40 C.F.R. PART 75—CONTINUOUS EMISSION MONITORING
Title 40 - Protection of Environment
Authority: 42 U.S.C. 7601 and 7651K, and 7651K note.
Source: 58 FR 3701, Jan. 11, 1993, unless otherwise noted.
Editorial Note: Nomenclature changes to part 75 appear at 67 FR 40476, June 12, 2002.
(a) Purpose. The purpose of this part is to establish requirements for the monitoring, recordkeeping, and reporting of sulfur dioxide (SO2), nitrogen oxides (NOX), and carbon dioxide (CO2) emissions, volumetric flow, and opacity data from affected units under the Acid Rain Program pursuant to sections 412 and 821 of the CAA, 42 U.S.C. 7401–7671q as amended by Public Law 101–549 (November 15, 1990) [the Act]. In addition, this part sets forth provisions for the monitoring, recordkeeping, and reporting of NOX mass emissions with which EPA, individual States, or groups of States may require sources to comply in order to demonstrate compliance with a NOX mass emission reduction program, to the extent these provisions are adopted as requirements under such a program. (b) Scope. (1) The regulations established under this part include general requirements for the installation, certification, operation, and maintenance of continuous emission or opacity monitoring systems and specific requirements for the monitoring of SO2 emissions, volumetric flow, NOX emissions, opacity, CO2 emissions and SO2 emissions removal by qualifying Phase I technologies. Specifications for the installation and performance of continuous emission monitoring systems, certification tests and procedures, and quality assurance tests and procedures are included in appendices A and B to this part. Criteria for alternative monitoring systems and provisions to account for missing data from certified continuous emission monitoring systems or approved alternative monitoring systems are also included in the regulation. (2) Statistical estimation procedures for missing data are included in appendix C to this part. Optional protocols for estimating SO2 mass emissions from gas-fired or oil-fired units and NOX emissions from gas-fired peaking or oil-fired peaking units are included in appendices D and E, respectively, to this part. Requirements for recording and recordkeeping of monitoring data and for quarterly electronic reporting also are specified. Procedures for conversion of monitoring data into units of the standard are included in appendix F to this part. Procedures for the monitoring and calculation of CO2 emissions are included in appendix G of this part. [58 FR 3701, Jan. 11, 1993; 58 FR 34126, June 23, 1993; 58 FR 40747, July 30, 1993; 63 FR 57498, Oct. 27, 1999; 67 FR 40421, June 12, 2002] (a) Except as provided in paragraphs (b) and (c) of this section, the provisions of this part apply to each affected unit subject to Acid Rain emission limitations or reduction requirements for SO2 or NOX. (b) The provisions of this part do not apply to: (1) A new unit for which a written exemption has been issued under §72.7 of this chapter (any new unit that serves one or more generators with total nameplate capacity of 25 MWe or less and burns only fuels with a sulfur content of 0.05 percent or less by weight may apply to the Administrator for an exemption); or (2) Any unit not subject to the requirements of the Acid Rain Program due to operation of any paragraph of §72.6(b) of this chapter; or (3) An affected unit for which a written exemption has been issued under §72.8 of this chapter and an exception granted under §75.67 of this part. (c) The provisions of this part apply to sources subject to a State or federal NOX mass emission reduction program, to the extent these provisions are adopted as requirements under such a program. (d) The provisions of this part apply to sources subject to a State or Federal mercury (Hg) mass emission reduction program, to the extent that these provisions are adopted as requirements under such a program. [58 FR 3701, Jan. 11, 1993, as amended at 58 FR 15716, Mar. 23, 1993; 60 FR 26516, May 17, 1995; 63 FR 57499, Oct. 27, 1998; 70 FR 28678, May 18, 2005] The provisions of part 72, including the following, shall apply to this part: (a) §72.2 (Definitions); (b) §72.3 (Measurements, Abbreviations, and Acronyms); (c) §72.4 (Federal Authority); (d) §72.5 (State Authority); (e) §72.6 (Applicability); (f) §72.7 (New Unit Exemption); (g) §72.8 (Retired Units Exemption); (h) §72.9 (Standard Requirements); (i) §72.10 (Availability of Information); and (j) §72.11 (Computation of Time). In addition, the procedures for appeals of decisions of the Administrator under this part are contained in part 78 of this chapter. (a) The provisions of this part apply to each existing Phase I and Phase II unit on February 10, 1993. For substitution or compensating units that are so designated under the Acid Rain permit which governs that unit and contains the approved substitution or reduced utilization plan, pursuant to §72.41 or §72.43 of this chapter, the provisions of this part become applicable upon the issuance date of the Acid Rain permit. For combustion sources seeking to enter the Opt-in Program in accordance with part 74 of this chapter, the provisions of this part become applicable upon the submission of an opt-in permit application in accordance with §74.14 of this chapter. The provisions of this part for the monitoring, recording, and reporting of NOX mass emissions become applicable on the deadlines specified in the applicable State or federal NOX mass emission reduction program, to the extent these provisions are adopted as requirements under such a program. In accordance with §75.20, the owner or operator of each existing affected unit shall ensure that all monitoring systems required by this part for monitoring SO2, NOX, CO2, opacity, moisture and volumetric flow are installed and that all certification tests are completed no later than the following dates (except as provided in paragraphs (d) through (i) of this section): (1) For a unit listed in table 1 of §73.10(a) of this chapter, November 15, 1993. (2) For a substitution or a compensating unit that is designated under an approved substitution plan or reduced utilization plan pursuant to §72.41 or §72.43 of this chapter, or for a unit that is designated an early election unit under an approved NOX compliance plan pursuant to part 76 of this chapter, that is not conditionally approved and that is effective for 1995, the earlier of the following dates: (i) January 1, 1995; or (ii) 90 days after the issuance date of the Acid Rain permit (or date of approval of permit revision) that governs the unit and contains the approved substitution plan, reduced utilization plan, or NOX compliance plan. (3) For either a Phase II unit, other than a gas-fired unit or an oil-fired unit, or a substitution or compensating unit that is not a substitution or compensating unit under paragraph (a)(2) of this section: January 1, 1995. (4) For a gas-fired Phase II unit or an oil-fired Phase II unit, January 1, 1995, except that installation and certification tests for continuous emission monitoring systems for NOX and CO2 or excepted monitoring systems for NOX under appendix E or CO2 estimation under appendix G of this part shall be completed as follows: (i) For an oil-fired Phase II unit or a gas-fired Phase II unit located in an ozone nonattainment area or the ozone transport region, not later than July 1, 1995; or (ii) For an oil-fired Phase II unit or a gas-fired Phase II unit not located in an ozone nonattainment area or the ozone transport region, not later than January 1, 1996. (5) For combustion sources seeking to enter the Opt-in Program in accordance with part 74 of this chapter, the expiration date of a combustion source's opt-in permit under §74.14(e) of this chapter. (b) In accordance with §75.20, the owner or operator of each new affected unit shall ensure that all monitoring systems required under this part for monitoring of SO2, NOX, CO2, opacity, and volumetric flow are installed and all certification tests are completed on or before the later of the following dates: (1) January 1, 1995, except that for a gas-fired unit or oil-fired unit located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NOX and CO2 monitoring systems shall be July 1, 1995 and for a gas-fired unit or an oil-fired unit not located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NOX and CO2 monitoring systems shall be January 1, 1996; or (2) The earlier of 90 unit operating days or 180 calendar days after the date the unit commences commercial operation, notice of which date shall be provided under subpart G of this part. (c) In accordance with §75.20, the owner or operator of any unit affected under any paragraph of §72.6(a)(3) (ii) through (vii) of this chapter shall ensure that all monitoring systems required under this part for monitoring of SO2, NOX, CO2, opacity, and volumetric flow are installed and all certification tests are completed on or before the later of the following dates: (1) January 1, 1995, except that for a gas-fired unit or oil-fired unit located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NOX and CO2 monitoring systems shall be July 1, 1995 and for a gas-fired unit or an oil-fired unit not located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NOX and CO2 monitoring systems shall be January 1, 1996; or (2) The earlier of 90 unit operating days or 180 calendar days after the date the unit first operates after becoming subject to the requirements of the Acid Rain Program, notice of which date shall be provided under subpart G of this part. (d) In accordance with §75.20, the owner or operator of an existing unit that is shutdown and is not yet operating by the applicable dates listed in paragraph (a) of this section, or an existing unit which has been placed in long-term cold storage after having previously reported emissions data in accordance with this part, shall ensure that all monitoring systems required under this part for monitoring of SO2, NOX, CO2, opacity, and volumetric flow are installed and all 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 subpart G of this part. The owner or operator shall determine and report SO2 concentration, NOX emission rate, CO2 concentration, and flow data for all unit operating hours after the applicable compliance date in paragraph (a) of this section until all 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; (2) Reference methods under §75.22(b); or (3) Another procedure approved by the Administrator pursuant to a petition under §75.66. (e) In accordance with §75.20, if the owner or operator of an existing unit completes construction of a new stack, flue, flue gas desulfurization system or add-on NOX emission controls after the applicable deadline in paragraph (a) of this section, then the owner or operator shall ensure that all monitoring systems required under this part for monitoring SO2, NOX, CO2, opacity, and volumetric flow are installed on the new stack or duct and all certification tests are completed not later than 90 unit operating days or 180 calendar days (whichever occurs first) after the date that emissions first exit to the atmosphere through the new stack, flue, flue gas desulfurization system or add-on NOX emission controls, notice of which date shall be provided under subpart G of this part. Until emissions first pass through the new stack, flue, flue gas desulfurization system or add-on NOX emission controls, the unit is subject to the appropriate deadline in paragraph (a) of this section. The owner or operator shall determine and report SO2 concentration, NOX emission rate, CO2 concentration, and flow data for all unit operating hours after emissions first pass through the new stack, flue, flue gas desulfurization system or add-on NOX emission controls until all required certification tests are successfully completed using either: (1) The appropriate value for substitution of missing data upon recertification pursuant to §75.20(b)(3); or (2) Reference methods under §75.22(b) of this part; or (3) Another procedure approved by the Administrator pursuant to a petition under §75.66. (f) In accordance with §75.20, the owner or operator of an affected gas-fired or oil-fired peaking unit, if planning to use appendix E of this part, shall ensure that the required certification tests for excepted monitoring systems under appendix E are completed for backup fuel, as defined in §72.2 of this chapter, no later than 90 unit operating days or 180 calendar days (whichever occurs first) after the date that the unit first combusts the backup fuel following the certification testing with the primary fuel. If the required testing is completed by this deadline, the appendix E correlation curve derived from the test results may be used for reporting data under this part beginning with the first date and hour that the backup fuel is combusted, provided that the fuel flowmeter for the backup fuel was certified as of that date and hour. If the required appendix E testing has not been successfully completed by the compliance date in this paragraph, then, until the testing is completed, the owner or operator shall report NOX emission rate data for all unit operating hours that the backup fuel is combusted using either: (1) The fuel-specific maximum potential NOX emission rate, as defined in §72.2 of this chapter; or (2) Reference methods under §75.22(b) of this part; or (3) Another procedure approved by the Administrator pursuant to a petition under §75.66. (g) The provisions of this paragraph shall apply unless an owner or operator is exempt from certifying a fuel flowmeter for use during combustion of emergency fuel under section 2.1.4.3 of appendix D to this part, in which circumstance the provisions of section 2.1.4.3 of appendix D shall apply. In accordance with §75.20, whenever the owner or operator of a gas-fired or oil-fired unit uses an excepted monitoring system under appendix D or E of this part and combusts emergency fuel as defined in §72.2 of this chapter, then the owner or operator shall ensure that a fuel flowmeter measuring emergency fuel is installed and the required certification tests for excepted monitoring systems are completed by no later than 30 unit operating days after the first date after January 1, 1995 that the unit combusts emergency fuel. For all unit operating hours that the unit combusts emergency fuel after January 1, 1995 until the owner or operator installs a flowmeter for emergency fuel and successfully completes all required certification tests, the owner or operator shall determine and report SO2 mass emission data using either: (1) The maximum potential fuel flow rate, as described in appendix D of this part, and the maximum sulfur content of the fuel, as described in section 2.1.1.1 of appendix A of this part; (2) Reference methods under §75.22(b) of this part; or (3) Another procedure approved by the Administrator pursuant to a petition under §75.66. (h) [Reserved] (i) In accordance with §75.20, the owner or operator of each affected unit at which SO2 concentration is measured on a dry basis or at which moisture corrections are required to account for CO2 emissions, NOX emission rate in lb/mmBtu, heat input, or NOX mass emissions for units in a NOX mass reduction program, shall ensure that the continuous moisture monitoring system required by this part is installed and that all applicable initial certification tests required under §75.20(c)(5), (c)(6), or (c)(7) for the continuous moisture monitoring system are completed no later than the following dates: (1) April 1, 2000, for a unit that is existing and has commenced commercial operation by January 2, 2000; (2) For a new affected unit which has not commenced commercial operation by January 2, 2000, 90 unit operating days or 180 calendar days (whichever occurs first) after the date the unit commences commercial operation; or (3) For an existing unit that is shutdown and is not yet operating by April 1, 2000, 90 unit operating days or 180 calendar days (whichever occurs first) after the date that the unit recommences commercial operation. (j) If the certification tests required under paragraph (b) or (c) of this section have not been completed by the applicable compliance date, the owner or operator shall determine and report SO2 concentration, NOX emission rate, CO2 concentration, and flow rate data for all unit operating hours after the applicable compliance date in this paragraph until all 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; (2) Reference methods under §75.22(b); or (3) Another procedure approved by the Administrator pursuant to a petition under §75.66. [60 FR 17131, Apr. 4, 1995, as amended at 60 FR 26516, May 17, 1995; 63 FR 57499, Oct. 27, 1998; 64 FR 28588, May 26, 1999; 67 FR 40421, June 12, 2002] (a) A violation of any applicable regulation in this part by the owners or operators or the designated representative of an affected source or an affected unit is a violation of the Act. (b) No owner or operator of an affected unit shall operate the unit without complying with the requirements of §§75.2 through 75.75 and appendices A through G to this part. (c) No owner or operator of an affected unit shall use any alternative monitoring system, alternative reference method, or any other alternative for the required continuous emission monitoring system without having obtained the Administrator's prior written approval in accordance with §§75.23, 75.48 and 75.66. (d) No owner or operator of an affected unit shall operate the unit so as to discharge, or allow to be discharged, emissions of SO2, NOX or CO2 to the atmosphere without accounting for all such emissions in accordance with the provisions of §§75.10 through 75.19. (e) No owner or operator of an affected unit shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording SO2, NOX, or CO2 emissions discharged to the atmosphere, except for periods of recertification, or periods when calibration, quality assurance, or maintenance is performed pursuant to §75.21 and appendix B of this part. (f) No owner or operator of an affected unit shall retire or permanently discontinue use of the continuous emission monitoring system, any component thereof, the continuous opacity monitoring system, or any other approved emission monitoring system under this part, except under any one of the following circumstances: (1) During the period that the unit is covered by an approved retired unit exemption under §72.8 of this chapter that is in effect; or (2) The owner or operator is monitoring emissions from the unit with another certified monitoring system or an excepted methodology approved by the Administrator for use at that unit that provides emissions data for the same pollutant or parameter as the retired or discontinued monitoring system; or (3) The designated representative submits notification of the date of recertification testing of a replacement monitoring system in accordance with §§75.20 and 75.61, and the owner or operator recertifies thereafter a replacement monitoring system in accordance with §75.20. [58 FR 3701, Jan. 11, 1993, as amended at 58 FR 40747, July 30, 1993; 60 FR 26517, May 17, 1995; 64 FR 28589, May 26, 1999] The materials listed in this section are incorporated by reference in the corresponding sections noted. These incorporations by reference were approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as they existed on the date of approval, and a notice of any change in these materials will be published in the (a) The following materials are available for purchase from the following addresses: American Society for Testing and Material (ASTM), 100 Barr harbor Drive, P.O. Box C–700, West Conshohocken, Pennsylvania 19428–2959; and the University Microfilms International 300 North Zeeb Road, Ann Arbor, Michigan 48106. (1) ASTM D129–91, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), for appendices A and D of this part. (2) ASTM D240–87 (Reapproved 1991), Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, for appendices A, D and F of this part. (3) ASTM D287–82 (Reapproved 1987), Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), for appendix D of this part. (4) ASTM D388–92, Standard Classification of Coals by Rank, incorporation by reference for appendix F of this part. (5) ASTM D941–88, Standard Test Method for Density and Relative Density (Specific Gravity) of Liquids by Lipkin Bicapillary Pycnometer, for appendix D of this part. (6) ASTM D1072–90, Standard Test Method for Total Sulfur in Fuel Gases, for appendix D of this part. (7) ASTM D1217–91, Standard Test Method for Density and Relative Density (Specific Gravity) of Liquids by Bingham Pycnometer, for appendix D of this part. (8) ASTM D1250–80 (Reapproved 1990), Standard Guide for Petroleum Measurement Tables, for appendix D of this part. (9) ASTM D1298–85 (Reapproved 1990), Standard Practice for Density, Relative Density (Specific Gravity) or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, for appendix D of this part. (10) ASTM D1480–91, Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Bingham Pycnometer, for appendix D of this part. (11) ASTM D1481–91, Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Lipkin Bicapillary Pycnometer, for appendix D of this part. (12) ASTM D1552–90, Standard Test Method for Sulfur in Petroleum Products (High Temperature Method), for appendices A and D of the part. (13) ASTM D1826–88, Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, for appendices D and F to this part. (14) ASTM D1945–91, Standard Test Method for Analysis of Natural Gas by Gas Chromatography, for appendices F and G of this part. (15) ASTM D1946–90, Standard Practice for Analysis of Reformed Gas by Gas Chromatography, for appendices F and G of this part. (16) ASTM D1989–92, Standard Test Method for Gross Calorific Value of Coal and Coke by Microprocessor Controlled Isoperibol Calorimeters, for appendix F of this part. (17) ASTM D2013–86, Standard Method of Preparing Coal Samples for Analysis, for appendix F of this part. (18) ASTM D2015–91, Standard Test Method for Gross Calorific Value of Coal and Coke by the Adiabatic Bomb Calorimeter, for appendices A, D and F of this part. (19) ASTM D2234–89, Standard Test Methods for Collection of a Gross Sample of Coal, for appendix F of this part. (20) ASTM D2382–88, Standard Test Method for Heat of Combustion of Hydrocarbon Fuels by Bomb Calorimeter (High-Precision Method), for appendices D and F of this part. (21) ASTM D2502–87, Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils from Viscosity Measurements, for appendix G of this part. (22) ASTM D2503–82 (Reapproved 1987), Standard Test Method for Molecular Weight (Relative Molecular Mass) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, for appendix G of this part. (23) ASTM D2622–92, Standard Test Method for Sulfur in Petroleum Products by X-Ray Spectrometry, for appendices A and D of this part. (24) ASTM D3174–89, Standard Test Method for Ash in the Analysis Sample of Coal and Coke From Coal, for appendix G of this part. (25) ASTM D3176–89, Standard Practice for Ultimate Analysis of Coal and Coke, for appendices A and F of this part. (26) ASTM D3177–89, Standard Test Methods for Total Sulfur in the Analysis Sample of Coal and Coke, for appendix A of this part. (27) ASTM D3178–89, Standard Test Methods for Carbon and Hydrogen in the Analysis Sample of Coal and Coke, for appendix G of this part. (28) ASTM D3238–90, Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method, for appendix G of this part. (29) ASTM D3246–81 (Reapproved 1987), Standard Test Method for Sulfur in Petroleum Gas By Oxidative Microcoulometry, for appendix D of this part. (30) ASTM D3286–91a, Standard Test Method for Gross Calorific Value of Coal and Coke by the Isoperibol Bomb Calorimeter, for appendix F of this part. (31) ASTM D3588–91, Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density (Specific Gravity) of Gaseous Fuels, for appendices D and F to this part. (32) ASTM D4052–91, Standard Test Method for Density and Relative Density of Liquids by Digital Density Meter, for appendix D of this part. (33) ASTM D4057–88, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, for appendix D of this part. (34) ASTM D4177–82 (Reapproved 1990), Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, for appendix D of this part. (35) ASTM D4239–85, Standard Test Methods for Sulfur in the Analysis Sample of Coal and Coke Using High Temperature Tube Furnace Combustion Methods, for appendix A of this part. (36) ASTM D4294–90, Standard Test Method for Sulfur in Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectroscopy, for appendices A and D of this part. (37) ASTM D4468–85 (Reapproved 1989), Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, for appendix D of this part. (38) ASTM D4840–99 (reapproved 2004), “Standard Guide for Sample Chain-of-Custody Procedures,” for appendix K of this part, section 7.2.9. (39) ASTM D4891–89, Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, for appendices D and F to this part. (40) ASTM D5291–92, Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, for appendices F and G to this part. (41) ASTM D5373–93, “Standard Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke,” for appendix G to this part. (42) ASTM D5504–94, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence, for appendix D of this part. (43) ASTM D6784–02, “Standard Test Method for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro Method),” for §75.22(a)(7) and (b)(5). (44) ASTM D6911–03, “Guide for Packaging and Shipping Environmental Samples for Laboratory Analysis,” for appendix K of this part, section 7.2.8. (b) The following materials are available for purchase from the American Society of Mechanical Engineers (ASME), 22 Law Drive, P.O. Box 2900, Fairfield, New Jersey 07007–2900: (1) ASME MFC–3M–1989 with September 1990 Errata, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, for appendix D of this part. (2) ASME MFC–4M–1986 (Reaffirmed 1990), Measurement of Gas Flow by Turbine Meters, for appendix D of this part. (3) ASME-MFC–5M–1985, Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, for appendix D of this part. (4) ASME MFC–6M–1987 with June 1987 Errata, Measurement of Fluid Flow in Pipes Using Vortex Flow Meters, for appendix D of this part. (5) ASME MFC–7M–1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles, for appendix D of this part. (6) ASME MFC–9M–1988 with December 1989 Errata, Measurement of Liquid Flow in Closed Conduits by Weighing Method, for appendix D of this part. (c) The following materials are available for purchase from the American National Standards Institute (ANSI), 25 West 43rd Street, Fourth Floor, New York, New York 10036: (1) ISO 8316: 1987(E) Measurement of Liquid Flow in closed Conduits-Method by Collection of the Liquid in a Volumetric Tank, for appendices D and E of this part. (2) [Reserved] (d) The following materials are available for purchase from the following address: Gas Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma 74143: (1) GPA Standard 2172–86, Calculation of Gross Heating Value, Relative Density and Compressibility Factor for Natural Gas Mixtures from Compositional Analysis, for appendices D, E, and F of this part. (2) GPA Standard 2261–90, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, for appendices D, F, and G of this part. (e) The following American Gas Association materials are available for purchase from the following address: ILI Infodisk, 610 Winters Avenue, Paramus, New Jersey 07652: (1) American Gas Association Report No. 3: Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty Guidelines (October 1990 Edition), Part 2: Specification and Installation Requirements (February 1991 Edition) and Part 3: Natural Gas Applications (August 1992 Edition), for appendices D and E of this part. (2) American Gas Association Transmission Measurement Committee Report No. 7: Measurement of Gas by Turbine Meters (Second Revision, April, 1996), for appendix D to this part. (f) The following materials are available for purchase from the following address: American Petroleum Institute, Publications Department, 1220 L Street NW, Washington, DC 20005–4070. (1) American Petroleum Institute (API) Petroleum Measurement Standards, Chapter 3, Tank Gauging: Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, December 1994; Section 1B, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, April 1992 (reaffirmed January 1997); Section 2, Standard Practice for Gauging Petroleum and Petroleum Products in Tank Cars, September 1995; Section 3, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Pressurized Storage Tanks by Automatic Tank Gauging, June 1996; Section 4, Standard Practice for Level Measurement of Liquid Hydrocarbons on Marine Vessels by Automatic Tank Gauging, April 1995; and Section 5, Standard Practice for Level Measurement of Light Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging, March 1997; for §75.19. (2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B, December 1961 (Reaffirmed August 1987, October 1992), for §75.19. (3) American Petroleum Institute (API) Section 2, “Conventional Pipe Provers,” Section 3, “Small Volume Provers,” and Section 5, “Master-Meter Provers,” from Chapter 4 of the Manual of Petroleum Measurement Standards, October 1988 (Reaffirmed 1993), for appendix D to this part. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26517, May 17, 1995; 61 FR 59157, Nov. 20, 1996; 63 FR 57499, Oct. 27, 1998; 64 FR 28589, May 26, 1999; 67 FR 40422, June 12, 2002; 70 FR 28678, May 18, 2005; 70 FR 51269, Aug. 30, 2005] Editorial Note: At 70 FR 28678, May 18, 2005, §75.6 was amended, however, certain amendments could not be incorporated due to inaccurate amendatory instruction.
(a) Primary Measurement Requirement. The owner or operator shall measure opacity, and all SO2, NOX, and CO2 emissions for each affected unit as follows: (1) To determine SO2 emissions, the owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a SO2 continuous emission monitoring system and a flow monitoring system with an automated data acquisition and handling system for measuring and recording SO2 concentration (in ppm), volumetric gas flow (in scfh), and SO2 mass emissions (in lb/hr) discharged to the atmosphere, except as provided in §§75.11 and 75.16 and subpart E of this part; (2) To determine NOX emissions, the owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a NOX-diluent continuous emission monitoring system (consisting of a NOX pollutant concentration monitor and an O2 or CO2 diluent gas monitor) with an automated data acquisition and handling system for measuring and recording NOX concentration (in ppm), O2 or CO2 concentration (in percent O2 or CO2) and NOX emission rate (in lb/mmBtu) discharged to the atmosphere, except as provided in §§75.12 and 75.17 and subpart E of this part. The owner or operator shall account for total NOX emissions, both NO and NO2, either by monitoring for both NO and NO2 or by monitoring for NO only and adjusting the emissions data to account for NO2; (3) The owner or operator shall determine CO2 emissions by using one of the following options, except as provided in §75.13 and subpart E of this part: (i) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a CO2 continuous emission monitoring system and a flow monitoring system with an automated data acquisition and handling system for measuring and recording CO2 concentration (in ppm or percent), volumetric gas flow (in scfh), and CO2 mass emissions (in tons/hr) discharged to the atmosphere; (ii) The owner or operator shall determine CO2 emissions based on the measured carbon content of the fuel and the procedures in appendix G of this part to estimate CO2 emissions (in ton/day) discharged to the atmosphere; or (iii) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a flow monitoring system and a CO2 continuous emission monitoring system that uses an O2 concentration monitor to determine CO2 emissions (according to the procedures in appendix F of this part) with an automated data acquisition and handling system for measuring and recording O2 concentration (in percent), CO2 concentration (in percent), volumetric gas flow (in scfh), and CO2 mass emissions (in tons/hr) discharged to the atmosphere; (4) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements in this part, a continuous opacity monitoring system with the automated data acquisition and handling system for measuring and recording the opacity of emissions (in percent opacity) discharged to the atmosphere, except as provided in §§75.14 and 75.18; and (5) A single certified flow monitoring system may be used to meet the requirements of paragraphs (a)(1) and (a)(3) of this section. A single certified diluent monitor may be used to meet the requirements of paragraphs (a)(2) and (a)(3) of this section. A single automated data acquisition and handling system may be used to meet the requirements of paragraphs (a)(1) through (a)(4) of this section. (b) Primary Equipment Performance Requirements. The owner or operator shall ensure that each continuous emission monitoring system required by this part meets the equipment, installation, and performance specifications in appendix A to this part; and is maintained according to the quality assurance and quality control procedures in appendix B to this part; and shall record SO2 and NOX emissions in the appropriate units of measurement (i.e., lb/hr for SO2 and lb/mmBtu for NOX). (c) Heat Input Rate Measurement Requirement. The owner or operator shall determine and record the heat input rate, in units of mmBtu/hr, to each affected unit for every hour or part of an hour any fuel is combusted following the procedures in appendix F to this part. (d) Primary equipment hourly operating requirements. The owner or operator shall ensure that all continuous emission and opacity monitoring systems required by this part are in operation and monitoring unit emissions or opacity at all times that the affected unit combusts any fuel except as provided in §75.11(e) and during periods of calibration, quality assurance, or preventive maintenance, performed pursuant to §75.21 and appendix B of this part, periods of repair, periods of backups of data from the data acquisition and handling system, or recertification performed pursuant to §75.20. The owner or operator shall also ensure, subject to the exceptions above in this paragraph, that all continuous opacity monitoring systems required by this part are in operation and monitoring opacity during the time following combustion when fans are still operating, unless fan operation is not required to be included under any other applicable Federal, State, or local regulation, or permit. The owner or operator shall ensure that the following requirements are met: (1) The owner or operator shall ensure that each continuous emission monitoring system is capable of completing a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-min interval. The owner or operator shall reduce all SO2 concentrations, volumetric flow, SO2 mass emissions, CO2 concentration, O2 concentration, CO2 mass emissions (if applicable), NOX concentration, NOX emission rate, and Hg concentration data collected by the monitors to hourly averages. Hourly averages shall be computed using at least one data point in each fifteen minute quadrant of an hour, where the unit combusted fuel during that quadrant of an hour. Notwithstanding this requirement, an hourly average may be computed from at least two data points separated by a minimum of 15 minutes (where the unit operates for more than one quadrant of an hour) if data are unavailable as a result of the performance of calibration, quality assurance, or preventive maintenance activities pursuant to §75.21 and appendix B of this part, or backups of data from the data acquisition and handling system, or recertification, pursuant to §75.20. The owner or operator shall use all valid measurements or data points collected during an hour to calculate the hourly averages. All data points collected during an hour shall be, to the extent practicable, evenly spaced over the hour. (2) The owner or operator shall ensure that each continuous opacity monitoring system is capable of completing a minimum of one cycle of sampling and analyzing for each successive 10-sec period and one cycle of data recording for each successive 6-min period. The owner or operator shall reduce all opacity data to 6-min averages calculated in accordance with the provisions of part 51, appendix M of this chapter, except where the applicable State implementation plan or operating permit requires a different averaging period, in which case the State requirement shall satisfy this Acid Rain Program requirement. (3) Failure of an SO2, CO2, or O2 emissions concentration monitor, NOX concentration monitor, Hg concentration monitor, flow monitor, moisture monitor, or NOX-diluent continuous emission monitoring system to acquire the minimum number of data points for calculation of an hourly average in paragraph (d)(1) of this section shall result in the failure to obtain a valid hour of data and the loss of such component data for the entire hour. For a NOX-diluent monitoring system, an hourly average NOX emission rate in lb/mmBtu is valid only if the minimum number of data points is acquired by both the NOX pollutant concentration monitor and the diluent monitor (O2 or CO2). For a moisture monitoring system consisting of one or more oxygen analyzers capable of measuring O2 on a wet-basis and a dry-basis, an hourly average percent moisture value is valid only if the minimum number of data points is acquired for both the wet-and dry-basis measurements. If a valid hour of data is not obtained, the owner or operator shall estimate and record emissions, moisture, or flow data for the missing hour by means of the automated data acquisition and handling system, in accordance with the applicable procedure for missing data substitution in subpart D of this part. (e) Optional backup monitor requirements. If the owner or operator chooses to use two or more continuous emission monitoring systems, each of which is capable of monitoring the same stack or duct at a specific affected unit, or group of units using a common stack, then the owner or operator shall designate one monitoring system as the primary monitoring system, and shall record this information in the monitoring plan, as provided for in §75.53. The owner or operator shall designate the other monitoring system(s) as backup monitoring system(s) in the monitoring plan. The backup monitoring system(s) shall be designated as redundant backup monitoring system(s), non-redundant backup monitoring system(s), or reference method backup system(s), as described in §75.20(d). When the certified primary monitoring system is operating and not out-of-control as defined in §75.24, only data from the certified primary monitoring system shall be reported as valid, quality-assured data. Thus, data from the backup monitoring system may be reported as valid, quality-assured data only when the backup is operating and not out-of-control as defined in §75.24 (or in the applicable reference method in appendix A of part 60 of this chapter) and when the certified primary monitoring system is not operating (or is operating but out-of-control). A particular monitor may be designated both as a certified primary monitor for one unit and as a certified redundant backup monitor for another unit. (f) Minimum measurement capability requirement. The owner or operator shall ensure that each continuous emission monitoring system is capable of accurately measuring, recording, and reporting data, and shall not incur an exceedance of the full scale range, except as provided in sections 2.1.1.5, 2.1.2.5, and 2.1.4.3 of appendix A to this part. (g) Minimum recording and recordkeeping requirements. The owner or operator shall record and the designated representative shall report the hourly, daily, quarterly, and annual information collected under the requirements of this part as specified in subparts F and G of this part. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26519, May 17, 1995; 64 FR 28590, May 26, 1999; 67 FR 40422, June 12, 2002; 70 FR 28678, May 18, 2005] (a) Coal-fired units. The owner or operator shall meet the general operating requirements in §75.10 for an SO2 continuous emission monitoring system and a flow monitoring system for each affected coal-fired unit while the unit is combusting coal and/or any other fuel, except as provided in paragraph (e) of this section, in §75.16, and in subpart E of this part. During hours in which only gaseous fuel is combusted in the unit, the owner or operator shall comply with the applicable provisions of paragraph (e)(1), (e)(2), or (e)(3) of this section. (b) Moisture correction. Where SO2 concentration is measured on a dry basis, the owner or operator shall either: (1) Report the appropriate fuel-specific default moisture value for each unit operating hour, selected from among the following: 3.0%, for anthracite coal; 6.0% for bituminous coal; 8.0% for sub-bituminous coal; 11.0% for lignite coal; 13.0% for wood; or (2) Install, operate, maintain, and quality assure a continuous moisture monitoring system for measuring and recording the moisture content of the flue gases, in order to correct the measured hourly volumetric flow rates for moisture when calculating SO2 mass emissions (in lb/hr) using the procedures in appendix F to this part. The following continuous moisture monitoring systems are acceptable: a continuous moisture sensor; an oxygen analyzer (or analyzers) capable of measuring O2 both on a wet basis and on a dry basis; or a stack temperature sensor and a moisture look-up table, i.e., a psychrometric chart (for saturated gas streams following wet scrubbers or other demonstrably saturated gas streams, only). The moisture monitoring system shall include as a component the automated data acquisition and handling system (DAHS) for recording and reporting both the raw data (e.g., hourly average wet-and dry-basis O2 values) and the hourly average values of the stack gas moisture content derived from those data. When a moisture look-up table is used, the moisture monitoring system shall be represented as a single component, the certified DAHS, in the monitoring plan for the unit or common stack. (c) Unit with no location for a flow monitor meeting siting requirements. Where no location exists that satisfies the minimum physical siting criteria in appendix A to this part for installation of a flow monitor in either the stack or the ducts serving an affected unit or installation of a flow monitor in either the stack or ducts is demonstrated to the satisfaction of the Administrator to be technically infeasible, either: (1) The designated representative shall petition the Administrator for an alternative method for monitoring volumetric flow in accordance with §75.66; or (2) The owner or operator shall construct a new stack or modify existing ductwork to accommodate the installation of a flow monitor, and the designated representative shall petition the Administrator for an extension of the required certification date given in §75.4 and approval of an interim alternative flow monitoring methodology in accordance with §75.66. The Administrator may grant existing Phase I affected units an extension to January 1, 1995, and existing Phase II affected units an extension to January 1, 1996 for the submission of the certification application for the purpose of constructing a new stack or making substantial modifications to ductwork for installation of a flow monitor; or (3) The owner or operator shall install a flow monitor in any existing location in the stack or ducts serving the affected unit at which the monitor can achieve the performance specifications of this part. (d) Gas-fired and oil-fired units. 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). (e) Units with SO2 continuous emission monitoring systems during the combustion of gaseous fuel. The owner or operator of an affected unit with an SO2 continuous emission monitoring system shall, during any hour in which the unit combusts only gaseous fuel, determine SO2 emissions in accordance with paragraph (e)(1), (e)(2) or (e)(3) of this section, as applicable. (1) If the gaseous fuel meets the definition of “pipeline natural gas” or “natural gas” in §72.2 of this chapter, the owner or operator may, in lieu of operating and recording data from the SO2 monitoring system, determine SO2 emissions by using Equation F–23 in appendix F to this part. Substitute into Equation F–23 the hourly heat input, calculated using a certified flow monitoring system and a certified diluent monitor (according to the applicable equation in section 5.2 of appendix F to this part), in conjunction with the appropriate default SO2 emission rate from section 2.3.1.1 or 2.3.2.1.1 of appendix D to this part. When this option is chosen, the owner or operator shall perform the necessary data acquisition and handling system tests under §75.20(c), and shall meet all quality control and quality assurance requirements in appendix B to this part for the flow monitor and the diluent monitor. (2) The owner or operator may, in lieu of operating and recording data from the SO2 monitoring system, determine SO2 emissions by certifying an excepted monitoring system in accordance with §75.20 and appendix D to this part, following the applicable fuel sampling and analysis procedures in section 2.3 of appendix D to this part, meeting the recordkeeping requirements of §75.58, and meeting all quality control and quality assurance requirements for fuel flowmeters in appendix D to this part. If this compliance option is selected, the hourly unit heat input rate reported under §75.57(b)(5), shall be determined using a certified flow monitoring system and a certified diluent monitor, in accordance with the procedures in section 5.2 of appendix F to this part. The flow monitor and diluent monitor shall meet all of the applicable quality control and quality assurance requirements of appendix B to this part. (3) The owner or operator may determine SO2 mass emissions by using a certified SO2 continuous monitoring system, in conjunction with a certified flow rate monitoring system. However, if the unit burns any gaseous fuel that is very low sulfur fuel (as defined in §72.2 of this chapter), the SO2 monitoring system shall meet the following quality assurance provisions when the very low sulfur fuel is combusted: (i) When conducting the daily calibration error tests of the SO2 monitoring system, as required by section 2.1.1 in appendix B of this part, the zero-level calibration gas shall have an SO2 concentration of 0.0 percent of span. This restriction does not apply if gaseous fuel is burned in the affected unit only during unit startup. (ii) EPA recommends that the calibration response of the SO2 monitoring system be adjusted, either automatically or manually, in accordance with the procedures for routine calibration adjustments in section 2.1.3 of appendix B to this part, whenever the zero-level calibration response during a required daily calibration error test exceeds the applicable performance specification of the instrument in section 3.1 of appendix A to this part (i.e., ±2.5 percent of the span value or ±5 ppm, whichever is less restrictive). (iii) Any bias-adjusted hourly average SO2 concentration of less than 2.0 ppm recorded by the SO2 monitoring system shall be adjusted to a default value of 2.0 ppm, for reporting purposes. Such adjusted hourly averages shall be considered to be quality-assured data, provided that the monitoring system is operating and is not out-of-control with respect to any of the quality assurance tests required by appendix B of this part (i.e., daily calibration error, linearity and relative accuracy test audit). (iv) In accordance with the requirements of section 2.1.1.2 of appendix A to this part, for units that sometimes burn gaseous fuel that is very low sulfur fuel (as defined in §72.2 of this chapter) and at other times burn higher sulfur fuel(s) such as coal or oil, a second low-scale SO2 measurement range is not required when the very low sulfur gaseous fuel is combusted. For units that burn only gaseous fuel that is very low sulfur fuel and burn no other type(s) of fuel(s), the owner or operator shall set the span of the SO2 monitoring system to a value no greater than 200 ppm. (f) Other units. The owner or operator of an affected unit that combusts wood, refuse, or other material in addition to oil or gas shall comply with the monitoring provisions for coal-fired units specified in paragraph (a) of this section. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26520, 26566, May 17, 1995; 61 FR 59157, Nov. 20, 1996; 63 FR 57499, Oct. 27, 1998; 64 FR 28590, May 26, 1999; 67 FR 40423, June 12, 2002] (a) Coal-fired units, gas-fired nonpeaking units or oil-fired nonpeaking units. The owner or operator shall meet the general operating requirements in §75.10 of this part for a NOX continuous emission monitoring system (CEMS) for each affected coal-fired unit, gas-fired nonpeaking unit, or oil-fired nonpeaking unit, except as provided in paragraph (d) of this section, §75.17, and subpart E of this part. The diluent gas monitor in the NOX-diluent CEMS may measure either O2 or CO2 concentration in the flue gases. (b) Moisture correction. If a correction for the stack gas moisture content is needed to properly calculate the NOX emission rate in lb/mmBtu, e.g., if the NOX pollutant concentration monitor measures on a different moisture basis from the diluent monitor, the owner or operator shall either report a fuel-specific default moisture value for each unit operating hour, as provided in §75.11(b)(1), or shall install, operate, maintain, and quality assure a continuous moisture monitoring system, as defined in §75.11(b)(2). Notwithstanding this requirement, if Equation 19–3, 19–4 or 19–8 in Method 19 in appendix A to part 60 of this chapter is used to measure NOX emission rate, the following fuel-specific default moisture percentages shall be used in lieu of the default values specified in §75.11(b)(1): 5.0%, for anthracite coal; 8.0% for bituminous coal; 12.0% for sub-bituminous coal; 13.0% for lignite coal; and 15.0% for wood. (c) Determination of NOX emission rate. The owner or operator shall calculate hourly, quarterly, and annual NOX emission rates (in lb/mmBtu) by combining the NOX concentration (in ppm), diluent concentration (in percent O2 or CO2), and percent moisture (if applicable) measurements according to the procedures in appendix F to this part. (d) Gas-fired peaking units or oil-fired peaking units. 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. (e) Low mass emissions units. Notwithstanding the requirements of paragraphs (a) and (d) of this section, the owner or operator of an affected unit that qualifies as a low mass emissions unit under §75.19(a) and (b) shall comply with one of the following: (1) Meet the general operating requirements in §75.10 for a NOX continuous emission monitoring system; (2) Meet the requirements specified in paragraph (d)(2) of this section for using the excepted monitoring procedures in appendix E to this part, if applicable; or (3) Use the low mass emissions excepted methodology in §75.19(c) for estimating hourly NOX emission rate and hourly NOX mass emissions, if applicable under §75.19(a) and (b). (f) Other units. The owner or operator of an affected unit that combusts wood, refuse, or other material in addition to oil or gas shall comply with the monitoring provisions specified in paragraph (a) of this section. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26520, May 17, 1995; 63 FR 57499, Oct. 27, 1998; 64 FR 28591, May 26, 1999; 67 FR 40423, June 12, 2002] (a) CO (b) Determination of CO (c) Determination of CO (d) Determination of CO (1) Meet the general operating requirements in §75.10 for a CO2 continuous emission monitoring system and flow monitoring system; (2) Meet the requirements specified in paragraph (b) or (c) of this section for use of the methods in appendix G or F to this part, respectively; or (3) Use the low mass emissions excepted methodology in §75.19(c) for estimating hourly CO2 mass emissions, if applicable under §75.19(a) and (b). [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26521, May 17, 1995; 63 FR 57499, Oct. 27, 1998; 64 FR 28591, May 26, 1999; 67 FR 40423, June 12, 2002] (a) Coal-fired units and oil-fired units. The owner or operator shall meet the general operating provisions in §75.10 of this part for a continuous opacity monitoring system for each affected coal-fired or oil-fired unit, except as provided in paragraphs (b), (c), and (d) of this section and in §75.18. Each continuous opacity monitoring system shall meet the design, installation, equipment, and performance specifications in Performance Specification 1 in appendix B to part 60 of this chapter. Any continuous opacity monitoring system previously certified to meet Performance Specification 1 shall be deemed certified for the purposes of this part. (b) Unit with wet flue gas pollution control system. If the owner or operator can demonstrate that condensed water is present in the exhaust flue gas stream and would impede the accuracy of opacity measurements, then the owner or operator of an affected unit equipped with a wet flue gas pollution control system for SO2 emissions or particulates is exempt from the opacity monitoring requirements of this part. (c) Gas-fired units. 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. (d) Diesel-fired units and dual-fuel reciprocating engine units. The owner or operator of an affected diesel-fired unit or a dual-fuel reciprocating engine unit is exempt from the opacity monitoring requirements of this part. [58 FR 3701, Jan. 11, 1993, as amended at 61 FR 25581, May 22, 1996] For an affected coal-fired unit under a State or Federal Hg mass emission reduction program that adopts the provisions of subpart I of this part, if the owner or operator elects to use sorbent trap monitoring systems (as defined in §72.2 of this chapter) to quantify Hg mass emissions, the guidelines in paragraphs (a) through (j) of this section shall be followed for this excepted monitoring methodology: (a) For each sorbent trap monitoring system (whether primary or redundant backup), the use of paired sorbent traps, as described in appendix K to this part, is required; (b) Each sorbent trap shall have both a main section, a backup section, and a third section to allow spiking with a calibration gas of known Hg concentration, as described in appendix K to this part; (c) A certified flow monitoring system is required; (d) Correction for stack gas moisture content is required, and in some cases, a certified O2 or CO2 monitoring system is required (see §75.81(a)(4)); (e) Each sorbent trap monitoring system shall be installed and operated in accordance with appendix K to this part. The automated data acquisition and handling system shall ensure that the sampling rate is proportional to the stack gas volumetric flow rate. (f) At the beginning and end of each sample collection period, and at least once in each unit operating hour during the collection period, the dry gas meter reading shall be recorded. (g) After each sample collection period, the mass of Hg adsorbed in each sorbent trap (in all three sections) shall be determined according to the applicable procedures in appendix K to this part. (h) The hourly Hg mass emissions for each collection period are determined using the results of the analyses in conjunction with contemporaneous hourly data recorded by a certified stack flow monitor, corrected for the stack gas moisture content. For each pair of sorbent traps analyzed, the average of the two Hg concentrations shall be used for reporting purposes under §75.84(f). Notwithstanding this requirement, if, due to circumstances beyond the control of the owner or operator, one of the paired traps is accidentally lost, damaged, or broken and cannot be analyzed, the results of the analysis of the other trap, if valid, may be used for reporting purposes. (i) All unit operating hours for which valid Hg concentration data are obtained with the primary sorbent trap monitoring system (as verified using the quality assurance procedures in appendix K to this part) shall be reported in the electronic quarterly report under §75.84(f). For hours in which data from the primary monitoring system are invalid, the owner or operator may report valid Hg concentration data from a certified redundant backup CEMS or sorbent trap monitoring system or from an applicable reference method under §75.22. If no quality-assured Hg concentration are available for a particular hour, the owner or operator shall report the appropriate substitute data value in accordance with §75.39. (j) Initial certification requirements and additional quality-assurance requirements for the sorbent trap monitoring systems are found in §75.20(c)(9), in section 6.5.7 of appendix A to this part, in sections 1.5 and 2.3 of appendix B to this part, and in appendix K to this part. [70 FR 28678, May 18, 2005] (a) [Reserved] (b) Common stack procedures. The following procedures shall be used when more than one unit uses a common stack: (1) Unit utilizing common stack with other affected unit(s). When a Phase I or Phase II affected unit utilizes a common stack with one or more other Phase I or Phase II affected units, but no nonaffected units, the owner or operator shall either: (i) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in the duct to the common stack from each affected unit; or (ii) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in the common stack; and (A) Combine emissions for the affected units for recordkeeping and compliance purposes; or (B) Provide information satisfactory to the Administrator on methods for apportioning SO2 mass emissions measured in the common stack to each of the Phase I and Phase II affected units. The designated representative shall provide the information to the Administrator through a petition submitted under §75.66. The Administrator may approve such substitute methods for apportioning SO2 mass emissions measured in a common stack whenever the method ensures complete and accurate accounting of all emissions regulated under this part. (2) Unit utilizing common stack with nonaffected unit(s). When one or more Phase I or Phase II affected units utilizes a common stack with one or more nonaffected units, the owner or operator shall either: (i) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in the duct to the common stack from each Phase I and Phase II unit; or (ii) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in the common stack; and (A) Designate the nonaffected units as opt-in units in accordance with part 74 of this chapter and combine emissions for recordkeeping and compliance purposes; or (B) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in the duct from each nonaffected unit; determine SO2 mass emissions from the affected units as the difference between SO2 mass emissions measured in the common stack and SO2 mass emissions measured in the ducts of the nonaffected units, not to be reported as an hourly average value less than zero; combine emissions for the Phase I and Phase II affected units for recordkeeping and compliance purposes; and calculate and report SO2 mass emissions from the Phase I and Phase II affected units, pursuant to an approach approved by the Administrator, such that these emissions are not underestimated; or (C) Record the combined emissions from all units as the combined SO2 mass emissions for the Phase I and Phase II affected units for recordkeeping and compliance purposes; or (D) Petition through the designated representative and provide information satisfactory to the Administrator on methods for apportioning SO2 mass emissions measured in the common stack to each of the units using the common stack and on reporting the SO2 mass emissions. The Administrator may approve such demonstrated substitute methods for apportioning and reporting SO2 mass emissions measured in a common stack whenever the demonstration ensures that there is a complete and accurate accounting of all emissions regulated under this part and, in particular, that the emissions from any affected unit are not underestimated. (c) Unit with bypass stack. Whenever any portion of the flue gases from an affected unit can be routed through a bypass stack so as to avoid the installed SO2 continuous emission monitoring system and flow monitoring system, the owner or operator shall either: (1) Install, certify, operate, and maintain separate SO2 continuous emission monitoring systems and flow monitoring systems on the main stack and the bypass stack and calculate SO2 mass emissions for the unit as the sum of the SO2 mass emissions measured at the two stacks; or (2) Monitor SO2 mass emissions at the main stack using SO2 and flow rate monitoring systems and measure SO2 mass emissions at the bypass stack using the reference methods in §75.22(b) for SO2 and flow rate and calculate SO2 mass emissions for the unit as the sum of the emissions recorded by the installed monitoring systems on the main stack and the emissions measured by the reference method monitoring systems; or (3) Install, certify, operate, and maintain SO2 and flow rate monitoring systems only on the main stack. If this option is chosen, report the following values for each hour during which emissions pass through the bypass stack: the maximum potential concentration of SO2 as determined under section 2.1.1.1 of appendix A to this part (or, if available, the SO2 concentration measured by a certified monitor located at the control device inlet may be reported instead), and the hourly volumetric flow rate value that would be substituted for the flow monitor installed on the main stack or flue under the missing data procedures in subpart D of this part if data from the flow monitor installed on the main stack or flue were missing for the hour. The maximum potential SO2 concentration may be specific to the type of fuel combusted in the unit during the bypass (see §75.33(b)(5)). The option in this paragraph, (c)(3), may only be used if use of the bypass stack is limited to unit startup, emergency situations (e.g., malfunction of a flue gas desulfurization system), and periods of routine maintenance of the flue gas desulfurization system or maintenance on the main stack. 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 SO2 or any other parameter that is monitored only at the main stack. Calculate SO2 mass emissions for the unit as the sum of the emissions calculated with the substitute values and the emissions recorded by the SO2 and flow monitoring systems installed on the main stack. (d) Unit with multiple stacks or ducts. When the flue gases from an affected unit utilize two or more ducts feeding into two or more stacks (that may include flue gases from other affected or nonaffected units), or when the flue gases utilize two or more ducts feeding into a single stack and the owner or operator chooses to monitor in the ducts rather than the stack, the owner or operator shall either: (1) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in each duct feeding into the stack or stacks and determine SO2 mass emissions from each affected unit as the sum of the SO2 mass emissions recorded for each duct; or (2) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in each stack. Determine SO2 mass emissions from each affected unit as the sum of the SO2 mass emissions recorded for each stack. Notwithstanding the prior sentence, if another unit also exhausts flue gases to one or more of the stacks, the owner or operator shall also comply with the applicable common stack requirements of this section to determine and record SO2 mass emissions from the units using that stack and shall calculate and report SO2 mass emissions from the affected units and stacks, pursuant to an approach approved by the Administrator, such that these emissions are not underestimated. (e) Heat input rate. The owner or operator of an affected unit using a common stack, bypass stack, or multiple stacks shall account for heat input rate according to the following: (1) The owner or operator of an affected unit using a common stack, bypass stack, or multiple stack with a diluent monitor and a flow monitor on each stack may use the flow rate and diluent monitors to determine the heat input rate for the affected unit, using the procedures specified in paragraphs (b) through (d) of this section, except that the term “heat input rate” shall apply rather than “SO2 mass emissions” or “emissions” and the phrase “a diluent monitor and a flow monitor” shall apply rather than “SO2 continuous emission monitoring system and flow monitoring system.” The applicable equation in appendix F to this part shall be used to calculate the heat input rate from the hourly flow rate, diluent monitor measurements, and (if the equation in appendix F requires a correction for the stack gas moisture content) hourly moisture measurements. Notwithstanding the options for combining heat input rate in paragraph (b)(1)(ii) and (b)(2)(ii) of this section, the owner or operator of an affected unit with a diluent monitor and a flow monitor installed on a common stack to determine the combined heat input rate at the common stack shall also determine and report heat input to each individual unit, according to paragraph (e)(3) of this section. (2) In the event that an owner or operator of a unit with a bypass stack does not install and certify a diluent monitor and flow monitoring system in a bypass stack, the owner or operator shall determine total heat input rate to the unit for each unit operating hour during which the bypass stack is used according to the missing data provisions for heat input rate under §75.36 or the procedures for calculating heat input rate from fuel sampling and analysis in section 5.5 of appendix F to this part. (3) The owner or operator of an affected unit with a diluent monitor and a flow monitor installed on a common stack to determine heat input rate at the common stack may choose to apportion the heat input rate from the common stack to each affected unit utilizing the common stack by using either of the following two methods, provided that all of the units utilizing the common stack are combusting fuel with the same F-factor found in section 3 of appendix F of this part. The heat input rate may be apportioned either by using the ratio of load (in MWe) for each individual unit to the total load for all units utilizing the common stack or by using the ratio of steam flow (in 1000 lb/hr) for each individual unit to the total steam flow for all units utilizing the common stack, in conjunction with the appropriate unit and stack operating times. If using either of these apportionment methods, the owner or operator shall apportion according to section 5.6 of appendix F to this part. (4) Notwithstanding paragraph (e)(1) of this section, any affected unit that is using the procedures in this part to meet the monitoring and reporting requirements of a State or federal NOX mass emission reduction program must also meet the requirements for monitoring heat input rate in §§75.71, 75.72 and 75.75. [60 FR 26522, May 17, 1995, as amended at 61 FR 25582, May 22, 1996; 61 FR 59158, Nov. 20, 1996; 64 FR 28591, May 26, 1999; 67 FR 40423, June 12, 2002; 67 FR 53504, Aug. 16, 2002] Notwithstanding the provisions of paragraphs (a), (b), (c), and (d) of this section, the owner or operator of an affected unit that is using the procedures in this part to meet the monitoring and reporting requirements of a State or federal NOX mass emission reduction program must also meet the provisions for monitoring NOX emission rate in §§75.71 and 75.72. (a) Unit utilizing common stack with other affected unit(s). When an affected unit utilizes a common stack with one or more affected units, but no nonaffected units, the owner or operator shall either: (1) Install, certify, operate, and maintain a NOX continuous emission monitoring system in the duct to the common stack from each affected unit; or (2) Install, certify, operate, and maintain a NOX continuous emission monitoring system in the common stack and follow the appropriate procedure in paragraphs (a)(2) (i) through (iii) of this section, depending on whether or not the units are required to comply with a NOX emission limitation (in lb/mmBtu, annual average basis) pursuant to section 407(b) of the Act (referred to hereafter as “NOX emission limitation”). (i) When each of the affected units has a NOX emission limitation, the designated representative shall submit a compliance plan to the Administrator that indicates: (A) Each unit will comply with the most stringent NOX emission limitation of any unit utilizing the common stack; or (B) Each unit will comply with the applicable NOX emission limitation by averaging its emissions with the other unit(s) utilizing the common stack, pursuant to the emissions averaging plan submitted under part 76 of this chapter; or (C) Each unit's compliance with the applicable NOX emission limit will be determined by a method satisfactory to the Administrator for apportioning to each of the units the combined NOX emission rate (in lb/mmBtu) measured in the common stack and for reporting the NOX emission rate, as provided in a petition submitted by the designated representative. The Administrator may approve such demonstrated substitute methods for apportioning and reporting NOX emission rate measured in a common stack whenever the demonstration ensures that there is a complete and accurate estimation of all emissions regulated under this part and, in particular, that the emissions from any unit with a NOX emission limitation are not underestimated. (ii) When none of the affected units has a NOX emission limitation, the owner or operator and the designated representative have no additional obligations pursuant to section 407 of the Act and may record and report a combined NOX emission rate (in lb/mmBtu) for the affected units utilizing the common stack. (iii) When at least one of the affected units has a NOX emission limitation and at least one of the affected units does not have a NOX emission limitation, the owner or operator shall either: (A) Install, certify, operate, and maintain NOX and diluent monitors in the ducts from the affected units; or (B) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined NOX emission rate (in lb/mmBtu) measured in the common stack on each of the units. The Administrator may approve such demonstrated substitute methods for apportioning the combined NOX emission rate measured in a common stack whenever the demonstration ensures complete and accurate estimation of all emissions regulated under this part. (b) Unit utilizing common stack with nonaffected unit(s). When one or more affected units utilizes a common stack with one or more nonaffected units, the owner or operator shall either: (1) Install, certify, operate, and maintain a NOX-diluent continuous emission monitoring system in the duct from each affected unit; or (2) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined NOX emission rate (in lb/mmBtu) measured in the common stack for each of the units. The Administrator may approve such demonstrated substitute methods for apportioning the combined NOX emission rate measured in a common stack whenever the demonstration ensures complete and accurate estimation of all emissions regulated under this part. (c) Unit with multiple stacks or ducts. When the flue gases from an affected unit discharge to the atmosphere through two or more stacks or when flue gases from an affected unit utilize two or more ducts feeding into a single stack and the owner or operator chooses to monitor in the ducts rather than the stack, the owner or operator shall monitor the NOX emission rate in a way that is representative of each affected unit. Where another unit also exhausts flue gases to one or more of the stacks where monitoring systems are installed, the owner or operator shall also comply with the applicable common stack monitoring requirements of this section. The owner or operator shall either: (1) Install, certify, operate, and maintain a NOX-diluent continuous emission monitoring system and a flow monitoring system in each stack or duct and determine the NOX emission rate for the unit as the Btu-weighted average of the NOX emission rates measured in the stacks or ducts using the heat input estimation procedures in appendix F to this part. Alternatively, for units that are eligible to use the procedures of appendix D to this part, the owner or operator may monitor heat input and NOX emission rate at the unit level, in lieu of installing flow monitors on each stack or duct. If this alternative unit-level monitoring is performed, report, for each unit operating hour, the highest emission rate measured by any of the NOX-diluent monitoring systems installed on the individual stacks or ducts as the hourly NOX emission rate for the unit, and report the hourly unit heat input as determined under appendix D to this part. Also, when this alternative unit-level monitoring is performed, the applicable NOX missing data procedures in §§75.31 or 75.33 shall be used for each unit operating hour in which a quality-assured NOX emission rate is not obtained for one or more of the individual stacks or ducts; or (2) Provided that the products of combustion are well-mixed, install, certify, operate, and maintain a NOX continuous emission monitoring system in one stack or duct from the affected unit and record the monitored value as the NOX emission rate for the unit. The owner or operator shall account for NOX emissions from the unit during all times when the unit combusts fuel. Therefore, this option shall not be used if the monitored stack or duct can be bypassed (e.g., by using dampers). Follow the procedure in §75.17(d) for units with bypass stacks. Further, this option shall not be used unless the monitored NOX emission rate truly represents the NOX emissions discharged to the atmosphere (e.g., the option is disallowed if there are any additional NOX emission controls downstream of the monitored location). (d) Unit with a main stack and bypass stack configuration. For an affected unit with a discharge configuration consisting of a main stack and a bypass stack, the owner or operator shall either: (1) Follow the procedures in paragraph (c)(1) of this section; or (2) Install, certify, operate, and maintain a NOX-diluent CEMS only on the main stack. 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, 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)). [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26523, May 17, 1995; 63 FR 57499, Oct. 27, 1998; 64 FR 28592, May 26, 1999; 67 FR 40424, June 12, 2002] (a) Unit using common stack.When an affected unit utilizes a common stack with other affected units or nonaffected units, the owner or operator shall comply with the applicable monitoring provision in this paragraph, as determined by existing Federal, State, or local opacity regulations. (1) Where another regulation requires the installation of a continuous opacity monitoring system upon each affected unit, the owner or operator shall install, certify, operate, and maintain a continuous opacity monitoring system meeting Performance Specification 1 in appendix B to part 60 of this chapter (referred to hereafter as a “certified continuous opacity monitoring system”) upon each unit. (2) Where another regulation does not require the installation of a continuous opacity monitoring system upon each affected unit, and where the affected source is not subject to any existing Federal, State, or local opacity regulations, the owner or operator shall install, certify, operate, and maintain a certified continuous opacity monitoring system upon each common stack for the combined effluent. (b) Unit using bypass stack. Where any portion of the flue gases from an affected unit can be routed so as to bypass the installed continuous opacity monitoring system, the owner or operator shall install, certify, operate, and maintain a certified continuous opacity monitoring system on each bypass stack flue, duct, or stack gas stream unless either: (1) An applicable Federal, State, or local opacity regulation or permit exempts the unit from a requirement to install a continuous opacity monitoring system in the bypass stack; or (2) A continuous opacity monitoring system is already installed and certified at the inlet of the add-on emissions controls. (3) The owner or operator monitors opacity using method 9 of appendix A of part 60 of this chapter whenever emissions pass through the bypass stack. Method 9 shall be used in accordance with the applicable State regulations. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26524, May 17, 1995; 60 FR 40296, Aug. 8, 1995; 61 FR 59158, Nov. 20, 1996] (a) Applicability and qualification. (1) For units that meet the requirements of this paragraph (a)(1) and paragraphs (a)(2) and (b) of this section, the low mass emissions excepted methodology in paragraph (c) of this section may be used in lieu of continuous emission monitoring systems or, if applicable, in lieu of excepted methods under appendix D or E to this part, for the purpose of determining hourly heat input and hourly NOX, SO2, and CO2 mass emissions under this part. (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. (ii) Each qualifying LME unit must start using the low mass emissions excepted methodology as follows: (A) For a unit that reports emission data on a year-round basis, begin using the methodology in the first unit operating hour in the calendar year designated in the certification application as the first year that the methodology will be used; or (B) For a unit that is subject to Subpart H of this part and that reports only during the ozone season according to §75.74(c), begin using the methodology in the first unit operating hour in the ozone season designated in the certification application as the first ozone season that the methodology will be used. (C) For a new or newly-affected unit, see paragraph (b)(4) of this section for additional guidance. (2) A unit may initially qualify as a low mass emissions unit if the designated representative submits a certification application to use the LME methodology (as described in §75.63(a)(1)(ii) and in this paragraph, (a)(2)) and the Administrator (or permitting authority, as applicable) certifies the use of such methodology. The certification application shall be submitted no later than 45 days prior to the date on which use of the low mass emissions methodology is expected to commence, and the application must contain: (i) A statement identifying the projected date on which the LME methodology will first be used. The projected commencement date shall be consistent with paragraphs (a)(1)(ii) and (b)(4) of this section, as applicable; and (ii) Either: (A) Actual SO2 and/or NOX mass emissions data (as applicable) for each of the three calendar years (or ozone seasons) prior to the calendar year in which the certification application is submitted demonstrating to the satisfaction of the Administrator or (if applicable) the permitting authority, that the unit emitted less than the applicable number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section. For the purposes of this paragraph, (a)(2)(ii)(A), the required actual SO2 or NOX mass emissions for each qualifying year or ozone season shall be determined using the SO2, NOX and heat input data reported to the Administrator in the electronic quarterly reports required under §75.64 or under the Ozone Transport Commission (OTC) NOX Budget Trading Program. Notwithstanding this requirement, in the absence of such electronic reports, an estimate of the actual emissions for each of the previous three years (or ozone seasons) shall be provided, using either the maximum rated heat input methodology described in paragraph (c)(3)(i) of this section or procedures consistent with the long term fuel flow heat input methodology described in paragraph (c)(3)(ii) of this section, in conjunction with the appropriate SO2 or NOX emission rate from paragraph (c)(1)(i) of this section for SO2, and paragraph (c)(1)(ii) or (c)(1)(iv) of this section for NOX. Alternatively, the initial estimate of the NOX emission rate may be based on historical emission test data that is representative of operation at normal load or historical data from a CEMS certified under part 60 of this chapter or under a state CEM program; or (B) When the three full years (or ozone seasons) of actual SO2 and NOX mass emissions data (or reliable estimates thereof) described under paragraph (a)(2)(ii)(A) of this section do not exist, the designated representative may submit an application to use the low mass emissions excepted methodology based upon a combination of actual historical SO2 and NOX mass emissions data and projected SO2 and NOX mass emissions, totaling three years (or ozone seasons). Except as provided in paragraph (a)(3) of this section, actual data must be used for any years (or ozone seasons) in which such data exists and projected data should be used for any remaining future years (or ozone seasons) needed to provide emissions data for three consecutive calender years (or ozone seasons). For example, if a unit commenced operation two years ago, the designated representative may submit actual, historical data for the previous two years and one year of projected emissions for the current calendar year or, for a new unit, the designated representative may submit three years of projected emissions, beginning with the current calendar year. Any actual or projected annual emissions must demonstrate to the satisfaction of the Administrator that the unit will emit less than the applicable number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section. Projected emissions shall be calculated using either the appropriate default emission rates from paragraphs (c)(1)(i) and (c)(1)(ii) of this section (or, alternatively for NOX, a conservative estimate of the NOX emission rate, as described in paragraph (a)(4) of this section), in conjunction with projections of unit operating hours or fuel type and fuel usage, according to one of the allowable calculation methodologies in paragraph (c) of this section; and (iii) A description of the methodology from paragraph (c) of this section that will be used to demonstrate on-going compliance under paragraph (b) of this section; and (iv) Appropriate documentation demonstrating that the unit is eligible to use projected emissions to qualify for LME status under paragraph (a)(3) of this section (if applicable). (3) In the following circumstances, projected emissions for a future year (or years) may be used in lieu of the actual emissions data from one (or more) of the three years (or ozone seasons) preceding the year of the certification application: (i) If the owner or operator takes an enforceable permit restriction on the number of annual or ozone season unit operating hours for the future year (or years), such that the unit will emit no more than the applicable number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section; or (ii) If the actual emissions for one (or more) of the three years (or ozone seasons) prior to the year of the certification application is not representative of the present and expected future emissions from the unit, because the owner or operator has recently installed emission controls on the unit. (4) When the owner or operator elects to demonstrate initial LME qualification and on-going compliance using a fuel-and-unit-specific NOX emission rate in accordance with paragraph (c)(1)(iv) of this section, there will be instances (e.g., for a new or newly-affected unit) where it is not possible to determine that NOX emission rate prior to submitting the certification application. In such cases, if the generic default NOX emission rates in Table LM–2 of this section are inappropriately high for the unit, the owner or operator may use a more representative, but conservatively high estimate of the expected NOX emission rate, for the purposes of the initial monitoring plan submittal and to calculate the unit's projected annual or ozone season emissions under paragraph (a)(2)(ii)(B) of this section. For example, the NOX emission rate could, as described in paragraph (a)(2)(ii)(A) of this section, be estimated using historical CEM data or historical emission test data that is representative of operation at normal load. The NOX emission limit specified in the operating permit for the unit could also be used to estimate the NOX emission rate (except for units equipped with SCR or SNCR), or, consistent with paragraph (c)(1)(iv)(C)(4) of this section, for a unit that uses SCR or SNCR to control NOX emissions, an estimated default NOX emission rate of 0.15 lb/mmBtu could be used. However, these estimated NOX emission rates may not be used for reporting purposes in the time period extending from the first hour in which the LME methodology is used to the date and hour on which the fuel-and-unit-specific NOX emission rate testing is completed. Rather, in that interval, the owner or operator shall either report the appropriate default NOX emission rate from Table LM–2, or shall report the maximum potential NOX emission rate, calculated in accordance with §72.2 of this chapter and section 2.1.2.1 of appendix A to this part. Then, beginning with the first unit operating hour after completion of the tests, the appropriate default NOX emission rate(s) obtained from the fuel-and-unit-specific testing shall be used for emissions reporting. (b) On-going qualification and disqualification. (1) Once a low mass emissions unit has qualified for and has started using the low mass emissions excepted methodology, an annual demonstration is required, showing that the 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. The calculation methodology used for the annual demonstration shall be the methodology described in the certification application under paragraph (a)(2)(iii) of this section. (2) If any low mass emissions unit fails to provide the required annual demonstration under paragraph (b)(1) of this section, such that the calculated cumulative emissions for the unit exceed the applicable number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section at the end of any calendar year or ozone season, then: (i) The low mass emissions unit shall be disqualified from using the low mass emissions excepted methodology; and (ii) The owner or operator of the low mass emissions unit shall install and certify monitoring systems that meet the requirements of §§75.11, 75.12, and 75.13, and shall report SO2 (Acid Rain Program units, only), NOX, and CO2 (Acid Rain Program units, only) emissions data and heat input data from such monitoring systems by December 31 of the calendar year following the year in which the unit exceeded the number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section; and (iii) If the required monitoring systems have not been installed and certified by the applicable deadline in paragraph (b)(2)(ii) of this section, the owner or operator shall report the following values for each unit operat
Title 40: Protection of Environment
PART 75—CONTINUOUS EMISSION MONITORING
Section Contents
§ 75.1 Purpose and scope.
§ 75.2 Applicability.
§ 75.3 General Acid Rain Program provisions.
§ 75.4 Compliance dates.
§ 75.5 Prohibitions.
§ 75.6 Incorporation by reference.
§§ 75.7-75.8 [Reserved]
§ 75.10 General operating requirements.
§ 75.11 Specific provisions for monitoring SO2 emissions (SO2 and flow monitors).
§ 75.12 Specific provisions for monitoring NO
§ 75.13 Specific provisions for monitoring CO2 emissions.
§ 75.14 Specific provisions for monitoring opacity.
§ 75.15 Special provisions for measuring Hg mass emissions using the excepted sorbent trap monitoring methodology.
§ 75.16 Special provisions for monitoring emissions from common, bypass, and multiple stacks for SO2 emissions and heat input determinations.
§ 75.17 Specific provisions for monitoring emissions from common, bypass, and multiple stacks for NO
§ 75.18 Specific provisions for monitoring emissions from common and by-pass stacks for opacity.
§ 75.19 Optional SO2, NO
§ 75.20 Initial certification and recertification procedures.
§ 75.21 Quality assurance and quality control requirements.
§ 75.22 Reference test methods.
§ 75.23 Alternatives to standards incorporated by reference.
§ 75.24 Out-of-control periods and adjustment for system bias.
§ 75.30 General provisions.
§ 75.31 Initial missing data procedures.
§ 75.32 Determination of monitor data availability for standard missing data procedures.
§ 75.33 Standard missing data procedures for SO2, NO
§ 75.34 Units with add-on emission controls.
§ 75.35 Missing data procedures for CO2.
§ 75.36 Missing data procedures for heat input rate determinations.
§ 75.37 Missing data procedures for moisture.
§ 75.38 Standard missing data procedures for Hg CEMS.
§ 75.39 Missing data procedures for sorbent trap monitoring systems.
§ 75.40 General demonstration requirements.
§ 75.41 Precision criteria.
§ 75.42 Reliability criteria.
§ 75.43 Accessibility criteria.
§ 75.44 Timeliness criteria.
§ 75.45 Daily quality assurance criteria.
§ 75.46 Missing data substitution criteria.
§ 75.47 Criteria for a class of affected units.
§ 75.48 Petition for an alternative monitoring system.
§§ 75.50-75.52 [Reserved]
§ 75.53 Monitoring plan.
§§ 75.54-75.56 [Reserved]
§ 75.57 General recordkeeping provisions.
§ 75.58 General recordkeeping provisions for specific situations.
§ 75.59 Certification, quality assurance, and quality control record provisions.
§ 75.60 General provisions.
§ 75.61 Notifications.
§ 75.62 Monitoring plan submittals.
§ 75.63 Initial certification or recertification application.
§ 75.64 Quarterly reports.
§ 75.65 Opacity reports.
§ 75.66 Petitions to the Administrator.
§ 75.67 Retired units petitions.
§ 75.70 NO
§ 75.71 Specific provisions for monitoring NO
§ 75.72 Determination of NO
§ 75.73 Recordkeeping and reporting.
§ 75.74 Annual and ozone season monitoring and reporting requirements.
§ 75.75 Additional ozone season calculation procedures for special circumstances.
§ 75.80 General provisions.
§ 75.81 Monitoring of Hg mass emissions and heat input at the unit level.
§ 75.82 Monitoring of Hg mass emissions and heat input at common and multiple stacks.
§ 75.83 Calculation of Hg mass emissions and heat input rate.
§ 75.84 Recordkeeping and reporting.
Appendix A to Part 75—Specifications and Test Procedures
Appendix B to Part 75—Quality Assurance and Quality Control Procedures
Appendix C to Part 75—Missing Data Estimation Procedures
Appendix D to Part 75—Optional SO2 Emissions Data Protocol for Gas-Fired and Oil-Fired Units
Appendix E to Part 75—Optional NOX Emissions Estimation Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units
Appendix F to Part 75—Conversion Procedures
Appendix G to Part 75—Determination of CO2 Emissions
Appendix H to Part 75—Revised Traceability Protocol No. 1 [Reserved]
Appendix I to Part 75—Optional F—Factor/Fuel Flow Method [Reserved]
Appendix J to Part 75—Compliance Dates for Revised Recordkeeping Requirements and Missing Data Procedures [Reserved]
Appendix K to Part 75—Quality Assurance and Operating Procedures for Sorbent Trap Monitoring Systems
Subpart A—General
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§ 75.1 Purpose and scope.
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§ 75.2 Applicability.
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§ 75.3 General Acid Rain Program provisions.
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§ 75.4 Compliance dates.
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§ 75.5 Prohibitions.
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§ 75.6 Incorporation by reference.
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§§ 75.7-75.8 [Reserved]
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Subpart B—Monitoring Provisions
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§ 75.10 General operating requirements.
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§ 75.11 Specific provisions for monitoring SO2 emissions (SO2 and flow monitors).
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§ 75.12 Specific provisions for monitoring NO
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§ 75.13 Specific provisions for monitoring CO2 emissions.
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§ 75.14 Specific provisions for monitoring opacity.
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§ 75.15 Special provisions for measuring Hg mass emissions using the excepted sorbent trap monitoring methodology.
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§ 75.16 Special provisions for monitoring emissions from common, bypass, and multiple stacks for SO2 emissions and heat input determinations.
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§ 75.17 Specific provisions for monitoring emissions from common, bypass, and multiple stacks for NO
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§ 75.18 Specific provisions for monitoring emissions from common and by-pass stacks for opacity.
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§ 75.19 Optional SO2, NO
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