§72.2. Definitions. — Inbound Citations

(ii) For gaseous fuels, either obtain, record, and keep records of the sulfur content from the vendor, or continuously monitor the sulfur content of the fuel gas line using a method that meets the requirements of Performance Specification 5, 7, 9, or 15 (as applicable for the sulfur compounds in the gaseous fuel) of appendix B and appendix F of 40 CFR part 60. If only purchased natural gas is used, then keep records showing that the gaseous fuel meets the definition of natural gas in 40 CFR 72.2.

(2) Terms not defined in this paragraph (j)(2) shall have the meaning given them in the Clean Air Act or EPA's regulations implementing the Clean Air Act. For purposes of this paragraph (j):

Ammonia injection shall include any of the following: Anhydrous ammonia, aqueous ammonia, or urea injection.

Boiler operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the unit.

Continuous emission monitoring system or CEMS means the equipment required by 40 CFR part 75 and this paragraph (j).

MMBtu means one million British thermal units.

Natural gas means a naturally occurring fluid mixture of hydrocarbons as defined in 40 CFR 72.2.

NOX means oxides of nitrogen.

Owner/operator means any person who owns or who operates, controls, or supervises the EGU identified in paragraph (j)(1) of this section.PM means total filterable particulate matter.

PM10 means total particulate matter less than 10 microns in diameter.

SO2 means sulfur dioxide.

Unit means the EGU identified paragraph (j)(1) of this section.

(e) Every term expressly defined by this section shall have the meaning given to that term within this section. Every other term used in this section that is also a term used under the Act or in Federal regulations in this chapter implementing the Act shall mean in this section what such term means under the Act or the regulations in this chapter.

CEMS or Continuous Emission Monitoring System, means, for obligations involving the monitoring of NOX emissions under this section, the devices defined in 40 CFR 72.2 and installed and maintained as required by 40 CFR part 75.

Clean Air Act or Act means the Federal Clean Air Act, 42 U.S.C. 7401-7671q, and its implementing regulations in this chapter.

Conemaugh means, for purposes of this section, Keystone Conemaugh Project LLC's Conemaugh Generating Station consisting of two coal-fired units designated as Unit 1 (8,280 MMBtu/hr) and Unit 2 (8,280 MMBtu/hr), located in West Wheatfield Township, Indiana County, Pennsylvania.

Day or daily means calendar day unless otherwise specified in this section.

EGU means electric generating unit.

EPA means the United States Environmental Protection Agency.

Facility means each of the following as defined in this section: Conemaugh; Homer City; Keystone; and Montour.

Facility-wide 30-Day Rolling Average NOX Emission Rate for the Facility shall be expressed in lb/MMBtu and calculated in accordance with the following procedure: first, sum the total pounds of NOX emitted from all Units during the current Operating Day and the previous twenty-nine (29) Operating Days; second, sum the total heat input from all Units in MMBtu during the current Unit Operating Day and the previous twenty-nine (29) Operating Days; and third, divide the total number of pounds of NOX emitted from all Units during the thirty (30) Operating Days by the total heat input during the thirty (30) Operating Days. A new Facility-wide 30-Day Rolling Average NOX Emission Rate shall be calculated for each new Operating Day. Each 30-Day Rolling Average NOX Emission Rate shall include all emissions that occur during all periods within any Operating Day, including, but not limited to, emissions from startup, shutdown, and malfunction.

Fossil fuel means any hydrocarbon fuel, including coal, petroleum coke, petroleum oil, fuel oil, or natural gas.

Homer City means, for purposes of this section, Homer City Generation LP's Homer City Generating Station consisting of three coal-fired units designated as Unit 1 (6,792 MMBtu/hr), Unit 2 (6,792 MMBtu/hr), and Unit 3 (7,260 MMBtu/hr), located in Center Township, Indiana County, Pennsylvania.

Keystone means, for purposes of this section, Keystone Conemaugh Project LLC's Keystone Generating Station consisting of two coal-fired units designated as Unit 1 (8,717 MMBtu/hr) and Unit 2 (8,717 MMBtu/hr), located in Plumcreek Township, Armstrong County, Pennsylvania.

lb/MMBtu means one pound per million British thermal units.

Montour means, for purposes of this section, Talen Energy Corporation's Montour Steam Electric Station consisting of two coal-fired units designated as Unit 1 (7,317 MMBtu/hr) and Unit 2 (7,239 MMBtu/hr), located in Derry Township, Montour County, Pennsylvania.

“NOX” means oxides of nitrogen, measured in accordance with the provisions of this section. “NOX emission rate” means the number of pounds of NOX emitted per million British thermal units of heat input (lb/MMBtu), calculated in accordance with this section.

Operating day means any calendar day on which a Unit fires Fossil Fuel.

Title V Permit means the permit required for major sources pursuant to Subchapter V of the Act, 42 U.S.C. 7661-7661e.

Unit means collectively, the coal pulverizer, stationary equipment that feeds coal to the boiler, the boiler that produces steam for the steam turbine, the steam turbine, the generator, the equipment necessary to operate the generator, steam turbine, and boiler, and all ancillary equipment, including pollution control equipment and systems necessary for production of electricity. An electric steam generating station may be comprised of one or more Units.

Unit-specific daily NOX mass emissions shall be expressed in lb/day and calculated as the sum of total pounds of NOX emitted from the Unit during the Unit Operating Day. Each Unit-specific Daily NOX Mass Emissions shall include all emissions that occur during all periods within any Operating Day, including emissions from startup, shutdown, and malfunction.

(2) Rules 53, 72.1, and 72.2 of the Riverside County APCD.

(4) If you have two or more combustion turbine engines share a common stack, are connected to a single electric generator, or share a steam turbine, except as provided for in paragraph (b)(4)(i) of this section, you must monitor the hourly NOX emissions at the common stack in lieu of monitoring each combustion turbine separately. If you choose to comply with the output-based emissions standard, the hourly gross or net energy output (electric, thermal, or mechanical, as applicable) must be the sum of the hourly loads for the individual affected combustion turbines, and you must express the operating time as “stack operating hours” (as defined in 40 CFR 72.2). If you attain compliance with the most stringent applicable emission standard in table 1 or 2 to this subpart, as applicable, at the common stack, each affected combustion turbine sharing the stack is in compliance.

(i) As an alternative to the requirements in this paragraph (b)(4), you may either:

(A) Monitor each combustion turbine separately by measuring the NOX emissions prior to mixing in the common stack; or

(B) Apportion the NOX emissions based on the unit's heat input contribution to the total heat input associated with the common stack and the appropriate F-factors. If you chose to comply with the output-based standard, output from a common steam turbine shall be apportioned based on the heat input to each combustion turbine. You may also elect to develop, demonstrate, and provide information satisfactory to the Administrator on alternate methods to apportion the NOX emissions. The Administrator may approve such alternate methods for apportioning the NOX emissions whenever the demonstration ensures accurate estimation of emissions regulated under this part.

(ii) [Reserved]

(n) The owner or operator of an affected unit that qualifies as a gas-fired or oil-fired unit, as defined in 40 CFR 72.2, may use, as an alternative to the requirements specified in either paragraph (l) or (m) of this section, a fuel flow monitoring system certified and operated according to the requirements of appendix D of part 75 of this chapter.

(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.

(1) For an affected EGU that commences commercial operation (as defined in 40 CFR 72.2), the first month of the initial compliance period shall be the first operating month (as defined in § 60.5580a) after the calendar month in which emissions reporting is required to begin under:

(i) Section 60.5555a(c)(3)(i), for units subject to the Acid Rain Program; or

(ii) Section 60.5555a(c)(3)(ii), for units that are not in the Acid Rain Program.

(ii) Next, multiply each hourly CO2 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 CO2.

(ii) Next, multiply each hourly CO2 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 CO2.

(B) 180 days after the date on which the EGU commences commercial operation (as defined in § 72.2 of this chapter).

(B) 180 days after the date on which the EGU commences commercial operation (as defined in 40 CFR 72.2).

(iii) Next, multiply each hourly CO2 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 CO2. Multiply the result by 2,000 lbs/ton to convert it to lbs.

(2) The requirements of this part shall not apply to a utility unit, as defined in § 72.2 of this chapter, that is municipally-owned if the owner or operator provides documentation in a part 70 or 71 permit application that:

(i) The utility unit is exempt from all monitoring requirements in part 75 (including the appendices thereto) of this chapter;

(ii) The utility unit is operated for the sole purpose of providing electricity during periods of peak electrical demand or emergency situations and will be operated consistent with that purpose throughout the part 70 or 71 permit term. The owner or operator shall provide historical operating data and relevant contractual obligations to document that this criterion is satisfied; and

(iii) The actual emissions from the utility unit, based on the average annual emissions over the last three calendar years of operation (or such shorter time period that is available for units with fewer than three years of operation) are less than 50 percent of the amount in tons per year required for a source to be classified as a major source and are expected to remain so.

The following definitions apply to part 71. Except as specifically provided in this section, terms used in this part retain the meaning accorded them under the applicable requirements of the Act.

(1) ASTM D388-92, Standard Classification of Coals by Rank for § 72.2 of this chapter.

(iii) If the repowering technology is not listed in the definition of a qualified repowering technology in § 72.2, a vendor certification of the guaranteed performance characteristics that demonstrate that the technology meets the criteria specified for non-listed technologies in § 72.2; provided that the existence of such guarantee shall not be a defense against the failure to meet the criteria for non-listed technologies.

(b) Each Acid Rain permit is deemed to incorporate the definitions of terms under § 72.2 of this part.

(1) Any new utility unit that meets the requirements of paragraph (a) of this section and that is not allocated any allowances under subpart B of part 73 of this chapter shall be exempt from the Acid Rain Program, except for the provisions of this section, §§ 72.2 through 72.6, and §§ 72.10 through 72.13.

(1) Any affected unit (except for an opt-in source) that is permanently retired shall be exempt from the Acid Rain Program, except for the provisions of this section, §§ 72.2 through 72.6, §§ 72.10 through 72.13, and subpart B of part 73 of this chapter.

(3) Whether all the emissions from the unit, or a group of units (including the unit) using a common stack, were monitored or accounted for through the missing data procedures and reported in the quarterly monitoring reports, including whether conditionally valid data, as defined in § 72.2, were reported in the quarterly report. If conditionally valid data were reported, the owner or operator shall indicate whether the status of all conditionally valid data has been resolved and all necessary quarterly report resubmissions have been made.

(1) “Baseline” is as defined in § 72.2 of this part.

(ii) “Dispatch system aggregate baseline” is the sum of the baselines (as defined in § 72.2 of this chapter) for all Phase I units in the dispatch system.

(b) Any new independent power producer as defined in section 416 of the Act and § 72.2 of this chapter, except as provided in section 405(g)(6) of the Act;

Part 72 of this chapter, including §§ 72.2 (definitions), 72.3 (measurements, abbreviations, and acronyms), 72.4 (Federal authority), 72.5 (State authority), 72.6 (applicability), 72.7 (new units exemption), 72.8 (retired unit exemption), 72.9 (standard requirements), 72.10 (availability of information), and 72.11 (computation of time) of part 72, subpart A of this chapter, shall apply to this part. The procedures for appeals of decisions of the Administrator under this part are contained in part 78 of this chapter. Sections 73.3 (Definitions) and 73.4 (Deadlines), which were previously published with subpart E of this part—“Auctions, Direct Sales, and Independent Power Producers Written Guarantee”, are codified at §§ 72.2 and 72.12 of this chapter, respectively.

(i) If the applicant is an investor-owner utility subject to the ratemaking jurisdiction of a State utility regulatory authority and is submitting an application on the basis of one or more qualified energy conservation measures, such State utility regulatory authority has established a procedure for determining rates and charges ensuring net income neutrality, as defined in § 72.2 of this chapter, including a provision that the utility's net income is compensated in full (considering factors such as risk) for lost sales attributable to the utility's conservation programs, which may include:

(A) General ratemaking for formulas that decouple utility profits from actual utility sales;

(B) Specific rate adjustment formulas that allow a utility to recover in its retail rates the full costs of conservation measures plus any associated net revenues lost as a result of reduced sales resulting from conservation initiatives; or

(C) Conservation incentive mechanisms designed to provide positive financial rewards to a utility to encourage implementation of cost-effective measures;

(d) Each opt-in permit is deemed to incorporate the definitions of terms under § 72.2 of this chapter.

(i) Allowable SO2 emissions rate of the combustion source expressed in lbs/mmBtu as defined under § 72.2 of this chapter for the calendar year specified in paragraph (a)(2) of this section. If the allowable SO2 emissions rate is not expressed in lbs/mmBtu, the allowable emissions rate shall be converted to lbs/mmBtu by multiplying the emissions rate by the appropriate factor as specified in Table 1 of this section.

(2) Subpart A, B, G, and H of part 72 of this chapter, including §§ 72.2 (definitions), 72.3 (measurements, abbreviations, and acronyms), 72.4 (Federal authority), 72.5 (State authority), 72.6 (applicability), 72.7 (New units exemption), 72.8 (Retired units exemption), 72.9 (Standard Requirements), 72.10 (availability of information), and 72.11 (computation of time), shall apply to this part.

(d) The owner or operator of an affected unit that qualifies as a gas-fired or oil-fired unit, as defined in § 72.2 of this chapter, based on information submitted by the designated representative in the monitoring plan, shall measure and record SO2 emissions:

(1) By meeting the general operating requirements in § 75.10 for an SO2 continuous emission monitoring system and flow monitoring system. If this option is selected, the owner or operator shall comply with the applicable provisions in paragraph (e)(1), (e)(2), or (e)(3) of this section during hours in which the unit combusts only gaseous fuel;

(2) By providing other information satisfactory to the Administrator using the applicable procedures specified in appendix D to this part for estimating hourly SO2 mass emissions; or

(3) By using the low mass emissions excepted methodology in § 75.19(c) for estimating hourly SO2 mass emissions if the affected unit qualifies as a low mass emissions unit under § 75.19(a) and (b). If this option is selected for SO2, the LME methodology must also be used for NOX and CO2 when these parameters are required to be monitored by applicable program(s).

(d) The owner or operator of an affected unit that qualifies as a gas-fired peaking unit or oil-fired peaking unit, as defined in § 72.2 of this chapter, based on information submitted by the designated representative in the monitoring plan shall comply with one of the following:

(1) Meet the general operating requirements in § 75.10 for a NOX continuous emission monitoring system; or

(2) Provide information satisfactory to the Administrator using the procedure specified in appendix E of this part for estimating hourly NOX emission rate. However, if in the years after certification of an excepted monitoring system under appendix E of this part, a unit's operations exceed a capacity factor of 20 percent in any calendar year or exceed a capacity factor of 10.0 percent averaged over three years, the owner or operator shall install, certify, and operate a NOX-diluent continuous emission monitoring system no later than December 31 of the following calendar year. If the required CEMS has not been installed and certified by that date, the owner or operator shall report the maximum potential NOX emission rate (MER) (as defined in § 72.2 of this chapter) for each unit operating hour, starting with the first unit operating hour after the deadline and continuing until the CEMS has been provisionally certified.

(c) The owner or operator of an affected unit that qualifies as gas-fired, as defined in § 72.2 of this chapter, based on information submitted by the designated representative in the monitoring plan is exempt from the opacity monitoring requirements of this part. Whenever a unit previously categorized as a gas-fired unit is recategorized as another type of unit by changing its fuel mix, the owner or operator shall install, operate, and certify a continuous opacity monitoring system as required by paragraph (a) of this section by December 31 of the following calendar year.

(2) If this option is chosen, it is not necessary to designate the exhaust configuration as a multiple stack configuration in the monitoring plan required under § 75.53, with respect to NOX or any other parameter that is monitored only at the main stack. For each unit operating hour in which the bypass stack is used and the emissions are either uncontrolled (or the add-on controls are not documented to be operating properly), report the maximum potential NOX emission rate (as defined in § 72.2 of this chapter). The maximum potential NOX emission rate may be specific to the type of fuel combusted in the unit during the bypass (see § 75.33(c)(8)). Alternatively, for a unit with NOX add-on emission controls, for each unit operating hour in which the bypass stack is used and the add-on NOX emission controls are not bypassed, the owner or operator may report the maximum controlled NOX emission rate (MCR) instead of the maximum potential NOX emission rate provided that the add-on controls are documented to be operating properly, as described in the quality assurance/quality control program for the unit, required by section 1 in appendix B of this part. To provide the necessary documentation, the owner or operator shall record parametric data to verify the proper operation of the NOX add-on emission controls as described in § 75.34(d). Furthermore, the owner or operator shall calculate the MCR using the procedure described in section 2.1.2.1(b) of appendix A to this part where the words “maximum potential NOX emission rate (MER)” shall apply instead of the words “maximum controlled NOX emission rate (MCR)” and by using the NOX MEC in the calculations instead of the NOX MPC.

(i) A low mass emissions unit is an affected unit that is gas-fired, or oil-fired (as defined in § 72.2 of this chapter), and for which:

(A) An initial demonstration is provided, in accordance with paragraph (a)(2) of this section, which shows that the unit emits:

(1) No more than 25 tons of SO2 annually and less than 100 tons of NOX annually, for Acid Rain Program affected units. If the unit is also subject to the provisions of subpart H of this part, no more than 50 of the allowable annual tons of NOX may be emitted during the ozone season; or

(2) Less than 100 tons of NOX annually and no more than 50 tons of NOX during the ozone season, for non-Acid Rain Program units subject to the provisions of subpart H of this part, for which the owner or operator reports emissions data on a year-round basis, in accordance with § 75.74(a) or § 75.74(b); or

(3) No more than 50 tons of NOX per ozone season, for non-Acid Rain Program units subject to the provisions of subpart H of this part, for which the owner or operator reports emissions data only during the ozone season, in accordance with § 75.74(b); and

(B) An annual demonstration is provided thereafter, using one of the allowable methodologies in paragraph (c) of this section, showing that the low mass emissions unit continues to emit no more than the applicable number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section.

(C) This paragraph, (a)(1)(i)(C), applies only to a unit that is subject to an SO2 emission limitation under the Acid Rain Program, and that combusts a gaseous fuel other than pipeline natural gas or natural gas (as defined in § 72.2 of this chapter). The owner or operator of such a unit must quantify the sulfur content and variability of the gaseous fuel by performing the demonstration described in section 2.3.6 of appendix D to this part, in order for the unit to qualify for LME unit status. If the results of that demonstration show that the gaseous fuel qualifies under paragraph (b) of section 2.3.6 to use a default SO2 emission rate to report SO2 mass emissions under this part, the unit is eligible for LME unit status.

(i) Until such time, date, and hour as the continuous emission monitoring system can be adjusted, repaired, or replaced and certification tests successfully completed (or, if the conditional data validation procedures in paragraphs (b)(3)(ii) through (b)(3)(ix) of this section are used, until a probationary calibration error test is passed following corrective actions in accordance with paragraph (b)(3)(ii) of this section), the owner or operator shall substitute the following values, as applicable, for each hour of unit operation during the period of invalid data specified in paragraph (a)(4)(iii) of this section or in § 75.21: the maximum potential concentration of SO2, as defined in section 2.1.1.1 of appendix A to this part, to report SO2 concentration; the maximum potential NOX emission rate, as defined in § 72.2 of this chapter, to report NOX emissions in lb/mmBtu; the maximum potential concentration of NOX, as defined in section 2.1.2.1 of appendix A to this part, to report NOX emissions in ppm (when a NOX concentration monitoring system is used to determine NOX mass emissions, as defined under § 75.71(a)(2)); the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to this part, to report volumetric flow; the maximum potential concentration of CO2, as defined in section 2.1.3.1 of appendix A to this part, to report CO2 concentration data; and either the minimum potential moisture percentage, as defined in section 2.1.5 of appendix A to this part or, if Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is used to determine NOX emission rate, the maximum potential moisture percentage, as defined in section 2.1.6 of appendix A to this part; and

(10) The owner or operator who, in accordance with § 75.11(e)(1), uses a certified flow monitor and a certified diluent monitor and Equation F-23 in appendix F to this part to calculate SO2 emissions during hours in which a unit combusts only natural gas or pipeline natural gas (as defined in § 72.2 of this chapter) shall meet all quality control and quality assurance requirements in appendix B to this part for the flow monitor and the diluent monitor.

(a) § 72.2 (Definitions);

(1) Whenever a unit with an SO2 CEMS combusts only natural gas or pipeline natural gas (as defined in § 72.2 of this chapter) and the owner or operator is using the procedures in section 7 of appendix F to this part to determine SO2 mass emissions pursuant to § 75.11(e)(1), the owner or operator shall, for purposes of reporting heat input data under § 75.57(b)(5), and for the calculation of SO2 mass emissions using Equation F-23 in section 7 of appendix F to this part, substitute for missing data from a flow monitoring system, CO2 diluent monitor or O2 diluent monitor using the missing data substitution procedures in § 75.36.

(iii) For the purposes of providing substitute data under paragraph (b)(4) of this section, determine a separate, fuel-specific maximum potential SO2 concentration (MPC) value for each type of fuel combusted in the unit, in a manner consistent with section 2.1.1.1 of appendix A to this part. For fuel that qualifies as pipeline natural gas or natural gas (as defined in § 72.2 of this chapter), the owner or operator shall, for the purposes of determining the MPC, either determine the maximum total sulfur content and minimum gross calorific value (GCV) of the gas by fuel sampling and analysis or shall use a default total sulfur content of 0.05 percent by weight (dry basis) and a default GCV value of 950 Btu/scf. For co-firing, the MPC value shall be based on the fuel with the highest SO2 emission rate. The exact methodology used to determine each fuel-specific MPC value shall be documented in the monitoring plan for the unit or stack; and

(1) The owner or operator may use the missing data substitution procedures specified in §§ 75.31 through 75.33 to provide substitute data for any missing data hour(s) in which the add-on emission controls are documented to be operating properly, as described in the quality assurance/quality control program for the unit, required by section 1 in appendix B of this part. To provide the necessary documentation, the owner or operator shall, for each missing data period, record parametric data to verify the proper operation of the SO2 or NOX add-on emission controls during each hour, as described in paragraph (d) of this section. For any missing data hour(s) in which such parametric data are either not provided or, if provided, do not demonstrate that proper operation of the SO2 or NOX add-on emission controls has been maintained, the owner or operator shall substitute (as applicable) the maximum potential NOX concentration (MPC) as defined in section 2.1.2.1 of appendix A to this part, the maximum potential NOX emission rate, as defined in § 72.2 of this chapter, or the maximum potential concentration for SO2, as defined by section 2.1.1.1. Alternatively, for SO2 or NOX, the owner or operator may substitute, if available, the hourly SO2 or NOX concentration recorded by a certified inlet monitor, in lieu of the MPC. For each hour in which data from an inlet monitor are reported, the owner or operator shall use a method of determination code (MODC) of “22” (see Table 4a in § 75.57). In addition, under § 75.64(c), the designated representative shall submit as part of each electronic quarterly report, a certification statement, verifying the proper operation of the SO2 or NOX add-on emission control for each missing data period in which the missing data procedures of §§ 75.31 through 75.33 were applied; or

(d) This paragraph (d) applies to affected units under the Acid Rain Program and to units subject to a State or Federal pollutant mass emissions reduction program that adopts the emission monitoring and reporting provisions of this part. In accordance with § 75.20, for an affected unit which, on the applicable compliance date, is either in long-term cold storage (as defined in § 72.2 of this chapter) or is shut down as the result of a planned outage or a forced outage, thereby preventing the required continuous monitoring system certification tests from being completed by the compliance date, the owner or operator shall provide notice of such unit storage or outage in accordance with § 75.61(a)(3) or § 75.61(a)(7), as applicable. For the planned and unplanned unit outages described in this paragraph (d), the owner or operator shall ensure that all of the continuous monitoring systems for SO2, NOX, CO2, opacity, and volumetric flow rate required under this part (or under the applicable State or Federal mass emissions reduction program) are installed and that all required certification tests are completed no later than 90 unit operating days or 180 calendar days (whichever occurs first) after the date that the unit recommences commercial operation, notice of which date shall be provided under § 75.61(a)(3) or § 75.61(a)(7), as applicable. The owner or operator shall determine and report SO2 concentration, NOX emission rate, CO2 concentration, and flow rate data (as applicable) for all unit operating hours after the applicable compliance date until all of the required certification tests are successfully completed, using either:

(1) The maximum potential concentration of SO2 (as defined in section 2.1.1.1 of appendix A to this part), the maximum potential NOX emission rate, as defined in § 72.2 of this chapter, the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to this part, or the maximum potential CO2 concentration, as defined in section 2.1.3.1 of appendix A to this part; or

(2) The conditional data validation provisions of § 75.20(b)(3); or

(3) Reference methods under § 75.22(b); or

(4) Another procedure approved by the Administrator pursuant to a petition under § 75.66.

(i) Unit operating and capacity factor information demonstrating that the unit qualifies as a peaking unit or gas-fired unit, as defined in § 72.2 of this chapter, and NOX correlation test information, including:

(A) Test date;

(B) Test number;

(C) Operating level;

(D) Segment ID of the NOX correlation curve;

(E) NOX monitoring system identification;

(F) Low and high heat input rate values and corresponding NOX emission rates;

(G) Type of fuel; and

(H) To document the unit qualifies as a peaking unit, current calendar year or ozone season, capacity factor data as specified in the definition of peaking unit in § 72.2 of this chapter, and an indication of whether the data are actual or projected data.

(2) The provisions of this paragraph apply to a unit which, in accordance with the provisions of § 75.11(e)(3), uses an SO2 CEMS to determine SO2 emissions during hours in which only gaseous fuel is combusted in the unit. If the unit sometimes burns only gaseous fuel that is very low sulfur fuel (as defined in § 72.2 of this chapter) as a primary and/or backup fuel and at other times combusts higher sulfur fuels, such as coal or oil, as primary and/or backup fuel(s), then the owner or operator shall keep records on-site, in a form suitable for inspection, of the type(s) of fuel(s) burned during each period of missing SO2 data and the number of hours that each type of fuel was combusted in the unit during each missing data period. This recordkeeping requirement does not apply to an affected unit that burns very low sulfur fuel exclusively, nor does it apply to a unit that burns such gaseous fuel(s) only during unit startup.

(ix) For 7-day calibration tests for certification or recertification, a certification from the cylinder gas vendor or CEMS vendor that calibration gas, as defined in § 72.2 of this chapter and appendix A to this part, was used to conduct calibration error testing;

(i) Whenever an affected unit has been placed into long-term cold storage, written notification of the date and hour that the unit was shutdown and a statement from the designated representative stating that the shutdown is expected to last for at least two years from that date, in accordance with the definition for long-term cold storage of a unit as provided in § 72.2 of this chapter.

(a) The designated representative for an affected unit shall electronically report the data and information in paragraphs (a), (b), and (c) of this section to the Administrator quarterly, beginning with the data from the earlier of the calendar quarter corresponding to the date of provisional certification or the calendar quarter corresponding to the relevant deadline for initial certification in § 75.4(a), (b), or (c). The initial quarterly report shall contain hourly data beginning with the hour of provisional certification or the hour corresponding to the relevant certification deadline, whichever is earlier. For an affected unit subject to § 75.4(d) that is shutdown on the relevant compliance date in § 75.4(a) or has been placed in long-term cold storage (as defined in § 72.2 of this chapter), quarterly reports are not required. In such cases, the owner or operator shall submit quarterly reports for the unit beginning with the data from the quarter in which the unit recommences commercial operation (where the initial quarterly report contains hourly data beginning with the first hour of recommenced commercial operation of the unit). For units placed into long-term cold storage during a reporting quarter, the exemption from submitting quarterly reports begins with the calendar quarter following the date that the unit is placed into long-term cold storage. For any provisionally-certified monitoring system, § 75.20(a)(3) shall apply for initial certifications, and § 75.20(b)(5) shall apply for recertifications. Each electronic report must be submitted to the Administrator within 30 days following the end of each calendar quarter. Prior to January 1, 2008, each electronic report shall include for each affected unit (or group of units using a common stack), the information provided in paragraphs (a)(1), (a)(2), and (a)(8) through (a)(15) of this section. During the time period of January 1, 2008 to January 1, 2009, each electronic report shall include, either the information provided in paragraphs (a)(1), (a)(2), and (a)(8) through (a)(15) of this section or the information provided in paragraphs (a)(3) through (a)(15) of this section. On and after January 1, 2009, the owner or operator shall meet the requirements of paragraphs (a)(3) through (a)(15) of this section only. Each electronic report shall also include the date of report generation.

(A) Facility/ORISPL number;

(B) Calendar quarter and year for the data contained in the report; and

(A) Plant name and facility ID;

(B) EPA AIRS facility system ID;

(C) State facility ID;

(D) Source category/type;

(E) Primary SIC code;

(F) State postal abbreviation;

(G) County code; and

(2) The information and hourly data required in § 75.53 and §§ 75.57 through 75.59, excluding the following:

(i) Descriptions of adjustments, corrective action, and maintenance;

(ii) Information which is incompatible with electronic reporting (e.g., field data sheets, lab analyses, quality control plan);

(iii) Opacity data listed in or § 75.57(f), and in § 75.59(a)(8);

(iv) For units with SO2 or NOX add-on emission controls that do not elect to use the approved site-specific parametric monitoring procedures for calculation of substitute data, the information in § 75.58(b)(3);

(v) [Reserved]

(vi) Information required by § 75.57(h) concerning the causes of any missing data periods and the actions taken to cure such causes;

(vii) Hardcopy monitoring plan information required by § 75.53 and hardcopy test data and results required by § 75.59;

(viii) Records of flow monitor and moisture monitoring system polynomial equations, coefficients, or “K” factors required by § 75.59(a)(5)(vi) or § 75.59(a)(5)(vii);

(ix) Daily fuel sampling information required by § 75.58(c)(3)(i) for units using assumed values under appendix D;

(x) Information required by §§ 75.59(b)(1)(vi), (vii), (viii), (ix), and (xiii), and (b)(2)(iii) and (iv) concerning fuel flowmeter accuracy tests and transmitter/transducer accuracy tests;

(xi) Stratification test results required as part of the RATA supplementary records under § 75.59(a)(7);

(xii) Data and results of RATAs that are aborted or invalidated due to problems with the reference method or operational problems with the unit and data and results of linearity checks that are aborted or invalidated due to problems unrelated to monitor performance; and

(xiii) Supplementary RATA information required under § 75.59(a)(7), except that:

(A) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for flow RATAs at circular or rectangular stacks (or ducts) in which angular compensation for yaw and/or pitch angles is used (i.e., Method 2F or 2G in appendices A-1 and A-2 to part 60 of this chapter), with or without wall effects adjustments;

(B) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for any flow RATA run at a circular stack in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is determined by direct measurement;

(C) The data under § 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs at circular stacks in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a default wall effects adjustment factor is applied; and

(D) The data under § 75.59(a)(7)(ix)(A) through (F) shall be reported for all flow RATAs at rectangular stacks or ducts in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is applied.

(i) Facility/ORISPL number;

(ii) Calendar quarter and year for the data contained in the report; and

(4) In accordance with § 75.62(a)(1), if any monitoring plan information required in § 75.53 requires an update, either under § 75.53(b) or elsewhere in this part, submission of the electronic monitoring plan update shall be completed prior to or concurrent with the submittal of the quarterly electronic data report for the appropriate quarter in which the update is required.

(5) The daily calibration error test and daily interference check information required in § 75.59(a)(1) and (a)(2) must always be included in the electronic quarterly emissions report. All other certification, quality assurance, and quality control information in § 75.59 that is not excluded from electronic reporting under paragraph (a)(2) or (a)(7) of this section shall be submitted separately, either prior to or concurrent with the submittal of the relevant electronic quarterly emissions report. However, reporting of the information in § 75.59(a)(9)(x) is not required until September 26, 2011, and reporting of the information in § 75.59(a)(15), (b)(6), and (d)(4) is not required until March 27, 2012.

(6) The information and hourly data required in §§ 75.57 through 75.59, and daily calibration error test data, daily interference check, and off-line calibration demonstration information required in § 75.59(a)(1) and (2).

(7) Notwithstanding the requirements of paragraphs (a)(4) through (a)(6) of this section, the following information is excluded from electronic reporting:

(i) Descriptions of adjustments, corrective action, and maintenance;

(ii) Information which is incompatible with electronic reporting (e.g., field data sheets, lab analyses, quality control plan);

(iii) Opacity data listed in § 75.57(f), and in § 75.59(a)(8);

(iv) For units with SO2 or NOX add-on emission controls that do not elect to use the approved site-specific parametric monitoring procedures for calculation of substitute data, the information in § 75.58(b)(3);

(v) Information required by § 75.57(h) concerning the causes of any missing data periods and the actions taken to cure such causes;

(vi) Hardcopy monitoring plan information required by § 75.53 and hardcopy test data and results required by § 75.59;

(vii) Records of flow monitor and moisture monitoring system polynomial equations, coefficients, or “K” factors required by § 75.59(a)(5)(vi) or § 75.59(a)(5)(vii);

(viii) Daily fuel sampling information required by § 75.58(c)(3)(i) for units using assumed values under appendix D of this part;

(ix) Information required by §§ 75.59(b)(1)(vi), (vii), (viii), (ix), and (xiii), and (b)(2)(iii) and (iv) concerning fuel flowmeter accuracy tests and transmitter/transducer accuracy tests;

(x) Stratification test results required as part of the RATA supplementary records under § 75.59(a)(7);

(xi) Data and results of RATAs that are aborted or invalidated due to problems with the reference method or operational problems with the unit and data and results of linearity checks that are aborted or invalidated due to problems unrelated to monitor performance;

(xii) Supplementary RATA information required under § 75.59(a)(7)(i) through § 75.59(a)(7)(v), except that:

(A) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for flow RATAs at circular or rectangular stacks (or ducts) in which angular compensation for yaw and/or pitch angles is used (i.e., Method 2F or 2G in appendices A-1 and A-2 to part 60 of this chapter), with or without wall effects adjustments;

(B) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for any flow RATA run at a circular stack in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is determined by direct measurement;

(C) The data under § 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs at circular stacks in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a default wall effects adjustment factor is applied; and

(D) The data under § 75.59(a)(7)(ix)(A) through (F) shall be reported for all flow RATAs at rectangular stacks or ducts in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is applied; and

(xiii) The certification required by section 6.1.2(b) of appendix A to this part and recorded under § 75.57(a)(7).

(8) Tons (rounded to the nearest tenth) of SO2 emitted during the quarter and cumulative SO2 emissions for the calendar year.

(9) Average NOX emission rate (lb/mmBtu, rounded to the nearest thousandth) during the quarter and cumulative NOX emission rate for the calendar year.

(12) Unit or stack or common pipe header operating hours for quarter and cumulative unit or stack or common pipe header operating hours for calendar year.

(13) For low mass emissions units for which the owner or operator is using the optional low mass emissions methodology in § 75.19(c) to calculate NOX mass emissions, the designated representative must also report tons (rounded to the nearest tenth) of NOX emitted during the quarter and cumulative NOX mass emissions for the calendar year.

(14) For low mass emissions units using the optional long term fuel flow methodology under § 75.19(c), for each quarter report the long term fuel flow for each fuel according to § 75.58(f)(2).

(15) For units using the optional fuel flow to load procedure in section 2.1.7 of appendix D to this part, report both the fuel flow-to-load baseline data and the results of the fuel flow-to-load test each quarter.

(1) For units that the owner or operator intends to monitor for NOX mass emissions using NOX emission rate and heat input rate, the maximum potential NOX emission rate and the maximum potential hourly heat input of the unit, as defined in § 72.2 of this chapter.

(c) The owner or operator of an affected unit that, based on information submitted by the designated representative in the monitoring plan, qualifies as a gas-fired or oil-fired unit but not as a peaking unit, as defined in § 72.2 of this chapter, shall either:

(1) Meet the requirements of paragraph (a) of this section and, if applicable, paragraph (b) of this section; or

(2) Meet the general operating requirements in § 75.10 for a NOX-diluent continuous emission monitoring system, except as provided in accordance with subpart E of this part, and use the procedures specified in appendix D to this part for determining hourly heat input rate. However, for a common pipe configuration, the heat input rate apportionment provisions in section 2.1.2 of appendix D to this part shall not be used to meet the NOX mass reporting provisions of this subpart, unless all of the units served by the common pipe are affected units and have similar efficiencies; or

(3) Meet the requirements of the low mass emission excepted methodology under paragraph (e)(2) of this section and under § 75.19, if applicable.

The owner or operator of an affected unit shall either: calculate hourly NOX mass emissions (in lbs) by multiplying the hourly NOX emission rate (in lbs/mmBtu) by the hourly heat input rate (in mmBtu/hr) and the unit or stack operating time (as defined in § 72.2), or, as provided in paragraph (e) of this section, calculate hourly NOX mass emissions from the hourly NOX concentration (in ppm) and the hourly stack flow rate (in scfh). Only one methodology for determining NOX mass emissions shall be identified in the monitoring plan for each monitoring location at any given time. The owner or operator shall also calculate quarterly and cumulative year-to-date NOX mass emissions and cumulative NOX mass emissions for the ozone season (in tons) by summing the hourly NOX mass emissions according to the procedures in section 8 of appendix F to this part.

(1) The designated representative for an affected unit shall electronically report the data and information in this paragraph (f)(1) and in paragraphs (f)(2) and (3) of this section to the Administrator quarterly, unless the unit has been placed in long-term cold storage (as defined in § 72.2 of this chapter). Each electronic report must be submitted to the Administrator within 30 days following the end of each calendar quarter. Each electronic report shall include the information provided in paragraphs (f)(1)(i) through (x) of this section and shall also include the date of report generation. A unit placed into long-term cold storage is exempted from submitting quarterly reports beginning with the calendar quarter following the quarter in which the unit is placed into long-term cold storage, provided that the owner or operator shall submit quarterly reports for the unit beginning with the data from the quarter in which the unit recommences operation (where the initial quarterly report contains hourly data beginning with the first hour of recommenced operation of the unit).

(A) (1) Facility/ORISPL number;

(2) Calendar quarter and year data contained in the report; and

(3) Electronic data reporting format version used for the report.

(B) [Reserved]

(A) Descriptions of adjustments, corrective action, and maintenance;

(B) Information which is incompatible with electronic reporting (e.g., field data sheets, lab analyses, quality control plan);

(C) For units with NOX add-on emission controls that do not elect to use the approved site-specific parametric monitoring procedures for calculation of substitute data, the information in § 75.58(b)(3);

(D) Information required by § 75.57(h) concerning the causes of any missing data periods and the actions taken to cure such causes;

(E) Hardcopy monitoring plan information required by § 75.53 and hardcopy test data and results required by § 75.59;

(F) Records of flow polynomial equations and numerical values required by § 75.59(a)(5)(vi);

(G) Daily fuel sampling information required by § 75.58(c)(3)(i) for units using assumed values under appendix D to this part;

(H) Information required by § 75.59(b)(2) concerning transmitter or transducer accuracy tests;

(I) Stratification test results required as part of the RATA supplementary records under § 75.59(a)(7);

(J) Data and results of RATAs that are aborted or invalidated due to problems with the reference method or operational problems with the unit and data and results of linearity checks that are aborted or invalidated due to operational problems with the unit; and

(K) Supplementary RATA information required under § 75.59(a)(7), except that:

(1) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for flow RATAs at circular or rectangular stacks (or ducts) in which angular compensation for yaw and/or pitch angles is used (i.e., Method 2F or 2G in appendices A-1 and A-2 to part 60 of this chapter), with or without wall effects adjustments;

(2) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for any flow RATA run at a circular stack in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is determined by direct measurement;

(3) The data under § 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs at circular stacks in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a default wall effects adjustment factor is applied; and

(4) The data under § 75.59(a)(7)(ix)(A) through (F) shall be reported for all flow RATAs at rectangular stacks or ducts in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is applied.

(iii) Average NOX emission rate (lb/mmBtu, rounded to the nearest thousandth) during the quarter and cumulative NOX emission rate for the calendar year.

(iv) Tons of NOX emitted during quarter, cumulative tons of NOX emitted during the year, and, during the second and third calendar quarters, cumulative tons of NOX emitted during the ozone season.

(vi) Unit or stack or common pipe header operating hours for quarter, cumulative unit, stack or common pipe header operating hours for calendar year, and, during the second and third calendar quarters, cumulative operating hours during the ozone season.

(ix) On and after on January 1, 2024, for a unit subject to subpart GGGGG of part 97 of this chapter or a state implementation plan approved under § 52.38(b)(12) of this chapter and determining NOX mass emission rate at a common stack, apportioned hourly NOX mass emission rate for the unit, lb/hr.

(x) On and after January 1, 2024, for a unit that is subject to subpart GGGGG of part 97 of this chapter or a state implementation plan approved under § 52.38(b)(12) of this chapter, that lists coal or a solid coal-derived fuel as a fuel in the unit's monitoring plan under § 75.53 for any portion of the ozone season in the year for which data are being reported, that serves a generator of 100 MW or larger nameplate capacity, and that is not a circulating fluidized bed boiler, provided that through December 31, 2029, the requirements under this paragraph (f)(1)(x) shall apply to a unit in a given calendar year only if the unit also was equipped with selective catalytic reduction controls on or before September 30 of the previous year:

(A) Daily NOX emissions (lbs) for each day of the reporting period;

(B) Daily heat input (mmBtu) for each day of the reporting period;

(C) Daily average NOX emission rate (lb/mmBtu, rounded to the nearest thousandth) for each day of the reporting period;

(D) Daily NOX emissions (lbs) exceeding the applicable backstop daily NOX emission rate for each day of the reporting period;

(E) Cumulative NOX emissions (tons, rounded to the nearest tenth) exceeding the applicable backstop daily NOX emission rate during the ozone season; and

(F) Cumulative NOX emissions (tons, rounded to the nearest tenth) exceeding the applicable backstop daily NOX emission rate during the ozone season by more than 50 tons, calculated as the remainder of the amount calculated under paragraph (f)(1)(x)(E) of this section minus 50, but not less than zero.

(11) Units may qualify to use the optional NOX mass emissions estimation protocol for gas-fired and oil-fired peaking units in appendix E to this part on an ozone season basis. In order to be allowed to use this methodology, the unit must meet the definition of “peaking unit” in § 72.2 of this chapter, except that the words “year”, “calendar year” and “calendar years” in that definition shall be replaced by the words “ozone season”, “ozone season”, and “ozone seasons”, respectively. In addition, in the definition of the term “capacity factor” in § 72.2 of this chapter, the word “annual” shall be replaced by the words “ozone season” and the number “8,760” shall be replaced by the number “3,672”.

All terms used in this part shall have the meaning set forth in the Act, in § 72.2 of this chapter, and in this section as follows:

(a) § 72.2 (Definitions);

Part 72 of this chapter, including §§ 72.2 (definitions), 72.3 (measurements, abbreviations, and acronyms), 72.4 (Federal authority), 72.5 (State authority), 72.6 (applicability), 72.7 (new units exemption), 72.8 (retired units exemption), 72.9 (standard requirements), 72.10 (availability of information), and 72.11 (computation of time), shall apply to this part. The procedures for appeals of decisions of the Administrator under this part are contained in part 78 of this chapter.

(A) “CPI(year)” is the Consumer Price Index as defined in § 72.2 of this chapter and “year” is the year in which the source or unit as appropriate had excess emissions.

(1) The terms used in this part with regard to a decision of the Administrator that is appealed under this part shall have the meanings as set forth in the regulations under which the Administrator made such decision and as set forth in paragraph (a)(2) of this section and § 72.2 of this chapter.

The owners and operators, and to the extent applicable, the CAIR designated representative, of a CAIR NOX unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and in subpart H of part 75 of this chapter. For purposes of complying with such requirements, the definitions in § 96.102 and in § 72.2 of this chapter shall apply, and the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CAIR NOX unit,” “CAIR designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively, as defined in § 96.102. The owner or operator of a unit that is not a CAIR NOX unit but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CAIR NOX unit.

(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved NOX emission rate (i.e., NOX-diluent) system, the maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

(2) For a disapproved NOX pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential concentration of NOX and the maximum potential flow rate, as defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this chapter.

(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO2 concentration or the minimum potential O2 concentration (as applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of appendix A to part 75 of this chapter.

(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.

(5) For a disapproved excepted NOX monitoring system under appendix E to part 75 of this chapter, the fuel-specific maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

The terms used in this part shall have the meanings set forth in this section as follows:

(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other nonmerchantable material, and that is;

(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or

(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.

Boiler means an enclosed fossil- or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.

Bottoming-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.

CAIR authorized account representative means, with regard to a general account, a responsible natural person who is authorized, in accordance with subparts BBB, FFF, and III of this part, to transfer and otherwise dispose of CAIR SO2 allowances held in the general account and, with regard to a compliance account, the CAIR designated representative of the source.

CAIR designated representative means, for a CAIR SO2 source and each CAIR SO2 unit at the source, the natural person who is authorized by the owners and operators of the source and all such units at the source, in accordance with subparts BBB and III of this part, to represent and legally bind each owner and operator in matters pertaining to the CAIR SO2 Trading Program. If the CAIR SO2 source is also a CAIR NOX source, then this natural person shall be the same person as the CAIR designated representative under the CAIR NOX Annual Trading Program. If the CAIR SO2 source is also a CAIR NOX Ozone Season source, then this natural person shall be the same person as the CAIR designated representative under the CAIR NOX Ozone Season Trading Program. If the CAIR SO2 source is also subject to the Acid Rain Program, then this natural person shall be the same person as the designated representative under the Acid Rain Program. If the CAIR SO2 source is also subject to the Hg Budget Trading Program, then this natural person shall be the same person as the Hg designated representative under the Hg Budget Trading Program.

CAIR NO X Annual Trading Program means a multi-state nitrogen oxides air pollution control and emission reduction program approved and administered by the Administrator in accordance with subparts AA through II of this part and § 51.123(o)(1) or (2) of this chapter or established by the Administrator in accordance with subparts AA through II of part 97 of this chapter and §§ 51.123(p) and 52.35 of this chapter, as a means of mitigating interstate transport of fine particulates and nitrogen oxides.

CAIR NOX Ozone Season source means a source that includes one or more CAIR NOX Ozone Season units.

CAIR NOX Ozone Season Trading Program means a multi-state nitrogen oxides air pollution control and emission reduction program approved and administered by the Administrator in accordance with subparts AAAA through IIII of this part and § 51.123(aa)(1) or (2) (and (bb)(1)), (bb)(2), or (dd) of this chapter or established by the Administrator in accordance with subparts AA through II of part 97 of this chapter and §§ 51.123(p) and 52.35 of this chapter, as a means of mitigating interstate transport of ozone and nitrogen oxides.

CAIR NOX source means a source that is subject to the CAIR NOX Ozone Season Trading Program.

CAIR permit means the legally binding and federally enforceable written document, or portion of such document, issued by the permitting authority under subpart CCC of this part, including any permit revisions, specifying the CAIR SO2 Trading Program requirements applicable to a CAIR SO2 source, to each CAIR SO2 unit at the source, and to the owners and operators and the CAIR designated representative of the source and each such unit.

CAIR SO2 allowance means a limited authorization issued by the Administrator under the Acid Rain Program, or by a permitting authority under provisions of a State implementation plan that are approved under § 51.124(o)(1) or (2) or (r) of this chapter or § 97.288 of this chapter,”, by designating the last sentence of the definition as paragraph (4), and by revising in paragraph (4) the words “(Program or under the provisions of a State implementation plan that is approved under § 51.124(o)(1) or (2) of this chapter” to read “(Program, provisions of a State implementation plan that are approved under § 51.124(o)(1) or (2) or (r) of this chapter, or § 97.288 of this chapter, to emit sulfur dioxide during the control period of the specified calendar year for which the authorization is allocated or of any calendar year thereafter under the CAIR SO2 Trading Program as follows:

The owners and operators, and to the extent applicable, the CAIR designated representative, of a CAIR SO2 unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and in subparts F and G of part 75 of this chapter. For purposes of complying with such requirements, the definitions in § 96.202 and in § 72.2 of this chapter shall apply, and the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CAIR SO2 unit,” “CAIR designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively, as defined in § 96.202. The owner or operator of a unit that is not a CAIR SO2 unit but that is monitored under § 75.16(b)(2) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CAIR SO2 unit.

The owners and operators, and to the extent applicable, the CAIR designated representative, of a CAIR NOX Ozone Season unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and in subpart H of part 75 of this chapter. For purposes of complying with such requirements, the definitions in § 96.302 and in § 72.2 of this chapter shall apply, and the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CAIR NOX Ozone Season unit,” “CAIR designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively, as defined in § 96.302. The owner or operator of a unit that is not a CAIR NOX Ozone Season unit but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CAIR NOX Ozone Season unit.

(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved NOX emission rate (i.e., NOX-diluent) system, the maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

(2) For a disapproved NOX pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential concentration of NOX and the maximum potential flow rate, as defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this chapter.

(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO2 concentration or the minimum potential O2 concentration (as applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of appendix A to part 75 of this chapter.

(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.

(5) For a disapproved excepted NOX monitoring system under appendix E to part 75 of this chapter, the fuel-specific maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

The owners and operators, and to the extent applicable, the NOX authorized account representative of a NOX Budget unit, shall comply with the monitoring and reporting requirements as provided in this subpart and in subpart H of part 75 of this chapter. For purposes of complying with such requirements, the definitions in § 96.2 and in § 72.2 of this chapter shall apply, and the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be replaced by the terms “NOX Budget unit,” “NOX authorized account representative,” and “continuous emission monitoring system” (or “CEMS”), respectively, as defined in § 96.2.

(3) An Indian country new unit set-aside;

The owners and operators, and to the extent applicable, the designated representative, of a CSAPR NOX Ozone Season Group 3 unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and subpart H of part 75 of this chapter. For purposes of applying such requirements, the definitions in § 97.1002 and in § 72.2 of this chapter shall apply, the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CSAPR NOX Ozone Season Group 3 unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively as defined in § 97.1002, and the term “newly affected unit” shall be deemed to mean “newly affected CSAPR NOX Ozone Season Group 3 unit”. The owner or operator of a unit that is not a CSAPR NOX Ozone Season Group 3 unit but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CSAPR NOX Ozone Season Group 3 unit.

(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved NOX emission rate (i.e., NOX-diluent) system, the maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

(2) For a disapproved NOX pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential concentration of NOX and the maximum potential flow rate, as defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this chapter.

(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO2 concentration or the minimum potential O2 concentration (as applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of appendix A to part 75 of this chapter.

(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.

(5) For a disapproved excepted NOX monitoring system under appendix E to part 75 of this chapter, the fuel-specific maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

The owners and operators, and to the extent applicable, the CAIR designated representative, of a CAIR NOX unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and in subpart H of part 75 of this chapter. For purposes of complying with such requirements, the definitions in § 97.102 and in § 72.2 of this chapter shall apply, and the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CAIR NOX unit,“ “CAIR designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively, as defined in § 97.102. The owner or operator of a unit that is not a CAIR NOX unit but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CAIR NOX unit.

(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved NOX emission rate (i.e.,, NOX-diluent) system, the maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

(2) For a disapproved NOX pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential concentration of NOX and the maximum potential flow rate, as defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this chapter.

(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO2 concentration or the minimum potential O2 concentration (as applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of appendix A to part 75 of this chapter.

(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.

(5) For a disapproved excepted NOX monitoring system under appendix E to part 75 of this chapter, the fuel-specific maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

The terms used in this part shall have the meanings set forth in this section as follows:

(4) An authorization to emit sulfur dioxide that is not issued under the Acid Rain Program, § 97.288, or provisions of a State implementation plan that are approved under § 51.124(o)(1) or (2) or (r) of this chapter shall not be a CAIR SO2 allowance.

CAIR SO2 allowance deduction or deduct CAIR SO2 allowances means the permanent withdrawal of CAIR SO2 allowances by the Administrator from a compliance account, e.g., in order to account for a specified number of tons of total sulfur dioxide emissions from all CAIR SO2 units at a CAIR SO2 source for a control period, determined in accordance with subpart HHH of this part, or to account for excess emissions.

CAIR SO2 Allowance Tracking System means the system by which the Administrator records allocations, deductions, and transfers of CAIR SO2 allowances under the CAIR SO2 Trading Program. This is the same system as the Allowance Tracking System under § 72.2 of this chapter by which the Administrator records allocations, deduction, and transfers of Acid Rain SO2 allowances under the Acid Rain Program.

CAIR SO2 Allowance Tracking System account means an account in the CAIR SO2 Allowance Tracking System established by the Administrator for purposes of recording the allocation, holding, transferring, or deducting of CAIR SO2 allowances. Such allowances will be allocated, held, deducted, or transferred only as whole allowances.

CAIR SO2 allowances held or hold CAIR SO2 allowances means the CAIR SO2 allowances recorded by the Administrator, or submitted to the Administrator for recordation, in accordance with subparts FFF, GGG, and III of this part or part 73 of this chapter, in a CAIR SO2 Allowance Tracking System account.

CAIR SO2 emissions limitation means, for a CAIR SO2 source, the tonnage equivalent, in SO2 emissions in a control period, of the CAIR SO2 allowances available for deduction for the source under § 97.254(a) and (b) for the control period.

CAIR SO2 source means a source that includes one or more CAIR SO2 units.

CAIR SO2 Trading Program means a multi-state sulfur dioxide air pollution control and emission reduction program established by the Administrator in accordance with subparts AAA through III of this part and §§ 51.124(r) and 52.36 of this chapter or approved and administered by the Administrator in accordance with subparts AAA through III of part 96 of this chapter and § 51.124(o) (1) or (2) of this chapter, as a means of mitigating interstate transport of fine particulates and sulfur dioxide.

CAIR SO2 unit means a unit that is subject to the CAIR SO2 Trading Program under § 97.204 and, except for purposes of § 97.205, a CAIR SO2 opt-in unit under subpart III of this part.

Certifying official means:

The owners and operators, and to the extent applicable, the CAIR designated representative, of a CAIR SO2 unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and in subparts F and G of part 75 of this chapter. For purposes of complying with such requirements, the definitions in § 97.202 and in § 72.2 of this chapter shall apply, and the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CAIR SO2 unit,” “CAIR designated representative,” and “continuous emission monitoring system” or (“CEMS”) respectively, as defined in § 97.202. The owner or operator of a unit that is not a CAIR SO2 unit but that is monitored under § 75.16(b)(2) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CAIR SO2 unit.

The owners and operators, and to the extent applicable, the CAIR designated representative, of a CAIR NOX Ozone Season unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and in subpart H of part 75 of this chapter. For purposes of complying with such requirements, the definitions in § 97.302 and in § 72.2 of this chapter shall apply, and the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CAIR NOX Ozone Season unit,” “CAIR designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively, as defined in § 97.302. The owner or operator of a unit that is not a CAIR NOX Ozone Season unit but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CAIR NOX Ozone Season unit.

(3) An Indian country new unit set-aside; or

The owners and operators, and to the extent applicable, the designated representative, of a CSAPR NOX Annual unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and subpart H of part 75 of this chapter. For purposes of applying such requirements, the definitions in § 97.402 and in § 72.2 of this chapter shall apply, the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CSAPR NOX Annual unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively as defined in § 97.402, and the term “newly affected unit” shall be deemed to mean “newly affected CSAPR NOX Annual unit”. The owner or operator of a unit that is not a CSAPR NOX Annual unit but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CSAPR NOX Annual unit.

(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved NOX emission rate (i.e., NOX-diluent) system, the maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

(2) For a disapproved NOX pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential concentration of NOX and the maximum potential flow rate, as defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this chapter.

(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO2 concentration or the minimum potential O2 concentration (as applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of appendix A to part 75 of this chapter.

(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.

(5) For a disapproved excepted NOX monitoring system under appendix E to part 75 of this chapter, the fuel-specific maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

(3) An Indian country new unit set-aside; or

The owners and operators, and to the extent applicable, the designated representative, of a CSAPR NOX Ozone Season Group 1 unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and subpart H of part 75 of this chapter. For purposes of applying such requirements, the definitions in § 97.502 and in § 72.2 of this chapter shall apply, the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CSAPR NOX Ozone Season Group 1 unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively as defined in § 97.502, and the term “newly affected unit” shall be deemed to mean “newly affected CSAPR NOX Ozone Season Group 1 unit”. The owner or operator of a unit that is not a CSAPR NOX Ozone Season Group 1 unit but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CSAPR NOX Ozone Season Group 1 unit.

(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved NOX emission rate (i.e., NOX-diluent) system, the maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

(2) For a disapproved NOX pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential concentration of NOX and the maximum potential flow rate, as defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this chapter.

(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO2 concentration or the minimum potential O2 concentration (as applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of appendix A to part 75 of this chapter.

(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.

(5) For a disapproved excepted NOX monitoring system under appendix E to part 75 of this chapter, the fuel-specific maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

(3) An Indian country new unit set-aside; or

The owners and operators, and to the extent applicable, the designated representative, of a CSAPR SO2 Group 1 unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and subparts F and G of part 75 of this chapter. For purposes of applying such requirements, the definitions in § 97.602 and in § 72.2 of this chapter shall apply, the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CSAPR SO2 Group 1 unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively as defined in § 97.602, and the term “newly affected unit” shall be deemed to mean “newly affected CSAPR SO2 Group 1 unit”. The owner or operator of a unit that is not a CSAPR SO2 Group 1 unit but that is monitored under § 75.16(b)(2) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CSAPR SO2 Group 1 unit.

The owners and operators, and to the extent applicable, the NOX authorized account representative of a NOX Budget unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and in subpart H of part 75 of this chapter. For purposes of complying with such requirements, the definitions in § 97.2 and in § 72.2 of this chapter shall apply, and the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “NOX Budget unit,” “NOX authorized account representative,” and “continuous emission monitoring system” (or “CEMS”) respectively, as defined in § 97.2. The owner or operator of a unit that is not a NOX Budget unit but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the monitoring, recordkeeping, and reporting requirements for a NOX Budget unit under this part.

(3) An Indian country new unit set-aside; or

The owners and operators, and to the extent applicable, the designated representative, of a CSAPR SO2 Group 2 unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and subparts F and G of part 75 of this chapter. For purposes of applying such requirements, the definitions in § 97.702 and in § 72.2 of this chapter shall apply, the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CSAPR SO2 Group 2 unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively as defined in § 97.702, and the term “newly affected unit” shall be deemed to mean “newly affected CSAPR SO2 Group 2 unit”. The owner or operator of a unit that is not a CSAPR SO2 Group 2 unit but that is monitored under § 75.16(b)(2) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CSAPR SO2 Group 2 unit.

(3) An Indian country new unit set-aside; or

The owners and operators, and to the extent applicable, the designated representative, of a CSAPR NOX Ozone Season Group 2 unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and subpart H of part 75 of this chapter. For purposes of applying such requirements, the definitions in § 97.802 and in § 72.2 of this chapter shall apply, the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “CSAPR NOX Ozone Season Group 2 unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively as defined in § 97.802, and the term “newly affected unit” shall be deemed to mean “newly affected CSAPR NOX Ozone Season Group 2 unit”. The owner or operator of a unit that is not a CSAPR NOX Ozone Season Group 2 unit but that is monitored under § 75.72(b)(2)(ii) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a CSAPR NOX Ozone Season Group 2 unit.

(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:

(1) For a disapproved NOX emission rate (i.e., NOX-diluent) system, the maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

(2) For a disapproved NOX pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential concentration of NOX and the maximum potential flow rate, as defined in sections 2.1.2.1 and 2.1.4.1 of appendix A to part 75 of this chapter.

(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO2 concentration or the minimum potential O2 concentration (as applicable), as defined in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of appendix A to part 75 of this chapter.

(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.

(5) For a disapproved excepted NOX monitoring system under appendix E to part 75 of this chapter, the fuel-specific maximum potential NOX emission rate, as defined in § 72.2 of this chapter.

The terms used in this subpart shall have the meanings set forth in this section as follows:

The owners and operators, and to the extent applicable, the designated representative, of a Texas SO2 Trading Program unit, shall comply with the monitoring, recordkeeping, and reporting requirements as provided in this subpart and subparts F and G of part 75 of this chapter. For purposes of applying such requirements, the definitions in § 97.902 and in § 72.2 of this chapter shall apply, the terms “affected unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) in part 75 of this chapter shall be deemed to refer to the terms “Texas SO2 Trading Program unit,” “designated representative,” and “continuous emission monitoring system” (or “CEMS”) respectively as defined in § 97.902. The owner or operator of a unit that is not a Texas SO2 Trading Program unit but that is monitored under § 75.16(b)(2) of this chapter shall comply with the same monitoring, recordkeeping, and reporting requirements as a Texas SO2 Trading Program unit.