Title 40—Protection of Environment--Volume 1
PART 49—INDIAN COUNTRY: AIR QUALITY PLANNING AND MANAGEMENT
§ 49.4162   Delegation of authority of administration to the tribes.
(a) What is the purpose of this section? The purpose of this section is to establish the process by which the Regional Administrator may delegate to the Mandan, Hidatsa and Arikara Nation the authority to assist the EPA with administration of this Federal Implementation Plan (FIP). This section provides for administrative delegation and does not affect the eligibility criteria under 40 CFR 49.6 for treatment in the same manner as a state.
(b) How does the Tribe request delegation? In order to be delegated authority to assist us with administration of this FIP, the authorized representative of the Mandan, Hidatsa and Arikara Nation must submit a request to the Regional Administrator that:
(1) Identifies the specific provisions for which delegation is requested;
(2) Includes a statement by the Mandan, Hidatsa and Arikara Nation's legal counsel (or equivalent official) that includes the following information:
(i) A statement that the Mandan, Hidatsa and Arikara Nation are an Indian Tribe recognized by the Secretary of the Interior;
(ii) A descriptive statement demonstrating that the Mandan, Hidatsa and Arikara Nation are currently carrying out substantial governmental duties and powers over a defined area and that meets the requirements of § 49.7(a)(2); and
(iii) A description of the laws of the Mandan, Hidatsa and Arikara Nation that provide adequate authority to carry out the aspects of the rule for which delegation is requested.
(3) Demonstrates that the Mandan, Hidatsa and Arikara Nation have, or will have, adequate resources to carry out the aspects of the rule for which delegation is requested.
(c) How is the delegation of administration accomplished? (1) A Delegation of Authority Agreement will set forth the terms and conditions of the delegation, will specify the rule and provisions that the Mandan, Hidatsa and Arikara Nation shall be authorized to implement on behalf of the EPA, and shall be entered into by the Regional Administrator and the Mandan, Hidatsa and Arikara Nation. The Agreement will become effective upon the date that both the Regional Administrator and the authorized representative of the Mandan, Hidatsa and Arikara Nation have signed the Agreement. Once the delegation becomes effective, the Mandan, Hidatsa and Arikara Nation will be responsible, to the extent specified in the Agreement, for assisting us with administration of this FIP and shall act as the Regional Administrator as that term is used in these regulations. Any Delegation of Authority Agreement will clarify the circumstances in which the term “Regional Administrator”' found throughout this FIP is to remain the EPA Regional Administrator and when it is intended to refer to the “Mandan, Hidatsa and Arikara Nation,” instead.
(2) A Delegation of Authority Agreement may be modified, amended, or revoked, in part or in whole, by the Regional Administrator after consultation with the Mandan, Hidatsa and Arikara Nation.
(d) How will any delegation of authority agreement be publicized? The Regional Administrator shall publish a notice in the Federal Register informing the public of any delegation of authority agreement with the Mandan, Hidatsa and Arikara Nation to assist us with administration of all or a portion of this FIP and will identify such delegation in the FIP. The Regional Administrator shall also publish an announcement of the delegation of authority agreement in local newspapers.
§ 49.4163   General provisions.
(a) Definitions. As used in §§ 49.4161 through 49.4168, all terms not defined herein shall have the meaning given them in the Act, in subpart A and subpart OOOO of 40 CFR part 60, in the Prevention of Significant Deterioration regulations at 40 CFR 52.21, or in the Federal Minor New Source Review Program in Indian Country at 40 CFR 49.151. The following terms shall have the specific meanings given them.
(1) Bakken Pool means Oil produced from the Bakken, Three Forks, and Sanish Formations.
(2) Breathing losses means natural gas emissions from fixed roof tanks resulting from evaporative losses during storage.
(3) Casinghead natural gas means the associated natural gas that naturally dissolves out of reservoir fluids during well completion operations and recompletion operations due to the pressure relief that occurs as the reservoir fluids travel up the well casinghead.
(4) Closed vent system means a system that is not open to the atmosphere and that is composed of hard-piping, ductwork, connections, and, if necessary, flow-inducing devices that transport natural gas from a piece or pieces of equipment to a control device or back to a process.
(5) Enclosed combustor means a thermal oxidation system with an enclosed combustion chamber that maintains a limited constant temperature by controlling fuel and combustion air.
(6) Existing facility means an oil and natural gas production facility that begins actual construction prior to the effective date of the “Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota”.
(7) Flashing losses means natural gas emissions resulting from the presence of dissolved natural gas in the produced oil and the produced water, both of which are under high pressure, that occurs as the produced oil and produced water is transferred to storage tanks or other vessels that are at atmospheric pressure.
(8) Modified facility means a facility which has undergone the addition, completion, or recompletion of one or more oil and natural gas wells, and/or the addition of any associated equipment necessary for production and storage operations at an existing facility.
(9) New facility means an oil and natural gas production facility that begins actual construction after the effective date of the “Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota”.
(10) Oil means hydrocarbon liquids.
(11) Oil and natural gas production facility means all of the air pollution emitting units and activities located on or integrally connected to one or more oil and natural gas wells that are necessary for production operations and storage operations.
(12) Oil and natural gas well means a single well that extracts subsurface reservoir fluids containing a mixture of oil, natural gas, and water.
(13) Owner or operator means any person who owns, leases, operates, controls, or supervises an oil and natural gas production facility.
(14) Permit to construct or construction permit means a permit issued by the Regional Administrator pursuant to 40 CFR 49.151, 52.10 or 52.21, or a permit issued by a tribe pursuant to a program approved by the Administrator under 40 CFR part 51, subpart I, authorizing the construction or modification of a stationary source.
(15) Permit to operate or operating permit means a permit issued by the Regional Administrator pursuant to 40 CFR part 71, or by a tribe pursuant to a program approved by the Administrator under 40 CFR part 51 or 40 CFR part 70, authorizing the operation of a stationary source.
(16) Pit flare means an ignition device, installed horizontally or vertically and used in oil and natural gas production operations to combust produced natural gas and natural gas emissions.
(17) Produced natural gas means natural gas that is separated from extracted reservoir fluids during production operations.
(18) Produced oil means oil that is separated from extracted reservoir fluids during production operations.
(19) Produced oil storage tank means a unit that is constructed primarily of non-earthen materials (such as steel, fiberglass, or plastic) which provides structural support and is designed to contain an accumulation of produced oil.
(20) Produced water means water that is separated from extracted reservoir fluids during production operations.
(21) Produced water storage tank means a unit that is constructed primarily of non-earthen materials (such as steel, fiberglass, or plastic) which provides structural support and is designed to contain an accumulation of produced water.
(22) Production operations means the extraction and separation of reservoir fluids from an oil and natural gas well, using separators and heater-treater systems. A separator is a pressurized vessel designed to separate reservoir fluids into their constituent components of oil, natural gas and water. A heater-treater is a unit that heats the reservoir fluid to break oil/water emulsions and to reduce the oil viscosity. The water is then typically removed by using gravity to allow the water to separate from the oil.
(23) Regional Administrator means the Regional Administrator of EPA Region 8 or an authorized representative of the Regional Administrator.
(24) Standing losses means natural gas emissions from fixed roof tanks as a result of evaporative losses during storage.
(25) Storage operations means the transfer of produced oil and produced water to storage tanks, the filling of the storage tanks, the storage of the produced oil and produced water in the storage tanks, and the draining of the produced oil and produced water from the storage tanks.
(26) Supervisory Control and Data Acquisition (SCADA) system generally refers to industrial control computer systems that monitor and control industrial infrastructure or facility-based processes.
(27) Utility flare means thermal oxidation system using an open (without enclosure) flame. An enclosed combustor as defined in §§ 49.4161 through 49.4168 is not considered a flare.
(28) Visible Smoke emissions means a pollutant generated by thermal oxidation in a flare or enclosed combustor and occurring immediately downstream of the flame. Visible smoke occurring within, but not downstream of, the flame, is not considered to constitute visible smoke emissions.
(29) Well completion means the process that allows for the flowback of oil and natural gas from newly drilled wells to expel drilling and reservoir fluids and tests the reservoir flow characteristics, which may vent produced hydrocarbons to the atmosphere via an open pit or tank.
(30) Well completion operation means any oil and natural gas well completion using hydraulic fracturing occurring at an oil and natural gas production facility.
(31) Well recompletion operation means any oil and natural gas well completion using hydraulic refracturing occurring at an oil and natural gas production facility.
(32) Working losses means natural gas emissions from fixed roof tanks resulting from evaporative losses during filling and emptying operations.
(b) Requirement for testing. The Regional Administrator may require that an owner or operator of an oil and natural gas production facility demonstrate compliance with the requirements of the “Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota” by performing a source test and submitting the test results to the Regional Administrator. Nothing in the “Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota” limits the authority of the Regional Administrator to require, in an information request pursuant to section 114 of the Act, an owner or operator of an oil and natural gas production facility subject to the “Federal Implementation Plan for Oil and Natural Gas Production Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation)” to demonstrate compliance by performing testing, even where the facility does not have a permit to construct or a permit to operate.
(c) Requirement for monitoring, recordkeeping, and reporting. Nothing in “Federal Implementation Plan for Oil and Natural Gas Production Facilities, Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation)” precludes the Regional Administrator from requiring monitoring, recordkeeping and reporting, including monitoring, recordkeeping and reporting in addition to that already required by an applicable requirement in these rules, in a permit to construct or permit to operate in order to ensure compliance.
(d) Credible evidence. For the purposes of submitting reports or establishing whether or not an owner or operator of an oil and natural gas production facility has violated or is in violation of any requirement, nothing in the “Federal Implementation Plan for Oil and Natural Gas Well Production Facilities; Fort Berthold Indian Reservation (Mandan, Hidatsa and Arikara Nation), North Dakota” shall preclude the use, including the exclusive use, of any credible evidence or information, relevant to whether a facility would have been in compliance with applicable requirements if the appropriate performance or compliance test had been performed.
§ 49.4164   Construction and operational control measures.
(a) Each owner or operator must operate and maintain all liquid and gas collection, storage, processing and handling operations, regardless of size, so as to minimize leakage of natural gas emissions to the atmosphere.
(b) During all oil and natural gas well completion operations or recompletion operations at an oil and natural gas production facility and prior to the first date of production of each oil and natural gas well, each owner or operator must, at a minimum, route all casinghead natural gas to a utility flare or a pit flare capable of reducing the mass content of VOC in the natural gas emissions vented to it by at least 90.0 percent or greater and operated as specified in §§ 49.4165 and 49.4166.
(c) Beginning with the first date of production from any one oil and natural gas well at an oil and natural gas production facility, each owner or operator must, at a minimum, route all natural gas emissions from production operations and storage operations to a control device capable of reducing the mass content of VOC in the natural gas emissions vented to it by at least 90.0 percent or greater and operated as specified in §§ 49.4165 and 49.4166.
(d) Within ninety (90) days of the first date of production from any oil and natural gas well at an oil and natural gas production facility, each owner or operator must:
(1) Route the produced natural gas from the production operations through a closed-vent system to:
(i) An operating system designed to recover and inject all the produced natural gas into a natural gas gathering pipeline system for sale or other beneficial purpose; or
(ii) A utility flare or equivalent combustion device capable of reducing the mass content of VOC in the produced natural gas vented to the device by at least 98.0 percent or greater and operated as specified in §§ 49.4165 and 49.4166.
(2) Route all standing, working, breathing, and flashing losses from the produced oil storage tanks and any produced water storage tank interconnected with the produced oil storage tanks through a closed-vent system to:
(i) An operating system designed to recover and inject the natural gas emissions into a natural gas gathering pipeline system for sale or other beneficial purpose; or
(ii) An enclosed combustor or utility flare capable of reducing the mass content of VOC in the natural gas emissions vented to the device by at least 98.0 percent or greater and operated as specified in §§ 49.4165(c) and 49.4166.
(iii) If the uncontrolled potential to emit VOCs from the aggregate of all produced oil storage tanks and produced water storage tanks interconnected with produced oil storage tanks at an oil and natural gas production facility is less than, and reasonably expected to remain below, 20 tons in any consecutive 12-month period, then, upon prior written approval by the EPA the owner or operator may use a pit flare, an enclosed combustor or a utility flare that is capable of reducing the mass content of VOC in the natural gas emissions from the storage tanks vented to the device by only 90.0 percent.
(e) In the event that pipeline injection of all or part of the natural gas collected in an operating system designed to recover and inject natural gas becomes temporarily infeasible and there is no operational enclosed combustor or utility flare at the facility, the owner or operator must route the natural gas that cannot be injected through a closed-vent system to a pit flare operated as specified in §§ 49.4165 and 49.4166.
(f) Produced oil storage tanks and any produced water storage tanks interconnected with produced oil storage tanks subject to the requirements specified in 40 CFR part 60, subpart OOOO are considered to meet the requirements of § 49.4164(d)(2). No further requirements apply for such storage tanks under § 49.4164(d)(2).
§ 49.4165   Control equipment requirements.
(a) Covers. Each owner or operator must equip all openings on each produced oil storage tank and produced water storage tank interconnected with produced oil storage tanks with a cover to ensure that all natural gas emissions are efficiently being routed through a closed-vent system to a vapor recovery system, an enclosed combustor, a utility flare, or a pit flare.
(1) Each cover and all openings on the cover (e.g., access hatches, sampling ports, pressure relief valves (PRV), and gauge wells) shall form a continuous impermeable barrier over the entire surface area of the produced oil and produced water in the storage tank.
(2) Each cover opening shall be secured in a closed, sealed position (e.g., covered by a gasketed lid or cap) whenever material is in the unit on which the cover is installed except during those times when it is necessary to use an opening as follows:
(i) To add material to, or remove material from the unit (this includes openings necessary to equalize or balance the internal pressure of the unit following changes in the level of the material in the unit);
(ii) To inspect or sample the material in the unit; or
(iii) To inspect, maintain, repair, or replace equipment located inside the unit.
(3) Each thief hatch cover shall be weighted and properly seated.
(4) Each PRV shall be set to release at a pressure that will ensure that natural gas emissions are routed through the closed-vent system to the vapor recovery system, the enclosed combustor, or the utility flare under normal operating conditions.
(b) Closed-vent systems. Each owner or operator must meet the following requirements for closed-vent systems:
(1) Each closed-vent system must route all produced natural gas and natural gas emissions from production and storage operations to the natural gas sales pipeline or the control devices required by paragraph (a) of this section.
(2) All vent lines, connections, fittings, valves, relief valves, or any other appurtenance employed to contain and collect natural gas, vapor, and fumes and transport them to a natural gas sales pipeline and any VOC control equipment must be maintained and operated properly at all times.
(3) Each closed-vent system must be designed to operate with no detectable natural gas emissions.
(4) If any closed-vent system contains one or more bypass devices, except as provided for in paragraph (b)(4)(iii) of this section, that could be used to divert all or a portion of the natural gas emissions, from entering a natural gas sales pipeline and/or any control devices, the owner or operator must meet the one of following requirements for each bypass device:
(i) At the inlet to the bypass device that could divert the natural gas emissions away from a natural gas sales pipeline or a control device and into the atmosphere, properly install, calibrate, maintain, and operate a natural gas flow indicator that is capable of taking continuous readings and sounding an alarm when the bypass device is open such that natural gas emissions are being, or could be, diverted away from a natural gas sales pipeline or a control device and into the atmosphere;
(ii) Secure the bypass device valve installed at the inlet to the bypass device in the non-diverting position using a car-seal or a lock-and-key type configuration;
(iii) Low leg drains, high point bleeds, analyzer vents, open-ended valves or lines, and safety devices are not subject to the requirements applicable to bypass devices.
(c) Enclosed combustors and utility flares. Each owner or operator must meet the following requirements for enclosed combustors and utility flares:
(1) For each enclosed combustor or utility flare, the owner or operator must follow the manufacturer's written operating instructions, procedures and maintenance schedule to ensure good air pollution control practices for minimizing emissions;
(2) For each enclosed combustor or utility flare, the owner or operator must ensure there is sufficient capacity to reduce the mass content of VOC in the produced natural gas and natural gas emissions routed to it by at least 98.0 percent for the minimum and maximum natural gas volumetric flow rate and BTU content routed to the device;
(3) Each enclosed combustor or utility flare must be operated to reduce the mass content of VOC in the produced natural gas and natural gas emissions routed to it by at least 98.0 percent;
(4) The owner or operator must ensure that each utility flare is designed and operated in accordance with the requirements of 40 CFR 60.18(b) for such flares, except for § 60.18(c)(2) and (f)(2) for those utility flares operated with an electronically controlled automatic igniter.
(5) The owner or operator must ensure that each enclosed combustor is:
(i) A model demonstrated by a manufacturer to the meet the VOC destruction efficiency requirements of §§ 49.4161 through 49.4168 using the procedure specified in 40 CFR part 60, subpart OOOO at § 60.5413(d) by the due date of the first annual report as specified in § 49.4168(b); or
(ii) Demonstrated to meet the VOC destruction efficiency requirements of §§ 49.4161 through 49.4168 using EPA approved performance test methods specified in 40 CFR part 60, subpart OOOO at § 60.5413(b) by the due date of the first annual report as specified in § 49.4168(b).
(6) The owner or operator must ensure that each enclosed combustor and utility flare is:
(i) Operated properly at all times that produced natural gas and/or natural gas emissions are routed to it;
(ii) Operated with a liquid knock-out system to collect any condensable vapors (to prevent liquids from going through the control device);
(iii) Equipped with a flash-back flame arrestor;
(iv) Equipped with one of the following:
(A) A continuous burning pilot flame.
(B) An electronically controlled automatic igniter;
(v) Equipped with a monitoring system for continuous recording of the parameters that indicate proper operation of each enclosed combustor, utility flare, continuous burning pilot flame, and electronically controlled automatic igniter, such as a chart recorder, data logger or similar devices;
(vi) Maintained in a leak-free condition; and
(vii) Operated with no visible smoke emissions.
(d) Pit Flares. Each owner or operator must meet the following requirements for pit flares:
(1) The owner or operator must develop written operating instructions, operating procedures and maintenance schedules to ensure good air pollution control practices for minimizing emissions from the pit flare based on the site-specific design.
(2) The owner or operator must only use a pit flare for the following operations:
(i) To control produced natural gas and natural gas emissions during well completion operations or recompletion operations;
(ii) To control produced natural gas and natural gas emissions in the event that natural gas recovered for pipeline injection must be diverted to a backup control device because injection is temporarily infeasible and there is no operational enclosed combustor or utility flare at the oil and natural gas production facility. Use of the pit flare for this situation is limited to a maximum of 500 hours in any twelve (12) consecutive months; or
(iii) Control of standing, working, breathing, and flashing losses from the produced oil storage tanks and any produced water storage tank interconnected with the produced oil storage tanks if the uncontrolled potential VOC emissions from the aggregate of all produced oil storage tanks and produced water storage tanks interconnected with produced oil storage tanks is less than, and reasonably expected to remain below, 20 tons in any consecutive 12-month period.
(3) The owner or operator must only use the pit flare under the following conditions and limitations:
(i) The pit flare is operated to reduce the mass content of VOC in the produced natural gas and natural gas emissions routed to it by at least 90.0 percent;
(ii) The pit flare is operated in accordance with the site-specific written operating instructions, operating procedures, and maintenance schedules to ensure good air pollution control practices for minimizing emissions;
(iii) The pit flare is operated with no visible smoke emissions;
(iv) The pit flare is equipped with an electronically controlled automatic igniter;
(v) The pit flare is visually inspected for the presence of a flame anytime produced natural gas or natural gas emissions are being routed to it. Should the flame fail, the flame must be relit as soon as safely possible and the electronically controlled automatic igniter must be repaired or replaced before the pit flare is utilized again; and
(vi) The owner or operator does not deposit or cause to be deposited into a flare pit any oil field fluids or oil and natural gas wastes other than those designed to go to the pit flare.
(e) Other Control Devices. Upon prior written approval by the EPA, the owner or operator may use control devices other than those listed above that are determined by EPA to be capable of reducing the mass content of VOC in the natural gas routed to it by at least 98.0 percent, provided that:
(1) In operating such control devices, the owner or operator must follow the manufacturer's written operating instructions, procedures and maintenance schedule to ensure good air pollution control practices for minimizing emissions; and
(2) The owner or operator must ensure there is sufficient capacity to reduce the mass content of VOC in the produced natural gas and natural gas emissions routed to such other control devices by at least 98.0 percent for the minimum and maximum natural gas volumetric flow rate and BTU content routed to each device.
(3) The owner or operator must operate such a control device to reduce the mass content of VOC in the produced natural gas and natural gas emissions routed to it by at least 98.0 percent.
§ 49.4166   Monitoring requirements.
(a) Each owner and operator must measure the barrels of oil produced at the oil and natural gas production facility each time the oil is unloaded from the produced oil storage tanks using the methodologies of tank gauging or positive displacement metering system, as appropriate, as established by the U.S. Department of the Interior's Bureau of Land Management at 43 CFR part 3160, in the “Onshore Oil and Gas Operations; Federal and Indian Oil & Gas Leases; Onshore Oil and Gas Order No. 4; Measurement of Oil”.
(b) Each owner or operator must monitor the hours that each pit flare is operated to control produced natural gas and natural gas emissions in the event that natural gas recovered for pipeline injection must be diverted to a backup control device because injection is temporarily infeasible and there is no enclosed combustor or utility flare at the oil and natural gas production facility.
(c) Each owner or operator must monitor the volume of produced natural gas sent to each enclosed combustor, utility flare, and pit flare at all times. Methods to measure the volume include, but are not limited to, direct measurement and gas-to-oil ratio (GOR) laboratory analyses.
(d) Each owner or operator must monitor the volume of standing, working, breathing, and flashing losses from the produced oil and produced water storage tanks sent to each vapor recovery system, enclosed combustor, utility flare, and pit flare at all times. Methods to measure the volume include, but are not limited to, direct measurement or GOR laboratory analyses.
(e) Each owner or operator must perform quarterly visual inspections of tank thief hatches, covers, seals, PRVs, and closed vent systems to ensure proper condition and functioning and repair any damaged equipment. The quarterly inspections must be performed while the produced oil and produced water storage tanks are being filled.
(f) Each owner or operator must perform quarterly visual inspections of the peak pressure and vacuum values in each closed vent system and control system for the produced oil and produced water storage tanks to ensure that the pressure and vacuum relief set-points are not being exceeded in a way that has resulted, or may result, in venting and possible damage to equipment. The quarterly inspections must be performed while the produced oil and produced water storage tanks are being filled.
(g) Each owner or operator must monitor the operation of each enclosed combustor, utility flare, and pit flare to confirm proper operation as follows:
(1) Continuously monitor all variable operational parameters specified in the written operating instructions and procedures, including continuous burning pilot flame, electronically controlled automatic igniters, and monitoring system failures, using a malfunction alarm and remote notification system, where such systems are available, or continuously monitor under an equivalent alternative protocol upon prior written approval by the EPA;
(2) Perform a physical inspection of all equipment associated with each enclosed combustor, utility flare, and pit flare each time an operator is on site, at a minimum quarterly, to ensure system integrity;
(3) Monitor for visible smoke during operation of any enclosed combustor, utility flare or pit flare each time an operator is on site, at a minimum quarterly. Upon observation of visible smoke, use EPA Reference Method 22 of 40 CFR part 60, Appendix A, to determine whether visible smoke emissions are present. The observation period shall be 2 hours. Visible smoke emissions are present if smoke is observed for more than 5 minutes in any 2 consecutive hours; and
(4) Respond to any observation of any continuous burning pilot flame failure, electronically controlled automatic igniter failure, or improper monitoring equipment operation and ensure the equipment is returned to proper operation as soon as practicable and safely possible after an observation or an alarm sounds.
(h) Where sufficient to meet the monitoring and recordkeeping requirements in §§ 49.4166 and 49.4167, the owner or operator may use a Supervisory Control and Data Acquisition (SCADA) system to monitor and record the required data in §§ 49.4161 through 49.4168.
(i) Other Monitoring Options. The owner or operator may use equivalent methods of monitoring other than those listed above upon prior written approval by the EPA.
§ 49.4167   Recordkeeping requirements.
(a) Each owner or operator must maintain the following records:
(1) The measured barrels of oil produced at the oil and natural gas production facility each time the oil is unloaded from the produced oil storage tanks;
(2) The volume of produced natural gas sent to each enclosed combustor, utility flare, and pit flare at all times;
(3) The volume of natural gas emissions from the produced oil storage tanks and produced water storage tanks sent to each enclosed combustor, utility flare, and pit flare at all times;
(4) A summary of each oil and natural gas well completion operation and recompletion operation at an oil and natural gas production facility. Each summary shall include:
(i) The latitude and longitude location of the oil and natural gas well in decimal format;
(ii) The date, time, and duration in hours of flowback from the oil and natural gas well;
(iii) The date, time, and duration in hours of any venting of casinghead natural gas from the oil and natural gas well; and
(iv) Specific reasons for each instance of venting in lieu of capture or combustion.
(5) For each enclosed combustor, utility flare, and pit flare at an oil and natural gas production facility:
(i) Written, site-specific designs, operating instructions, operating procedures and maintenance schedules;
(ii) Records of all required monitoring of operations;
(iii) Records of any deviations from the operating parameters specified by the written site-specific designs, operating instructions, and operating procedures. The records must include the enclosed combustor, utility flare, or pit flare's total operating time during which a deviation occurred, the date, time and length of time that deviations occurred, and the corrective actions taken and any preventative measures adopted to operate the device within that operating parameter;
(iv) Records of any instances in which the pilot flame is not present, electronically controlled automatic igniter is not functioning, or the monitoring equipment is not functioning in the enclosed combustor, the utility flare, or the pit flare, the date and times of the occurrence, the corrective actions taken, and any preventative measures adopted to prevent recurrence of the occurrence;
(v) Records of any instances in which a recording device installed to record data from the enclosed combustor, utility flare, or pit flare is not operational; and
(vi) Records of any time periods in which visible smoke emissions are observed emanating from the enclosed combustor, utility flare, or pit flare.
(6) For each pit flare at an oil and natural gas production facility, a demonstration of compliance with the use restrictions set forth in § 49.4165(d)(2)(ii) is made by keeping records in a log book, or similar recording system, during each period of time that the pit flare is operating. The records must contain the following information:
(i) Date and time the pit flare was started up and subsequently shut down;
(ii) Total hours operated when pipeline injection was temporarily infeasible for the current calendar month plus the previous consecutive eleven (11) calendar months; and
(iii) Brief descriptions of the justification for each period of operation.
(7) Records of any instances in which any closed-vent system or control device was bypassed or down, the reason for each incident, its duration, the volume of natural gas emissions released, and the corrective actions taken and any preventative measures adopted to avoid such bypasses or downtimes; and
(8) Documentation of all produced oil storage tank and produced water storage tank inspections required in § 49.4166(e) and (f). All inspection records must include, at a minimum, the following information:
(i) The date of the inspection;
(ii) The findings of the inspection;
(iii) Any adjustments or repairs made as a result of the inspections, and the date of the adjustment or repair; and
(iv) The inspector's name and signature.
(b) Each owner or operator must keep all records required by this section onsite at the facility or at the location that has day-to-day operational control over the facility and must make the records available to the EPA upon request.
(c) Each owner or operator must retain all records required by this section for a period of at least five (5) years from the date the record was created.
§ 49.4168   Notification and reporting requirements.
(a) Each owner or operator must submit any documents required under this section to: U.S. Environmental Protection Agency, Region 8 Office of Enforcement, Compliance & Environmental Justice, Air Toxics and Technical Enforcement Program, 8ENF-AT, 1595 Wynkoop Street, Denver, Colorado 80202. Documents may be submitted electronically to r8airreportenforcement@epa.gov.
(b) Each owner and operator must submit an annual report containing the information specified in paragraphs (b)(1) through (4) of this section. Each annual report is due August 15th every year and must cover all information for the previous calendar year. The initial report must cover the cumulative information for that year. If you own or operate more than one oil and natural gas production facility, you may submit one report for multiple oil and natural gas production facilities provided the report contains all of the information required as specified in paragraphs (b)(1) through (4) of this section. Annual reports may coincide with title V reports as long as all the required elements of the annual report are included. The EPA may approve a common schedule on which reports required by §§ 49.4161 through 49.4168 may be submitted as long as the schedule does not extend the reporting period.
(1) The company name and the address of the oil and natural gas production facility or facilities.
(2) An identification of each oil and natural gas production facility being included in the annual report.
(3) The beginning and ending dates of the reporting period.
(4) For each oil and natural gas production facility, the information in paragraphs (b)(4)(i) through (iv) of this section.
(i) A summary of all required records identifying each oil and natural gas well completion or recompletion operation for each oil and natural gas production facility conducted during the reporting period;
(ii) An identification of the first date of production for each oil and natural gas well at each oil and natural gas production facility that commenced production during the reporting period; and
(iii) A summary of cases where construction or operation was not performed in compliance with the requirements specified in § 49.4164, § 49.4165, or § 49.4166 for each oil and natural gas well at each oil and natural gas production facility, and the corrective measures taken.
(iv) A certification by a responsible official of truth, accuracy and completeness. This certification shall state that, based on information and belief formed after reasonable inquiry, the statements and information in the document are true, accurate and complete.
§ 49.4169   Introduction.
(a) What is the purpose of §§ 49.4169 through 49.4184? Sections 49.4169 through 49.4184 establish legally and practicably enforceable requirements for oil and natural gas sources on Indian country lands within the Uintah and Ouray Indian Reservation (U&O Reservation) to address ozone air quality. Section 49.4170 establishes provisions for delegation of authority to allow the Ute Indian Tribe to assist the EPA with administration of this Federal Implementation Plan (U&O FIP). Section 49.4171 contains general provisions and definitions applicable to oil and natural gas sources. Sections 49.4173 through 49.4184 establish legally and practicably enforceable requirements to control and reduce VOC emissions from oil and natural gas well production and storage operations, natural gas processing, and gathering and boosting operations at oil and natural gas sources that are located on Indian country lands within the U&O Reservation.
(b) Am I subject to §§ 49.4169 through 49.4184? Sections 49.4169 through 49.4184, as appropriate, apply to each owner or operator of an oil and natural gas source (as defined at 40 CFR 49.102) located on Indian country lands within the U&O Reservation that has equipment or activities that meet the applicability thresholds specified in each section. Generally, the equipment and activities at oil and natural gas sources that are already subject to and in compliance with VOC emission control requirements under another EPA standard or other federally enforceable requirement, as specified in each appropriate subsection later, are considered to be in compliance with the requirements to control VOC emissions from that same equipment under this U&O FIP.
(c) When must I comply with §§ 49.4169 through 49.4184? For oil and natural gas sources that commence construction before February 6, 2023, compliance with §§ 49.4169 through 49.4171 and §§ 49.4173 through 49.4184, as applicable, is required no later than February 6, 2024. You may submit a written request to the EPA for an extension of the compliance date for existing sources. The extension request must be submitted to the EPA at least 60 days before the compliance deadline, must identify the specific provision(s) for which you seek an extension, must include an alternative compliance deadline(s), and must provide the rationale for the requested extension with supporting information explaining how you will effectively meet all applicable requirements after the requested alternative compliance deadline. Any decision to approve or deny a request, including the length of time of an approved request, will be based on the merits of case-specific circumstances. For oil and natural gas sources that commence construction on or after February 6, 2023, compliance with §§ 49.4169 through 49.4171 and §§ 49.4173 through 49.4184, as applicable, is required upon startup.
§ 49.4170   Delegation of authority of administration to the Tribe.
(a) What is the purpose of this section? The purpose of this section is to establish the process by which the Regional Administrator may delegate to the Ute Indian Tribe the authority to assist the EPA with administration of this U&O FIP. This section provides for administrative delegation and does not affect the eligibility criteria under § 49.6 for treatment in the same manner as a state.
(b) How does the Ute Indian Tribe request delegation? To be delegated authority to assist the EPA with administration of this U&O FIP, the authorized representative of the Ute Indian Tribe must submit a written request to the Regional Administrator that:
(1) Identifies the specific provisions for which delegation is requested;
(2) Includes a statement by the Ute Indian Tribe's legal counsel (or equivalent official) with the following information:
(i) A statement that the Ute Indian Tribe is an Indian tribe recognized by the Secretary of the Interior;
(ii) A descriptive statement that meets the requirements of § 49.7(a)(2) and demonstrates that the Ute Indian Tribe is currently carrying out substantial governmental duties and powers over a defined area;
(iii) A description of the laws of the Ute Indian Tribe that provide adequate authority to carry out the aspects of the rule for which delegation is requested; and
(3) Demonstrates that the Ute Indian Tribe has, or will have, adequate resources to carry out the aspects of the rule for which delegation is requested.
(c) How is the delegation of administration accomplished? (1) A Delegation of Authority Agreement setting forth the terms and conditions of the delegation and specifying the provisions of this rule that the Ute Indian Tribe will be authorized to implement on behalf of the EPA will be entered into by the Regional Administrator and the Ute Indian Tribe. The Agreement will become effective on the date that both the Regional Administrator and the authorized representative of the Ute Indian Tribe have signed the Agreement. Once the delegation becomes effective, the Ute Indian Tribe will be responsible, to the extent specified in the Agreement, for assisting the EPA with administration of the FIP and will act as the Regional Administrator as that term is used in these regulations. Any Delegation of Authority Agreement will clarify the circumstances in which the term “Regional Administrator” found throughout the FIP is to remain the EPA Regional Administrator and when it is intended to refer to the “Ute Indian Tribe,” instead.
(2) A Delegation of Authority Agreement may be modified, amended, or revoked, in part or in whole, by the Regional Administrator after consultation with the Ute Indian Tribe.
(d) How will any Delegation of Authority Agreement be publicized? The Agency will publish a document in the Federal Register informing the public of any Delegation of Authority Agreement with the Ute Indian Tribe to assist the EPA with administration of all or a portion of the FIP and identifying such delegation in the FIP. The EPA will also publish an announcement of the Delegation of Authority Agreement in local newspapers.
§ 49.4171   General provisions.
(a) At all times, including periods of startup, shutdown, and malfunction, each owner or operator must, to the extent practicable, design, operate, and maintain all equipment used for crude oil, condensate, intermediate hydrocarbon liquid, or produced water, and gas collection, storage, processing, and handling operations covered under §§ 49.4171 and 49.4173 through 49.4184, regardless of emissions rate and including associated air pollution control equipment, in a manner that is consistent with good air pollution control practices and that minimizes leakage of VOC emissions to the atmosphere. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Administrator, including monitoring results, review of operating and maintenance procedures, and inspection of the source.
(b) Definitions. As used in §§ 49.4169 through 49.4184, all terms not defined have the meaning given them in the Act, in 40 CFR parts 60 and 63, in the Prevention of Significant Deterioration regulations at 40 CFR 52.21, in the Federal Minor New Source Review Program in Indian Country at § 49.151, or in the Federal Implementation Plan for Managing Air Emissions from True Minor Sources in Indian Country in the Oil and Natural Gas Production and Natural Gas Processing Segments of the Oil and Natural Gas Sector at § 49.102. The following terms are defined here:
Bottom filling means the filling of a storage vessel through an inlet at or near the bottom of the storage vessel designed to have the opening covered by the liquid after the pipe normally used to withdraw liquid can no longer withdraw any liquid.
Condensate means hydrocarbon liquid separated from produced natural gas that condenses due to changes in temperature, pressure, or both, and that remains liquid at standard conditions.
Crude oil means hydrocarbon liquids that are separated from well-extracted reservoir fluids during oil and natural gas production operations, and that are stored or injected to pipelines as a saleable product. Condensate is not considered crude oil.
Electronically controlled automatic ignition device means an electronic device which generates sparks across an electrode and reaches into a combustible gas stream traveling up a flare stack or entering an enclosed combustor, at the point of the pilot tip, equipped with a temperature monitor that signals the device to attempt to re-light an extinguished pilot flame.
Enclosed combustor means a thermal oxidation system with an enclosed combustion chamber that maintains a limited constant temperature by controlling fuel and combustion air.
Flare means a thermal oxidation system using an open (without enclosure) flame that is designed and operated in accordance with the requirements of 40 CFR 60.18(b). An enclosed combustor is not considered a flare. A combustion device is not considered a flare when installed horizontally or vertically within an open pit and used to combust produced natural gas during initial well completion or temporarily during emergencies when enclosed combustors or flares installed at a source are not operational or injection of recovered produced natural gas is unavailable.
Flashing losses means natural gas emissions resulting from the presence of dissolved natural gas in the crude oil, condensate, intermediate hydrocarbon liquids or produced water, which are under high pressure that occurs as the liquids are transferred to storage vessels that are at atmospheric pressure.
Fugitive emissions component means any component that has the potential to emit fugitive emissions of VOC at an oil and natural gas source, such as valves, connectors, pressure relief devices, open-ended lines, flanges, covers and closed vent systems not subject to § 49.4176, thief hatches or other openings on a controlled storage vessel not subject to § 49.4173, compressors, instruments, and meters. Devices that vent as part of normal operations, such as natural gas-driven pneumatic controllers or natural gas-driven pneumatic pumps, are not fugitive emissions components, insofar as the natural gas discharged from the device's vent is not considered a fugitive emission. Emissions originating from locations other than the device's vent, such as the thief hatch on a controlled storage vessel, would be considered fugitive emissions.
Glycol dehydration unit process vent emissions means VOC-containing emissions from the glycol dehydration unit regenerator or still vent and the vent from the dehydration unit flash tank (if present).
Indian country is defined at 18 U.S.C. 1151 and means.
(i) All land within the limits of any Indian reservation under the jurisdiction of the United States Government, notwithstanding the issuance of any patent, and, including rights-of-way running through the reservation,
(ii) All dependent Indian communities within the borders of the United States whether within the original or subsequently acquired territory thereof, and whether within or without the limits of a state, and
(iii) All Indian allotments, the Indian titles to which have not been extinguished, including rights-of-way running through the same.
Intermediate hydrocarbon liquids means any naturally occurring, unrefined petroleum liquid.
Malfunction alarm and remote notification system means a system connected to an electronically controlled automatic ignition device that sends an alarm through a remote notification system to an owner or operator's central control center, if an attempt to relight the pilot flame is unsuccessful.
Pneumatic controller means a natural gas-driven pneumatic controller as defined at 40 CFR 60.5430 and 60.5430a.
Pneumatic pump means a natural gas-driven diaphragm pump as defined at 40 CFR 60.5430a.
Pneumatic pump emissions means the VOC-containing emissions from pneumatic pumps.
Produced natural gas means natural gas that is separated from extracted reservoir fluids during oil and natural gas production operations.
Produced water means water that is extracted from the earth from an oil or natural gas production well, or that is separated from crude oil, condensate, or natural gas after extraction.
Regional Administrator means the Regional Administrator of EPA Region 8 or an authorized representative of the Regional Administrator of EPA Region 8, except to the extent otherwise specifically specified in a Delegation of Authority Agreement between the Regional Administrator and the Ute Indian Tribe.
Repaired means, for the purposes of fugitive emissions components, that fugitive emissions components are adjusted, replaced, or otherwise altered in order to eliminate fugitive emissions as defined in § 49.4178(d)(1)(iii), and subsequently monitored as specified in § 49.4178(d)(1)(ii), and that it is verified that emissions from the fugitive emissions components are below the applicable fugitive emissions definition.
Standing and breathing losses means VOC emissions from fixed-roof storage vessels as a result of evaporative losses during storage.
Storage vessel means a tank or other vessel that contains an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water, and that is constructed primarily of non-earthen materials (such as wood, concrete, steel, fiberglass, or plastic), which provide structural support. A well completion vessel that receives recovered liquids from a well after startup of production following flowback for a period which exceeds 60 days is considered a storage vessel under this subpart. A tank or other vessel will not be considered a storage vessel if it has been removed from service in accordance with the requirements of § 49.4173(a)(3), until that tank or other vessel has been returned to service. For the purposes of this subpart, the following are not considered storage vessels:
(i) Vessels that are skid-mounted or permanently attached to something that is mobile (such as trucks, railcars, barges or ships), and are intended to be located at a site for less than 180 consecutive days. If you do not keep or are not able to produce records, as required by § 49.4183(a)(1)(iv), showing that the vessel has been located at a site for less than 180 consecutive days, the vessel is considered to be a storage vessel from the date it was first located at the site. This exclusion does not apply to a well completion vessel as described above.
(ii) Process vessels such as surge control vessels, bottoms receivers, and knockout vessels.
(iii) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere.
Submerged fill pipe means any fill pipe with a discharge opening that is entirely submerged when the liquid level is six inches above the bottom of the storage vessel and the pipe normally used to withdraw liquid from the storage vessel can no longer withdraw any liquid.
Supervisory Control and Data Acquisition (SCADA) system generally refers to industrial control computer systems that monitor and control industrial infrastructure or source-based processes.
Unsafe to repair means (in the context of fugitive emissions monitoring) that operator personnel would be exposed to an imminent or potential danger as a consequence of the attempt to repair the leak during normal operation of the source.
Visible smoke emissions means air pollution generated by thermal oxidation in a flare or enclosed combustor and occurring immediately downstream of the flame present in those units. Visible smoke occurring within, but not downstream of, the flame, does not constitute visible smoke emissions.
Working losses means natural gas emissions from fixed roof storage vessels resulting from evaporative losses during filling and emptying operations.
§ 49.4172   Emissions inventory.
(a) Applicability. The emissions inventory requirements of this section apply to each oil and natural gas source, as identified in § 49.4169(b), that has actual emissions of any pollutant identified in paragraph (c) of this section greater than or equal to one ton in any consecutive 12-month period.
(b) Each oil and natural gas source must submit an inventory for every third year, beginning with the 2023 calendar year, for all emission units at a source.
(c) The inventory must include the total emissions for PM 10 , PM 2.5 , oxides of sulfur, nitrogen oxides, carbon monoxide, and volatile organic compounds, as defined at 40 CFR 51.50, for each emissions unit at the source. Emissions for each emissions unit at the source must be calculated using the emissions unit's actual operating hours, appropriate emissions rates, the use of performance test results where applicable, product rates and types of materials processed, stored, or combusted during the calendar year of the reporting period.
(d) The inventory must include the type and efficiency, for each pollutant controlled, of any air pollution control equipment present at the reporting source. The detail of the emissions inventory must be consistent with the detail and data elements required by 40 CFR part 51, subpart A.
(e) The inventory must be submitted to the EPA no later than April 15th of the year following each inventory year.
(f) The inventory must be submitted in an electronic format specific to this source category, as instructed on the EPA Region 8 website at https://www.epa.gov/air-quality-implementation-plans/approved-air-quality-implementation-plans-region-8.
§ 49.4173   VOC emissions control requirements for storage vessels.
(a) Applicability. The VOC emissions control requirements of this section apply to storage vessels at an oil and natural gas source (as specified in § 49.4169(b)) as follows:
(1) For oil and natural gas sources that began operations before February 6, 2023, the VOC emissions control requirements of this section apply when the source-wide potential for VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps is equal to or greater than 4 tpy, as determined according to this section. The potential for VOC emissions must be calculated using a generally accepted model or calculation methodology, based on the maximum average daily throughput determined for a 30-day period of production during the 12 months before the compliance deadline for the affected source under this rule. The determination may take into account requirements under a legally and practicably enforceable limit in an operating permit or other federally enforceable requirement. You must reevaluate the source-wide VOC emissions from the collection of all storage vessels, glycol dehydrators and pneumatic pumps for each modification to an existing source; or
(2) For oil and natural gas sources that began operations on or after February 6, 2023, the VOC emissions control requirements of this section apply upon startup of operation.
(3) Modification to an oil and natural gas source requires a re-evaluation of the source-wide VOC emissions from the collection of all storage vessels, glycol dehydrators and pneumatic pumps. Adding production from a new well or increasing production at an existing well is considered a modification of a well site. Increasing maximum throughput at a tank battery, compressor station or natural gas processing plant is considered a modification.
(b) Exemptions. (1) This section does not apply to storage vessels located at an oil and natural gas source that are subject to the emissions control requirements for storage vessels in 40 CFR part 60, subparts OOOO or OOOOa, or 40 CFR part 63, subpart HH.
(2) This section does not apply to an emergency storage vessel located at an oil and natural gas source, if it meets the following requirements:
(i) The emergency storage vessel is not used as an active storage vessel;
(ii) The owner or operator empties the emergency storage vessel no later than 15 days after receiving fluids;
(iii) The emergency storage vessel is equipped with a liquid level gauge or equivalent device; and
(iv) Records are kept of the usage of each emergency storage vessel as required in § 49.4183(a)(3), including the date the vessel received fluids, the volume of fluids received in barrels, the date the vessel was emptied, and the volume of fluids emptied in barrels.
(3) This section does not apply to storage vessels that are removed from service. If you remove a storage vessel from service, you must comply with paragraphs (b)(3)(i) through (iii) of this section.
(i) For a storage vessel to be removed from service, you must comply with the requirements of paragraphs (b)(3)(i)(A) and (B) of this section.
(A) You must completely empty and degas the storage vessel, such that the storage vessel no longer contains crude oil, condensate, intermediate hydrocarbon liquids or produced water. A storage vessel where liquid is left on walls, as bottom clingage, or in pools due to floor irregularity is considered to be completely empty.
(B) You must keep records as required in § 49.4183(a)(4), identifying each storage vessel removed from service and the date of its removal from service.
(ii) If a storage vessel identified in paragraph (b)(3)(i)(B) of this section is returned to service, you must determine its applicability as provided in paragraph (a) of this section, and you must keep records as required in § 49.4183(a)(4), identifying the storage vessel and the date of its return to service.
(c) VOC emission control requirements. For each storage vessel, you must comply with the VOC emissions control requirements of paragraph (c)(1) or (c)(2) of this section.
(1) You must reduce VOC emissions from each storage vessel by at least 95.0 percent on a continuous basis according to paragraph (c)(1)(i) or (ii) of this section. You must equip each storage vessel with a cover that meets the conditions specified in § 49.4176(c), and must route all flashing, working, standing and breathing losses from the storage vessels through a closed-vent system that meets the conditions specified in § 49.4176(d) to:
(i) An operating system designed to recover 100 percent of the emissions and recycle them for use in a process unit or incorporate them into a product; or
(ii) An enclosed combustor or flare that is designed to reduce the mass content of VOC in the natural gas emissions vented to the device by at least 95.0 percent and that is operated as specified in § 49.4177;
(2) You must maintain the source-wide uncontrolled actual VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps at an oil and natural gas source at less than 4 tpy. Before using the uncontrolled actual VOC emission rate for compliance purposes, you must demonstrate that the uncontrolled actual VOC emissions have remained at less than 4 tpy, as determined monthly for 12 consecutive months. After such demonstration, you must determine the uncontrolled actual VOC emission rate each month. The uncontrolled actual VOC emissions must be calculated using a generally accepted model or calculation methodology. Monthly calculations must be based on the average throughput of the source for the month. Monthly calculations must be separated by at least 14 days. You must comply with paragraph (c)(1) of this section within 30 days of the monthly emissions determination required in this section if the determination indicates that VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps at your oil and natural gas source increased to 4 tpy or greater.
(3) Except as provided in paragraph (c)(4) of this section, if you use a control device to reduce emissions from your storage vessels, you must equip each storage vessel with a cover that meets the requirements of § 49.4176(c).
(4) If you use a floating roof to reduce emissions, you must meet the requirements of § 60.112b(a)(1) or (2) and the relevant monitoring, inspection, recordkeeping, and reporting requirements in 40 CFR part 60, subpart Kb.
(5) After a minimum of 12 consecutive months of operation at a source that begins operation on or after February 6, 2023, controls may be removed if the source-wide uncontrolled actual VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps has been maintained at a rate less than 4 tpy, as determined according to paragraph (c)(2) of this section.
§ 49.4174   VOC emissions control requirements for dehydrators.
(a) Applicability. The VOC emissions control requirements of this section apply to each glycol dehydration unit located at an oil and natural gas source as identified in § 49.4169(b) where the source-wide potential for VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps is equal to or greater than 4 tpy, as determined according to § 49.4173. You must reevaluate the source-wide VOC emissions from the collection of all storage vessels, glycol dehydrators and pneumatic pumps for each modification to an existing source, as described in § 49.4173(a)(3). Applicability for glycol dehydrators that began operation before February 6, 2023 must be determined using uncontrolled actual emissions. Applicability for glycol dehydrators that began operation on or after February 6, 2023 must be determined using potential to emit.
(b) Exemptions. This section does not apply to glycol dehydration units subject to the emissions control requirements for glycol dehydration unit process vents in 40 CFR part 63, subpart HH.
(c) VOC emissions control requirements. For each glycol dehydration unit, you must comply with the VOC emissions control requirements of paragraphs (c)(1) or (2) of this section.
(1) You must reduce VOC emissions from each glycol dehydration unit process vent by at least 95.0 percent on a continuous basis according to paragraphs (c)(1)(i) and (ii) of this section. You must route all glycol dehydration unit process vent emissions through a closed-vent system that meets the conditions specified in § 49.4176(d) to:
(i) An operating system designed to recover 100 percent of the emissions and recycle them for use in a process unit or incorporate them into a product; or
(ii) An enclosed combustor or flare designed to reduce the mass content of VOC in the emissions vented to the device by at least 95.0 percent and operated as specified in § 49.4177; or
(2) You must maintain the source-wide uncontrolled actual VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps at an oil and natural gas source at less than 4 tpy for 12 consecutive months in accordance with the procedures specified in § 49.4173(c)(2).
§ 49.4175   VOC emissions control requirements for pneumatic pumps.
(a) Applicability. The requirements of this section apply to each pneumatic pump located at an oil and natural gas source as identified in § 49.4169(b) where the source-wide potential for VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps is equal to or greater than 4 tpy, as determined according to § 49.4173. You must reevaluate the source-wide VOC emissions from the collection of all storage vessels, glycol dehydrators and pneumatic pumps for each modification to an existing source, as described in § 49.4173(a)(3). Applicability for pneumatic pumps that began operation before February 6, 2023 must be determined using uncontrolled actual emissions. Applicability for pneumatic pumps that began operation on or after February 6, 2023 must be determined using potential to emit.
(b) Exemptions. This section does not apply to pneumatic pumps subject to the emissions control requirements for pneumatic pumps in 40 CFR part 60, subpart OOOOa.
(c) VOC Emission Control Requirements. For each pneumatic pump, you must comply with the VOC emissions control requirements of paragraph (c)(1) or (2) of this section.
(1) You must reduce VOC emissions from each pneumatic pump by at least 95.0 percent on a continuous basis according to paragraph (c)(1)(i) or (ii) of this section. You must route all pneumatic pump emissions through a closed-vent system that meets the conditions specified in § 49.4176(d) to:
(i) An operating system designed to recover 100 percent of the emissions and recycle them for use in a process unit or incorporate them into a product; or
(ii) An enclosed combustor or flare designed to reduce the mass content of VOC in the emissions vented to the device by at least 95.0 percent and operated as specified in § 49.4177; or
(2) You must maintain the source-wide uncontrolled actual VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps at an oil and natural gas source at less than 4 tpy for any 12 consecutive months in accordance with the procedures specified in § 49.4173(c)(2).
§ 49.4176   VOC emissions control requirements for covers and closed-vent systems.
(a) Applicability. The VOC emissions control requirements in this section apply to each cover on a storage vessel that is subject to § 49.4173, and to each closed-vent system that is used to convey VOC emissions from the collection of all storage vessels, glycol dehydration units, or pneumatic pumps (to a vapor recovery system or control device) that are subject to §§ 49.4173 through 49.4175.
(b) Exemptions. This section does not apply to covers and closed-vent systems that are subject to the requirements for covers and closed-vent systems in 40 CFR part 60, subparts OOOO or OOOOa, or 40 CFR part 63, subpart HH.
(c) Covers. Each owner or operator must equip all openings on each storage vessel with a cover to ensure that all flashing, working, standing and breathing loss emissions are routed through a closed-vent system to a vapor recovery system, an enclosed combustor, or a flare.
(1) Each cover and all openings on the cover (e.g., access hatches, sampling ports, pressure relief valves (PRV), and gauge wells) must form a continuous impermeable barrier over the entire surface area of the crude oil, condensate, intermediate hydrocarbon liquids, or produced water in the storage vessel.
(2) Each cover opening must be secured in a closed, sealed position (e.g., covered by a gasketed lid or cap) whenever material is in the unit on which the cover is installed except when it is necessary to use an opening as follows:
(i) To add fluids to, or remove fluids from the unit (this includes openings necessary to equalize or balance the internal pressure of the unit following changes in the level of the material in the unit);
(ii) To inspect or sample the fluids in the unit; or
(iii) To inspect, maintain, repair, or replace equipment located inside the unit.
(3) Each thief hatch cover must be weighted and properly seated to ensure that flashing, working, standing, and breathing loss emissions are routed through the closed-vent system to the vapor recovery system, the enclosed combustor, or the flare under normal operating conditions.
(4) Each PRV must be set to release at a pressure that will ensure that flashing, working, standing, and breathing loss emissions are routed through the closed-vent system to the vapor recovery system, the enclosed combustor, or the flare under normal operating conditions.
(d) Closed-vent systems. Each owner or operator must meet the following requirements for closed-vent systems:
(1) Each closed-vent system must route all captured storage vessel emissions from flashing, working, standing, and breathing losses; glycol dehydration unit process vent emissions; and pneumatic pump emissions from the oil and natural gas source to a gathering pipeline system for sale, use in a process unit, incorporation into a product, or other beneficial purpose, or to a VOC emission control device, as specified in §§ 49.4173 through 49.4175.
(2) All vent lines, connections, fittings, valves, relief valves, and any other appurtenances employed to collect or contain captured storage vessel emissions from flashing, working, standing, and breathing losses; glycol dehydration unit process vent emissions; or pneumatic pump emissions; or to transport such emissions to a gathering pipeline system for sale, use in a process unit, incorporation into a product, or other beneficial purpose, or to a VOC emission control device, as specified in §§ 49.4173 through 49.4175, must be maintained and operated properly at all times.
(3) Each closed-vent system must be designed to operate with no detectable emissions, as demonstrated by the closed-vent system monitoring requirements in § 49.4182(c).
(4) If any closed-vent system contains one or more bypass devices that could be used to divert all or a portion of the captured storage vessel flashing, working, standing, and breathing losses; glycol dehydration unit process vent emissions; or pneumatic pump emissions from entering a gathering pipeline system for sale, use in a process unit, incorporation into a product, or other beneficial purpose, or from being transferred to the VOC emissions control device, the owner or operator must meet one of the requirements in paragraphs (d)(4)(i) or (ii) of this section for each bypass device. Low leg drains, high point bleeds, analyzer vents, open-ended valves or lines, and safety devices are not subject to the requirements applicable to bypass devices.
(i) At the inlet to a bypass device the owner or operator must properly install, calibrate, maintain, and operate a flow indicator that is capable of taking continuous readings and sounding an alarm when the bypass device is open such that emissions are being, or could be, diverted away from a gathering pipeline system for sale, use in a process unit, incorporation into a product, or other beneficial purpose, or the VOC emission control device and into the atmosphere; or
(ii) The owner or operator must secure the bypass device valve installed at the inlet to the bypass device in the non-diverting position using a car-seal or a lock-and-key type configuration.
§ 49.4177   VOC emissions control devices.
(a) Applicability. The requirements in this section apply to all flares and enclosed combustors used to control VOC emissions at an oil and natural gas source, as identified in § 49.4169(b), in order to meet the requirements specified in §§ 49.4173 through 49.4176, as applicable.
(b) Exemptions. This section does not apply to VOC emission control devices that are subject to the requirements for control devices used to comply with the emissions standards in 40 CFR part 60, subparts OOOO or OOOOa; or 40 CFR part 63, subpart HH.
(c) Enclosed combustors and flares. Each owner or operator must meet the following requirements for enclosed combustors and flares:
(1) For each enclosed combustor or flare, the owner or operator must follow the manufacturer's written operating instructions, procedures, and maintenance schedule to ensure good air pollution control practices for minimizing emissions;
(2) The owner or operator must ensure that each enclosed combustor or flare is designed to have sufficient capacity to reduce the mass content of VOC in the captured emissions routed to it by at least 95.0 percent for the minimum and maximum natural gas volumetric flow rate and BTU content routed to the device;
(3) Each enclosed combustor or flare must be operated to reduce the mass content of VOC in the captured emissions routed to it by continuously meeting at least 95.0 percent VOC control efficiency;
(4) The owner or operator must ensure that each flare is designed and operated in accordance with the requirements of 40 CFR 60.18(b) for such flares;
(5) The owner or operator must ensure that each enclosed combustor is:
(i) A model that is:
(A) Demonstrated by a manufacturer to meet the VOC control efficiency requirements of §§ 49.4173 through 49.4176 using EPA-approved performance test procedures specified in 40 CFR 60.5413; or
(B) Demonstrated by the owner or operator to meet the VOC control efficiency requirements of §§ 49.4173 through 49.4176 according to the procedures and schedule specified in § 49.4182(d)(1);
(ii) Operated properly at all times that captured emissions are routed to it;
(iii) Operated with a liquid knock-out system to collect any condensable vapors (to prevent liquids from going through the control device);
(iv) Equipped and operated with a flash-back flame arrestor;
(v) Equipped and operated with one of the following:
(A) A continuous burning pilot; or
(B) An operational electronically controlled automatic ignition device;
(vi) Equipped with a monitoring system for continuous measuring and recording of the parameters that indicate proper operation of each enclosed combustor or flare, including each continuous burning pilot flame or electronically controlled automatic ignition device, to monitor and document proper operation of the enclosed combustor or flare. Examples of such continuous monitoring systems may include a thermocouple and a chart recorder, data logger or similar device, or connection to a SCADA system;
(vii) Maintained in a leak-free condition; and
(viii) Operated with no visible smoke emissions.
(d) Other control devices. Upon prior written approval by the EPA, the owner or operator may use control devices other than those listed above that are determined by the EPA to be capable of reducing the mass content of VOC in the natural gas routed to it by at least 95.0 percent, provided that:
(1) In operating such control devices, the owner or operator must follow the manufacturer's written operating instructions, procedures and maintenance schedule to ensure good air pollution control practices for minimizing emissions; and
(2) The owner or operator must ensure there is sufficient capacity to reduce the mass content of VOC in the produced natural gas and natural gas emissions routed to such other control devices by at least 95.0 percent for the minimum and maximum natural gas volumetric flow rate and BTU content routed to each device.
(3) The owner or operator must operate such a control device to reduce the mass content of VOC in the produced natural gas and natural gas emissions routed to it by at least 95.0 percent.
§ 49.4178   VOC emissions control requirements for fugitive emissions.
(a) Applicability. The requirements of this section apply to all owners or operators of the collection of fugitive emissions components, as defined in § 49.4171, located at any oil and natural gas source, as identified in § 49.4169(b), except that this section does not apply to owners or operators of the collection of fugitive emissions components at an oil and natural gas source that is subject to the fugitive emissions monitoring requirements in 40 CFR part 60, subpart OOOOa.
(b) Owners or operators of the collection of fugitive emissions components must comply with paragraph (d) of this section if either of the following is true:
(1) The collection of fugitive emissions components is located at an oil and natural gas source that is required to control VOC emissions according to §§ 49.4173 through 49.4177 of this section ( i.e., the source-wide potential for VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps is equal to or greater than 4 tpy, as determined according to § 49.4173(a)(1)); or
(2) The collection of fugitive emissions components is located at a well site, as defined in 40 CFR 60.5430a, that at any time has total production greater than 15 barrels of oil equivalent (boe) per day based on a rolling 12-month average.
(c) Owners or operators of the collection of fugitive emissions components for which neither (b)(1) nor (b)(2) is true must comply with either paragraph (c)(1) or paragraph (c)(2) of this section.
(1) You must monitor all fugitive emissions components and repair all sources of fugitive emissions in accordance with paragraph (d) of this section. You must keep records in accordance with § 49.4183 and report in accordance with § 49.4184; or
(2) You must maintain the total production for the well site at or below 15 boe per day based on a rolling 12-month average. You must demonstrate that the total daily oil and natural gas production from the collection of all wells producing to the well site is at or below 15 boe per day, based on a 12-month rolling average, according to the procedures in paragraph (e) of this section. You must maintain records as specified in § 49.4183(a)(11).
(d) Monitoring requirements. (1) Each owner or operator must develop and implement a fugitive emissions monitoring plan to reduce emissions from fugitive emissions components at all of their oil and natural gas sources on Indian country lands within the U&O Reservation. This Reservation-wide monitoring plan must include the following elements, at a minimum:
(i) A requirement to perform an initial monitoring of the collection of fugitive emissions components at each oil and natural gas source by February 6, 2024;
(ii) A requirement to perform subsequent monitoring of the collection of fugitive emissions components at each oil and natural gas source once every 6 months after the initial monitoring survey, with consecutive monitoring surveys conducted at least 4 months apart and no more than 7 months apart.
(iii) A description of the technique used to identify leaking fugitive emission components, which must be limited to:
(A) Onsite EPA Reference Method 21, 40 CFR part 60, appendix A, where an analyzer reading of 500 parts per million volume (ppmv) VOC or greater is considered a leak in need of repair;
(B) Onsite optical gas imaging instruments, as defined in 40 CFR 60.18(g)(4), where any visible emissions are considered a leak in need of repair, unless the owner or operator evaluates the leak with an analyzer meeting EPA Reference Method 21 at 40 CFR part 60, appendix A, and the concentration is less than 500 ppmv. The optical gas imaging instrument must be capable of meeting the optical gas imaging equipment requirements specified in 40 CFR part 60, subpart OOOOa; or
(C) Another method approved by the Administrator to demonstrate compliance with the fugitive emissions monitoring requirements. To be approved, you must demonstrate that the alternative method achieves emissions reductions that equal or exceed those that would result from the application of either Method 21 or optical gas imaging instruments. Approval of an alternative method will be subject to public notice and comment.
(iv) The manufacturer and model number of any fugitive emissions monitoring device to be used;
(v) Procedures and timeframes for identifying and repairing components from which leaks are detected, including:
(A) A requirement to repair any leaks identified from components that are safe to repair and do not require source shutdown as soon as practicable, but no later than 30 calendar days after discovering the leak;
(B) Timeframes for inspecting and repairing leaking components that are difficult-to-monitor, unsafe-to-monitor, or require source shutdown, to be no later than the next required monitoring event, as noted in paragraphs (c)(1)(v)(B)( 1 ) through ( 3 ) of this section:
( 1 ) If using Method 21, fugitive emissions components that cannot be monitored without elevating the monitoring personnel more than 2 meters above the surface may be designated as difficult-to-monitor and must meet the specifications in paragraphs (c)(1)(v)(B)( 1 ) (i) through (iv) of this section:
(i) For all fugitive emissions components designated difficult-to-monitor, a written plan must be developed and incorporated into the fugitive emissions monitoring plan.
(ii) The plan must include the identification and location of each fugitive emissions component designated difficult-to-monitor.
(iii) The plan must include an explanation of why each fugitive emissions component designated as difficult-to-monitor is difficult-to-monitor.
(iv) The plan must include a schedule for monitoring the difficult-to-monitor fugitive emissions components at least once per calendar year and a schedule for repairing such fugitive emissions components according to paragraph (c)(1)(v)(B)( 3 ) of this section;
( 2 ) Fugitive emissions components that cannot be monitored because monitoring personnel would be exposed to an immediate danger while conducting a monitoring survey may be designated as unsafe-to-monitor and must meet the specification in paragraphs (c)(1)(v)(B)( 2 ) (i) through (iv) of this section:
(i) A written plan must be developed for all of the fugitive emissions components designated unsafe-to-monitor and incorporated into the fugitive emissions monitoring plan;
(ii) The plan must include the identification and location of each fugitive emissions component designated unsafe-to-monitor.
(iii) The plan must include an explanation of why each fugitive emissions component designated as unsafe-to-monitor is unsafe-to-monitor.
(iv) The plan must include a schedule for monitoring the unsafe-to-monitor fugitive emissions components as frequently as practicable during safe to inspect times and for repairing such fugitive emissions components according to paragraph (c)(1)(v)(B)( 3 ) of this section;
( 3 ) If the repair or replacement of a fugitive emissions component designated difficult-to-monitor or unsafe-to-monitor is technically infeasible; would require a vent blowdown, a compressor station shutdown, a well shutdown, or well shut-in; or would be unsafe to repair during operation of the unit, the repair or replacement must be completed during the next scheduled compressor station shutdown, well shutdown, or well shut-in; after a planned vent blowdown; or within 2 years, whichever is earlier; and
(C) Procedures for verifying leaking component repairs, no more than 30 calendar days after repairing the leak;
(vi) Training and experience needed before performing surveys;
(vii) Procedures for calibration and maintenance of any fugitive emissions monitoring device to be used; and
(viii) Standard monitoring protocols for each type of typical oil and natural gas source (e.g., well site, tank battery, compressor station), including a general list of component types that will be inspected and what supporting data will be recorded (e.g., wind speed, detection method device-specific operational parameters, date, time, and duration of inspection).
(2) The owner or operator is exempt from inspecting and repairing a fugitive emissions component under any of the following circumstances:
(i) The contacting process stream only contains glycol, amine, methanol, or produced water; or
(ii) The component to be inspected is buried, insulated in a manner that prevents access to the components by a monitor probe or optical gas imaging device, or obstructed by equipment or piping that prevents access to the components by a monitor probe or optical gas imaging device.
(e) Procedures for determining total well site production. The total well site production must be determined according to the following procedures:
(1) Calculate the total average boe per day for each calendar month using:
(i) For existing well sites, the records of production for the first 30 days after becoming subject to this section.
(ii) For well sites that commence construction, reconstruction or modification on or after February 6, 2023, the first 30 days of production, performing the calculation within 45 days of the end of the first 30 days of production.
(2) Determine the daily oil and natural gas production for each individual well at the well site for the month. To convert gas production to equivalent barrels of oil, divide the cubic feet of gas produced by 6,000.
(3) Sum the daily production for each individual well at the well site to determine the total well site production and divide by the total number of days in the calendar month. This is the average daily total well site production for the month.
(4) Use the result determined in paragraph (e)(2) of this section and average with the daily average well site production values determined for each of the preceding 11 months to calculate the rolling 12-month average of the total well site production.
§ 49.4179   VOC emissions control requirements for tank truck loading.
(a) Applicability. The requirements in this section apply to each owner or operator who loads or permits the loading of any intermediate hydrocarbon liquid or produced water at an oil and natural gas source as identified in § 49.4169(b).
(b) Tank truck loading requirements. Tank trucks used for transporting intermediate hydrocarbon liquid or produced water must be loaded and unloaded using measures to minimize VOC emissions. These measures must include, at a minimum, bottom filling or a submerged fill pipe, as defined in § 49.4171(b).
§ 49.4180   VOC emissions control requirements for pneumatic controllers.
(a) Applicability. The VOC emissions control requirements in this section apply to each owner or operator of any existing pneumatic controller located at an oil and natural gas source as identified in § 49.4169(b).
(b) Exemptions. This section does not apply to pneumatic controllers subject to and controlled in accordance with the requirements for pneumatic controllers in 40 CFR part 60, subparts OOOO or OOOOa.
(c) Retrofit requirements. All existing pneumatic controllers must meet the standards established for pneumatic controllers that are constructed, modified, or reconstructed on or after October 15, 2013, as specified in 40 CFR part 60, subpart OOOO.
(d) Documentation requirements. The owner or operator of any existing pneumatic controllers must meet the tagging requirements in 40 CFR 60.5390(a), except that the month and year of installation, reconstruction or modification is not required.
§ 49.4181   Other combustion devices.
(a) Applicability. The VOC emission control requirements in this section apply to each owner or operator of any existing enclosed combustor or flare located at an oil and natural gas source as identified in § 49.4169(b) that is used to control VOC emissions, but that is not required under §§ 49.4173 through 49.4175 of this rule.
(b) Retrofit requirements. All existing enclosed combustors and flares must be equipped with an operational electronically controlled automatic ignition device.
§ 49.4182   Monitoring and testing requirements.
(a) Applicability. The monitoring and testing requirements in paragraphs (c) and (d) of this section apply, as appropriate, to each oil and natural gas source as identified in § 49.4169(b) with equipment or activities that are subject to §§ 49.4173 through 49.4177.
(b) Exemptions. Paragraphs (c) and (d) of this section do not apply to any storage vessels, glycol dehydration units, pneumatic pumps, covers, or closed-vent systems, or to VOC emission control devices subject to and monitored in accordance with the monitoring requirements for such equipment and activities in 40 CFR part 60, subparts OOOO or OOOOa, or 40 CFR part 63, subpart HH.
(c) Each owner or operator must inspect each cover and closed-vent system as specified in paragraphs (c)(1) or (2).
(1) Conduct olfactory, visual, and auditory inspections at least once every calendar month, separated by at least 15 days between each inspection, of each cover and closed-vent system, including each bypass device, and each storage vessel thief hatch, seal, and pressure relief valve, to ensure proper condition and functioning of the equipment to identify defects that can result in air emissions according to the procedures. Examples of defects are visible cracks, holes, or gaps in the cover or piping, or between the cover and the separator wall; loose connections; liquid leaks; and broken, cracked, or otherwise damaged seals or gaskets on closure devices, caps, or other closure devices. If the storage vessel is partially or entirely buried, you must inspect only those portions of the cover that extend to or above the ground surface, and those connections that are on such portions of the cover (e.g., fill ports, access hatches, gauge wells) and can be opened to the atmosphere. The inspector should note whether there are signs of oil releases around storage vessel thief hatches, seals and pressure relief valves (e.g., staining on the storage vessel), which may indicate over-pressure events that occurred when the storage vessel was being filled. Any defects identified must be corrected or repaired within 30 days of identification.
(2) Conduct optical gas imaging inspections of each cover and closed vent system for any visible emissions at the same frequency as the frequency for the collection of fugitive emissions components located at the oil and natural gas source, as specified in § 49.4178(d)(1).
(d) Each owner or operator must monitor the operation of each enclosed combustor and flare to confirm proper operation and demonstrate compliance with the requirements of § 49.4177(c), as follows and as applicable:
(1) Demonstrate compliance with the requirement of § 49.4177(c)(5)(i)(B) that each enclosed combustor must be demonstrated by the owner or operator to meet the VOC control efficiency requirements of §§ 49.4173 through 49.4176, by conducting performance tests using EPA-approved performance test methods and procedures specified in 40 CFR 60.5413 and according to the schedule specified in paragraphs (d)(1)(i) and (ii) of this section.
(i) You must conduct an initial performance test within 180 days after the effective date of this rule for existing enclosed combustors, and within 180 days after initial startup for new enclosed combustors. You must submit the performance test results as specified in § 49.4184(a) within 60 days of completing the test.
(ii) You must conduct periodic performance tests for all enclosed combustors required to conduct initial performance tests. You must conduct the first periodic performance test no later than 60 months after the initial performance test required in paragraph (d)(1)(i) of this section. You must conduct subsequent periodic performance tests at intervals no longer than 60 months following the previous periodic performance test or whenever you desire to establish a new operating limit. You must submit the periodic performance test results as specified in § 49.4184(a) within 60 days of completing each test.
(iii) The owner or operator of an enclosed combustor whose model is tested under, and meets the criteria of, § 49.4177(c)(5)(i)(A) is not required to conduct performance testing.
(2) Conduct inspections of each enclosed combustor or flare at least once every calendar month, separated by at least 15 days between each inspection, to confirm proper operation of the device, as follows:
(i) Demonstrate that each enclosed combustor or flare is operated with no visible smoke emissions, except for periods not to exceed a total of 1 minute during any 15-minute period, by conducting a visible emissions test using section 11 of EPA Method 22 of appendix A-7 of 40 CFR part 60. The observation period must be of sufficient length to meet the requirement for determining compliance with this visible emissions standard. Devices failing the visible emissions test must follow manufacturer's repair instructions, if available, or best combustion engineering practice as outlined in the unit inspection and maintenance plan, to return the unit to compliant operation. All inspection, repair, and maintenance activities for each unit must be recorded in a maintenance and repair log and must be available for inspection. Following return to operation from maintenance or repair activity, each device must pass a Method 22 of Appendix A-7 of 40 CFR part 60 visual observation as described in this paragraph.
(ii) Conduct visual inspections to confirm that the pilot is lit when vapors are being routed to the device and that the continuous burning pilot or electronically controlled automatic ignition device and the continuous parameter monitoring system is operating properly;
(iii) Conduct olfactory, visual and auditory inspections of all other equipment associated with the combustion device to ensure system integrity; and
(iv) Respond to any indication of pilot flame failure and ensure that the pilot flame is relit as soon as practically and safely possible after discovery.
(e) Where sufficient to meet the monitoring requirements in this section, the owner or operator may use a SCADA system to monitor and record the required data.
§ 49.4183   Recordkeeping requirements.
(a) Each owner or operator of an oil and natural gas source as identified in § 49.4169(b) must maintain the following records, as applicable:
(1) Monthly calculations, as specified in § 49.4173(c)(2), demonstrating that the uncontrolled actual VOC emissions from the collection of all storage vessels, glycol dehydrators, and pneumatic pumps at an oil and natural gas source, as identified in § 49.4169(b), have been maintained at less than 4 tpy;
(2) Records of monthly and rolling 12-month crude oil, condensate, intermediate hydrocarbon liquids, produced water or natural gas throughput;
(3) For each emergency storage vessel that is exempted from the control requirements of § 49.4173(b)(2), records of usage including:
(i) The date the vessel received fluids;
(ii) The volume of fluids received in barrels;
(iii) The date the overflow vessel was emptied; and
(iv) The volume of fluids emptied in barrels.
(4) Identification of each storage vessel that is removed from service or returned to service as specified in § 49.4173(b)(3), including the date the storage vessel was removed from service or returned to service.
(5) For storage vessels that are skid-mounted or permanently attached to something that is mobile (such as trucks, railcars, barges or ships), records indicating the number of consecutive days that the vessel is located at an oil and natural gas source. If a storage vessel is removed from an oil and natural gas source and, within 30 days, is either returned to the source or replaced by another storage vessel at the source to serve the same or similar function, then the entire period since the original storage vessel was first located at the source, including the days when the storage vessel was removed, must be added to the count of the number of consecutive days.
(6) For each enclosed combustor or flare at an oil and natural gas source required under §§ 49.4173 through 49.4177:
(i) Manufacturer-written, site-specific designs, operating instructions, operating procedures and maintenance schedules, including those of any operation monitoring systems;
(ii) Date of installation;
(iii) Records of required monitoring of operations in § 49.4182(d)(1);
(iv) Records of any instances in which the pilot flame is not present or the monitoring equipment is not functioning in the enclosed combustor or flare, the date and times of the occurrence, the corrective actions taken, and any preventative measures adopted to prevent recurrence of the occurrence; and
(v) Records of any visible emissions tests conducted according to § 49.4182(d)(3), including any time periods in which visible smoke emissions are observed emanating from the enclosed combustor or flare.
(7) For each closed-vent system:
(i) The date of installation; and
(ii) Records of any instances in which any closed-vent system or control device was bypassed or down, the reason for each incident, its duration, and the corrective actions taken, and any preventative measures adopted to avoid such bypasses or downtimes.
(8) Documentation of all storage vessel and closed-vent system inspections required in § 49.4182(c). All inspection records must include the following information:
(i) The date of the inspection;
(ii) The findings of the inspection;
(iii) Any adjustments or repairs made as a result of the inspection, and the date of the adjustment or repair; and
(iv) The inspector's name or identification number;
(9) The Uinta Basin-wide fugitive emissions monitoring plan for the Indian country lands within the U&O Reservation, including all elements required by § 49.4178(d).
(10) Documentation of each fugitive emissions inspection conducted in accordance with § 49.4178(d). All inspection records must include the following information:
(i) The date of the inspection;
(ii) The identification of any component that was determined to be leaking;
(iii) The identification of any component designated difficult-to-monitor or unsafe-to-monitor that was not inspected, and the reason it was not inspected;
(iv) The date of the first attempt to repair the leaking component;
(v) The identification of any leaking component with a delayed repair and the reason for the delayed repair:
(A) For unavailable parts:
( 1 ) The date of ordering a replacement component; and
( 2 ) The date the replacement component was received; and
(B) For a shutdown:
( 1 ) The reason the repair is technically infeasible;
( 2 ) The date of the shutdown;
( 3 ) The date of subsequent startup after a shutdown; and
( 4 ) Emission estimates of the shutdown and the repair if the delay is longer than 6 months;
(vi) The date and description of any corrective action taken, including the date the component was verified to no longer be leaking;
(vii) The identification of each component exempt under § 49.4178(d)(2), including the type of component and a description of the qualifying exemption; and
(viii) The inspector's name or identification number.
(11) For each well site complying with either § 49.4178(b)(2) or § 49.4178(c)(2), you must maintain records of the rolling 12-month average daily production no later than 12 months before complying with § 49.4178(b)(2) or § 49.4178(c)(2).
(12) For each electronically controlled automatic ignition system required under § 49.4181, records demonstrating the date of installation and manufacturer specifications; and
(13) For each retrofitted pneumatic controller, the records required in 40 CFR 60.5420(c)(4)(i).
(b) Each owner or operator must keep all records required by this section onsite at the source or at the location that has day-to-day operational control over the source and must make the records available to the EPA upon request.
(c) Each owner or operator must retain all records required by this section for a period of at least 5 years from the date the record was created.
§ 49.4184   Notification and reporting requirements.
(a) Unless otherwise specified, each owner or operator must submit any documents required under this rule to: U.S. EPA Region 8, Enforcement and Compliance Assurance Division, Air and Toxics Enforcement Branch, 8ENF-AT, 1595 Wynkoop St., Denver, CO 80202, or documents may be submitted electronically to r8airreportenforcement@epa.gov and/or to the EPA's Compliance and Emissions Data Reporting Interface (CEDRI). Information on CEDRI is available at https://www.epa.gov/electronic-reporting-air-emissions/cedri; CEDRI can be accessed directly through the EPA's Central Data Exchange (CDX) at 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). Anything submitted using CEDRI cannot later be claimed CBI. Although we do not expect persons to assert a claim of CBI, if you wish to assert a CBI claim, you must submit a complete file, including the information claimed to be CBI, on a compact disc, flash drive, or other commonly used electronic storage media to the EPA, and the electronic media must be clearly marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group Leader, Measurement Policy Group, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same information, with the CBI omitted, must be submitted to the EPA via r8airreportenforcement@epa.gov or the EPA's CDX as described earlier in this paragraph. All claims of CBI must be asserted at the time of submission. Furthermore, under CAA section 114(c), emissions data is 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.
(b) Each owner and operator of an affected oil and natural gas source as identified in § 49.4169(b) must submit an annual report containing the information specified in paragraphs (b)(1) through (3) of this section, as applicable. The annual report must cover affected operations for the previous calendar year. The initial annual report is due April 1st of the calendar year following February 6, 2023 and must cover all affected operations for the previous calendar year on and after February 6, 2023. Subsequent annual reports are due on the same date each year as the date the initial annual report was submitted. If you own or operate more than one oil and natural gas source, you may submit one report for multiple oil and natural gas sources, provided the report contains all of the information required as specified in paragraphs (b)(1) through (3) of this section. Annual reports may coincide with title V, NSPS OOOO or OOOOa, or NESHAP HH reports as long as all the required elements of the annual report are included. An alternative schedule on which the annual report must be submitted will be allowed as long as the schedule does not extend the reporting period. The annual report must include:
(1) The owner or operator name, and the name and location (decimal degree latitude and longitude location indicating the datum used in parentheses) of each oil and natural gas source being included in the annual report.
(2) The beginning and ending dates of the reporting period.
(3) For each oil and natural gas source, a summary of the required records specified in § 49.4183 that are identified in paragraphs (b)(3)(i) through (iv) of this section as they relate to the source's compliance with the requirements of §§ 49.4173 through 49.4183.
(i) For each enclosed combustor or flare at an oil and natural gas source required under §§ 49.4173 through 49.4177:
(A) Records of any instances in which the pilot flame is not present or the monitoring equipment is not functioning, the date and times of the occurrence, the corrective actions taken, and any preventative measures adopted to prevent recurrence of the occurrence; and
(B) Records of any time periods in which visible smoke emissions are observed emanating from the enclosed combustor or flare.
(ii) For each closed-vent system:
(A) Records of any instances in which any closed-vent system or control device was bypassed or down, the reason for each incident, its duration, the corrective actions taken, and any preventative measures adopted to avoid such bypasses or downtimes; and
(B) Records of any instances of defects identified during the monthly inspection required in § 49.4182(c), including:
( 1 ) The date of the inspection;
( 2 ) The findings of the inspection;
( 3 ) Date and description of corrective adjustments or repairs made as a result of the inspection or reason for delay of repair; and
(iii) For Fugitive Emissions Monitoring, records documenting each fugitive emissions inspection, including:
(A) The date of the inspection;
(B) Identification of any component that was determined to be leaking;
(C) Identification of any component designated difficult-to-monitor or unsafe-to-monitor that was not inspected and the reason it was not inspected;
(D) The date of repair of each leaking component;
(E) Identification of any leaking component with a delayed repair, the reason for the delayed repair and the emission estimates associated with any shutdown and repair if the delay is longer than 6 months;
(F) The date and description of any corrective action taken, including the date the component was verified to no longer be leaking;
(G) The inspector's name or identification number;
(H) For each well site complying with § 49.4178(c)(2), you must specify that the well site is exempt from the requirements of § 49.4178(d) and submit the average daily production for the well site; and
(iv) For each pneumatic controller with a natural gas bleed rate greater than the applicable standard, records of the reason for the use of the controller.
§§ 49.4185-49.4199   [Reserved]
§ 49.4200   Identification of plan.
(a) Purpose and scope. This section contains the approved implementation plan for the Northern Cheyenne Tribe, submitted to EPA on September 25, 2017. The plan consists of programs and procedures that cover general and emergency authorities, ambient air quality standards, permitting requirements for open burning, general prohibitory rules, open burning limitations, enforcement authorities, and procedures for administrative appeals and judicial review in Tribal court.
(b) Incorporation by reference. (1) Material listed in paragraph (c) of this section was approved for incorporation by reference by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Material is incorporated as it exists on the date of the approval, and notice of any change in the material will be published in the Federal Register .
(2) EPA Region 8 certifies that the rules/regulations provided by EPA in the TIP compilation at the addresses in paragraph (b)(3) of this section are an exact duplicate of the officially promulgated tribal rules/regulations which have been approved as part of the Tribal Implementation Plan.
(3) Copies of the materials incorporated by reference may be inspected at the Region 8 Office of EPA at 1595 Wynkoop Street, Denver, CO 80202 or call 303-312-6002; the U.S. Environmental Protection Agency, EPA Docket Center (EPA/DC), Air and Radiation Docket and Information Center, MC 2822T, 1200 Pennsylvania Avenue NW, Washington, DC 20460 or call 202-566-1742; and the National Archives and Records Administration. For information on the availability of this material at NARA, email fr.inspection@nara.gov, or go to: http://www.archives.gov/federal-register/cfr/ibr-locations.html. Copies of the Northern Cheyenne TIP regulations we have approved are also available at http://www.epa.gov/region8/air/sip.html.
(c) EPA-approved regulations.
Table 1 to Paragraph ( c )
§§ 49.4201-49.5510   [Reserved]
§ 49.5511   Identification of plan.
(a) Purpose and scope. This section contains the approved implementation plan for the Gila River Indian Community dated August 2008. The plan consists of programs and procedures that cover general and emergency authorities, ambient air quality standards, permitting requirements for minor sources of air pollution, enforcement authorities, procedures for administrative appeals and judicial review in Tribal court, requirements for area sources of fugitive dust and fugitive particulate matter, general prohibitory rules, and source category-specific emission limitations and standards.
(b) Incorporation by reference.
(1) Material listed in paragraph (c) of this section was approved for incorporation by reference by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Material is incorporated as it exists on the date of the approval, and notice of any change in the material will be published in the Federal Register.
(2) EPA Region IX certifies that the rules/regulations provided by EPA in the TIP compilation at the addresses in paragraph (b)(3) of this section are an exact duplicate of the officially promulgated tribal rules/regulations which have been approved as part of the Tribal Implementation Plan as of January 19, 2011.
(3) Copies of the materials incorporated by reference may be inspected at the Region IX Office of EPA at 75 Hawthorne Street, San Francisco, CA 94105-3901 or call 415-947-4192; the U.S. Environmental Protection Agency, EPA Docket Center (EPA/DC), Air and Radiation Docket and Information Center, MC 2822T, 1200 Pennsylvania Avenue, NW., Washington, DC 20460 or call 202-566-1742; and the National Archives and Records Administration. For information on the availability of this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.
(c) EPA-approved regulations.
EPA-Approved Gila River Indian Community Tribal Regulations
(d) Nonregulatory.
§ 49.5512   Federal Implementation Plan Provisions for Four Corners Power Plant, Navajo Nation.
(a) Applicability. The provisions of this section shall apply to each owner or operator of the coal burning equipment designated as Units 1, 2, 3, 4, and 5 at the Four Corners Power Plant (the Plant) on the Navajo Nation Indian Reservation located in the Four Corners Interstate Air Quality Control Region (see 40 CFR 81.121).
(b) Compliance Dates. Compliance with the requirements of this section is required upon the effective date of this rule unless otherwise indicated by compliance dates contained in specific provisions.
(c) Definitions. For the purposes of this section:
(1) Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding.
(2) Air pollution control equipment includes baghouses, particulate or gaseous scrubbers, and any other apparatus utilized to control emissions of regulated air contaminants which would be emitted to the atmosphere.
(3) Business Day. Business day means a normal working day, excluding weekends and Federal Holidays.
(4) Daily average means the arithmetic average of the hourly values measured in a 24-hour period.
(5) Excess emissions means the emissions of air contaminants in excess of an applicable emissions limitation or requirement.
(6) Heat input means heat derived from combustion of fuel in a Unit and does not include the heat input from preheated combustion air, recirculated flue gases, or exhaust gases from other sources. Heat input shall be in accordance with 40 CFR part 75.
(7) Malfunction means any sudden and unavoidable failure of air pollution control equipment or process equipment or of a process to operate in a normal or usual manner. Failures that are caused entirely or in part by poor maintenance, careless operation, or any other preventable upset condition or preventable equipment breakdown shall not be considered malfunctions. This rule provides an affirmative defense to actions for penalties brought for excess emissions that arise during certain malfunction episodes. An affirmative defense is not available if during the period of excess emissions, there was an exceedance of the relevant ambient air quality standard that could be attributed to the emitting source.
(8) Owner or Operator means any person who owns, leases, operates, controls, or supervises the Plant or any of the coal burning equipment designated as Units 1, 2, 3, 4, or 5 at the Plant.
(9) Oxides of nitrogen (NO X ) means the sum of nitric oxide (NO) and nitrogen dioxide (NO 2 ) in the flue gas, expressed as nitrogen dioxide.
(10) Plant-wide basis means total stack emissions of any particular pollutant from all coal burning equipment at the Plant.
(11) Regional Administrator means the Regional Administrator of the Environmental Protection Agency (EPA) Region 9 or his/her authorized representative.
(12) Shutdown means the cessation of operation of any air pollution control equipment, process equipment, or process for any purpose. Specifically, for Units 1, 2, or 3, shutdown begins when the unit drops below 40 MW net load with the intent to remove the unit from service. For Units 4 or 5, shutdown begins when the unit drops below 300 MW net load with the intent to remove the unit from service.
(13) Startup means the setting into operation of any air pollution control equipment, process equipment, or process for any purpose. Specifically, for Units 1, 2, or 3, startup ends when the unit reaches 40 MW net load. For Units 4 or 5, startup ends when the unit reaches 400 MW net load.
(14) 24-hour period means the period of time between 12:01 a.m. and 12 midnight.
(d) Emissions Standards and Control Measures —(1) Sulfur Dioxide. No owner or operator shall discharge or cause the discharge of sulfur dioxide (SO 2 ) into the atmosphere in excess of:
(i) 12.0 percent of the potential combustion concentration assuming all of the sulfur in the coal is converted to SO 2 . This percent emitted is determined by a daily calculation of the plantwide heatinput weighted annual average.
(ii) 17,900 pounds of total SO 2 emissions per hour averaged over any consecutive three (3) hour period, determined on a plant-wide basis.
(2) Particulate Matter. No owner or operator shall discharge or cause the discharge of particulate matter from any coal burning equipment into the atmosphere in excess of 0.050 pounds per million British thermal unit (lb/MMBtu) of heat input (higher heating value), as averaged from three sampling runs, each at 60 minutes in duration, each collecting a minimum sample of 30 dry standard cubic feet.
(3) Dust. Each owner or operator shall operate and maintain the existing dust suppression methods for controlling dust from the coal handling and storage facilities. Within ninety (90) days after promulgation of this section, the owner or operator shall submit to the Regional Administrator a description of the dust suppression methods for controlling dust from the coal handling and storage facilities, flyash handling and storage, and road sweeping activities. Within 548 days of promulgation of this section each owner or operator shall not emit dust with an opacity greater than 20 percent from any crusher, grinding mill, screening operation, belt conveyor, or truck loading or unloading operation.
(4) Opacity. No owner or operator shall discharge or cause the discharge of emissions from the stacks of Units 4 and 5 into the atmosphere exhibiting greater than 20% opacity, excluding uncombined water droplets, averaged over any six (6) minute period, except for one six (6) minute period per hour of not more than 27% opacity.
(5) Oxides of nitrogen. No owner or operator shall discharge or cause the discharge of NO X into the atmosphere.
(i) From either Unit 1 or 2 in excess of 0.85 lb/MMBtu of heat input per unit, and from either Units 3, 4, or 5 in excess of 0.65 lb/MMBtu of heat input per unit averaged over any successive thirty (30) boiler operating day period;
(ii) In excess of 335,000 lb per 24-hour period when coal burning equipment is operating, on a plant-wide basis; for each hour when coal burning equipment is not operating, this limitation shall be reduced. If the unit which is not operating is Unit 1, 2, or 3, the limitation shall be reduced by 1,542 lb per hour for each unit which is not operating. If the unit which is not operating is Unit 4 or 5, the limitation shall be reduced by 4,667 lb per hour for each unit which is not operating.
(e) Testing and Monitoring. Upon completion of the installation of continuous emissions monitoring systems (CEMS) software as required in this section, compliance with the emissions limits set for SO2 and NO X shall be determined by using data from a CEMS unless otherwise specified in paragraphs (e)(2) and (e)(4) of this section. Compliance with the emissions limit set for particulate matter shall be tested annually, or at such other time as requested by the Regional Administrator, based on data from testing conducted in accordance with 40 CFR part 60, appendix A, Methods 1 through 5, or any other method receiving prior approval from the Regional Administrator. Compliance with the emissions limits set for opacity shall be determined by using data from a Continuous Opacity Monitoring System (COMS) except during saturated stack conditions (uncombined water droplets). If the baghouse is operating within its normal operating parameters, the baghouse is not fully closed, and a high opacity reading occurs, it will be presumed that the occurrence was caused by saturated stack conditions and shall not be considered a violation.
(1) The owner or operator shall maintain and operate CEMS for SO2, NO or NO X , a diluent and, for Units 4 and 5 only, COMS, in accordance with 40 CFR 60.8 and 60.13, and appendix B of 40 CFR part 60. Within six (6) months of promulgation of this section, the owner or operator shall install CEMS and COMS software which complies with the requirements of this section. The owner or operator of the Plant may petition the Regional Administrator for extension of the six (6) month period for good cause shown. Completion of 40 CFR part 75 monitor certification requirements shall be deemed to satisfy the requirements under 40 CFR 60.8 and 60.13 and appendix B of part 60. The owner or operator shall comply with the quality assurance procedures for CEMS found in 40 CFR part 75, and all reports required thereunder shall be submitted to the Regional Administrator. The owner or operator shall provide the Regional Administrator notice in accordance with 40 CFR 75.61.
(2) Sulfur Dioxide. For the purpose of determining compliance with this section, the sulfur dioxide inlet concentration (in lb/MMBtu) shall be calculated using the daily average percent sulfur and Btu content of the coal combusted. The inlet sulfur concentration and Btu content shall be determined in accordance with American Society for Testing and Materials (ASTM) methods or any other method receiving prior approval from the Regional Administrator. A daily fuel sample shall be collected using the coal sampling tower conforming to the ASTM specifications. The analyses shall be done on the daily sample using ASTM methods or any other method receiving prior approval from the Regional Administrator.
(i) The inlet sulfur dioxide concentration shall be calculated using the following formula:
(ii) The total pounds of SO 2 generated by burning the coal shall be calculated by multiplying the SO 2 inlet concentration by the daily total heat input determined by the 40 CFR part 75 acid rain monitoring. This will determine the pounds of SO 2 produced per day. The SO 2 emitted from the stacks shall be determined by adding the daily SO 2 emissions from each stack as determined by the 40 CFR part 75 acid rain monitors. Compliance with the emission limit shall be determined for each day by adding that day's SO 2 emissions and that day's SO 2 produced to the previous 364 days and then dividing the 365 days of emissions by the 365 days of SO 2 produced. Compliance is demonstrated if this fraction, converted to a percent, is equal to or less than 12.0 percent. The data from the 40 CFR part 75 monitors shall not be bias adjusted. If a valid SO 2 pounds per hour or heat input is not available for any hour for a unit, that heat input and SO 2 pounds per hour shall not be used in the calculation of the annual plant-wide average.
(3) Particulate matter. Particulate matter emissions shall be determined by averaging the results of three test runs. Each test run shall be sixty (60) minutes in duration and shall collect a minimum volume of thirty (30) dry standard cubic feet. Within six (6) months of promulgation of this section, particulate matter testing shall be conducted annually and at least six (6) months apart, with the equipment within 90 percent of maximum operation in accordance with 40 CFR 60.8 and appendix A to 40 CFR part 60. The owner or operator shall submit written notice of the date of testing no later than 21 days prior to testing. Testing may be performed on a date other than that already provided in a notice as long as notice of the new date is provided either in writing or by telephone or other means acceptable to the Region 9 Enforcement Office, and the notice is provided as soon as practicable after the new testing date is known, but no later than 7 days (or a shorter period as approved by the Region 9 Enforcement Office) in advance of the new date of testing.
(4) Oxides of nitrogen. The total daily plant-wide oxides of nitrogen emissions in pounds of NO 2 per day shall be calculated using the following formula:
(5) Continuous emissions monitoring shall apply during all periods of operation of the coal burning equipment, including periods of startup, shutdown, and malfunction, except for CEMS breakdowns, repairs, calibration checks, and zero and span adjustments. Continuous monitoring systems for measuring SO 2 , NO X , and diluent gas shall complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-minute period. Hourly averages shall be computed using at least one data point in each fifteen minute quadrant of an hour. Notwithstanding this requirement, an hourly average may be computed from at least two data points separated by a minimum of 15 minutes (where the unit operates for more than one quadrant in an hour) if data are unavailable as a result of performance of calibration, quality assurance, preventive maintenance activities, or backups of data from data acquisition and handling system, and recertification events. When valid SO 2 pounds per hour, NO 2 pounds per hour, or NO 2 pounds per million Btu emission data are not obtained because of continuous monitoring system breakdowns, repairs, calibration checks, or zero and span adjustments, emission data must be obtained by using other monitoring systems approved by the EPA to provide emission data for a minimum of 18 hours in at least 22 out of 30 successive boiler operating days. If a parameter essential for determining either the SO 2 pound per hour or the heat input is not valid or unavailable, that hour for that unit shall not be used in calculating the percent emissions of SO 2 for the plant-wide limit. The necessary software for determining compliance with the SO 2 plantwide annual average shall be installed and operating within 180 days of the effective date of this rule. The first day for determining compliance with the plantwide SO 2 limit shall be 365 days after the successful installation of the software.
(6) The owner or operator shall maintain a set of opacity filters to be used as audit standards.
(7) Nothing herein shall limit EPA's ability to ask for a test at any time under Section 114 of the Clean Air Act, 42 U.S.C. 7414, and enforce against any violation.
(8) In order to provide reasonable assurance that the scrubbers for control of particulate matter from Units 1, 2, and 3 are being maintained and operated in a manner consistent with good air pollution control practice for minimizing emissions, the owner or operator shall comply with the following provisions:
(i) The owner or operator shall develop a plan to monitor, record, and report parameter(s) indicative of the proper operation of the scrubbers to provide a reasonable assurance of compliance with the particulate matter limits in paragraph (d)(2) of this section. The owner or operator shall submit this plan to the Regional Administrator no later than sixty (60) days after the effective date of this FIP. The owner or operator shall implement this plan within 90 days of approval by the Regional Administrator and shall commence reporting the data generated pursuant to the monitoring plan in accordance with the schedule in paragraph (e)(8)(v) of this section. If requested by the Regional Administrator, this plan shall be revised and submitted to the Regional Administrator for approval within sixty (60) days of the request. The revised plan shall be implemented within sixty (60) days of the Regional Administrator's approval.
(ii) In the event that the owner or operator is unable to develop the plan required in paragraph (e)(8)(i) of this section due to technical difficulties, fails to submit the plan within sixty (60) days of the effective date of this FIP, or the Regional Administrator disapproves the plan, the owner or operator shall install and operate devices to measure the pressure drop across each scrubber module and the total flow of scrubbing liquid to the venturi section of each scrubber module. The data from these instruments shall be monitored and recorded electronically. A minimum of one reading every 15 minutes shall be used to calculate an hourly average which shall be recorded and stored for at least a five-year period. The owner or operator shall report in an electronic format either all hourly data, or one-hour averages deviating by more than 30 percent from the levels measured during the last particulate matter stack test that demonstrated compliance with the limit in this section. The owner or operator shall implement this requirement no later than one hundred eighty (180) days after the effective date of this FIP if it failed to submit the plan within sixty (60) days after the effective date of this FIP; or no later than 60 days after the Regional Administrator's disapproval of the plan.
(iii) The monitoring required under paragraphs (e)(8)(i) and (e)(8)(ii) of this section shall apply to each Unit at all times that the Unit is operating, except for monitoring malfunctions, associated repairs, and required quality assurance or control activities (including, as applicable, calibration checks and required zero and span adjustments). A monitoring malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring to provide valid data. Monitoring failures that are caused in part by poor maintenance or careless operation are not malfunctions.
(iv) The owner or operator may petition the Regional Administrator for an extension of the sixty (60) day deadline. Such extension shall be granted only if the owner or operator demonstrates to the satisfaction of the Regional Administrator that:
(A) The delay is due to technical infeasibility beyond the control of the owner or operator; and
(B) The requested extension, if granted, will allow the owner or operator to successfully complete the plan.
(v) The owner or operator shall submit to the Regional Administrator reports of the monitoring data required by this section semi-annually. The reports shall be postmarked within 30 days of the end of each calendar quarter.
(vi) The owner or operator shall develop and document a quality assurance program for the monitoring and recording instrumentation. This program shall be updated or improved as requested by the Regional Administrator.
(vii) In the event that a program for parameter monitoring on Units 1, 2, and 3 is approved pursuant to the Compliance Assurance Monitoring rule, 40 CFR Part 64, such program will supersede the provisions contained in paragraph (e)(8) of this section.
(f) Reporting and Recordkeeping Requirements. Unless otherwise stated all requests, reports, submittals, notifications, and other communications to the Regional Administrator required by this section shall be submitted, unless instructed otherwise, to the Director, Navajo Environmental Protection Agency, P.O. Box 339, Window Rock, Arizona 86515, (928) 871-7692, (928) 871-7996 (facsimile), and to the Director, Air Division, U.S. Environmental Protection Agency, Region IX, to the attention of Mail Code: AIR-5, at 75 Hawthorne Street, San Francisco, California 94105, (415) 972-3990, (415) 947-3579 (facsimile). For each unit subject to the emissions limitation in this section and upon completion of the installation of CEMS and COMS as required in this section, the owner or operator shall comply with the following requirements:
(1) For each emissions limit in this section, comply with the notification and recordkeeping requirements for CEMS compliance monitoring in 40 CFR 60.7(c) and (d). For Units 4 and 5, periods of excess opacity due to water droplets shall be reported in the summary report required by 40 CFR 60.7(d).
(2) For each day, provide the 365 day percent SO 2 emitted, the total SO 2 emitted that day, and the total SO 2 produced that day. For any hours on any unit where data for SO 2 hourly pounds or heat input is missing, identify the unit number and monitoring device that did not produce valid data that caused the missing hour.
(3) Furnish the Regional Administrator with reports describing the results of the annual particulate matter emissions tests postmarked within sixty (60) days of completing the tests. Each report shall include the following information:
(i) The test date;
(ii) The test method;
(iii) Identification of the coal burning equipment tested;
(iv) Values for stack pressure, temperature, moisture, and distribution of velocity heads;
(v) Average heat input;
(vi) Emissions data, identified by sample number, and expressed in pounds per MMBtu;
(vii) Arithmetic average of sample data expressed in pounds per MMBtu; and
(viii) A description of any variances from the test method.
(4) Excess Emissions Report. (i) For excess emissions (except in the case of saturated stack conditions), the owner or operator shall notify the Navajo Environmental Protection Agency Director and the U.S. Environmental Protection Agency Regional Administrator by telephone or in writing within one business day (initial notification). A complete written report of the incident shall be submitted to the Navajo Environmental Protection Agency Director and the U.S. Environmental Protection Agency Regional Administrator within ten (10) working days of the initial notification. This notification should be sent to the Director, Navajo Environmental Protection Agency, by mail to: P.O. Box 339, Window Rock, Arizona 86515, or by facsimile to: (928) 871-7996 (facsimile), and to the Regional Administrator, U.S. Environmental Protection Agency, by mail to the attention of Mail Code: AIR-5, at 75 Hawthorne Street, San Francisco, California 94105, by facsimile to: (415) 947-3579 (facsimile), or by e-mail to: r9.aeo@epa.gov. The complete written report shall include:
(A) The name and title of the person reporting;
(B) The identity and location of the Plant and Unit(s) involved, and the emissions point(s), including bypass, from which the excess emissions occurred or are occurring;
(C) The time and duration or expected duration of the excess emissions;
(D) The magnitude of the excess emissions expressed in the units of the applicable emissions limitation and the operating data and calculations used in determining the magnitude of the excess emissions;
(E) The nature of the condition causing the excess emissions and the reasons why excess emissions occurred or are occurring;
(F) If the excess emissions were the result of a malfunction, the steps taken to remedy the malfunction and the steps taken or planned to prevent the recurrence of such malfunction;
(G) For an opacity exceedance, the 6-minute average opacity monitoring data greater than 20 percent for the 24 hours prior to and during the exceedance for Units 4 and 5; and
(H) The efforts taken or being taken to minimize the excess emissions and to repair or otherwise bring the Plant into compliance with the applicable emissions limit(s) or other requirements. For this reporting requirement, excess opacity due to saturated stack conditions is exempted.
(ii) If the period of excess emissions extends beyond the submittal of the written report, the owner or operator shall also notify the Regional Administrator in writing of the exact time and date when the excess emissions stopped. Compliance with the excess emissions notification provisions of this section shall not excuse or otherwise constitute a defense to any violations of this section or of any law or regulation which such excess emissions or malfunction may cause.
(g) Equipment Operations. At all times, including periods of startup, shutdown, and malfunction, the owner or operator shall, to the extent practicable, maintain and operate the Plant including associated air pollution control equipment in a manner consistent with good air pollution control practices for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Regional Administrator which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the Plant. With regard to the operation of the baghouses on Units 4 and 5, placing the baghouses in service before coal fires are initiated will constitute compliance with this paragraph. (If the baghouse inlet temperature cannot achieve 185 degrees Fahrenheit using only gas fires, the owner or operator will not be expected to place baghouses in service before coal fires are initiated; however, the owner or operator will remain subject to the requirements of this paragraph.)
(h) Enforcement. (1) Notwithstanding any other provision in this implementation plan, any credible evidence or information relevant to whether the Plant would have been in compliance with applicable requirements if the appropriate performance or compliance test had been performed, can be used to establish whether or not the owner or operator has violated or is in violation of any standard in the plan.
(2) During periods of startup and shutdown the otherwise applicable emission limits or requirements for opacity and particulate matter shall not apply provided that:
(i) At all times the facility is operated in a manner consistent with good practice for minimizing emissions, and the owner or operator uses best efforts regarding planning, design, and operating procedures to meet the otherwise applicable emission limit;
(ii) The frequency and duration of operation in start-up or shutdown mode are minimized to the maximum extent practicable; and
(iii) The owner or operator's actions during start-up and shutdown periods are documented by properly signed, contemporaneous operating logs, or other relevant evidence.
(3) Emissions in excess of the level of the applicable emission limit or requirement that occur due to a malfunction shall constitute a violation of the applicable emission limit. However, it shall be an affirmative defense in an enforcement action seeking penalties if the owner or operator has met with all of the following conditions:
(i) The malfunction was the result of a sudden and unavoidable failure of process or air pollution control equipment or of a process to operate in a normal or usual manner;
(ii) The malfunction did not result from operator error or neglect, or from improper operation or maintenance procedures;
(iii) The excess emissions were not part of a recurring pattern indicative of inadequate design, operation, or maintenance;
(iv) Steps were taken in an expeditious fashion to correct conditions leading to the malfunction, and the amount and duration of the excess emissions caused by the malfunction were minimized to the maximum extent practicable;
(v) All possible steps were taken to minimize the impact of the excess emissions on ambient air quality;
(vi) All emissions monitoring systems were kept in operation if at all possible; and
(vii) The owner or operator's actions in response to the excess emissions were documented by properly signed, contemporaneous operating logs, or other relevant evidence.
(i) Regional Haze Best Available Retrofit Technology limits for this plant are in addition to the requirements of paragraphs (a) through (h) of this section. All definitions and testing and monitoring methods of this section apply to the limits in this paragraph (i) except as indicated in paragraphs (i)(1) through (4) of this section. The interim NO X emission limit in paragraph (i)(2)(ii) of this section shall be effective 180 days after re-start of the unit after installation of add-on post-combustion NO X controls for that unit and until the plant-wide limit goes into effect. The plant-wide NO X limit shall be effective no later than 5 years after October 23, 2012. The owner or operator may elect to meet the plant-wide limit early to remove the individual unit limits. Particulate limits for Units 4 and 5 shall be effective 60 days after restart following the scheduled major outage for Units 4 and 5 in 2013 and 2014.
(1) Particulate Matter from Units 4 and 5 shall be limited to 0.015 lb/MMBtu for each unit as measured by the average of three test runs with each run collecting a minimum of 60 dscf of sample gas and with a duration of at least 120 minutes. Sampling shall be performed according to 40 CFR Part 60 Appendices A-1 through A-3, Methods 1 through 4 and Method 5 or Method 5e. The averaging time for any other demonstration of the particulate matter compliance or exceedance shall be based on a 6-hour average. Particulate testing shall be performed annually as required by paragraph (e)(3) of this section. This test with 120 minute test runs may be substituted and used to demonstrate compliance with the particulate limits in paragraph (d)(2) of this section.
(2) Plant-wide nitrogen oxide emission limits.
(i) The plant-wide nitrogen oxide limit, expressed as nitrogen dioxide (NO 2 ), shall be 0.11 lb/MMBtu as averaged over a rolling 30-calendar day period. NO X emissions for each calendar day shall be determined by summing the hourly emissions measured as pounds of NO 2 for all operating units. Heat input for each calendar day shall be determined by adding together all hourly heat inputs, in millions of Btu, for all operating units. Each day the rolling 30-calendar day average shall be determined by adding together that day's and the preceding 29 days' pounds of NO 2 and dividing that total pounds of NO 2 by the sum of the heat input during the same 30-day period. The results shall be the rolling 30-calendar day-average pound per million Btu emissions of NO X .
(ii) The interim NO X limit for the first 750 MW boiler retrofitted with add-on post-combustion NO X control shall be 0.11 lb/MMBtu, based on a rolling average of 30 successive boiler operating days.
(iii) Schedule for add-on post-combustion NO X controls installation
(A) Within 4 years of the effective date of this rule, FCPP shall have installed add-on post-combustion NO X controls on at least 750 MW (net) of generation to meet the interim emission limit in paragraph (i)(2)(ii)(A) of this section.
(B) Within 5 years of the effective date of this rule, FCPP shall have installed add-on post-combustion NO X controls on all 2060 MW (net) of generation to meet the plant-wide emission limit for NO X in paragraph (i)(2)(i) of this section.
(iv) Testing and monitoring shall use the 40 CFR part 75 monitors and meet the 40 CFR part 75 quality assurance requirements. In addition to these 40 CFR part 75 requirements, relative accuracy test audits shall be performed for both the NO X pounds per hour measurement and the heat input measurement. These shall have relative accuracies of less than 20 percent. This testing shall be evaluated each time the 40 CFR part 75 monitors undergo relative accuracy testing.
(v) If a valid NO X pounds per hour or heat input is not available for any hour for a unit, that heat input and NO X pounds per hour shall not be used in the calculation of the 30 day plant-wide rolling average.
(vi) Upon the effective date of the plant-wide NO X average, the owner or operator shall have installed CEMS and COMS software that complies with the requirements of this section.
(3) In lieu of meeting the NO X requirements of paragraph (i)(2) of this section, FCPP may choose to permanently shut down Units 1, 2, and 3 by January 1, 2014 and meet the requirements of this paragraph to control NO X emissions from Units 4 and 5. By July 31, 2018, Units 4 and 5 shall be retrofitted with add-on post-combustion NO X controls to reduce NO X emissions. Units 4 and 5 shall each meet a 0.098 lb/MMBtu emission limit for NO X expressed as NO 2 based on a rolling average of 30 successive boiler operating days. A “boiler operating day” is defined as any 24-hour period between 12:00 midnight and the following midnight during which any fuel is combusted at any time at the steam generating unit. Emissions from each unit shall be measured with the 40 CFR part 75 continuous NO X monitor system and expressed in the units of lb/MMBtu and recorded each hour. A valid hour of NO X data shall be determined per 40 CFR part 75. For each boiler operating day, every valid hour of NO X lb/MMBtu measurement shall be averaged to determine a daily average. Each daily average shall be averaged with the preceding 29 valid daily averages to determine the 30 boiler operating day rolling average. The NO X monitoring system shall meet the data requirements of 40 CFR 60.49Da(e)(2) (at least 90 percent valid hours for all operating hours over any 30 successive boiler operating days). Emission testing using 40 CFR part 60 Appendix A Method 7E may be used to supplement any missing data due to continuous monitor problems. The 40 CFR part 75 requirements for bias adjusting and data substitution do not apply for adjusting the data for this emission limit.
(4) By January 1, 2013, the owner or operator shall submit a letter to the Regional Administrator updating EPA of the status of lease negotiations and regulatory approvals required to comply with paragraph (i)(3) of this section. By December 31, 2013, the owner or operator shall notify the Regional Administrator by letter whether it will comply with paragraph (i)(2) of this section or whether it will comply with paragraph (i)(3) of this section and shall submit a plan and time table for compliance with either paragraph (i)(2) or (3) of this section. The owner or operator shall amend and submit this amended plan to the Regional Administrator as changes occur.
(5) The owner or operator shall follow the requirements of 40 CFR part 71 for submitting an application for permit revision to update its Part 71 operating permit after it achieves compliance with paragraph (i)(2) or (3) of this section.
(j) Dust. Each owner or operator shall operate and maintain the existing dust suppression methods for controlling dust from the coal handling and ash handling and storage facilities. Within ninety (90) days after promulgation of this paragraph, the owner or operator shall develop a dust control plan and submit the plan to the Regional Administrator. The owner or operator shall comply with the plan once the plan is submitted to the Regional Administrator. The owner or operator shall amend the plan as requested or needed. The plan shall include a description of the dust suppression methods for controlling dust from the coal handling and storage facilities, ash handling, storage, and landfills, and road sweeping activities. Within 18 months of promulgation of this paragraph each owner or operator shall not emit dust with opacity greater than 20 percent from any crusher, grinding mill, screening operation, belt conveyor, or truck loading or unloading operation.
§ 49.5513   [Reserved]
§ 49.5514   EPA-approved Tribal rules and plans.
(a) Purpose and scope. This section contains the approved implementation plan for the Pechanga Band of Luiseño Mission Indians of the Pechanga Reservation dated May 2014. The plan consists of a redesignation request, a demonstration of maintenance of the 1997 8-hour ozone national ambient air quality standard, and related commitments to continue monitoring and to implement contingency provisions in the event of a monitored violation of the standard.
(b)-(c) [Reserved]
(d) EPA-approved nonregulatory provisions and quasi-regulatory measures.
EPA-Approved Nonregulatory Provisions and Quasi-Regulatory Measures for the Pechanga Band of Luiseño Mission Indians of the Pechanga Reservation
§ 49.5515   Federal implementation plan for Tri-Cities landfill, Salt River Pima-Maricopa Indian Community.
(a) Applicability. This section applies to the owner or operator of the project located on the Reservation of the Salt River Pima Maricopa Indian Community (SRPMIC) in Arizona, including any new owner or operator in the event of a change in ownership of the project.
(b) Definitions. The following definitions apply to this section. Except as specifically defined herein, terms used in this section retain the meaning accorded them under the Clean Air Act.
Actual emissions means the actual rate of emissions of a pollutant from an emissions unit as determined in paragraphs (1)-(3) of this definition:
(1) In general, actual emissions as of a particular date shall equal the average rate, in tons per year, at which the unit actually emitted the pollutant during a two-year period which precedes the particular date and which is representative of normal source operation. EPA shall allow the use of a different time period upon a determination that it is more representative of normal source operation. Actual emissions shall be calculated using the unit's actual operating hours, production rates, and types of materials processed, stored, or combusted during the selected time period.
(2) EPA may presume that the source-specific allowable emissions for the unit are equivalent to the actual emissions of the unit.
(3) For any emissions unit which has not begun normal operations on the particular date, actual emissions shall equal the potential to emit of the unit on that date.
Begin actual construction means, in general, initiation of physical on-site construction activities on an emissions unit which are of a permanent nature. Such activities include, but are not limited to, installation of building supports and foundations, laying of underground pipework, and construction of permanent storage structures. With respect to a change in method of operating this term refers to those on-site activities other than preparatory activities which mark the initiation of the change.
Building, structure, facility, or installation means all of the pollutant-emitting activities which belong to the same industrial grouping, are located on one or more contiguous or adjacent properties, and are under the control of the same person (or persons under common control) except the activities of any vessel. Pollutant-emitting activities shall be considered as part of the same industrial grouping if they belong to the same Major Group ( i.e., which have the same two-digit code) as described in the Standard Industrial Classification Manual, 1972, as amended by the 1977 Supplement (U.S. Government Printing Office stock numbers 4101-0065 and 003-005-00176-0, respectively).
Commence as applied to construction of a major stationary source or major modification means that the owner or operator has all necessary preconstruction approvals or permits and either has: (1) Begun, or caused to begin, a continuous program of actual on-site construction of the source, to be completed within a reasonable time; or
(2) Entered into binding agreements or contractual obligations, which cannot be cancelled or modified without substantial loss to the owner or operator, to undertake a program of actual construction of the source to be completed within a reasonable time.
Construction means any physical change or change in the method of operation (including fabrication, erection, installation, demolition, or modification of an emissions unit) which would result in a change in actual emissions.
EPA means United States Environmental Protection Agency, Region 9.
Fugitive emissions means those emissions which could not reasonably pass through a stack, chimney, vent, or other functionally equivalent opening.
Lowest achievable emission rate means the more stringent rate of emissions based on the following:
(1) The most stringent emissions limitation which is contained in any State, Tribal, or federal implementation plan for such class or category of stationary source, unless the owner or operator of the project demonstrates that such limitations are not achievable; or
(2) The most stringent emissions limitation which is achieved in practice by such class or category of stationary sources. This limitation, when applied to a modification, means the lowest achievable emissions rate for the new or modified emissions units within a stationary source. In no event shall the application of the term permit a proposed new or modified stationary source to emit any pollutant in excess of the amount allowable under an applicable new source standard of performance.
Major stationary source means a stationary source of air pollutants which emits, or has the potential to emit, 100 tons per year or more of any pollutant subject to regulation under the Act. The fugitive emissions of a stationary source shall not be included in determining for any of the purposes of this project whether it is a major stationary source.
Potential to emit means the maximum capacity of a stationary source to emit a pollutant under its physical and operational design. Any physical or operational limitation on the capacity of the source to emit a pollutant, including air pollution control equipment and restrictions on hours of operation or on the type or amount of material combusted, stored, or processed, shall be treated as part of its design only if the limitation or the effect it would have on emissions is federally enforceable. Secondary emissions do not count in determining the potential to emit of a stationary source.
Project means the construction of electricity-generating engines owned and operated by the Salt River Project at the Tri-Cities landfill, which are fueled by collected landfill gas.
Secondary emissions means emissions which would occur as a result of the construction or operation of a major stationary source, but do not come from the major stationary source itself. For the purpose of this section, secondary emissions must be specific, well defined, quantifiable, and impact the same general area as the stationary source which causes the secondary emissions. Secondary emissions include emissions from any offsite support facility which would not be constructed or increase its emissions except as a result of the construction of operation of the major stationary source. Secondary emissions do not include any emissions which come directly from a mobile source such as emissions from the tailpipe of a motor vehicle, from a train, or from a vessel.
Stationary source means any building, structure, facility, or installation which emits or may emit any air pollutant subject to regulation under the Clean Air Act.
(c) Requirement to submit an application. The owner or operator of the project shall submit an application for a permit to construct to EPA which contains all information necessary to perform any analysis or make any determination as required by this Federal Implementation Plan.
(d) Source obligations. (1) The owner or operator of the project shall not begin actual construction on the project without obtaining a nonattainment New Source Review permit regulating emissions of air pollutants. The EPA Region 9 Regional Administrator has the authority to issue such a permit. Any permit issued by EPA shall ensure that the project meets the following requirements:
(i) By the time the project is to commence operation, the owner or operator of the project must have obtained sufficient reductions in actual emissions from existing facilities within the same nonattainment area which satisfy the requirements of section 173 of the Clean Air Act, to offset the potential to emit of the project;
(ii) The owner or operator of the project must comply with the lowest achievable emissions rate;
(iii) The owner or operator of the project must demonstrate that all major stationary sources owned or operated by such person (or by any entity controlling, controlled by, or under common control with such person) located on the reservation of the SRPMIC are subject to emission limitations and are in compliance, or on a schedule for compliance, with all applicable emission limitations and standards under the Act; and
(iv) The owner or operator of the project has provided an analysis of alternative sites, sizes, production processes, and environmental control techniques for the proposed source which demonstrates that benefits of the proposed source significantly outweigh the environmental and social costs imposed as a result of its location or construction.
(2) If the owner or operator constructs or operates the project not in accordance with the application submitted pursuant to this section or with the terms of any approval to construct, or if the owner or operator subject to this section commences construction after January 24 , 2000 without applying for and receiving approval under this section, then the owner or operator shall be subject to appropriate enforcement action.
(3) Approval to construct shall become invalid if construction is not commenced within 18 months after receipt of such approval, if construction is discontinued for a period of 18 months or more, or if construction is not completed within a reasonable time. The Administrator may extend the 18-month period upon a satisfactory showing that an extension is justified.
(4) Approval to construct shall not relieve any owner or operator of the responsibility to comply fully with applicable provisions of the Federal implementation plan and any other requirements under Tribal or Federal law.
(e) Public participation. (1) When issuing a permit for the project, the EPA Region 9 Regional Administrator shall follow the procedures for decision making for PSD permits contained in 40 CFR part 124, including the requirements for public notice, consideration of and response to public comment, and the opportunity for public hearing.
(2) Within 30 days after the EPA Region 9 Regional Administrator has issued a final permit decision, any person who filed comments on the draft permit or participated in the public hearing, if one has been held, may petition the Environmental Appeals Board to review any condition of the permit. Review of the permit decision will be governed by the regulations for review of PSD permits contained in 40 CFR part 124.
§§ 49.5516-49.9860   [Reserved]
§ 49.9861   Identification of plan.
This section and §§ 49.9862 through 49.9890 contain the implementation plan for the Burns Paiute Tribe of the Burns Paiute Indian Colony. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Reservation of the Burns Paiute Indian Colony.
§ 49.9862   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Reservation of the Burns Paiute Indian Colony.
§ 49.9863   Legal authority. [Reserved]
§ 49.9864   Source surveillance. [Reserved]
§ 49.9865   Classification of regions for episode plans.
The air quality control region which encompasses the Reservation of the Burns Paiute Indian Colony is classified as follows for purposes of episode plans:
§ 49.9866   Contents of implementation plan.
The implementation plan for the Reservation of the Burns Paiute Indian Colony consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.9867   EPA-approved Tribal rules and plans. [Reserved]
§ 49.9868   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.9869   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR Part 71 in accordance with the requirements of § 49.139.
§ 49.9870   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Reservation of the Burns Paiute Indian Colony:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§§ 49.9871-49.9890   [Reserved]
§ 49.9891   Identification of plan.
This section and §§ 49.9892 through 49.9920 contain the implementation plan for the Confederated Tribes of the Chehalis Reservation. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Chehalis Reservation.
§ 49.9892   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Chehalis Reservation.
§ 49.9893   Legal authority. [Reserved]
§ 49.9894   Source surveillance. [Reserved]
§ 49.9895   Classification of regions for episode plans.
The air quality control region which encompasses the Chehalis Reservation is classified as follows for purposes of episode plans:
§ 49.9896   Contents of implementation plan.
The implementation plan for the Chehalis Reservation consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.9897   EPA-approved Tribal rules and plans. [Reserved]
§ 49.9898   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.9899   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR Part 71 in accordance with the requirements of § 49.139.
§ 49.9900   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Chehalis Reservation:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§§ 49.9901-49.9920   [Reserved]
§ 49.9921   Identification of plan.
This section and §§ 49.9922 through 49.9950 contain the implementation plan for the Coeur D'Alene Tribe of the Coeur D'Alene Reservation. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Coeur D'Alene Reservation.
§ 49.9922   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Coeur D'Alene Reservation.
§ 49.9923   Legal authority. [Reserved]
§ 49.9924   Source surveillance. [Reserved]
§ 49.9925   Classification of regions for episode plans.
The air quality control region which encompasses the Coeur D'Alene Reservation is classified as follows for purposes of episode plans:
§ 49.9926   Contents of implementation plan.
The implementation plan for the Coeur D'Alene Reservation consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.9927   EPA-approved Tribal rules and plans. [Reserved]
§ 49.9928   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.9929   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR Part 71 in accordance with the requirements of § 49.139.
§ 49.9930   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Coeur D'Alene Reservation:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
EPA entered into a Partial Delegation of Administrative Authority with the Coeur d'Alene Tribe on August 26, 2008 for the rules listed in paragraphs (b), (g), and (i) of this section.
§§ 49.9931-49.9950   [Reserved]
§ 49.9951   Identification of plan.
This section and §§ 49.9952 through 49.9980 contain the implementation plan for the Confederated Tribes of the Colville Reservation. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Colville Reservation.
§ 49.9952   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Colville Reservation.
§ 49.9953   Legal authority. [Reserved]
§ 49.9954   Source surveillance. [Reserved]
§ 49.9955   Classification of regions for episode plans.
The air quality control region which encompasses the Colville Reservation is classified as follows for purposes of episode plans:
§ 49.9956   Contents of implementation plan.
The implementation plan for the Colville Reservation consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.127 Rule for woodwaste burners.
(f) Section 49.128 Rule for limiting particulate matter emissions from wood products industry sources.
(g) Section 49.129 Rule for limiting emissions of sulfur dioxides.
(h) Section 49.130 Rule for limiting sulfur in fuels.
(i) Section 49.131 General rule for open burning.
(j) Section 49.135 Rule for emissions detrimental to public health or welfare.
(k) Section 49.137 Rule for air pollution episodes.
(l) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(m) Section 49.139 Rule for non-Title V operating permits.
§ 49.9957   EPA-approved Tribal rules and plans. [Reserved]
§ 49.9958   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.9959   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR part 71 in accordance with the requirements of § 49.139.
§ 49.9960   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Colville Reservation:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.127 Rule for woodwaste burners.
(f) Section 49.128 Rule for limiting particulate matter emissions from wood products industry sources.
(g) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(h) Section 49.130 Rule for limiting sulfur in fuels.
(i) Section 49.131 General rule for open burning.
(j) Section 49.135 Rule for emissions detrimental to public health or welfare.
(k) Section 49.137 Rule for air pollution episodes.
(l) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(m) Section 49.139 Rule for non-Title V operating permits.
The EPA entered into a Partial Delegation of Administrative Authority with the Confederated Tribes of the Colville Reservation on October 26, 2015 for the rules listed in paragraphs (b), (i), and (k) of this section.
§§ 49.9961-49.9980   [Reserved]
§ 49.9981   Identification of plan.
This section and §§ 49.9982 through 49.10010 contain the implementation plan for the Confederated Tribes of the Coos, Lower Umpqua and Siuslaw Indians. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Reservation of the Confederated Tribes of the Coos, Lower Umpqua and Siuslaw Indians.
§ 49.9982   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Reservation of the Confederated Tribes of the Coos, Lower Umpqua and Siuslaw Indians.
§ 49.9983   Legal authority. [Reserved]
§ 49.9984   Source surveillance. [Reserved]
§ 49.9985   Classification of regions for episode plans.
The air quality control region which encompasses the Reservation of the Confederated Tribes of the Coos, Lower Umpqua and Siuslaw Indians is classified as follows for purposes of episode plans:
§ 49.9986   Contents of implementation plan.
The implementation plan for the Reservation of the Confederated Tribes of the Coos, Lower Umpqua and Siuslaw Indians consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.9987   EPA-approved Tribal rules and plans. [Reserved]
§ 49.9988   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.9989   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR Part 71 in accordance with the requirements of § 49.139.
§ 49.9990   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Reservation of the Confederated Tribes of the Coos, Lower Umpqua and Siuslaw Indians:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§§ 49.9991-49.10010   [Reserved]
§ 49.10011   Identification of plan.
This section and § 49.10012 through 49.10040 contain the implementation plan for the Coquille Tribe. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Reservation of the Coquille Tribe.
§ 49.10012   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Reservation of the Coquille Tribe.
§ 49.10013   Legal authority. [Reserved]
§ 49.10014   Source surveillance. [Reserved]
§ 49.10015   Classification of regions for episode plans.
The air quality control region which encompasses the Reservation of the Coquille Tribe is classified as follows for purposes of episode plans:
§ 49.10016   Contents of implementation plan.
The implementation plan for the Reservation of the Coquille Tribe consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.10017   EPA-approved Tribal rules and plans. [Reserved]
§ 49.10018   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.10019   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR Part 71 in accordance with the requirements of § 49.139.
§ 49.10020   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Reservation of the Coquille Tribe:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§§ 49.10021-49.10040   [Reserved]
§ 49.10041   Identification of plan.
This section and §§ 49.10042 through 49.10100 contain the implementation plan for the Cow Creek Band of Umpqua Indians. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Reservation of the Cow Creek Band of Umpqua Indians.
§ 49.10042   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Reservation of the Cow Creek Band of Umpqua Indians.
§ 49.10043   Legal authority. [Reserved]
§ 49.10044   Source surveillance. [Reserved]
§ 49.10045   Classification of regions for episode plans.
The air quality control region which encompasses the Reservation of the Cow Creek Band of Umpqua Indians is classified as follows for purposes of episode plans:
§ 49.10046   Contents of implementation plan.
The implementation plan for the Reservation of the Cow Creek Band of Umpqua Indians consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.10047   EPA-approved Tribal rules and plans. [Reserved]
§ 49.10048   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.10049   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR Part 71 in accordance with the requirements of § 49.139.
§ 49.10050   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Reservation of the Cow Creek Band of Umpqua Indians:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§§ 49.10051-49.10100   [Reserved]
§ 49.10101   Identification of plan.
This section and §§ 49.10102 through 49.10130 contain the implementation plan for the Confederated Tribes of the Grand Ronde Community. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Reservation of the Confederated Tribes of the Grand Ronde Community.
§ 49.10102   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Reservation of the Confederated Tribes of the Grand Ronde Community.
§ 49.10103   Legal authority. [Reserved]
§ 49.10104   Source surveillance. [Reserved]
§ 49.10105   Classification of regions for episode plans.
The air quality control region which encompasses the Reservation of the Confederated Tribes of the Grand Ronde Community is classified as follows for purposes of episode plans:
§ 49.10106   Contents of implementation plan.
The implementation plan for the Reservation of the Confederated Tribes of the Grand Ronde Community consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.10107   EPA-approved Tribal rules and plans. [Reserved]
§ 49.10108   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.10109   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR part 71 in accordance with the requirements of § 49.139.
§ 49.10110   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Reservation of the Confederated Tribes of the Grand Ronde Community:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§§ 49.10111-49.10130   [Reserved]
§ 49.10131   Identification of plan.
This section and §§ 49.10132 through 49.10160 contain the implementation plan for the Hoh Indian Tribe of the Hoh Indian Reservation. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Hoh Indian Reservation.
§ 49.10132   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Hoh Indian Reservation.
§ 49.10133   Legal authority. [Reserved]
§ 49.10134   Source surveillance. [Reserved]
§ 49.10135   Classification of regions for episode plans.
The air quality control region which encompasses the Hoh Indian Reservation is classified as follows for purposes of episode plans:
§ 49.10136   Contents of implementation plan.
The implementation plan for the Hoh Indian Reservation consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.10137   EPA-approved Tribal rules and plans. [Reserved]
§ 49.10138   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.10139   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR Part 71 in accordance with the requirements of § 49.139.
§ 49.10140   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Hoh Indian Reservation:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§§ 49.10141-49.10160   [Reserved]
§ 49.10161   Identification of plan.
This section and §§ 49.10162 through 49.10190 contain the implementation plan for the Jamestown S'Klallam Tribe. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Reservation of the Jamestown S'Klallam Tribe.
§ 49.10162   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Reservation of the Jamestown S'Klallam Tribe.
§ 49.10163   Legal authority. [Reserved]
§ 49.10164   Source surveillance. [Reserved]
§ 49.10165   Classification of regions for episode plans.
The air quality control region which encompasses the Reservation of the Jamestown S'Klallam Tribe is classified as follows for purposes of episode plans:
§ 49.10166   Contents of implementation plan.
The implementation plan for the Reservation of the Jamestown S'Klallam Tribe consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.10167   EPA-approved Tribal rules and plans. [Reserved]
§ 49.10168   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.10169   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR Part 71 in accordance with the requirements of § 49.139.
§ 49.10170   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Reservation of the Jamestown S'Klallam Tribe:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§§ 49.10171-49.10190   [Reserved]
§ 49.10191   Identification of plan.
This section and §§ 49.1019192 through 49.10220 contain the implementation plan for the Kalispel Indian Community. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Kalispel Reservation.
§ 49.10192   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Kalispel Reservation.
§ 49.10193   Legal authority. [Reserved]
§ 49.10194   Source surveillance. [Reserved]
§ 49.10195   Classification of regions for episode plans.
The air quality control region which encompasses the Kalispel Reservation is classified as follows for purposes of episode plans:
§ 49.10196   Contents of implementation plan.
The implementation plan for the Kalispel Reservation consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.10197   EPA-approved Tribal rules and plans. [Reserved]
§ 49.10198   Permits to construct.
(a) Permits to construct are required for new major stationary sources and major modifications to existing stationary sources pursuant to 40 CFR 52.21.
(b) In accordance with section 164 of the Clean Air Act and the provisions of 40 CFR 52.21(g), the original Kalispel Reservation, as established by Executive Order No. 1904, signed by President Woodrow Wilson on March 23, 1914, is designated as a Class I area for the purposes of prevention of significant deterioration of air quality.
§ 49.10199   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR Part 71 in accordance with the requirements of § 49.139.
§ 49.10200   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Kalispel Reservation:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§§ 49.10201-49.10220   [Reserved]
§ 49.10221   Identification of plan.
This section and §§ 49.10222 through 49.10250 contain the implementation plan for the Klamath Indian Tribe. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Reservation of the Klamath Indian Tribe.
§ 49.10222   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Reservation of the Klamath Indian Tribe.
§ 49.10223   Legal authority. [Reserved]
§ 49.10224   Source surveillance. [Reserved]
§ 49.10225   Classification of regions for episode plans.
The air quality control region which encompasses the Reservation of the Klamath Indian Tribe is classified as follows for purposes of episode plans:
§ 49.10226   Contents of implementation plan.
The implementation plan for the Reservation of the Klamath Indian Tribe consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.10227   EPA-approved Tribal rules and plans. [Reserved]
§ 49.10228   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.10229   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR Part 71 in accordance with the requirements of § 49.139.
§ 49.10230   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Reservation of the Klamath Indian Tribe:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§§ 49.10231-49.10250   [Reserved]
§ 49.10251   Identification of plan.
This section and §§ 49.10252 through 49.10280 contain the implementation plan for the Kootenai Tribe of Idaho. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Reservation of the Kootenai Tribe of Idaho.
§ 49.10252   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Reservation of the Kootenai Tribe of Idaho.
§ 49.10253   Legal authority. [Reserved]
§ 49.10254   Source surveillance. [Reserved]
§ 49.10255   Classification of regions for episode plans.
The air quality control region which encompasses the Reservation of the Kootenai Tribe of Idaho is classified as follows for purposes of episode plans:
§ 49.10256   Contents of implementation plan.
The implementation plan for the Reservation of the Kootenai Tribe of Idaho consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.10257   EPA-approved Tribal rules and plans. [Reserved]
§ 49.10258   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.10259   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR Part 71 in accordance with the requirements of § 49.139.
§ 49.10260   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Reservation of the Kootenai Tribe of Idaho:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§§ 49.10261-49.10280   [Reserved]
§ 49.10281   Identification of plan.
This section and §§ 49.10282 through 49.10310 contain the implementation plan for the Lower Elwha Tribal Community. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Lower Elwha Reservation.
§ 49.10282   Approval status.
There are currently no EPA-approved Tribal rules or measures in the implementation plan for the Lower Elwha Reservation.
§ 49.10283   Legal authority. [Reserved]
§ 49.10284   Source surveillance. [Reserved]
§ 49.10285   Classification of regions for episode plans.
The air quality control region which encompasses the Lower Elwha Reservation is classified as follows for purposes of episode plans:
§ 49.10286   Contents of implementation plan.
The implementation plan for the Lower Elwha Reservation consists of the following rules, regulations, and measures:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§ 49.10287   EPA-approved Tribal rules and plans. [Reserved]
§ 49.10288   Permits to construct.
Permits to construct are required for new major stationary sources and major modifications to existing major stationary sources pursuant to 40 CFR 52.21.
§ 49.10289   Permits to operate.
Permits to operate are required for sources not subject to 40 CFR Part 71 in accordance with the requirements of § 49.139.
§ 49.10290   Federally-promulgated regulations and Federal implementation plans.
The following regulations are incorporated and made part of the implementation plan for the Lower Elwha Reservation:
(a) Section 49.123 General provisions.
(b) Section 49.124 Rule for limiting visible emissions.
(c) Section 49.125 Rule for limiting the emissions of particulate matter.
(d) Section 49.126 Rule for limiting fugitive particulate matter emissions.
(e) Section 49.129 Rule for limiting emissions of sulfur dioxide.
(f) Section 49.130 Rule for limiting sulfur in fuels.
(g) Section 49.131 General rule for open burning.
(h) Section 49.135 Rule for emissions detrimental to public health or welfare.
(i) Section 49.137 Rule for air pollution episodes.
(j) Section 49.138 Rule for the registration of air pollution sources and the reporting of emissions.
(k) Section 49.139 Rule for non-Title V operating permits.
§§ 49.10291-49.10310   [Reserved]
§ 49.10311   Identification of plan.
This section and §§ 49.10312 through 49.10340 contain the implementation plan for the Lummi Tribe. This plan consists of a combination of Tribal rules and measures and Federal regulations and measures which apply within the Lummi Reservation.