Title 40—Protection of Environment--Volume 1
PART 60—STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
§ 60.5430c   What definitions apply to this subpart?
As used in this subpart, all terms not defined herein shall have the meaning given them in the Act or in subpart A of this part; and the following terms shall have the specific meanings given them.
Access to electrical power means commercial line power is available onsite, with sufficient capacity to support the required power loading of onsite equipment, and which provides reliable and consistent power.
Acid gas means a gas stream of hydrogen sulfide (H 2 S) and carbon dioxide (CO 2 ) that has been separated from sour natural gas by a sweetening unit.
Alaskan North Slope means the approximately 69,000 square-mile area extending from the Brooks Range to the Arctic Ocean.
API Gravity means the weight per unit volume of hydrocarbon liquids as measured by a system recommended by the American Petroleum Institute (API) and is expressed in degrees.
Artificial lift equipment means mechanical pumps including, but not limited to, rod pumps and electric submersible pumps used to flowback fluids from a well.
Associated gas means the natural gas from wells operated primarily for oil production that is released from the liquid hydrocarbon during the initial stage of separation after the wellhead. Associated gas production begins at the startup of production after the flow back period ends. Gas from wildcat or delineation wells is not associated gas.
Average aggregate detection threshold means:
(1) For the purposes of § 60.5398c, the average of all site-level detection thresholds from a single deployment ( e.g., a singular flight that surveys multiple well sites, centralized production facility, and/or compressor stations) of a technology; and
(2) For the purposes of § 60.5388c, the average of all site-level detection thresholds from a single deployment in the same basin and field.
Bleed rate means the rate in standard cubic feet per hour at which natural gas is continuously vented (bleeds) from a process controller.
Capital expenditure means, as an alternative to the definition in § 60.2, an expenditure for a physical or operational change to an existing facility that:
(1) Exceeds P, the product of the facility's replacement cost, R, and an adjusted annual asset guideline repair allowance, A, as reflected by the following equation: P = R × A, where:
(i) The adjusted annual asset guideline repair allowance, A, is the product of the percent of the replacement cost, Y, and the applicable basic annual asset guideline repair allowance, B, divided by 100 as reflected by the following equation: A = Y × (B ÷ 100);
(ii) The percent Y is determined from the following equation: Y = (CPI of date of construction/most recently available CPI of date of project), where the “CPI-U, U.S. city average, all items” must be used for each CPI value; and
(iii) The applicable basic annual asset guideline repair allowance, B, is 4.5.
(2) [Reserved]
Centralized production facility means one or more storage vessels and all equipment at a single surface site used to gather, for the purpose of sale or processing to sell, crude oil, condensate, produced water, or intermediate hydrocarbon liquid from one or more offsite natural gas or oil production wells. This equipment includes, but is not limited to, equipment used for storage, separation, treating, dehydration, artificial lift, combustion, compression, pumping, metering, monitoring, and flowline. Process vessels and process tanks are not considered storage vessels or storage tanks. A centralized production facility is located upstream of the natural gas processing plant or the crude oil pipeline breakout station and is a part of producing operations.
Centrifugal compressor means any machine for raising the pressure of a natural gas by drawing in low pressure natural gas and discharging significantly higher-pressure natural gas by means of mechanical rotating vanes or impellers. Screw, sliding vane, and liquid ring compressors are not centrifugal compressors for the purposes of this subpart.
Centrifugal compressor equipped with sour seal oil separator and capture system means a wet seal centrifugal compressor system which has an intermediate closed process that degasses most of the gas entrained in the sour seal oil and sends that gas to either another process or combustion device ( i.e., degassed emissions are recovered). The de-gas emissions are routed back to a process or combustion device directly from the intermediate closed degassing process; after the intermediate closed process the oil is ultimately recycled for recirculation in the seals to the lube oil tank where any small amount of residual gas is released through a vent.
Certifying official means one of the following:
(1) For a corporation: A president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function, or any other person who performs similar policy or decision-making functions for the corporation, or a duly authorized representative of such person if the representative is responsible for the overall operation of one or more manufacturing, production, or operating facilities with a designated facility subject to this subpart and either:
(i) The facilities employ more than 250 persons or have gross annual sales or expenditures exceeding $25 million (in second quarter 1980 dollars); or
(ii) The Administrator is notified of such delegation of authority prior to the exercise of that authority. The Administrator reserves the right to evaluate such delegation;
(2) For a partnership (including but not limited to general partnerships, limited partnerships, and limited liability partnerships) or sole proprietorship: A general partner or the proprietor, respectively. If a general partner is a corporation, the provisions of paragraph (1) of this definition apply;
(3) For a municipality, State, Federal, or other public agency: Either a principal executive officer or ranking elected official. For the purposes of this part, a principal executive officer of a Federal agency includes the chief executive officer having responsibility for the overall operations of a principal geographic unit of the agency ( e.g., a Regional Administrator of EPA); or
(4) For designated facilities:
(i) The designated representative in so far as actions, standards, requirements, or prohibitions under title IV of the CAA or the regulations promulgated thereunder are concerned; or
(ii) The designated representative for any other purposes under this part.
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 gas or vapor from a piece or pieces of equipment to a control device or back to a process.
Coil tubing cleanout means the process where an operator runs a string of coil tubing to the packed proppant within a well and jets the well to dislodge the proppant and provide sufficient lift energy to flow it to the surface. Coil tubing cleanout includes mechanical methods to remove solids and/or debris from a wellbore.
Collection system means any infrastructure that conveys gas or liquids from the well site to another location for treatment, storage, processing, recycling, disposal, or other handling.
Completion combustion device means any ignition device, installed horizontally or vertically, used in exploration and production operations to combust otherwise vented emissions from completions. Completion combustion devices include pit flares.
Compressor mode means the operational and pressurized status of a compressor. For both centrifugal compressors and reciprocating compressors, “mode” refers to either: Operating-mode, standby-pressurized-mode, or not-operating-depressurized-mode.
Compressor station means any permanent combination of one or more compressors that move natural gas at increased pressure through gathering or transmission pipelines, or into or out of storage. This includes, but is not limited to, gathering and boosting stations and transmission compressor stations. The combination of one or more compressors located at a well site, centralized production facility, or an onshore natural gas processing plant, is not a compressor station for purposes of § 60.5386c(e) and § 60.5397c.
Condensate means hydrocarbon liquid separated from natural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at standard conditions.
Connector means flanged, screwed, or other joined fittings used to connect two pipe lines or a pipe line and a piece of process equipment or that close an opening in a pipe that could be connected to another pipe. Joined fittings welded completely around the circumference of the interface are not considered connectors for the purpose of this regulation.
Continuous bleed means a continuous flow of pneumatic supply natural gas to a process controller.
Crude oil and natural gas source category means:
(1) Crude oil production, which includes the well and extends to the point of custody transfer to the crude oil transmission pipeline or any other forms of transportation; and
(2) Natural gas production, processing, transmission, and storage, which include the well and extend to, but do not include, the local distribution company custody transfer station.
Custody meter means the meter where natural gas or hydrocarbon liquids are measured for sales, transfers, and/or royalty determination.
Custody meter assembly means an assembly of fugitive emissions components, including the custody meter, valves, flanges, and connectors necessary for the proper operation of the custody meter.
Custody transfer means the transfer of crude oil or natural gas after processing and/or treatment in the producing operations, or from storage vessels or automatic transfer facilities or other such equipment, including product loading racks, to pipelines or any other forms of transportation.
Dehydrator means a device in which an absorbent directly contacts a natural gas stream and absorbs water in a contact tower or adsorption column (absorber).
Delineation well means a well drilled in order to determine the boundary of a field or producing reservoir.
Deviation means any instance in which a designated source subject to this subpart, or an owner or operator of such a source:
(1) Fails to meet any requirement or obligation established by this subpart including, but not limited to, any emission limit, operating limit, or work practice standard;
(2) Fails to meet any term or condition that is adopted to implement an applicable requirement in this subpart and that is included in the operating permit for any designated source required to obtain such a permit; or
(3) Fails to meet any emission limit, operating limit, or work practice standard of this subpart during startup, shutdown, or malfunction, regardless of whether or not such failure is permitted by this subpart.
Distance piece means an open or enclosed casing through which the piston rod travels, separating the compressor cylinder from the crankcase.
Double block and bleed system means two block valves connected in series with a bleed valve or line that can vent the line between the two block valves.
Duct work means a conveyance system such as those commonly used for heating and ventilation systems. It is often made of sheet metal and often has sections connected by screw or crimping. Hard-piping is not ductwork.
Emergency shutdown device means a device which functions exclusively to protect personnel and/or prevent physical damage to equipment by shutting down equipment or gas flow during unsafe conditions resulting from an unexpected event, such as a pipe break or fire. For the purposes of this subpart, an emergency shutdown device is not used for routine control of operating conditions.
Equipment, as used in the standards and requirements of this subpart relative to the process unit equipment designated facility at onshore natural gas processing plants, means each pump, pressure relief device, open-ended valve or line, valve, and flange or other connector that has the potential to emit methane and any device or system required by those same standards and requirements of this subpart.
Field gas means feedstock gas entering the natural gas processing plant.
Field gas gathering means the system used transport field gas from a field to the main pipeline in the area.
First attempt at repair means an action taken for the purpose of stopping or reducing fugitive emissions to the atmosphere. First attempts at repair include, but are not limited to, the following practices where practicable and appropriate: Tightening bonnet bolts; replacing bonnet bolts; tightening packing gland nuts; or injecting lubricant into lubricated packing.
Flare means a thermal oxidation system using an open (without enclosure) flame. Completion combustion devices as defined in this section are not considered flares.
Flow line means a pipeline used to transport oil and/or gas to a processing facility or a mainline pipeline.
Flowback means the process of allowing fluids and entrained solids to flow from a well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for cleanup and returning the well to production. The term flowback also means the fluids and entrained solids that emerge from a well during the flowback process. The flowback period begins when material introduced into the well during the treatment returns to the surface following hydraulic fracturing or refracturing. The flowback period ends when either the well is shut in and permanently disconnected from the flowback equipment or at the startup of production. The flowback period includes the initial flowback stage and the separation flowback stage. Screenouts, coil tubing cleanouts, and plug drill-outs are not considered part of the flowback process.
Fuel gas means gases that are combusted to derive useful work or heat.
Fuel gas system means the offsite and onsite piping and flow and pressure control system that gathers gaseous stream(s) generated by onsite operations, may blend them with other sources of gas, and transports the gaseous stream for use as fuel gas in combustion devices or in-process combustion equipment, such as furnaces and gas turbines, either singly or in combination.
Fugitive emissions means, for the purposes of § 60.5397c, any indication of emissions observed from a fugitive emissions component using AVO, an indication of visible emissions observed from an OGI instrument, or an instrument reading of 500 ppmv or greater using Method 21 of appendix A-7 to this part.
Fugitive emissions component means any component that has the potential to emit fugitive emissions of methane at a well site, centralized production facility, or compressor station, such as valves (including separator dump valves), connectors, pressure relief devices, open-ended lines, flanges, covers and closed vent systems not subject to § 60.5411c, thief hatches or other openings on a storage vessel not subject to § 60.5396c, compressors, instruments, meters, and yard piping.
Gas to oil ratio (GOR) means the ratio of the volume of gas at standard temperature and pressure that is produced from a volume of oil when depressurized to standard temperature and pressure.
Hard-piping means pipe or tubing that is manufactured and properly installed using good engineering judgment and standards such as ASME B31.3, Process Piping (available from the American Society of Mechanical Engineers, P.O. Box 2300, Fairfield, NJ 07007-2300).
Hydraulic fracturing means the process of directing pressurized fluids containing any combination of water, proppant, and any added chemicals to penetrate tight formations, such as shale or coal formations, that subsequently require high rate, extended flowback to expel fracture fluids and solids during completions.
Hydraulic refracturing means conducting a subsequent hydraulic fracturing operation at a well that has previously undergone a hydraulic fracturing operation.
In gas/vapor service means that the piece of equipment contains process fluid that is in the gaseous state at operating conditions.
In heavy liquid service means that the piece of equipment is not in gas/vapor service or in light liquid service.
In light liquid service means that the piece of equipment contains a liquid that meets the conditions specified in § 60.5402c(d)(2) or § 60.5406c.
In vacuum service means that equipment is operating at an internal pressure which is at least 5 kilopascals (kPa) (0.7 psia) below ambient pressure.
In wet gas service means that a compressor or piece of equipment contains or contacts the field gas before the extraction step at a gas processing plant process unit.
Initial calibration value, as used in the standards and requirements of this subpart relative to the process unit equipment designated facility at onshore natural gas processing plants, means the concentration measured during the initial calibration at the beginning of each day required in § 60.5406c, or the most recent calibration if the instrument is recalibrated during the day ( i.e., the calibration is adjusted) after a calibration drift assessment.
Initial flowback stage means the period during a well completion operation which begins at the onset of flowback and ends at the separation flowback stage.
Intermediate hydrocarbon liquid means any naturally occurring, unrefined petroleum liquid.
Intermittent vent natural gas-driven process controller means a process controller that is not designed to have a continuous bleed rate but is instead designed to only release natural gas to the atmosphere as part of the actuation cycle.
Liquefied natural gas unit means a unit used to cool natural gas to the point at which it is condensed into a liquid which is colorless, odorless, non-corrosive and non-toxic.
Liquid collection system means tankage and/or lines at a well site to contain liquids from one or more wells or to convey liquids to another site.
Liquids dripping means any visible leakage from the seal, including spraying, misting, clouding, and ice formation.
Liquids unloading means the unloading of liquids that have accumulated over time in gas wells, which are impeding or halting production. Routine well maintenance activities, including workovers, screenouts, coil tubing cleanouts, or any other activity that requires a rig or other machinery are not considered liquids unloading.
Local distribution company (LDC) custody transfer station means a metering station where the LDC receives a natural gas supply from an upstream supplier, which may be an interstate transmission pipeline or a local natural gas producer, for delivery to customers through the LDC's intrastate transmission or distribution lines.
Low-e valve means a valve (including its specific packing assembly) for which the manufacturer has issued a written warranty or performance guarantee that it will not emit fugitives at greater than 100 ppm in the first five years. A valve may qualify as a low-e valve if it is as an extension of another valve that has qualified as a low-e valve.
Low-e packing means a valve packing product for which the manufacturer has issued a written warranty or performance guarantee that it will not emit fugitives at greater than 100 ppm in the first five years. Low-e injectable packing is a type of low-e packing product for which the manufacturer has also issued a written warranty or performance guarantee and that can be injected into a valve during a “drill-and-tap” repair of the valve.
Major production and processing equipment means reciprocating or centrifugal compressors, glycol dehydrators, heater/treaters, separators, control devices, natural gas-driven process controllers, natural gas-driven pumps, and storage vessels or tank batteries collecting crude oil, condensate, intermediate hydrocarbon liquids, or produced water, for the purpose of determining whether a well site is a wellhead only well site.
Maximum average daily throughput means the following:
(1) The earliest calculation of daily average throughput, determined as described in paragraph (2) or (3) of this definition, to a tank battery over the days that production is routed to that tank battery during the 30-day PTE evaluation period employing generally accepted methods specified in § 60.5386c(e)(2).
(2) If throughput to the tank battery is measured on a daily basis ( e.g., via level gauge automation or daily manual gauging), the maximum average daily throughput is the average of all daily throughputs for days on which throughput was routed to the tank battery during the 30-day evaluation period; or
(3) If throughput to the tank battery is not measured on a daily basis ( e.g., via manual gauging at the start and end of loadouts), the maximum average daily throughput is the highest, of the average daily throughputs, determined for any production period to that tank battery during the 30-day evaluation period, as determined by averaging total throughput to that tank battery over each production period. A production period begins when production begins to be routed to a tank battery and ends either when throughput is routed away from that tank battery or when a loadout occurs from that tank battery, whichever happens first. Regardless of the determination methodology, operators must not include days during which throughput is not routed to the tank battery when calculating maximum average daily throughput for that tank battery.
Multi-wellhead only well site means a well site that contains two or more wellheads and no major production and processing equipment.
Natural gas-driven diaphragm pump means a positive displacement pump powered by pressurized natural gas that uses the reciprocating action of flexible diaphragms in conjunction with check valves to pump a fluid. A pump in which a fluid is displaced by a piston driven by a diaphragm is not considered a diaphragm pump for purposes of this subpart. A lean glycol circulation pump that relies on energy exchange with the rich glycol from the contactor is not considered a diaphragm pump.
Natural gas-driven piston pump means a positive displacement pump powered by pressurized natural gas that moves and pressurizes fluid by using one or more reciprocating pistons. A pump in which a fluid is displaced by a piston driven by a diaphragm is considered a piston pump for purposes of this subpart. A lean glycol circulation pump that relies on energy exchange with the rich glycol from the contactor is not considered a piston pump.
Natural gas-driven process controller means a process controller powered by pressurized natural gas.
Natural gas liquids means the hydrocarbons, such as ethane, propane, butane, and pentane that are extracted from field gas.
Natural gas processing plant (gas plant) means any processing site engaged in the extraction of natural gas liquids from field gas, fractionation of mixed natural gas liquids to natural gas products, or both. A Joule-Thompson valve, a dew point depression valve, or an isolated or standalone Joule-Thompson skid is not a natural gas processing plant.
Natural gas transmission means the pipelines used for the long-distance transport of natural gas (excluding processing). Specific equipment used in natural gas transmission includes the land, mains, valves, meters, boosters, regulators, storage vessels, dehydrators, compressors, and their driving units and appurtenances, and equipment used for transporting gas from a production plant, delivery point of purchased gas, gathering system, storage area, or other wholesale source of gas to one or more distribution area(s).
No detectable emissions means, for the purposes of §§ 60.5401c and 60.5406c, that the equipment is operating with an instrument reading of less than 500 ppmv above background, as determined by Method 21 of appendix A-7 to this part.
No identifiable emissions means, for the purposes of covers, closed vent systems, and self-contained natural gas-driven process controllers and as determined according to the provisions of § 60.5416c, that no emissions are detected by AVO means when inspections are conducted by AVO; no emissions are imaged with an OGI camera when inspections are conducted with OGI; and equipment is operating with an instrument reading of less than 500 ppmv above background, as determined by Method 21 of appendix A-7 to this part when inspections are conducted with Method 21.
Nonfractionating plant means any gas plant that does not fractionate mixed natural gas liquids into natural gas products.
Non-natural gas-driven process controller means an instrument that is actuated using other sources of power than pressurized natural gas; examples include solar, electric, and instrument air.
Onshore means all facilities except those that are located in the territorial seas or on the outer continental shelf.
Open-ended valve or line or open-ended vent line means any valves, except safety relief valves, having one side of the valve seat in contact with process fluid and one side open to the atmosphere, either directly or through open piping.
Plug drill-out means the removal of a plug (or plugs) that was used to isolate different sections of the well.
Process controller means an automated instrument used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature.
Pressure release means the emission of materials resulting from system pressure being greater than set pressure of the pressure relief device.
Pressure vessel means a storage vessel that is used to store liquids or gases and is designed not to vent to the atmosphere as a result of compression of the vapor headspace in the pressure vessel during filling of the pressure vessel to its design capacity.
Pressurized mode means when the compressor contains natural gas that is maintained at a pressure higher than the atmospheric pressure.
Process improvement means routine changes made for safety and occupational health requirements, for energy savings, for better utility, for ease of maintenance and operation, for correction of design deficiencies, for bottleneck removal, for changing product requirements, or for environmental control.
Process unit means components assembled for the extraction of natural gas liquids from field gas, the fractionation of the liquids into natural gas products, or other operations associated with the processing of natural gas products. A process unit can operate independently if supplied with sufficient feed or raw materials and sufficient storage facilities for the products.
Process unit shutdown means a work practice or operational procedure that stops production from a process unit or part of a process unit during which it is technically feasible to clear process material from a process unit or part of a process unit consistent with safety constraints and during which repairs can be accomplished. The following are not considered process unit shutdowns:
(1) An unscheduled work practice or operational procedure that stops production from a process unit or part of a process unit for less than 24 hours.
(2) An unscheduled work practice or operational procedure that would stop production from a process unit or part of a process unit for a shorter period of time than would be required to clear the process unit or part of the process unit of materials and start up the unit, and would result in greater emissions than delay of repair of leaking components until the next scheduled process unit shutdown.
(3) The use of spare equipment and technically feasible bypassing of equipment without stopping production.
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.
Qualified Professional Engineer means an individual who is licensed by a state as a Professional Engineer to practice one or more disciplines of engineering and who is qualified by education, technical knowledge and experience to make the specific technical certifications required under this subpart. Professional engineers making these certifications must be currently licensed in at least one state in which the certifying official is located.
Quarter means a 3-month period. For purposes of standards for process unit equipment designated facilities at onshore natural gas processing plants, the first quarter concludes on the last day of the last full month during the 180 days following initial startup.
Reciprocating compressor means a piece of equipment that increases the pressure of a process gas by positive displacement, employing linear movement of the driveshaft.
Reciprocating compressor rod packing means a series of flexible rings in machined metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas that escapes to the atmosphere, or other mechanism that provides the same function.
Recovered gas means gas recovered through the separation process during flowback.
Recovered liquids means any crude oil, condensate or produced water recovered through the separation process during flowback.
Reduced emissions completion means a well completion following fracturing or refracturing where gas flowback that is otherwise vented is captured, cleaned, and routed to the gas flow line or collection system, re-injected into the well or another well, used as an onsite fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with no direct release to the atmosphere.
Reduced sulfur compounds means H 2 S, carbonyl sulfide (COS), and carbon disulfide (CS 2 ).
Removed from service means that a storage vessel designated facility has been physically isolated and disconnected from the process for a purpose other than maintenance in accordance with § 60.5396c(c)(1).
Repaired means the following:
(1) For the purposes of fugitive emissions components designated facilities, that fugitive emissions components are adjusted, replaced, or otherwise altered, in order to eliminate fugitive emissions as defined in § 60.5397c and resurveyed as specified in § 60.5397c(h)(4) and it is verified that emissions from the fugitive emissions components are below the applicable fugitive emissions definition.
(2) For the purposes of process unit equipment designated facilities, that equipment is adjusted, or otherwise altered, in order to eliminate a leak as defined in §§ 60.5400c and 60.5401c and is re-monitored as specified in § 60.5400c(b) introductory text or § 60.5406c, respectively, to verify that emissions from the equipment are below the applicable leak definition. Pumps in light liquid service subject to § 60.5400c(c)(2) or § 60.5401c(b)(1)(ii) are not subject to re-monitoring.
Replacement cost means the capital needed to purchase all the depreciable components in a facility.
Returned to service means that a storage vessel designated facility that was removed from service has been:
(1) Reconnected to the original source of liquids or has been used to replace any storage vessel designated facility; or
(2) Installed in any location covered by this subpart and introduced with crude oil, condensate, intermediate hydrocarbon liquids or produced water.
Routed to a process or route to a process means the emissions are conveyed via a closed vent system to any enclosed portion of a process that is operational where the emissions are predominantly recycled and/or consumed in the same manner as a material that fulfills the same function in the process and/or transformed by chemical reaction into materials that are not regulated materials and/or incorporated into a product; and/or recovered.
Salable quality gas means natural gas that meets the flow line or collection system operator specifications, regardless of whether such gas is sold.
Screenout means an attempt to clear proppant from the wellbore to dislodge the proppant out of the well.
Self-contained process controller means a natural gas-driven process controller that releases gas into the downstream piping and not to the atmosphere, resulting in zero methane emissions.
Self-contained wet seal centrifugal compressor means:
(1) A wet seal centrifugal compressor system that is a closed process that ports the degassing emissions into the natural gas line at the compressor suction ( i.e., degassed emissions are recovered) or which has an intermediate closed process that degasses most of the gas entrained in the seal oil and sends that gas to another process. The de-gas emissions are routed back to suction or process directly from the closed or intermediate closed degassing process; after the closed or intermediate closed degassing process the oil is ultimately recycled for recirculation in the seals to the lube oil tank where any small amount of residual gas is released through a vent.
(2) A wet seal centrifugal compressor equipped with mechanical wet seals, where (1) a differential pressure is maintained on the system and there is no off gassing of the lube oil, and (2) the mechanical seal is integrated into the compressor housing.
Sensor means a device that measures a physical quantity or the change in a physical quantity such as temperature, pressure, flow rate, pH, or liquid level.
Separation flowback stage means the period during a well completion operation when it is technically feasible for a separator to function. The separation flowback stage ends either at the startup of production, or when the well is shut in and permanently disconnected from the flowback equipment.
Separator dump valve means, for purposes of the fugitive emission standards in §§ 60.5397c and 60.5398c, a liquid-control valve in a separator that controls the liquid level within the separator vessel.
Single wellhead only well site means a wellhead only well site that contains only one wellhead and no major production and processing equipment.
Small well site means, for purposes of the fugitive emissions standards in §§ 60.5397c and 60.5398c, a well site that contains a single wellhead, no more than one piece of certain major production and processing equipment, and associated meters and yard piping. Small well sites cannot include any controlled storage vessels (or controlled tank batteries), control devices, or natural gas-driven process controllers, or natural gas-driven pumps.
Startup of production means the beginning of initial flow following the end of flowback when there is continuous recovery of salable quality gas and separation and recovery of any crude oil, condensate, or produced water, except as otherwise provided in this definition. For the purposes of the fugitive monitoring requirements of § 60.5397c, startup of production means the beginning of the continuous recovery of salable quality gas and separation and recovery of any crude oil, condensate, or produced water.
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 nonearthen 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 shall not be considered a storage vessel if it has been removed from service in accordance with the requirements of § 60.5396c(c)(1) until such time as such tank or other vessel has been returned to service. For the purposes of this subpart, the following are not considered storage vessels:
(1) 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 § 60.5420c(c)(6)(v), showing that the vessel has been located at a site for less than 180 consecutive days, the vessel described herein is considered to be a storage vessel from the date the original vessel was first located at the site. This exclusion does not apply to a well completion vessel as described above.
(2) Process vessels such as surge control vessels, bottoms receivers or knockout vessels.
(3) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere.
Sulfur production rate means the rate of liquid sulfur accumulation from the sulfur recovery unit.
Sulfur recovery unit means a process device that recovers element sulfur from acid gas.
Surface site means any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate physical location upon which equipment is physically affixed.
Sweetening unit means a process device that removes hydrogen sulfide and/or carbon dioxide from the sour natural gas stream.
Tank battery means a group of all storage vessels that are manifolded together for liquid transfer. A tank battery may consist of a single storage vessel if only one storage vessel is present.
Total Reduced Sulfur (TRS) means the sum of the sulfur compounds hydrogen sulfide, methyl mercaptan, dimethyl sulfide, and dimethyl disulfide as measured by Method 16 of appendix A-6 to this part.
Total SO 2 equivalents means the sum of volumetric or mass concentrations of the sulfur compounds obtained by adding the quantity existing as SO 2 to the quantity of SO 2 that would be obtained if all reduced sulfur compounds were converted to SO 2 (ppmv or kg/dscm (lb/dscf)).
UIC Class I oilfield disposal well means a well with a UIC Class I permit that meets the definition in 40 CFR 144.6(a)(2) and receives eligible fluids from oil and natural gas exploration and production operations.
UIC Class II oilfield disposal well means a well with a UIC Class II permit where wastewater resulting from oil and natural gas production operations is injected into underground porous rock formations not productive of oil or gas, and sealed above and below by unbroken, impermeable strata.
Underground storage vessel means a storage vessel stored below ground.
Well means a hole drilled for the purpose of producing oil or natural gas, or a well into which fluids are injected.
Well completion means the process that allows for the flowback of petroleum or 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.
Well completion operation means any well completion with hydraulic fracturing or refracturing occurring at a well completion designated facility.
Well completion vessel means a vessel that contains flowback during a well completion operation following hydraulic fracturing or refracturing. A well completion vessel may be a lined earthen pit, a tank or other vessel that is skid-mounted or portable. 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.
Well site means one or more surface sites that are constructed for the drilling and subsequent operation of any oil well, natural gas well, or injection well. For the purposes of the fugitive emissions standards at § 60.5397c, a well site does not include:
(1) UIC Class II oilfield disposal wells and disposal facilities;
(2) UIC Class I oilfield disposal wells; and
(3) The flange immediately upstream of the custody meter assembly and equipment, including fugitive emissions components, located downstream of this flange.
Wellhead means the piping, casing, tubing and connected valves protruding above the earth's surface for an oil and/or natural gas well. The wellhead ends where the flow line connects to a wellhead valve. The wellhead does not include other equipment at the well site except for any conveyance through which gas is vented to the atmosphere.
Wellhead only well site means, for the purposes of the fugitive emissions standards at § 60.5397c and the standards in § 60.5398c, a well site that contains one or more wellheads and no major production and processing equipment.
Wildcat well means a well outside known fields or the first well drilled in an oil or gas field where no other oil and gas production exists.
Yard piping means hard-piping at a well site, centralized production facility, or compressor station that is not part of a closed vent system.
§§ 60.5431c-60.5439c   [Reserved]
§ 60.5472   Am I subject to this subpart?
(a) You are subject to this subpart if you manufacture, sell, offer for sale, import for sale, distribute, offer to distribute, introduce or deliver for introduction into commerce in the United States, or install or operate a residential hydronic heater, forced-air furnace or other central heater manufactured on or after May 15, 2015, except as provided in paragraph (c) of this section.
(b) Each residential hydronic heater, forced-air furnace or other central heater must comply with the provisions of this subpart unless exempted under paragraphs (b)(1) through (b)(3) of this section. These exemptions are determined by rule applicability and do not require additional EPA notification or public notice.
(1) Affected residential hydronic heaters, forced-air furnaces or other central heaters manufactured in the United States for export are exempt from the applicable emission limits of § 60.5474 and the requirements of § 60.5475.
(2) Affected residential hydronic heaters, forced-air furnaces or other central heaters used for research and development purposes that are never offered for sale or sold and that are not used to provide heat are exempt from the applicable emission limits of § 60.5474 and the requirements of § 60.5475. No more than 12 affected residential central heaters manufactured per model line may be exempted for this purpose.
(3) Appliances that do not burn wood or wood pellets or wood chips (such as coal-only central heaters that meet the definition in § 60.5473 or corn-only central heaters) are exempt from the applicable emission limits of § 60.5474 and the requirements of § 60.5475 provided that all advertising and warranties clearly denote that wood burning is prohibited in these appliances.
(c) The following are not affected central heaters and are not subject to this subpart:
(1) Residential wood heaters subject to subpart AAA of this part.
(2) Residential masonry heaters as defined in § 60.5473.
§ 60.5473   What definitions must I know?
As used in this subpart, all terms not defined herein have the same meaning given them in the Clean Air Act and subpart A of this part.
Approved test laboratory means a test laboratory that is approved for central heater certification testing under § 60.5477 or is an independent third-party test laboratory that is accredited under ISO-IEC Standard 17025 to perform testing using the test methods specified in § 60.5476 by an accreditation body that is a full member signatory to the International Laboratory Accreditation Cooperation Mutual Recognition Arrangement and approved by the EPA for conducting testing under this subpart.
Catalytic combustor means a device coated with a noble metal used in a wood heater to lower the temperature required for combustion.
Central heater means a fuel-burning device designed to burn wood or wood pellet fuel that warms spaces other than the space where the device is located, by the distribution of air heated by the furnace through ducts or liquid heated in the device and distributed typically through pipes. Unless otherwise specified, these devices include, but are not limited to, residential forced-air furnaces (small and large) and residential hydronic heaters.
Chip wood fuel means wood chipped into small pieces that are uniform in size, shape, moisture, density and energy content.
Coal-only hydronic heater or forced-air furnace means an enclosed, coal-burning appliance capable of space heating or domestic water heating that has all of the following characteristics:
(1) Installation instructions, owner's manual and marketing information that state that the use of wood in the appliance, except for coal ignition purposes, is prohibited by law; and
(2) The model is listed by a nationally recognized safety-testing laboratory for coal use only, except for coal ignition purposes.
Commercial owner means any person who owns or controls a residential hydronic heater, forced-air furnace or other affected central heater in the course of the business of the manufacture, importation, distribution, or sale of the unit.
Large residential forced-air furnace means a residential forced-air furnace that is capable of a heat output of 65,000 BTU per hour or greater.
Manufactured means completed and ready for shipment (whether or not assembled or packaged) for purposes of determining the date of manufacture.
Manufacturer means any entity that constructs or imports into the United States a central heater.
Model line means all central heaters offered for sale by a single manufacturer that are similar in all material respects that would affect emissions as defined in this section.
Particulate matter (PM) means total particulate matter including coarse particulate (PM 10 ) and fine particulate (PM 2.5 ).
Pellet fuel means refined and densified solid wood shaped into small pellets or briquettes that are uniform in size, shape, moisture, density and energy content.
Representative affected wood or central heater means an individual heater that is similar in all material respects that would affect emissions as defined in this section to other heaters within the model line it represents.
Residential forced-air furnace means a fuel burning device designed to burn wood or wood pellet fuel that warms spaces other than the space where the furnace is located, by the distribution of air heated by the furnace through ducts.
Residential hydronic heater means a fuel burning device designed to burn wood or wood pellet fuel for the purpose of heating building space and/or water through the distribution, typically through pipes, of a fluid heated in the device, typically water or a water and antifreeze mixture.
Residential masonry heater means a factory-built or site-built wood-burning device in which the heat from intermittent fires burned rapidly in the firebox is stored in the refractory mass for slow release to building spaces. Masonry heaters are site-built (using local materials or a combination of local materials and manufactured components) or site-assembled (using factory-built components), solid fuel-burning heating appliances constructed mainly of refractory materials ( e.g., masonry materials or soapstone. They typically have an interior construction consisting of a firebox and heat exchange channels built from refractory components, through which flue gases are routed. ASTM E1602 “Standard Guide for Construction of Solid Fuel Burning Masonry Heaters” provides design and construction information for the range of masonry heaters most commonly built in the United States. The site-assembled models are generally listed to UL-1482.
Sale means the transfer of ownership or control, except that a transfer of control of an affected central heater for research and development purposes within the scope of § 60.5472(b)(2) is not a sale.
Similar in all material respects that would affect emissions means that the construction materials, exhaust and inlet air system, and other design features are within the allowed tolerances for components identified in § 60.5475(k).
Small residential forced-air furnace means a residential forced-air furnace that is only capable of a maximum heat output of less than 65,000 BTU per hour.
Sold at retail means the sale by a commercial owner of a central heater to the ultimate purchaser/user or noncommercial purchaser.
Third-party certifier (sometimes called third-party certifying body or product certifying body) means an independent third party that is accredited under ISO-IEC Standards 17025 and 17065 to perform certifications, inspections and audits by an accreditation body that is a full member signatory to the International Laboratory Accreditation Cooperation Mutual Recognition Arrangement and approved by the EPA for conducting certifications, inspections and audits under this subpart.
Unseasoned wood means wood with an average moisture content of 20 percent or more.
Valid certification test means a test that meets the following criteria:
(1) The Administrator was notified about the test in accordance with § 60.5476(h);
(2) The test was conducted by an approved test laboratory as defined in this section;
(3) The test was conducted on a central heater similar in all material respects that would affect emissions as defined in this section to other central heaters of the model line that is to be certified; and
(4) The test was conducted in accordance with the test methods and procedures specified in § 60.5476.
Wood heater under this subpart means an enclosed, wood burning-appliance capable of and intended for residential central heating or central heating and domestic water heating. Unless otherwise specified, these devices include, but are not limited to, hydronic heaters and forced-air furnaces.
§ 60.5474   What standards and requirements must I meet and by when?
(a) Standards. Unless exempted under § 60.5472, no person is permitted to:
(1) On or after May 15, 2015, manufacture, import into the United States or sell at retail a residential hydronic heater unless it has been certified to meet the 2015 particulate matter emission limits in paragraph (b)(1) of this section, except that a residential hydronic heater that was manufactured on or before May 15, 2015 may be imported into the United States and/or sold at retail on or before December 31, 2015.
(2) On or after May 15, 2020 manufacture or sell at retail a residential hydronic heater unless it has been certified to meet the 2020 particulate matter emission limit in paragraph (b)(2) or (b)(3) of this section.
(3) On or after May 15, 2015, manufacture or sell at retail a residential forced-air furnace unless it complies with the work practice and operating standards in paragraphs (d), (e), (f) and (g) of this section and the owner's manual requirements in appendix I.
(4) On or after May 16, 2016, manufacture or sell at retail a small residential forced-air furnace unless it has been certified to meet the 2016 particulate matter emission limits in paragraph (b)(4) of this section
(5) On or after May 15, 2017 manufacture or sell at retail a large forced-air furnace unless it has been certified to meet the 2017 particulate matter emission limits in paragraph (b)(5) of this section.
(6) On or after May 15, 2020 manufacture or sell at retail a small or large residential forced-air furnace unless it has been certified to meet the 2020 particulate matter emission limit in paragraph (b)(6) of this section.
(b)(1) 2015 residential hydronic heater particulate matter emission limit: A weighted average of 0.32 lb/mmBtu (0.137 g/MJ) heat output and a maximum per individual burn rate of 18.0 g/hr (0.041 lb/hr) as determined by the test methods and procedures in § 60.5476 or an alternative crib wood or cord wood test method approved by the Administrator.
(2) 2020 residential hydronic heater particulate matter emission limit: 0.10 lb/mmBtu (0.043 g/MJ) heat output per individual burn rate as determined by the crib wood test methods and procedures in § 60.5476 or an alternative crib wood test method approved by the Administrator.
(3) 2020 residential hydronic heater cord wood alternative compliance option for particulate matter emission limit: 0.15 lb/mmBtu (0.064 g/MJ) heat output per individual burn rate as determined by the cord wood test methods and procedures in § 60.5476 or an alternative cord wood test method approved by the Administrator.
(4) 2016 small forced-air furnace particulate matter emission limit: A weighted average of 0.93 lb/mmBtu (0.40 g/MJ) heat output as determined by the test methods and procedures in § 60.5476.
(5) 2017 large forced-air furnace particulate matter emission limit: A weighted average of 0.93 lb/mmBtu (0.40 g/MJ) heat output as determined by the test methods and procedures in § 60.5476.
(6) 2020 forced-air furnace particulate matter emission limit: 0.15 lb/mmBtu (0.064 g/MJ) heat output per individual burn rate as determined by the cord wood test methods and procedures in § 60.5476 or cord wood test methods approved by the Administrator.
(c) [Reserved]
(d) Chip wood fuel requirements. Operators of wood central heaters, including hydronic heaters and forced-air furnaces, that are certified to burn chip wood fuels may only burn wood chips that have been specified in the owner's manual. The chip wood fuel must meet the following minimum requirements:
(1) Moisture content: Less than 35 percent,
(2) Inorganic fines: Less than or equal to 1 percent;
(3) Chlorides: Less than or equal to 300 parts per million by weight;
(4) Ash content: No more than 2 percent;
(5) No demolition or construction waste; and
(6) Trace metals: Less than 100 mg/kg.
(e) Pellet fuel requirements. Operators of wood central heaters, including outdoor residential hydronic heaters, indoor residential hydronic heaters, and residential forced-air furnaces, that are certified to burn pellet fuels may burn only pellets that have been specified in the owner's manual and graded under a licensing agreement with a third-party organization approved by the EPA (including a certification by the third-party organization that the pellets do not contain, and are not manufactured from, any of the prohibited fuels in paragraph (f) of this section). The Pellet Fuels Institute, ENplus, and CANplus are initially deemed to be approved third-party organizations for this purpose, and additional organizations may apply to the Administrator for approval.
(f) Prohibited fuel types. No person is permitted to burn any of the following materials in an outdoor residential hydronic heater, indoor residential hydronic heater, residential forced-air furnace or other affected central heater:
(1) Residential or commercial garbage;
(2) Lawn clippings or yard waste;
(3) Materials containing rubber, including tires;
(4) Materials containing plastic;
(5) Waste petroleum products, paints or paint thinners, or asphalt products;
(6) Materials containing asbestos;
(7) Construction or demolition debris;
(8) Paper products; cardboard, plywood or particleboard. The prohibition against burning these materials does not prohibit the use of fire starters made from paper, cardboard, saw dust, wax and similar substances for the purpose of starting a fire in an affected central heater;
(9) Railroad ties or pressure treated lumber;
(10) Manure or animal remains;
(11) Salt water driftwood or other or other previously salt water saturated materials;
(12) Unseasoned wood;
(13) Any materials that are not included in the warranty and owner's manual for the subject heater or furnace; or
(14) Any materials that were not included in the certification tests for the subject heater or furnace.
(g) Operation of affected wood heaters. A user must operate an outdoor residential hydronic heater, indoor residential hydronic heater, residential forced-air furnace or other affected central heater in a manner consistent with the owner's manual. The owner's manual must clearly specify that operation in a manner inconsistent with the owner's manual would void the warranty.
(h) Temperature sensor requirement. An affected wood heater equipped with a catalytic combustor must be equipped with a temperature sensor that can monitor combustor gas stream temperatures within or immediately downstream [within 2.54 centimeters (1 inch)] of the catalytic combustor surface.
§ 60.5475   What compliance and certification requirements must I meet and by when?
(a) Certification requirement. (1) Each affected residential hydronic heater, forced-air furnace and other central heater must be certified to be in compliance with the applicable emission standards and other requirements of this subpart. For each model line manufactured or sold by a single entity, e.g., company or manufacturer, compliance with applicable emission standards of § 60.5474 must be determined based on testing of representative affected central heaters within the model line. If one entity licenses a model line to another entity, each entity's model line must be certified. If an entity intends to change the name of the entity or the name of the model, the manufacturer must apply for a new certification 60 days before making the change.
(2) The manufacturer of each model line must submit the information required in paragraph (b) of this section and follow either the certification process in paragraphs (c) through (e) of this section (for forced-air furnaces) or the certification procedure specified in paragraph (f) of this section.
(3) Models qualified as meeting the Phase 2 emission levels under the 2011 EPA hydronic heater partnership agreement are automatically deemed to have a certificate of compliance for the 2015 particulate matter emission standards and be valid until the effective date for the 2020 particulate matter emission standards.
(4) Models certified by the New York State Department of Environment and Conservation to meet the emission levels in § 60.5474(b) are automatically deemed to have a certificate of compliance for the 2015 particulate matter emission standards and be valid until the effective date for the 2020 particulate matter emission standards.
(5) Models approved by the New York State Energy Research and Development Authority under the Renewable Heat New York (RHNY) Biomass Boiler Program are automatically deemed to have a certificate of compliance for the 2015 particulate matter emission standards and be valid until the effective date for the 2020 particulate matter emission standards provided that they comply with the thermal storage requirements in the RHNY program.
(6) Small forced-air furnace models that are certified under CSA B415.1-10 (IBR, see § 60.17), by an EPA approved third-party certifier, to meet the 2016 particulate matter emission level will be automatically deemed to have a certificate of compliance for the 2016 particulate matter emission standards and be valid until the effective date for the 2020 particulate matter emission standards.
(7) Large forced-air furnace models that are certified under CSA B415.1-10 (IBR, see § 60.17), by an EPA approved third-party certifier, to meet the 2017 particulate matter emission level will be automatically deemed to have a certificate of compliance for the 2017 particulate matter emission standards and be valid until the effective date of the 2020 particulate matter emission standards.
(b) Application for a certificate of compliance. Any manufacturer of an affected residential hydronic heater or forced-air furnace or other central heater must apply to the Administrator for a certificate of compliance for each model line. The application must be submitted to: WoodHeaterReports@epa.gov. The application must be signed by a responsible representative of the manufacturer or an authorized representative and must contain the following:
(1) The model name and/or design number. The model name and/or design number must clearly distinguish one model from another. The name and/or design number cannot include the EPA symbol or logo or name or derivatives such as “EPA.”
(2) Engineering drawings and specifications of components that may affect emissions (including specifications for each component listed in paragraph (k) of this section). Manufacturers may use assembly or design drawings that have been prepared for other purposes, but must designate on the drawings the dimensions of each component listed in paragraph (k) of this section. Manufacturers must identify dimensions of components listed in paragraph (k)(2) of this section that are different from those specified in that paragraph, and show that such differences cannot reasonably be anticipated to cause central heaters in the model line to exceed the applicable emission limits. The drawings must identify how the emission critical parts, such as air tubes and catalyst, can be readily inspected and replaced.
(3) A statement whether the firebox or any firebox component (including the materials listed in paragraph (k)(3) of this section) will be composed of material different from the material used for the firebox or firebox component in the central heater on which certification testing was performed and a description of any such differences and demonstration that any such differences may not reasonably be anticipated to adversely affect emissions or efficiency.
(4) Clear identification of any claimed confidential business information (CBI). Submit such information under separate cover to the EPA CBI Office; Attn: Residential Wood Heater Compliance Program Lead, 1200 Pennsylvania Ave. NW., Washington, DC 20004. Note that all emissions data, including all information necessary to determine emission rates in the format of the standard, cannot be claimed as CBI.
(5) All documentation pertaining to a valid certification test, including the complete test report and, for all test runs: Raw data sheets, laboratory technician notes, calculations and test results. Documentation must include the items specified in the applicable test methods. Documentation must include discussion of each test run and its appropriateness and validity, and must include detailed discussion of all anomalies, whether all burn rate categories were achieved, any data not used in the calculations and, for any test runs not completed, the data collected during the test run and the reason(s) that the test run was not completed. The documentation must show that the burn rate for the low burn rate category is no greater than the rate that an operator can achieve in home use and no greater than is advertised by the manufacturer or retailer. The test report must include a summary table that clearly presents the individual and overall emission rates, efficiencies and heat outputs. Submit the test report and all associated required information according to the procedures for electronic reporting specified in § 60.5479(f).
(6) A copy of the warranties for the model line, which must include a statement that the warranties are void if the unit is used to burn materials for which the unit is not certified by the EPA and void if not operated according to the owner's manual.
(7) A statement that the manufacturer will conduct a quality assurance program for the model line that satisfies the requirements of paragraph (m) of this section.
(8) A statement describing how the tested unit was sealed by the laboratory after the completion of certification testing and asserting that such unit will be stored by the manufacturer in the sealed state until 5 years after the certification test.
(9) Statements that the central heater manufactured under this certificate will be—
(i) Similar in all material respects that would affect emissions as defined in this subpart to the central heater submitted for certification testing, and
(ii) Labeled as prescribed in § 60.5478.
(iii) Accompanied by an owner's manual that meets the requirements in § 60.5478. In addition, a copy of the owner's manual must be submitted to the EPA and be available to the public on the manufacturer's Web site.
(10) A statement that the manufacturer has entered into contracts with an approved laboratory and an approved third-party certifier that satisfy the requirements of paragraph (f) of this section.
(11) A statement that the approved laboratory and approved third-party certifier are allowed to submit information on behalf of the manufacturer, including any claimed to be CBI.
(12) A statement that the manufacturer will place a copy of the certification test report and summary on the manufacturer's Web site available to the public within 30 days after the Administrator issues a certificate of compliance.
(13) A statement of acknowledgment that the certificate of compliance cannot be transferred to another manufacturer or model line without written approval by the Administrator.
(14) A statement acknowledging that it is unlawful to sell, distribute, or offer to sell or distribute an affected wood heater without a valid certificate of compliance.
(15) Contact information for the responsible representative of the manufacturer and all authorized representatives, including name, affiliation, physical address, telephone number and email address.
(c) Administrator approval process. (1) The Administrator may issue a certificate of compliance for a model line if the Administrator determines, based on all information submitted by the applicant and any other relevant information available, that:
(i) A valid certification test demonstrates that the representative affected central heater complies with the applicable emission standards in § 60.5474;
(ii) Any tolerances or materials for components listed in paragraph (k)(2) or (3) of this section that are different from those specified in those paragraphs may not reasonably be anticipated to cause central heaters in the model line to exceed the applicable emission limits; and
(iii) The requirements of paragraph (b) of this section have been met.
(2) The Administrator will deny certification if the Administrator determines that the criteria in paragraph (c)(1) of this section have not been satisfied. Upon denying certification under this paragraph, the Administrator will give written notice to the manufacturer setting forth the basis for this determination.
(d) Level of compliance certification. The Administrator will issue the certificate of compliance for the most stringent particulate matter emission standard that the tested representative central heater meets under § 60.5474.
(e) Conditional, temporary certificate of compliance. A conditional, temporary certificate of compliance with the Step 1 p.m. emission standards may be granted by the Administrator until May 16, 2016 for small or large forced-air furnaces based on the manufacturer's submittal of a complete certification application meeting all requirements in § 60.5475(b). The application must include the full test report by an EPA-approved laboratory and all required compliance statements by the manufacturer with the exception of a certificate of conformity by an EPA approved third-party certifier. The conditional, temporary approval would allow early marketing of forced-air furnaces as having a conditional, temporary certificate of compliance with the Step 1 p.m. emission standards until May 16, 2016 or until the Administrator completes the review of the application, whichever is earlier.
(f) Third-party certifier-based application process. (1) Any manufacturer of an affected central heater must apply to the Administrator for a certificate of compliance for each model line. The manufacturer must meet the following requirements:
(i) The manufacturer must contract with a third-party certifier for certification services. The contract must include regular (at least annual) unannounced audits under ISO-IEC Standard 17065 to ensure that the manufacturer's quality assurance plan is being implemented. The contract must also include a report for each audit under ISO-IEC Standard 17065 that fully documents the results of the audit. The contract must include authorization and requirement for the third-party certifier to submit all such reports to the Administrator and the manufacturer within 30 days of the audit. The audit report must identify deviations from the manufacturer's quality assurance plan and specify the corrective actions that need to be taken to address each identified deficiency.
(ii) The manufacturer must submit the materials specified in paragraph (b) of this section and a quality assurance plan that meets the requirements of paragraph (m) of this section to the third-party certifier. The quality assurance plan must ensure that units within a model line will be similar in all material respects that would affect emissions to the wood heater submitted for certification testing, and it must include design drawings for the model line.
(iii) The manufacturer must apply to the third-party certifier for a certification of conformity with the applicable requirements of this subpart for the model line.
(A) After testing by an approved test laboratory is complete, certification of conformity with the emission standards in § 60.5474 must be performed by the manufacturer's contracted third-party certifier.
(B) The third-party certifier may certify conformity if the emission tests have been conducted per the appropriate guidelines: The test report is complete and accurate; the instrumentation used for the test was properly calibrated; the test report shows that the representative affected central heater meets the applicable emission limits specified in § 60.5474; and the quality assurance plan is adequate to ensure that units within the model line will be similar in all material respects that would affect emissions to the central heater submitted for certification testing, and that the affected heaters would meet all applicable requirements of this subpart.
(iv) The manufacturer must then submit to the Administrator an application for a certificate of compliance that includes the certification of conformity, quality assurance plan, test report and all supporting documentation specified in paragraph (b) of this section.
(v) The submission also must include a statement signed by a responsible official of the manufacturer or authorized representative that the manufacturer has complied with and will continue to comply with all requirements of this subpart for certificate of compliance and that the manufacturer remains responsible for compliance regardless of any error by the test laboratory or third-party certifier.
(2) The Administrator will issue to the manufacturer a certificate of compliance for a model line if it is determined, based on all of the information submitted in the application for certification and any other relevant information, that:
(i) A valid certification of conformity has demonstrated that the representative affected central heater complies with the applicable emission standards in § 60.5474;
(ii) Any tolerances or materials for components listed in paragraph (k)(2) or (3) of this section that are different from those specified in those paragraphs may not be reasonably anticipated to cause central heaters in the model line to exceed the applicable emission limits;
(iii) The requirements of paragraphs (b) of this section have been met; and
(iv) A valid certificate of conformity for the model line has been prepared and submitted.
(3) The Administrator will deny certification if the Administrator determines that the criteria in paragraph (f)(2) of this section have not been satisfied. Upon denying certification under this paragraph, the Administrator will give written notice to the manufacturer setting forth the basis for the determination.
(g) Waiver from submitting test results. An applicant for certification may apply for a potential waiver of the requirement to submit the results of a certification test pursuant to paragraph (b) of this section, if the central heater meets either of the following conditions:
(1) The central heaters of the model line are similar in all material respects that would affect emissions, as defined in § 60.5473 and paragraph (k) of this section, to another model line that has already been issued a certificate of compliance. A manufacturer that seeks a waiver of certification testing must identify the model line that has been certified, and must submit a copy of an agreement with the owner of the design permitting the applicant to produce central heaters of that design.
(2) The manufacturer has previously conducted a valid certification test to demonstrate that the central heaters of the model line meet the applicable standard specified in § 60.5474.
(h) Certification period. Unless revoked sooner by the Administrator, a certificate of compliance will be valid for 5 years from the date of issuance or until a more stringent standard comes into effect, whichever is sooner.
(i) Renewal of certification. (1) The manufacturer must renew a model line's certificate of compliance or recertify the model line every 5 years, or the manufacturer may choose to no longer manufacture or sell that model line after the expiration date. If the manufacturer chooses to no longer manufacture that model line, then the manufacturer must submit a statement to the Administrator to that effect.
(2) A manufacturer of an affected residential hydronic heater or forced-air furnace or other central heater may apply to the Administrator for potential renewal of its certificate of compliance by submitting the material specified in paragraph (b) and following the procedures specified in paragraph (f) of this section, or by affirming in writing that the central heaters in the model line continue to be similar in all material respects that would affect emissions to the representative central heater submitted for testing on which the original certificate of compliance was based and requesting a potential waiver from certification testing. The application must include a copy of the review of the draft application and approval by the third-party certifier.
(3) If the Administrator grants a renewal of certification, the Administrator will give written notice to the manufacturer setting forth the basis for the determination and issue a certification renewal.
(4) If the Administrator denies the request for a renewal of certification, the Administrator will give written notice to the manufacturer setting forth the basis for the determination.
(5) If the Administrator denies the request for a renewal of certification, the manufacturer and retailer must not manufacture or sell the previously-certified central heaters after the expiration date of the certificate of compliance.
(j) [Reserved]
(k) Recertification. (1) The manufacturer must recertify a model line whenever any change is made in the design submitted pursuant to paragraph (k)(2) of this section that affects or is presumed to affect the particulate matter emission rate for that model line. The manufacturer of an affected central heater must apply to the Administrator for potential recertification by submitting the material specified in paragraph (b) of this section and following the procedures specified in paragraph (f) of this section or by affirming in writing that the change will not cause the central heaters in the model line to exceed applicable emission limits and requesting a waiver from certification testing. The application for recertification must be reviewed and approved by the contracted third-party certifier and a copy of the review and approval must be included. The Administrator may waive this requirement upon written request by the manufacturer, if the manufacturer presents adequate rationale and the Administrator determines that the change may not reasonably be anticipated to cause central heaters in the model line to exceed the applicable emission limits. The granting of such a waiver does not relieve the manufacturer of any compliance obligations under this subpart.
(2) Any change in the design tolerances of any of the following components (where such components are applicable) is presumed to affect particulate matter and carbon monoxide emissions and efficiency if that change exceeds ±0.64 cm (±1/4 inch) for any linear dimension and ±5 percent for any cross-sectional area relating to air introduction systems and catalyst bypass gaps unless other dimensions and cross-sectional areas are previously approved by the Administrator under paragraph (c)(1)(ii) of this section:
(i) Firebox: Dimensions;
(ii) Air introduction systems: Cross-sectional area of restrictive air inlets and outlets, location and method of control;
(iii) Baffles: Dimensions and locations;
(iv) Refractory/insulation: Dimensions and location;
(v) Catalyst: Dimensions and location;
(vi) Catalyst bypass mechanism and catalyst bypass gap tolerances (when bypass mechanism is in closed position): Dimensions, cross-sectional area, and location;
(vii) Flue gas exit: Dimensions and location;
(viii) Door and catalyst bypass gaskets: Dimensions and fit;
(ix) Outer thermal shielding and thermal coverings: Dimensions and location;
(x) Fuel feed system: For central heaters that are designed primarily to burn wood pellet fuel or wood chips and other central heaters equipped with a fuel feed system, the fuel feed rate, auger motor design and power rating, and the angle of the auger to the firebox; and
(xi) Forced air combustion system: For central heaters so equipped, the location and horsepower of blower motors and the fan blade size.
(3) Any change in the materials used for the following components is presumed to affect particulate matter emissions and efficiency:
(i) Refractory/insulation; or
(ii) Door and catalyst bypass gaskets.
(4) A change in the make, model, or composition of a catalyst is presumed to affect particulate matter and carbon monoxide emissions and efficiency, unless the change has been requested by the central heater manufacturer and has been approved in advance by the Administrator, based on test data that demonstrate that the replacement catalyst is equivalent to or better than the original catalyst in terms of particulate matter emission reduction.
(l) Criteria for revocation of certification. (1) The Administrator may revoke certification of a product line if it is determined that the central heaters being manufactured or sold in that model line do not comply with the requirements of this subpart. Such a determination will be based on all available evidence, including but not limited to:
(i) Test data from retesting of the original unit on which the certification test was conducted on a unit that is similar in all material respects that would affect emissions;
(ii) A finding that the certification test was not valid. The finding will be based on problems or irregularities with the certification test or its documentation, but may be supplemented by other information;
(iii) A finding that the labeling of the central heater model line or the owner's manual or the associated marketing information does not comply with the requirements of § 60.5478;
(iv) Failure by the manufacturer to comply with the reporting and recordkeeping requirements of § 60.5479;
(v) Physical examination showing that a significant percentage (as defined in the quality assurance plan approved pursuant to paragraph (m) of this section, but no larger than 1 percent) of production units inspected is not similar in all material respects that would affect emissions to the representative affected central heater submitted for certification testing; or
(vi) Failure of the manufacturer to conduct a quality assurance program in conformity with paragraph (m).
(vii) Failure of the approved laboratory to test the central heater using the methods specified in § 60.5476.
(2) Revocation of certification under this paragraph (l) of this section will not take effect until the manufacturer concerned has been given written notice by the Administrator setting forth the basis for the proposed determination and an opportunity to request a hearing under § 60.5481.
(m) Quality assurance program. On or after May 16, 2016, for each certified model line, the manufacturer must conduct a quality assurance program that satisfies the requirements of paragraphs (m)(1) through (5) of this section.
(1) The manufacturer must prepare and operate according to a quality assurance plan for each certified model line that includes specific inspection and testing requirements for ensuring that all units within a model line are similar in all material respects that would affect emissions to the central heater submitted for certification testing and meet the emissions standards in § 60.5474.
(2) The quality assurance plan must be approved by the third-party certifier as part of the certification of conformity process specified in paragraph (f) of this section.
(3) The quality assurance plan must include regular (at least annual) unannounced audits by the third-party certifier under ISO-IEC Standard 17065 to ensure that the manufacturer's quality assurance plan is being implemented.
(4) The quality assurance plan must include a report for each audit under ISO-IEC Standard 17065 that fully documents the results of the audit. The third-party certifier must be authorized and required to submit all such reports to the Administrator within 30 days of the audit. The audit report must identify deviations from the manufacturer's quality assurance plan and specify the corrective actions that need to be taken to address each identified deficiency.
(5) Within 30 days after receiving each audit report, the manufacturer must report to the third-party certifier and to the Administrator its corrective actions and responses to any deficiencies identified in the audit report. No such report is required if an audit report did not identify any deficiencies.
(n) EPA compliance audit testing. (1)(i) The Administrator may select by written notice central heaters or model lines for compliance audit testing to determine compliance with the emission standards in § 60.5474.
(ii) The Administrator will transmit a written notification of the selected central heaters or model line(s) to the manufacturer, which will include the name and address of the laboratory selected to perform the audit test and the model name and serial number of the central heater(s) or central heater model line(s) selected to undergo audit testing.
(2)(i) The Administrator may test, or direct the manufacturer to have tested, the central heater(s) from the model line(s) selected under paragraph (n)(1)(i) of this section in a laboratory approved under § 60.5477. The Administrator may select any approved test laboratory or federal laboratory for this audit testing.
(ii) The expense of the compliance audit test is the responsibility of the central heater manufacturer.
(iii) The test must be conducted using the same test method used to obtain certification. If the certification test consisted of more than one particulate matter sampling test method, the Administrator may direct the manufacturer and test laboratory as to which of these methods to use for the purpose of audit testing. The Administrator will notify the manufacturer at least 30 days prior to any test under this paragraph, and allow the manufacturer and/or his authorized representatives to observe the test.
(3) Revocation of certification. (i) If emissions from a central heater tested under paragraph (n)(2) of this section exceed the applicable emission standard by more than 50 percent using the same test method used to obtain certification, the Administrator will notify the manufacturer that certification for that model line is suspended effective 72 hours from the receipt of the notice, unless the suspension notice is withdrawn by the Administrator. The suspension will remain in effect until withdrawn by the Administrator, or the date 30 days from its effective date if a revocation notice under paragraph (n)(3)(ii) of this section is not issued within that period, or the date of final agency action on revocation, whichever occurs earliest.
(ii)(A) If emissions from a central heater tested under paragraph (n)(2) of this section exceed the applicable emission limit, the Administrator will notify the manufacturer that certification is revoked for that model line.
(B) A notice under paragraph (n)(3)(ii)(A) of this section will become final and effective 60 days after the date of written notification to the manufacturer, unless it is withdrawn, a hearing is requested under § 60.5481(a)(2), or the deadline for requesting a hearing is extended.
(C) The Administrator may extend the deadline for requesting a hearing for up to 60 days for good cause.
(D) A manufacturer may extend the deadline for requesting a hearing for up to 6 months, by agreeing to a voluntary suspension of certification.
(iii) Any notification under paragraph (n)(3)(i) or (ii) of this section will include a copy of a preliminary test report from the approved test laboratory or federal test laboratory. The test laboratory must provide a preliminary test report to the Administrator within 14 days of the completion of testing, if a central heater exceeds the applicable emission limit in § 60.5474. The test laboratory must provide the Administrator and the manufacturer, within 30 days of the completion of testing, all documentation pertaining to the test, including the complete test report and raw data sheets, laboratory technician notes, and test results for all test runs.
(iv) Upon receiving notification of a test failure under paragraph (n)(3)(ii) of this section, the manufacturer may request that up to four additional central heaters from the same model line be tested at the manufacturer's expense, at the test laboratory that performed the emissions test for the Administrator.
(v) Whether or not the manufacturer proceeds under paragraph (n)(3)(iv) of this section, the manufacturer may submit any relevant information to the Administrator, including any other test data generated pursuant to this subpart. The manufacturer must bear the expense of any additional testing.
(vi) The Administrator will withdraw any notice issued under paragraph (n)(3)(ii) of this section if tests under paragraph (n)(3)(iv) of this section show either—
(A) That exactly four additional central heaters were tested for the manufacturer and all four met the applicable emission limits; or
(B) That exactly two additional central heaters were tested for the manufacturer and each of them met the applicable emission limits and the average emissions of all three tested heaters (the original audit heater and the two additional heaters) met the applicable emission limits.
(vii) If the Administrator withdraws a notice pursuant to paragraph (n)(3)(vi) of this section, the Administrator will revise the certification values for the model line based on the test data and other relevant information. The manufacturer must then revise the labels and marketing information accordingly.
(viii) The Administrator may withdraw any proposed revocation, if the Administrator finds that an audit test failure has been rebutted by information submitted by the manufacturer under paragraph (n)(3)(iv) of this section and/or (n)(3)(v) of this section or by any other relevant information available to the Administrator.
§ 60.5476   What test methods and procedures must I use to determine compliance with the standards and requirements for certification?
Test methods and procedures specified in this section or in appendices of this part, except as provided under § 60.8(b), must be used to determine compliance with the standards and requirements for certification under §§ 60.5474 and 60.5475 and for reporting carbon monoxide emissions and efficiency. The EPA will post all approved alternative test methods on the EPA Web site. The manufacturer or the manufacturer's authorized representative must submit a summary and the full test report with all supporting information, including detailed discussion of all anomalies, whether all burn rate categories were properly achieved, any data not used in the calculations and, for any test runs not completed, the data that were collected and the reason that the test run was not completed. The burn rate for the low burn rate category must be no greater than the rate that an operator can achieve in home use and no greater than is advertised by the manufacturer or retailer.
(a) Canadian Standards Administration (CSA) Method B415.1-10, sections 13.7-13.10 (IBR, see § 60.17), must be used to measure the thermal efficiency and CO emissions of outdoor and indoor residential hydronic heaters and forced-air furnaces, except that the burn rates specified in Method 28WHH must be used for hydronic heaters.
(b) Testing conducted with continuously fed biomass as the fuel(s) must be conducted according to the relevant section of the ASTM E2618-13 (IBR, see § 60.17) or adaptations approved by EPA. The EPA will post all approved alternative test methods on the EPA Web site.
(c)(1) For outdoor and indoor residential hydronic heaters to be tested under the 2015 particulate matter emission standards in § 60.5474(b)(1), the manufacturer must have an EPA-approved test laboratory use:
(i) Method 28WHH;
(ii) Method 28WHH PTS;
(iii) ASTM E2618-13 (IBR, see § 60.17) (using crib wood); or
(iv) EN 303-5 (IBR, see § 60.17), only for units sold with thermal storage.
(2) For outdoor and indoor residential hydronic heaters to be tested under the 2020 particulate matter emission standards in § 60.5474(b)(2), the manufacturer must have an EPA-approved test laboratory use:
(i) Method 28WHH;
(ii) Method 28WHH PTS; or
(iii) ASTM E2618-13 (IBR, see § 60.17) (using crib wood).
(3) If the heater is equipped with full or partial heat storage, the manufacturer, retailer and installer must not sell or install the heater with less heat storage capacity than is used in the certification test.
(4) The manufacturer and approved laboratory must make the following adjustments to the methods listed in paragraphs (a), (c)(1) and (2) of this section:
(i) For ASTM E2618-13 (IBR, see § 60.17), the burn rate categories specified in Method 28WHH must be used;
(ii) For EN 303-5 (IBR, see § 60.17), the organic compounds must be included as part of the PM.
(iii) For ASTM 2618-13 (IBR, see § 60.17) Appendix A1 for full thermal storage certification tests, the test must use the large scale as required in the test method unless the manufacturer requests a variance, in advance of testing, contingent upon measuring flue gas temperature, oxygen and CO, using a simple electronic spreadsheet calculator to estimate efficiency and conducting a comparison to the delivered efficiency to determine if a more detailed examination should be made.
(d)(1) For hydronic heaters subject to the 2020 cord wood alternative compliance option specified in § 60.5474(b)(3), the manufacturers must have the approved laboratory conduct cord wood testing using the test methods listed below:
(i) Method 28WHH;
(ii) Method 28WHH PTS; or
(iii) ASTM E2618-13 (IBR, see § 60.17) (using cord wood).
(2) If the heater is equipped with full or partial heat storage, the manufacturer, retailer and installer must not sell or install the heater with less heat storage capacity than is used in the certification test.
(3) The manufacturer and approved laboratory must make the following adjustments to the methods listed in (d)(1) of this section:
(i) For ASTM E2618-13 (IBR, see § 60.17), use the burn rate categories specified in Method 28WHH;
(ii) For all methods, report the results separately per burn rate category.
(e) For forced-air furnaces, use CSA Method B415.1-10 (IBR, see § 60.17) to measure the heat output (mmBtu/hr) and particulate matter emission rate (lb/mmBtu heat output), except use the burn rate categories in Method 28WHH for the 2020 particulate matter emission standards. For the 2020 particulate matter emission standards, report the particulate matter, efficiency and CO emission results separately per burn rate category.
(f) For affected wood heaters subject to the particulate matter emission standards, particulate matter emission concentrations must be measured with ASTM E2515-11 (IBR, see § 60.17) with the following exceptions, eliminate section 9.6.5.1 of ASTM E2515-11 and perform the post-test leak checks as described in paragraph (f)(1) of this section. Additionally, if a component change of either sampling train is needed during sampling, then perform the leak check specified in paragraph (f)(2) of this section. Four-inch filters and Teflon membrane filters or Teflon-coated glass fiber filters may be used in ASTM E2515-11. For all tests conducted using ASTM 2515-11, with the exceptions described in paragraphs (f)(1) and (2) of this section, the manufacturer and approved test laboratory must also measure the first hour of particulate matter emissions for each test run by sampling with a third, identical and independent sampling train operated concurrently with the first hour of PM paired train compliance testing. The manufacturer and approved test laboratory must report the test results for this third train separately as the first hour emissions.
(1) Post-test leak check. A leak check of each sampling train is mandatory at the conclusion of each sampling run before sample recovery. The leak check must be performed in accordance with the procedures of ASTM E2515-11, section 9.6.4.1 (IBR, see § 60.17), except that it must be conducted at a vacuum equal to or greater than the maximum value reached during the sampling run. If the leakage rate is found to be no greater than 0.0003 m 3 /min (0.01 cfm) or 4% of the average sampling rate (whichever is less), the leak check results are acceptable. If a higher leakage rate is obtained, the sampling run is invalid.
(2) Leak checks during sample run. If, during a sampling run, a component ( e.g., filter assembly) change becomes necessary, a leak check must be conducted immediately before the change is made. Record the sample volume before and after the leak test. The sample volume collected during any leak checks must not be included in the total sample volume for the test run. The leak check must be done according to the procedure outlined in ASTM E2515-11, section 9.6.4.1 (IBR, see § 60.17), except that it must be done at a vacuum equal to or greater than the maximum value recorded up to that point in the sampling run. If the leakage rate is found to be no greater than 0.0003 m 3 /min (0.01 cfm) or 4% of the average sampling rate (whichever is less), the leak check results are acceptable. If a higher leakage rate is obtained, the sampling run is invalid.
Immediately after component changes, leak checks are optional but highly recommended. If such leak checks are done, the procedure in paragraph (f)(1) of this section should be used.
(g) Douglas fir may be used in ASTM E2618-13 and CSA B415.1-10 (IBR, see § 60.17).
(h) The manufacturer of an affected central heater model line must notify the Administrator of the date that certification testing is to begin, by email, to WoodHeaterReports@epa.gov . This notice must be at least 30 days before the start of testing. The notification of testing must include the manufacturer's name and physical and email addresses, the approved test laboratory's name and physical and email addresses, third-party certifier name, the model name and number (or, if unavailable, some other way to distinguish between models), and the dates of testing. The laboratory may substitute certification testing of another affected central heater on the original date in order to ensure regular laboratory testing operations.
(i) The approved test laboratory must allow the manufacturer, the manufacturer's approved third-party certifier, the EPA and delegated state regulatory agencies to observe certification testing. However, manufacturers must not involve themselves in the conduct of the test after the pretest burn has begun. Communications between the manufacturer and laboratory or third-party certifier personnel regarding operation of the central heater must be limited to written communications transmitted prior to the first pretest burn of the certification test series. During certification tests, the manufacturer may communicate with the third-party certifier, and only in writing to notify them that the manufacturer has observed a deviation from proper test procedures by the laboratory. All communications must be included in the test documentation required to be submitted pursuant to § 60.5475(b)(5) and must be consistent with instructions provided in the owner's manual required under § 60.5478(f).
§ 60.5477   What procedures must I use for EPA approval of a test laboratory or EPA approval of a third-party certifier?
(a) Test laboratory approval. (1) A laboratory must apply to the Administrator for approval to test under this rule by submitting documentation that the laboratory is accredited by a nationally recognized accrediting entity under ISO-IEC Standard 17025 to perform testing using the test methods specified under § 60.5476. Laboratories accredited by EPA prior to May 15, 2015 may have until May 15, 2018 to submit documentation that they have accreditation under ISO-IEC Standard 17025 to perform testing using the test methods specified under § 60.5476. ISO accreditation is required for all other laboratories performing hydronic heater testing beginning on May 15, 2015, and performing forced-air furnace testing beginning on November 16, 2015.
(2) As part of the application, the test laboratory must:
(i) Agree to participate biennially in an independently operated proficiency testing program with no direct ties to the laboratories participating;
(ii) Agree to allow the Administrator, regulatory agencies and certifying bodies access to observe certification testing;
(iii) Agree to comply with calibration, reporting and recordkeeping requirements that affect testing laboratories; and
(iv) Agree to perform a compliance audit test at the manufacturer's expense at the testing cost normally charged to such manufacturer if the laboratory is selected by the Administrator to conduct the compliance audit test of the manufacturer's model line. The test laboratory must provide a preliminary audit test report to the Administrator within 14 days of the completion of testing, if a central heater exceeds the applicable emission limit in § 60.5474. The test laboratory must provide the Administrator and the manufacturer, within 30 days of the completion of audit testing, all documentation pertaining to the test, including the complete test report and raw data sheets, laboratory technician notes, and test results for all test runs.
(v) Have no conflict of interest and receive no financial benefit from the outcome of certification testing conducted pursuant to § 60.5475.
(vi) Agree to not perform initial certification tests on any models manufactured by a manufacturer for which the laboratory has conducted research and development design services within the last 5 years.
(vii) Agree to seal any wood heater on which it performed certification tests, immediately upon completion or suspension of certification testing, by using a laboratory-specific seal.
(viii) Agree to immediately notify the Administrator of any suspended tests through email and in writing, giving the date suspended, the reason(s) why, and the projected date for restarting. The laboratory must submit the operation and test data obtained, even if the test is not completed.
(3) If the EPA approves the laboratory, the Administrator will provide the test laboratory with a certificate of approval for testing under this rule. If the EPA does not approve the laboratory, the Administrator will give written notice to the laboratory setting forth the basis for the determination.
(b) Revocation of test laboratory approval. (1) The Administrator may revoke the EPA laboratory approval if it is determined that the laboratory:
(i) Is no longer accredited by the accreditation body;
(ii) Does not follow required procedures or practices;
(iii) Has falsified data or otherwise misrepresented emission data;
(iv) Failed to participate in a proficiency testing program, in accordance with its commitment under paragraph (a)(2)(i) of this section; or
(v) Failed to seal the central heater in accordance with paragraph (a)(2)(vii) of this section.
(2) Revocation of approval under this paragraph (b) will not take effect until the laboratory concerned has been given written notice by the Administrator setting forth the basis for the proposed determination and an opportunity for a hearing under § 60.5481. However, if revocation is ultimately upheld, all tests conducted by the laboratory after written notice was given will, at the discretion of the Administrator, be declared invalid.
(c) Period of test laboratory approval. (1) With the exception of laboratories meeting the provisions of paragraph (c)(2) of this section, and unless revoked sooner, a certificate of approval for testing under this rule is valid for 5 years from the date of issuance.
(2) Laboratories accredited by the EPA by May 15, 2015, under the provisions of § 60.535 as in effect prior to that date may continue to be EPA accredited and deemed EPA approved for testing under this subpart until May 15, 2018, at which time the EPA accreditation and approval ends unless the laboratory has obtained accreditation under § 60.5477 as in effect on that date.
(d) Third-party certifier approval. (1) A Third-party certifier may apply to the Administrator for approval to be an EPA-approved third-party certifier by submitting credentials demonstrating that it has been accredited by a nationally recognized accrediting entity to perform certifications and inspections under ISO-IEC Standard 17025, ISO-IEC Standard 17065 and ISO-IEC Standard 17020.
(2) As part of the application, the third-party certifier must:
(i) Agree to offer to contract with central heater manufacturers to perform third-party certification activities according to the requirements set out in this subpart.
(ii) Agree to periodically conduct audits as described in § 60.5475(m) and the manufacturer's quality assurance program;
(iii) Agree to comply with reporting and recordkeeping requirements that affect approved central heater testing laboratories and third-party certifiers;
(iv) Have no conflict of interest and receive no financial benefit from the outcome of certification testing conducted pursuant to § 60.5475;
(v) Agree to make available to the Administrator supporting documentation for each central heater certification and audit; and
(vi) Agree to not perform initial certification reviews on any models manufactured by a manufacturer for which the third-party certifier has conducted research and development design services within the last 5 years.
(3) If approved, the Administrator will provide the third-party certifier with a certificate of approval. The approval will expire 5 years after being issued unless renewed by the third-party certifier. If the EPA denies the approval, the Administrator will give written notice to the third-party certifier for the basis for the determination.
(e) Revocation of third-party certifier approval. (1) The Administrator will revoke the third-party certifier's EPA approval if it is determined that the certifier:
(i) Is no longer accredited by the accreditation body;
(ii) Does not follow required procedures or practices; or
(iii) Has falsified certification data or otherwise misrepresented emission data.
(2) Revocation of approval under this paragraph (e) will not take effect until the certifier concerned is given written notice by the Administrator setting forth the basis for the proposed determination and an opportunity for a hearing under § 60.5481. However, if revocation is upheld, all certifications by the certifier after written notice was given will, at the discretion of the Administrator, be declared invalid.
§ 60.5478   What requirements must I meet for permanent labels, temporary labels (hangtags), and owner's manuals?
(a) General permanent label requirements. (1) Each affected central heater manufactured or sold on or after the date the applicable standards come into effect as specified in § 60.5474, must have a permanent label affixed to it that meets the requirements of this section.
(2) The permanent label must contain the following information:
(i) Month and year of manufacture of the individual unit;
(ii) Model name and number;
(iii) Certification test emission value, test method, and standard met; and
(iv) Serial number.
(3) The permanent label must:
(i) Be affixed in a readily visible or accessible location in such a manner that it can be easily viewed before and after the appliance is installed (a easily removable façade can be used for aesthetic purposes);
(ii) Be at least 8.9 cm long and 5.1 cm wide (3 1/2 inches long and 2 inches wide);
(iii) Be made of a material expected to last the lifetime of the central heater;
(iv) Present the required information in a manner so that it is likely to remain legible for the lifetime of the central heater; and
(v) Be affixed in such a manner that it cannot be removed without damage to the label.
(4) The permanent label may be combined with any other label, as long as the required information is displayed, the integrity of the permanent label is not compromised, and the permanent label meets the requirements of § 60.5478(a)(3).
(5) Any label statement under paragraph (b) of this section constitutes a representation by the manufacturer as to any central heater that bears it:
(i) That a certification of compliance was in effect at the time the central heater left the possession of the manufacturer;
(ii) That the manufacturer was, at the time the label was affixed, conducting a quality assurance program in conformity with § 60.5475(m); and
(iii) That all the central heaters individually tested for emissions by the manufacturer under its quality assurance program pursuant to § 60.5475(m) met the applicable emissions limit.
(b) Permanent label requirements for central heaters. If a central heater belongs to a model line certified under § 60.5475, and no unit in the model line has been found to exceed the applicable emission limits or tolerances through quality assurance testing, one of the following statements, as appropriate, must appear on the permanent label:
(c) Additional permanent label content. The permanent label for all certified central heaters must also contain the following statement on the permanent label:
(d) Permanent label requirements for affected wood heaters with exemptions under § 60.5472(b). (1) If an affected central heater is manufactured in the United States for export as provided in § 60.5472(b)(1), the following statement must appear on the permanent label:
(2) If an affected central heater is manufactured for use for research and development purposes as provided in § 60.5472(b)(2), the following statement must appear on the permanent label:
(3) If an affected central heater is a non wood-burning central heater exclusively as provided in § 60.5472(b)(3), the following statement must appear on the permanent label:
(e) Temporary label (hangtag) voluntary options. (1) Each model line certified to meet the 2020 particulate emission standards prior to May 15, 2020 may display the hangtags specified in section 3 of appendix I of this part. The electronic template will be provided by the Administrator upon approval of the certification.
(2) The hangtags in paragraph (e)(1) of this section end upon May 15, 2020.
(3) Each model certified to meet the 2020 Cord Wood Alternative Compliance Option may display the cord wood temporary label specified in section 3 of appendix I of this part. The electronic template will be provided by the Administrator upon approval of the certification.
(f) Owner's manual requirements. (1) Each affected central heater offered for sale by a commercial owner must be accompanied by an owner's manual that must contain the information listed in paragraph (f)(2) of this section (pertaining to installation), and paragraph (f)(3) of this section (pertaining to operation and maintenance). Such information must be adequate to enable consumers to achieve optimal emissions performance. Such information must be consistent with the operating instructions provided by the manufacturer to the approved test laboratory for operating the central heater during certification testing, except for details of the certification test that would not be relevant to the ultimate user. The commercial owner must also make current and historical owner's manuals available on the company Web site and upon request to the EPA.
(2) Guidance on proper installation information, including stack height, heater location and achieving proper draft.
(3) Proper operation and maintenance information, including minimizing visible emissions.
(i) Fuel loading and re-loading procedures, recommendations on fuel selection and warnings on what fuels not to use, such as unseasoned wood, treated wood, colored paper, cardboard, solvents, trash and garbage;
(ii) Fire starting procedures;
(iii) Proper use of air controls, including how to establish good combustion and how to ensure good combustion at the lowest burn rate for which the heater is warranted;
(iv) Ash removal procedures;
(v) Instructions for replacement of gaskets and other parts that are critical to the emissions performance of the unit and other maintenance and repair instructions;
(vi) For catalytic models, information on the following pertaining to the catalytic combustor: Procedures for achieving and maintaining catalyst activity, maintenance procedures, procedures for determining deterioration or failure, procedures for replacement and information on how to exercise warranty rights;
(vii) For catalytic models, the following statement—
(viii) For noncatalytic models, the following statement—
(4) Any manufacturer using the EPA-recommended language contained in appendix I of this part to satisfy any requirement of this paragraph (f) will be considered to be in compliance with that requirement, provided that the particular model language is printed in full, with only such changes as are necessary to ensure accuracy for the particular model line.
(g) Central heaters that are affected by this subpart, but that have been owned and operated by a noncommercial owner, are not subject to paragraphs (e) and (f) of this section when offered for resale.
§ 60.5479   What records must I keep and what reports must I submit?
(a)(1) Each manufacturer who holds a certificate of compliance pursuant to § 60.5475(a)(2) for a model line must maintain records containing the information required by paragraphs (a)(2) through (4) of this section with respect to that model line for at least 5 years.
(2) All documentation pertaining to the certification test used to obtain certification, including the full test report and raw data sheets, laboratory technician notes, calculations, and the test results for all test runs, and discussions of the appropriateness and validity of all test runs, including runs attempted but not completed. The retained certification test documentation must include, as applicable, detailed discussions of all anomalies, whether all burn rate categories were properly achieved, any data not used in the calculations and, for any test runs not completed, the data that were collected and the reason that the test run was not completed. The retained certification test also must include documentation that the burn rate for the low burn category was no greater than the rate that an operator can achieve in home use and no greater than is advertised by the manufacturer or retailer.
(3) Results of the quality assurance program inspections required pursuant to § 60.5475(m).
(4) For emissions tests conducted pursuant to the quality assurance program required by § 60.5475(m), all test reports, data sheets, laboratory technician notes, calculations, and test results for all test runs, the corrective actions taken, if any, and any follow-up actions such as additional testing.
(b) Each approved test laboratory and third-party certifier must maintain records consisting of all documentation pertaining to each certification test, quality assurance program inspection and audit test, including the full test report and raw data sheets, technician notes, calculations, the test results for all test runs. Each approved test laboratory must submit accreditation credentials and all proficiency test results to the Administrator. Each third-party certifier must submit each certification test, quality assurance program inspection report and ISO-IEC accreditation credentials to the Administrator.
(c) Each manufacturer must retain each central heater upon which certification tests were performed and certification granted under § 60.5475(a)(2) at the manufacturer's facility for 5 years after the certification test. Each central heater must remain sealed and unaltered. Any such central heater must be made available upon request to the Administrator for inspection and testing.
(d) Each manufacturer of an affected central heater model line certified pursuant to § 60.5475(a)(2) must submit a report to the Administrator every 2 years following issuance of a certificate of compliance for each model line. This report must include the sales for each model by state and certify that no changes in the design or manufacture of the model line have been made that require recertification pursuant to § 60.5475(k).
(e)(1) Unless otherwise specified, all records required under this section must be maintained by the manufacturer, commercial owner of the affected central heater, approved test laboratory or third-party certifier for a period of no less than 5 years.
(2) Unless otherwise specified, all reports to the Administrator required under this subpart must be made to: WoodHeaterReports@epa.gov.
(f) Within 60 days after the date of completing each performance test ( e.g., initial certification test, tests conducted for quality assurance and tests for renewal or recertification), each manufacturer must submit performance test data electronically to WoodHeaterReports@epa.gov. Owners or operators who claim that some of the information being submitted for performance tests is CBI ( e.g., design drawings) must submit a complete file, including information claimed to be CBI on a compact disk or other commonly used electronic storage media (including, but not limited to, flash drives), by mail, and the same file with the CBI omitted, electronically. The compact disk must be clearly marked as CBI and mailed to U.S. EPA, OECA CBI Office, Attention: Residential Wood Heater Compliance Program, Washington, DC 20004. Emission data and all information necessary to determine compliance, except sensitive engineering drawings and sensitive detailed material specifications, cannot be claimed as CBI.
(g) Within 30 days of receiving a certification of compliance for a model line, the manufacturer must make the full non-CBI test report and the summary of the test report available on the manufacturer's Web site.
(h) Each manufacturer who uses the exemption for R&D heaters under § 60.5472(b)(2) must maintain records for at least 5 years documenting where the heaters were located, that the heaters were never offered for sale or sold and that the heaters were not used for the purpose of heating.
§ 60.5480   What activities are prohibited under this subpart?
(a) No person is permitted to advertise for sale, offer for sale, sell or operate an affected residential hydronic heater or forced-air furnace or other central heater that does not have affixed to it a permanent label pursuant to § 60.5478(b) through (d), as applicable.
(b) No person is permitted to advertise for sale, offer for sale, or sell an affected central heater labeled under § 60.5478(d)(1) except for export. No person is permitted to operate an affected central heater in the United States if it is labeled under § 60.5478(d)(1).
(c)(1) No commercial owner is permitted to advertise for sale, offer for sale, or sell an affected central heater permanently labeled under § 60.5478(b) unless:
(i) The affected appliance has been certified to comply with the particulate emission standards pursuant to § 60.5474 as applicable; and
(ii) The commercial owner provides any purchaser or transferee with an owner's manual that meets the requirements of § 60.5478(f), a copy of the warranty and a moisture meter.
(2) A commercial owner other than a manufacturer complies with the requirements of paragraph (c)(1) of this section if the commercial owner:
(i) Receives the required documentation from the manufacturer or a previous commercial owner; and
(ii) Provides that documentation unaltered to any person to whom the central heater that it covers is sold or transferred.
(d)(1) In any case in which the Administrator revokes a certificate of compliance either for the knowing submission of false or inaccurate information or other fraudulent acts, or based on a finding under § 60.5475(l)(1)(ii) that the certification test was not valid, the Administrator may give notice of that revocation and the grounds for it to all commercial owners.
(2) On and after the date of receipt of the notice given under paragraph (d)(1) of this section, no commercial owner is permitted to sell any central heater covered by the revoked certificate (other than to the manufacturer) unless the model line has been recertified in accordance with this subpart.
(e) No person is permitted to install or operate an affected central heater except in a manner consistent with the instructions on its permanent label and in the owner's manual pursuant to § 60.5478(f), including only using fuels for which the unit is certified.
(f) No person is permitted to operate, sell or offer for sale an affected central heater that was originally equipped with a catalytic combustor if the catalytic element is deactivated or removed.
(g) No person is permitted to operate, sell or offer for sale an affected central heater that has been physically altered to exceed the tolerance limits of its certificate of compliance, pursuant to § 60.5475(k).
(h) No person is permitted to alter, deface, or remove any permanent label required to be affixed pursuant to § 60.5478(a) through (d), as applicable.
(i) If a temporary label is affixed to the central heater, retailers may not sell or offer for sale that central heater unless the temporary label affixed is in accordance with § 60.5478(e), as applicable.
§ 60.5481   What hearing and appeal procedures apply to me?
(a)(1) The affected manufacturer, laboratory or third-party certifier may request a hearing under this section within 30 days following receipt of the required notification in any case where the Administrator—
(i) Denies an application for a certificate of compliance under § 60.5475 (a)(2);
(ii) Denies an application for a renewal of certification under § 60.5475(i);
(iii) Issues a notice of revocation of certification under § 60.5475(l);
(iv) Denies an application for laboratory approval under § 60.5477(a);
(v) Issues a notice of revocation of laboratory approval under § 60.5477(b).
(vi) Denies an application for third-party certifier approval under § 60.5477(d); or
(vii) Issues a notice of revocation of third-party certifier approval under § 60.5477(e).
(2) In any case where the Administrator issues a notice of revocation under § 60.5475(n)(3)(ii), the manufacturer may request a hearing under this section with the time limits set out in § 60.5475(n)(3)(ii).
(b) Any hearing request must be in writing, must be signed by an authorized representative of the petitioning manufacturer or laboratory, and must include a statement setting forth with particularity the petitioner's objection to the Administrator's determination or proposed determination.
(c)(1) Upon receipt of a request for a hearing under paragraph (a) of this section, the Administrator will request the Chief Administrative Law Judge to designate an Administrative Law Judge as Presiding Officer for the hearing. If the Chief Administrative Law Judge replies that no Administrative Law Judge is available to perform this function, the Administrator will designate a Presiding Officer who has not had any prior responsibility for the matter under review, and who is not subject to the direct control or supervision of someone who has had such responsibility.
(2) The hearing will commence as soon as practicable at a time and place fixed by the Presiding Officer.
(3)(i) A motion for leave to intervene in any proceeding conducted under this section must set forth the grounds for the proposed intervention, the position and interest of the movant and the likely impact that intervention will have on the expeditious progress of the proceeding. Any person already a party to the proceeding may file an answer to a motion to intervene, making specific reference to the factors set forth in the foregoing sentence and paragraph (c)(3)(iii) of this section within 10 days after service of the motion for leave to intervene.
(ii) A motion for leave to intervene in a proceeding must ordinarily be filed before the first prehearing conference or, in the absence of a prehearing conference, prior to the setting of a time and place for a hearing. Any motion filed after that time must include, in addition to the information set forth in paragraph (c)(3)(i) of this section, a statement of good cause for the failure to file in a timely manner. The intervener shall be bound by any agreements, arrangements and other matters previously made in the proceeding.
(iii) A motion for leave to intervene may be granted only if the movant demonstrates that his presence in the proceeding would not unduly prolong or otherwise prejudice the adjudication of the rights of the original parties, and that movant may be adversely affected by a final order. The intervener will become a full party to the proceeding upon the granting of leave to intervene.
(iv) Persons not parties to the proceeding may move for leave to file amicus curiae briefs. The movant must state his interest and the reasons why the proposed amicus brief is desirable. If the motion is granted, the Presiding Officer or Administrator will issue an order setting the time for filing such brief. An amicus curia may participate in any briefing after his motion is granted, and will be served with all briefs, reply briefs, motions, and orders relating to issues to be briefed.
(4) In computing any period of time prescribed or allowed in this subpart, the day of the event from which the designated period begins to run will not be included. Saturdays, Sundays, and federal legal holidays will be included. When a stated time expires on a Saturday, Sunday or legal holiday, the stated time period will be extended to include the next business day.
(d)(1) Upon his appointment the Presiding Officer must establish a hearing file. The file will consist of the notice issued by the Administrator under § 60.5475(c)(2), § 60.5475(f)(3), § 60.5475(i)(4), § 60.5475(l)(2), § 60.5475(n)(3)(ii)(A), § 60.5477(a)(3), § 60.5477(b)(2), § 60.5477(d)(3) or § 60.5477(e)(2), together with any accompanying material, the request for a hearing and the supporting data submitted therewith, and all documents relating to the request for certification or approval, or the proposed revocation of either.
(2) The hearing file must be available for inspection by any party, to the extent authorized by law, at the office of the Presiding Officer, or other place designated by him.
(e) Any party may appear in person, or may be represented by counsel or by any other duly authorized representative.
(f)(1) The Presiding Officer, upon the request of any party, or at his discretion, may order a prehearing conference at a time and place specified by him to consider the following:
(i) Simplification of the issues;
(ii) Stipulations, admissions of fact, and the introduction of documents;
(iii) Limitation of the number of expert witnesses;
(iv) Possibility of agreement disposing of all or any of the issues in dispute; and
(v) Such other matters as may aid in the disposition of the hearing, including such additional tests as may be agreed upon by the parties.
(2) The results of the conference must be reduced to writing by the Presiding Officer and made part of the record.
(g)(1) Hearings shall be conducted by the Presiding Officer in an informal but orderly and expeditious manner. The parties may offer oral or written evidence, subject to the exclusion by the Presiding Officer of irrelevant, immaterial and repetitious evidence.
(2) Witnesses will not be required to testify under oath. However, the Presiding Officer will call to the attention of witnesses that their statements may be subject to penalties under title 18 U.S.C. 1001 for knowingly making false statements or representations or using false documents in any matter within the jurisdiction of any department or agency of the United States.
(3) Any witness may be examined or cross-examined by the Presiding Officer, the parties, or their representatives.
(4) Hearings must be recorded verbatim. Copies of transcripts of proceedings may be purchased by the applicant from the reporter.
(5) All written statements, charts, tabulations and similar data offered in evidence at the hearings must, upon a showing satisfactory to the Presiding Officer of their authenticity, relevancy and materiality, be received in evidence and will constitute a part of the record.
(h)(1) The Presiding Officer will make an initial decision which must include written findings and conclusions and the reasons or basis therefor on all the material issues of fact, law, or discretion presented on the record. The findings, conclusions and written decision must be provided to the parties and made a part of the record. The initial decision will become the decision of the Administrator without further proceedings unless there is an appeal to the Administrator or motion for review by the Administrator. Except as provided in paragraph (h)(3) of this section, any such appeal must be taken within 20 days of the date the initial decision was filed.
(2) On appeal from or review of the initial decision the Administrator will have all the powers which he would have in making the initial decision including the discretion to require or allow briefs, oral argument, the taking of additional evidence or the remanding to the Presiding Officer for additional proceedings. The decision by the Administrator must include written findings and conclusions and the reasons or basis therefor on all the material issues of fact, law, or discretion presented on the appeal or considered in the review.
(3) In any hearing requested under paragraph (a)(2) of this section the Presiding Officer must render the initial decision within 60 days of that request. Any appeal to the Administrator must be taken within 10 days of the initial decision, and the Administrator must render a decision in that appeal within 30 days of the filing of the appeal.
§ 60.5482   Who implements and enforces this subpart?
(a) Under section 111(c) of the Clean Air Act, the Administrator may delegate the following implementation and enforcement authority to a state, local or tribal authority upon request:
(1) Enforcement of prohibitions on the installation and operation of affected central heaters in a manner inconsistent with the installation and owner's manual;
(2) Enforcement of prohibitions on operation of catalytic central heaters where the catalyst has been deactivated or removed;
(3) Enforcement of prohibitions on advertisement and/or sale of uncertified model lines;
(4) Enforcement of prohibitions on advertisement and/or sale of affected central heaters that do not have required permanent label;
(5) Enforcement of proper labeling of affected central heaters;
(6) Enforcement of compliance with other labeling requirements for affected central heaters.
(7) Enforcement of certification testing procedures;
(8) Enforcement of requirements for sealing of the tested central heaters and meeting parameter limits; and
(9) Enforcement of compliance requirements of EPA-approved laboratories.
(b) Delegations shall not include:
(1) Decisions on certification;
(2) Revocation of certification;
(3) Establishment or revision of standards;
(4) Establishment or revision of test methods;
(5) Laboratory and third-party certifier approvals and revocations;
(6) Enforcing provisions governing content of owner's manuals; and
(7) Hearings and appeals procedures.
(c) Nothing in these delegations will prohibit the Administrator from enforcing any applicable requirements.
(d) Nothing in these delegations will limit delegated entities from using their authority under section 116 of the Clean Air Act to adopt or enforce more restrictive requirements.
§ 60.5483   What parts of the General Provisions do not apply to me?
The following provisions of subpart A of part 60 do not apply to this subpart:
(a) Section 60.7;
(b) Section 60.8(a), (c), (d), (e), (f)(1), and (g);
(c) Section 60.15(d).
§ 60.5508   What is the purpose of this subpart?
This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a steam generating unit or an integrated gasification combined cycle (IGCC) facility that commences construction after January 8, 2014, commences reconstruction after June 18, 2014, or commences modification after January 8, 2014, but on or before May 23, 2023. This subpart also establishes emission standards and compliance schedules for the control of GHG emissions from a stationary combustion turbine that commences construction after January 8, 2014, but on or before May 23, 2023, or commences reconstruction after June 18, 2014, but on or before May 23, 2023. An affected steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this subpart, be referred to as an affected electric generating unit (EGU).
§ 60.5509   What are my general requirements for complying with this subpart?
(a) Except as provided for in paragraph (b) of this section, the GHG standards included in this subpart apply to any steam generating unit or IGCC that commenced construction after January 8, 2014, or commenced modification or reconstruction after June 18, 2014, that meets the relevant applicability conditions in paragraphs (a)(1) and (2) of this section. The GHG standards included in this subpart also apply to any stationary combustion turbine that commenced construction after January 8, 2014, but on or before May 23, 2023, or commenced reconstruction after June 18, 2014, but on or before May 23, 2023, that meets the relevant applicability conditions in paragraphs (a)(1) and (2) of this section.
(1) Has a base load rating greater than 260 gigajoules per hour (GJ/h) (250 million British thermal units per hour (MMBtu/h)) of fossil fuel (either alone or in combination with any other fuel); and
(2) Serves a generator or generators capable of selling greater than 25 megawatts (MW) of electricity to a utility power distribution system.
(b) You are not subject to the requirements of this subpart if your affected EGU meets any of the conditions specified in paragraphs (b)(1) through (10) of this section.
(1) Your EGU is a steam generating unit or IGCC whose annual net-electric sales have never exceeded one-third of its potential electric output or 219,000 megawatt-hour (MWh), whichever is greater, and is currently subject to a federally enforceable permit condition limiting annual net-electric sales to no more than one-third of its potential electric output or 219,000 MWh, whichever is greater.
(2) Your EGU is capable of deriving 50 percent or more of the heat input from non-fossil fuel at the base load rating and is also subject to a federally enforceable permit condition limiting the annual capacity factor for all fossil fuels combined of 10 percent (0.10) or less.
(3) Your EGU is a combined heat and power unit that is subject to a federally enforceable permit condition limiting annual net-electric sales to no more than either 219,000 MWh or the product of the design efficiency and the potential electric output, whichever is greater.
(4) Your EGU serves a generator along with other steam generating unit(s), IGCC, or stationary combustion turbine(s) where the effective generation capacity (determined based on a prorated output of the base load rating of each steam generating unit, IGCC, or stationary combustion turbine) is 25 MW or less.
(5) Your EGU is a municipal waste combustor that is subject to subpart Eb of this part.
(6) Your EGU is a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part.
(7) Your EGU is a steam generating unit or IGCC that undergoes a modification resulting in an hourly increase in CO 2 emissions (mass per hour) of 10 percent or less (2 significant figures). Modified units that are not subject to the requirements of this subpart pursuant to this paragraph (b)(7) continue to be existing units under section 111 with respect to CO 2 emissions standards.
(8) Your EGU is a stationary combustion turbine that is not capable of combusting natural gas ( e.g., not connected to a natural gas pipeline).
(9) Your EGU derives greater than 50 percent of the heat input from an industrial process that does not produce any electrical or mechanical output or useful thermal output that is used outside the affected EGU.
(10) Your EGU is subject to subpart TTTTa of this part.
§ 60.5515   Which pollutants are regulated by this subpart?
(a) The pollutants regulated by this subpart are greenhouse gases. The greenhouse gas standard in this subpart is in the form of a limitation on emission of carbon dioxide.
(b) PSD and title V thresholds for greenhouse gases. (1) For the purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 51.166(b)(48) of this chapter and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, § 51.166(b)(48).
(2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in § 52.21(b)(49) of this chapter.
(3) For the purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 70.2.
(4) For the purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 71.2.
§ 60.5520   What CO2emissions standard must I meet?
(a) For each affected EGU subject to this subpart, you must not discharge from the affected EGU any gases that contain CO 2 in excess of the applicable CO 2 emission standard specified in table 1 or 2 to this subpart, consistent with paragraphs (b), (c), and (d) of this section, as applicable.
(b) Except as specified in paragraphs (c) and (d) of this section, you must comply with the applicable gross or net energy output standard, and your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable gross or net energy output standard. For the remainder of this subpart (for sources that do not qualify under paragraphs (c) and (d) of this section), where the term “gross or net energy output” is used, the term that applies to you is “gross energy output.”
(c) As an alternate to meeting the requirements in paragraph (b) of this section, an owner or operator of a stationary combustion turbine may petition the Administrator in writing to comply with the alternate applicable net energy output standard. If the Administrator grants the petition, beginning on the date the Administrator grants the petition, the affected EGU must comply with the applicable net energy output-based standard included in this subpart. Your operating permit must include monitoring, recordkeeping, and reporting methodologies based on the applicable net energy output standard. For the remainder of this subpart, where the term “gross or net energy output” is used, the term that applies to you is “net energy output.” Owners or operators complying with the net output-based standard must petition the Administrator to switch back to complying with the gross energy output-based standard.
(d) Owners or operators of a stationary combustion turbine that maintain records of electric sales to demonstrate that the stationary combustion turbine is subject to a heat input-based standard in table 2 to this subpart that are only permitted to burn one or more uniform fuels, as described in paragraph (d)(1) of this section, are only subject to the monitoring requirements in paragraph (d)(1). Owners or operators of all other stationary combustion turbines that maintain records of electric sales to demonstrate that the stationary combustion turbines are subject to a heat input-based standard in table 2 are only subject to the requirements in paragraph (d)(2) of this section.
(1) Owners or operators of stationary combustion turbines that are only permitted to burn fuels with a consistent chemical composition ( i.e., uniform fuels) that result in a consistent emission rate of 69 kilograms per gigajoule (kg/GJ) (160 lb CO 2 /MMBtu) or less are not subject to any monitoring or reporting requirements under this subpart. These fuels include, but are not limited to hydrogen, natural gas, methane, butane, butylene, ethane, ethylene, propane, naphtha, propylene, jet fuel kerosene, No. 1 fuel oil, No. 2 fuel oil, and biodiesel. Stationary combustion turbines qualifying under this paragraph are only required to maintain purchase records for permitted fuels.
(2) Owners or operators of stationary combustion turbines permitted to burn fuels that do not have a consistent chemical composition or that do not have an emission rate of 69 kg/GJ (160 lb CO 2 /MMBtu) or less (e.g., non-uniform fuels such as residual oil and non-jet fuel kerosene) must follow the monitoring, recordkeeping, and reporting requirements necessary to complete the heat input-based calculations under this subpart.
§ 60.5525   What are my general requirements for complying with this subpart?
Combustion turbines qualifying under § 60.5520(d)(1) are not subject to any requirements in this section other than the requirement to maintain fuel purchase records for permitted fuel(s). For all other affected sources, compliance with the applicable CO 2 emission standard of this subpart shall be determined on a 12-operating-month rolling average basis. See table 1 or 2 to this subpart for the applicable CO 2 emission standards.
(a) You must be in compliance with the emission standards in this subpart that apply to your affected EGU at all times. However, you must determine compliance with the emission standards only at the end of the applicable operating month, as provided in paragraph (a)(1) of this section.
(1) For each affected EGU subject to a CO 2 emissions standard based on a 12-operating-month rolling average, you must determine compliance monthly by calculating the average CO 2 emissions rate for the affected EGU at the end of the initial and each subsequent 12-operating-month period.
(2) Consistent with § 60.5520(d)(2), if your affected stationary combustion turbine is subject to an input-based CO 2 emissions standard, you must determine the total heat input in GJ or MMBtu from natural gas (HTIP ng ) and the total heat input from all other fuels combined (HTIP o ) using one of the methods under § 60.5535(d)(2). You must then use the following equation to determine the applicable emissions standard during the compliance period:
(b) At all times you must operate and maintain each affected EGU, including associated equipment and monitors, in a manner consistent with safety and good air pollution control practice. The Administrator will determine if you are using consistent operation and maintenance procedures based on information available to the Administrator that may include, but is not limited to, fuel use records, monitoring results, review of operation and maintenance procedures and records, review of reports required by this subpart, and inspection of the EGU.
(c) Within 30 days after the end of the initial compliance period ( i.e., no more than 30 days after the first 12-operating-month compliance period), you must make an initial compliance determination for your affected EGU(s) with respect to the applicable emissions standard in table 1 or 2 to this subpart, in accordance with the requirements in this subpart. The first operating month included in the initial 12-operating-month compliance period shall be determined as follows:
(1) For an affected EGU that commences commercial operation (as defined in 40 CFR 72.2) on or after October 23, 2015, the first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which emissions reporting is required to begin under:
(i) Section 60.5555(c)(3)(i), for units subject to the Acid Rain Program; or
(ii) Section 60.5555(c)(3)(ii)(A), for units that are not in the Acid Rain Program.
(2) For an affected EGU that has commenced commercial operation (as defined in 40 CFR 72.2) prior to October 23, 2015:
(i) If the date on which emissions reporting is required to begin under 40 CFR 75.64(a) has passed prior to October 23, 2015, emissions reporting shall begin according to § 60.5555(c)(3)(i) (for Acid Rain program units), or according to § 60.5555(c)(3)(ii)(B) (for units that are not subject to the Acid Rain Program). The first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which the rule becomes effective; or
(ii) If the date on which emissions reporting is required to begin under 40 CFR 75.64(a) occurs on or after October 23, 2015, then the first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which emissions reporting is required to begin under § 60.5555(c)(3)(ii)(A).
(3) For a modified or reconstructed EGU that becomes subject to this subpart, the first month of the initial compliance period shall be the first operating month (as defined in § 60.5580) after the calendar month in which emissions reporting is required to begin under § 60.5555(c)(3)(iii).
(4) Electric sales by your affected facility generated when it operated during a system emergency as defined in § 60.5580 are excluded for applicability with the base load standard if you can sufficiently provide the documentation listed in § 60.5560(i).
§ 60.5535   How do I monitor and collect data to demonstrate compliance?
(a) Combustion turbines qualifying under § 60.5520(d)(1) are not subject to any requirements in this section other than the requirement to maintain fuel purchase records for permitted fuel(s). If your combustion turbine uses non-uniform fuels as specified under § 60.5520(d)(2), you must monitor heat input in accordance with paragraph (c)(1) of this section, and you must monitor CO 2 emissions in accordance with either paragraph (b), (c)(2), or (c)(5) of this section. For all other affected sources, you must prepare a monitoring plan to quantify the hourly CO 2 mass emission rate (tons/h), in accordance with the applicable provisions in 40 CFR 75.53(g) and (h). The electronic portion of the monitoring plan must be submitted using the ECMPS Client Tool and must be in place prior to reporting emissions data and/or the results of monitoring system certification tests under this subpart. The monitoring plan must be updated as necessary. Monitoring plan submittals must be made by the Designated Representative (DR), the Alternate DR, or a delegated agent of the DR (see § 60.5555(d) and (e)).
(b) You must determine the hourly CO 2 mass emissions in kg from your affected EGU(s) according to paragraphs (b)(1) through (5) of this section, or, if applicable, as provided in paragraph (c) of this section.
(1) For an affected EGU that combusts coal you must, and for all other affected EGUs you may, install, certify, operate, maintain, and calibrate a CO 2 continuous emission monitoring system (CEMS) to directly measure and record hourly average CO 2 concentrations in the affected EGU exhaust gases emitted to the atmosphere, and a flow monitoring system to measure hourly average stack gas flow rates, according to 40 CFR 75.10(a)(3)(i). As an alternative to direct measurement of CO 2 concentration, provided that your EGU does not use carbon separation ( e.g., carbon capture and storage), you may use data from a certified oxygen (O 2 ) monitor to calculate hourly average CO 2 concentrations, in accordance with 40 CFR 75.10(a)(3)(iii). If you measure CO 2 concentration on a dry basis, you must also install, certify, operate, maintain, and calibrate a continuous moisture monitoring system, according to 40 CFR 75.11(b). Alternatively, you may either use an appropriate fuel-specific default moisture value from 40 CFR 75.11(b) or submit a petition to the Administrator under 40 CFR 75.66 for a site-specific default moisture value.
(2) For each continuous monitoring system that you use to determine the CO 2 mass emissions, you must meet the applicable certification and quality assurance procedures in 40 CFR 75.20 and appendices A and B to 40 CFR part 75.
(3) You must use only unadjusted exhaust gas volumetric flow rates to determine the hourly CO 2 mass emissions rate from the affected EGU; you must not apply the bias adjustment factors described in Section 7.6.5 of appendix A to 40 CFR part 75 to the exhaust gas flow rate data.
(4) You must select an appropriate reference method to setup (characterize) the flow monitor and to perform the on-going RATAs, in accordance with 40 CFR part 75. If you use a Type-S pitot tube or a pitot tube assembly for the flow RATAs, you must calibrate the pitot tube or pitot tube assembly; you may not use the 0.84 default Type-S pitot tube coefficient specified in Method 2.
(5) Calculate the hourly CO 2 mass emissions (kg) as described in paragraphs (b)(5)(i) through (iv) of this section. Perform this calculation only for “valid operating hours”, as defined in § 60.5540(a)(1).
(i) Begin with the hourly CO 2 mass emission rate (tons/h), obtained either from equation F-11 in appendix F to 40 CFR part 75 (if CO 2 concentration is measured on a wet basis), or by following the procedure in section 4.2 of appendix F to part 75 (if CO 2 concentration is measured on a dry basis).
(ii) Next, multiply each hourly CO 2 mass emission rate by the EGU or stack operating time in hours (as defined in 40 CFR 72.2), to convert it to tons of CO 2.
(iii) Finally, multiply the result from paragraph (b)(5)(ii) of this section by 907.2 to convert it from tons of CO 2 to kg. Round off to the nearest kg.
(iv) The hourly CO 2 tons/h values and EGU (or stack) operating times used to calculate CO 2 mass emissions are required to be recorded under 40 CFR 75.57(e) and must be reported electronically under 40 CFR 75.64(a)(6). You must use these data to calculate the hourly CO 2 mass emissions.
(c) If your affected EGU exclusively combusts liquid fuel and/or gaseous fuel, as an alternative to complying with paragraph (b) of this section, you may determine the hourly CO 2 mass emissions according to paragraphs (c)(1) through (4) of this section. If you use non-uniform fuels as specified in § 60.5520(d)(2), you may determine CO 2 mass emissions during the compliance period according to paragraph (c)(5) of this section.
(1) If you are subject to an output-based standard and you do not install CEMS in accordance with paragraph (b) of this section, you must implement the applicable procedures in appendix D to part 75 of this chapter to determine hourly EGU heat input rates (MMBtu/h), based on hourly measurements of fuel flow rate and periodic determinations of the gross calorific value (GCV) of each fuel combusted.
(2) For each measured hourly heat input rate, use Equation G-4 in appendix G to part 75 of this chapter to calculate the hourly CO 2 mass emission rate (tons/h). You may determine site-specific carbon-based F-factors (F c ) using Equation F-7b in section 3.3.6 of appendix F to part 75 of this chapter, and you may use these F c values in the emissions calculations instead of using the default F c values in the Equation G-4 nomenclature.
(3) For each “valid operating hour” (as defined in § 60.5540(a)(1), multiply the hourly tons/h CO 2 mass emission rate from paragraph (c)(2) of this section by the EGU or stack operating time in hours (as defined in 40 CFR 72.2), to convert it to tons of CO 2 . Then, multiply the result by 907.2 to convert from tons of CO 2 to kg. Round off to the nearest two significant figures.
(4) The hourly CO 2 tons/h values and EGU (or stack) operating times used to calculate CO 2 mass emissions are required to be recorded under § 75.57(e) of this chapter and must be reported electronically under § 75.64(a)(6) of this chapter. You must use these data to calculate the hourly CO 2 mass emissions.
(5) If you operate a combustion turbine firing non-uniform fuels, as an alternative to following paragraphs (c)(1) through (4) of this section, you may determine CO 2 emissions during the compliance period using one of the following methods:
(i) Units firing fuel gas may determine the heat input during the compliance period following the procedure under § 60.107a(d) and convert this heat input to CO 2 emissions using Equation G-4 in appendix G to part 75 of this chapter.
(ii) You may use the procedure for determining CO 2 emissions during the compliance period based on the use of the Tier 3 methodology under § 98.33(a)(3) of this chapter.
(d) Consistent with § 60.5520, you must determine the basis of the emissions standard that applies to your affected source in accordance with either paragraph (d)(1) or (2) of this section, as applicable:
(1) If you operate a source subject to an emissions standard established on an output basis ( e.g., lb of CO 2 per gross or net MWh of energy output), you must install, calibrate, maintain, and operate a sufficient number of watt meters to continuously measure and record the hourly gross electric output or net electric output, as applicable, from the affected EGU(s). These measurements must be performed using 0.2 class electricity metering instrumentation and calibration procedures as specified under ANSI No. C12.20-2010 (incorporated by reference, see § 60.17). For a combined heat and power (CHP) EGU, as defined in § 60.5580, you must also install, calibrate, maintain, and operate meters to continuously ( i.e., hour-by-hour) determine and record the total useful thermal output. For process steam applications, you will need to install, calibrate, maintain, and operate meters to continuously determine and record the hourly steam flow rate, temperature, and pressure. Your plan shall ensure that you install, calibrate, maintain, and operate meters to record each component of the determination, hour-by-hour.
(2) If you operate a source subject to an emissions standard established on a heat-input basis ( e.g., lb CO 2 /MMBtu) and your affected source uses non-uniform heating value fuels as delineated under § 60.5520(d), you must determine the total heat input for each fuel fired during the compliance period in accordance with one of the following procedures:
(i) Appendix D to part 75 of this chapter;
(ii) The procedures for monitoring heat input under § 60.107a(d);
(iii) If you monitor CO 2 emissions in accordance with the Tier 3 methodology under § 98.33(a)(3) of this chapter, you may convert your CO 2 emissions to heat input using the appropriate emission factor in table C-1 of part 98 of this chapter. If your fuel is not listed in table C-1, you must determine a fuel-specific carbon-based F-factor (F c ) in accordance with section 12.3.2 of EPA Method 19 of appendix A-7 to this part, and you must convert your CO 2 emissions to heat input using Equation G-4 in appendix G to part 75 of this chapter.
(e) Consistent with § 60.5520, if two or more affected EGUs serve a common electric generator, you must apportion the combined hourly gross or net energy output to the individual affected EGUs according to the fraction of the total steam load and/or direct mechanical energy contributed by each EGU to the electric generator. Alternatively, if the EGUs are identical, you may apportion the combined hourly gross or net electrical load to the individual EGUs according to the fraction of the total heat input contributed by each EGU. You may also elect to develop, demonstrate, and provide information satisfactory to the Administrator on alternate methods to apportion the gross energy output. The Administrator may approve such alternate methods for apportioning the gross energy output whenever the demonstration ensures accurate estimation of emissions regulated under this part.
(f) In accordance with §§ 60.13(g) and 60.5520, if two or more affected EGUs that implement the continuous emission monitoring provisions in paragraph (b) of this section share a common exhaust gas stack you must monitor hourly CO 2 mass emissions in accordance with one of the following procedures:
(1) If the EGUs are subject to the same emissions standard in table 1 or 2 to this subpart, you may monitor the hourly CO 2 mass emissions at the common stack in lieu of monitoring each EGU separately. If you choose this option, the hourly gross or net energy output (electric, thermal, and/or mechanical, as applicable) must be the sum of the hourly loads for the individual affected EGUs and you must express the operating time as “stack operating hours” (as defined in 40 CFR 72.2). If you attain compliance with the applicable emissions standard in § 60.5520 at the common stack, each affected EGU sharing the stack is in compliance.
(2) As an alternative, or if the EGUs are subject to different emission standards in table 1 or 2 to this subpart, you must either:
(i) Monitor each EGU separately by measuring the hourly CO 2 mass emissions prior to mixing in the common stack or
(ii) Apportion the CO 2 mass emissions based on the unit's load contribution to the total load associated with the common stack and the appropriate F-factors. You may also elect to develop, demonstrate, and provide information satisfactory to the Administrator on alternate methods to apportion the CO 2 emissions. The Administrator may approve such alternate methods for apportioning the CO 2 emissions whenever the demonstration ensures accurate estimation of emissions regulated under this part.
(g) In accordance with §§ 60.13(g) and 60.5520 if the exhaust gases from an affected EGU that implements the continuous emission monitoring provisions in paragraph (b) of this section are emitted to the atmosphere through multiple stacks (or if the exhaust gases are routed to a common stack through multiple ducts and you elect to monitor in the ducts), you must monitor the hourly CO 2 mass emissions and the “stack operating time” (as defined in § 72.2 of this chapter) at each stack or duct separately. In this case, you must determine compliance with the applicable emissions standard in Table 1 or 2 of this subpart by summing the CO 2 mass emissions measured at the individual stacks or ducts and dividing by the total gross or net energy output for the affected EGU.
§ 60.5540   How do I demonstrate compliance with my CO2emissions standard and determine excess emissions?
(a) In accordance with § 60.5520, if you are subject to an output-based emission standard or you burn non-uniform fuels as specified in § 60.5520(d)(2), you must demonstrate compliance with the applicable CO 2 emission standard in table 1 or 2 to this subpart as required in this section. For the initial and each subsequent 12-operating-month rolling average compliance period, you must follow the procedures in paragraphs (a)(1) through (8) of this section to calculate the CO 2 mass emissions rate for your affected EGU(s) in units of the applicable emissions standard ( e.g., either kg/MWh or kg/GJ). You must use the hourly CO 2 mass emissions calculated under § 60.5535(b) or (c), as applicable, and either the generating load data from § 60.5535(d)(1) for output-based calculations or the heat input data from § 60.5535(d)(2) for heat-input-based calculations. Combustion turbines firing non-uniform fuels that contain CO 2 prior to combustion (e.g., blast furnace gas or landfill gas) may sample the fuel stream to determine the quantity of CO 2 present in the fuel prior to combustion and exclude this portion of the CO 2 mass emissions from compliance determinations.
(1) Each compliance period shall include only “valid operating hours” in the compliance period, i.e., operating hours for which:
(i) “Valid data” (as defined in § 60.5580) are obtained for all of the parameters used to determine the hourly CO 2 mass emissions (kg) and, if a heat input-based standard applies, all the parameters used to determine total heat input for the hour are also obtained; and
(ii) The corresponding hourly gross or net energy output value is also valid data ( Note: For hours with no useful output, zero is considered to be a valid value).
(2) You must exclude operating hours in which:
(i) The substitute data provisions of 40 CFR 75 are applied for any of the parameters used to determine the hourly CO 2 mass emissions or, if a heat input-based standard applies, for any parameters used to determine the hourly heat input;
(ii) An exceedance of the full-scale range of a continuous emission monitoring system occurs for any of the parameters used to determine the hourly CO 2 mass emissions or, if applicable, to determine the hourly heat input; or
(iii) The total gross or net energy output (P gross/net ) or, if applicable, the total heat input is unavailable.
(3) For each compliance period, at least 95 percent of the operating hours in the compliance period must be valid operating hours, as defined in paragraph (a)(1) of this section.
(4) You must calculate the total CO 2 mass emissions by summing the valid hourly CO 2 mass emissions values from § 60.5535 for all of the valid operating hours in the compliance period.
(5) For each valid operating hour of the compliance period that was used in paragraph (a)(4) of this section to calculate the total CO 2 mass emissions, you must determine P gross/net (the corresponding hourly gross or net energy output in MWh) according to the procedures in paragraphs (a)(5)(i) and (ii) of this section, as appropriate for the type of affected EGU(s). For an operating hour in which a valid CO 2 mass emissions value is determined according to paragraph (a)(1)(i) of this section, if there is no gross or net electrical output, but there is mechanical or useful thermal output, you must still determine the gross or net energy output for that hour. In addition, for an operating hour in which a valid CO 2 mass emissions value is determined according to paragraph (a)(1)(i) of this section, but there is no ( i.e., zero) gross electrical, mechanical, or useful thermal output, you must use that hour in the compliance determination. For hours or partial hours where the gross electric output is equal to or less than the auxiliary loads, net electric output shall be counted as zero for this calculation.
(i) Calculate P gross/net for your affected EGU using the following equation. All terms in the equation must be expressed in units of MWh. To convert each hourly gross or net energy output (consistent with § 60.5520) value reported under 40 CFR part 75 to MWh, multiply by the corresponding EGU or stack operating time.
(ii) If applicable to your affected EGU (for example, for combined heat and power), you must calculate (Pt) PS using the following equation:
(6) Sources complying with energy output-based standards must calculate the basis ( i.e., denominator) of their actual 12-operating month emission rate in accordance with paragraph (a)(6)(i) of this section. Sources complying with heat input based standards must calculate the basis of their actual 12-operating month emission rate in accordance with paragraph (a)(6)(ii) of this section.
(i) In accordance with § 60.5520 if you are subject to an output-based standard, you must calculate the total gross or net energy output for the affected EGU's compliance period by summing the hourly gross or net energy output values for the affected EGU that you determined under paragraph (a)(5) of this section for all of the valid operating hours in the applicable compliance period.
(ii) If you are subject to a heat input-based standard, you must calculate the total heat input for each fuel fired during the compliance period. The calculation of total heat input for each individual fuel must include all valid operating hours and must also be consistent with any fuel-specific procedures specified within your selected monitoring option under § 60.5535(d)(2).
(7) If you are subject to an output-based standard, you must calculate the CO 2 mass emissions rate for the affected EGU(s) (kg/MWh) by dividing the total CO 2 mass emissions value calculated according to the procedures in paragraph (a)(4) of this section by the total gross or net energy output value calculated according to the procedures in paragraph (a)(6)(i) of this section. Round off the result to two significant figures if the calculated value is less than 1,000; round the result to three significant figures if the calculated value is greater than 1,000. If you are subject to a heat input-based standard, you must calculate the CO 2 mass emissions rate for the affected EGU(s) (kg/GJ or lb/MMBtu) by dividing the total CO 2 mass emissions value calculated according to the procedures in paragraph (a)(4) of this section by the total heat input calculated according to the procedures in paragraph (a)(6)(ii) of this section. Round off the result to two significant figures.
(b) In accordance with § 60.5520, to demonstrate compliance with the applicable CO 2 emission standard, for the initial and each subsequent 12-operating-month compliance period, the CO 2 mass emissions rate for your affected EGU must be determined according to the procedures specified in paragraph (a)(1) through (8) of this section and must be less than or equal to the applicable CO 2 emissions standard in table 1 or 2 to this subpart, or the emissions standard calculated in accordance with § 60.5525(a)(2).
§ 60.5550   What notifications must I submit and when?
(a) You must prepare and submit the notifications specified in §§ 60.7(a)(1) and (3) and 60.19, as applicable to your affected EGU(s) (see table 3 of this subpart).
(b) You must prepare and submit notifications specified in § 75.61 of this chapter, as applicable, to your affected EGUs.
§ 60.5555   What reports must I submit and when?
(a) You must prepare and submit reports according to paragraphs (a) through (d) of this section, as applicable.
(1) For affected EGUs that are required by § 60.5525 to conduct initial and on-going compliance determinations on a 12-operating-month rolling average basis, you must submit electronic quarterly reports as follows. After you have accumulated the first 12-operating months for the affected EGU, you must submit a report for the calendar quarter that includes the twelfth operating month no later than 30 days after the end of that quarter. Thereafter, you must submit a report for each subsequent calendar quarter, no later than 30 days after the end of the quarter.
(2) In each quarterly report you must include the following information, as applicable:
(i) Each rolling average CO 2 mass emissions rate for which the last (twelfth) operating month in a 12-operating-month compliance period falls within the calendar quarter. You must calculate each average CO 2 mass emissions rate for the compliance period according to the procedures in § 60.5540. You must report the dates (month and year) of the first and twelfth operating months in each compliance period for which you performed a CO 2 mass emissions rate calculation. If there are no compliance periods that end in the quarter, you must include a statement to that effect;
(ii) If one or more compliance periods end in the quarter, you must identify each operating month in the calendar quarter where your EGU violated the applicable CO 2 emission standard;
(iii) If one or more compliance periods end in the quarter and there are no violations for the affected EGU, you must include a statement indicating this in the report;
(iv) The percentage of valid operating hours in each 12-operating-month compliance period described in paragraph (a)(1) of this section ( i.e., the total number of valid operating hours (as defined in § 60.5540(a)(1)) in that period divided by the total number of operating hours in that period, multiplied by 100 percent);
(v) Consistent with § 60.5520, the CO 2 emissions standard (as identified in table 1 or 2 to this subpart) with which your affected EGU must comply; and
(vi) Consistent with § 60.5520, an indication whether or not the hourly gross or net energy output (P gross/net ) values used in the compliance determinations are based solely upon gross electrical load.
(3) In the final quarterly report of each calendar year, you must include the following:
(i) Consistent with § 60.5520, gross energy output or net energy output sold to an electric grid, as applicable to the units of your emission standard, over the four quarters of the calendar year; and
(ii) The potential electric output of the EGU.
(b) You must submit all electronic reports required under paragraph (a) of this section using the Emissions Collection and Monitoring Plan System (ECMPS) Client Tool provided by the Clean Air Markets Division in the Office of Atmospheric Programs of EPA.
(c)(1) For affected EGUs under this subpart that are also subject to the Acid Rain Program, you must meet all applicable reporting requirements and submit reports as required under subpart G of part 75 of this chapter.
(2) For affected EGUs under this subpart that are not in the Acid Rain Program, you must also meet the reporting requirements and submit reports as required under subpart G of part 75 of this chapter, to the extent that those requirements and reports provide applicable data for the compliance demonstrations required under this subpart.
(3)(i) For all newly-constructed affected EGUs under this subpart that are also subject to the Acid Rain Program, you must begin submitting the quarterly electronic emissions reports described in paragraph (c)(1) of this section in accordance with § 75.64(a) of this chapter, i.e., beginning with data recorded on and after the earlier of:
(A) The date of provisional certification, as defined in § 75.20(a)(3) of this chapter; or
(B) 180 days after the date on which the EGU commences commercial operation (as defined in § 72.2 of this chapter).
(ii) For newly-constructed affected EGUs under this subpart that are not subject to the Acid Rain Program, you must begin submitting the quarterly electronic reports described in paragraph (c)(2) of this section, beginning with data recorded on and after:
(A) The date on which reporting is required to begin under § 75.64(a) of this chapter, if that date occurs on or after October 23, 2015; or
(B) October 23, 2015, if the date on which reporting would ordinarily be required to begin under § 75.64(a) of this chapter has passed prior to October 23, 2015.
(iii) For reconstructed or modified units, reporting of emissions data shall begin at the date on which the EGU becomes an affected unit under this subpart, provided that the ECMPS Client Tool is able to receive and process net energy output data on that date. Otherwise, emissions data reporting shall be on a gross energy output basis until the date that the Client Tool is first able to receive and process net energy output data.
(4) If any required monitoring system has not been provisionally certified by the applicable date on which emissions data reporting is required to begin under paragraph (c)(3) of this section, the maximum (or in some cases, minimum) potential value for the parameter measured by the monitoring system shall be reported until the required certification testing is successfully completed, in accordance with § 75.4(j) of this chapter, § 75.37(b) of this chapter, or section 2.4 of appendix D to part 75 of this chapter (as applicable). Operating hours in which CO 2 mass emission rates are calculated using maximum potential values are not “valid operating hours” (as defined in § 60.5540(a)(1)), and shall not be used in the compliance determinations under § 60.5540.
(d) For affected EGUs subject to the Acid Rain Program, the reports required under paragraphs (a) and (c)(1) of this section shall be submitted by:
(1) The person appointed as the Designated Representative (DR) under § 72.20 of this chapter; or
(2) The person appointed as the Alternate Designated Representative (ADR) under § 72.22 of this chapter; or
(3) A person (or persons) authorized by the DR or ADR under § 72.26 of this chapter to make the required submissions.
(e) For affected EGUs that are not subject to the Acid Rain Program, the owner or operator shall appoint a DR and (optionally) an ADR to submit the reports required under paragraphs (a) and (c)(2) of this section. The DR and ADR must register with the Clean Air Markets Division (CAMD) Business System. The DR may delegate the authority to make the required submissions to one or more persons.
(f) If your affected EGU captures CO 2 to meet the applicable emissions standard, you must report in accordance with the requirements of 40 CFR part 98, subpart PP, and either:
(1) Report in accordance with the requirements of 40 CFR part 98, subpart RR, or subpart VV, if injection occurs on-site;
(2) Transfer the captured CO 2 to an EGU or facility that reports in accordance with the requirements of 40 CFR part 98, subpart RR, or subpart VV, if injection occurs off-site; or
(3) Transfer the captured CO 2 to a facility that has received an innovative technology waiver from EPA pursuant to paragraph (g) of this section.
(g) Any person may request the Administrator to issue a waiver of the requirement that captured CO 2 from an affected EGU be transferred to a facility reporting under 40 CFR part 98, subpart RR, or subpart VV. To receive a waiver, the applicant must demonstrate to the Administrator that its technology will store captured CO 2 as effectively as geologic sequestration, and that the proposed technology will not cause or contribute to an unreasonable risk to public health, welfare, or safety. In making this determination, the Administrator shall consider (among other factors) operating history of the technology, whether the technology will increase emissions or other releases of any pollutant other than CO 2 , and permanence of the CO 2 storage. The Administrator may test the system or require the applicant to perform any tests considered by the Administrator to be necessary to show the technology's effectiveness, safety, and ability to store captured CO 2 without release. The Administrator may grant conditional approval of a technology, with the approval conditioned on monitoring and reporting of operations. The Administrator may also withdraw approval of the waiver on evidence of releases of CO 2 or other pollutants. The Administrator will provide notice to the public of any application under this provision and provide public notice of any proposed action on a petition before the Administrator takes final action.
§ 60.5560   What records must I maintain?
(a) You must maintain records of the information you used to demonstrate compliance with this subpart as specified in § 60.7(b) and (f).
(b)(1) For affected EGUs subject to the Acid Rain Program, you must follow the applicable recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter.
(2) For affected EGUs that are not subject to the Acid Rain Program, you must also follow the recordkeeping requirements and maintain records as required under subpart F of part 75 of this chapter, to the extent that those records provide applicable data for the compliance determinations required under this subpart. Regardless of the prior sentence, at a minimum, the following records must be kept, as applicable to the types of continuous monitoring systems used to demonstrate compliance under this subpart:
(i) Monitoring plan records under § 75.53(g) and (h) of this chapter;
(ii) Operating parameter records under § 75.57(b)(1) through (4) of this chapter;
(iii) The records under § 75.57(c)(2) of this chapter, for stack gas volumetric flow rate;
(iv) The records under § 75.57(c)(3) of this chapter for continuous moisture monitoring systems;
(v) The records under § 75.57(e)(1) of this chapter, except for paragraph (e)(1)(x), for CO 2 concentration monitoring systems or O 2 monitors used to calculate CO 2 concentration;
(vi) The records under § 75.58(c)(1) of this chapter, specifically paragraphs (c)(1)(i), (ii), and (viii) through (xiv), for oil flow meters;
(vii) The records under § 75.58(c)(4) of this chapter, specifically paragraphs (c)(4)(i), (ii), (iv), (v), and (vii) through (xi), for gas flow meters;
(viii) The quality-assurance records under § 75.59(a) of this chapter, specifically paragraphs (a)(1) through (12) and (15), for CEMS;
(ix) The quality-assurance records under § 75.59(a) of this chapter, specifically paragraphs (b)(1) through (4), for fuel flow meters; and
(x) Records of data acquisition and handling system (DAHS) verification under § 75.59(e) of this chapter.
(c) You must keep records of the calculations you performed to determine the hourly and total CO 2 mass emissions (tons) for:
(1) Each operating month (for all affected EGUs); and
(2) Each compliance period, including, each 12-operating-month compliance period.
(d) Consistent with § 60.5520, you must keep records of the applicable data recorded and calculations performed that you used to determine your affected EGU's gross or net energy output for each operating month.
(e) You must keep records of the calculations you performed to determine the percentage of valid CO 2 mass emission rates in each compliance period.
(f) You must keep records of the calculations you performed to assess compliance with each applicable CO 2 mass emissions standard in Table 1 or 2 of this subpart.
(g) You must keep records of the calculations you performed to determine any site-specific carbon-based F-factors you used in the emissions calculations (if applicable).
(h) For stationary combustion turbines, you must keep records of electric sales to determine the applicable subcategory.
(i) You must keep the records listed in paragraphs (i)(1) through (3) of this section to demonstrate that your affected facility operated during a system emergency.
(1) Documentation that the system emergency to which the affected EGU was responding was in effect from the entity issuing the alert, and documentation of the exact duration of the event;
(2) Documentation from the entity issuing the alert that the system emergency included the affected source/region where the affected facility was located, and
(3) Documentation that the affected facility was instructed to increase output beyond the planned day-ahead or other near-term expected output and/or was asked to remain in operation outside its scheduled dispatch during emergency conditions from a Reliability Coordinator, Balancing Authority, or Independent System Operator/Regional Transmission Organization.
§ 60.5565   In what form and how long must I keep my records?
(a) Your records must be in a form suitable and readily available for expeditious review.
(b) You must maintain each record for 3 years after the date of conclusion of each compliance period.
(c) You must maintain each record on site for at least 2 years after the date of each occurrence, measurement, maintenance, corrective action, report, or record, according to § 60.7. Records that are accessible from a central location by a computer or other means that instantly provide access at the site meet this requirement. You may maintain the records off site for the remaining year(s) as required by this subpart.
§ 60.5570   What parts of the general provisions apply to my affected EGU?
Notwithstanding any other provision of this chapter, certain parts of the general provisions in §§ 60.1 through 60.19, listed in table 3 to this subpart, do not apply to your affected EGU.
§ 60.5575   Who implements and enforces this subpart?
(a) This subpart can be implemented and enforced by the EPA, or a delegated authority such as your state, local, or tribal agency. If the Administrator has delegated authority to your state, local, or tribal agency, then that agency (as well as the EPA) has the authority to implement and enforce this subpart. You should contact your EPA Regional Office to find out if this subpart is delegated to your state, local, or tribal agency.
(b) In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency, the Administrator retains the authorities listed in paragraphs (b)(1) through (5) of this section and does not transfer them to the state, local, or tribal agency. In addition, the EPA retains oversight of this subpart and can take enforcement actions, as appropriate.
(1) Approval of alternatives to the emission standards.
(2) Approval of major alternatives to test methods.
(3) Approval of major alternatives to monitoring.
(4) Approval of major alternatives to recordkeeping and reporting.
(5) Performance test and data reduction waivers under § 60.8(b).
§ 60.5580   What definitions apply to this subpart?
As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subpart A (general provisions of this part).
Annual capacity factor means the ratio between the actual heat input to an EGU during a calendar year and the potential heat input to the EGU had it been operated for 8,760 hours during a calendar year at the base load rating. Actual and potential heat input derived from non-combustion sources (e.g., solar thermal) are not included when calculating the annual capacity factor.
Base load rating means the maximum amount of heat input (fuel) that an EGU can combust on a steady state basis plus the maximum amount of heat input derived from non-combustion source (e.g., solar thermal), as determined by the physical design and characteristics of the EGU at International Organization for Standardization (ISO) conditions. For a stationary combustion turbine, base load rating includes the heat input from duct burners.
Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by ASTM International in ASTM D388-99R04 (incorporated by reference, see § 60.17), coal refuse, and petroleum coke. Synthetic fuels derived from coal for the purpose of creating useful heat, including, but not limited to, solvent-refined coal, gasified coal (not meeting the definition of natural gas), coal-oil mixtures, and coal-water mixtures are included in this definition for the purposes of this subpart.
Combined cycle unit means a stationary combustion turbine from which the heat from the turbine exhaust gases is recovered by a heat recovery steam generating unit (HRSG) to generate additional electricity.
Combined heat and power unit or CHP unit, ( also known as “cogeneration”) means an electric generating unit that simultaneously produces both electric (or mechanical) and useful thermal output from the same primary energy source.
Design efficiency means the rated overall net efficiency (e.g., electric plus useful thermal output) on a lower heating value basis at the base load rating, at ISO conditions, and at the maximum useful thermal output (e.g., CHP unit with condensing steam turbines would determine the design efficiency at the maximum level of extraction and/or bypass). Design efficiency shall be determined using one of the following methods: ASME PTC 22-2014, ASME PTC 46-1996, ISO 2314:2009(E) (all incorporated by reference, see § 60.17), or an alternative approved by the Administrator.
Distillate oil means fuel oils that comply with the specifications for fuel oil numbers 1 and 2, as defined in ASTM D396-98 (incorporated by reference, see § 60.17); diesel fuel oil numbers 1 and 2, as defined in ASTM D975-08a (incorporated by reference, see § 60.17); kerosene, as defined in ASTM D3699-08 (incorporated by reference, see § 60.17); biodiesel as defined in ASTM D6751-11b (incorporated by reference, see § 60.17); or biodiesel blends as defined in ASTM D7467-10 (incorporated by reference, see § 60.17).
Electric Generating units or EGU means any steam generating unit, IGCC unit, or stationary combustion turbine that is subject to this rule ( i.e., meets the applicability criteria)
Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
Gaseous fuel means any fuel that is present as a gas at ISO conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.
Gross energy output means:
(1) For stationary combustion turbines and IGCC, the gross electric or direct mechanical output from both the EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) plus 100 percent of the useful thermal output.
(2) For steam generating units, the gross electric or mechanical output from the affected EGU(s) (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps plus 100 percent of the useful thermal output;
(3) For combined heat and power facilities where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and 20.0 percent of the total gross energy output consists of useful thermal output on a 12-operating-month rolling average basis, the gross electric or mechanical output from the affected EGU (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)) minus any electricity used to power the feedwater pumps (the electric auxiliary load of boiler feedwater pumps is not applicable to IGCC facilities), that difference divided by 0.95, plus 100 percent of the useful thermal output.
Heat recovery steam generating unit (HRSG) means an EGU in which hot exhaust gases from the combustion turbine engine are routed in order to extract heat from the gases and generate useful output. Heat recovery steam generating units can be used with or without duct burners.
Integrated gasification combined cycle facility or IGCC means a combined cycle facility that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas, plus any integrated equipment that provides electricity or useful thermal output to the affected EGU or auxiliary equipment. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the EGU during operation.
ISO conditions means 288 Kelvin (15 °C, 59 °F), 60 percent relative humidity and 101.3 kilopascals (14.69 psi, 1 atm) pressure.
Liquid fuel means any fuel that is present as a liquid at ISO conditions and includes, but is not limited to, distillate oil and residual oil.
Mechanical output means the useful mechanical energy that is not used to operate the affected EGU(s), generate electricity and/or thermal energy, or to enhance the performance of the affected EGU. Mechanical energy measured in horsepower hour should be converted into MWh by multiplying it by 745.7 then dividing by 1,000,000.
Natural gas means a fluid mixture of hydrocarbons ( e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. Finally, natural gas does not include the following gaseous fuels: Landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable CO 2 content or heating value.
Net-electric output means the amount of gross generation the generator(s) produces (including, but not limited to, output from steam turbine(s), combustion turbine(s), and gas expander(s)), as measured at the generator terminals, less the electricity used to operate the plant ( i.e., auxiliary loads); such uses include fuel handling equipment, pumps, fans, pollution control equipment, other electricity needs, and transformer losses as measured at the transmission side of the step up transformer ( e.g., the point of sale).
Net-electric sales means:
(1) The gross electric sales to the utility power distribution system minus purchased power; or
(2) For combined heat and power facilities, where at least 20.0 percent of the total gross energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross energy output consists of useful thermal output on a 12-operating month basis, the gross electric sales to the utility power distribution system minus purchased power of the thermal host facility or facilities.
(3) Electricity supplied to other facilities that produce electricity to offset auxiliary loads are included when calculating net-electric sales.
(4) Electric sales during a system emergency are not included when calculating net-electric sales.
Net energy output means:
(1) The net electric or mechanical output from the affected EGU plus 100 percent of the useful thermal output; or
(2) For combined heat and power facilities where at least 20.0 percent of the total gross or net energy output consists of electric or direct mechanical output and at least 20.0 percent of the total gross or net energy output consists of useful thermal output on a 12-operating-month rolling average basis, the net electric or mechanical output from the affected EGU divided by 0.95, plus 100 percent of the useful thermal output.
Operating month means a calendar month during which any fuel is combusted in the affected EGU at any time.
Petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, distillate and residual oil.
Potential electric output means 33 percent or the base load rating design efficiency at the maximum electric production rate ( e.g., CHP units with condensing steam turbines will operate at maximum electric production), whichever is greater, multiplied by the base load rating (expressed in MMBtu/h) of the EGU, multiplied by 10 6 Btu/MMBtu, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 h/yr ( e.g., a 35 percent efficient affected EGU with a 100 MW (341 MMBtu/h) fossil fuel heat input capacity would have a 306,000 MWh 12-month potential electric output capacity).
Solid fuel means any fuel that has a definite shape and volume, has no tendency to flow or disperse under moderate stress, and is not liquid or gaseous at ISO conditions. This includes, but is not limited to, coal, biomass, and pulverized solid fuels.
Standard ambient temperature and pressure (SATP) conditions means 298.15 Kelvin (25 °C, 77 °F) and 100.0 kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy of water at SATP conditions is 50 Btu/lb.
Stationary combustion turbine means all equipment including, but not limited to, the turbine engine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, fuel compressor, heater, and/or pump, post-combustion emission control technology, and any ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system plus any integrated equipment that provides electricity or useful thermal output to the combustion turbine engine, heat recovery system or auxiliary equipment. Stationary means that the combustion turbine is not self-propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. A stationary combustion turbine that burns any solid fuel directly is considered a steam generating unit.
Steam generating unit means any furnace, boiler, or other device used for combusting fuel and producing steam (nuclear steam generators are not included) plus any integrated equipment that provides electricity or useful thermal output to the affected EGU(s) or auxiliary equipment.
System emergency means periods when the Reliability Coordinator has declared an Energy Emergency Alert level 2 or 3 as defined by NERC Reliability Standard EOP-011-2 or its successor.
Useful thermal output means the thermal energy made available for use in any heating application ( e.g., steam delivered to an industrial process for a heating application, including thermal cooling applications) that is not used for electric generation, mechanical output at the affected EGU, to directly enhance the performance of the affected EGU ( e.g., economizer output is not useful thermal output, but thermal energy used to reduce fuel moisture is considered useful thermal output), or to supply energy to a pollution control device at the affected EGU. Useful thermal output for affected EGU(s) with no condensate return (or other thermal energy input to the affected EGU(s)) or where measuring the energy in the condensate (or other thermal energy input to the affected EGU(s)) would not meaningfully impact the emission rate calculation is measured against the energy in the thermal output at SATP conditions. Affected EGU(s) with meaningful energy in the condensate return (or other thermal energy input to the affected EGU) must measure the energy in the condensate and subtract that energy relative to SATP conditions from the measured thermal output.
Valid data means quality-assured data generated by continuous monitoring systems that are installed, operated, and maintained according to part 75 of this chapter. For CEMS, the initial certification requirements in § 75.20 of this chapter and appendix A to part 75 of this chapter must be met before quality-assured data are reported under this subpart; for on-going quality assurance, the daily, quarterly, and semiannual/annual test requirements in sections 2.1, 2.2, and 2.3 of appendix B to part 75 of this chapter must be met and the data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of appendix B to part 75 of this chapter apply. For fuel flow meters, the initial certification requirements in section 2.1.5 of appendix D to part 75 of this chapter must be met before quality-assured data are reported under this subpart (except for qualifying commercial billing meters under section 2.1.4.2 of appendix D to part 75), and for on-going quality assurance, the provisions in section 2.1.6 of appendix D to part 75 apply (except for qualifying commercial billing meters).
Violation means a specified averaging period over which the CO 2 emissions rate is higher than the applicable emissions standard located in table 1 or 2 of this subpart.
§ 60.5508a   What is the purpose of this subpart?
This subpart establishes emission standards and compliance schedules for the control of greenhouse gas (GHG) emissions from a coal-fired steam generating unit or integrated gasification combined cycle facility (IGCC) that commences modification after May 23, 2023. This subpart also establishes emission standards and compliance schedules for the control of GHG emissions from a stationary combustion turbine that commences construction or reconstruction after May 23, 2023. An affected coal-fired steam generating unit, IGCC, or stationary combustion turbine shall, for the purposes of this subpart, be referred to as an affected electric generating unit (EGU).
§ 60.5509a   Am I subject to this subpart?
(a) Except as provided for in paragraph (b) of this section, the GHG standards included in this subpart apply to any steam generating unit or IGCC that combusts coal and that commences modification after May 23, 2023, that meets the relevant applicability conditions in paragraphs (a)(1) and (2) of this section. The GHG standards included in this subpart also apply to any stationary combustion turbine that commences construction or reconstruction after May 23, 2023, that meets the relevant applicability conditions in paragraphs (a)(1) and (2) of this section.
(1) Has a base load rating greater than 260 gigajoules per hour (GJ/h) (250 million British thermal units per hour (MMBtu/h)) of fossil fuel (either alone or in combination with any other fuel); and
(2) Serves a generator or generators capable of selling greater than 25 megawatts (MW) of electricity to a utility power distribution system.
(b) You are not subject to the requirements of this subpart if your affected EGU meets any of the conditions specified in paragraphs (b)(1) through (8) of this section.
(1) Your EGU is a steam generating unit or IGCC whose annual net-electric sales have never exceeded one-third of its potential electric output or 219,000 megawatt-hour (MWh), whichever is greater, and is currently subject to a federally enforceable permit condition limiting annual net-electric sales to no more than one-third of its potential electric output or 219,000 MWh, whichever is greater.
(2) Your EGU is capable of deriving 50 percent or more of the heat input from non-fossil fuel at the base load rating and is also subject to a federally enforceable permit condition limiting the annual capacity factor for all fossil fuels combined of 10 percent (0.10) or less.
(3) Your EGU is a combined heat and power unit that is subject to a federally enforceable permit condition limiting annual net-electric sales to no more than either 219,000 MWh or the product of the design efficiency and the potential electric output, whichever is greater.
(4) Your EGU serves a generator along with other steam generating unit(s), IGCC, or stationary combustion turbine(s) where the effective generation capacity (determined based on a prorated output of the base load rating of each steam generating unit, IGCC, or stationary combustion turbine) is 25 MW or less.
(5) Your EGU is a municipal waste combustor that is subject to subpart Eb of this part.
(6) Your EGU is a commercial or industrial solid waste incineration unit that is subject to subpart CCCC of this part.
(7) Your EGU is a steam generating unit or IGCC that undergoes a modification resulting in an hourly increase in CO 2 emissions (mass per hour) of 10 percent or less (2 significant figures). Modified units that are not subject to the requirements of this subpart pursuant to this subsection continue to be existing units under section 111 with respect to CO 2 emissions standards.
(8) Your EGU derives greater than 50 percent of the heat input from an industrial process that does not produce any electrical or mechanical output or useful thermal output that is used outside the affected EGU.
§ 60.5515a   Which pollutants are regulated by this subpart?
(a) The pollutants regulated by this subpart are greenhouse gases. The greenhouse gas standard in this subpart is in the form of a limitation on emission of carbon dioxide.
(b) PSD and Title V thresholds for greenhouse gases.
(1) For the purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 51.166(b)(48) and in any SIP approved by the EPA that is interpreted to incorporate, or specifically incorporates, 40 CFR 51.166(b)(48).
(2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to GHG emissions from affected facilities, the “pollutant that is subject to the standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is subject to regulation under the Act as defined in 40 CFR 52.21(b)(49).
(3) For the purposes of 40 CFR 70.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 70.2.
(4) For the purposes of 40 CFR 71.2, with respect to greenhouse gas emissions from affected facilities, the “pollutant that is subject to any standard promulgated under section 111 of the Act” shall be considered to be the pollutant that otherwise is “subject to regulation” as defined in 40 CFR 71.2.