to the emission standard in § 63.422(b)(1) or § 60.112b(a)(3)(ii) of this chapter shall comply with the requirements in paragraph (b) of this section. Each owner or operator subject to the emission standard in § 63.422(b)(2) shall comply with the requirements in paragraph (c) of this section. Performance tests shall be conducted under representative conditions when liquid product is being loaded into gasoline cargo tanks and shall include periods between gasoline cargo tank loading (when one cargo tank is disconnected and another cargo tank is moved into position for loading) provided that liquid product loading into gasoline cargo tanks is conducted for at least a portion of each 5 minute block of the performance test. You may not conduct performance tests during periods of malfunction. You must record the process information that is necessary to document operating conditions during the test and include in such record an explanation to support that such conditions represent normal operation. Upon request, you shall make available to the Administrator such records as may be necessary to determine the conditions of performance tests.

(b) Gasoline loading rack and gasoline storage vessel performance test requirements. For gasoline loading racks subject to the requirements in § 63.422(b)(1) or gasoline storage vessels subject to the requirements in § 60.112b(a)(3)(ii) of this chapter:

(1) Conduct a performance test on the vapor processing and collection systems according to either paragraph (b)(1)(i) or (ii) of this section.

(i) Use the test methods and procedures in § 60.503 of this chapter, except a reading of 500 ppm shall be used to determine the level of leaks to be repaired under § 60.503(b) of this chapter, or

(ii) Use alternative test methods and procedures in accordance with the alternative test method requirements in § 63.7(f).

(2) The performance test requirements of § 60.503(c) of this chapter do not apply to flares defined in § 63.421 and meeting the flare requirements in § 63.11(b). The owner or operator shall demonstrate that the flare and associated vapor collection system is in compliance with the requirements in § 63.11(b) and § 60.503(a), (b), and (d) of this chapter, respectively.

(3) For each performance test conducted under paragraph (b)(1) of this section, the owner or operator shall determine a monitored operating parameter value for the vapor processing system using the following procedure:

(i) During the performance test, continuously record the operating parameter under § 63.427(a);

(ii) Determine an operating parameter value based on the parameter data monitored during the performance test, supplemented by engineering assessments and the manufacturer's recommendations; and

(iii) Provide for the Administrator's approval the rationale for the selected operating parameter value, and monitoring frequency and averaging time, including data and calculations used to develop the value and a description of why the value, monitoring frequency, and averaging time demonstrate continuous compliance with the emission standard in § 63.422(b)(1) or § 60.112b(a)(3)(ii) of this chapter.

(4) For performance tests performed after the initial test, the owner or operator shall document the reasons for any change in the operating parameter value since the previous performance test.

(c) Gasoline loading rack performance test and evaluation requirements. For gasoline loading rack sources subject to the requirements in § 63.422(b)(2):

(1) Conduct performance tests or evaluations on the vapor processing and collection systems according to the requirements in § 60.503a(a), (c) and (d) of this chapter.

(2) The first performance test or performance evaluation of the continuous emissions monitoring system (CEMS) shall be conducted within 180 days of the date affected source begins compliance with the requirements in § 63.422(b)(2). A previously conducted performance test may be used to satisfy this requirement if the conditions in paragraphs (c)(2)(i) through (v) of this section are met. Prior to conducting this performance test or evaluation, you must continue to meet the monitoring and operating limits that apply based on the previously conducted performance test.

(i) The performance test was conducted on or after May 8, 2022.

(ii) No changes have been made to the process or control device since the time of the performance test.

(iii) The operating conditions, test methods, and test requirements ( e.g., length of test) used for the previous performance test conform to the requirements in paragraph (c)(1) of this section.

(iv) The temperature in the combustion zone was recorded during the performance test as specified in § 60.503a(c)(8)(i) of this chapter and can be used to establish the operating limit as specified in § 60.503a(c)(8)(ii) through (iv) of this chapter.

(v) The performance test demonstrates compliance with the emission limit specified in § 63.422(b)(2).

(3) For loading racks complying with the mass loading emission limit in § 60.502a(c)(1) of this chapter, subsequent performance tests shall be conducted no later than 60 calendar months after the previous performance test.

(4) For loading racks complying with the concentration emission limit in § 60.502a(c)(2) of this chapter, subsequent performance evaluations of CEMS for the vapor collection and processing system shall be conducted no later than 12 calendar months after the previous performance evaluation.

(d) Gasoline storage vessel requirements. The owner or operator of each gasoline storage vessel subject to the provisions of § 63.423 shall comply with § 60.113b of this chapter and, if applicable, the provisions in paragraph (j) of this section. If a closed vent system and control device are used, as specified in § 60.112b(a)(3) of this chapter, to comply with the requirements in § 63.423, the owner or operator shall also comply with the requirements in paragraph (d)(1) or (2) of this section, as applicable.

(1) If the gasoline storage vessel is subject to the provision in § 63.423(a) or the provision in § 63.423(b) and a control device other than a flare is used for the gasoline storage vessel, the owner or operator shall also comply with the requirements in paragraph (b) of this section.

(2) If the gasoline storage vessel is subject to the provision in § 63.423(b) and a flare is used as the control device for the gasoline storage vessel, you must comply with the requirements in § 60.502a(c)(3) of this chapter as indicated in paragraphs (d)(2)(i) and (ii) of this section rather than the requirements in § 60.18(e) and (f) of this chapter as specified in § 60.113b(d) of this chapter.

(i) At § 60.502a(c)(3)(i) of this chapter, replace “vapors displaced from gasoline cargo tanks during product loading” with “vapors from the gasoline storage vessel.”

(ii) Section 60.502a(c)(3)(vi) through (ix) of this chapter does not apply.

(e) * * *

(1) Method 27 of appendix A-8 to part 60 of this chapter. Conduct the test using a time period (t) for the pressure and vacuum tests of 5 minutes. The initial pressure (P_i) for the pressure test shall be 460 millimeters (mm) of water (H₂ O) (18 inches (in.) H₂ O), gauge. The initial vacuum (V_i) for the vacuum test shall be 150 mm H₂ O (6 in. H₂ O), gauge. Each owner or operator shall implement the requirements in paragraph (e)(1)(i) or (ii) of this section, as applicable in paragraph (e)(1)(iii) of this section.

(i) The maximum allowable pressure and vacuum changes (Δ p, Δ v) are as shown in the second column of table 1 to this paragraph (e)(1).

(ii) The maximum allowable pressure and vacuum changes (Δ p, Δ v) are as shown in the third column of table 1 to this paragraph (e)(1).

(iii) Compliance with the provisions of this section shall be achieved as expeditiously as practicable, but no later than the dates provided in paragraphs (e)(1)(iii)(A) and (B) of this section.

(A) For facilities that commenced construction on or before June 10, 2022, meet the requirements in paragraph (e)(1)(i) of this section prior to May 8, 2027, and meet the requirements in paragraph (e)(1)(ii) of this section no later than May 8, 2027.

(B) For facilities that commenced construction after June 10, 2022, meet the requirements in paragraph (e)(1)(ii) of this section upon startup or July 8, 2024, whichever is later.

(f) Leak detection test. The leak detection test shall be performed using Method 21 of appendix A-7 to part 60 of this chapter. A vapor-tight gasoline cargo tank shall have no leaks at any time when tested according to the procedures in this paragraph (f).

(1) The instrument reading that defines a leak is 10,000 ppm (as propane). Use propane to calibrate the instrument, setting the span at the leak definition. The response time to 90 percent of the final stable reading shall be less than 8 seconds for the detector with the sampling line and probe attached.

(g) * * *

(3) * * *

N = 5-minute continuous performance standard at any time from the fourth column of table 1 to paragraph (e)(1) of this section, inches H₂ O.

(h) Continuous performance pressure decay test. The continuous performance pressure decay test shall be performed using Method 27 in appendix A to part 60 of this chapter. Conduct only the positive pressure test using a time period (t) of 5 minutes. The initial pressure (P_i) shall be 460 mm H₂ O (18 in. H₂ O), gauge. The maximum allowable 5-minute pressure change (Δ p) which shall be met at any time is shown in the fourth column of table 1 to paragraph (e)(1) of this section.

(j) LEL monitoring procedures. Compliance with the vapor concentration below the LEL level for internal floating roof storage vessels at § 63.423(b)(2) shall be determined based on the procedures specified in paragraphs (j)(1) through (5) of this section. If tubing is necessary to obtain the measurements, the tubing must be non-crimping and made of Teflon or other inert material.

(1) LEL monitoring must be conducted at least once every 12 months and at other times upon request by the Administrator. If the measurement cannot be performed due to wind speeds exceeding those specified in paragraph (j)(3)(iii) of this section, the measurement must be performed within 30 days of the previous attempt.

(2) The calibration of the LEL meter must be checked per manufacturer specifications immediately before and after the measurements as specified in paragraphs (j)(2)(i) and (ii) of this section. If tubing will be used for the measurements, the tubing must be attached during calibration so that the calibration gas travels through the entire measurement system.

(i) Conduct the span check using a calibration gas recommended by the LEL meter manufacturer. The calibration gas must contain a single hydrocarbon at a concentration corresponding to 50 percent of the LEL ( e.g., 2.50 percent by volume when using methane as the calibration gas). The vendor must provide a Certificate of Analysis for the gas, and the certified concentration must be within ±2 percent ( e.g., 2.45 percent—2.55 percent by volume when using methane as the calibration gas). The LEL span response must be between 49 percent and 51 percent. If the span check prior to the measurements does not meet this requirement, the LEL meter must be recalibrated or replaced. If the span check after the measurements does not meet this requirement, the LEL meter must be recalibrated or replaced, and the measurements must be repeated.

(ii) Check the instrumental offset response using a certified compressed gas cylinder of zero air or an ambient environment that is free of organic compounds. The pre-measurement instrumental offset response must be 0 percent LEL. If the LEL meter does not meet this requirement, the LEL meter must be recalibrated or replaced.

(3) Conduct the measurements as specified in paragraphs (j)(3)(i) through (iv) of this section.

(i) Measurements of the vapors within the internal floating roof storage vessel must be collected no more than 3 feet above the internal floating roof.

(ii) Measurements shall be taken for a minimum of 20 minutes, logging the measurements at least once every 15 seconds, or until one 5-minute average as determined according to paragraph (j)(5)(ii) of this section exceeds the level specified in § 63.423(b)(2).

(iii) Measurements shall be taken when the wind speed at the top of the tank is 5 mph or less to the extent practicable, but in no case shall measurements be taken when the sustained wind speed at top of tank is greater than the annual average wind speed at the site or 15 mph, whichever is less.

(iv) Measurements should be conducted when the internal floating roof is floating with limited product movement (limited filling or emptying of the tank).

(4) To determine the actual vapor concentration within the storage vessel, the percent of the LEL “as the calibration gas” must be corrected according to one of the following procedures. Alternatively, if the LEL meter used has correction factors that can be selected from the meter's program, you may enable this feature to automatically apply one of the correction factors specified in paragraphs (j)(4)(i) and (ii) of this section.

(i) Multiply the measurement by the published gasoline vapor correction factor for the specific LEL meter and calibration gas used.

(ii) If there is no published correction factor for gasoline vapors for the specific LEL meter used, multiply the measurement by the published correction factor for butane as a surrogate for determining the LEL of gasoline vapors. The correction factor must correspond to the calibration gas used.

(5) Use the calculation procedures in paragraphs (j)(5)(i) through (iii) of this section to determine compliance with the LEL level.

(i) For each minute while measurements are being taken, determine the one-minute average reading as the arithmetic average of the corrected individual measurements (taken at least once every 15 seconds) during the minute.

(ii) Starting with the end of the fifth minute of data, calculate a five-minute rolling average as the arithmetic average of the previous five one-minute readings determined under paragraph (j)(5)(i) of this section. Determine a new five-minute average reading for every subsequent one-minute reading.

(iii) Each five-minute rolling average must meet the LEL level specified in § 63.423(b)(2).

(a) Each owner or operator of a bulk gasoline terminal subject to the provisions in § 63.422(b)(1) shall install, calibrate, certify, operate, and maintain, according to the manufacturer's specifications, a continuous monitoring system (CMS) as specified in paragraph (a)(1), (2), (3), or (4) of this section, except as allowed in paragraph (a)(5) of this section.

(3) Where a thermal oxidation system is used, a CPMS capable of measuring temperature must be installed in the firebox or in the ductwork immediately downstream from the firebox in a position before any substantial heat exchange occurs.

(b) Each owner or operator of a bulk gasoline terminal subject to the provisions in § 63.422(b)(1) shall operate the vapor processing system in a manner not to exceed the operating parameter value for the parameter described in paragraphs (a)(1) and (2) of this section, or to go below the operating parameter value for the parameter described in paragraph (a)(3) of this section, and established using the procedures in § 63.425(b). In cases where an alternative parameter pursuant to paragraph (a)(5) of this section is approved, each owner or operator shall operate the vapor processing system in a manner not to exceed or not to go below, as appropriate, the alternative operating parameter value. Operation of the vapor processing system in a manner exceeding or going below the operating parameter value, as specified above, shall constitute a violation of the emission standard in § 63.422(b)(1).

(c) Except as provided in paragraph (f) of this section, each owner or operator of a bulk gasoline terminal subject to the provisions in § 63.422(b)(2) shall install, calibrate, certify, operate, and maintain a CMS as specified in § 60.504a(a) through (d) of this chapter, as applicable. You may use the limited alternative monitoring methods as specified in § 60.504a(e) of this chapter, if applicable.

(d) Each owner or operator of a bulk gasoline terminal subject to the provisions in § 63.422(b)(2) shall operate the vapor processing system in a manner consistent with the minimum and/or maximum operating parameter value or procedures described in §§ 60.502a(a) and (c) and 60.504a(a) and (c) of this chapter. Operation of the vapor processing system in a manner that constitutes a period of excess emissions or failure to perform procedures required shall constitute a deviation of the emission standard in § 63.422(b)(2).

(e) Each owner or operator of gasoline storage vessels subject to the provisions of § 63.423 shall comply with the monitoring requirements in § 60.116b of this chapter, except records shall be kept for at least 5 years. If a closed vent system and control device are used, as specified in § 60.112b(a)(3) of this chapter, to comply with the requirements in § 63.423, the owner or operator shall also comply with the requirements in paragraph (e)(1) or (2) of this section, as applicable.

(1) If the gasoline storage vessel is subject to the provision in § 63.423(a) or if the gasoline storage vessel is subject to the provision in § 63.423(b) and a control device other than a flare is used for the gasoline storage vessel, the owner or operator shall also comply with the requirements in paragraph (a) of this section.

(2) If the gasoline storage vessel is subject to the provision in § 63.423(b) and a flare is used as the control device for the affected gasoline storage vessel, you must comply with the monitoring requirements in § 60.504a(c) of this chapter.

(f) As an alternative to the pressure monitoring requirements in § 60.504a(d) of this chapter, you may comply with the pressure monitoring requirements in § 60.503(d) of this chapter during any performance test or performance evaluation conducted under § 63.425(c) to demonstrate compliance with the provisions in § 60.502a(h) of this chapter.

(a) The initial notifications required for existing affected sources under § 63.9(b)(2) shall be submitted by 1 year after an affected source becomes subject to the provisions of this subpart or by December 16, 1996, whichever is later. Affected sources that are major sources on December 16, 1996, and plan to be area sources by December 15, 1997, shall include in this notification a brief, non-binding description of and schedule for the action(s) that are planned to achieve area source status.

(b) Each owner or operator of a bulk gasoline terminal subject to the provisions of this subpart shall keep records in either hardcopy or electronic form of the test results for each gasoline cargo tank loading at the facility for at least 5 years as specified in paragraphs (b)(1) through (3) of this section. Each owner or operator of a bulk gasoline terminal subject to the provisions of this subpart shall keep records for at least 5 years as specified in paragraphs (b)(4) and (5) of this section.

(1) Annual certification testing performed under § 63.425(e) and railcar bubble leak testing performed under § 63.425(i); and

(2) Continuous performance testing performed at any time at that facility under § 63.425(f), (g), and (h).

(3) The documentation file shall be kept up-to-date for each gasoline cargo tank loading at the facility. The documentation for each test shall include, as a minimum, the following information:

(i) Name of test: Annual Certification Test—Method 27 (§ 63.425(e)(1)); Annual Certification Test—Internal Vapor Valve (§ 63.425(e)(2)); Leak Detection Test (§ 63.425(f)); Nitrogen Pressure Decay Field Test (§ 63.425(g)); Continuous Performance Pressure Decay Test (§ 63.425(h)); or Railcar Bubble Leak Test Procedure (§ 63.425(i)).

(ii) Cargo tank owner's name and address.

(iii) Cargo tank identification number.

(iv) Test location and date.

(v) Tester name and signature.

(vi) Witnessing inspector, if any: Name, signature, and affiliation.

(vii) Vapor tightness repair: Nature of repair work and when performed in relation to vapor tightness testing.

(viii) Test results: tank or compartment capacity; test pressure; pressure or vacuum change, mm of water; time period of test; number of leaks found with instrument; and leak definition.

(4) Records of each instance in which liquid product was loaded into a gasoline cargo tank for which vapor tightness documentation required under § 60.502(e)(1) or § 60.502a(e)(1) of this chapter, as applicable, was not provided or available in the terminal's records. These records shall include, at a minimum:

(i) Cargo tank owner and address.

(ii) Cargo tank identification number.

(iii) Date and time liquid product was loaded into a gasoline cargo tank without proper documentation.

(iv) Date proper documentation was received or statement that proper documentation was never received.

(5) Records of each instance when liquid product was loaded into gasoline cargo tanks not using submerged filling, as defined in § 63.421, not equipped with vapor collection equipment that is compatible with the terminal's vapor collection system, or not properly connected to the terminal's vapor collection system. These records shall include, at a minimum:

(i) Date and time of liquid product loading into gasoline cargo tank not using submerged filling, improperly equipped or improperly connected.

(ii) Type of deviation ( e.g., not submerged filling, incompatible equipment, not properly connected).

(iii) Cargo tank identification number.

(c) Each owner or operator of a bulk gasoline terminal subject to the provisions in § 63.422(b)(1) shall:

(1) Keep an up-to-date, readily accessible record of the continuous monitoring data required under § 63.427(a). This record shall indicate the time intervals during which loadings of gasoline cargo tanks have occurred or, alternatively, shall record the operating parameter data only during such loadings. The date and time of day shall also be indicated at reasonable intervals on this record.

(2) Record and report simultaneously with the notification of compliance status required under § 63.9(h):

(i) All data and calculations, engineering assessments, and manufacturer's recommendations used in determining the operating parameter value under § 63.425(b); and

(ii) The following information when using a flare under provisions of § 63.11(b) to comply with § 63.422(b):

(A) Flare design ( i.e., steam-assisted, air-assisted, or non-assisted); and

(B) All visible emissions readings, heat content determinations, flow rate measurements, and exit velocity determinations made during the compliance determination required under § 63.425(b).

(3) If an owner or operator requests approval to use a vapor processing system or monitor an operating parameter other than those specified in § 63.427(a), the owner or operator shall submit a description of planned reporting and recordkeeping procedures. The Administrator will specify appropriate reporting and recordkeeping requirements as part of the review of the permit application.

(4) Keep written procedures required under § 63.8(d)(2) on record for the life of the affected source or until the affected source is no longer subject to the provisions of this part, to be made available for inspection, upon request, by the Administrator. If the performance evaluation plan is revised, you shall keep previous ( i.e., superseded) versions of the performance evaluation plan on record to be made available for inspection, upon request, by the Administrator, for a period of 5 years after each revision to the plan. The program of corrective action shall be included in the plan as required under § 63.8(d)(2).

(d) Each owner or operator of a bulk gasoline terminal subject to the provisions in § 63.422(b)(2) shall keep records as specified in paragraphs (d)(1) through (4) of this section, as applicable, for a minimum of five years unless otherwise specified in this section:

(1) For each thermal oxidation system used to comply with the emission limitations in § 63.422(b)(2) by monitoring the combustion zone temperature as specified in § 60.502a(c)(1)(ii) of this chapter, for each pressure CPMS used to comply with the requirements in § 60.502a(h) of this chapter, and for each vapor recovery system used to comply with the emission limitations in § 63.422(b)(2), maintain records, as applicable, of:

(i) The applicable operating or emission limit for the CMS. For combustion zone temperature operating limits, include the applicable date range the limit applies based on when the performance test was conducted.

(ii) Each 3-hour rolling average combustion zone temperature measured by the temperature CPMS, each 5-minute average reading from the pressure CPMS, and each 3-hour rolling average total organic compounds (TOC) concentration (as propane) measured by the TOC CEMS.

(iii) For each deviation of the 3-hour rolling average combustion zone temperature operating limit, maximum loading pressure specified in § 60.502a(h) of this chapter, or 3-hour rolling average TOC concentration (as propane), the start date and time, duration, cause, and the corrective action taken.

(iv) For each period when there was a CMS outage or the CMS was out of control, the start date and time, duration, cause, and the corrective action taken. For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) of this chapter is used, the corrective action taken shall include an indication of the use of the limited alternative for vapor recovery systems in § 60.504a(e).

(v) Each inspection or calibration of the CMS including a unique identifier, make, and model number of the CMS, and date of calibration check. For TOC CEMS, include the type of CEMS used ( i.e., flame ionization detector, nondispersive infrared analyzer) and an indication of whether methane is excluded from the TOC concentration reported in paragraph (d)(1)(ii) of this section.

(vi) TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) of this chapter is used, also keep records of:

(A) The quantity of liquid product loaded in gasoline cargo tanks for the past 10 adsorption cycles prior to the CEMS outage.

(B) The vacuum pressure, purge gas quantities, and duration of the vacuum/purge cycles used for the past 10 desorption cycles prior to the CEMS outage.

(C) The quantity of liquid product loaded in gasoline cargo tanks for each adsorption cycle while using the alternative.

(D) The vacuum pressure, purge gas quantities, and duration of the vacuum/purge cycles for each desorption cycle while using the alternative.

(2) For each flare used to comply with the emission limitations in § 63.422(b)(2) and for each thermal oxidation system using the flare monitoring alternative as provided in § 60.502a(c)(1)(iii) of this chapter, maintain records of:

(i) The output of the monitoring device used to detect the presence of a pilot flame as required in § 63.670(b) for a minimum of 2 years. Retain records of each 15-minute block during which there was at least one minute that no pilot flame is present when gasoline vapors were routed to the flare for a minimum of 5 years. The record must identify the start and end time and date of each 15-minute block.

(ii) Visible emissions observations as specified in paragraphs (d)(2)(ii)(A) and (B) of this section, as applicable, for a minimum of 3 years.

(A) If visible emissions observations are performed using Method 22 of appendix A-7 to part 60 of this chapter, the record must identify the date, the start and end time of the visible emissions observation, and the number of minutes for which visible emissions were observed during the observation. If the owner or operator performs visible emissions observations more than one time during a day, include separate records for each visible emissions observation performed.

(B) For each 2-hour period for which visible emissions are observed for more than 5 minutes in 2 consecutive hours but visible emissions observations according to Method 22 of appendix A-7 to part 60 of this chapter were not conducted for the full 2-hour period, the record must include the date, the start and end time of the visible emissions observation, and an estimate of the cumulative number of minutes in the 2-hour period for which emissions were visible based on best information available to the owner or operator.

(iii) Each 15-minute block period during which operating values are outside of the applicable operating limits specified in § 63.670(d) through (f) when liquid product is being loaded into gasoline cargo tanks for at least 15-minutes identifying the specific operating limit that was not met.

(iv) The 15-minute block average cumulative flows for the thermal oxidation system vent gas or flare vent gas and, if applicable, total steam, perimeter assist air, and premix assist air specified to be monitored under § 63.670(i), along with the date and start and end time for the 15-minute block. If multiple monitoring locations are used to determine cumulative vent gas flow, total steam, perimeter assist air, and premix assist air, retain records of the 15-minute block average flows for each monitoring location for a minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in subsequent calculations for a minimum of 5 years. If pressure and temperature monitoring is used, retain records of the 15-minute block average temperature, pressure and molecular weight of the thermal oxidation system vent gas, flare vent gas, or assist gas stream for each measurement location used to determine the 15-minute block average cumulative flows for a minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in subsequent calculations for a minimum of 5 years. If you use the supplemental gas flow rate monitoring alternative in § 60.502a(c)(3)(viii) of this chapter, the required supplemental gas flow rate (winter and summer, if applicable) and the actual monitored supplemental gas flow rate for the 15-minute block. Retain the supplemental gas flow rate records for a minimum of 5 years.

(v) The thermal oxidation system vent gas or flare vent gas compositions specified to be monitored under § 63.670(j). Retain records of individual component concentrations from each compositional analyses for a minimum of 2 years. If NHV_vg analyzer is used, retain records of the 15-minute block average values for a minimum of 5 years. If you demonstrate your gas streams have consistent composition using the provisions in § 63.670(j)(6) as specified in § 60.502a(c)(3)(vii) of this chapter, retain records of the required minimum ratio of gasoline loaded to total liquid product loaded and the actual ratio on a 15-minute block basis. If applicable, you must retain records of the required minimum gasoline loading rate as specified in § 60.502a(c)(3)(vii) and the actual gasoline loading rate on a 15-minute block basis for a minimum of 5 years.

(vi) Each 15-minute block average operating parameter calculated following the methods specified in § 63.670(k) through (n), as applicable.

(vii) All periods during which the owner or operator does not perform monitoring according to the procedures in § 63.670(g), (i), and (j) or in § 60.502a(c)(3)(vii) and (viii) of this chapter as applicable. Note the start date, start time, and duration in minutes for each period.

(viii) An indication of whether “vapors displaced from gasoline cargo tanks during product loading” excludes periods when liquid product is loaded but no gasoline cargo tanks are being loaded or if liquid product loading is assumed to be loaded into gasoline cargo tanks according to the provisions in § 60.502a(c)(3)(i) of this chapter, records of all time periods when “vapors displaced from gasoline cargo tanks during product loading”, and records of time periods when there were no “vapors displaced from gasoline cargo tanks during product loading”.

(ix) If you comply with the flare tip velocity operating limit using the one-time flare tip velocity operating limit compliance assessment as provided in § 60.502a(c)(3)(ix) of this chapter, maintain records of the applicable one-time flare tip velocity operating limit compliance assessment for as long as you use this compliance method.

(x) For each parameter monitored using a CMS, retain the records specified in paragraphs (d)(2)(x)(A) through (C) of this section, as applicable:

(A) For each deviation, record the start date and time, duration, cause, and corrective action taken.

(B) For each period when there is a CMS outage or the CMS is out of control, record the start date and time, duration, cause, and corrective action taken.

(C) Each inspection or calibration of the CMS including a unique identifier, make, and model number of the CMS, and date of calibration check.

(3) Records of all 5-minute time periods during which liquid product is loaded into gasoline cargo tanks or assumed to be loaded into gasoline cargo tanks and records of all 5-minute time periods when there was no liquid product loaded into gasoline cargo tanks.

(4) Keep written procedures required under § 63.8(d)(2) on record for the life of the affected source or until the affected source is no longer subject to the provisions of this part, to be made available for inspection, upon request, by the Administrator. If the performance evaluation plan is revised, you shall keep previous ( i.e., superseded) versions of the performance evaluation plan on record to be made available for inspection, upon request, by the Administrator, for a period of 5 years after each revision to the plan. The program of corrective action shall be included in the plan as required under § 63.8(d)(2).

(e) Each owner or operator of storage vessels subject to the provisions of this subpart shall keep records as specified in § 60.115b of this chapter, except records shall be kept for at least 5 years. Additionally, for each storage vessel complying with the provisions in § 63.423(b)(2), keep records of each LEL monitoring event as specified in paragraphs (e)(1) through (9) of this section.

(1) Date and time of the LEL monitoring, and the storage vessel being monitored.

(2) A description of the monitoring event ( e.g., monitoring conducted concurrent with visual inspection required under § 60.113b(a)(2) of this chapter or § 63.1063(d)(2); monitoring that occurred on a date other than the visual inspection required under § 60.113b(a)(2) or § 63.1063(d)(2); re-monitoring due to high winds; re-monitoring after repair attempt).

(3) Wind speed at the top of the storage vessel on the date of LEL monitoring.

(4) The LEL meter manufacturer and model number used, as well as an indication of whether tubing was used during the LEL monitoring, and if so, the type and length of tubing used.

(5) Calibration checks conducted before and after making the measurements, including both the span check and instrumental offset. This includes the hydrocarbon used as the calibration gas, the Certificate of Analysis for the calibration gas(es), the results of the calibration check, and any corrective action for calibration checks that do not meet the required response.

(6) Location of the measurements and the location of the floating roof.

(7) Each measurement (taken at least once every 15 seconds). The records should indicate whether the recorded values were automatically corrected using the meter's programming. If the values were not automatically corrected, record both the raw (as the calibration gas) and corrected measurements, as well as the correction factor used.

(8) Each 5-minute rolling average reading.

(9) If the vapor concentration of the storage vessel was above 25 percent of the LEL on a 5-minue rolling average basis, a description of whether the floating roof was repaired, replaced, or taken out of gasoline service.

(f) Each owner or operator complying with the provisions of § 63.424 shall keep records of the information in paragraphs (f)(1) and (2) of this section.

(1) Each owner or operator complying with the provisions of § 63.424(b) shall record the following information in the logbook for each leak that is detected:

(i) The equipment type and identification number;

(ii) The nature of the leak ( i.e., vapor or liquid) and the method of detection ( i.e., sight, sound, or smell);

(iii) The date the leak was detected and the date of each attempt to repair the leak;

(iv) Repair methods applied in each attempt to repair the leak;

(v) “Repair delayed” and the reason for the delay if the leak is not repaired within 15 calendar days after discovery of the leak;

(vi) The expected date of successful repair of the leak if the leak is not repaired within 15 days; and

(vii) The date of successful repair of the leak.

(2) Each owner or operator complying with the provisions of § 63.424(c) or § 60.503a(a)(2) of this chapter shall keep records of the following information:

(i) Types, identification numbers, and locations of all equipment in gasoline service.

(ii) For each leak inspection conducted under § 63.424(c) or § 60.503a(a)(2) of this chapter, keep the following records:

(A) An indication if the leak inspection was conducted under § 63.424(c) or § 60.503a(a)(2) of this chapter.

(B) Leak determination method used for the leak inspection.

(iii) For leak inspections conducted with Method 21 of appendix A-7 to part 60 of this chapter, keep the following additional records:

(A) Date of inspection.

(B) Inspector name.

(C) Monitoring instrument identification.

(D) Identification of all equipment surveyed and the instrument reading for each piece of equipment.

(E) Date and time of instrument calibration and initials of operator performing the calibration.

(F) Calibration gas cylinder identification, certification date, and certified concentration.

(G) Instrument scale used.

(H) Results of the daily calibration drift assessment.

(iv) For leak inspections conducted with OGI, keep the records specified in section 12 of appendix K to part 60 of this chapter.

(v) For each leak that is detected during a leak inspection or by audio/visual/olfactory methods during normal duties, record the following information:

(A) The equipment type and identification number.

(B) The date the leak was detected, the name of the person who found the leak, nature of the leak ( i.e., vapor or liquid) and the method of detection ( i.e., audio/visual/olfactory, Method 21 of appendix A-7 to part 60 of this chapter, or OGI).

(C) The date of each attempt to repair the leak and the repair methods applied in each attempt to repair the leak.

(D) The date of successful repair of the leak, the method of monitoring used to confirm the repair, and if Method 21 of appendix A-7 to part 60 of this chapter is used to confirm the repair, the maximum instrument reading measured by Method 21 of appendix A-7 to part 60. If OGI is used to confirm the repair, keep video footage of the repair confirmation.

(E) For each repair delayed beyond 15 calendar days after discovery of the leak, record “Repair delayed”, the reason for the delay, and the expected date of successful repair. The owner or operator (or designate) whose decision it was that repair could not be carried out in the 15-calendar day timeframe must sign the record.

(F) For each leak that is not repairable, the maximum instrument reading measured by Method 21 of appendix A-7 to part 60 of this chapter at the time the leak is determined to be not repairable, a video captured by the OGI camera showing that emissions are still visible, or a signed record that the leak is still detectable via audio/visual/olfactory methods.

(g) Each owner or operator of a bulk gasoline terminal or pipeline breakout station subject to the provisions of this subpart shall keep the following records for each deviation of an emissions limitation (including operating limit), work practice standard, or operation and maintenance requirement in this subpart.

(1) Date, start time, and duration of each deviation.

(2) List of the affected sources or equipment for each deviation, an estimate of the quantity of each regulated pollutant emitted over any emission limit and a description of the method used to estimate the emissions.

(3) Actions taken to minimize emissions.

(h) Any records required to be maintained by this subpart that are submitted electronically via the U.S. Environmental Protection Agency (EPA) Compliance and Emissions Data Reporting Interface (CEDRI) may be maintained in electronic format. This ability to maintain electronic copies does not affect the requirement for facilities to make records, data, and reports available upon request to a delegated authority or the EPA as part of an on-site compliance evaluation.

(i) Records of each performance test or performance evaluation conducted and each notification and report submitted to the Administrator for at least 5 years. For each performance test, include an indication of whether liquid product loading is assumed to be loaded into gasoline cargo tanks or periods when liquid product is loaded but no gasoline cargo tanks are being loaded are excluded in the determination of the combustion zone temperature operating limit according to the provision in § 60.503a(c)(8)(ii) of this chapter. If complying with the alternative in § 63.427(f), for each performance test or performance evaluation conducted, include the pressure every 5 minutes while a gasoline cargo tank is being loaded and the highest instantaneous pressure that occurs during each loading.

(j) Prior to November 4, 2024, each owner or operator of an affected source under this subpart shall submit performance test reports to the Administrator according to the requirements in § 63.13. Beginning on November 4, 2024, within 60 days after the date of completing each performance test and each CEMS performance evaluation required by this subpart, you must submit the results of the performance test following the procedure specified in § 63.9(k). As required by § 63.7(g)(2)(iv), you must include the value for the combustion zone temperature operating parameter limit set based on your performance test in the performance test report. If the monitoring alternative in § 63.427(f) is used, indicate that this monitoring alternative is being used, identify each loading rack that loads gasoline cargo tanks at the bulk gasoline terminal subject to the provisions of this subpart, and report the highest instantaneous pressure monitored during the performance test or performance evaluation for each identified loading rack. Data collected using test methods supported by the EPA's Electronic Reporting Tool (ERT) and performance evaluations of CEMS measuring RATA pollutants that are supported by the EPA's ERT as listed on the EPA's ERT website ( https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert ) at the time of the test or performance evaluation must be submitted in a file format generated using the EPA's ERT. Alternatively, you may submit an electronic file consistent with the extensible markup language (XML) schema listed on the EPA's ERT website. Data collected using test methods that are not supported by the EPA's ERT and performance evaluations of CEMS measuring RATA pollutants that are not supported by the EPA's ERT as listed on the EPA's ERT website at the time of the test must be included as an attachment in the ERT or alternate electronic file.

(k) The owner or operator must submit all Notification of Compliance Status reports in PDF format to the EPA following the procedure specified in § 63.9(k), except any medium submitted through mail must be sent to the attention of the Gasoline Distribution Sector Lead.

(l) Prior to May 8, 2027, each owner or operator of a source subject to the requirements of this subpart shall submit reports as specified in paragraphs (l)(1) through (5) of this section, as applicable.

(1) Each owner or operator subject to the provisions of § 63.424 shall report to the Administrator a description of the types, identification numbers, and locations of all equipment in gasoline service. For facilities electing to implement an instrument program under § 63.424(b)(4), the report shall contain a full description of the program.

(i) In the case of an existing source or a new source that has an initial startup date before December 14, 1994, the report shall be submitted with the notification of compliance status required under § 63.9(h), unless an extension of compliance is granted under § 63.6(i). If an extension of compliance is granted, the report shall be submitted on a date scheduled by the Administrator.

(ii) In the case of new sources that did not have an initial startup date before December 14, 1994, the report shall be submitted with the application for approval of construction, as described in § 63.5(d).

(2) Each owner or operator of a bulk gasoline terminal or pipeline breakout station subject to the provisions of this subpart shall include in a semiannual report to the Administrator the following information, as applicable:

(i) Each loading of a gasoline cargo tank for which vapor tightness documentation had not been previously obtained by the facility;

(ii) Periodic reports as specified in § 60.115b of this chapter; and

(iii) The number of equipment leaks not repaired within 5 days after detection.

(3) Each owner or operator of a bulk gasoline terminal or pipeline breakout station subject to the provisions of this subpart shall submit an excess emissions report to the Administrator in accordance with § 63.10(e)(3), whether or not a CMS is installed at the facility. The following occurrences are excess emissions events under this subpart, and the following information shall be included in the excess emissions report, as applicable:

(i) Each exceedance or failure to maintain, as appropriate, the monitored operating parameter value determined under § 63.425(b)(3). The report shall include the monitoring data for the days on which exceedances or failures to maintain have occurred, and a description and timing of the steps taken to repair or perform maintenance on the vapor collection and processing systems or the CMS.

(ii) Each instance of a nonvapor-tight gasoline cargo tank loading at the facility in which the owner or operator failed to take steps to assure that such cargo tank would not be reloaded at the facility before vapor tightness documentation for that cargo tank was obtained.

(iii) Each reloading of a nonvapor-tight gasoline cargo tank at the facility before vapor tightness documentation for that cargo tank is obtained by the facility in accordance with § 63.422(c).

(iv) For each occurrence of an equipment leak for which no repair attempt was made within 5 days or for which repair was not completed within 15 days after detection:

(A) The date on which the leak was detected;

(B) The date of each attempt to repair the leak;

(C) The reasons for the delay of repair; and

(D) The date of successful repair.

(4) Each owner or operator of a facility meeting the criteria in § 63.420(c) shall perform the requirements of this paragraph (l)(4), all of which will be available for public inspection:

(i) Document and report to the Administrator not later than December 16, 1996, for existing facilities, within 30 days for existing facilities subject to § 63.420(c) after December 16, 1996, or at startup for new facilities the methods, procedures, and assumptions supporting the calculations for determining criteria in § 63.420(c);

(ii) Maintain records to document that the facility parameters established under § 63.420(c) have not been exceeded; and

(iii) Report annually to the Administrator that the facility parameters established under § 63.420(c) have not been exceeded.

(iv) At any time following the notification required under paragraph (l)(4)(i) of this section and approval by the Administrator of the facility parameters, and prior to any of the parameters being exceeded, the owner or operator may submit a report to request modification of any facility parameter to the Administrator for approval. Each such request shall document any expected HAP emission change resulting from the change in parameter.

(5) Each owner or operator of a facility meeting the criteria in § 63.420(d) shall perform the requirements of this paragraph (l)(5), all of which will be available for public inspection:

(i) Document and report to the Administrator not later than December 16, 1996, for existing facilities, within 30 days for existing facilities subject to § 63.420(d) after December 16, 1996, or at startup for new facilities the use of the emission screening equations in § 63.420(a)(1) or (b)(1) and the calculated value of E_T or E_P;

(ii) Maintain a record of the calculations in § 63.420 (a)(1) or (b)(1), including methods, procedures, and assumptions supporting the calculations for determining criteria in § 63.420(d); and

(iii) At any time following the notification required under paragraph (l)(5)(i) of this section, and prior to any of the parameters being exceeded, the owner or operator may notify the Administrator of modifications to the facility parameters. Each such notification shall document any expected HAP emission change resulting from the change in parameter.

(m) On or after May 8, 2027, you must submit to the Administrator semiannual reports with the applicable information in paragraphs (m)(1) through (8) of this section following the procedure specified in paragraph (n) of this section.

(1) Report the following general facility information:

(i) Facility name.

(ii) Facility physical address, including city, county, and State.

(iii) Latitude and longitude of facility's physical location. Coordinates must be in decimal degrees with at least five decimal places.

(iv) The following information for the contact person:

(A) Name.

(B) Mailing address.

(C) Telephone number.

(D) Email address.

(v) The type of facility (bulk gasoline terminal or pipeline breakout station).

(vi) Date of report and beginning and ending dates of the reporting period. You are no longer required to provide the date of report when the report is submitted via CEDRI.

(vii) Statement by a responsible official, with that official's name, title, and signature, certifying the truth, accuracy, and completeness of the content of the report. If your report is submitted via CEDRI, the certifier's electronic signature during the submission process replaces the requirement in this paragraph (m)(1)(vii).

(2) For each thermal oxidation system used to comply with the emission limit in § 60.502a(c)(1) of this chapter by monitoring the combustion zone temperature as specified in § 60.502a(c)(1)(ii), for each pressure CPMS used to comply with the requirements in § 60.502a(h), and for each vapor recovery system used to comply with the emission limitations in § 60.502a(c)(2), report the following information for the CMS:

(i) For all instances when the temperature CPMS measured 3-hour rolling averages below the established operating limit or when the vapor collection system pressure exceeded the maximum loading pressure specified in § 60.502a(h) of this chapter when liquid product was being loaded into gasoline cargo tanks or when the TOC CEMS measured 3-hour rolling average concentrations higher than the applicable emission limitation when the vapor recovery system was operating:

(A) The date and start time of the deviation.

(B) The duration of the deviation in hours.

(C) Each 3-hour rolling average combustion zone temperature, average pressure, or 3-hour rolling average TOC concentration during the deviation. For TOC concentration, indicate whether methane is excluded from the TOC concentration.

(D) A unique identifier for the CMS.

(E) The make, model number, and date of last calibration check of the CMS.

(F) The cause of the deviation and the corrective action taken.

(ii) For all instances that the temperature CPMS for measuring the combustion zone temperature or pressure CPMS was not operating or out of control when liquid product was loaded into gasoline cargo tanks, or the TOC CEMS was not operating or was out of control when the vapor recovery system was operating:

(A) The date and start time of the deviation.

(B) The duration of the deviation in hours.

(C) A unique identifier for the CMS.

(D) The make, model number, and date of last calibration check of the CMS.

(E) The cause of the deviation and the corrective action taken. For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) of this chapter is used, the corrective action taken shall include an indication of the use of the limited alternative for vapor recovery systems in § 60.504a(e).

(F) For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) of this chapter is used, report either an indication that there were no deviations from the operating limits when using the limited alternative or report the number of each of the following types of deviations that occurred during the use of the limited alternative for vapor recovery systems in § 60.504a(e).

( 1) The number of adsorption cycles when the quantity of liquid product loaded in gasoline cargo tanks exceeded the operating limit established in § 60.504a(e)(1) of this chapter. Enter 0 if no deviations of this type.

( 2) The number of desorption cycles when the vacuum pressure was below the average vacuum pressure as specified in § 60.504a(e)(2)(i) of this chapter. Enter 0 if no deviations of this type.

( 3) The number of desorption cycles when the quantity of purge gas used was below the average quantity of purge gas as specified in § 60.504a(e)(2)(ii) of this chapter. Enter 0 if no deviations of this type.

( 4) The number of desorption cycles when the duration of the vacuum/purge cycle was less than the average duration as specified in § 60.504a(e)(2)(iii) of this chapter. Enter 0 if no deviations of this type.

(3) For each flare used to comply with the emission limitations in § 60.502a(c)(3) of this chapter and for each thermal oxidation system using the flare monitoring alternative as provided in § 60.502a(c)(1)(iii), report:

(i) The date and start and end times for each of the following instances:

(A) Each 15-minute block during which there was at least one minute when gasoline vapors were routed to the flare and no pilot flame was present.

(B) Each period of 2 consecutive hours during which visible emissions exceeded a total of 5 minutes. Additionally, report the number of minutes for which visible emissions were observed during the observation or an estimate of the cumulative number of minutes in the 2-hour period for which emissions were visible based on best information available to the owner or operator.

(C) Each 15-minute period for which the applicable operating limits specified in § 63.670(d) through (f) were not met. You must identify the specific operating limit that was not met. Additionally, report the information in paragraphs (m)(3)(i)(C)( 1) through ( 3) of this section, as applicable.

( 1) If you use the loading rate operating limits as determined in § 60.502a(c)(3)(vii) of this chapter alone or in combination with the supplemental gas flow rate monitoring alternative in § 60.502a(c)(3)(viii) of this chapter, the required minimum ratio and the actual ratio of gasoline loaded to total product loaded for the rolling 15-minute period and, if applicable, the required minimum quantity and the actual quantity of gasoline loaded, in gallons, for the rolling 15-minute period.

( 2) If you use the supplemental gas flow rate monitoring alternative in § 60.502a(c)(3)(viii) of this chapter, the required minimum supplemental gas flow rate and the actual supplemental gas flow rate including units of flow rates for the 15-minute block.

( 3) If you use parameter monitoring systems other than those specified in paragraphs (m)(3)(i)(C)( 1) and ( 2) of this section, the value of the net heating value operating parameter(s) during the deviation determined following the methods in § 63.670(k) through (n) as applicable.

(ii) The start date, start time, and duration in minutes for each period when “vapors displaced from gasoline cargo tanks during product loading” were routed to the flare or thermal oxidation system and the applicable monitoring was not performed.

(iii) For each instance reported under paragraphs (m)(3)(i) and (ii) of this section that involves CMS, report the following information:

(A) A unique identifier for the CMS.

(B) The make, model number, and date of last calibration check of the CMS.

(C) The cause of the deviation or downtime and the corrective action taken.

(4) For any instance in which liquid product was loaded into a gasoline cargo tank for which vapor tightness documentation required under § 60.502a(e)(1) of this chapter was not provided or available in the terminal's records, report:

(i) Cargo tank owner and address.

(ii) Cargo tank identification number.

(iii) Date and time liquid product was loaded into a gasoline cargo tank without proper documentation.

(iv) Date proper documentation was received or statement that proper documentation was never received.

(5) For each instance when liquid product was loaded into gasoline cargo tanks not using submerged filling, as defined in § 63.421, not equipped with vapor collection equipment that is compatible with the terminal's vapor collection system, or not properly connected to the terminal's vapor collection system, report:

(i) Date and time of liquid product loading into gasoline cargo tank not using submerged filling, improperly equipped, or improperly connected.

(ii) The type of deviation ( e.g., not submerged filling, incompatible equipment, not properly connected).

(iii) Cargo tank identification number.

(6) Report the following information for each leak inspection required and each leak identified under § 63.424(c) and § 60.503a(a)(2) of this chapter.

(i) For each leak detected during a leak inspection required under § 63.424(c) and § 60.503a(a)(2) of this chapter, report:

(A) The date of inspection.

(B) The leak determination method (OGI or Method 21).

(C) The total number and type of equipment for which leaks were detected.

(D) The total number and type of equipment for which leaks were repaired within 15 calendar days.

(E) The total number and type of equipment for which no repair attempt was made within 5 calendar days of the leaks being identified.

(F) The total number and types of equipment that were placed on the delay of repair, as specified in § 60.502a(j)(8) of this chapter.

(ii) For leaks identified under § 63.424(c) by audio/visual/olfactory methods during normal duties report:

(A) The total number and type of equipment for which leaks were identified.

(B) The total number and type of equipment for which leaks were repaired within 15 calendar days.

(C) The total number and type of equipment for which no repair attempt was made within 5 calendar days of the leaks being identified.

(D) The total number and type of equipment placed on the delay of repair, as specified in § 60.502a(j)(8) of this chapter.

(iii) The total number of leaks on the delay of repair list at the start of the reporting period.

(iv) The total number of leaks on the delay of repair list at the end of the reporting period.

(v) For each leak that was on the delay of repair list at any time during the reporting period, report:

(A) Unique equipment identification number.

(B) Type of equipment.

(C) Leak determination method (OGI, Method 21, or audio/visual/olfactory).

(D) The reason(s) why the repair was not feasible within 15 calendar days.

(E) If applicable, the date repair was completed.

(7) For each gasoline storage vessel subject to requirements in § 63.423, report:

(i) The information specified in § 60.115b(a) or (b) of this chapter or deviations in measured parameter values from the plan specified in § 60.115b(c) of this chapter, depending upon the control equipment installed, or, if applicable, the information specified in § 63.1066(b).

(ii) If you are complying with § 63.423(b)(2), for each deviation in LEL monitoring, report:

(A) Date and start and end times of the LEL monitoring, and the storage vessel being monitored.

(B) Description of the monitoring event, e.g., monitoring conducted concurrent with visual inspection required under § 60.113b(a)(2) of this chapter or § 63.1063(d)(2); monitoring that occurred on a date other than the visual inspection required under § 60.113b(a)(2) or § 63.1063(d)(2); re-monitoring due to high winds; re-monitoring after repair attempt.

(C) Wind speed in miles per hour at the top of the storage vessel on the date of LEL monitoring.

(D) The highest 5-minute rolling average reading during the monitoring event.

(E) Whether the floating roof was repaired, replaced, or taken out of gasoline service. If the floating roof was repaired or replaced, also report the information in paragraphs (m)(7)(ii)(A) through (D) of this section for each re-monitoring conducted to confirm the repair.

(8) If there were no deviations from the emission limitations, operating parameters, or work practice standards, then provide a statement that there were no deviations from the emission limitations, operating parameters, or work practice standards during the reporting period. If there were no periods during which a continuous monitoring system (including a CEMS or CPMS) was inoperable or out-of-control, then provide a statement that there were no periods during which a continuous monitoring system was inoperable or out-of-control during the reporting period.

(n) Each owner or operator of an affected source under this subpart shall submit semiannual compliance reports with the information specified in paragraph (l) or (m) of this section to the Administrator according to the requirements in § 63.13. Beginning on May 8, 2027, or once the report template for this subpart has been available on the CEDRI website ( https://www.epa.gov/electronic-reporting-air-emissions/cedri ) for one year, whichever date is later, you must submit all subsequent semiannual compliance reports using the appropriate electronic report template on the CEDRI website for this subpart and following the procedure specified in § 63.9(k), except any medium submitted through mail must be sent to the attention of the Gasoline Distribution Sector Lead. The date report templates become available will be listed on the CEDRI website. Unless the Administrator or delegated State agency or other authority has approved a different schedule for submission of reports, the report must be submitted by the deadline specified in this subpart, regardless of the method in which the report is submitted.

(c) The authorities that cannot be delegated to State, local, or Tribal agencies are as specified in paragraphs (c)(1) through (5) of this section.

(5) Approval of an alternative to any electronic reporting to the EPA required by this subpart.

Table 1 to Subpart R of Part 63—General Provisions Applicability to This Subpart

Reference	Applies to this subpart	Comment
63.1(a)(1)	Yes.
63.1(a)(2)	Yes.
63.1(a)(3)	Yes.
63.1(a)(4)	Yes.
63.1(a)(5)	No	Section reserved.
63.1(a)(6)	Yes.
63.1(a)(7) through (9)	No	Sections reserved.
63.1(a)(10)	Yes.
63.1(a)(11)	Yes.
63.1(a)(12)	Yes.
63.1(b)(1)	No	This subpart specifies applicability in § 63.420.
63.1(b)(2)	Yes.
63.1(b)(3)	Yes	Except this subpart specifies additional reporting and recordkeeping for some large area sources in § 63.428. These additional requirements only apply prior to the date the applicability equations are no longer applicable.
63.1(c)(1)	Yes.
63.1(c)(2)	Yes	Some small sources are not subject to this subpart.
63.1(c)(3)	No	Section reserved.
63.1(c)(4)	No	Section reserved.
63.1(c)(5)	Yes.
63.1(c)(6)	Yes.
63.1(d)	No	Section reserved.
63.1(e)	Yes.
63.2	Yes	Additional definitions in § 63.421.
63.3(a)-(c)	Yes.
63.4(a)(1) and (2)	Yes.
63.4(a)(3) through (5)	No	Sections reserved.
63.4(b)	Yes.
63.4(c)	Yes.
63.5(a)(1)	Yes.
63.5(a)(2)	Yes.
63.5(b)(1)	Yes.
63.5(b)(2)	No	Section reserved.
63.5(b)(3)	Yes.
63.5(b)(4)	Yes.
63.5(b)(5)	No	Section reserved.
63.5(b)(6)	Yes.
63.5(c)	No	Section reserved.
63.5(d)(1)	Yes.
63.5(d)(2)	Yes.
63.5(d)(3)	Yes.
63.5(d)(4)	Yes.
63.5(e)	Yes.
63.5(f)(1)	Yes.
63.5(f)(2)	Yes.
63.6(a)	Yes.
63.6(b)(1)	Yes.
63.6(b)(2)	Yes.
63.6(b)(3)	Yes.
63.6(b)(4)	Yes.
63.6(b)(5)	Yes.
63.6(b)(6)	No	Section reserved.
63.6(b)(7)	Yes.
63.6(c)(1)	No	This subpart specifies the compliance date.
63.6(c)(2)	Yes.
63.6(c)(3) and (4)	No	Sections reserved.
63.6(c)(5)	Yes.
63.6(d)	No	Section reserved.
63.6(e)	No	See § 62.420(k) for general duty requirement.
63.6(f)(1)	No
63.6(f)(2)	Yes.
63.6(f)(3)	Yes.
63.6(g)	Yes.
63.6(h)	No	This subpart does not require COMS; this subpart specifies requirements for visible emissions observations for flares.
63.6(i)(1) through (14)	Yes.
63.6(i)(15)	No	Section reserved.
63.6(i)(16)	Yes.
63.6(j)	Yes.
63.7(a)(1)	Yes.
63.7(a)(2)	Yes.
63.7(a)(3)	Yes.
63.7(a)(4)	Yes.
63.7(b)	Yes.
63.7(c)	Yes.
63.7(d)	Yes.
63.7(e)(1)	No	This subpart specifies performance test conditions.
63.7(e)(2)	Yes.
63.7(e)(3)	Yes.
63.7(e)(4)	Yes.
63.7(f)	Yes.
63.7(g)	Yes	Except this subpart specifies how and when the performance test and performance evaluation results are reported.
63.7(h)	Yes.
63.8(a)(1)	Yes.
63.8(a)(2)	Yes.
63.8(a)(3)	No	Section reserved.
63.8(a)(4)	Yes.
63.8(b)(1)	Yes.
63.8(b)(2)	Yes.
63.8(b)(3)	Yes.
63.8(c)(1) introductory text	Yes.
63.8(c)(1)(i)	No
63.8(c)(1)(ii)	Yes.
63.8(c)(1)(iii)	No
63.8(c)(2)	Yes.
63.8(c)(3)	Yes.
63.8(c)(4)	Yes.
63.8(c)(5)	No	This subpart does not require COMS.
63.8(c)(6) through (8)	Yes.
63.8(d)(1) and (2)	Yes.
63.8(d)(3)	No	This subpart specifies CMS records requirements.
63.8(e)	Yes	Except this subpart specifies how and when the performance evaluation results are reported.
63.8(f)(1) through (5)	Yes.
63.8(f)(6)	Yes.
63.8(g)	Yes.
63.9(a)	Yes.
63.9(b)(1)	Yes.
63.9(b)(2)	Yes	Except this subpart allows additional time for existing sources to submit initial notification. Section 63.428(a) specifies submittal by 1 year after being subject to the rule or December 16, 1996, whichever is later.
63.9(b)(3)	No	Section reserved.
63.9(b)(4)	Yes.
63.9(b)(5)	Yes.
63.9(c)	Yes.
63.9(d)	Yes.
63.9(e)	Yes.
63.9(f)	No
63.9(g)	Yes.
63.9(h)(1) through (3)	Yes	Except this subpart specifies how to submit the Notification of Compliance Status.
63.9(h)(4)	No	Section reserved.
63.9(h)(5) and (6)	Yes.
63.9(i)	Yes.
63.9(j)	Yes.
63.9(k)	Yes.
63.10(a)	Yes.
63.10(b)(1)	Yes.
63.10(b)(2)(i), (ii), (iv), and (v)	No	This subpart specifies recordkeeping requirements for deviations.
63.10(b)(2)(iii) and (vi) through (xiv)	Yes.
63.10(b)(3)	Yes.
63.10(c)(1)	Yes.
63.10(c)(2) through (4)	No	Sections reserved.
63.10(c)(5) through (8)	Yes.
63.10(c)(9)	No.	Section reserved.
63.10(c)(10) through (14)	Yes.
63.10(c)(15)	No
63.10(d)(1)	Yes
63.10(d)(2)	No	This subpart specifies how and when the performance test results are reported.
63.10(d)(3)	No	This subpart specifies reporting requirements for visible emissions observations for flares.
63.10(d)(4)	Yes.
63.10(d)(5)	No
63.10(e)(1)	Yes.
63.10(e)(2) through (4)	No	This subpart specifies reporting requirements for CMS and continuous opacity monitoring systems.
63.10(f)	Yes.
63.11(a) and (b)	Yes	Except these provisions no longer apply upon compliance with the provisions in §§ 63.422(b)(2) and 63.425(d)(2) for flares to meet the requirements specified in §§ 60.502a(c)(3) and 60.504a(c) of this chapter.
63.11(c), (d), and (e)	Yes	Except these provisions do not apply to monitoring required under § 63.425(b)(1) or (c)(1) and these provisions no longer apply upon compliance with the provisions in § 63.424(c).
63.12	Yes.
63.13	Yes.
63.14	Yes.
63.15	Yes.
63.16	Yes.

(c) Gasoline storage tanks that are located at affected sources identified in paragraphs (a)(1) through (4) of this section, and that are used only for dispensing gasoline in a manner consistent with tanks located at a gasoline dispensing facility as defined in § 63.11132, are not subject to any of the requirements in this subpart. These tanks must comply with subpart CCCCCC of this part.

(f) If your affected source's throughput ever exceeds an applicable throughput threshold in the definition of “bulk gasoline terminal” or in item 1 in table 2 to this subpart, the affected source will remain subject to the requirements for sources above the threshold, even if the affected source throughput later falls below the applicable throughput threshold. If your bulk gasoline plant's annual average gasoline throughput ever reaches or exceeds 4,000 gallons per day, the bulk gasoline plant will remain subject to the vapor balancing requirements, even if the affected source annual average gasoline throughput later falls below 4,000 gallons per day.

(a) The emission sources to which this subpart applies are gasoline storage tanks, gasoline loading racks, vapor collection-equipped gasoline cargo tanks, and equipment components in vapor or liquid gasoline service that meet the criteria specified in tables 1 through 4 to this subpart.

(a) Except as specified in paragraphs (d) and (e) of this section, if you have a new or reconstructed affected source, you must comply with this subpart according to paragraphs (a)(1) and (2) of this section.

(1) If you start up your affected source before January 10, 2008, you must comply with the standards in this subpart no later than January 10, 2008.

(2) If you start up your affected source after January 10, 2008, you must comply with the standards in this subpart upon startup of your affected source.

(b) Except as specified in paragraphs (d) and (e) of this section, if you have an existing affected source, you must comply with the standards in this subpart no later than January 10, 2011.

(c) If you have an existing affected source that becomes subject to the control requirements in this subpart because of an increase in the daily throughput, as specified in § 63.11086(a) or in option 1 of table 2 to this subpart, you must comply with the standards in this subpart no later than 3 years after the affected source becomes subject to the control requirements in this subpart.

(d) All affected sources that commenced construction or reconstruction on or before June 10, 2022, must comply with the requirements in paragraphs (d)(1) through (5) of this section upon startup or on May 8, 2027, whichever is later. All affected sources that commenced construction or reconstruction after June 10, 2022, must comply with the requirements in paragraphs (d)(1) through (5) of this section upon startup, or on July 8, 2024, whichever is later.

(1) For bulk gasoline plants, the requirements specified in § 63.11086(a)(4) through (6).

(2) For storage vessels at bulk gasoline terminals, pipeline breakout stations, or pipeline pumping stations, the requirements specified in items 1(b), 2(c), and 2(f) in table 1 to this subpart and §§ 63.11087(g) and 63.11092(f)(1)(ii).

(3) For loading racks at bulk gasoline terminals, the requirements specified in items 1(c), 1(f), and 2(c) in table 2 to this subpart.

(4) For equipment leak inspections at bulk gasoline terminals, bulk gasoline plants, pipeline breakout stations, or pipeline pumping stations, the requirements in § 63.11089(c).

(5) For gasoline cargo tanks, the requirements specified in § 63.11092(g)(1)(ii).

(e) All affected sources that commenced construction or reconstruction on or before June 10, 2022, must comply with the requirements specified in items 2(d) and 2(e) in table 1 to this subpart upon startup or the next time the storage vessel is completely emptied and degassed, or by May 8, 2034, whichever occurs first. All affected sources that commenced construction or reconstruction after June 10, 2022, must comply with the requirements specified in items 2(d) and 2(e) in table 1 to this subpart upon startup, or on July 8, 2024, whichever is later.

Each owner or operator of an affected source under this subpart must comply with the requirements of paragraphs (a) through (c) of this section.

(a) You must, at all times, operate and maintain any affected source, including associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions. The general duty to minimize emissions does not require the owner or operator to make any further efforts to reduce emissions if levels required by the applicable standard have been achieved. Determination of whether such operation and maintenance procedures are being used will be based on information available to the Administrator, which may include, but is not limited to, monitoring results, review of operation and maintenance procedures, review of operation and maintenance records, and inspection of the source.

(b) You must not allow gasoline to be handled in a manner that would result in vapor releases to the atmosphere for extended periods of time. Measures to be taken include, but are not limited to, the following:

(1) Minimize gasoline spills;

(2) Clean up spills as expeditiously as practicable;

(3) Cover all open gasoline containers and all gasoline storage tank fill-pipes with a gasketed seal when not in use; and

(4) Minimize gasoline sent to open waste collection systems that collect and transport gasoline to reclamation and recycling devices, such as oil/water separators.

(c) You must keep applicable records and submit reports as specified in §§ 63.11094(g) and 63.11095(d) or § 63.11095(e).

Each owner or operator of an affected bulk gasoline plant, as defined in § 63.11100, must comply with the requirements of paragraphs (a) through (j) of this section.

(a) Except as specified in paragraph (b) of this section, you must only load gasoline into storage tanks and cargo tanks at your facility by utilizing submerged filling, as defined in § 63.11100, and as specified in paragraph (a)(1), (2), or (3) of this section. The applicable distances in paragraphs (a)(1) and (2) of this section shall be measured from the point in the opening of the submerged fill pipe that is the greatest distance from the bottom of the storage tank. Additionally, for bulk gasoline plants with an annual average gasoline throughput of 4,000 gallons per day or more (calculated by summing the current day's throughput, plus the throughput for the previous 364 days, and then dividing that sum by 365), you must only load gasoline utilizing vapor balancing as specified in paragraphs (a)(4) through (6) of this section.

(4) Beginning no later than the dates specified in § 63.11083, each bulk gasoline plant with an annual average gasoline throughput of 4,000 gallons per day or more shall be equipped with a vapor balance system between fixed roof gasoline storage tank(s) other than storage tank(s) vented through a closed vent system to a control device and incoming gasoline cargo tank(s) designed to capture and transfer vapors displaced during filling of fixed roof gasoline storage tank(s) other than storage tank(s) vented through a closed vent system to a control device. These lines shall be equipped with fittings that are vapor tight and that automatically and immediately close upon disconnection.

(5) Beginning no later than the dates specified in § 63.11083, each bulk gasoline plant with an annual average gasoline throughput of 4,000 gallons per day or more shall be equipped with a vapor balance system between fixed roof gasoline storage tank(s) other than storage tank(s) vented through a closed vent system to a control device and outgoing gasoline cargo tank(s) designed to capture and transfer vapors displaced during the loading of gasoline cargo tank(s). The vapor balance system shall be designed to prevent any vapors collected at one loading rack from passing to another loading rack.

(6) Beginning no later than the dates specified in § 63.11083, each owner or operator of a bulk gasoline plant subject to this subpart shall act to ensure that the following procedures are followed during all loading, unloading, and storage operations:

(i) The vapor balance system shall be connected between the cargo tank and storage tank during all gasoline transfer operations between a cargo tank and a fixed roof gasoline storage tank other than a storage tank vented through a closed vent system to a control device;

(ii) All storage tank openings, including inspection hatches and gauging and sampling devices shall be vapor tight when not in use;

(iii) No pressure relief device on a gasoline storage tank shall begin to open at a tank pressure less than 18 inches of water to minimize breathing losses;

(iv) The gasoline cargo tank compartment hatch covers shall not be opened during the gasoline transfer;

(v) All vapor balance systems shall be designed and operated at all times to prevent gauge pressure in the gasoline cargo tank from exceeding 18 inches of water and vacuum from exceeding 6 inches of water during product transfers;

(vi) No pressure vacuum relief valve in the bulk gasoline plant vapor balance system shall begin to open at a system pressure of less than 18 inches of water or at a vacuum of less than 6 inches of water; and

(vii) No gasoline shall be transferred into a cargo tank that does not have a current annual certification for vapor-tightness pursuant to the requirements in § 60.502a(e) of this chapter.

(b) Gasoline storage tanks with a capacity of less than 250 gallons are not required to comply with the control requirements in paragraph (a) of this section but must comply only with the requirements in § 63.11085(b).

(c) You must perform a leak inspection of all equipment in gasoline service and repair leaking equipment according to the requirements specified in § 63.11089.

(e) You must submit an Initial Notification that you are subject to this subpart by May 9, 2008, or no later than 120 days after the source becomes subject to this subpart, whichever is later unless you meet the requirements in paragraph (g) of this section. The Initial Notification must contain the information specified in paragraphs (e)(1) through (4) of this section. The notification must be submitted to the applicable U.S. Environmental Protection Agency (EPA) Regional Office and the delegated State authority, as specified in § 63.13.

(1) The name and address of the owner and the operator.

(2) The address ( i.e., physical location) of the bulk gasoline plant.

(3) A statement that the notification is being submitted in response to this subpart and identifying the requirements in paragraphs (a), (b), and (c) of this section that apply to you.

(4) A brief description of the bulk gasoline plant, including the number of storage tanks in gasoline service, the capacity of each storage tank in gasoline service, and the average monthly gasoline throughput at the affected source.

(i) You must keep applicable records and submit reports as specified in §§ 63.11094 and 63.11095.

(c) You must comply with the applicable testing and monitoring requirements specified in § 63.11092(f).

(g) No later than the dates specified in § 63.11083, if your gasoline storage tank is subject to, and complies with, the control requirements of § 60.112b(a)(2), (3), or (4) of this chapter, your storage tank will be deemed in compliance with this section. If your gasoline storage tank is subject to the control requirements of § 60.112b(a)(1) of this chapter, you must conduct lower explosive limit (LEL) monitoring as specified in § 63.11092(f)(1)(ii) to demonstrate compliance with this section. You must report this determination in the Notification of Compliance Status report under § 63.11093(b). The requirements in paragraph (f) of this section do not apply when demonstrating compliance with this paragraph (g).

(d) You must comply with the applicable testing and monitoring requirements specified in § 63.11092. As an alternative to the pressure monitoring requirements specified in § 60.504a(d) of this chapter, you may comply with the requirements specified in § 63.11092(h).

(a) Each owner or operator of a bulk gasoline terminal, bulk gasoline plant, pipeline breakout station, or pipeline pumping station subject to the provisions of this subpart shall implement a leak detection and repair program for all equipment in gasoline service according to the requirements in paragraph (b) or (c) of this section, as applicable based on the compliance dates specified in § 63.11083.

(b) Perform a monthly leak inspection of all equipment in gasoline service, as defined in § 63.11100. For this inspection, detection methods incorporating sight, sound, and smell are acceptable.

(1) A logbook shall be used and shall be signed by the owner or operator at the completion of each inspection. A section of the logbook shall contain a list, summary description, or diagram(s) showing the location of all equipment in gasoline service at the facility.

(2) Each detection of a liquid or vapor leak shall be recorded in the logbook. When a leak is detected, an initial attempt at repair shall be made as soon as practicable, but no later than 5 calendar days after the leak is detected. Repair or replacement of leaking equipment shall be completed within 15 calendar days after detection of each leak, except as provided in paragraph (b)(3) of this section.

(3) Delay of repair of leaking equipment will be allowed if the repair is not feasible within 15 days. The owner or operator shall provide in the semiannual report specified in § 63.11095(c), the reason(s) why the repair was not feasible and the date each repair was completed.

(c) No later than the dates specified in § 63.11083, comply with the requirements in § 60.502a(j) of this chapter except as provided in paragraphs (c)(1) through (4) of this section. The requirements in paragraph (b) of this section do not apply when demonstrating compliance with this paragraph (c).

(1) The frequency for optical gas imaging (OGI) monitoring shall be annually rather than quarterly as specified in § 60.502a(j)(1)(i) of this chapter.

(2) The frequency for Method 21 monitoring of pumps and valves shall be annually rather than quarterly as specified in § 60.502a(j)(1)(ii)(A) and (B) of this chapter.

(3) The frequency of monitoring of pressure relief devices shall be annually and within 5 calendar days after each pressure release rather than quarterly and within 5 calendar days after each pressure release as specified in § 60.502a(j)(4)(i) of this chapter.

(4) Any pressure relief device that is located at a bulk gasoline plant or pipeline pumping station that is monitored only by non-plant personnel may be monitored after a pressure release the next time the monitoring personnel are onsite, but in no case more than 30 calendar days after a pressure release.

(d) You must comply with the requirements of this subpart by the applicable dates specified in § 63.11083.

(e) You must submit the applicable notifications as required under § 63.11093.

(f) You must keep records and submit reports as specified in §§ 63.11094 and 63.11095.

(a) * * *

(1) Conduct a performance test on the vapor processing and collection systems according to either paragraph (a)(1)(i) or (ii) of this section, except as provided in paragraphs (a)(2) through (4) of this section.

(b) * * *

(1) * * *

(i) * * *

(B) * * *

( 1) Carbon adsorption devices shall be monitored as specified in paragraphs (b)(1)(i)(B)( 1)( i), ( ii), and ( iii) of this section.

( 2) * * *

( v) The owner or operator shall document the maximum vacuum level observed on each carbon bed from each daily inspection and the maximum VOC concentration observed from each carbon bed on each monthly inspection, as defined in the monitoring and inspection plan, and any activation of the automated alarm or shutdown system with a written entry into a logbook or other permanent form of record. Such record shall also include a description of the corrective action taken and whether such corrective actions were taken in a timely manner, as defined in the monitoring and inspection plan, as well as an estimate of the amount of gasoline loaded.

(iii) Where a thermal oxidation system is used, the owner or operator shall monitor the operation of the system as specified in paragraph (b)(1)(iii)(A) or (B) of this section.

(B) * * *

( 2) * * *

( v) The owner or operator shall document any activation of the automated alarm or shutdown system with a written entry into a logbook or other permanent form of record. Such record shall also include a description of the corrective action taken and whether such corrective actions were taken in a timely manner, as defined in the monitoring and inspection plan, as well as an estimate of the amount of gasoline loaded.

(d) Each owner or operator of a bulk gasoline terminal subject to the provisions of this subpart shall comply with the requirements in paragraphs (d)(1) through (3) of this section.

(1) Operate the vapor processing system in a manner not to exceed or not to go below, as appropriate, the operating parameter value for the parameters described in paragraph (b)(1) of this section.

(2) In cases where an alternative parameter pursuant to paragraph (b)(1)(iv) or (b)(5)(i) of this section is approved, each owner or operator shall operate the vapor processing system in a manner not to exceed or not to go below, as appropriate, the alternative operating parameter value.

(3) Operation of the vapor processing system in a manner exceeding or going below the operating parameter value, as appropriate, shall constitute a violation of the emission standard in § 63.11088(a).

(e) Each owner or operator of a bulk gasoline terminal subject to the emission standard in item 1(c) of table 2 to this subpart for loading racks must comply with the requirements in paragraphs (e)(1) through (4) of this section, as applicable.

(1) For each bulk gasoline terminal complying with the emission limitations in item 1 of table 3 to this subpart (thermal oxidation system), conduct a performance test no later than 180 days after becoming subject to the applicable emission limitation in table 3 and conduct subsequent performance tests at least once every 60 calendar months following the methods specified in § 60.503a(a) and (c) of this chapter. Prior to conducting this performance test, you must continue to meet the monitoring and operating limits that apply based on the previously conducted performance test. A previously conducted performance test may be used to satisfy this requirement if the conditions in paragraphs (e)(1)(i) through (v) of this section are met.

(i) The performance test was conducted on or after May 8, 2022.

(ii) No changes have been made to the process or control device since the time of the performance test.

(iii) The operating conditions, test methods, and test requirements ( e.g., length of test) used for the previous performance test conform to the requirements in paragraph (e)(1) of this section.

(iv) The temperature in the combustion zone was recorded during the performance test as specified in § 60.503a(c)(8)(i) of this chapter and can be used to establish the operating limit as specified in § 60.503a(c)(8)(ii) through (iv) of this chapter.

(v) The performance test demonstrates compliance with the emission limit specified in item 1(a) in table 3 to this subpart.

(2) For each bulk gasoline terminal complying with the emission limitations in item 1 of table 3 to this subpart (thermal oxidation system), comply with either the provisions in paragraph (e)(2)(i) or (ii) of this section.

(i) Install, operate, and maintain a CPMS to measure the combustion zone temperature according to § 60.504a(a) of this chapter and maintain the 3-hour rolling average combustion zone temperature when gasoline cargo tanks are being loaded at or above the operating limit set during the most recent performance test following the procedures specified in § 60.503a(c)(8) of this chapter. Valid operating data must exclude periods when there is no liquid product being loaded. If previous contents of the cargo tanks are known, you may also exclude periods when liquid product is loaded but no gasoline cargo tanks are being loaded provided that you excluded these periods in the determination of the combustion zone temperature operating limit according to the provisions in § 60.503a(c)(8)(ii) of this chapter.

(ii) Operate each thermal oxidation system in compliance with the requirements for a flare in § 60.502a(c)(3) of this chapter and the monitoring requirements in § 60.504a(c) of this chapter.

(3) For each bulk gasoline terminal complying with the emission limitations in item 2 of table 3 to this subpart (flare), install, operate, and maintain flare continuous parameter monitoring systems as specified in in § 60.504a(c) of this chapter.

(4) For each bulk gasoline terminal complying with the emission limitation in item 3 of table 3 to this subpart (carbon adsorption system, refrigerated condenser, or other vapor recovery system), install, operate, and maintain a continuous emission monitoring system (CEMS) to measure the total organic compounds (TOC) concentration according to § 60.504a(b) of this chapter and conduct performance evaluations as specified in § 60.503a(a) and (d) of this chapter. For periods of CEMS outages, you may use the limited alternative monitoring methods as specified in § 60.504a(e) of this chapter.

(f) Each owner or operator subject to the emission standard in § 63.11087 for gasoline storage tanks shall comply with the requirements in paragraphs (f)(1) through (3) of this section.

(1) If your gasoline storage tank is equipped with an internal floating roof,

(i) You must perform inspections of the floating roof system according to the requirements of § 60.113b(a) of this chapter if you are complying with option 2(b) in table 1 to this subpart, or according to the requirements of § 63.1063(c)(1) if you are complying with option 2(e) in table 1 to this subpart.

(ii) No later than the dates specified in § 63.11083, you must conduct LEL monitoring according to the provisions in § 63.425(j). A deviation of the LEL level is considered an inspection failure under § 60.113b(a)(2) of this chapter or § 63.1063(d)(2) and must be remedied as such. Any repairs must be confirmed effective through re-monitoring of the LEL and meeting the levels in options 2(c) and 2(f) in table 1 to this subpart within the timeframes specified in § 60.113b(a)(2) or § 63.1063(e), as applicable.

(2) If your gasoline storage tank is equipped with an external floating roof, you must perform inspections of the floating roof system according to the requirements of § 60.113b(b) of this chapter if you are complying with option 2(d) in table 1 to this subpart, or according to the requirements of § 63.1063(c)(2) if you are complying with option 2(e) in table 1 to this subpart.

(3) If your gasoline storage tank is equipped with a closed vent system and control device, you must conduct a performance test and determine a monitored operating parameter value in accordance with the requirements in paragraphs (a) through (d) of this section, except that the applicable level of control specified in paragraph (a)(2) of this section shall be a 95-percent reduction in inlet TOC levels rather than 80 mg/l of gasoline loaded.

(g) The annual certification test for gasoline cargo tanks shall consist of the test methods specified in paragraph (g)(1) or (2) of this section. Affected facilities that are subject to subpart XX to part 60 of this chapter may elect, after notification to the subpart XX delegated authority, to comply with paragraphs (g)(1) and (2) of this section.

(1) EPA Method 27 of appendix A-8 to part 60 of this chapter. Conduct the test using a time period (t) for the pressure and vacuum tests of 5 minutes. The initial pressure (P_i) for the pressure test shall be 460 millimeters (mm) of water (18 inches of water), gauge. The initial vacuum (V_i) for the vacuum test shall be 150 mm of water (6 inches of water), gauge.

(i) The maximum allowable pressure and vacuum changes (Δ p, Δ v) for all affected gasoline cargo tanks is 3 inches of water, or less, in 5 minutes.

(ii) No later than the dates specified in § 63.11083, the maximum allowable pressure and vacuum changes (Δ p, Δ v) for all affected gasoline cargo tanks is provided in column 3 of table 2 in § 63.425(e). The requirements in paragraph (g)(1)(i) of this section do not apply when demonstrating compliance with this paragraph (g)(1)(ii).

(2) Railcar bubble leak test procedures. As an alternative to the annual certification test required under paragraph (g)(1) of this section for certification leakage testing of gasoline cargo tanks, the owner or operator may comply with paragraphs (g)(2)(i) and (ii) of this section for railcar cargo tanks, provided the railcar cargo tank meets the requirement in paragraph (g)(2)(iii) of this section.

(i) Comply with the requirements of 49 CFR 173.31(d), 179.7, 180.509, and 180.511 for the periodic testing of railcar cargo tanks.

(ii) The leakage pressure test procedure required under 49 CFR 180.509(j) and used to show no indication of leakage under 49 CFR 180.511(f) shall be a bubble leak test procedure meeting the requirements in 49 CFR 179.7, 180.505, and 180.509. Use of ASTM E515-95 (Reapproved 2000) or BS EN 1593:1999 (incorporated by reference, see § 63.14) complies with those requirements.

(iii) The alternative requirements in this paragraph (g)(2) may not be used for any railcar cargo tank that collects gasoline vapors from a vapor balance system and the system complies with a Federal, State, local, or Tribal rule or permit. A vapor balance system is a piping and collection system designed to collect gasoline vapors displaced from a storage vessel, barge, or other container being loaded, and routes the displaced gasoline vapors into the railcar cargo tank from which liquid gasoline is being unloaded.

(h) As an alternative to the pressure monitoring requirements in § 60.504a(d) of this chapter, you may comply with the pressure monitoring requirements in § 60.503(d) of this chapter during any performance test or performance evaluation conducted under § 63.11092(e) to demonstrate compliance with the provisions in § 60.502a(h) of this chapter.

(i) Performance tests conducted for this subpart shall be conducted under such conditions as the Administrator specifies to the owner or operator, based on representative performance ( i.e., performance based on normal operating conditions) of the affected source. Performance tests shall be conducted under representative conditions when liquid product is being loaded into gasoline cargo tanks and shall include periods between gasoline cargo tank loading (when one cargo tank is disconnected and another cargo tank is moved into position for loading) provided that liquid product loading into gasoline cargo tanks is conducted for at least a portion of each 5 minute block of the performance test. You may not conduct performance tests during periods of malfunction. You must record the process information that is necessary to document operating conditions during the test and include in such record an explanation to support that such conditions represent normal operation. Upon request, the owner or operator shall make available to the Administrator such records as may be necessary to determine the conditions of performance tests.

(c) Each owner or operator of an affected bulk gasoline terminal under this subpart must submit a Notification of Performance Test or Performance Evaluation, as specified in subpart A to this part, prior to initiating testing required by this subpart.

(e) The owner or operator must submit all Notification of Compliance Status reports in PDF format to the EPA following the procedure specified in § 63.9(k), except any medium submitted through mail must be sent to the attention of the Gasoline Distribution Sector Lead.

(a) Each owner or operator of a bulk gasoline terminal or pipeline breakout station whose storage vessels are subject to the provisions of this subpart shall keep records as specified in paragraphs (a)(1) and (2) of this section.

(1) If you are complying with options 2(a), 2(b), or 2(d) in table 1 to this subpart, keep records as specified in § 60.115b of this chapter except records shall be kept for at least 5 years. If you are complying with the requirements of option 2(e) in table 1 to this subpart, you shall keep records as specified in § 63.1065.

(2) If you are complying with options 2(c) or 2(f) in table 1 to this subpart, keep records of each LEL monitoring event as specified in paragraphs (a)(2)(i) through (ix) of this section for at least 5 years.

(i) Date and time of the LEL monitoring, and the storage vessel being monitored.

(ii) A description of the monitoring event ( e.g., monitoring conducted concurrent with visual inspection required under § 60.113b(a)(2) of this chapter or § 63.1063(d)(2); monitoring that occurred on a date other than the visual inspection required under § 60.113b(a)(2) or § 63.1063(d)(2); re-monitoring due to high winds; re-monitoring after repair attempt).

(iii) Wind speed at the top of the storage vessel on the date of LEL monitoring.

(iv) The LEL meter manufacturer and model number used, as well as an indication of whether tubing was used during the LEL monitoring, and if so, the type and length of tubing used.

(v) Calibration checks conducted before and after making the measurements, including both the span check and instrumental offset. This includes the hydrocarbon used as the calibration gas, the Certificate of Analysis for the calibration gas(es), the results of the calibration check, and any corrective action for calibration checks that do not meet the required response.

(vi) Location of the measurements and the location of the floating roof.

(vii) Each measurement (taken at least once every 15 seconds). The records should indicate whether the recorded values were automatically corrected using the meter's programming. If the values were not automatically corrected, record both the raw (as the calibration gas) and corrected measurements, as well as the correction factor used.

(viii) Each 5-minute rolling average reading.

(ix) If the vapor concentration of the storage vessel was above 25 percent of the LEL on a 5-minue rolling average basis, a description of whether the floating roof was repaired, replaced, or taken out of gasoline service.

(b) Each owner or operator of a bulk gasoline terminal subject to the provisions in items 1(e), 1(f), or 2(c) in table 2 to this subpart or bulk gasoline plant subject to the requirements in § 63.11086(a)(6) shall keep records in either a hardcopy or electronic form of the test results for each gasoline cargo tank loading at the facility as specified in paragraphs (b)(1) through (3) of this section for at least 5 years.

(1) Annual certification testing performed under § 63.11092(g)(1) and periodic railcar bubble leak testing performed under § 63.11092(g)(2).

(2) The documentation file shall be kept up to date for each gasoline cargo tank loading at the facility. The documentation for each test shall include, as a minimum, the following information:

(i) Name of test: Annual Certification Test—Method 27 or Periodic Railcar Bubble Leak Test Procedure.

(ii) Cargo tank owner's name and address.

(iii) Cargo tank identification number.

(iv) Test location and date.

(v) Tester name and signature.

(vi) Witnessing inspector, if any: Name, signature, and affiliation.

(vii) Vapor tightness repair: Nature of repair work and when performed in relation to vapor tightness testing.

(viii) Test results: Tank or compartment capacity; test pressure; pressure or vacuum change, mm of water; time period of test; number of leaks found with instrument; and leak definition.

(3) If you are complying with the alternative requirements in § 63.11088(b), you must keep records documenting that you have verified the vapor tightness testing according to the requirements of the Administrator.

(c) Each owner or operator subject to the equipment leak provisions of § 63.11089 shall prepare and maintain a record describing the types, identification numbers, and locations of all equipment in gasoline service. For facilities electing to implement an instrument program under § 63.11089(b), the record shall contain a full description of the program.

(d) Each owner or operator of an affected source subject to equipment leak inspections under § 63.11089(b) shall record in the logbook for each leak that is detected the information specified in paragraphs (d)(1) through (7) of this section.

(1) The equipment type and identification number.

(2) The nature of the leak ( i.e., vapor or liquid) and the method of detection ( i.e., sight, sound, or smell).

(3) The date the leak was detected and the date of each attempt to repair the leak.

(4) Repair methods applied in each attempt to repair the leak.

(5) “Repair delayed” and the reason for the delay if the leak is not repaired within 15 calendar days after discovery of the leak.

(6) The expected date of successful repair of the leak if the leak is not repaired within 15 days.

(7) The date of successful repair of the leak.

(e) Each owner or operator of an affected source subject to § 63.11089(c) or § 60.503a(a)(2) of this chapter shall maintain records of each leak inspection and leak identified under § 63.11089(c) or § 60.503a(a)(2) as specified in paragraphs (e)(1) through (5) of this section for at least 5 years.

(1) An indication if the leak inspection was conducted under § 63.11089(c) or § 60.503a(a)(2) of this chapter.

(2) Leak determination method used for the leak inspection.

(3) For leak inspections conducted with Method 21 of appendix A-7 to part 60 of this chapter, keep the following additional records:

(i) Date of inspection.

(ii) Inspector name.

(iii) Monitoring instrument identification.

(iv) Identification of all equipment surveyed and the instrument reading for each piece of equipment.

(v) Date and time of instrument calibration and initials of operator performing the calibration.

(vi) Calibration gas cylinder identification, certification date, and certified concentration.

(vii) Instrument scale used.

(viii) Results of the daily calibration drift assessment.

(4) For leak inspections conducted with OGI, keep the records specified in section 12 of appendix K to part 60 of this chapter.

(5) For each leak detected during a leak inspection or by audio/visual/olfactory methods during normal duties, record the following information:

(i) The equipment type and identification number.

(ii) The date the leak was detected, the name of the person who found the leak, the nature of the leak ( i.e., vapor or liquid), and the method of detection ( i.e., audio/visual/olfactory, Method 21, or OGI).

(iii) The date of each attempt to repair the leak and the repair methods applied in each attempt to repair the leak.

(iv) The date of successful repair of the leak, the method of monitoring used to confirm the repair, and if Method 21 of appendix A-7 to part 60 of this chapter is used to confirm the repair, the maximum instrument reading measured by Method 21 of appendix A-7. If OGI is used to confirm the repair, keep video footage of the repair confirmation.

(v) For each repair delayed beyond 15 calendar days after discovery of the leak, record “Repair delayed”, the reason for the delay, and the expected date of successful repair. The owner or operator (or designate) whose decision it was that repair could not be carried out in the 15- calendar day timeframe must sign the record.

(vi) For each leak that is not repairable, the maximum instrument reading measured by Method 21 of appendix A-7 to part 60 of this chapter at the time the leak is determined to be not repairable, a video captured by the OGI camera showing that emissions are still visible, or a signed record that the leak is still detectable via audio/visual/olfactory methods.

(f) Each owner or operator of a bulk gasoline terminal subject to the loading rack provisions of item 1(c) of table 2 to this subpart or storage vessel provisions in § 63.11092(f) shall:

(1) Keep an up-to-date, readily accessible record of the continuous monitoring data required under § 63.11092(b) or (f). This record shall indicate the time intervals during which loadings of gasoline cargo tanks have occurred or, alternatively, shall record the operating parameter data only during such loadings. The date and time of day shall also be indicated at reasonable intervals on this record.

(2) Record and report simultaneously with the Notification of Compliance Status required under § 63.11093(b):

(i) All data and calculations, engineering assessments, and manufacturer's recommendations used in determining the operating parameter value under § 63.11092(b) or (f); and

(ii) The following information when using a flare under provisions of § 63.11(b) to comply with § 63.11087(a):

(A) Flare design ( i.e., steam-assisted, air-assisted, or non-assisted); and

(B) All visible emissions (VE) readings, heat content determinations, flow rate measurements, and exit velocity determinations made during the compliance determination required under § 63.11092(e)(3).

(3) Keep an up-to-date, readily accessible copy of the monitoring and inspection plan required under § 63.11092(b)(1)(i)(B)( 2) or (b)(1)(iii)(B)( 2).

(4) Keep an up-to-date, readily accessible record as specified in § 63.11092(b)(1)(i)(B)( 2)( v) or (b)(1)(iii)(B)( 2)( v).

(5) If an owner or operator requests approval to use a vapor processing system or monitor an operating parameter other than those specified in § 63.11092(b), the owner or operator shall submit a description of planned reporting and recordkeeping procedures.

(g) Each owner or operator of a bulk gasoline terminal subject to the loading rack provisions of item 1(c) of table 2 to this subpart shall keep records specified in paragraphs (g)(1) through (3) of this section, as applicable, for at least 5 years unless otherwise specified.

(1) For each thermal oxidation system used to comply with the provisions in § 63.11092(e)(2)(i) by monitoring the combustion zone temperature, for each pressure CPMS used to comply with the requirements in § 60.502a(h) of this chapter, and for each vapor recovery system used to comply with the provisions in item 3 of table 3 to this subpart, maintain records, as applicable, of:

(i) The applicable operating or emission limit for the CMS. For combustion zone temperature operating limits, include the applicable date range the limit applies based on when the performance test was conducted.

(ii) Each 3-hour rolling average combustion zone temperature measured by the temperature CPMS, each 5-minute average reading from the pressure CPMS, and each 3-hour rolling average TOC concentration (as propane) measured by the TOC CEMS.

(iii) For each deviation of the 3-hour rolling average combustion zone temperature operating limit, maximum loading pressure specified in § 60.502a(h) of this chapter, or 3-hour rolling average TOC concentration (as propane), the start date and time, duration, cause, and the corrective action taken.

(iv) For each period when there was a CMS outage or the CMS was out of control, the start date and time, duration, cause, and the corrective action taken. For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) of this chapter is used, the corrective action taken shall include an indication of the use of the limited alternative for vapor recovery systems in § 60.504a(e).

(v) Each inspection or calibration of the CMS including a unique identifier, make, and model number of the CMS, and date of calibration check. For TOC CEMS, include the type of CEMS used ( i.e., flame ionization detector, nondispersive infrared analyzer) and an indication of whether methane is excluded from the TOC concentration reported in paragraph (g)(1)(ii) of this section.

(vi) TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) of this chapter is used, also keep records of:

(A) The quantity of liquid product loaded in gasoline cargo tanks for the past 10 adsorption cycles prior to the CEMS outage.

(B) The vacuum pressure, purge gas quantities, and duration of the vacuum/purge cycles used for the past 10 desorption cycles prior to the CEMS outage.

(C) The quantity of liquid product loaded in gasoline cargo tanks for each adsorption cycle while using the alternative.

(D) The vacuum pressure, purge gas quantities, and duration of the vacuum/purge cycles for each desorption cycle while using the alternative.

(2) For each thermal oxidation system used to comply with the provision in § 63.11092(e)(2)(ii) and for each flare used to comply with the provision in item 2 of table 3 to this subpart, maintain records of:

(i) The output of the monitoring device used to detect the presence of a pilot flame as required in § 63.670(b) for a minimum of 2 years. Retain records of each 15-minute block during which there was at least one minute that no pilot flame is present when gasoline vapors were routed to the flare for a minimum of 5 years. The record must identify the start and end time and date of each 15-minute block.

(ii) Visible emissions observations as specified in paragraphs (g)(2)(ii)(A) and (B) of this section, as applicable, for a minimum of 3 years.

(A) If visible emissions observations are performed using Method 22 of appendix A-7 to part 60 of this chapter, the record must identify the date, the start and end time of the visible emissions observation, and the number of minutes for which visible emissions were observed during the observation. If the owner or operator performs visible emissions observations more than one time during a day, include separate records for each visible emissions observation performed.

(B) For each 2-hour period for which visible emissions are observed for more than 5 minutes in 2 consecutive hours but visible emissions observations according to Method 22 of appendix A-7 to part 60 of this chapter were not conducted for the full 2-hour period, the record must include the date, the start and end time of the visible emissions observation, and an estimate of the cumulative number of minutes in the 2-hour period for which emissions were visible based on best information available to the owner or operator.

(iii) Each 15-minute block period during which operating values are outside of the applicable operating limits specified in § 63.670(d) through (f) when liquid product is being loaded into gasoline cargo tanks for at least 15-minutes identifying the specific operating limit that was not met.

(iv) The 15-minute block average cumulative flows for the thermal oxidation system vent gas or flare vent gas and, if applicable, total steam, perimeter assist air, and premix assist air specified to be monitored under § 63.670(i), along with the date and start and end time for the 15-minute block. If multiple monitoring locations are used to determine cumulative vent gas flow, total steam, perimeter assist air, and premix assist air, retain records of the 15-minute block average flows for each monitoring location for a minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in subsequent calculations for a minimum of 5 years. If pressure and temperature monitoring is used, retain records of the 15-minute block average temperature, pressure and molecular weight of the thermal oxidation system vent gas, flare vent gas, or assist gas stream for each measurement location used to determine the 15-minute block average cumulative flows for a minimum of 2 years, and retain the 15-minute block average cumulative flows that are used in subsequent calculations for a minimum of 5 years. If you use the supplemental gas flow rate monitoring alternative in § 60.502a(c)(3)(viii) of this chapter, the required supplemental gas flow rate (winter and summer, if applicable) and the actual monitored supplemental gas flow rate for the 15-minute block. Retain the supplemental gas flow rate records for a minimum of 5 years.

(v) The thermal oxidation system vent gas or flare vent gas compositions specified to be monitored under § 63.670(j). Retain records of individual component concentrations from each compositional analyses for a minimum of 2 years. If NHV_vg analyzer is used, retain records of the 15-minute block average values for a minimum of 5 years. If you demonstrate your gas streams have consistent composition using the provisions in § 63.670(j)(6) as specified in § 60.502a(c)(3)(vii) of this chapter, retain records of the required minimum ratio of gasoline loaded to total liquid product loaded and the actual ratio on a 15-minute block basis. If applicable, you must retain records of the required minimum gasoline loading rate as specified in § 60.502a(c)(3)(vii) and the actual gasoline loading rate on a 15-minute block basis for a minimum of 5 years.

(vi) Each 15-minute block average operating parameter calculated following the methods specified in § 63.670(k) through (n), as applicable.

(vii) All periods during which the owner or operator does not perform monitoring according to the procedures in § 63.670(g), (i), and (j) or in § 60.502a(c)(3)(vii) and (viii) of this chapter as applicable. Note the start date, start time, and duration in minutes for each period.

(viii) An indication of whether “vapors displaced from gasoline cargo tanks during product loading” excludes periods when liquid product is loaded but no gasoline cargo tanks are being loaded or if liquid product loading is assumed to be loaded into gasoline cargo tanks according to the provisions in § 60.502a(c)(3)(i) of this chapter, records of all time periods when “vapors displaced from gasoline cargo tanks during product loading”, and records of time periods when there were no “vapors displaced from gasoline cargo tanks during product loading”.

(ix) If you comply with the flare tip velocity operating limit using the one-time flare tip velocity operating limit compliance assessment as provided in § 60.502a(c)(3)(ix) of this chapter, maintain records of the applicable one-time flare tip velocity operating limit compliance assessment for as long as you use this compliance method.

(x) For each parameter monitored using a CMS, retain the records specified in paragraphs (g)(2)(x)(A) through (C) of this section, as applicable:

(A) For each deviation, record the start date and time, duration, cause, and corrective action taken.

(B) For each period when there is a CMS outage or the CMS is out of control, record the start date and time, duration, cause, and corrective action taken.

(C) Each inspection or calibration of the CMS including a unique identifier, make, and model number of the CMS, and date of calibration check.

(3) Records of all 5-minute time periods during which liquid product is loaded into gasoline cargo tanks or assumed to be loaded into gasoline cargo tanks and records of all 5-minute time periods when there was no liquid product loaded into gasoline cargo tanks.

(h) Each owner or operator of a bulk gasoline terminal subject to the provisions in items 1(e), 1(f), or 2(c) in table 2 to this subpart or bulk gasoline plant subject to the requirements in § 63.11086(a)(6) shall maintain records of each instance in which liquid product was loaded into a gasoline cargo tank for which vapor tightness documentation required under § 60.502(e)(1) or § 60.502a(e)(1) of this chapter, as applicable, was not provided or available in the terminal's or plant's records for at least 5 years. These records shall include, at a minimum:

(1) Cargo tank owner and address.

(2) Cargo tank identification number.

(3) Date and time liquid product was loaded into a gasoline cargo tank without proper documentation.

(4) Date proper documentation was received or statement that proper documentation was never received.

(i) Each owner or operator of a bulk gasoline terminal or bulk gasoline plant subject to the provisions of this subpart shall maintain records for at least 5 years of each instance when liquid product was loaded into gasoline cargo tanks not using submerged filling, or, if applicable, not equipped with vapor collection or balancing equipment that is compatible with the terminal's vapor collection system or plant's vapor balancing system. These records shall include, at a minimum:

(1) Date and time of liquid product loading into gasoline cargo tank not using submerged filling, improperly equipped, or improperly connected.

(2) Type of deviation ( e.g., not submerged filling, incompatible equipment, not properly connected).

(3) Cargo tank identification number.

(j) Each owner or operator of a bulk gasoline plant subject to the requirements in § 63.11086(a)(6) shall maintain records for at least 5 years of instances when gasoline was loaded between gasoline cargo tanks and storage tanks and the plant's vapor balancing system was not properly connected between the gasoline cargo tank and storage tank. These records shall include, at a minimum:

(1) Date and time of gasoline loading between a gasoline cargo tank and a storage tank that was not properly connected.

(2) Cargo tank identification number and storage tank identification number.

(k) Each owner or operator of an affected source under this subpart shall keep the following records for each deviation of an emissions limitation (including operating limit), work practice standard, or operation and maintenance requirement in this subpart.

(1) Date, start time, and duration of each deviation.

(2) List of the affected sources or equipment for each deviation, an estimate of the quantity of each regulated pollutant emitted over any emission limit and a description of the method used to estimate the emissions.

(3) Actions taken to minimize emissions in accordance with § 63.11085(a).

(l) Each owner or operator of a bulk gasoline terminal or bulk gasoline plant subject to the provisions of this subpart shall maintain records of the average gasoline throughput (in gallons per day) for at least 5 years.

(m) Keep written procedures required under § 63.8(d)(2) on record for the life of the affected source or until the affected source is no longer subject to the provisions of this part, to be made available for inspection, upon request, by the Administrator. If the performance evaluation plan is revised, you shall keep previous ( i.e., superseded) versions of the performance evaluation plan on record to be made available for inspection, upon request, by the Administrator, for a period of 5 years after each revision to the plan. The program of corrective action shall be included in the plan as required under § 63.8(d)(2).

(n) Keep records of each performance test or performance evaluation conducted and each notification and report submitted to the Administrator for at least 5 years. For each performance test, include an indication of whether liquid product loading is assumed to be loaded into a gasoline cargo tank or periods when liquid product is loaded but no gasoline cargo tanks are being loaded are excluded in the determination of the combustion zone temperature operating limit according to the provision in § 60.503a(c)(8)(ii) of this chapter. If complying with the alternative in § 63.11092(h), for each performance test or performance evaluation conducted, include the pressure every 5 minutes while a gasoline cargo tank is being loaded and the highest instantaneous pressure that occurs during each loading.

(o) Any records required to be maintained by this subpart that are submitted electronically via the EPA's Compliance and Emissions Reporting Interface (CEDRI) may be maintained in electronic format. This ability to maintain electronic copies does not affect the requirement for facilities to make records, data, and reports available upon request to a delegated authority or the EPA as part of an on-site compliance evaluation.

(a) Reporting requirements for performance tests. Prior to November 4, 2024, each owner or operator of an affected source under this subpart shall submit performance test reports to the Administrator according to the requirements in § 63.13. Beginning on November 4, 2024, within 60 days after the date of completing each performance test required by this subpart, you must submit the results of the performance test following the procedures specified in § 63.9(k). As required by § 63.7(g)(2)(iv), you must include the value for the combustion zone temperature operating parameter limit set based on your performance test in the performance test report. If the monitoring alternative in § 63.11092(h) is used, indicate that this monitoring alternative is being used, identify each loading rack that loads gasoline cargo tanks at the bulk gasoline terminal subject to the provisions of this subpart, and report the highest instantaneous pressure monitored during the performance test or performance evaluation for each identified loading rack. Data collected using test methods supported by the EPA's Electronic Reporting Tool (ERT) as listed on the EPA's ERT website ( https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert ) at the time of the test must be submitted in a file format generated using the EPA's ERT. Alternatively, you may submit an electronic file consistent with the extensible markup language (XML) schema listed on the EPA's ERT website. Data collected using test methods that are not supported by the EPA's ERT as listed on the EPA's ERT website at the time of the test must be included as an attachment in the ERT or an alternate electronic file.

(b) Reporting requirements for performance evaluations. Prior to November 4, 2024, each owner or operator of an affected source under this subpart shall submit performance evaluations to the Administrator according to the requirements in § 63.13. Beginning on November 4, 2024, within 60 days after the date of completing each CEMS performance evaluation, you must submit the results of the performance evaluation following the procedures specified in § 63.9(k). If the monitoring alternative in § 63.11092(h) is used, indicate that this monitoring alternative is being used, identify each loading rack that loads gasoline cargo tanks at the bulk gasoline terminal subject to the provisions of this subpart, and report the highest instantaneous pressure monitored during the performance test or performance evaluation for each identified loading rack. The results of performance evaluations of CEMS measuring relative accuracy test audit (RATA) pollutants that are supported by the EPA's ERT as listed on the EPA's ERT website at the time of the evaluation must be submitted in a file format generated using the EPA's ERT. Alternatively, you may submit an electronic file consistent with the XML schema listed on the EPA's ERT website. The results of performance evaluations of CEMS measuring RATA pollutants that are not supported by the EPA's ERT as listed on the EPA's ERT website at the time of the evaluation must be included as an attachment in the ERT or an alternate electronic file.

(c) Reporting requirements prior to May 8, 2027. Prior to May 8, 2027, each owner or operator of a source subject to the requirements of this subpart shall submit reports as specified in paragraphs (c)(1) through (3) of this section, as applicable.

(1) Each owner or operator of a bulk terminal or a pipeline breakout station subject to the control requirements of this subpart shall include in a semiannual compliance report to the Administrator the following information, as applicable:

(i) For storage vessels, if you are complying with options 2(a), 2(b), or 2(d) in table 1 to this subpart, the information specified in § 60.115b(a), (b), or (c) of this chapter, depending upon the control equipment installed, or, if you are complying with option 2(e) in table 1 to this subpart, the information specified in § 63.1066.

(ii) For loading racks, each loading of a gasoline cargo tank for which vapor tightness documentation had not been previously obtained by the facility.

(iii) For equipment leak inspections, the number of equipment leaks not repaired within 15 days after detection.

(iv) For storage vessels complying with § 63.11087(b) after January 10, 2011, the storage vessel's Notice of Compliance Status information can be included in the next semi-annual compliance report in lieu of filing a separate Notification of Compliance Status report under § 63.11093.

(2) Each owner or operator of an affected source subject to the control requirements of this subpart shall submit an excess emissions report to the Administrator at the time the semiannual compliance report is submitted. Excess emissions events under this subpart, and the information to be included in the excess emissions report, are specified in paragraphs (c)(2)(i) through (v) of this section.

(i) Each instance of a non-vapor-tight gasoline cargo tank loading at the facility in which the owner or operator failed to take steps to assure that such cargo tank would not be reloaded at the facility before vapor tightness documentation for that cargo tank was obtained.

(ii) Each reloading of a non-vapor-tight gasoline cargo tank at the facility before vapor tightness documentation for that cargo tank is obtained by the facility in accordance with § 63.11094(b).

(iii) Each exceedance or failure to maintain, as appropriate, the monitored operating parameter value determined under § 63.11092(b). The report shall include the monitoring data for the days on which exceedances or failures to maintain have occurred, and a description and timing of the steps taken to repair or perform maintenance on the vapor collection and processing systems or the CMS.

(iv) [Reserved]

(v) For each occurrence of an equipment leak for which no repair attempt was made within 5 days or for which repair was not completed within 15 days after detection:

(A) The date on which the leak was detected;

(B) The date of each attempt to repair the leak;

(C) The reasons for the delay of repair; and

(D) The date of successful repair.

(3) Each owner or operator of a bulk gasoline plant or a pipeline pumping station shall submit a semiannual excess emissions report, including the information specified in paragraphs (c)(1)(iii) and (c)(2)(v) of this section, only for a 6-month period during which an excess emission event has occurred. If no excess emission events have occurred during the previous 6-month period, no report is required.

(d) Reporting requirements for semiannual reports on or after May 8, 2027. On or after May 8, 2027, you must submit to the Administrator semiannual reports with the applicable information in paragraphs (d)(1) through (9) of this section following the procedure specified in paragraph (e) of this section.

(1) Report the following general facility information:

(i) Facility name.

(ii) Facility physical address, including city, county, and State.

(iii) Latitude and longitude of facility's physical location. Coordinates must be in decimal degrees with at least five decimal places.

(iv) The following information for the contact person:

(A) Name.

(B) Mailing address.

(C) Telephone number.

(D) Email address.

(v) The type of facility (bulk gasoline plant with an annual average gasoline throughput less than 4,000 gallons per day; bulk gasoline plant with an annual average gasoline throughput of 4,000 gallons per day or more; bulk gasoline terminal with a gasoline throughput (total of all racks) less than 250,000 gallons per day; bulk gasoline terminal with a gasoline throughput (total of all racks) of 250,000 gallons per day or more; pipeline breakout station; or pipeline pumping station).

(vi) Date of report and beginning and ending dates of the reporting period. You are no longer required to provide the date of report when the report is submitted via CEDRI.

(vii) Statement by a responsible official, with that official's name, title, and signature, certifying the truth, accuracy, and completeness of the content of the report. If your report is submitted via CEDRI, the certifier's electronic signature during the submission process replaces the requirement in this paragraph (d)(1)(vii).

(2) For each thermal oxidation system used to comply with the provision in § 63.11092(e)(2)(i) by monitoring the combustion zone temperature, for each pressure CPMS used to comply with the requirements in § 60.502a(h) of this chapter, and for each vapor recovery system used to comply with the provisions in item 3 of table 3 to this subpart, report the following information for the CMS:

(i) For all instances when the temperature CPMS measured 3-hour rolling averages below the established operating limit or when the vapor collection system pressure exceeded the maximum loading pressure specified in § 60.502a(h) when liquid product was being loaded into gasoline cargo tanks or when the TOC CEMS measured 3-hour rolling average concentrations higher than the applicable emission limitation when the vapor recovery system was operating:

(A) The date and start time of the deviation.

(B) The duration of the deviation in hours.

(C) Each 3-hour rolling average combustion zone temperature, average pressure, or 3-hour rolling average TOC concentration during the deviation. For TOC concentration, indicate whether methane is excluded from the TOC concentration.

(D) A unique identifier for the CMS.

(E) The make, model number, and date of last calibration check of the CMS.

(F) The cause of the deviation and the corrective action taken.

(ii) For all instances that the temperature CPMS for measuring the combustion zone temperature or pressure CPMS was not operating or out of control when liquid product was loaded into gasoline cargo tanks, or the TOC CEMS was not operating or was out of control when the vapor recovery system was operating:

(A) The date and start time of the deviation.

(B) The duration of the deviation in hours.

(C) A unique identifier for the CMS.

(D) The make, model number, and date of last calibration check of the CMS.

(E) The cause of the deviation and the corrective action taken. For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) of this chapter is used, the corrective action taken shall include an indication of the use of the limited alternative for vapor recovery systems in § 60.504a(e) of this chapter.

(F) For TOC CEMS outages where the limited alternative for vapor recovery systems in § 60.504a(e) of this chapter is used, report either an indication that there were no deviations from the operating limits when using the limited alternative or report the number of each of the following types of deviations that occurred during the use of the limited alternative for vapor recovery systems in § 60.504a(e) of this chapter.

( 1) The number of adsorption cycles when the quantity of liquid product loaded in gasoline cargo tanks exceeded the operating limit established in § 60.504a(e)(1) of this chapter. Enter 0 if no deviations of this type.

( 2) The number of desorption cycles when the vacuum pressure was below the average vacuum pressure as specified in § 60.504a(e)(2)(i) of this chapter. Enter 0 if no deviations of this type.

( 3) The number of desorption cycles when the quantity of purge gas used was below the average quantity of purge gas as specified in § 60.504a(e)(2)(ii) of this chapter. Enter 0 if no deviations of this type.

( 4) The number of desorption cycles when the duration of the vacuum/purge cycle was less than the average duration as specified in § 60.504a(e)(2)(iii) of this chapter. Enter 0 if no deviations of this type.

(3) For each thermal oxidation system used to comply with the provision in § 63.11092(e)(2)(ii) and each flare used to comply with the provision in item 2 of table 3 to this subpart, report:

(i) The date and start and end times for each of the following instances:

(A) Each 15-minute block during which there was at least one minute when gasoline vapors were routed to the flare and no pilot flame was present.

(B) Each period of 2 consecutive hours during which visible emissions exceeded a total of 5 minutes. Additionally, report the number of minutes for which visible emissions were observed during the observation or an estimate of the cumulative number of minutes in the 2-hour period for which emissions were visible based on best information available to the owner or operator.

(C) Each 15-minute period for which the applicable operating limits specified in § 63.670(d) through (f) were not met. You must identify the specific operating limit that was not met. Additionally, report the information in paragraphs (d)(3)(i)(C)( 1) through ( 3) of this section, as applicable.

( 1) If you use the loading rate operating limits as determined in § 60.502a(c)(3)(vii) of this chapter alone or in combination with the supplemental gas flow rate monitoring alternative in § 60.502a(c)(3)(viii) of this chapter, the required minimum ratio and the actual ratio of gasoline loaded to total product loaded for the rolling 15-minute period and, if applicable, the required minimum quantity and the actual quantity of gasoline loaded, in gallons, for the rolling 15-minute period.

( 2) If you use the supplemental gas flow rate monitoring alternative in § 60.502a(c)(3)(viii) of this chapter, the required minimum supplemental gas flow rate and the actual supplemental gas flow rate including units of flow rates for the 15-minute block.

( 3) If you use parameter monitoring systems other than those specified in paragraphs (d)(3)(i)(C)( 1) and ( 2) of this section, the value of the net heating value operating parameter(s) during the deviation determined following the methods in § 63.670(k) through (n) as applicable.

(ii) The start date, start time, and duration in minutes for each period when “vapors displaced from gasoline cargo tanks during product loading” were routed to the flare or thermal oxidation system and the applicable monitoring was not performed.

(iii) For each instance reported under paragraphs (d)(3)(i) and (ii) of this section that involves CMS, report the following information:

(A) A unique identifier for the CMS.

(B) The make, model number, and date of last calibration check of the CMS.

(C) The cause of the deviation or downtime and the corrective action taken.

(4) For any instance in which liquid product was loaded into a gasoline cargo tank for which vapor tightness documentation required under § 63.11094(b) was not provided or available in the terminal's records, report:

(i) Cargo tank owner and address.

(ii) Cargo tank identification number.

(iii) Date and time liquid product was loaded into a gasoline cargo tank without proper documentation.

(iv) Date proper documentation was received or statement that proper documentation was never received.

(5) For each instance when liquid product was loaded into gasoline cargo tanks not using submerged filling, as defined in § 63.11100, not equipped with vapor collection or balancing equipment that is compatible with the terminal's vapor collection system or plant's vapor balancing system, or not properly connected to the terminal's vapor collection system or plant's vapor balancing system, report:

(i) Date and time of liquid product loading into gasoline cargo tank not using submerged filling, improperly equipped, or improperly connected.

(ii) The type of deviation ( e.g., not submerged filling, incompatible equipment, not properly connected).

(iii) Cargo tank identification number.

(6) For each instance when gasoline was loaded between gasoline cargo tanks and storage tanks and the plant's vapor balancing system was not properly connected between the gasoline cargo tank and storage tank, report:

(i) Date and time of gasoline loading between a gasoline cargo tank and a storage tank that was not properly connected.

(ii) Cargo tank identification number and storage tank identification number.

(7) Report the following information for each leak inspection and each leak identified under § 63.11089(c) and § 60.503a(a)(2) of this chapter.

(i) For each leak detected during a leak inspection required under § 63.11089(c) and § 60.503a(a)(2) of this chapter, report:

(A) The date of inspection.

(B) The leak determination method (OGI or Method 21).

(C) The total number and type of equipment for which leaks were detected.

(D) The total number and type of equipment for which leaks were repaired within 15 calendar days.

(E) The total number and type of equipment for which no repair attempt was made within 5 calendar days of the leaks being identified.

(F) The total number and types of equipment placed on the delay of repair, as specified in § 60.502a(j)(8) of this chapter.

(ii) For leaks identified under § 63.11089(c) by audio/visual/olfactory methods during normal duties report:

(A) The total number and type of equipment for which leaks were identified.

(B) The total number and type of equipment for which leaks were repaired within 15 calendar days.

(C) The total number and type of equipment for which no repair attempt was made within 5 calendar days of the leaks being identified.

(D) The total number and type of equipment placed on the delay of repair, as specified in § 60.502a(j)(8) of this chapter.

(iii) The total number of leaks on the delay of repair list at the start of the reporting period.

(iv) The total number of leaks on the delay of repair list at the end of the reporting period.

(v) For each leak that was on the delay of repair list at any time during the reporting period, report:

(A) Unique equipment identification number.

(B) Type of equipment.

(C) Leak determination method (OGI, Method 21, or audio/visual/olfactory).

(D) The reason(s) why the repair was not feasible within 15 calendar days.

(E) If applicable, the date repair was completed.

(8) For each gasoline storage tank subject to requirements in item 2 of table 1 to this subpart, report:

(i) If you are complying with options 2(a), 2(b), or 2(d) in table 1 to this subpart, the information specified in § 60.115b(a) or (b) of this chapter or deviations in measured parameter values from the plan specified in § 60.115b(c) of this chapter, depending upon the control equipment installed, or, if you are complying with option 2(e) in table 1 to this subpart, the information specified in § 63.1066(b).

(ii) If you are complying with options 2(c) or 2(e) in table 1 to this subpart, for each deviation in LEL monitoring, report:

(A) Date and start and end times of the LEL monitoring, and the tank being monitored.

(B) Description of the monitoring event, e.g., monitoring conducted concurrent with visual inspection required under § 60.113b(a)(2) of this chapter or § 63.1063(d)(2); monitoring that occurred on a date other than the visual inspection required under § 60.113b(a)(2) or § 63.1063(d)(2) of this chapter; re-monitoring due to high winds; re-monitoring after repair attempt.

(C) Wind speed in miles per hour at the top of the tank on the date of LEL monitoring.

(D) The highest 5-minute rolling average reading during the monitoring event.

(E) Whether the floating roof was repaired, replaced, or taken out of gasoline service. If the floating roof was repaired or replaced, also report the information in paragraphs (d)(8)(ii)(A) through (D) of this section for each re-monitoring conducted to confirm the repair.

(9) If there were no deviations from the emission limitations, operating parameters, or work practice standards, then provide a statement that there were no deviations from the emission limitations, operating parameters, or work practice standards during the reporting period. If there were no periods during which a continuous monitoring system (including a CEMS or CPMS) was inoperable or out-of-control, then provide a statement that there were no periods during which a continuous monitoring system was inoperable or out-of-control during the reporting period.

(e) Requirements for semiannual report submissions. Each owner or operator of an affected source under this subpart shall submit semiannual compliance reports with the information specified in paragraph (c) or (d) of this section to the Administrator according to the requirements in § 63.13. Beginning on May 8, 2027, or once the report template for this subpart has been available on the CEDRI website ( https://www.epa.gov/electronic-reporting-air-emissions/cedri ) for one year, whichever date is later, you must submit all subsequent semiannual compliance reports using the appropriate electronic report template on the CEDRI website for this subpart and following the procedure specified in § 63.9(k), except any medium submitted through mail must be sent to the attention of the Gasoline Distribution Sector Lead. The date report templates become available will be listed on the CEDRI website. Unless the Administrator or delegated State agency or other authority has approved a different schedule for submission of reports, the report must be submitted by the deadline specified in this subpart, regardless of the method in which the report is submitted.

Table 4 to this subpart shows which parts of the General Provisions apply to you.

(c) The authorities that cannot be delegated to State, local, or Tribal agencies are as specified in paragraphs (c)(1) through (5) of this section.

(5) Approval of an alternative to any electronic reporting to the EPA required by this subpart.

As used in this subpart, all terms not defined herein shall have the meaning given them in the Clean Air Act (CAA), in subparts A, K, Ka, Kb, and XXa of part 60 of this chapter, or in subparts A, R, and WW of this part. All terms defined in both subpart A of part 60 of this chapter and subparts A, R, and WW of this part shall have the meaning given in subparts A, R, and WW of this part. For purposes of this subpart, definitions in this section supersede definitions in other parts or subparts.

Bulk gasoline terminal means:

(1) Prior to May 8, 2027, any gasoline storage and distribution facility that receives gasoline by pipeline, ship or barge, or cargo tank and has a gasoline throughput of 20,000 gallons per day or greater. Gasoline throughput shall be the maximum calculated design throughput as may be limited by compliance with an enforceable condition under Federal, State, or local law and discoverable by the Administrator and any other person.

(2) On or after May 8, 2027, any gasoline facility which receives gasoline by pipeline, ship, barge, or cargo tank and subsequently loads all or a portion of the gasoline into gasoline cargo tanks for transport to bulk gasoline plants or gasoline dispensing facilities and has a gasoline throughput of 20,000 gallons per day (75,700 liters per day) or greater. Gasoline throughput shall be the maximum calculated design throughput for the facility as may be limited by compliance with an enforceable condition under Federal, State, or local law and discoverable by the Administrator and any other person.

Flare means a thermal combustion device using an open or shrouded flame (without full enclosure) such that the pollutants are not emitted through a conveyance suitable to conduct a performance test.

Gasoline means any petroleum distillate or petroleum distillate/alcohol blend having a Reid vapor pressure of 4.0 pounds per square inch (27.6 kilopascals) or greater, which is used as a fuel for internal combustion engines.

Operating parameter value means a value for an operating or emission parameter of the vapor processing system ( e.g., temperature) which, if maintained continuously by itself or in combination with one or more other operating parameter values, determines that an owner or operator has complied with the applicable emission standard. The operating parameter value is determined using the procedures specified in § 63.11092(b) and (e).

Pipeline breakout station means:

(1) Prior to May 8, 2027, a facility along a pipeline containing storage vessels used to relieve surges or receive and store gasoline from the pipeline for reinjection and continued transportation by pipeline or to other facilities.

(2) On or after May 8, 2027, a facility along a pipeline containing storage vessels used to relieve surges or receive and store gasoline from the pipeline for reinjection and continued transportation by pipeline to other facilities. Pipeline breakout stations do not have loading racks where gasoline is loaded into cargo tanks. If any gasoline is loaded into cargo tanks, the facility is a bulk gasoline terminal for the purposes of this subpart provided the facility-wide gasoline throughput (including pipeline throughput) exceeds the limits specified for bulk gasoline terminals.

Pipeline pumping station means a facility along a pipeline containing pumps to maintain the desired pressure and flow of product through the pipeline, and not containing gasoline loading racks or gasoline storage tanks other than surge control tanks.

Thermal oxidation system means an enclosed combustion device used to mix and ignite fuel, air pollutants, and air to provide a flame to heat and oxidize hazardous air pollutants. Auxiliary fuel may be used to heat air pollutants to combustion temperatures. Thermal oxidation systems emit pollutants through a conveyance suitable to conduct a performance test.

Table 1 to Subpart BBBBBB of Part 63—Applicability Criteria, Emission Limits, and Management Practices for Storage Tanks

If you own or operate . . .	Then you must . . .
1. A gasoline storage tank meeting either of the following conditions: (i) a capacity of less than 75 cubic meters (m ); or (ii) a capacity of less than 151 m and a gasoline throughput of 480 gallons per day or less. Gallons per day is calculated by summing the current day's throughput, plus the throughput for the previous 364 days, and then dividing that sum by 365	(a) Equip each gasoline storage tank with a fixed roof that is mounted to the storage tank in a stationary manner, and maintain all openings in a closed position at all times when not in use; and (b) No later than the dates specified in § 63.11083, all pressure relief devices on each gasoline storage tank must be set to no less than 18 inches of water at all times to minimize breathing losses.
2. A gasoline storage tank with a capacity of greater than or equal to 75 m and not meeting any of the criteria specified in item 1 of this table	Do the following: (a) Reduce emissions of total organic HAP or TOC by 95 weight-percent with a closed vent system and control device, as specified in § 60.112b(a)(3) of this chapter; or (b) Equip each internal floating roof gasoline storage tank according to the requirements in § 60.112b(a)(1) of this chapter, except for the secondary seal requirements under § 60.112b(a)(1)(ii)(B) and the requirements in § 60.112b(a)(1)(iv) through (ix) of this chapter; and (c) No later than the dates specified in § 63.11083, equip, maintain, and operate each internal floating roof control system to maintain the vapor concentration within the storage tank above the floating roof at or below 25 percent of the LEL on a 5-minute rolling average basis without the use of purge gas, which may require additional controls beyond those specified in item 2(b) of this table; and (d) Equip each external floating roof gasoline storage tank according to the requirements in § 60.112b(a)(2) of this chapter, except that the requirements of § 60.112b(a)(2)(ii) of this chapter shall only be required if such storage tank does not currently meet the requirements of § 60.112b(a)(2)(i) of this chapter; by the dates specified in § 63.11083, all external floating roofs must meet the requirements of § 60.112b(a)(2)(ii) of this chapter; or (e) Equip and operate each internal and external floating roof gasoline storage tank according to the applicable requirements in § 63.1063(a)(1) and (b), except for the secondary seal requirements under § 63.1063(a)(1)(i)(C) and (D), and equip each external floating roof gasoline storage tank according to the requirements of § 63.1063(a)(2) by the dates specified in § 63.11087(b) if such storage tank does not currently meet the requirements of § 63.1063(a)(1); by the dates specified in § 63.11083, all external floating roofs must meet the requirements of § 63.1063(a)(2); and (f) No later than the dates specified in § 63.11083, equip, maintain, and operate each internal floating roof control system to maintain the vapor concentration within the storage tank above the floating roof at or below 25 percent of the LEL on a 5-minute rolling average basis without the use of purge gas, which may require additional controls beyond those specified in item 2(e) of this table.
3. A surge control tank	Equip each tank with a fixed roof that is mounted to the tank in a stationary manner and with a pressure/vacuum vent with a positive cracking pressure of no less than 0.50 inches of water. Maintain all openings in a closed position at all times when not in use.

Table 2 to Subpart BBBBBB of Part 63—Applicability Criteria, Emission Limits, and Management Practices for Loading Racks

If you own or operate . . .	Then you must . . .
1. A bulk gasoline terminal loading rack(s) with a gasoline throughput (total of all racks) of 250,000 gallons per day, or greater (“large bulk gasoline terminal”). Gallons per day is calculated by summing the current day's throughput, plus the throughput for the previous 364 days, and then dividing that sum by 365	(a) Equip your loading rack(s) with a vapor collection system designed and operated to collect the TOC vapors displaced from cargo tanks during product loading; and (b) Reduce emissions of TOC to less than or equal to 80 mg/l of gasoline loaded into gasoline cargo tanks at the loading rack; and (c) No later than the dates specified in § 63.11083, reduce emissions of TOC to the applicable limits in table 3 to this subpart. The requirements in item 1(b) do not apply when demonstrating compliance with this item; and (d) Design and operate the vapor collection system to prevent any TOC vapors collected at one loading rack or lane from passing through another loading rack or lane to the atmosphere; and (e) Limit the loading of gasoline into gasoline cargo tanks that are vapor tight using the procedures specified in § 60.502(e) through (j) of this chapter. For the purposes of this section, the term “tank truck” as used in § 60.502(e) through (j) means “gasoline cargo tank” as defined in § 63.11100; and (f) No later than the dates specified in § 63.11083, limit the loading of liquid product into gasoline cargo tanks using the procedures specified in § 60.502a(e) through (i) of this chapter and in § 63.11092(g) and (h). The requirements in item 1(e) do not apply when demonstrating compliance with this item.
2. A bulk gasoline terminal loading rack(s) with a gasoline throughput (total of all racks) of less than 250,000 gallons per day. Gallons per day is calculated by summing the current day's throughput, plus the throughput for the previous 364 days, and then dividing that sum by 365	(a) Use submerged filling with a submerged fill pipe that is no more than 6 inches from the bottom of the cargo tank; and (b) Make records available within 24 hours of a request by the Administrator to document your gasoline throughput. (c) No later than the dates specified in § 63.11083, limit the loading of gasoline into gasoline cargo tanks that are vapor tight using the procedures specified in § 60.502a(e) of this chapter and in § 63.11092(g).

Table 3 to Subpart BBBBBB of Part 63—Emission Limitations and Requirements for Large Bulk Gasoline Terminals Based on Control System Used

If you operate . . .	Then you must . . .
1. A thermal oxidation system	(a) Reduce emissions of TOC to less than or equal to 35 mg/l of liquid product loaded into gasoline cargo tanks at the loading rack; and (b) Continuously meet the applicable operating limit as specified in § 63.11092(e)(2).
2. A flare	Operate the flare following the applicable requirements specified in § 60.502a(c)(3) of this chapter.
3. A carbon adsorption system, refrigerated condenser, or other vapor recovery system.	(a) Reduce emissions of TOC to less than or equal to 19,200 parts per million by volume as propane determined on a 3-hour rolling average considering all periods when the vapor recovery system is capable of processing gasoline vapors, including periods when liquid product is being loaded, during carbon bed regeneration, and when preparing the beds for reuse. (b) Operate the vapor recovery system to minimize air or nitrogen intrusion except as needed for the system to operate as designed for the purpose of removing VOC from the adsorption media or to break vacuum in the system and bring the system back to atmospheric pressure. Consistent with § 63.4, the use of diluents to achieve compliance with a relevant standard based on the concentration of a pollutant in the effluent discharged to the atmosphere is prohibited.

Table 4 to Subpart BBBBBB of Part 63—Applicability of General Provisions

§ 63.2§ 63.6(a)§ 63.6(b)(5)§ 63.6(b)(6)§ 63.6(b)(7)§ 63.6(c)(5)§ 63.6(d)§ 63.6(e)(1)(i)§ 63.6(e)(1)(ii)§ 63.6(e)(2)§ 63.6(e)(3)§ 63.6(f)(1)§ 63.6(h)(1)§ 63.6(h)(2)(i)§ 63.6(h)(2)(ii)§ 63.6(h)(2)(iii)§ 63.6(h)(3)§ 63.6(h)(4)§ 63.6(h)(5)(ii)§ 63.6(h)(6)§ 63.6(h)(7)(i)§ 63.6(h)(7)(ii)§ 63.6(h)(7)(iii)§ 63.6(h)(7)(iv)§ 63.6(h)(7)(v)§ 63.6(h)(8)§ 63.6(h)(9)§ 63.6(j)§ 63.7(a)(2)§ 63.7(a)(3)§ 63.7(a)(4)§ 63.7(b)(1)§ 63.7(b)(2)§ 63.7(c)§ 63.7(d)§ 63.7(e)(1)§ 63.7(e)(2)§ 63.7(e)(3)§ 63.7(f)§ 63.7(g)§ 63.7(h)§ 63.8(a)(1)§ 63.8(a)(2)§ 63.8(a)(3)§ 63.8(a)(4)§ 63.8(b)(1)§ 63.8(c)(1)(i)§ 63.8(c)(1)(ii)§ 63.8(c)(1)(iii)§ 63.8(d)(3)§ 63.8(e)§ 63.8(f)(6)§ 63.8(g)§ 63.9(a)§ 63.9(b)(3)§ 63.9(c)§ 63.9(d)§ 63.9(e)§ 63.9(f)§ 63.9(g)§ 63.9(h)(4)§ 63.9(i)§ 63.9(j)§ 63.9(k)§ 63.10(a)§ 63.10(b)(1)§ 63.10(b)(2)(i)§ 63.10(b)(2)(ii)§ 63.10(b)(2)(iii)§ 63.10(b)(2)(iv)§ 63.10(b)(2)(v)§ 63.10(b)(2)(xii)§ 63.10(b)(2)(xiii)§ 63.10(b)(2)(xiv)§ 63.10(b)(3)§ 63.10(c)§ 63.10(d)(1)§ 63.10(d)(2)§ 63.10(d)(3)§ 63.10(d)(4)§ 63.10(d)(5)§ 63.10(e)(4)§ 63.10(f)§ 63.11(a)§ 63.11(b)

Citation	Subject	Brief description	Applies to this subpart
§ 63.1	Applicability	Initial applicability determination; applicability after standard established; permit requirements; extensions, notifications	Yes, specific requirements given in § 63.11081.
§ 63.1(c)(2)	Title V permit	Requirements for obtaining a title V permit from the applicable permitting authority	Yes, § 63.11081(b) exempts identified area sources from the obligation to obtain title V operating permits.
Definitions	Definitions for standards in this part	Yes, additional definitions in § 63.11100.
§ 63.3	Units and Abbreviations	Units and abbreviations for standards under this part	Yes.
§ 63.4	Prohibited Activities and Circumvention	Prohibited activities; circumvention, severability	Yes.
§ 63.5	Construction/Reconstruction	Applicability; applications; approvals	Yes.
Compliance with Standards/Operation & Maintenance Applicability	General Provisions apply unless compliance extension; General Provisions apply to area sources that become major	Yes.
§ 63.6(b)(1) through (4)	Compliance Dates for New and Reconstructed Sources	Dates standards apply for new and reconstructed sources	Yes.
Notification	Must notify if commenced construction or reconstruction after proposal	Yes.
[Reserved].
Compliance Dates for New and Reconstructed Area Sources that Become Major	Area sources that become major must comply with major source standards immediately upon becoming major, regardless of whether required to comply when they were an area source	No.
§ 63.6(c)(1) and (2)	Compliance Dates for Existing Sources	Comply according to date in this subpart	No, § 63.11083 specifies the compliance dates.
§ 63.6(c)(3) and (4)	[Reserved].
Compliance Dates for Existing Area Sources that Become Major	Area sources that become major must comply with major source standards by date indicated in this subpart or by equivalent time period ( e.g., 3 years)	No.
[Reserved].
General duty to minimize emissions	Operate to minimize emissions at all times; information Administrator will use to determine if operation and maintenance requirements were met	No. See § 63.11085 for general duty requirement.
Requirement to correct malfunctions as soon as possible	Owner or operator must correct malfunctions as soon as possible	No.
[Reserved].
Startup, Shutdown, and Malfunction (SSM) plan	Requirement for SSM plan; content of SSM plan; actions during SSM	No.
Compliance Except During SSM	You must comply with emission standards at all times except during SSM	No.
§ 63.6(f)(2) and (3)	Methods for Determining Compliance	Compliance based on performance test, operation and maintenance plans, records, inspection	Yes.
§ 63.6(g)(1) through (3)	Alternative Standard	Procedures for getting an alternative standard	Yes.
Compliance with Opacity/VE Standards	You must comply with opacity/VE standards at all times except during SSM	No.
Determining Compliance with Opacity/VE Standards	If standard does not state test method, use EPA Method 9 for opacity in appendix A to part 60 of this chapter and EPA Method 22 for VE in appendix A to part 60 of this chapter	No.
[Reserved].
Using Previous Tests to Demonstrate Compliance with Opacity/VE Standards	Criteria for when previous opacity/VE testing can be used to show compliance with this subpart	No.
[Reserved].
Notification of Opacity/VE Observation Date	Must notify Administrator of anticipated date of observation	No.
§ 63.6(h)(5)(i) and (iii) through (v)	Conducting Opacity/VE Observations	Dates and schedule for conducting opacity/VE observations	No.
Opacity Test Duration and Averaging Times	Must have at least 3 hours of observation with 30 6-minute averages	No.
Records of Conditions During Opacity/VE Observations	Must keep records available and allow Administrator to inspect	No.
Report Continuous Opacity Monitoring System (COMS) Monitoring Data from Performance Test	Must submit COMS data with other performance test data	No.
Using COMS Instead of EPA Method 9	Can submit COMS data instead of EPA Method 9 results even if this subpart requires EPA Method 9 in appendix A of part 60 of this chapter, but must notify Administrator before performance test	No.
Averaging Time for COMS During Performance Test	To determine compliance, must reduce COMS data to 6-minute averages	No.
COMS Requirements	Owner/operator must demonstrate that COMS performance evaluations are conducted according to § 63.8(e); COMS are properly maintained and operated according to § 63.8(c) and data quality as § 63.8(d)	No.
Determining Compliance with Opacity/VE Standards	COMS is probable but not conclusive evidence of compliance with opacity standard, even if EPA Method 9 (in appendix A to part 60 of this chapter) observation shows otherwise. Requirements for COMS to be probable evidence-proper maintenance, meeting Performance Specification 1 in appendix B to part 60 of this chapter, and data have not been altered	No.
Determining Compliance with Opacity/VE Standards	Administrator will use all COMS, EPA Method 9 (in appendix A to part 60 of this chapter), and EPA Method 22 (in appendix A to part 60 of this chapter) results, as well as information about operation and maintenance to determine compliance	No.
Adjusted Opacity Standard	Procedures for Administrator to adjust an opacity standard	No.
§ 63.6(i)(1) through (14)	Compliance Extension	Procedures and criteria for Administrator to grant compliance extension	Yes.
Presidential Compliance Exemption	President may exempt any source from requirement to comply with this subpart	Yes.
Performance Test Dates	Dates for conducting initial performance testing; must conduct 180 days after compliance date	Yes.
Section 114 Authority	Administrator may require a performance test under CAA section 114 at any time	Yes.
Force Majeure	Provisions for delayed performance tests due to force majeure	Yes.
Notification of Performance Test	Must notify Administrator 60 days before the test	Yes.
Notification of Re-scheduling	If have to reschedule performance test, must notify Administrator of rescheduled date as soon as practicable and without delay	Yes.
Quality Assurance (QA)/Test Plan	Requirement to submit site-specific test plan 60 days before the test or on date Administrator agrees with; test plan approval procedures; performance audit requirements; internal and external QA procedures for testing	Yes.
Testing Facilities	Requirements for testing facilities	Yes.
Conditions for Conducting Performance Tests	Performance test must be conducted under representative conditions	No, § 63.11092(i) specifies conditions for conducting performance tests.
Conditions for Conducting Performance Tests	Must conduct according to this subpart and EPA test methods unless Administrator approves alternative	Yes.
Test Run Duration	Must have three test runs of at least 1 hour each; compliance is based on arithmetic mean of three runs; conditions when data from an additional test run can be used	Yes, except for testing conducted under § 63.11092(a) and (e).
Alternative Test Method	Procedures by which Administrator can grant approval to use an intermediate or major change, or alternative to a test method	Yes.
Performance Test Data Analysis	Must include raw data in performance test report; must submit performance test data 60 days after end of test with the notification of compliance status; keep data for 5 years	Yes, except this subpart specifies how and when the performance test and performance evaluation results are reported.
Waiver of Tests	Procedures for Administrator to waive performance test	Yes.
Applicability of Monitoring Requirements	Subject to all monitoring requirements in standard	Yes.
Performance Specifications	Performance specifications in appendix B to part 60 of this chapter apply	Yes.
[Reserved].
Monitoring of Flares	Monitoring requirements for flares in § 63.11 apply	Yes.
Monitoring	Must conduct monitoring according to standard unless Administrator approves alternative	Yes.
§ 63.8(b)(2) and (3)	Multiple Effluents and Multiple Monitoring Systems	Specific requirements for installing monitoring systems; must install on each affected source or after combined with another affected source before it is released to the atmosphere provided the monitoring is sufficient to demonstrate compliance with the standard; if more than one monitoring system on an emission point, must report all monitoring system results, unless one monitoring system is a backup	Yes.
§ 63.8(c)(1) introductory text	Monitoring System Operation and Maintenance	Maintain monitoring system in a manner consistent with good air pollution control practices	Yes.
Operation and Maintenance of CMS	Must maintain and operate each CMS as specified in § 63.6(e)(1)	No.
Operation and Maintenance of CMS	Must keep parts for routine repairs readily available	Yes.
Operation and Maintenance of CMS	Requirement to develop SSM Plan for CMS	No.
§ 63.8(c)(2) through (8)	CMS Requirements	Must install to get representative emission or parameter measurements; must verify operational status before or at performance test	Yes.
§ 63.8(d)(1) and (2)	CMS Quality Control	Requirements for CMS quality control, including calibration, etc.	Yes.
CMS Quality Control Records	Must keep quality control plan on record for 5 years; keep old versions for 5 years after revisions	No. This subpart specifies CMS records requirements.
CMS Performance Evaluation	Notification, performance evaluation test plan, reports	Yes, except this subpart specifies how and when the performance evaluation results are reported.
§ 63.8(f)(1) through (5)	Alternative Monitoring Method	Procedures for Administrator to approve alternative monitoring	Yes.
Alternative to Relative Accuracy Test	Procedures for Administrator to approve alternative relative accuracy tests for CEMS	Yes.
Data Reduction	COMS 6-minute averages calculated over at least 36 evenly spaced data points; CEMS 1 hour averages computed over at least 4 equally spaced data points; data that cannot be used in average	Yes.
Notification Requirements	Applicability and State delegation	Yes.
§ 63.9(b)(1), (2), (4), and (5)	Initial Notifications	Submit notification of being subject to standard; notification of intent to construct/reconstruct, notification of commencement of construction/reconstruction, notification of startup; contents of each	Yes.
[Reserved].
Request for Compliance Extension	Can request if cannot comply by date or if installed best available control technology or lowest achievable emission rate	Yes.
Notification of Special Compliance Requirements for New Sources	Notification for new sources subject to special compliance requirements	Yes.
Notification of Performance Test	Notify Administrator 60 days prior	Yes.
Notification of VE/Opacity Test	Notify Administrator 30 days prior	No.
Additional Notifications When Using CMS	Notification of performance evaluation; notification about use of COMS data; notification that exceeded criterion for relative accuracy alternative	Yes, however, there are no opacity standards.
§ 63.9(h)(1) through (3), (5), and (6)	Notification of Compliance Status	Contents due 60 days after end of performance test or other compliance demonstration, except for opacity/VE, which are due 30 days after; when to submit to Federal vs. State authority	Yes, except as specified in § 63.11095(c).
[Reserved].
Adjustment of Submittal Deadlines	Procedures for Administrator to approve change when notifications must be submitted	Yes.
Change in Previous Information	Must submit within 15 days after the change	Yes.
Notifications	Electronic reporting procedures	Yes.
Recordkeeping/Reporting	Applies to all, unless compliance extension; when to submit to Federal vs. State authority; procedures for owners of more than one source	Yes.
Recordkeeping/Reporting	General requirements; keep all records readily available; keep for 5 years	Yes.
Records related to SSM	Recordkeeping of occurrence and duration of startups and shutdowns	No.
Records related to SSM	Recordkeeping of malfunctions	No. See § 63.11094(k) for recordkeeping requirements for deviations.
Maintenance records	Recordkeeping of maintenance on air pollution control and monitoring equipment	Yes.
Records Related to SSM	Actions taken to minimize emissions during SSM	No.
Records Related to SSM	Actions taken to minimize emissions during SSM	No.
§ 63.10(b)(2)(vi) through (xi)	CMS Records	Malfunctions, inoperative, out-of-control periods	Yes.
Records	Records when under waiver	Yes.
Records	Records when using alternative to relative accuracy test	Yes.
Records	All documentation supporting initial notification and notification of compliance status	Yes.
Records	Applicability determinations	Yes.
Records	Additional records for CMS	No. This subpart specifies CMS records.
General Reporting Requirements	Requirement to report	Yes.
Report of Performance Test Results	When to submit to Federal or State authority	No. This subpart specifies how and when the performance test results are reported.
Reporting Opacity or VE Observations	What to report and when	No.
Progress Reports	Must submit progress reports on schedule if under compliance extension	Yes.
SSM Reports	Contents and submission	No.
§ 63.10(e)(1) and (2)	Additional CMS Reports	Must report results for each CEMS on a unit; written copy of CMS performance evaluation; 2-3 copies of COMS performance evaluation	No.
§ 63.10(e)(3)(i) through (iii)	Reports	Schedule for reporting excess emissions	No.
§ 63.10(e)(3)(iv) and (v)	Excess Emissions Reports	Requirement to revert to quarterly submission if there is an excess emissions and parameter monitor exceedances (now defined as deviations); provision to request semiannual reporting after compliance for 1 year; submit report by 30th day following end of quarter or calendar half; if there has not been an exceedance or excess emissions (now defined as deviations), report contents in a statement that there have been no deviations; must submit report containing all of the information in §§ 63.8(c)(7) and (8) and 63.10(c)(5) through (13)	No.
§ 63.10(e)(3)(vi) through (viii)	Excess Emissions Report and Summary Report	Requirements for reporting excess emissions for CMS; requires all of the information in §§ 63.8(c)(7) and (8) and 63.10(c)(5) through (13)	No.
Reporting COMS Data	Must submit COMS data with performance test data	No. This subpart specifies COMS reporting.
Waiver for Recordkeeping/Reporting	Procedures for Administrator to waive	Yes.
Applicability	Specifies applicability of control device and work practice requirements within § 63.11	Yes.
Flares	Requirements for flares	Yes, except these provisions no longer apply for flares used to comply with the flare provisions in item 2 of table 3 to this subpart.
§ 63.11(c) through (e)	Alternative Work Practice for Monitoring Equipment for Leaks	Requirements for using optical gas imaging for EPA Method 21 monitoring	Yes, except these provisions do not apply to monitoring required under § 63.11092(a)(1)(i) or (e)(1) and these provisions no longer apply upon compliance with the provisions in § 63.11089(c).
§ 63.12	Delegation	State authority to enforce standards	Yes.
§ 63.13	Addresses	Addresses where reports, notifications, and requests are sent	Yes.
§ 63.14	Incorporations by Reference	Test methods incorporated by reference	Yes.
§ 63.15	Availability of Information	Public and confidential information	Yes.
§ 63.16	Performance Track Provisions	Special reporting provision for Performance Track member facilities.	Yes.

[FR Doc. 2024-04629 Filed 5-7-24; 8:45 am]

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