PART 75—CONTINUOUS EMISSION MONITORING Authority: 42 U.S.C. 7401-7671q 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. Subpart A—General § 75.1 Purpose and scope. (a) Purpose. 2 X 2 X X (b) Scope. 2 X 2 2 (2) Statistical estimation procedures for missing data are included in appendix C to this part. Optional protocols for estimating SO 2 X 2 [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] § 75.2 Applicability. (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 SO 2 X (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 NO X [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; 76 FR 17306, Mar. 28, 2011] § 75.3 General Acid Rain Program provisions. 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. § 75.4 Compliance dates. (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 NO X X 2 X 2 (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 NO X (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 NO X (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 NO X 2 X 2 (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 SO 2 X 2 (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 NO X 2 X 2 (2) 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 SO 2 X 2 (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 NO X 2 X 2 (2) 180 calendar days after the date on which the unit becomes subject to the requirements of the Acid Rain Program, notice of which date shall be provided under subpart G of this part. (d) This paragraph (d) applies to affected units under the Acid Rain Program and to units subject to a State or Federal pollutant mass emissions reduction program that adopts the emission monitoring and reporting provisions of this part. In accordance with § 75.20, for an affected unit which, on the applicable compliance date, is either in long-term cold storage (as defined in § 72.2 of this chapter) or is shut down as the result of a planned outage or a forced outage, thereby preventing the required continuous monitoring system certification tests from being completed by the compliance date, the owner or operator shall provide notice of such unit storage or outage in accordance with § 75.61(a)(3) or § 75.61(a)(7), as applicable. For the planned and unplanned unit outages described in this paragraph (d), the owner or operator shall ensure that all of the continuous monitoring systems for SO 2 X 2 2 X 2 (1) The maximum potential concentration of SO 2 X 2 (2) The conditional data validation provisions of § 75.20(b)(3); or (3) Reference methods under § 75.22(b); or (4) Another procedure approved by the Administrator pursuant to a petition under § 75.66. (e) In accordance with § 75.20, if the owner or operator of an affected unit completes construction of a new stack or flue, or a flue gas desulfurization system or add-on NO X (1) Except as otherwise provided in paragraph (e)(3) of this section, the owner or operator shall ensure that all required certification and/or recertification and/or diagnostic tests of the monitoring systems required under this part ( i.e., 2 X 2 2 (i) For the event of construction of a new stack or flue, the date that emissions first exit to the atmosphere through the new stack or flue, notice of which date shall be provided under subpart G of this part; or (ii) For the event of installation of a flue gas desulfurization system or add-on NO X X (2) The owner or operator shall determine and report, as applicable, SO 2 X X 2 2 X (i) Quality-assured data recorded by a previously-certified monitoring system for which the event requires no additional testing; (ii) The applicable missing data substitution procedures under §§ 75.31 through 75.37; (iii) The conditional data validation procedures of § 75.20(b)(3), except that conditional data validation may, if necessary, be used for the entire window of time provided under paragraph (e)(1) of this section in lieu of the periods specified in § 75.20(b)(3)(iv); (iv) Reference methods under § 75.22(b); (v) For the event of installation of a flue gas desulfurization system or add-on NO X i.e., 2 X 2 X (vi) Another procedure approved by the Administrator pursuant to a petition under § 75.66. (3) If a particular project involves both the event of new stack or flue construction and the event of installation of a flue gas desulfurization system or add-on NO X (i) Complete all of the monitoring system certification and/or recertification and/or diagnostic testing requirements of both events within the window of time provided under paragraph (e)(1)(i) of this section; or (ii) Complete all of the monitoring system certification and/or recertification and/or diagnostic testing requirements of each event within the separate window of time applicable to such event provided under paragraph (e)(1) of this section. (4) For the project described in paragraph (e)(3) of this section, the emissions data from each CEMS installed on the new stack recorded in the interval of time starting on the date and hour on which emissions first exit to the atmosphere through the new stack and ending on the hour before the date and hour on which reagent is first injected into the control device may be reported as quality assured: (i) For the CEMS that includes the monitor that measures the pollutant being removed by the add-on emission controls ( i.e., 2 X (A) Only if the relative accuracy test audit (RATA) of the high measurement scale of the monitor is successfully completed either prior to the date and hour of the first injection of reagent into the emission control device, or after that date and hour during a period when the control device is not operating, but still within the window of time provided under paragraph (e)(1)(i) of this section, and the rest of the certification tests required under § 75.20(c) and section 6 of appendix A to this part for the high measurement scale of the monitor are successfully completed within the window of time provided under paragraph (e)(1)(i) of this section; (B) Beginning with: ( 1 ( 2 (ii) For a CEMS other than one addressed in paragraph (e)(4)(i) of this section: (A) Only if the relative accuracy test audit (RATA) of the CEMS is successfully completed either prior to the date and hour of the first injection of reagent into the emission control device, or after that date and hour during a period when the control device is not operating, but still within the window of time provided under paragraph (e)(1)(i) of this section, and the rest of the certification tests required under § 75.20(c) and section 6 of appendix A to this part for the CEMS are successfully completed within the window of time provided under paragraph (e)(1)(i) of this section; (B) Beginning with: ( 1 ( 2 see (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 NO X (1) The fuel-specific maximum potential NO X (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 SO 2 (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 SO 2 2 X X X (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 SO 2 X 2 (1) The maximum potential concentration of SO 2 X 2 (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; 73 FR 4340, Jan. 24, 2008; 76 FR 17306, Mar. 28, 2011; 76 FR 50132, Aug. 12, 2011] § 75.5 Prohibitions. (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 SO 2 X 2 (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 SO 2 X 2 (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] § 75.6 Incorporation by reference. 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 Federal Register. http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html. (a) The following materials are available for purchase from the following address: American Society for Testing and Material (ASTM) International, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken, Pennsylvania, 19428-2959, phone: 610-832-9585, http://www.astm.org/DIGITAL_LIBRARY/index.shtml. (1) ASTM D129-00, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), for appendices A and D of this part. (2) D240-00, 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 D287-92 (Reapproved 2000), Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), for appendix D of this part. (4) ASTM D388-99, Standard Classification of Coals by Rank, incorporation by reference for appendix F of this part. (5) [Reserved] (6) ASTM D1072-06, Standard Test Method for Total Sulfur in Fuel Gases by Combustion and Barium Chloride Titration, for appendix D of this part. (7) ASTM D1217-993 (Reapproved 1998), Standard Test Method for Density and Relative Density (Specific Gravity) of Liquids by Bingham Pycnometer, for appendix D of this part. (8) ASTM D1250-07 , Standard Guide for Use of the Petroleum Measurement Tables, for appendix D of this part. (9) ASTM D1298-99, Standard Test Method 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 D1480-93 (Reapproved 1997), Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Bingham Pycnometer, for appendix D of this part. (11) ASTM D1481-93 (Reapproved 1997), 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 D1552-01, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), for appendices A and D of the part. (13) ASTM D1826-94 (Reapproved 1998), 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 D1945-96 (Reapproved 2001), Standard Test Method for Analysis of Natural Gas by Gas Chromatography, for appendices F and G of this part. (15) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography, for appendices F and G of this part. (16) [Reserved] (17) ASTM D2013-01, Standard Practice for Preparing Coal Samples for Analysis, for appendix F of this part. (18) [Reserved] (19) ASTM D2234-00, Standard Practice for Collection of a Gross Sample of Coal, for appendix F of this part. (20) [Reserved] (21) ASTM D2502-92 (Reapproved 1996), 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 D2503-92 (Reapproved 1997), Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, for appendix G of this part. (23) ASTM D2622-98, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence Spectrometry, for appendices A and D of this part. (24) ASTM D3174-00, 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 (Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and Coke, for appendices A and F of this part. (26) ASTM D3177-02 (Reapproved 2007), Standard Test Methods for Total Sulfur in the Analysis Sample of Coal and Coke, for appendix A of this part. (27) ASTM D5373-02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke, for appendix G of this part. (28) ASTM D3238-95 (Reapproved 2000), 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 D3246-96, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, for appendix D of this part. (30) [Reserved] (31) ASTM D3588-98, Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, for appendices D and F to this part. (32) ASTM D4052-96 (Reapproved 2002), Standard Test Method for Density and Relative Density of Liquids by Digital Density Meter, for appendix D of this part. (33) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual Sampling of Petroleum and Petroleum Products, for appendix D of this part. (34) ASTM D4177-95 (Reapproved 2000), Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, for appendix D of this part. (35) ASTM D4239-02, 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 D4294-98, Standard Test Method for Sulfur in Petroleum and Petroleum Products by Energy-Dispersive X-ray Fluorescence Spectrometry, for appendices A and D of this part. (37) ASTM D4468-85 (Reapproved 2006), Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, for appendix D of this part. (38) [Reserved] (39) ASTM D4891-89 (Reapproved 2006), 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 D5291-02, 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 D5373-02 (Reapproved 2007), “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke,” for appendix G to this part. (42) ASTM D5504-01, 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) [Reserved] (44) [Reserved] (45) ASTM D6667-04, Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, for appendix D of this part. (46) ASTM D4809-00, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), for appendices D and F of this part. (47) ASTM D5865-01a, Standard Test Method for Gross Calorific Value of Coal and Coke, for appendices A, D, and F of this part. (48) ASTM D7036-04, Standard Practice for Competence of Air Emission Testing Bodies, for § 75.21, § 75.59, and appendix A to this part. (49) ASTM D5453-06, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and Engine Oil by Ultraviolet Fluorescence, for appendix D of this part. (50) ASTM D5865-10 (Approved January 1, 2010), Standard Test Method for Gross Calorific Value of Coal and Coke, for appendices A, D, and F of this part. (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-2004 (Revision of ASME MFC-3M-1989 (R1995)), Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, for appendix D of this part. (2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters, for appendix D of this part. (3) ASME-MFC-5M-1985 (Reaffirmed 1994), Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, for appendix D of this part. (4) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters, 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 (Reaffirmed 2001), 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 2172-96, 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 2261-00, 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) Manual of Petroleum Measurement Standards, Chapter 3—Tank Gauging, Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, Second Edition, August 2005; Section 1B—Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, Second Edition June 2001; Section 2—Standard Practice for Gauging Petroleum and Petroleum Products in Tank Cars, First Edition, August 1995 (Reaffirmed March 2006); Section 3—Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Pressurized Storage Tanks by Automatic Tank Gauging, First Edition June 1996; Section 4—Standard Practice for Level Measurement of Liquid Hydrocarbons on Marine Vessels by Automatic Tank Gauging, First Edition April 1995 (Reaffirmed, March 2006); and Section 5—Standard Practice for Level Measurement of Light Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging, First Edition March 1997 (Reaffirmed, March 2003); 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) Manual of Petroleum Measurement Standards, Chapter 4—Proving Systems, Section 2—Pipe Provers (Provers Accumulating at Least 10,000 Pulses), Second Edition, March 2001, Section 3—Small Volume Provers, First Edition, July 1988, Reaffirmed Oct 1993, and Section 5—Master-Meter Provers, Second Edition, May 2000, for appendix D to this part. (4) American Petroleum Institute (API) Manual of Petroleum Measurement Standards, Chapter 22—Testing Protocol, Section 2—Differential Pressure Flow Measurement Devices (First Edition, August 2005), for appendix D to this part. (g) A copy of the following material is available from http://www.epa.gov/ttn/emc/news.html see [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; 73 FR 4341, Jan. 24, 2008; 76 FR 17307, Mar. 28, 2011; 77 FR 2460, Jan. 18, 2012] 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. §§ 75.7-75.8 [Reserved] Subpart B—Monitoring Provisions § 75.10 General operating requirements. (a) Primary Measurement Requirement. 2 X 2 (1) To determine SO 2 2 2 2 (2) To determine NO X X X 2 2 X 2 2 2 2 X X 2 2 2 (3) The owner or operator shall determine CO 2 (i) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a CO 2 2 2 (ii) The owner or operator shall determine CO 2 2 (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 CO 2 2 2 2 2 2 (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. 2 X i.e. 2 X (c) Heat Input Rate Measurement Requirement. (d) Primary equipment hourly operating requirements. (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 SO 2 2 2 2 2 X X (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 SO 2 2 2 X X X X X 2 2 2 (e) Optional backup monitor requirements. (f) Minimum measurement capability requirement. (g) Minimum recording and recordkeeping requirements. [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; 76 FR 17308, Mar. 28, 2011] § 75.11 Specific provisions for monitoring SO 2 (a) Coal-fired units. 2 (b) Moisture correction. 2 (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 and 14.0% for natural gas (boilers, only); 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 SO 2 2 2 (c) Unit with no location for a flow monitor meeting siting requirements. (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. 2 (1) By meeting the general operating requirements in § 75.10 for an SO 2 (2) By providing other information satisfactory to the Administrator using the applicable procedures specified in appendix D to this part for estimating hourly SO 2 (3) By using the low mass emissions excepted methodology in § 75.19(c) for estimating hourly SO 2 2 X 2 (e) Special considerations during the combustion of gaseous fuels. 2 2 2 (1) If the gaseous fuel qualifies for a default SO 2 2 2 (2) [Reserved] (3) The owner or operator may determine SO 2 2 2 (i) When conducting the daily calibration error tests of the SO 2 2 (ii) EPA recommends that the calibration response of the SO 2 i.e. (iii) Any bias-adjusted hourly average SO 2 2 i.e. (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 SO 2 2 (4) The provisions in paragraph (e)(1) of this section, may also be used for the combustion of a solid or liquid fuel that meets the definition of very low sulfur fuel in § 72.2 of this chapter, mixtures of such fuels, or combinations of such fuels with gaseous fuel, if the owner or operator submits a petition under § 75.66 for a default SO 2 (f) Other units. [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; 73 FR 4342, Jan. 24, 2008] § 75.12 Specific provisions for monitoring NO X (a) Coal-fired units, gas-fired nonpeaking units or oil-fired nonpeaking units. X X 2 2 (b) Moisture correction. X X X (c) Determination of NO X emission rate. X X 2 2 (d) Gas-fired peaking units or oil-fired peaking units. (1) Meet the general operating requirements in § 75.10 for a NO X (2) Provide information satisfactory to the Administrator using the procedure specified in appendix E of this part for estimating hourly NO X X X (e) Low mass emissions units. (1) Meet the general operating requirements in § 75.10 for a NO X (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 NO X X X 2 2 (f) Other units. [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; 73 FR 4342, Jan. 24, 2008] § 75.13 Specific provisions for monitoring CO 2 (a) CO 2 continuous emission monitoring system. 2 2 2 2 2 2 2 2 2 (b) Determination of CO 2 emissions using appendix G to this part. 2 2 2 (c) Determination of CO 2 mass emissions using an O 2 monitor according to appendix F to this part. 2 2 c 2 2 2 2 2 2 2 2 (d) Determination of CO 2 mass emissions from low mass emissions units. (1) Meet the general operating requirements in § 75.10 for a CO 2 (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 CO 2 2 X 2 [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; 73 FR 4343, Jan. 24, 2008] § 75.14 Specific provisions for monitoring opacity. (a) Coal-fired units and oil-fired units. (b) Unit with wet flue gas pollution control system. 2 (c) Gas-fired units. (d) Diesel-fired units and dual-fuel reciprocating engine units. (e) Unit with a certified particulate matter (PM) monitoring system. If, for a particular affected unit, the owner or operator installs, certifies, operates, maintains, and quality-assures a continuous particulate matter (PM) monitoring system in accordance with Procedure 2 in appendix F to part 60 of this chapter, the unit shall be exempt from the opacity monitoring requirement of this part. [58 FR 3701, Jan. 11, 1993, as amended at 61 FR 25581, May 22, 1996; 73 FR 4343, Jan. 24, 2008] § 75.15 [Reserved] § 75.16 Special provisions for monitoring emissions from common, bypass, and multiple stacks for SO 2 (a) [Reserved] (b) Common stack procedures. (1) Unit utilizing common stack with other affected unit(s). (i) Install, certify, operate, and maintain an SO 2 (ii) Install, certify, operate, and maintain an SO 2 (2) Unit utilizing common stack with nonaffected unit(s). (i) Install, certify, operate, and maintain an SO 2 (ii) Install, certify, operate, and maintain an SO 2 (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 SO 2 2 2 2 2 (C) Record the combined emissions from all units as the combined SO 2 (D) Petition through the designated representative and provide information satisfactory to the Administrator on methods for apportioning SO 2 2 2 (c) Unit with bypass stack. 2 (1) Install, certify, operate, and maintain separate SO 2 2 2 (2) Monitor SO 2 2 2 2 2 (3) Install, certify, operate, and maintain SO 2 2 2 2 see 2 2 2 (d) Unit with multiple stacks or ducts. (1) Install, certify, operate, and maintain an SO 2 2 2 (2) Install, certify, operate, and maintain an SO 2 2 2 2 2 (e) Heat input rate. (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 “SO 2 2 (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 load (in 1000 lb/hr or mmBtu/hr thermal output) for each individual unit to the total steam load 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 NO X [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; 73 FR 4343, Jan. 24, 2008] § 75.17 Specific provisions for monitoring emissions from common, bypass, and multiple stacks for NO X 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 NO X X (a) Unit utilizing common stack with other affected unit(s). (1) Install, certify, operate, and maintain a NO X (2) Install, certify, operate, and maintain a NO X X X (i) When each of the affected units has a NO X (A) Each unit will comply with the most stringent NO X (B) Each unit will comply with the applicable NO X (C) Each unit's compliance with the applicable NO X X X X X (ii) When none of the affected units has a NO X X (iii) When at least one of the affected units has a NO X X (A) Install, certify, operate, and maintain NO X (B) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined NO X X (b) Unit utilizing common stack with nonaffected unit(s). (1) Install, certify, operate, and maintain a NO X (2) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined NO X X (c) Unit with multiple stacks or ducts. X (1) Install, certify, operate, and maintain a NO X X X X X X X X (2) Provided that the products of combustion are well-mixed, install, certify, operate, and maintain a NO X X X e.g., X X e.g., X (d) Unit with a main stack and bypass stack configuration. (1) Follow the procedures in paragraph (c)(1) of this section; or (2) Install, certify, operate, and maintain a NO X X X X X X X X X X X X X [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; 73 FR 4343, Jan. 24, 2008] § 75.18 Specific provisions for monitoring emissions from common and by-pass stacks for opacity. (a) Unit using common stack. (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. (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] § 75.19 Optional SO 2 X 2 (a) Applicability and qualification. X 2 2 X 2 X 2 X (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 2 X X ( 2 X and X ( 3 X (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 SO 2 X (C) This paragraph, (a)(1)(i)(C), applies only to a unit that is subject to an SO 2 2 2 (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 SO 2 X 2 X 2 X 2 X X 2 X 2 X X (B) When the three full years (or ozone seasons) of actual SO 2 X 2 X 2 X 2 X X X (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 SO 2 X (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 NO X X X X X X X 4 X X X X X X X (b) On-going qualification and disqualification. 2 X (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 SO 2 X (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 SO 2 X 2 2 X (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 operating hour, beginning with the first operating hour after the deadline and continuing until the monitoring systems have been provisionally certified: the maximum potential hourly heat input for the unit, as defined in § 72.2 of this chapter; the SO 2 2 2 2 X (3) If a low mass emissions unit that initially qualifies to use the low mass emissions excepted methodology under this section changes fuels, such that a fuel other than those allowed for use in the low mass emissions methodology is combusted in the unit, the unit shall be disqualified from using the low mass emissions excepted methodology as of the first hour that the new fuel is combusted in the unit. The owner or operator shall install and certify SO 2 X 2 2 2 X X 2 X 2 (4) If a new of newly-affected unit initially qualifies to use the low mass emissions excepted methodology under this section and the owner or operator wants to use the low mass emissions methodology for the unit, he or she must: (i) Keep the records specified in paragraph (c)(2) of this section, beginning with the date and hour of commencement of commercial operation, for a new unit subject to an Acid Rain emission limitation, and beginning with the date and hour of the commencement of operation, for a new unit subject to a NO X (A) For Acid Rain Program units, begin keeping the records as of the first hour of commercial operation of the unit following the date on which the unit becomes affected; or (B) For units subject to a NO X (ii) Use these records to determine the cumulative heat input and SO 2 2 X (iii) Determine the cumulative SO 2 X X 2 2 (5) A low mass emissions unit that has been disqualified from using the low mass emissions excepted methodology may subsequently submit an application to qualify again to use the low mass emissions methodology under paragraph (a)(2) of this section only if, following the non-compliant year (or ozone season), at least three full years (or ozone seasons) of actual, monitored emissions data is obtained showing that the unit emitted no more than the applicable number of tons of SO 2 X (c) Low mass emissions excepted methodology, calculations, and values Determination of SO 2 NO X and CO 2 emission rates. (i) If the unit combusts only natural gas and/or fuel oil, use Table LM-1 of this section to determine the appropriate SO 2 2 2 2 (ii) If the unit combusts only natural gas and/or fuel oil, use either the appropriate NO X X X X (iii) If the unit combusts only natural gas and/or fuel oil, use Table LM-3 of this section to determine the appropriate CO 2 2 2 (A) Derive a carbon-based F-factor for the fuel, using fuel sampling and analysis, as described in section 3.3.6 of appendix F to this part; and (B) Use Equation G-4 in appendix G to this part to derive the default CO 2 CO2 2 (iv) In lieu of using the default NO X X X (A) Except as otherwise provided in paragraphs (c)(1)(iv)(F), (c)(1)(iv)(G), and (c)(1)(iv)(I) of this section, determine a fuel-and-unit-specific NO X X ( 1 ( 2 ( 3 X 2 ( 4 X Where: NO X corr X NO X obs X P r P o H r 2 H o 2 T r T a (B) Representative appendix E testing may be done on low mass emission units in a group of identical units. All of the units in a group of identical units must combust the same fuel type but do not have to share a common fuel supply. ( 1 ( 2 ( 3 ( 4 1 ( 5 X (C) Based on the results of the part 75 appendix E testing, determine the fuel-and-unit-specific NO X ( 1 X X X ( 2 ( 3 X X X ( 4 7 8 X X ( i ( ii ( 5 ( 6 7 8 X X ( i X ( ii ( 7 4 6 and X ( i and ( ii X ( 8 4 6 and X X ( i X ( ii X 2 X X ( 9 X ( i X ( ii X X (D) For each low mass emissions unit, or group of identical units for which the provisions of paragraph (c)(1)(iv) of this section are used to account for NO X X X X X X X X (E) Each low mass emissions unit or each low mass emissions unit in a group of identical units for which a fuel-and-unit-specific NO X (F) Low mass emission units may use the results of appendix E testing, if such test results are available from a test conducted no more than five years prior to the time of initial certification, to determine the appropriate fuel-and-unit-specific NO X X (G) Low mass emissions units for which at least 3 years of quality-assured NO X X X X X X X X X (H) For low mass emission units with add-on NO X X X X X ( 1 X X X X ( 2 X X X X X X ( 3 X X X X (I) Notwithstanding the requirements in paragraph (c)(1)(iv)(A) of this section, the appendix E testing to determine (or re-determine) the fuel-specific, unit-specific NO X ( 1 ( 2 X X ( 3 ( 4 3 ( 5 3 4 ( 6 3 5 (J) To determine whether a unit qualifies for testing at fewer than four loads under paragraph (c)(1)(iv)(I) of this section, follow the procedures in paragraph (c)(1)(iv)(J)( 1 2 ( 1 ( 2 (2) Records of operating time, fuel usage, unit output and NO X emission control operating status. (i) For each low mass emissions unit, the owner or operator shall keep hourly records which indicate whether or not the unit operated during each clock hour of each calendar year. The owner or operator may report partial operating hours or may assume that for each hour the unit operated the operating time is a whole hour. Units using partial operating hours and the maximum rated hourly heat input to calculate heat input for each hour must report partial operating hours. (ii) For each low mass emissions unit, the owner or operator shall keep hourly records indicating the type(s) of fuel(s) combusted in the unit during each hour of unit operation. (iii) For each low mass emissions unit using the long term fuel flow methodology under paragraph (c)(3)(ii) of this section to determine hourly heat input, the owner or operator shall keep hourly records of unit load (in megawatts or thousands of pounds of steam per hour), for the purpose of apportioning heat input to the individual unit operating hours. (iv) For each low mass emissions unit with add-on NO X X X (3) Heat input. (i) Maximum rated hourly heat input method. hr (B) The quarterly heat input, HI qtr Where: n HI hr (C) The year-to-date cumulative heat input (mmBtu) shall be the sum of the quarterly heat input values for all of the calendar quarters in the year to date. (D) For a unit subject to the provisions of subpart H of this part, which is not required to report emission data on a year-round basis and elects to report only during the ozone season, the quarterly heat input for the second calendar quarter of the year shall, for compliance purposes, include only the heat input for the months of May and June, and the cumulative ozone season heat input shall be the sum of the heat input values for May, June and the third calendar quarter of the year. (ii) Long term fuel flow heat input method. (A) This option may be used for a group of low mass emission units only if: ( 1 ( 2 ( 3 (B) For each fuel used during the quarter, the volume in standard cubic feet (for gas) or gallons (for oil) may be determined using any of the following methods; ( 1 ( 2 ( 3 (C) Except as provided in paragraph (c)(3)(ii)(C)( 3 ( 1 ( 2 ( 3 max (D) If Eq. LM-2 is used for heat input determination, the specific gravity of each type of fuel oil combusted during the quarter shall be determined either by: ( 1 ( 2 (E) The quarterly heat input from each type of fuel combusted during the quarter by a low mass emissions unit or group of low mass emissions units sharing a common fuel supply shall be determined using either Equation LM-2 or Equation LM-3 for oil (as applicable to the method used to quantify oil usage) and Equation LM-3 for gaseous fuels. For a unit subject to the provisions of subpart H of this part, which is not required to report emission data on a year-round basis and elects to report only during the ozone season, the quarterly heat input for the second calendar quarter of the year shall include only the heat input for the months of May and June. Where: HI fuel-qtr M qtr GCV max 10 6 Where: HI fuel-qtr Q qtr GCV max 10 6 (F) Use Eq. LM-4 to calculate HI qtr-total qtr-total fuel-qtr (G) The year-to-date cumulative heat input (mmBtu) for all fuels shall be the sum of all quarterly total heat input (HI qtr-total (H) For each low mass emissions unit or each low mass emissions unit in a group of identical units, the owner or operator shall determine the cumulative quarterly unit load in megawatt hours or thousands of pounds of steam. The quarterly cumulative unit load shall be the sum of the hourly unit load values recorded under paragraph (c)(2) of this section and shall be determined using Equations LM-5 or LM-6. For a unit subject to the provisions of subpart H of this part, which is not required to report emission data on a year-round basis and elects to report only during the ozone season, the quarterly cumulative load for the second calendar quarter of the year shall include only the unit loads for the months of May and June. Where: MW qtr ST fuel-qtr MW = Unit operating load for a particular unit operating hour (MWh). ST = Unit steam load for a particular unit operating hour (klb of steam). (I) For a low mass emissions unit that is not included in a group of low mass emission units sharing a common fuel supply, apportion the total heat input for the quarter, HI qtr-total (Eq LM-7 for MW output) (Eq LM-8 for steam output) Where: HI hr MW hr ST hr (J) For each low mass emissions unit that is included in a group of units sharing a common fuel supply, apportion the total heat input for the quarter, HI qtr-total (Eq LM-7a for MW output) (Eq LM-8a for steam output) Where: HI hr MW hr ST hr Σ MW qtr all-units Σ ST qtr all-units (4) Calculation of SO 2 NO X and CO 2 mass emissions. 2 X 2 (i) SO 2 mass emissions. 2 2 W SO2 SO2 hr Where: W SO2 2 EF SO2 2 2 HI hr (B) The quarterly SO 2 2 (C) The year-to-date cumulative SO 2 2 (ii)(A) The hourly NO X X X X X X W NOX NOX × hr Where: W NOX X EF NOX X X HI hr (B) The quarterly NO X X (C) The year-to-date cumulative NO X X X X (D) The quarterly and cumulative NO X X NO X X X (iii) CO 2 Mass Emissions. 2 2 WCO 2 2 hr Where: WCO 2 2 EF CO2 2 2 HI hr (B) The quarterly CO 2 2 (C) The year-to-date cumulative CO 2 2 (d) Each unit that qualifies under this section to use the low mass emissions methodology must follow the recordkeeping and reporting requirements pertaining to low mass emissions units in subparts F and G of this part. (e) The quality control and quality assurance requirements in § 75.21 are not applicable to a low mass emissions unit for which the low mass emissions excepted methodology under paragraph (c) of this section is being used in lieu of a continuous emission monitoring system or an excepted monitoring system under appendix D or E to this part, except for fuel flowmeters used to meet the provisions in paragraph (c)(3)(ii) of this section. However, the owner or operator of a low mass emissions unit shall implement the following quality assurance and quality control provisions: (1) For low mass emission units or groups of units which use the long term fuel flow methodology under paragraph (c)(3)(ii) of this section and which use fuel billing records to determine fuel usage, the owner or operator shall keep, at the facility, for three years, the records of the fuel billing statements used for long term fuel flow determinations. (2) For low mass emissions units or groups of units which use the long term fuel flow methodology under paragraph (c)(3)(ii) of this section and which use one of the methods specified in paragraph (c)(3)(ii)(B)( 2 (3) For low mass emission units or groups of units which use the long term fuel flow methodology under paragraph (c)(3)(ii) of this section and which use a certified fuel flow meter to determine fuel usage, the owner or operator shall comply with the quality control quality assurance requirements for a fuel flow meter under section 2.1.6 of appendix D of this part. (4) For each low mass emissions unit for which fuel-and-unit-specific NO X X X X X (5) For each low mass emissions unit for which fuel-and-unit-specific NO X X X X X (6) For unmanned facilities, the records required by paragraphs (e)(1), (e)(2) and (e)(4) of this section may be kept at a central location, rather than at the facility. Table LM-1—SO 2 Fuel type SO 2 Pipeline Natural Gas 0.0006 lb/mmBtu. Other Natural Gas 0.06 lb/mmBtu. Residual Oil 2.1 lb/mmBtu. Diesel Fuel 0.5 lb/mmBtu. Table LM-2—NO X Unit type Fuel type NO X Turbine Gas 0.7 Turbine Oil 1.2 Boiler Gas 1.5 Boiler Oil 2 Table LM-3—CO 2 Fuel type CO 2 Pipeline (or other) Natural Gas 0.059 ton/mmBtu. Oil 0.081 ton/mmBtu. Table LM-4—Identical Unit Testing Requirements Number of identical units in the group Number of appendix E tests required 2 1 3 to 6 2 7 3 >7 n tests; where n = number of units divided by 3 and rounded to nearest integer. Table LM-5—Default Gross Calorific Values (GCVs) for Various Fuels Fuel GCV for use in equation LM-2 or LM-3 Pipeline Natural Gas 1050 Btu/scf. Other Natural Gas 1100 Btu/scf. Residual Oil 19,700 Btu/lb or 167,500 Btu/gallon. Diesel Fuel 20,500 Btu/lb or 151,700 Btu/gallon. Table LM-6—Default Specific Gravity Values for Fuel Oil Fuel Specific gravity (lb/gal) Residual Oil 8.5 Diesel Fuel 7.4 [63 FR 57500, Oct. 27, 1998, as amended at 64 FR 28592, May 26, 1999; 64 FR 37582, July 12, 1999; 67 FR 40424, 40425, June 12, 2002; 67 FR 53504, Aug. 16, 2002; 73 FR 4344, Jan. 24, 2008] Subpart C—Operation and Maintenance Requirements § 75.20 Initial certification and recertification procedures. (a) Initial certification approval process. (1) Notification of initial certification test dates. (2) Certification application. (3) Provisional approval of certification (or recertification) applications. (4) Certification (or recertification) application formal approval process. (i) Approval notice. (ii) Incomplete application notice. (iii) Disapproval notice. (iv) Audit decertification. (5) Procedures for loss of certification. (i) Until such time, date, and hour as the continuous emission monitoring system can be adjusted, repaired, or replaced and certification tests successfully completed (or, if the conditional data validation procedures in paragraphs (b)(3)(ii) through (b)(3)(ix) of this section are used, until a probationary calibration error test is passed following corrective actions in accordance with paragraph (b)(3)(ii) of this section), the owner or operator shall substitute the following values, as applicable, for each hour of unit operation during the period of invalid data specified in paragraph (a)(4)(iii) of this section or in § 75.21: the maximum potential concentration of SO 2 2 X X X X X X 2 2 X (ii) The designated representative shall submit a notification of certification retest dates as specified in § 75.61(a)(1)(ii) and a new certification application according to the procedures in paragraph (a)(2) of this section; and (iii) The owner or operator shall repeat all certification tests or other requirements that were failed by the continuous emission or opacity monitoring system, as indicated in the Administrator's notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval. (b) Recertification approval process. 2 2 X X (1) Tests required. (2) Notification of recertification test dates. (3) Recertification test period requirements and data validation. (i) The owner or operator shall use substitute data, according to the standard missing data procedures in §§ 75.33 through 75.37 (or shall report emission data using a reference method or another monitoring system that has been certified or approved for use under this part), in the period extending from the hour of the replacement, modification or change made to a monitoring system that triggers the need to perform recertification testing, until either: the hour of successful completion of all of the required recertification tests; or the hour in which a probationary calibration error test (according to paragraph (b)(3)(ii) of this section) is performed and passed, following all necessary repairs, adjustments or reprogramming of the monitoring system. The first hour of quality-assured data for the recertified monitoring system shall either be the hour after all recertification tests have been completed or, if conditional data validation is used, the first quality-assured hour shall be determined in accordance with paragraphs (b)(3)(ii) through (b)(3)(ix) of this section. Notwithstanding these requirements, if the replacement, modification, or change requiring recertification of the CEMS is such that the historical data stream is no longer representative (e.g., where the SO 2 (ii) Once the modification or change to the CEMS has been completed and all of the associated repairs, component replacements, adjustments, linearization, and reprogramming of the CEMS have been completed, a probationary calibration error test is required to establish the beginning point of the recertification test period. In this instance, the first successful calibration error test of the monitoring system following completion of all necessary repairs, component replacements, adjustments, linearization and reprogramming shall be the probationary calibration error test. The probationary calibration error test must be passed before any of the required recertification tests are commenced. (iii) Beginning with the hour of commencement of a recertification test period, emission data recorded by the CEMS are considered to be conditionally valid, contingent upon the results of the subsequent recertification tests. (iv) Each required recertification test shall be completed no later than the following number of unit operating hours (or unit operating days) after the probationary calibration error test that initiates the test period: (A) For a linearity check and/or cycle time test, 168 consecutive unit operating hours, as defined in § 72.2 of this chapter or, for CEMS installed on common stacks or bypass stacks, 168 consecutive stack operating hours, as defined in § 72.2 of this chapter; (B) For a RATA (whether normal-load or multiple-load), 720 consecutive unit operating hours, as defined in § 72.2 of this chapter or, for CEMS installed on common stacks or bypass stacks, 720 consecutive stack operating hours, as defined in § 72.2 of this chapter; and (C) For a 7-day calibration error test, 21 consecutive unit operating days, as defined in § 72.2 of this chapter. (v) All recertification tests shall be performed hands-off. No adjustments to the calibration of the CEMS, other than the routine calibration adjustments following daily calibration error tests as described in section 2.1.3 of appendix B to this part, are permitted during the recertification test period. Routine daily calibration error tests shall be performed throughout the recertification test period, in accordance with section 2.1.1 of appendix B to this part. The additional calibration error test requirements in section 2.1.3 of appendix B to this part shall also apply during the recertification test period. (vi) If all of the required recertification tests and required daily calibration error tests are successfully completed in succession with no failures, and if each recertification test is completed within the time period specified in paragraph (b)(3)(iv)(A), (B), or (C) of this section, then all of the conditionally valid emission data recorded by the CEMS shall be considered quality-assured, from the hour of commencement of the recertification test period until the hour of completion of the required test(s). (vii) If a required recertification test is failed or aborted due to a problem with the CEMS, or if a daily calibration error test is failed during a recertification test period, data validation shall be done as follows: (A) If any required recertification test is failed, it shall be repeated. If any recertification test other than a 7-day calibration error test is failed or aborted due to a problem with the CEMS, the original recertification test period is ended, and a new recertification test period must be commenced with a probationary calibration error test. The tests that are required in the new recertification test period will include any tests that were required for the initial recertification event which were not successfully completed and any recertification or diagnostic tests that are required as a result of changes made to the monitoring system to correct the problems that caused the failure of the recertification test. For a 2- or 3-load flow RATA, if the relative accuracy test is passed at one or more load levels, but is failed at a subsequent load level, provided that the problem that caused the RATA failure is corrected without re-linearizing the instrument, the length of the new recertification test period shall be equal to the number of unit operating hours remaining in the original recertification test period, as of the hour of failure of the RATA. However, if re-linearization of the flow monitor is required after a flow RATA is failed at a particular load level, then a subsequent 3-load RATA is required, and the new recertification test period shall be 720 consecutive unit (or stack) operating hours. The new recertification test sequence shall not be commenced until all necessary maintenance activities, adjustments, linearizations, and reprogramming of the CEMS have been completed; (B) If a linearity check, RATA, or cycle time test is failed or aborted due to a problem with the CEMS, all conditionally valid emission data recorded by the CEMS are invalidated, from the hour of commencement of the recertification test period to the hour in which the test is failed or aborted, except for the case in which a multiple-load flow RATA is passed at one or more load levels, failed at a subsequent load level, and the problem that caused the RATA failure is corrected without re-linearizing the instrument. In that case, data invalidation shall be prospective, from the hour of failure of the RATA until the commencement of the new recertification test period. Data from the CEMS remain invalid until the hour in which a new recertification test period is commenced, following corrective action, and a probationary calibration error test is passed, at which time the conditionally valid status of emission data from the CEMS begins again; (C) If a 7-day calibration error test is failed within the recertification test period, previously-recorded conditionally valid emission data from the CEMS are not invalidated. The conditionally valid data status is unaffected, unless the calibration error on the day of the failed 7-day calibration error test exceeds twice the performance specification in section 3 of appendix A to this part, as described in paragraph (b)(3)(vii)(D) of this section; and (D) If a daily calibration error test is failed during a recertification test period ( i.e. (E) Trial gas injections and trial RATA runs are permissible during the recertification test period, prior to commencing a linearity check or RATA, for the purpose of optimizing the performance of the CEMS. The results of such gas injections and trial runs shall not affect the status of previously-recorded conditionally valid data or result in termination of the recertification test period, provided that the following specifications and conditions are met: ( 1 ( 2 2 ( 3 ( 4 (F) If the results of any trial gas injection(s) or RATA run(s) are outside the limits in paragraphs (b)(3)(vii)(E)( 1 2 (viii) If any required recertification test is not completed within its allotted time period, data validation shall be done as follows. For a late linearity test, RATA, or cycle time test that is passed on the first attempt, data from the monitoring system shall be invalidated from the hour of expiration of the recertification test period until the hour of completion of the late test. For a late 7-day calibration error test, whether or not it is passed on the first attempt, data from the monitoring system shall also be invalidated from the hour of expiration of the recertification test period until the hour of completion of the late test. For a late linearity test, RATA, or cycle time test that is failed on the first attempt or aborted on the first attempt due to a problem with the monitor, all conditionally valid data from the monitoring system shall be considered invalid back to the hour of the first probationary calibration error test which initiated the recertification test period. Data from the monitoring system shall remain invalid until the hour of successful completion of the late recertification test and any additional recertification or diagnostic tests that are required as a result of changes made to the monitoring system to correct problems that caused failure of the late recertification test. (ix) If any required recertification test of a monitoring system has not been completed by the end of a calendar quarter and if data contained in the quarterly report are conditionally valid pending the results of test(s) to be completed in a subsequent quarter, the owner or operator shall indicate this by means of a suitable conditionally valid data flag in the electronic quarterly report for that quarter. The owner or operator shall resubmit the report for that quarter if the required recertification test is subsequently failed. In the resubmitted report, the owner or operator shall use the appropriate missing data routine in § 75.31 or § 75.33 to replace with substitute data each hour of conditionally valid data that was invalidated by the failed recertification test. Alternatively, if any required recertification test is not completed by the end of a particular calendar quarter but is completed no later than 30 days after the end of that quarter ( i.e. i.e. (4) Recertification application. (5) Approval or disapproval of request for recertification. (c) Initial certification and recertification procedures. (1) For each SO 2 X X X (i) A 7-day calibration error test, where, for the NO X X (ii) A linearity check, where, for the NO X X (iii) A relative accuracy test audit. For the NO X X (iv) A bias test; (v) A cycle time test, (where, for the NO X X (2) For each flow monitor: (i) A 7-day calibration error test; (ii) Relative accuracy test audits, as follows: (A) A single-load (or single-level) RATA at the normal load (or level), as defined in section 6.5.2.1(d) of appendix A to this part, for a flow monitor installed on a peaking unit or bypass stack, or for a flow monitor exempted from multiple-level RATA testing under section 6.5.2(e) of appendix A to this part; (B) For all other flow monitors, a RATA at each of the three load levels (or operating levels) corresponding to the three flue gas velocities described in section 6.5.2(a) of appendix A to this part; (iii) A bias test for the single-load (or single-level) flow RATA described in paragraph (c)(2)(ii)(A) of this section; and (iv) A bias test (or bias tests) for the 3-level flow RATA described in paragraph (c)(2)(ii)(B) of this section, at the following load or operational level(s): (A) At each load level designated as normal under section 6.5.2.1(d) of appendix A to this part, for units that produce electrical or thermal output, or (B) At the operational level identified as normal in section 6.5.2.1(d) of appendix A to this part, for units that do not produce electrical or thermal output. (3) The initial certification test data from an O 2 2 X 2 2 (4) For each CO 2 2 2 2 (i) A 7-day calibration error test; (ii) A linearity check; (iii) A relative accuracy test audit, where, for an O 2 2 2 (iv) A cycle-time test. (5) For each continuous moisture monitoring system consisting of wet- and dry-basis O 2 (i) A 7-day calibration error test of each O 2 (ii) A cycle time test of each O 2 (iii) A linearity test of each O 2 (iv) A RATA, directly comparing the percent moisture measured by the monitoring system to a reference method. (6) For each continuous moisture sensor: A RATA, directly comparing the percent moisture measured by the monitor sensor to a reference method. (7) For a continuous moisture monitoring system consisting of a temperature sensor and a data acquisition and handling system (DAHS) software component programmed with a moisture lookup table: (i) A demonstration that the correct moisture value for each hour is being taken from the moisture lookup tables and applied to the emission calculations. At a minimum, the demonstration shall be made at three different temperatures covering the normal range of stack temperatures from low to high. (ii) [Reserved] (8) The owner or operator shall ensure that initial certification or recertification of a continuous opacity monitor for use under the Acid Rain Program is conducted according to one of the following procedures: (i) Performance of the tests for initial certification or recertification, according to the requirements of Performance Specification 1 in appendix B to part 60 of this chapter; or (ii) A continuous opacity monitoring system tested and certified previously under State or other Federal requirements to meet the requirements of Performance Specification 1 shall be deemed certified for the purposes of this part. (9) [Reserved] (10) For the automated data acquisition and handling system, tests designed to verify: (i) Proper computation of hourly averages for pollutant concentrations, flow rate, pollutant emission rates, and pollutant mass emissions; and (ii) Proper computation and application of the missing data substitution procedures in subpart D of this part and the bias adjustment factors in section 7 of appendix A to this part. (11) The owner or operator shall provide adequate facilities for initial certification or recertification testing that include: (i) Sampling ports adequate for test methods applicable to such facility, such that: (A) Volumetric flow rate, pollutant concentration, and pollutant emission rates can be accurately determined by applicable test methods and procedures; and (B) A stack or duct free of cyclonic flow during performance tests is available, as demonstrated by applicable test methods and procedures. (ii) Basic facilities (e.g., electricity) for sampling and testing equipment. (d) Initial certification and recertification and quality assurance procedures for optional backup continuous emission monitoring systems Redundant backups. (2) Non-redundant backups. (i) Except as provided in paragraph (d)(2)(v) of this section, for a regular non-redundant backup CEMS ( i.e. (ii) For a like-kind replacement non-redundant backup analyzer ( i.e. (iii) Each non-redundant backup CEMS or like-kind replacement analyzer shall comply with the daily and quarterly quality assurance and quality control requirements in appendix B to this part for each day and quarter that the non-redundant backup CEMS or like-kind replacement analyzer is used to report data, and shall meet the additional linearity and calibration error test requirements specified in this paragraph. The owner or operator shall ensure that each non-redundant backup CEMS or like-kind replacement analyzer passes a linearity check (for pollutant concentration and diluent gas monitors) or a calibration error test (for flow monitors) prior to each use for recording and reporting emissions. For a primary NO X (iv) When data are reported from a non-redundant backup CEMS or like-kind replacement analyzer, the appropriate bias adjustment factor shall be determined as follows: (A) For a regular non-redundant backup CEMS, as described in paragraph (d)(2)(i) of this section, apply the bias adjustment factor from the most recent RATA of the non-redundant backup system (even if that RATA was done more than 12 months previously); or (B) When a like-kind replacement non-redundant backup analyzer is used as a component of a primary CEMS (as described in paragraph (d)(2)(ii) of this section), apply the primary monitoring system bias adjustment factor. (v) For each parameter monitored ( i.e. 2 2 2 X (vi) For each regular non-redundant backup CEMS, no more than eight successive calendar quarters shall elapse following the quarter in which the last RATA of the CEMS was done at a particular unit or stack, without performing a subsequent RATA. Otherwise, the CEMS may not be used to report data from that unit or stack until the hour of completion of a passing RATA at that location. (vii) Each regular non-redundant backup CEMS shall be represented in the monitoring plan required under § 75.53 as a separate monitoring system, with unique system and component identification numbers. When like-kind replacement non-redundant backup analyzers are used, the owner or operator shall represent each like-kind replacement analyzer used during a particular calendar quarter in the monitoring plan required under § 75.53 as a component of a primary monitoring system. The owner or operator shall also assign a unique component identification number to each like-kind replacement analyzer, beginning with the letters “LK” ( e.g., (viii) When reporting data from a certified regular non-redundant backup CEMS, use a method of determination (MODC) code of “02.” When reporting data from a like-kind replacement non-redundant backup analyzer, use a MODC of “17” (see Table 4a under § 75.57). For the purposes of the electronic quarterly report required under § 75.64, the owner or operator may manually enter the required MODC of “17” for a like-kind replacement analyzer. (3) Reference method backups. (e) Certification/recertification procedures for either peaking unit or by-pass stack/duct continuous emission monitoring systems. (f) Certification/recertification procedures for alternative monitoring systems. (g) Initial certification and recertification procedures for excepted monitoring systems under appendices D and E. (1) Initial certification and recertification testing. (i) When the optional SO 2 X (ii) For the automated data acquisition and handling system used under either the optional SO 2 X (A) The proper computation of hourly averages for pollutant concentrations, fuel flow rates, emission rates, heat input, and pollutant mass emissions; and (B) Proper computation and application of the missing data substitution procedures in appendix D or E of this part. (iii) When the optional NO X (2) Initial certification, recertification, and QA testing notification. (3) Monitoring plan. (4) Initial certification or recertification application. (5) Provisional approval of initial certification and recertification applications. (6) Recertification requirements. X (7) Procedures for loss of certification or recertification for excepted monitoring systems under appendices D and E to this part. (h) Initial certification and recertification procedures for low mass emission units using the excepted methodologies under § 75.19. (1) Monitoring plan. (2) Certification application. (3) Approval of certification applications. X (4) Disapproval of low mass emissions unit certification applications. (i) The owner or operator shall substitute the following values, as applicable, for each hour of unit operation in which data were reported using the low mass emissions methodology until such time, date, and hour as continuous emission monitoring systems or excepted monitoring systems, where applicable, are installed and provisionally certified: the maximum potential concentration of SO 2 X 2 X X X X X (ii) The designated representative shall submit a notification of certification test dates for the required monitoring systems, as specified in § 75.61(a)(1)(i), and shall submit a certification application according to the procedures in paragraph (a)(2) of this section. (5) Recertification. [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; 63 FR 57506, Oct. 27, 1998; 64 FR 28592, May 26, 1999; 67 FR 40431, June 12, 2002; 70 FR 28678, May 18, 2005; 72 FR 51527, Sept. 7, 2007; 73 FR 4345, Jan. 24, 2008; 76 FR 17308, Mar. 28, 2011] § 75.21 Quality assurance and quality control requirements. (a) Continuous emission monitoring systems. (1) The owner or operator shall operate, calibrate and maintain each primary and redundant backup continuous emission monitoring system according to the quality assurance and quality control procedures in appendix B of this part. (2) The owner or operator shall ensure that each non-redundant backup CEMS meets the quality assurance requirements of § 75.20(d) for each day and quarter that the system is used to report data. (3) The owner or operator shall perform quality assurance upon a reference method backup monitoring system according to the requirements of Method 2, 6C, 7E, or 3A in Appendices A-1, A-2 and A-4 to part 60 of this chapter (supplemented, as necessary, by guidance from the Administrator), instead of the procedures specified in appendix B to this part. (4) The owner or operator of a unit with an SO 2 2 2 2 2 (5) For a unit with an SO 2 2 2 (6) If the designated representative certifies that a unit with an SO 2 2 (7) If the designated representative certifies that a particular unit with an SO 2 e.g., 2 2 (8) The quality assurance provisions of §§ 75.11(e)(3)(i) through 75.11(e)(3)(iv) shall apply to all units with SO 2 (9) Provided that a unit with an SO 2 2 2 2 (10) The owner or operator who, in accordance with § 75.11(e)(1), uses a certified flow monitor and a certified diluent monitor and Equation F-23 in appendix F to this part to calculate SO 2 (b) Continuous opacity monitoring systems. (c) Calibration gases. (d) Notification for periodic relative accuracy test audits. (e) Consequences of audits. (1) Audit decertification. (2) Out-of-control period. (f) Requirements for Air Emission Testing. (g) Requirements for EPA Protocol Gas Verification Program. (1) A production site participating in the PGVP shall provide the following information in its initial and ongoing notifications to EPA in an electronic format prescribed by the Administrator ( see http://www.epa.gov/airmarkets/emissions/pgvp.html (i) The specialty gas company name which owns or operates the participating production site; (ii) The name, e-mail address, and telephone number of a contact person for that specialty gas company; (iii) The name and address of that participating EPA Protocol gas production site, owned or operated by the specialty gas company; and (iv) The name, e-mail address, and telephone number of a contact person for that participating EPA Protocol gas production site. (2) An EPA Protocol gas production site that elects to continue participating in the PGVP in the next calendar year must notify the Administrator of its intent to continue in the program by December 31 of the current year by submitting to EPA the information described in paragraph (g)(1) of this section. (3) A list of the names, contact information, and vendor IDs of EPA Protocol gas production sites participating in the PGVP will be made publicly available by posting on EPA Web sites ( see http://www.epa.gov/airmarkets/emissions/pgvp.html (4) EPA may remove an EPA Protocol gas production site from the list of PGVP participants and give notice to the production site for any of the following reasons: (i) If the EPA Protocol gas production site fails to provide all of the information required by paragraph (g)(1) of this section in accordance with paragraph (g)(2) of this section; (ii) If, after being notified that its EPA Protocol gas cylinders are being audited by EPA, the EPA Protocol gas production site fails to cancel its invoice or to credit the purchaser's account for the cylinders within 45 calendar days of such notification; or (iii) If, after being notified that its EPA Protocol gas cylinders are being audited by EPA, the EPA Protocol gas production site cannot provide to EPA upon demand proof of payment to the National Institute of Standards and Technology (NIST) and a valid contract with NIST; (5) EPA may relist an EPA Protocol gas production site as follows: (i) An EPA Protocol gas production site may be relisted immediately after its failure is remedied if the only reason for removal from the list of PGVP participants is failure to provide all of the information required by paragraph (g)(1) of this section; (ii) If EPA does not receive hardcopy or electronic proof of a credit receipt or of cancellation of the invoice for the cylinders from the EPA Protocol gas production site within 45 calendar days of notifying the EPA Protocol gas production site that its cylinders are being audited by EPA, the cylinders shall be returned to the EPA Protocol gas production site free of any demurrage, and that EPA Protocol gas production site shall not be eligible for relisting for 180 calendar days from the date of notice that it was removed from the list and until it submits to EPA the information required by paragraph (g)(1) of this section; (iii) For any EPA Protocol gas production site which is notified by EPA that its cylinders are being audited and cannot provide to EPA upon demand proof of payment to NIST and a valid contract with NIST, the cylinders may either be kept by NIST or returned to the EPA Protocol gas production site free of any demurrage and at no cost to NIST, and that EPA Protocol gas production site shall not be eligible for relisting for 180 calendar days from the date of notice that it was removed from the list and until it submits to EPA the information required by paragraph (g)(1) of this section. (6) On and after May 27, 2011 for each unit subject to this part that uses EPA Protocol gases, the owner or operator must obtain such gases from either an EPA Protocol gas production site that is on the EPA list of sites participating in the PGVP on the date the owner or operator procures such gases or from a reseller that sells to the owner or operator unaltered EPA Protocol gases produced by an EPA Protocol gas production site that was on the EPA list of participating sites on the date the reseller procured such gases. (7) An EPA Protocol gas cylinder certified by or ordered from any non-participating EPA Protocol gas production site no later than May 27, 2011 may be used for the purposes of this part until the earlier of the cylinder's expiration date or the date on which the cylinder gas pressure reaches 150 psig. In the event that an EPA Protocol gas production site is removed from the list of PGVP participants on the same date as or after the date on which a particular cylinder has been certified or ordered, that gas cylinder may continue to be used for the purposes of this part until the earlier of the cylinder's expiration date or the date on which the cylinder gas pressure reaches 150 psig. However, in no case shall a cylinder described in this paragraph (g)(7) be recertified by a non-participating EPA Protocol gas production site to extend its useful life and be used by a source subject to this part. (8) If EPA notifies a participating EPA Protocol gas production site that its EPA Protocol gas cylinders are being audited and identifies the purchaser as an EPA representative or contractor participating in the audit process, the production site shall: (i) Either cancel that purchaser's invoice or credit that purchaser's account for the purchase of those EPA Protocol gas cylinders; (ii) Not charge for demurrage for those EPA Protocol gas cylinders; (iii) Arrange for and pay for the return shipment of its cylinders from NIST; and (iv) Provide sufficient funding to NIST for: (A) The analysis of those EPA Protocol gas cylinders by NIST; (B) The production site's pro rata share of draft and final NIST electronic audit reports as specified in paragraphs (g)(9)(ii) through (g)(9)(v) of this section on all cylinders in the current audit; and (C) The full cost of a draft redacted electronic audit report containing just that production site's results and the information as specified in paragraphs (g)(9)(ii) through (g)(9)(v) of this section; (9) If EPA notifies a participating EPA Protocol gas production site that its EPA Protocol gas cylinders are being audited then: (i) Each participating EPA Protocol gas production site must have NIST analyze its EPA Protocol gas cylinders provided for audit as soon after NIST receives the batch containing those cylinders as possible, preferably within two weeks of NIST's receipt, using analytical procedures consistent with metrology institute practices and at least as rigorous as the “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards” (Traceability Protocol), September 1997, as amended August 25, 1999, EPA-600/R-97/121, (incorporated by reference, see § 75.6) or equivalent written cylinder analysis protocol that has been approved by EPA. (ii) Each cylinder's concentration must be determined by NIST and the results compared to each cylinder's certification documentation and tag value to establish conformance with section 5.1 of appendix A to this part. After NIST analysis, each cylinder must be provided with a NIST analyzed concentration with an expanded uncertainty, as defined in § 72.2, (coverage factor, as defined in § 72.2, k = 2) of plus or minus 1.0 percent (calculated combined standard uncertainty of plus or minus 0.5%), inclusive, or better, unless otherwise approved by EPA. (iii) The certification documentation accompanying each cylinder must be verified in the audit report as meeting the requirements of “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, as amended August 25, 1999, EPA-600/R-97/121 (incorporated by reference, see (iv) Each participating EPA Protocol gas production site shall have NIST provide all of the information required by paragraphs (g)(9)(ii) through (g)(9)(v) of this section in draft and final electronic audit reports on all cylinders in the current audit, and in a draft redacted electronic audit report containing just that production site's information. The draft audit report on all cylinders in the current audit and each draft redacted version of the audit report shall be submitted electronically by NIST to [email protected], [email protected], [email protected], see http://www.epa.gov/airmarkets/emissions/pgvp.html). (A) A table with the information and in the format specified by Figure 3 (or the Note below Figure 3, as applicable) of appendix B to this part or such revised format as approved by the Administrator; and (B) Complete documentation of the NIST procedures used to analyze the cylinders, including the analytical reference standards, analytical method, analytical method uncertainty, analytical instrumentation, and instrument calibration procedures. (v) For EPA Protocol gas production sites that produce EPA Protocol gas cylinders claiming NIST traceability for both NO and NO X X X 2 (10) An EPA Protocol gas production site shall continue to be on the EPA list of sites participating in the PGVP and may continue to sell EPA Protocol gases to sources subject to part 75 if it is not notified by EPA that its cylinders are being audited under the PGVP if it provides the information described in paragraph (g)(1) of this section in accordance with paragraph (g)(2) of this section. (11) The data validation procedures under §§ 2.1.4, 2.2.3, and 2.3.2 of appendix B to this part apply. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26527, 26566, May 17, 1995; 61 FR 25582, May 22, 1996; 61 FR 59159, Nov. 20, 1996; 64 FR 28599, May 26, 1999; 67 FR 40433, June 12, 2002; 67 FR 53505, Aug. 16, 2002; 70 FR 28679, May 18, 2005; 73 FR 4345, Jan. 24, 2008; 76 FR 17308, Mar. 28, 2011] § 75.22 Reference test methods. (a) The owner or operator shall use the following methods, which are found in appendices A-1 through A-4 to part 60 of this chapter, to conduct the following tests: Monitoring system tests for certification or recertification of continuous emission monitoring Systems; NO X X (1) Methods 1 or 1A are the reference methods for selection of sampling site and sample traverses. (2) Method 2 or its allowable alternatives, as provided in appendix A to part 60 of this chapter, except for Methods 2B and 2E, are the reference methods for determination of volumetric flow. (3) Methods 3, 3A, or 3B are the reference methods for the determination of the dry molecular weight O 2 2 (4) Method 4 (either the standard procedure described in section 8.1 of the method or the moisture approximation procedure described in section 8.2 of the method) shall be used to correct pollutant concentrations from a dry basis to a wet basis (or from a wet basis to a dry basis) and shall be used when relative accuracy test audits of continuous moisture monitoring systems are conducted. For the purpose of determining the stack gas molecular weight, however, the alternative wet bulb-dry bulb technique for approximating the stack gas moisture content described in section 2.2 of Method 4 may be used in lieu of the procedures in sections 8.1 and 8.2 of the method. (5) Methods 6, 6A, 6B or 6C, and 7, 7A, 7C, 7D or 7E in appendix A-4 to part 60 of this chapter, as applicable, are the reference methods for determining SO 2 X 2 X 2 (i) Section 7.1 of the method allowing for use of prepared calibration gas mixtures that are produced in accordance with method 205 in Appendix M of 40 CFR Part 51; (ii) The sampling point selection procedures in section 8.1 of the method, for the emission testing of boilers and combustion turbines under appendix E to this part. The number and location of the sampling points for those applications shall be as specified in sections 2.1.2.1 and 2.1.2.2 of appendix E to this part; (iii) Paragraph (3) in section 8.4 of the method allowing for the use of a multi-hole probe to satisfy the multipoint traverse requirement of the method; (iv) Section 8.6 of the method allowing for the use of “Dynamic Spiking” as an alternative to the interference and system bias checks of the method. Dynamic spiking may be conducted (optionally) as an additional quality assurance check; and (v) That portion of Section 8.5 of the method allowing multiple sampling runs to be conducted before performing the post-run system bias check or system calibration error check. (6) Method 3A in appendix A-2 and method 7E in appendix A-4 to part 60 of this chapter are the reference methods for determining NO X (b) The owner or operator may use any of the following methods, which are found in appendices A-1 through A-4 to part 60 of this chapter, as a reference method backup monitoring system to provide quality-assured monitor data: (1) Method 3A for determining O 2 2 (2) Method 6C for determining SO 2 (3) Method 7E for determining total NO X 2 (4) Method 2, or its allowable alternatives, as provided in appendix A to part 60 of this chapter, except for Methods 2B and 2E, for determining volumetric flow. The sample point(s) for reference methods shall be located according to the provisions of section 6.5.5 of appendix A to this part. (c)(1) Instrumental EPA Reference Methods 3A, 6C, and 7E in appendices A-2 and A-4 of part 60 of this chapter shall be conducted using calibration gases as defined in section 5 of appendix A to this part. Otherwise, performance tests shall be conducted and data reduced in accordance with the test methods and procedures of this part unless the Administrator: (i) Specifies or approves, in specific cases, the use of a reference method with minor changes in methodology; (ii) Approves the use of an equivalent method; or (iii) Approves shorter sampling times and smaller sample volumes when necessitated by process variables or other factors. (2) Nothing in this paragraph shall be construed to abrogate the Administrator's authority to require testing under Section 114 of the Act. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26528, May 17, 1995; 64 FR 28600, May 26, 1999; 67 FR 40433, June 12, 2002; 67 FR 53505, Aug. 16, 2002; 70 FR 28679, May 18, 2005; 73 FR 4345, Jan. 24, 2008; 76 FR 17310, Mar. 28, 2011] § 75.23 Alternatives to standards incorporated by reference. (a) The designated representative of a unit may petition the Administrator for an alternative to any standard incorporated by reference and prescribed in this part in accordance with § 75.66(c). (b) [Reserved] [60 FR 26528, May 17, 1995] § 75.24 Out-of-control periods and adjustment for system bias. (a) If an out-of-control period occurs to a monitor or continuous emission monitoring system, the owner or operator shall take corrective action and repeat the tests applicable to the “out-of-control parameter” as described in appendix B of this part. (1) For daily calibration error tests, an out-of-control period occurs when the calibration error of a pollutant concentration monitor exceeds the applicable specification in section 2.1.4 of appendix B to this part. (2) For quarterly linearity checks, an out-of-control period occurs when the error in linearity at any of three gas concentrations (low, mid-range, and high) exceeds the applicable specification in appendix A to this part. (3) For relative accuracy test audits, an out-of-control period occurs when the relative accuracy exceeds the applicable specification in appendix A to this part. (b) When a monitor or continuous emission monitoring system is out-of-control, any data recorded by the monitor or monitoring system are not quality-assured and shall not be used in calculating monitor data availabilities pursuant to § 75.32 of this part. (c) When a monitor or continuous emission monitoring system is out-of-control, the owner or operator shall take one of the following actions until the monitor or monitoring system has successfully met the relevant criteria in appendices A and B of this part as demonstrated by subsequent tests: (1) Apply the procedures for missing data substitution to emissions from affected unit(s); or (2) Use a certified backup monitoring system or a reference method for measuring and recording emissions from the affected unit(s); or (3) Adjust the gas discharge paths from the affected unit(s) with emissions normally observed by the out-of-control monitor or monitoring system so that all exhaust gases are monitored by a certified monitor or monitoring system meeting the requirements of appendices A and B of this part. (d) When the bias test indicates that an SO 2 X X X i.e., (e) The owner or operator shall determine if a continuous opacity monitoring system is out-of-control and shall take appropriate corrective actions according to the procedures specified for State Implementation Plans, pursuant to appendix M of part 51 of this chapter. The owner or operator shall comply with the monitor data availability requirements of the State. If the State has no monitor data availability requirements for continuous opacity monitoring systems, then the owner or operator shall comply with the monitor data availability requirements as stated in the data capture provisions of appendix M, part 51 of this chapter. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26528, May 17, 1995; 64 FR 28600, May 26, 1999; 67 FR 40433, June 12, 2002; 70 FR 28680, May 18, 2005; 76 FR 17311, Mar. 28, 2011] Subpart D—Missing Data Substitution Procedures § 75.30 General provisions. (a) Except as provided in § 75.34, the owner or operator shall provide substitute data for each affected unit using a continuous emission monitoring system according to the missing data procedures in this subpart whenever the unit combusts any fuel and: (1) A valid, quality-assured hour of SO 2 2 (2) A valid, quality-assured hour of flow data (in scfh) has not been measured and recorded for an affected unit from a certified flow monitor, or by an approved alternative monitoring system under subpart E of this part; or (3) A valid, quality-assured hour of NO X X (4) A valid, quality-assured hour of CO 2 2 2 2 2 (5) A valid, quality-assured hour of NO X X X (6) A valid, quality-assured hour of CO 2 2 2 2 2 2 (7) A valid, quality-assured hour of moisture data (in percent H 2 (8) A valid, quality-assured hour of heat input rate data (in mmBtu/hr) has not been measured and recorded for a unit from a certified flow monitor and a certified diluent (CO 2 2 (b) However, the owner or operator shall have no need to provide substitute data according to the missing data procedures in this subpart if the owner or operator uses SO 2 2 X 2 X (c) When the certified primary monitor is not operating or out-of-control, then data recorded for an affected unit from a certified backup continuous emission monitor or backup reference method monitoring system are used, as if such data were from the certified primary monitor, to calculate monitor data availability in § 75.32, and to provide the quality-assured data used in the missing data procedures in §§ 75.31 and 75.33, such as the “hour after” value. (d) The owner or operator shall comply with the applicable provisions of this paragraph during hours in which a unit with an SO 2 (1) Whenever a unit with an SO 2 2 2 2 2 (2) Whenever a unit with an SO 2 2 2 2 (3) The owner or operator of a unit with an SO 2 2 2 2 2 2 (4) During all hours in which a unit with an SO 2 2 2 2 2 [60 FR 26528, 26566, May 17, 1995, as amended at 61 FR 59160, Nov. 20, 1996; 64 FR 28600, May 26, 1999; 67 FR 40433, June 12, 2002] § 75.31 Initial missing data procedures. (a) During the first 720 quality-assured monitor operating hours following initial certification of the required SO 2 2 2 i.e., X X (b) SO 2 2 2 2 2 2 2 2 2 (1) Whenever prior quality-assured data exist, the owner or operator shall substitute, by means of the data acquisition and handling system, for each hour of missing data, the average of the hourly SO 2 2 2 (2) Whenever no prior quality assured SO 2 2 2 2 2 2 X X (c) Volumetric flow and NO X emission rate or NO X concentration data (load ranges or operational bins used). X X X X (1) Whenever prior quality-assured data exist in the load range (or operational bin) corresponding to the operating load (or operating conditions) at the time of the missing data period, the owner or operator shall substitute, by means of the automated data acquisition and handling system, for each hour of missing data, the arithmetic average of all of the prior quality-assured hourly flow rates, NO X X X X (2) This paragraph (c)(2) does not apply to non-load-based units using operational bins. Whenever no prior quality-assured flow or NO X X X X (3) Whenever no prior quality-assured flow rate or NO X X X X X X X (d) Non-load-based volumetric flow and NO X emission rate or NO X concentration data (operational bins not used X X X (1) Whenever prior quality-assured data exist at the time of the missing data period, the owner or operator shall substitute, by means of the automated data acquisition and handling system, for each hour of missing data, the arithmetic average of all of the prior quality-assured hourly average flow rates or NO X X (2) Whenever no prior quality-assured flow rate, NO X X X X [64 FR 28601, May 26, 1999, as amended at 67 FR 40433, June 12, 2002; 70 FR 28680, May 18, 2005; 73 FR 4346, Jan. 24, 2008; 76 FR 17311, Mar. 28, 2011] § 75.32 Determination of monitor data availability for standard missing data procedures. (a) Following initial certification of the required SO 2 2 2 i.e., X X (1) Prior to completion of 8,760 unit or stack operating hours following initial certification, the owner or operator shall, for the purpose of applying the standard missing data procedures of § 75.33, use Equation 8 to calculate, hourly, percent monitor data availability. (2) Upon completion of 8,760 unit (or stack) operating hours following initial certification and thereafter, the owner or operator shall, for the purpose of applying the standard missing data procedures of § 75.33, use Equation 9 to calculate hourly, percent monitor data availability. Notwithstanding this requirement, if three years (26,280 clock hours) have elapsed since initial certification and fewer than 8,760 unit or stack operating hours have been accumulated, the owner or operator shall begin using a modified version of Equation 9, as described in paragraph (a)(3) of this section. (3) When calculating percent monitor data availability using Equation 8 or 9, the owner or operator shall include all unit operating hours, and all monitor operating hours for which quality-assured data were recorded by a certified primary monitor; a certified redundant or non-redundant backup monitor or a reference method for that unit; or by an approved alternative monitoring system under subpart E of this part. No hours from more than three years (26,280 clock hours) earlier shall be used in Equation 9. For a unit that has accumulated fewer than 8,760 unit operating hours in the previous three years (26,280 clock hours), replace the words “during previous 8,760 unit operating hours” in the numerator of Equation 9 with “in the previous three years” and replace “8,760” in the denominator of Equation 9 with “total unit operating hours in the previous three years.” The owner or operator of a unit with an SO 2 2 2 (b) The monitor data availability shall be calculated for each hour during each missing data period. The owner or operator shall record the percent monitor data availability for each hour of each missing data period to implement the missing data substitution procedures. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26529, 26567, May 17, 1995; 61 FR 59160, Nov. 20, 1996; 64 FR 28602, May 26, 1999; 67 FR 40434, June 12, 2002; 70 FR 28680, May 18, 2005; 73 FR 4346, Jan. 24, 2008; 76 FR 17311, Mar. 28, 2011] § 75.33 Standard missing data procedures for SO 2 X (a) Following initial certification of the required SO 2 X i.e. 2 X X 2 X (b) SO 2 concentration data. 2 (1) If the monitor data availability is equal to or greater than 95.0 percent, the owner or operator shall calculate substitute data by means of the automated data acquisition and handling system for that hour of the missing data period according to the following procedures: (i) For a missing data period less than or equal to 24 hours, substitute the average of the hourly SO 2 2 (ii) For a missing data period greater than 24 hours, substitute the greater of: (A) The 90th percentile hourly SO 2 2 (B) The average of the hourly SO 2 2 (2) If the monitor data availability is at least 90.0 percent but less than 95.0 percent, the owner or operator shall calculate substitute data by means of the automated data acquisition and handling system for that hour of the missing data period according to the following procedures: (i) For a missing data period of less than or equal to 8 hours, substitute the average of the hourly SO 2 2 (ii) For a missing data period of more than 8 hours, substitute the greater of: (A) the 95th percentile hourly SO 2 2 (B) The average of the hourly SO 2 2 (3) If the monitor data availability is at least 80.0 percent but less than 90.0 percent, the owner or operator shall substitute for that hour of the missing data period the maximum hourly SO 2 2 (4) If the monitor data availability is less than 80.0 percent, the owner or operator shall substitute for that hour of the missing data period the maximum potential SO 2 (5) For units that combust more than one type of fuel, the owner or operator may opt to implement the missing data routines in paragraphs (b)(1) through (b)(4) of this section on a fuel-specific basis. If this option is selected, the owner or operator shall document this in the monitoring plan required under § 75.53. (6) Use the following guidelines to implement paragraphs (b)(1) through (b)(4) of this section on a fuel-specific basis: (i) Separate the historical, quality-assured SO 2 (ii) For units that co-fire different types of fuel, either group the co-fired hours with the historical data for the fuel with the highest SO 2 (iii) For the purposes of providing substitute data under paragraph (b)(4) of this section, determine a separate, fuel-specific maximum potential SO 2 2 (iv) For missing data periods that require 720-hour (or, if applicable, 3-year) lookbacks, use historical data for the type of fuel combusted during each hour of the missing data period to determine the appropriate substitute data value for that hour. For co-fired missing data hours, if the historical data are separated into single-fuel and co-fired hours, use co-fired data to provide the substitute data values. Otherwise, use data for the fuel with the highest SO 2 (7) Table 1 summarizes the provisions of paragraphs (b)(1) through (b)(6) of this section. (c) Volumetric flow rate, NO X emission rate and NO X concentration data. X i.e. X X X (1) If the monitor data availability is equal to or greater than 95.0 percent, the owner or operator shall calculate substitute data by means of the automated data acquisition and handling system for that hour of the missing data period according to the following procedures: (i) For a missing data period less than or equal to 24 hours, substitute, as applicable, for each missing hour, the arithmetic average of the flow rates or NO X X (ii) For a missing data period greater than 24 hours, substitute, as applicable, for each missing hour, the greater of: (A) The 90th percentile hourly flow rate or the 90th percentile NO X X (B) The average of the recorded hourly flow rates, NO X X (2) If the monitor data availability is at least 90.0 percent but less than 95.0 percent, the owner or operator shall calculate substitute data by means of the automated data acquisition and handling system for that hour of the missing data period according to the following procedures: (i) For a missing data period of less than or equal to 8 hours, substitute, as applicable, the arithmetic average hourly flow rate or NO X X (ii) For a missing data period greater than 8 hours, substitute, as applicable, for each missing hour, the greater of: (A) The 95th percentile hourly flow rate or the 95th percentile NO X X (B) The average of the hourly flow rates, NO X X (3) If the monitor data availability is at least 80.0 percent but less than 90.0 percent, the owner or operator shall, by means of the automated data acquisition and handling system, substitute, as applicable, for that hour of the missing data period, the maximum hourly flow rate or the maximum hourly NO X X (4) If the monitor data availability is less than 80.0 percent, the owner or operator shall substitute, as applicable, for that hour of the missing data period, the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to this part, or the maximum NO X X (5) This paragraph, (c)(5), does not apply to non-load-based, affected units using operational bins. Whenever no prior quality-assured flow rate data, NO X X X X (6) Whenever no prior quality-assured flow rate data, NO X X X X (7) This paragraph (c)(7) does not apply to affected units using non-load-based operational bins. For units that combust more than one type of fuel, the owner or operator may opt to implement the missing data routines in paragraphs (c)(1) through (c)(6) of this section on a fuel-specific basis. If this option is selected, the owner or operator shall document this in the monitoring plan required under § 75.53. (8) This paragraph, (c)(8), does not apply to affected units using non-load-based operational bins. Use the following guidelines to implement paragraphs (c)(1) through (c)(6) of this section on a fuel-specific basis: (i) Separate the historical, quality-assured NO X X (ii) For units that co-fire different types of fuel, either group the co-fired hours with the historical data for the fuel with the highest NO X X (iii) For the purposes of providing substitute data under paragraph (c)(4) of this section, a separate, fuel-specific maximum potential concentration (MPC), maximum potential NO X X X X (iv) For missing data periods that require 2,160-hour (or, if applicable, 3-year) lookbacks, use historical data for the type of fuel combusted during each hour of the missing data period to determine the appropriate substitute data value for that hour. For co-fired missing data hours, if the historical data are separated into single-fuel and co-fired hours, use co-fired data to provide the substitute data values. Otherwise, use data for the fuel with the highest NO X X Table 1—Missing Data Procedure for SO 2 2 2 2 Trigger conditions Calculation routines Monitor data availability (percent) Duration (N) of CEMS outage 2 Method Lookback period 95 or more N ≤24 Average HB/HA. N >24 For SO 2 2 2 Average HB/HA. 90th percentile 720 hours. * For O 2 2 X HB/HA. 10th percentile 720 hours. * 90 or more, but below 95 N ≤8 Average HB/HA. N >8 For SO 2 2 2 Average HB/HA. 95th percentile 720 hours. * For O 2 2 X Average HB/HA. 5th Percentile 720 hours. * 80 or more, but below 90 N >0 For SO 2 2 2 Maximum value 1 720 hours. * For O 2 2 X Minimum value 1 720 hours. * Below 80 N >0 Maximum potential concentration 3 2 2 2 or Minimum potential concentration or % (for O 2 2 X None. HB/HA = hour before and hour after the CEMS outage. * Quality-assured, monitor operating hours, during unit operation. May be either fuel-specific or non-fuel-specific. For units that report data only for the ozone season, include only quality assured monitor operating hours within the ozone season in the lookback period. Use data from no earlier than 3 years prior to the missing data period. 1 2 2 3 2 2 X X ** Use this algorithm for moisture only X Table 2—Load-Based Missing Data Procedure for NO X X Trigger conditions Calculation routines Monitor data availability Duration (N) of CEMS outage 2 Method Lookback period Load ranges 95 or more N ≤24 Average 2,160 hours * Yes. N >24 The greater of: Average HB/HA No. 90th percentile 2,160 hours * Yes. 90 or more, but below 95 N ≤8 Average 2,160 hours * Yes. N >8 The greater of: Average HB/HA No. 95th percentile 2,160 hours * Yes. 80 or more, but below 90 N >0 Maximum value 1 2,160 hours * Yes. Below 80 N >0 Maximum potential NO X 3 X 3 None No. HB/HA = hour before and hour after the CEMS outage. * Quality-assured, monitor operating hours, using data at the corresponding load range (“load bin”) for each hour of the missing data period. May be either fuel-specific or non-fuel-specific. For units that report data only for the ozone season, include only quality assured monitor operating hours within the ozone season in the lookback period. Use data from no earlier than three years prior to the missing data period. 1 X X X 2 3 X X X (9) The load-based provisions of paragraphs (c)(1) through (c)(8) of this section are summarized in Table 2 of this section. The non-load-based provisions for volumetric flow rate, found in paragraphs (c)(1) through (c)(4), and (c)(6) of this section, are presented in Table 4 of this section. (d) Non-load-based X X concentration data. X X X X (1) If the monitor data availability is equal to or greater than 95.0 percent, the owner or operator shall calculate substitute data by means of the automated data acquisition and handling system for that hour of the missing data period according to the following procedures: (i) For a missing data period less than or equal to 24 hours, substitute, as applicable, for each missing hour, the arithmetic average of the NO X X (A) The previous 2,160 quality-assured monitor operating hours, or (B) The previous 2,160 quality-assured monitor operating hours at the corresponding operational bin, if operational bins, as defined in section 3 of appendix C to this part, are used. (ii) For a missing data period greater than 24 hours, substitute, for each missing hour, the 90th percentile NO X X (2) If the monitor data availability is at least 90.0 percent but less than 95.0 percent, the owner or operator shall calculate substitute data by means of the automated data acquisition and handling system for that hour of the missing data period according to the following procedures: (i) For a missing data period of less than or equal to eight hours, substitute, as applicable, the arithmetic average of the hourly NO X X (ii) For a missing data period greater than eight hours, substitute, for each missing hour, the 95th percentile hourly flow rate or the 95th percentile NO X X (3) If the monitor data availability is at least 80.0 percent but less than 90.0 percent, the owner or operator shall, by means of the automated data acquisition and handling system, substitute, as applicable, for that hour of the missing data period, the maximum hourly NO X X (4) If the monitor data availability is less than 80.0 percent, the owner or operator shall substitute, as applicable, for that hour of the missing data period, the maximum NO X X X X (5) If operational bins are used and no prior quality-assured NO X X X X (6) Table 3 of this section summarizes the provisions of paragraphs (d)(1) through (d)(5) of this section. (e) Non-load-based volumetric flow rate data. (2) If operational bins are not used, modify the procedures in paragraph (c) of this section as follows: (i) In paragraphs (c)(1) through (c)(3), the words “previous 2,160 quality-assured monitor operating hours” shall apply rather than “previous 2,160 quality-assured monitor operating hours at the corresponding unit load range or operational bin, as determined using the procedure in appendix C to this part;” (ii) The last sentence in paragraph (c)(4) does not apply; (iii) Paragraphs (c)(5), (c)(7), and (c)(8) are not applicable; and (iv) In paragraph (c)(6), the words, “for either the corresponding load range (or a higher load range) or at the corresponding operational bin” do not apply. (3) Table 4 of this section summarizes the provisions of paragraphs (e)(1) and (e)(2) of this section. Tables 3 and 4 follow: Table 3—Non-load-based Missing Data Procedure for NO X X Trigger conditions Calculation routines Monitor data availability Duration (N) of CEMS outage 1 Method Lookback period 95 or more N ≤24 Average 2,160 hours. * N >24 90th percentile 2,160 hours. * 90 or more, but below 95 N ≤8 Average 2,160 hours. * N >8 95th percentile 2,160 hours. * 80 or more, but below 90 N >0 Maximum value 3 2,160 hours. * Below 80, or operational bin indeterminable N >0 Maximum potential NO X 2 X 2 None. * If operational bins are used, the lookback period is 2,160 quality-assured, monitor operating hours, and data at the corresponding operational bin are used to provide substitute data values. If operational bins are not used, the lookback period is the previous 2,160 quality-assured monitor operating hours. For units that report data only for the ozone season, include only quality-assured monitor operating hours within the ozone season in the lookback period. Use data from no earlier than three years prior to the missing data period. 1 2 X X X 3 X X X Table 4—Non-load-based Missing Data Procedure for Flow Rate CEMS Trigger conditions Calculation routines Monitor data availability (percent) Duration (N) of CEMS outage 1 Method Lookback 95 or more N ≤24 Average 2160 hours* N >24 The greater of: 90 or more, but below 95 N ≤8 Average 2160 hours* N >8 The greater of: 80 or more, but below 90 N >0 Maximum value 2160 hours* Below 80, or operational bin indeterminable N >0 Maximum potential flow rate None * If operational bins are used, the lookback period is the previous 2,160 quality-assured, monitor operating hours and data at the corresponding operational bin are used to provide substitute data values. If operational bins are not used, the lookback period is the previous 2,160 quality-assured, monitor operating hours. For units that report data only for the ozone season, include only quality-assured monitor operating hours within the ozone season in the lookback period. Use data from no earlier than three years prior to the missing data period. 1 [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26529, May 17, 1995; 61 FR 25582, May 22, 1996; 64 FR 28602, May 26, 1999; 67 FR 40434, June 12, 2002; 67 FR 53505, Aug. 16, 2002; 67 FR 57274, Sept. 9, 2002; 70 FR 28680, May 18, 2005; 73 FR 4346, Jan. 24, 2008; 76 FR 17311, Mar. 28, 2011] § 75.34 Units with add-on emission controls. (a) The owner or operator of an affected unit equipped with add-on SO 2 X 2 X (1) The owner or operator may use the missing data substitution procedures specified in §§ 75.31 through 75.33 to provide substitute data for any missing data hour(s) in which the add-on emission controls are documented to be operating properly, as described in the quality assurance/quality control program for the unit, required by section 1 in appendix B of this part. To provide the necessary documentation, the owner or operator shall, for each missing data period, record parametric data to verify the proper operation of the SO 2 X 2 X X X 2 2 X 2 X 2 X (2) This paragraph, (a)(2), applies only to a unit which, as provided in § 75.74(a) or § 75.74(b)(1), reports NO X X X (i) The historical, quality-assured NO X X (ii) For the purposes of the missing data lookback periods described under §§ 75.33 (c)(1), (c)(2), (c)(3) and (c)(5) of this section, the substitute data values shall be taken from the appropriate database, depending on the date(s) and hour(s) of the missing data period. That is, if the missing data period occurs inside the ozone season, the ozone season data shall be used to provide substitute data. If the missing data period occurs outside the ozone season, data from outside the ozone season shall be used to provide substitute data. (iii) A missing data period that begins outside the ozone season and continues into the ozone season shall be considered to be two separate missing data periods, one ending on April 30, hour 23, and the other beginning on May 1, hour 00; (iv) For missing data hours outside the ozone season, the procedures of § 75.33 may be applied unconditionally, i.e., documentation of the operational status of the emission controls is not required in order to apply the standard missing data routines. (3) For each missing data hour in which the percent monitor data availability for SO 2 X i.e. (i) Replace the maximum SO 2 (ii) Replace the maximum NO X X X (4) The designated representative may petition the Administrator under § 75.66 for approval of site-specific parametric monitoring procedure(s) for calculating substitute data for missing SO 2 X X (5) For each missing data hour in which the percent monitor data availability for SO 2 X i.e. (i) The maximum expected SO 2 2 (ii) The maximum expected NO X X (iii) The maximum controlled hourly NO X X (iv) For the purposes of implementing the missing data options in paragraphs (a)(5)(i) through (a)(5)(iii) of this section, the maximum expected SO 2 X X X X X (b) For an affected unit equipped with add-on SO 2 2 2 (1) Where the monitor data availability is 90.0 percent or more for an outlet SO 2 (2) Where the monitor data availability for an outlet SO 2 (c) For an affected unit with NO X X X (1) Where monitor data availability for a NO X (2) Where monitor data availability for a NO X (d) In order to implement the options in paragraphs (a)(1), (a)(3) and (a)(5) of this section; and §§ 75.31(c)(3) and 75.72(c)(3), the owner or operator shall keep records of information as described in § 75.58(b)(3) to verify the proper operation of all add-on SO 2 X 2 X [60 FR 26567, May 17, 1995, as amended at 61 FR 59160, Nov. 20, 1996; 64 FR 28604, May 26, 1999; 67 FR 40438, June 12, 2002; 73 FR 4348, Jan. 24, 2008; 76 FR 17312, Mar. 28, 2011] § 75.35 Missing data procedures for CO 2 (a) The owner or operator of a unit with a CO 2 2 2 2 2 (b) During the first 720 quality-assured monitor operating hours following initial certification at a particular unit or stack location ( i.e. 2 2 2 (c) [Reserved] (d) Upon completion of 720 quality-assured monitor operating hours using the initial missing data procedures of § 75.31(b), the owner or operator shall provide substitute data for CO 2 2 2 2 2 2 2 2 2 [67 FR 40439, June 12, 2002] § 75.36 Missing data procedures for heat input rate determinations. (a) When hourly heat input rate is determined using a flow monitoring system and a diluent gas (O 2 2 2 2 (b) During the first 720 quality-assured monitor operating hours following initial certification at a particular unit or stack location ( i.e., 2 2 2 2 (c) [Reserved] (d) Upon completion of 720 quality-assured monitor operating hours using the initial missing data procedures of § 75.31(b), the owner or operator shall provide substitute data for CO 2 2 2 2 2 2 2 2 2 2 2 2 [60 FR 26530, May 17, 1995, as amended at 64 FR 28604, May 26, 1999; 67 FR 40439, June 12, 2002] § 75.37 Missing data procedures for moisture. (a) The owner or operator of a unit with a continuous moisture monitoring system shall substitute for missing moisture data using the procedures of this section. (b) Where no prior quality-assured moisture data exist, substitute the minimum potential moisture percentage, from section 2.1.5 of appendix A to this part, except when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is used to determine NO X X (c) During the first 720 quality-assured monitor operating hours following initial certification at a particular unit or stack location ( i.e. (d) Upon completion of the first 720 quality-assured monitor operating hours following initial certification, the owner or operator shall provide substitute data for moisture as follows: (1) Unless Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is used to determine NO X 2 2 2 2 (2) When Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is used to determine NO X (i) Provided that none of the following equations is used to determine SO 2 2 2 2 2 (ii) If any of the following equations is used to determine SO 2 2 [64 FR 28604, May 26, 1999, as amended at 67 FR 40439, June 12, 2002] §§ 75.38-75.39 [Reserved] Subpart E—Alternative Monitoring Systems § 75.40 General demonstration requirements. (a) The owner or operator of an affected unit, or the owner or operator of an affected unit and representing a class of affected units which meet the criteria specified in § 75.47, required to install a continuous emission monitoring system may apply to the Administrator for approval of an alternative monitoring system (or system component) to determine average hourly emission data for SO 2 X (b) The requirements of this subpart shall be met by the alternative monitoring system when compared to a contemporaneously operating, fully certified continuous emission monitoring system or a contemporaneously operating reference method, where the appropriate reference methods are listed in § 75.22. § 75.41 Precision criteria. (a) Data collection and analysis. (1) Data from the alternative monitoring system and the continuous emission monitoring system shall be collected and paired in a manner that ensures each pair of values applies to hourly average emissions during the same hour. (2) An alternative monitoring system that directly measures emissions shall have probes or other measuring devices in locations that are in proximity to the continuous emission monitoring system and shall provide data on the same parameters as those measured by the continuous emission monitoring system. Data from the alternative monitoring system shall meet the statistical tests for precision in paragraph (c) of this section and the t-test for bias in appendix A of this part. (3) An alternative monitoring system that indirectly quantifies emission values by measuring inputs, operating characteristics, or outputs and then applying a regression or another quantitative technique to estimate emissions, shall meet the statistical tests for precision in paragraph (c) of this section and the t-test for bias in appendix A of this part. (4) For flow monitor alternatives, the alternative monitoring system must provide sample data for each of three different exhaust gas velocities while the unit or units, if more than one unit exhausts into the stack or duct, is burning its primary fuel at: (i) A frequently used low operating level, selected within the range between the minimum safe and stable operating level and 50 percent of the maximum operating level, (ii) A frequently used high operating level, selected within the range between 80 percent of the maximum operating level and the maximum operating level, and (iii) The normal operating level, or an evenly spaced intermediary level between low and high levels used if the normal operating level is within a specified range (10.0 percent of the maximum operating level), of either paragraphs (a)(4) (i) or (ii) of this section. (5) For pollutant concentration monitor alternatives, the alternative monitoring system shall provide sample data for the primary fuel supply and for all alternative fuel supplies that have significantly different sulfur content. (6) For the normal unit operating level and primary fuel supply, paired hourly sample data shall be provided for at least 90.0 percent of the hours during 720 unit operating hours. For each of the remaining two operating levels for flow monitor alternatives, and for each alternative fuel supply for pollutant concentration monitor alternatives, paired hourly sample data shall be provided for at least 24 successive unit operating hours. (7) The owner or operator shall not use missing data substitution procedures to provide sample data. (8) If the collected data meet the requirements of the F-test, the correlation test, and the t-test at one or more, but not all, of the operating levels or fuel supplies, the owner or operator may elect to continue collecting the paired data for up to 1,440 additional operating hours and repeat the statistical tests using the data for the entire 30- to 90-day period. (9) The owner or operator shall provide two separate time series data plots for the data at each operating level or fuel supply described in paragraphs (a)(4) and (a)(5) of this section. Each data plot shall have a horizontal axis that represents the clock hour and calendar date of the readings and shall contain a separate data point for every hour for the duration of the performance evaluation. The data plots shall show the following: (i) Percentage difference versus time where the vertical axis represents the percentage difference between each paired hourly reading generated by the continuous emission monitoring system (or reference method) and the alternative emission monitoring system as calculated using the following equation: (Eq. 10) where, Δ e = Percentage difference between the readings generated by the alternative monitoring system and the continuous emission monitoring system. e p e v (ii) Alternative monitoring system readings and continuous emission monitoring system (or reference method) readings versus time where the vertical axis represents hourly pollutant concentrations or volumetric flow, as appropriate, and two different symbols are used to represent the readings from the alternative monitoring system and the continuous emission monitoring system (or reference method), respectively. (b) Data screening and calculation adjustments. (1) Lognormality. (i) Apply the log transformation to each measured value of either the certified continuous emissions monitoring system or certified flow monitor, using the following equation: l v v (Eq. 11) where, e v l v and to each measured value, e p p l p p (Eq. 12) where, e p l p (ii) Separately test each set of transformed data, l v l p (A) Shapiro-Wilk test; (B) Histogram of the transformed data; and (C) Quantile-Quantile plot of the transformed data. (iii) The transformed data in a data set will be considered normally distributed if all of the following conditions are satisfied: (A) The Shapiro-Wilk test statistic, W, is greater than or equal to 0.75 or is not statistically significant at α = 0.05. (B) The histogram of the data is unimodal and symmetric. (C) The Quantile-Quantile plot is a diagonal straight line. (iv) If both of the transformed data sets, l v l p l v l p (v) If the transformed data are used in the statistical tests in paragraph (c) of this section and in appendix A of this part, the owner or operator shall provide the following: (A) Copy of the original measured values and the corresponding transformed data in printed and electronic format. (B) Printed copy of the test results and plots described in paragraphs (b)(1) (i) through (iii) of this section. (2) Time dependency (autocorrelation). (i) Calculate the degree of autocorrelation of the data on their LAG1 values, where the degree of autocorrelation is represented by the Pearson autocorrelation coefficient, ρ, computed from an AR(1) autoregression model, such that: (Eq. 13) where, x′ i i. x″ i i. COV(x′ i i i (Eq. 14) where, n i i s x i x i (Eq. 15) where, s x i x i (Eq. 16) where, x x i (Eq. 17) where, x x i (Eq. 18) where, (ii) The data in a data set will be considered autocorrelated if the autocorrelation coefficient, ρ, is significant at the 5 percent significance level. To determine if this condition is satisfied, calculate Z using the following equation: (Eq. 19) If Z a (iii) If the data in a data set satisfy the conditions for autocorrelation, specified in paragraph (b)(2)(ii) of this section, the variance of the data, S 2 S 2 adj VIF S 2 (Eq. 20) where, S 2 VIF (Eq. 21) S 2 adj (iv) The procedures described in paragraphs (b)(2)(i)-(iii) of this section may be separately applied to the following data sets in order to derive distinct autocorrelation coefficients and variance inflation factors for each data set: (A) The set of measured hourly values, e v (B) The set of hourly values, e p (C) The set of hourly differences, e v p v p (v) For any data set, listed in paragraph (b)(2)(iv) of this section, that satisfies the conditions for autocorrelation specified in paragraph (b)(2)(ii) of this section, the owner or operator may adjust the variance of that data set, using equation 20 of this section. (A) The adjusted variance may be used in place of the corresponding original variance, as calculated using equation 23 of this section, in the F-test (Equation 24) of this section. (B) In place of the standard error of the mean, in the bias test Equation A-9 of appendix A of this part the following adjusted standard error of the mean may be used: (Eq. 22)where (vi) For each data set in which a variance adjustment is used, the owner or operator shall provide the following: (A) All values in the data set in printed and electronic format. (B) Values of the autocorrelation coefficient, its level of significance, the variance inflation factor, and the unadjusted original and adjusted values found in equations 20 and 22 of this section. (C) Equation and related statistics of the AR(1) autoregression model of the data set. (D) Printed documentation of the intermediate calculations used to derive the autocorrelation coefficient and the Variance Inflation Factor. (c) Statistical Tests. (1) F-test. (i) Calculate the variance of the certified continuous emission monitoring system or certified flow monitor as applicable, S v p (Eq. 23) where, e i e m n = Total number of paired samples. (ii) Determine if the variance of the proposed method is significantly different from that of the certified continuous emission monitoring system or certified flow monitor, as applicable, by calculating the F-value using the following equation. (Eq. 24) Compare the experimental F-value with the critical value of F at the 95-percent confidence level with n-1 degrees of freedom. The critical value is obtained from a table for F-distribution. If the calculated F-value is greater than the critical value, the proposed method is unacceptable. (2) Correlation analysis. (i) Plot each of the paired emissions readings as a separate point on a graph where the vertical axis represents the value (pollutant concentration or volumetric flow, as appropriate) generated by the alternative monitoring system and the horizontal axis represents the value (pollutant concentration or volumetric flow, as appropriate) generated by the continuous emission monitoring system (or reference method). On the graph, draw a horizontal line representing the mean value, e p v (Eq. 25) (Eq. 26) where, e p e v n = Total number of hours for which data were generated for the tests. A separate graph shall be produced for the data generated at each of the operating levels or fuel supplies described in paragraphs (a)(4) and (a)(5) of this section. (ii) Use the following equation to calculate the coefficient of correlation, r, between the emissions data from the alternative monitoring system and the continuous emission monitoring system using all hourly data for which paired values were available from both monitoring systems. (Eq. 27) (iii) If the calculated r-value is less than 0.8, the proposed method is unacceptable. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26530, May 17, 1995; 60 FR 40296, Aug. 8, 1995; 67 FR 40440, June 12, 2002] § 75.42 Reliability criteria. To demonstrate reliability equal to or better than the continuous emission monitoring system, the owner or operator shall demonstrate that the alternative monitoring system is capable of providing valid 1-hr averages for 95.0 percent or more of unit operating hours over a 1-yr period and that the system meets the applicable requirements of appendix B of this part. § 75.43 Accessibility criteria. To demonstrate accessibility equal to or better than the continuous emission monitoring system, the owner or operator shall provide reports and onsite records of emission data to demonstrate that the alternative monitoring system provides data meeting the requirements of subparts F and G of this part. § 75.44 Timeliness criteria. To demonstrate timeliness equal to or better than the continuous emission monitoring system, the owner or operator shall demonstrate that the alternative monitoring system can meet the requirements of subparts F and G of this part; can provide a continuous, quality-assured, permanent record of certified emissions data on an hourly basis; and can issue a record of data for the previous day within 24 hours. § 75.45 Daily quality assurance criteria. The owner or operator shall either demonstrate that daily tests equivalent to those specified in appendix B of this part can be performed on the alternative monitoring system or demonstrate and document that such tests are unnecessary for providing quality-assured data. § 75.46 Missing data substitution criteria. The owner or operator shall demonstrate that all missing data can be accounted for in a manner consistent with the applicable missing data procedures in subpart D of this part. § 75.47 Criteria for a class of affected units. (a) The owner or operator of an affected unit may represent a class of affected units for the purpose of applying to the Administrator for a class-approved alternative monitoring system. (b) The owner or operator of an affected unit representing a class of affected units shall provide the following information: (1) A description of the affected unit and how it appropriately represents the class of affected units; (2) A description of the class of affected units, including data describing all of the affected units that will comprise the class. [60 FR 40297, Aug. 8, 1995, as amended at 76 FR 17312, Mar. 28, 2011] § 75.48 Petition for an alternative monitoring system. (a) The designated representative shall submit the following information in the application for certification or recertification of an alternative monitoring system. (1) Source identification information. (2) A description of the alternative monitoring system. (3) Data, calculations, and results of the statistical tests, specified in § 75.41(c) of this part, including: (i) Date and hour. (ii) Hourly test data for the alternative monitoring system at each required operating level and fuel type. The fuel type, operating level and gross unit load shall be recorded. (iii) Hourly test data for the continuous emissions monitoring system at each required operating level and fuel type. The fuel type, operating level and gross unit load shall be recorded. (iv) Arithmetic mean of the alternative monitoring system measurement values, as specified in Equation 25 in § 75.41(c) of this part, of the continuous emission monitoring system values, as specified in Equation 26 in § 75.41(c) of this part, and of their differences. (v) Standard deviation of the difference, as specified in equation A-8 in appendix A of this part. (vi) Confidence coefficient, as specified in equation A-9 in appendix A of this part. (vii) The bias test results as specified in § 7.6.4 in appendix A of this part. (viii) Variance of the measured values for the alternative monitoring system and of the measured values for the continuous emission monitoring system, as specified in Equation 23 in § 75.41(c) of this part. (ix) F-statistic, as specified in Equation 24 in § 75.41(c) of this part. (x) Critical value of F at the 95-percent confidence level with n-1 degrees of freedom. (xi) Coefficient of correlation, r, as specified in Equation 27 in § 75.41(c) of this part. (4) Data plots, specified in §§ 75.41(a)(9) and 75.41(c)(2)(i) of this part. (5) Results of monitor reliability analysis. (6) Results of monitor accessibility analysis. (7) Results of monitor timeliness analysis. (8) A detailed description of the process used to collect data, including location and method of ensuring an accurate assessment of operating hourly conditions on a real-time basis. (9) A detailed description of the operation, maintenance, and quality assurance procedures for the alternative monitoring system as required in appendix B of this part. (10) A description of methods used to calculate heat input or diluent gas concentration, if applicable. (11) Results of tests and measurements (including the results of all reference method field test sheets, charts, laboratory analyses, example calculations, or other data as appropriate) necessary to substantiate that the alternative monitoring system is equivalent in performance to an appropriate, certified operating continuous emission monitoring system. (b) [Reserved] [60 FR 40297, Aug. 8, 1995, as amended at 64 FR 28605, May 26, 1999] Subpart F—Recordkeeping Requirements §§ 75.50-75.52 [Reserved] § 75.53 Monitoring plan. (a) General provisions. (2) The owner or operator of an affected unit shall prepare and maintain a monitoring plan. Except as provided in paragraphs (f) or (h) of this section (as applicable), a monitoring plan shall contain sufficient information on the continuous emission or opacity monitoring systems, excepted methodology under § 75.19, or excepted monitoring systems under appendix D or E to this part and the use of data derived from these systems to demonstrate that all unit SO 2 X 2 (b) Whenever the owner or operator makes a replacement, modification, or change in the certified CEMS, continuous opacity monitoring system, excepted methodology under § 75.19, excepted monitoring system under appendix D or E to this part, or alternative monitoring system under subpart E of this part, including a change in the automated data acquisition and handling system or in the flue gas handling system, that affects information reported in the monitoring plan (e.g., a change to a serial number for a component of a monitoring system), then the owner or operator shall update the monitoring plan, by the applicable deadline specified in § 75.62 or elsewhere in this part. (c)-(d) [Reserved] (e) Contents of the monitoring plan. (1) Electronic. (A) Short name; (B) Classification of the unit as one of the following: Phase I (including substitution or compensating units), Phase II, new, or nonaffected; (C) Type of boiler (or boilers for a group of units using a common stack); (D) Type of fuel(s) fired by boiler, fuel type start and end dates, primary/secondary/emergency/startup fuel indicator, and, if more than one fuel, the fuel classification of the boiler; (E) Type(s) of emission controls for SO 2 X (F) Maximum hourly heat input capacity; (G) Date of first commercial operation; (H) Unit retirement date (if applicable); (I) Maximum hourly gross load (in MW, rounded to the nearest MW, or steam load in 1000 lb/hr, rounded to the nearest 100 lb/hr); (J) Identification of all units using a common stack; (K) Activation date for the stack/pipe; (L) Retirement date of the stack/pipe (if applicable); and (M) Indicator of whether the stack is a bypass stack. (ii) For each unit and parameter required to be monitored, identification of monitoring methodology information, consisting of monitoring methodology, type of fuel associated with the methodology, primary/secondary methodology indicator, missing data approach for the methodology, methodology start date, and methodology end date (if applicable). (iii) The following information: (A) Program(s) for which the EDR is submitted; (B) Unit classification; (C) Reporting frequency; (D) Program participation date; (E) State regulation code (if applicable); and (F) State or local regulatory agency code. (iv) Identification and description of each monitoring system component (including each monitor and its identifiable components, such as analyzer and/or probe) in the CEMS ( e.g., 2 X e.g., (A) Manufacturer, model number and serial number; (B) Component/system identification code assigned by the utility to each identifiable monitoring component (such as the analyzer and/or probe). Each code shall use a three-digit format, unique to each monitoring component and unique to each monitoring system; (C) Designation of the component type and method of sample acquisition or operation, (e.g., in situ pollutant concentration monitor or thermal flow monitor); (D) Designation of the system as a primary, redundant backup, non-redundant backup, data backup, or reference method backup system, as provided in § 75.10(e); (E) First and last dates the system reported data; (F) Status of the monitoring component; and (G) Parameter monitored. (v) Identification and description of all major hardware and software components of the automated data acquisition and handling system, including: (A) Hardware components that perform emission calculations or store data for quarterly reporting purposes (provide the manufacturer and model number); and (B) Software components (provide the identification of the provider and model/version number). (vi) Explicit formulas for each measured emission parameter, using component/system identification codes for the primary system used to measure the parameter that links CEMS or excepted monitoring system observations with reported concentrations, mass emissions, or emission rates, according to the conversions listed in appendix D or E to this part. Formulas for backup monitoring systems are required only if different formulas for the same parameter are used for the primary and backup monitoring systems (e.g., if the primary system measures pollutant concentration on a different moisture basis from the backup system). The formulas must contain all constants and factors required to derive mass emissions or emission rates from component/system code observations and an indication of whether the formula is being added, corrected, deleted, or is unchanged. Each emissions formula is identified with a unique three digit code. The owner or operator of a low mass emissions unit for which the owner or operator is using the optional low mass emissions excepted methodology in § 75.19(c) is not required to report such formulas. (vii) Inside cross-sectional area (ft 2 (viii) Stack exit height (ft) above ground level and ground level elevation above sea level. (ix) Monitoring location identification, facility identification code as assigned by the Administrator for use under the Acid Rain Program or this part, and the following information, as reported to the Energy Information Administration (EIA): facility identification number, flue identification number, boiler identification number, ARP/Subpart H facility ID number or ORISPL number (as applicable), reporting year, and 767 reporting indicator (or equivalent). (x) For each parameter monitored: Scale, maximum potential concentration (and method of calculation), maximum expected concentration (if applicable) (and method of calculation), maximum potential flow rate (and method of calculation), maximum potential NO X 2 X 2 2 (xi) If the monitoring system or excepted methodology provides for the use of a constant, assumed, or default value for a parameter under specific circumstances, then include the following information for each such value for each parameter: (A) Identification of the parameter; (B) Default, maximum, minimum, or constant value, and units of measure for the value; (C) Purpose of the value; (D) Indicator of use during controlled/uncontrolled hours; (E) Type of fuel; (F) Source of the value; (G) Value effective date and hour; (H) Date and hour value is no longer effective (if applicable); and (I) For units using the excepted methodology under § 75.19, the applicable SO 2 (xii) Uless otherwise specified in section 6.5.2.1 of appendix A to this part, for each unit of common stack on which hardware CEMS are installed: (A) The upper and lower boundaries of the range of operation (as defined in section 6.5.2.1 of appendix A to this part), expressed in megawatts, or thousands of lb/hr of steam, or ft/sec (as applicable); (B) The load or operating level(s) designated as normal in section 6.5.2.1 of appendix A to this part, expressed in megawatts, or thousands of lb/hr of steam, or ft/sec (as applicable); (C) The two load or operating levels ( i.e. (D) The date of the data analysis used to determine the normal load (or operating) level(s) and the two most frequently-used load (or operating) levels; and (E) Activation and deactivation dates, when the normal load or operating level(s) or two most frequently-used load or operating levels change and are updated. (xiii) For each unit for which the optional fuel flow-to-load test in section 2.1.7 of appendix D to this part is used: (A) The upper and lower boundaries of the range of operation (as defined in section 6.5.2.1 of appendix A to this part), expressed in megawatts or thousands of lb/hr of steam; (B) The load level designated as normal, pursuant to section 6.5.2.1 of appendix A to this part, expressed in megawatts or thousands of lb/hr of steam; and (C) The date of the load analysis used to determine the normal load level. (xiv) For each unit with a flow monitor installed on a rectangular stack or duct, if a wall effects adjustment factor (WAF) is determined and applied to the hourly flow rate data: (A) Stack or duct width at the test location, ft; (B) Stack or duct depth at the test location, ft; (C) Wall effects adjustment factor (WAF), to the nearest 0.0001; (D) Method of determining the WAF; (E) WAF Effective date and hour; (F) WAF no longer effective date and hour (if applicable); (G) WAF determination date; (H) Number of WAF test runs; (I) Number of Method 1 traverse points in the WAF test; (J) Number of test ports in the WAF test; and (K) Number of Method 1 traverse points in the reference flow RATA. (2) Hardcopy. X (ii) Description of site locations for each monitoring component in the continuous emission or opacity monitoring systems, including schematic diagrams and engineering drawings specified in paragraphs (e)(2)(iv) and (e)(2)(v) of this section and any other documentation that demonstrates each monitor location meets the appropriate siting criteria. (iii) A data flow diagram denoting the complete information handling path from output signals of CEMS components to final reports. (iv) For units monitored by a continuous emission or opacity monitoring system, a schematic diagram identifying entire gas handling system from boiler to stack for all affected units, using identification numbers for units, monitor components, and stacks corresponding to the identification numbers provided in paragraphs (e)(1)(i), (e)(1)(iv), (e)(1)(vi), and (e)(1)(ix) of this section. The schematic diagram must depict stack height and the height of any monitor locations. Comprehensive and/or separate schematic diagrams shall be used to describe groups of units using a common stack. (v) For units monitored by a continuous emission or opacity monitoring system, stack and duct engineering diagrams showing the dimensions and location of fans, turning vanes, air preheaters, monitor components, probes, reference method sampling ports, and other equipment that affects the monitoring system location, performance, or quality control checks. (f) Contents of monitoring plan for specific situations. (1) For each gas-fired unit or oil-fired unit for which the owner or operator uses the optional protocol in appendix D to this part for estimating heat input and/or SO 2 X (i) Electronic. (B) Type of fuel measured, maximum fuel flow rate, units of measure, and basis of maximum fuel flow rate ( i.e. (C) Test method used to check the accuracy of each fuel flowmeter; (D) Submission status of the data; (E) Monitoring system identification code; and (F) The method used to demonstrate that the unit qualifies for monthly GCV sampling or for daily or annual fuel sampling for sulfur content, as applicable. (ii) Hardcopy. (B) For units using the optional default SO 2 (C) For units using the 720 hour test under 2.3.6 of Appendix D of this part to determine the required sulfur sampling requirements, report the procedures and results of the test; and (D) For units using the 720 hour test under 2.3.5 of Appendix D of this part to determine the appropriate fuel GCV sampling frequency, report the procedures used and the results of the test; (2) For each gas-fired peaking unit and oil-fired peaking unit for which the owner or operator uses the optional procedures in appendix E to this part for estimating NO X (i) Electronic. X (A) Test date; (B) Test number; (C) Operating level; (D) Segment ID of the NO X (E) NO X (F) Low and high heat input rate values and corresponding NO X (G) Type of fuel; and (H) To document the unit qualifies as a peaking unit, current calendar year or ozone season, capacity factor data as specified in the definition of peaking unit in § 72.2 of this chapter, and an indication of whether the data are actual or projected data. (ii) Hardcopy. X (B) Unit operating parameters related to NO X (3) For each gas-fired unit and diesel-fired unit or unit with a wet flue gas pollution control system for which the designated representative claims an opacity monitoring exemption under § 75.14, the designated representative shall include in the hardcopy monitoring plan the information specified under § 75.14(b), (c), or (d), demonstrating that the unit qualifies for the exemption. (4) For each monitoring system recertification, maintenance, or other event, the designated representative shall include the following additional information in electronic format in the monitoring plan: (i) Component/system identification code; (ii) Event code or code for required test; (iii) Event begin date and hour; (iv) Conditionally valid data period begin date and hour (if applicable); (v) Date and hour that last test is successfully completed; and (vi) Indicator of whether conditionally valid data were reported at the end of the quarter. (5) For each unit using the low mass emission excepted methodology under § 75.19 the designated representative shall include the following additional information in the monitoring plan that accompanies the initial certification application: (i) Electronic. (A) Current calendar year of application; (B) Type of qualification; (C) Years one, two, and three; (D) Annual or ozone season measured, estimated or projected NO X (E) Annual measured, estimated or projected SO 2 (F) Annual or ozone season operating hours for years one, two, and three. (ii) Hardcopy. (B) For units which use the long term fuel flow methodology under § 75.19(c)(3), the designated representative must provide a diagram of the fuel flow to each affected unit or group of units and describe in detail the procedures used to determine the long term fuel flow for a unit or group of units for each fuel combusted by the unit or group of units; (C) A statement that the unit burns only gaseous fuel(s) and/or fuel oil and a list of the fuels that are burned or a statement that the unit is projected to burn only gaseous fuel(s) and/or fuel oil and a list of the fuels that are projected to be burned; (D) A statement that the unit meets the applicability requirements in §§ 75.19(a) and (b); and (E) Any unit historical actual, estimated and projected emissions data and calculated emissions data demonstrating that the affected unit qualifies as a low mass emissions unit under §§ 75.19(a) and 75.19(b). (6) For each gas-fired unit the designated representative shall include in the monitoring plan, in electronic format, the following: current calendar year, fuel usage data as specified in the definition of gas-fired in § 72.2 of this part, and an indication of whether the data are actual or projected data. (g) Contents of the monitoring plan. (1) Electronic. (A) A representation of the exhaust configuration for the units in the monitoring plan. On and after April 27, 2011, provide the activation date and deactivation date (if applicable) of the configuration. Provide the ID number of each unit and assign a unique ID number to each common stack, common pipe multiple stack and/or multiple pipe associated with the unit(s) represented in the monitoring plan. For common and multiple stacks and/or pipes, provide the activation date and deactivation date (if applicable) of each stack and/or pipe; (B) Identification of the monitoring system location(s) (e.g., at the unit-level, on the common stack, at each multiple stack, etc.). Provide an indicator (“flag”) if the monitoring location is at a bypass stack or in the ductwork (breeching); (C) The stack exit height (ft) above ground level and ground level elevation above sea level, and the inside cross-sectional area (ft 2 (D) The type(s) of fuel(s) fired by each unit. Indicate the start and (if applicable) end date of combustion for each type of fuel, and whether the fuel is the primary, secondary, emergency, or startup fuel; (E) The type(s) of emission controls that are used to reduce SO 2 X (F) Maximum hourly heat input capacity of each unit. On and after April 27, 2011, provide the activation date and deactivation date (if applicable) for this parameter; and (G) A non-load based unit indicator (if applicable) for units that do not produce electrical or thermal output. (ii) For each monitored parameter (e.g., SO 2 X (iii) For each required continuous emission monitoring system, each fuel flowmeter system, and each continuous opacity monitoring system, identify and describe the major monitoring components in the monitoring system ( e.g., e.g., (A) For each required monitoring system: ( 1 ( 2 ( 3 ( 4 (B) For each component of each monitoring system represented in the monitoring plan: ( 1 ( 2 ( 3 ( 4 ( 5 ( 6 ( 7 (iv) Explicit formulas, using the component and system identification codes for the primary monitoring system, and containing all constants and factors required to derive the required mass emissions, emission rates, heat input rates, etc. from the hourly data recorded by the monitoring systems. Formulas using the system and component ID codes for backup monitoring systems are required only if different formulas for the same parameter are used for the primary and backup monitoring systems (e.g., if the primary system measures pollutant concentration on a different moisture basis from the backup system). Provide the equation number or other appropriate code for each emissions formula (e.g., use code F-1 if Equation F-1 in appendix F to this part is used to calculate SO 2 (v) For each parameter monitored with CEMS, provide the following information: (A) Measurement scale (high or low); (B) Maximum potential value (and method of calculation). If NO X X X (C) Maximum expected value (if applicable) and method of calculation; (D) Span value(s) and full-scale measurement range(s); (E) Daily calibration units of measure; (F) Effective date/hour, and (if applicable) inactivation date/hour of each span value. On and after April 27, 2011, provide the activation date and deactivation date (if applicable) for the measurement scale and dual span information in paragraphs (g)(1)(v)(A), (g)(1)(v)(G), and (g)(1)(v)(H) of this section; (G) An indication of whether dual spans are required. If two span values are required, then, on and after April 27, 2011, indicate whether an autoranging analyzer is used to represent the two measurement scales; and (H) The default high range value (if applicable) and the maximum allowable low-range value for this option. (vi) If the monitoring system or excepted methodology provides for the use of a constant, assumed, or default value for a parameter under specific circumstances, then include the following information for each such value for each parameter: (A) Identification of the parameter; (B) Default, maximum, minimum, or constant value, and units of measure for the value; (C) Purpose of the value; (D) Indicator of use, i.e., during controlled hours, uncontrolled hours, or all operating hours; (E) Type of fuel; (F) Source of the value; (G) Value effective date and hour; (H) Date and hour that the value is no longer effective (if applicable); (I) For units using the excepted methodology under § 75.19, the applicable SO 2 (J) On and after April 27, 2011, group identification code. (vii) Unless otherwise specified in section 6.5.2.1 of appendix A to this part, for each unit or common stack on which hardware CEMS are installed: (A) Maximum hourly gross load (in MW, rounded to the nearest MW, or steam load in 1000 lb/hr ( i.e. (B) The upper and lower boundaries of the range of operation (as defined in section 6.5.2.1 of appendix A to this part), expressed in megawatts, thousands of lb/hr of steam, mmBtu/hr of thermal output, or ft/sec (as applicable); (C) Except for peaking units, identify the most frequently and second most frequently used load (or operating) levels ( i.e. (D) Except for peaking units, an indicator of whether the second most frequently used load (or operating) level is designated as normal in section 6.5.2.1 of appendix A to this part; (E) The date of the data analysis used to determine the normal load (or operating) level(s) and the two most frequently-used load (or operating) levels (as applicable); and (F) Activation and deactivation dates and hours, when the maximum hourly gross load, boundaries of the range of operation, normal load (or operating) level(s) or two most frequently-used load (or operating) levels change and are updated. (viii) For each unit for which CEMS are not installed: (A) Maximum hourly gross load (in MW, rounded to the nearest MW, or steam load in klb/hr, rounded to the nearest klb/hr, or steam load in mmBtu/hr, rounded to the nearest mmBtu/hr); (B) The upper and lower boundaries of the range of operation (as defined in section 6.5.2.1 of appendix A to this part), expressed in megawatts, mmBtu/hr of thermal output, or thousands of lb/hr of steam; (C) Except for peaking units and units using the low mass emissions excepted methodology under § 75.19, identify the load level designated as normal, pursuant to section 6.5.2.1 of appendix A to this part, expressed in megawatts, mmBtu/hr of thermal output, or thousands of lb/hr of steam; (D) The date of the load analysis used to determine the normal load level (as applicable); and (E) Activation and deactivation dates and hours, when the maximum hourly gross load, boundaries of the range of operation, or normal load level change and are updated. (ix) For each unit with a flow monitor installed on a rectangular stack or duct, if a wall effects adjustment factor (WAF) is determined and applied to the hourly flow rate data: (A) Stack or duct width at the test location, ft; (B) Stack or duct depth at the test location, ft; (C) Wall effects adjustment factor (WAF), to the nearest 0.0001; (D) Method of determining the WAF; (E) WAF Effective date and hour; (F) WAF no longer effective date and hour (if applicable); (G) WAF determination date; (H) Number of WAF test runs; (I) Number of Method 1 traverse points in the WAF test; (J) Number of test ports in the WAF test; and (K) Number of Method 1 traverse points in the reference flow RATA. (2) Hardcopy. X (ii) Description of site locations for each monitoring component in the continuous emission or opacity monitoring systems, including schematic diagrams and engineering drawings specified in paragraphs (e)(2)(iv) and (e)(2)(v) of this section and any other documentation that demonstrates each monitor location meets the appropriate siting criteria. (iii) A data flow diagram denoting the complete information handling path from output signals of CEMS components to final reports. (iv) For units monitored by a continuous emission or opacity monitoring system, a schematic diagram identifying entire gas handling system from boiler to stack for all affected units, using identification numbers for units, monitoring systems and components, and stacks corresponding to the identification numbers provided in paragraphs (g)(1)(i) and (g)(1)(iii) of this section. The schematic diagram must depict stack height and the height of any monitor locations. Comprehensive and/or separate schematic diagrams shall be used to describe groups of units using a common stack. (v) For units monitored by a continuous emission or opacity monitoring system, stack and duct engineering diagrams showing the dimensions and location of fans, turning vanes, air preheaters, monitor components, probes, reference method sampling ports, and other equipment that affects the monitoring system location, performance, or quality control checks. (h) Contents of monitoring plan for specific situations. (1) For each gas-fired unit or oil-fired unit for which the owner or operator uses the optional protocol in appendix D to this part for estimating heat input and/or SO 2 X (i) Electronic. (B) Type of fuel measured, maximum fuel flow rate, units of measure, and basis of maximum fuel flow rate ( i.e. (C) Test method used to check the accuracy of each fuel flowmeter; (D) Monitoring system identification code; (E) The method used to demonstrate that the unit qualifies for monthly GCV sampling or for daily or annual fuel sampling for sulfur content, as applicable; and (F) Activation date/hour and (if applicable) inactivation date/hour for the fuel flowmeter system; (ii) Hardcopy. (B) For units using the optional default SO 2 (C) For units using the 720 hour test under 2.3.6 of Appendix D of this part to determine the required sulfur sampling requirements, report the procedures and results of the test; and (D) For units using the 720 hour test under 2.3.5 of Appendix D of this part to determine the appropriate fuel GCV sampling frequency, report the procedures used and the results of the test. (2) For each gas-fired peaking unit and oil-fired peaking unit for which the owner or operator uses the optional procedures in appendix E to this part for estimating NO X (i) Electronic. (ii) Hardcopy. X (B) Unit operating parameters related to NO X (3) For each gas-fired unit and diesel-fired unit or unit with a wet flue gas pollution control system for which the designated representative claims an opacity monitoring exemption under § 75.14, the designated representative shall include in the hardcopy monitoring plan the information specified under § 75.14(b), (c), or (d), demonstrating that the unit qualifies for the exemption. (4) For each unit using the low mass emissions excepted methodology under § 75.19 the designated representative shall include the following additional information in the monitoring plan that accompanies the initial certification application: (i) Electronic. (A) Current calendar year of application; (B) Type of qualification; (C) Years one, two, and three; (D) Annual and/or ozone season measured, estimated or projected NO X (E) Annual measured, estimated or projected SO 2 (F) Annual or ozone season operating hours for years one, two, and three. (ii) Hardcopy. (B) For units which use the long term fuel flow methodology under § 75.19(c)(3), the designated representative must provide a diagram of the fuel flow to each affected unit or group of units and describe in detail the procedures used to determine the long term fuel flow for a unit or group of units for each fuel combusted by the unit or group of units; (C) A statement that the unit burns only gaseous fuel(s) and/or fuel oil and a list of the fuels that are burned or a statement that the unit is projected to burn only gaseous fuel(s) and/or fuel oil and a list of the fuels that are projected to be burned; (D) A statement that the unit meets the applicability requirements in § 75.19(a) and (b); and (E) Any unit historical actual, estimated and projected emissions data and calculated emissions data demonstrating that the affected unit qualifies as a low mass emissions unit under § 75.19(a) and 75.19(b). (5) For qualification as a gas-fired unit, as defined in § 72.2 of this part, the designated representative shall include in the monitoring plan, in electronic format, the following: current calendar year, fuel usage data for three calendar years (or ozone seasons) as specified in the definition of gas-fired in § 72.2 of this chapter, the method of qualification used, and an indication of whether the data are actual or projected data. On and after April 27, 2011, provide the activation date and deactivation date (if applicable) for the gas-fired unit qualification information in this paragraph (h)(5). (6) For each monitoring location with a stack flow monitor that is exempt from performing 3-load flow RATAs (peaking units, bypass stacks, or by petition) the designated representative shall include in the monitoring plan an indicator of exemption from 3-load flow RATA using the appropriate exemption code. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26532, 26568, May 17, 1995; 61 FR 59161, Nov. 20, 1996; 64 FR 28605, May 26, 1999; 67 FR 40440, June 12, 2002; 70 FR 28682, May 18, 2005; 73 FR 4350, Jan. 24, 2008; 76 FR 17312, Mar. 28, 2011] §§ 75.54-75.56 [Reserved] § 75.57 General recordkeeping provisions. The owner or operator shall meet all of the applicable recordkeeping requirements of this section. (a) Recordkeeping requirements for affected sources. (1) The data and information required in paragraphs (b) through (h) of this section, beginning with the earlier of the date of provisional certification or the deadline in § 75.4(a), (b), or (c); (2) The supporting data and information used to calculate values required in paragraphs (b) through (g) of this section, excluding the subhourly data points used to compute hourly averages under § 75.10(d), beginning with the earlier of the date of provisional certification or the deadline in § 75.4(a), (b), or (c); (3) The data and information required in § 75.58 for specific situations, beginning with the earlier of the date of provisional certification or the deadline in § 75.4(a), (b), or (c); (4) The certification test data and information required in § 75.59 for tests required under § 75.20, beginning with the date of the first certification test performed, the quality assurance and quality control data and information required in § 75.59 for tests, and the quality assurance/quality control plan required under § 75.21 and appendix B to this part, beginning with the date of provisional certification; (5) The current monitoring plan as specified in § 75.53, beginning with the initial submission required by § 75.62; (6) The quality control plan as described in section 1 of appendix B to this part, beginning with the date of provisional certification; and (7) The information required by sections 6.1.2(b) and (c) of appendix A to this part. (b) Operating parameter record provisions. (1) Date and hour; (2) Unit operating time (rounded up to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator)); (3) Hourly gross unit load (rounded to nearest MWge) (or steam load in 1000 lb/hr at stated temperature and pressure, rounded to the nearest 1000 lb/hr, or mmBtu/hr of thermal output, rounded to the nearest mmBtu/hr, if elected in the monitoring plan); (4) Operating load range corresponding to hourly gross load of 1 to 10, except for units using a common stack or common pipe header, which may use up to 20 load ranges for stack or fuel flow, as specified in the monitoring plan; (5) Hourly heat input rate (mmBtu/hr, rounded to the nearest tenth); (6) Identification code for formula used for heat input, as provided in § 75.53; and (7) For CEMS units only, F-factor for heat input calculation and indication of whether the diluent cap was used for heat input calculations for the hour. (c) SO 2 emission record provisions. 2 (1) For SO 2 (i) Component-system identification code, as provided in § 75.53; (ii) Date and hour; (iii) Hourly average SO 2 (iv) Hourly average SO 2 (v) Percent monitor data availability (recorded to the nearest tenth of a percent), calculated pursuant to § 75.32; and (vi) Method of determination for hourly average SO 2 (2) For flow rate during unit operation, as measured and reported from each certified primary monitor, certified back-up monitor, or other approved method of emissions determination: (i) Component-system identification code, as provided in § 75.53; (ii) Date and hour; (iii) Hourly average volumetric flow rate (in scfh, rounded to the nearest thousand); (iv) Hourly average volumetric flow rate (in scfh, rounded to the nearest thousand), adjusted for bias if bias adjustment factor required, as provided in § 75.24(d); (v) Percent monitor data availability (recorded to the nearest tenth of a percent) for the flow monitor, calculated pursuant to § 75.32; and (vi) Method of determination for hourly average flow rate using Codes 1-55 in Table 4a of this section. (3) For flue gas moisture content during unit operation (where SO 2 (i) Component-system identification code, as provided in § 75.53; (ii) Date and hour; (iii) Hourly average moisture content of flue gas (percent, rounded to the nearest tenth). If the continuous moisture monitoring system consists of wet- and dry-basis oxygen analyzers, also record both the wet- and dry-basis oxygen hourly averages (in percent O 2 (iv) Percent monitor data availability (recorded to the nearest tenth of a percent) for the moisture monitoring system, calculated pursuant to § 75.32; and (v) Method of determination for hourly average moisture percentage, using Codes 1-55 in Table 4a of this section. (4) For SO 2 (i) Date and hour; (ii) Hourly SO 2 (iii) Hourly SO 2 (iv) Identification code for emissions formula used to derive hourly SO 2 2 Table 4a—Codes for Method of Emissions and Flow Determination Code Hourly emissions/flow measurement or estimation method 1 Certified primary emission/flow monitoring system. 2 Certified backup emission/flow monitoring system. 3 Approved alternative monitoring system. 4 Reference method: 2 X 2 2 5 For units with add-on SO 2 X 2 X 6 Average of the hourly SO 2 2 2 X X 7 Initial missing data procedures used. Either: (a) the average of the hourly SO 2 2 2 X X X X 8 90th percentile hourly SO 2 2 X X 2 9 95th percentile hourly SO 2 2 X X 2 10 Maximum hourly SO 2 2 X X 2 11 Average of hourly flow rates, NO X X X X X 12 Maximum potential concentration of SO 2 2 X X 2 13 Maximum expected concentration of SO 2 X X See 14 Diluent cap value (if the cap is replacing a CO 2 2 15 1.25 times the maximum hourly controlled SO 2 X X See 16 SO 2 17 Like-kind replacement non-redundant backup analyzer. 19 200 percent of the MPC; default high range value. 20 200 percent of the full-scale range setting (full-scale exceedance of high range). 21 Negative hourly CO 2 2 X X 22 Hourly average SO 2 X 23 Maximum potential SO 2 X 2 X 2 24 Maximum expected NO X X X X 25 Maximum potential NO X X 26 1.0 mmBtu/hr substituted for Heat Input Rate for an operating hour in which the calculated Heat Input Rate is zero or negative. 40 Fuel specific default value (or prorated default value) used for the hour. 53 Other quality-assured data approved through petition. These are treated as available hours for percent monitor availability calculations and are included in missing data lookback. 54 Other quality assured methodologies approved through petition. These hours are included in missing data lookback and are treated as unavailable hours for percent monitor availability calculations. 55 Other substitute data approved through petition. These hours are not included in missing data lookback and are treated as unavailable hours for percent monitor availability calculations. (d) NO X emission record provisions. X X X X X X (1) Component-system identification code, as provided in § 75.53 (including identification code for the moisture monitoring system, if applicable); (2) Date and hour; (3) Hourly average NO X X (4) Hourly average diluent gas concentration (for NO X 2 2 (5) If applicable, the hourly average moisture content of the stack gas (percent H 2 2 (6) Hourly average NO X X (7) Hourly average NO X X X X (8) Percent monitoring system data availability (recorded to the nearest tenth of a percent), for the NO X X (9) Method of determination for hourly average NO X X (10) Identification codes for emissions formulas used to derive hourly average NO X X X (e) CO 2 emission record provisions. 2 2 (1) If the owner or operator chooses to use a CO 2 2 2 (i) Component-system identification code, as provided in § 75.53 (including identification code for the moisture monitoring system, if applicable); (ii) Date and hour; (iii) Hourly average CO 2 (iv) Hourly average volumetric flow rate (scfh, rounded to the nearest thousand scfh); (v) Hourly average moisture content of flue gas (percent, rounded to the nearest tenth), where CO 2 2 (vi) Hourly average CO 2 (vii) Percent monitor data availability for both the CO 2 (viii) Method of determination for hourly average CO 2 2 (ix) Identification code for emissions formula used to derive hourly average CO 2 (x) Indication of whether the diluent cap was used for CO 2 (2) As an alternative to paragraph (e)(1) of this section, the owner or operator may use the procedures in § 75.13 and in appendix G to this part, and shall record daily the following information for CO 2 (i) Date; (ii) Daily combustion-formed CO 2 (iii) For coal-fired units, flag indicating whether optional procedure to adjust combustion-formed CO 2 (iv) For a unit with a wet flue gas desulfurization system or other controls generating CO 2 2 (v) For a unit with a wet flue gas desulfurization system or other controls generating CO 2 2 (f) Opacity records. (1) Component/system identification code; (2) Date, hour, and minute; (3) Average opacity of emissions for each six minute averaging period (in percent opacity); (4) If the average opacity of emissions exceeds the applicable standard, then a code indicating such an exceedance has occurred; and (5) Percent monitor data availability (recorded to the nearest tenth of a percent), calculated according to the requirements of the procedure recommended for State Implementation Plans in appendix M to part 51 of this chapter. (g) Diluent record provisions. 2 2 2 2 2 (1) Component-system identification code, as provided in § 75.53; (2) Date and hour; (3) Hourly average diluent gas (O 2 2 (4) Percent monitor data availability for the diluent monitor (recorded to the nearest tenth of a percent), calculated pursuant to § 75.32; and (5) Method of determination code for diluent gas (O 2 2 (h) Missing data records. [64 FR 28609, May 26, 1999; 64 FR 37582, July 12, 1999; 67 FR 40440, June 12, 2002; 70 FR 28682, May 18, 2005; 72 FR 51528, Sept. 7, 2007; 73 FR 4353, Jan. 24, 2008; 76 FR 17313, Mar. 28, 2011] § 75.58 General recordkeeping provisions for specific situations. The owner or operator shall meet all of the applicable recordkeeping requirements of this section. (a) [Reserved] (b) Specific parametric data record provisions for calculating substitute emissions data for units with add-on emission controls. 2 X 2 X (1) For units with add-on SO 2 2 (i) The information required in § 75.57(c) for SO 2 (ii) Date and hour; (iii) Number of operating scrubber modules; (iv) Total feedrate of slurry to each operating scrubber module (gal/min); (v) Pressure differential across each operating scrubber module (inches of water column); (vi) For a unit with a wet flue gas desulfurization system, an in-line measure of absorber pH for each operating scrubber module; (vii) For a unit with a dry flue gas desulfurization system, the inlet and outlet temperatures across each operating scrubber module; (viii) For a unit with a wet flue gas desulfurization system, the percent solids in slurry for each scrubber module; (ix) For a unit with a dry flue gas desulfurization system, the slurry feed rate (gal/min) to the atomizer nozzle; (x) For a unit with SO 2 (xi) Method of determination of SO 2 (xii) Inlet and outlet SO 2 2 (2) For units with add-on NO X X (i) Date and hour; (ii) Inlet air flow rate (scfh, rounded to the nearest thousand); (iii) Excess O 2 (iv) Carbon monoxide concentration of flue gas at stack outlet (ppm, rounded to the nearest tenth); (v) Temperature of flue gas at furnace exit or economizer outlet duct (°F); (vi) Other parameters specific to NO X (vii) Method of determination of NO X (viii) Inlet and outlet NO X X (3) Except as otherwise provided in § 75.34(d), for units with add-on SO 2 X (i) Parametric data which demonstrate, for each hour of missing SO 2 X (ii) A flag indicating, for each hour of missing SO 2 X (c) Specific SO 2 emission record provisions for gas-fired or oil-fired units using optional protocol in appendix D to this part. 2 (1) For each hour when the unit is combusting oil: (i) Date and hour; (ii) Hourly average volumetric flow rate of oil, while the unit combusts oil, with the units in which oil flow is recorded (gal/hr, scf/hr, m 3 (iii) Sulfur content of oil sample used to determine SO 2 (iv) [Reserved]; (v) Mass flow rate of oil combusted each hour and method of determination (lb/hr, rounded to the nearest tenth) (flag value if derived from missing data procedures); (vi) SO 2 (vii) For units using volumetric oil flowmeters, density of oil with the units in which oil density is recorded and method of determination (flag value if derived from missing data procedures); (viii) Gross calorific value of oil used to determine heat input and method of determination (Btu/lb) (flag value if derived from missing data procedures); (ix) Hourly heat input rate from oil, according to procedures in appendix D to this part (mmBtu/hr, to the nearest tenth); (x) Fuel usage time for combustion of oil during the hour (rounded up to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator)) (flag to indicate multiple/single fuel types combusted); (xi) Monitoring system identification code; (xii) Operating load range corresponding to gross unit load (01-20); (xiii) Type of oil combusted; and (xiv) Heat input formula ID and SO 2 (2) For gas-fired units or oil-fired units using the optional protocol in appendix D to this part for daily manual oil sampling, when the unit is combusting oil, the highest sulfur content recorded from the most recent 30 daily oil samples (rounded to the nearest tenth of a percent). (3) For gas-fired units or oil-fired units using the optional protocol in appendix D to this part, when either an assumed oil sulfur content or density value is used, or when as-delivered oil sampling is performed: (i) Record the measured sulfur content, gross calorific value, and, if applicable, density from each fuel sample; and (ii) Record and report the assumed sulfur content, gross calorific value, and, if applicable, density used to calculate SO 2 (4) For each hour when the unit is combusting gaseous fuel: (i) Date and hour. (ii) Hourly heat input rate from gaseous fuel, according to procedures in appendix F to this part (mmBtu/hr, rounded to the nearest tenth). (iii) Sulfur content or SO 2 (A) Sulfur content of gas sample and method of determination (rounded to the nearest 0.1 grains/100 scf) (flag value if derived from missing data procedures); or (B) Default SO 2 2 (iv) Hourly flow rate of gaseous fuel, while the unit combusts gas (100 scfh) and source of data code for gas flow rate. (v) Gross calorific value of gaseous fuel used to determine heat input rate (Btu/100 scf) (flag value if derived from missing data procedures). (vi) SO 2 (vii) Fuel usage time for combustion of gaseous fuel during the hour (rounded up to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator)) (flag to indicate multiple/single fuel types combusted). (viii) Monitoring system identification code. (ix) Operating load range corresponding to gross unit load (01-20). (x) Type of gas combusted; and (xi) Heat input formula ID and SO 2 (5) For each oil sample or sample of diesel fuel: (i) Date of sampling; (ii) Sulfur content (percent, rounded to either the nearest hundredth, or nearest ten-thousandth for diesel fuels and to the nearest tenth for other fuel oil); (iii) Gross calorific value (Btu/lb); and (iv) Density or specific gravity, if required to convert volume to mass. (6) For each sample of gaseous fuel for sulfur content: (i) Date of sampling; and (ii) Sulfur content (grains/100 scf, rounded to the nearest tenth). (7) For each sample of gaseous fuel for gross calorific value: (i) Date of sampling; and (ii) Gross calorific value (Btu/100 scf). (8) For each oil sample or sample of gaseous fuel: (i) Type of oil or gas; and (ii) Type of sulfur sampling (using codes in tables D-4 and D-5 of appendix D to this part) and value used in calculations, and type of GCV or density sampling (using codes in tables D-4 and D-5 of appendix D to this part). (d) Specific NO X emission record provisions for gas-fired peaking units or oil-fired peaking units using optional protocol in appendix E to this part. X X X (1) For each hour when the unit is combusting oil: (i) Date and hour; (ii) Hourly average mass flow rate of oil while the unit combusts oil with the units in which oil flow is recorded (lb/hr); (iii) Gross calorific value of oil used to determine heat input (Btu/lb); (iv) Hourly average NO X (v) Heat input rate of oil (mmBtu/hr, rounded to the nearest tenth); (vi) Fuel usage time for combustion of oil during the hour (rounded up to the nearest fraction of an hour, in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator); (vii) NO X (viii) NO X (ix) Fuel flow monitoring system identification code; (x) Segment identification of the correlation curve; and (xi) Heat input rate formula ID (required beginning January 1, 2009). (2) For each hour when the unit is combusting gaseous fuel: (i) Date and hour; (ii) Hourly average fuel flow rate of gaseous fuel, while the unit combusts gas (100 scfh); (iii) Gross calorific value of gaseous fuel used to determine heat input (Btu/100 scf) (flag value if derived from missing data procedures); (iv) Hourly average NO X (v) Heat input rate from gaseous fuel, while the unit combusts gas (mmBtu/hr, rounded to the nearest tenth); (vi) Fuel usage time for combustion of gaseous fuel during the hour (rounded up to the nearest fraction of an hour, in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator); (vii) NO X (viii) NO X (ix) Fuel flow monitoring system identification code; (x) Segment identification of the correlation curve; and (xi) Heat input rate formula ID (required beginning January 1, 2009). (3) For each hour when the unit combusts multiple fuels: (i) Date and hour; (ii) Hourly average heat input rate from all fuels (mmBtu/hr, rounded to the nearest tenth); and (iii) Hourly average NO X (4) For each hour when the unit combusts any fuel(s): (i) For stationary gas turbines and diesel or dual-fuel reciprocating engines, hourly averages of operating parameters under section 2.3 of appendix E to this part (flag if value is outside of manufacturer's recommended range); and (ii) For boilers, hourly average boiler O 2 2 X (iii) On and after April 27, 2011, operating condition codes for the following: (A) Unit operated on emergency fuel; (B) Correlation curve for the fuel mixture has expired; (C) Operating parameter is outside of normal limits; (D) Uncontrolled hour; (E) Operation above highest tested heat input rate point on the curve; (F) Operating parameter data missing or invalid; (G) Designated operational and control equipment parameters within normal limits; and (H) Operation below lowest tested heat input rate point on the curve. (5) For each fuel sample: (i) Date of sampling; (ii) Gross calorific value (Btu/lb for oil, Btu/100 scf for gaseous fuel); and (iii) Density or specific gravity, if required to convert volume to mass. (6) Flag to indicate multiple or single fuels combusted. (e) Specific SO 2 emission record provisions during the combustion of gaseous fuel. 2 2 (2) The provisions of this paragraph apply to a unit which, in accordance with the provisions of § 75.11(e)(3), uses an SO 2 2 2 (f) Specific SO 2 NO X and CO 2 record provisions for gas-fired or oil-fired units using the optional low mass emissions excepted methodology in § 75.19. (1) All low mass emission units shall report for each hour: (i) Date and hour; (ii) Unit operating time (units using the long term fuel flow methodology report operating time to be 1); (iii) Fuel type (pipeline natural gas, natural gas, other gaseous fuel, residual oil, or diesel fuel). If more than one type of fuel is combusted in the hour, either: (A) Indicate the fuel type which results in the highest emission factors for NO X (B) Indicate the fuel type resulting in the highest emission factor for each parameter (SO 2 X 2 (iv) Average hourly NO X (v) Hourly NO X (vi) Hourly SO 2 (vii) Hourly CO 2 (viii) Hourly calculated unit heat input in mmBtu; (ix) Hourly unit output in gross load or steam load; (x) The method of determining hourly heat input: unit maximum rated heat input, unit long term fuel flow or group long term fuel flow; (xi) The method of determining NO X X (xii) Control status of the unit; and (xiii) Base or peak load indicator (as applicable); and (xiv) Multiple fuel flag. (2) Low mass emission units using the optional long term fuel flow methodology to determine unit heat input shall report for each quarter: (i) Type of fuel; (ii) Beginning date and hour of long term fuel flow measurement period; (iii) End date and hour of long term fuel flow period; (iv) Quantity of fuel measured; (v) Units of measure; (vi) Fuel GCV value used to calculate heat input; (vii) Units of GCV; (viii) Method of determining fuel GCV used; (ix) Method of determining fuel flow over period; (x) Monitoring-system identification code; (xi) Quarter and year; (xii) Total heat input (mmBtu); and (xiii) Operating hours in period. [64 FR 28612, May 26, 1999, as amended at 67 FR 40441, 40442, June 12, 2002; 70 FR 28683, May 18, 2005; 73 FR 4354, Jan. 24, 2008; 76 FR 17314, Mar. 28, 2011] § 75.59 Certification, quality assurance, and quality control record provisions. The owner or operator shall meet all of the applicable recordkeeping requirements of this section. (a) Continuous emission or opacity monitoring systems. (1) For each SO 2 X 2 2 2 2 (i) Component-system identification code (on and after January 1, 2009, only the component identification code is required); (ii) Instrument span and span scale; (iii) On and after April 27, 2011, date, hour, and minute; (iv) Reference value ( i.e. (v) Observed value (monitor response during calibration, in ppm or other appropriate units); (vi) Percent calibration error (rounded to the nearest tenth of a percent) (flag if using alternative performance specification for low emitters or differential pressure flow monitors); (vii) Reference signal or calibration gas level; (viii) For 7-day calibration error tests, a test number and reason for test; (ix) For 7-day calibration tests for certification or recertification, a certification from the cylinder gas vendor or CEMS vendor that calibration gas, as defined in § 72.2 of this chapter and appendix A to this part, was used to conduct calibration error testing; (x) Description of any adjustments, corrective actions, or maintenance prior to a passed test or following a failed test; and (xi) Indication of whether the unit is off-line or on-line. (2) For each flow monitor, the owner or operator shall record the following for all daily interference checks, including any follow-up tests after corrective action. (i) Component-system identification code (after January 1, 2009, only the component identification code is required); (ii) Date and hour; (iii) Code indicating whether monitor passes or fails the interference check; and (iv) Description of any adjustments, corrective actions, or maintenance prior to a passed test or following a failed test. (3) For each SO 2 X 2 2 2 2 (i) Component-system identification code (on and after January 1, 2009, only the component identification code is required); (ii) Instrument span and span scale (only span scale is required on and after January 1, 2009); (iii) Calibration gas level; (iv) Date and time (hour and minute) of each gas injection at each calibration gas level; (v) Reference value ( i.e. (vi) Observed value (monitor response to each reference gas injection at each calibration gas level, in ppm or other appropriate units); (vii) Mean of reference values and mean of measured values at each calibration gas level; (viii) Linearity error at each of the reference gas concentrations (rounded to nearest tenth of a percent) (flag if using alternative performance specification); (ix) Test number and reason for test (flag if aborted test); and (x) Description of any adjustments, corrective action, or maintenance prior to a passed test or following a failed test. (4) For each differential pressure type flow monitor, the owner or operator shall record items in paragraphs (a)(4) (i) through (v) of this section, for all quarterly leak checks, including any follow-up tests after corrective action. For each flow monitor, the owner or operator shall record items in paragraphs (a)(4) (vi) and (vii) for all flow-to-load ratio and gross heat rate tests: (i) Component-system identification code (on and after January 1, 2009, only the system identification code is required). (ii) Date and hour. (iii) Reason for test. (iv) Code indicating whether monitor passes or fails the quarterly leak check. (v) Description of any adjustments, corrective actions, or maintenance prior to a passed test or following a failed test. (vi) Test data from the flow-to-load ratio or gross heat rate (GHR) evaluation, including: (A) Monitoring system identification code; (B) Calendar year and quarter; (C) Indication of whether the test is a flow-to-load ratio or gross heat rate evaluation; (D) Indication of whether bias adjusted flow rates were used; (E) Average absolute percent difference between reference ratio (or GHR) and hourly ratios (or GHR values); (F) Test result; (G) Number of hours used in final quarterly average; (H) Number of hours exempted for use of a different fuel type; (I) Number of hours exempted for load ramping up or down; (J) Number of hours exempted for scrubber bypass; (K) Number of hours exempted for hours preceding a normal-load flow RATA; (L) Number of hours exempted for hours preceding a successful diagnostic test, following a documented monitor repair or major component replacement; (M) Number of hours excluded for flue gases discharging simultaneously thorough a main stack and a bypass stack; and (N) Test number. (vii) Reference data for the flow-to-load ratio or gross heat rate evaluation, including (as applicable): (A) Reference flow RATA end date and time; (B) Test number of the reference RATA; (C) Reference RATA load and load level; (D) Average reference method flow rate during reference flow RATA; (E) Reference flow/load ratio; (F) Average reference method diluent gas concentration during flow RATA and diluent gas units of measure; (G) Fuel specific F d c (H) Reference gross heat rate value; (I) Monitoring system identification code; (J) Average hourly heat input rate during RATA; (K) Average gross unit load; (L) Operating load level; and (M) An indicator (“flag”) if separate reference ratios are calculated for each multiple stack. (5) For each SO 2 2 2 2 X X 2 2 (i) Reference method(s) used. (ii) Individual test run data from the relative accuracy test audit for the SO 2 2 X 2 2 X (A) Date, hour, and minute of beginning of test run; (B) Date, hour, and minute of end of test run; (C) Monitoring system identification code; (D) Test number and reason for test; (E) Operating level (low, mid, high, or normal, as appropriate) and number of operating levels comprising test; (F) Normal load (or operating level) indicator for flow RATAs (except for peaking units); (G) Units of measure; (H) Run number; (I) Run value from CEMS being tested, in the appropriate units of measure; (J) Run value from reference method, in the appropriate units of measure; (K) Flag value (0, 1, or 9, as appropriate) indicating whether run has been used in calculating relative accuracy and bias values or whether the test was aborted prior to completion; (L) Average gross unit load, expressed as a total gross unit load, rounded to the nearest MWe, or as steam load, rounded to the nearest thousand lb/hr; on and after April 27, 2011, for units that do not produce electrical or thermal output, record, instead, the average stack gas velocity at the operating level being tested; and (M) Flag to indicate whether an alternative performance specification has been used. (iii) Calculations and tabulated results, as follows: (A) Arithmetic mean of the monitoring system measurement values, of the reference method values, and of their differences, as specified in Equation A-7 in appendix A to this part; (B) Standard deviation, as specified in Equation A-8 in appendix A to this part; (C) Confidence coefficient, as specified in Equation A-9 in appendix A to this part; (D) Statistical “t” value used in calculations; (E) Relative accuracy test results, as specified in Equation A-10 in appendix A to this part. For multi-level flow monitor tests the relative accuracy test results shall be recorded at each load (or operating) level tested. Each load (or operating) level shall be expressed as a total gross unit load, rounded to the nearest MWe, or as steam load, rounded to the nearest thousand lb/hr, or as otherwise specified by the Administrator, for units that do not produce electrical or thermal output; (F) Bias test results as specified in section 7.6.4 of appendix A to this part; (G) Bias adjustment factor from Equation A-12 in appendix A to this part for any monitoring system that failed the bias test (except as otherwise provided in section 7.6.5 of appendix A to this part) and 1.000 for any monitoring system that passed the bias test; and (H) On and after April 27, 2011, RATA frequency code. (iv) Description of any adjustment, corrective action, or maintenance prior to a passed test or following a failed or aborted test. (v) F-factor value(s) used to convert NO X 2 2 X 2 (vi) For flow monitors, the equation used to linearize the flow monitor and the numerical values of the polynomial coefficients or K factor(s) of that equation. (vii) For moisture monitoring systems, the coefficient or “K” factor or other mathematical algorithm used to adjust the monitoring system with respect to the reference method. (6) For each SO 2 X 2 X 2 2 (i) Component-system identification code (on and after January 1, 2009, only the component identification code is required); (ii) Date; (iii) Start and end times; (iv) Upscale and downscale cycle times for each component; (v) Stable start monitor value; (vi) Stable end monitor value; (vii) Reference value of calibration gas(es); (viii) Calibration gas level; (ix) Total cycle time; (x) Reason for test; and (xi) Test number. (7) In addition to the information in paragraph (a)(5) of this section, the owner or operator shall record, for each relative accuracy test audit, supporting information sufficient to substantiate compliance with all applicable sections and appendices in this part. Unless otherwise specified in this part or in an applicable test method, the information in paragraphs (a)(7)(i) through (a)(7)(vi) of this section may be recorded either in hard copy format, electronic format or a combination of the two, and the owner or operator shall maintain this information in a format suitable for inspection and audit purposes. This RATA supporting information shall include, but shall not be limited to, the following data elements: (i) For each RATA using Reference Method 2 (or its allowable alternatives) in appendix A to part 60 of this chapter to determine volumetric flow rate: (A) Information indicating whether or not the location meets requirements of Method 1 in appendix A to part 60 of this chapter; and (B) Information indicating whether or not the equipment passed the required leak checks. (ii) For each run of each RATA using Reference Method 2 (or its allowable alternatives in appendix A to part 60 of this chapter) to determine volumetric flow rate, record the following data elements (as applicable to the measurement method used): (A) Operating level (low, mid, high, or normal, as appropriate); (B) Number of reference method traverse points; (C) Average stack gas temperature (°F); (D) Barometric pressure at test port (inches of mercury); (E) Stack static pressure (inches of H 2 (F) Absolute stack gas pressure (inches of mercury); (G) Percent CO 2 2 (H) CO 2 2 (I) Moisture content of stack gas (percent H 2 (J) Molecular weight of stack gas, dry basis (lb/lb-mole); (K) Molecular weight of stack gas, wet basis (lb/lb-mole); (L) Stack diameter (or equivalent diameter) at the test port (ft); (M) Average square root of velocity head of stack gas (inches of H 2 (N) Stack or duct cross-sectional area at test port (ft 2 (O) Average velocity (ft/sec); (P) Average stack flow rate, adjusted, if applicable, for wall effects (scfh, wet basis); (Q) Flow rate reference method used; (R) Average velocity, adjusted for wall effects; (S) Calculated (site-specific) wall effects adjustment factor determined during the run, and, if different, the wall effects adjustment factor used in the calculations; and (T) Default wall effects adjustment factor used. (iii) For each traverse point of each run of each RATA using Reference Method 2 (or its allowable alternatives in appendix A to part 60 of this chapter) to determine volumetric flow rate, record the following data elements (as applicable to the measurement method used): (A) Reference method probe type; (B) Pressure measurement device type; (C) Traverse point ID; (D) Probe or pitot tube calibration coefficient; (E) Date of latest probe or pitot tube calibration; (F) Average velocity differential pressure at traverse point (inches of H 2 2 1/2 (G) T S (H) Composite (wall effects) traverse point identifier; (I) Number of points included in composite traverse point; (J) Yaw angle of flow at traverse point (degrees); (K) Pitch angle of flow at traverse point (degrees); (L) Calculated velocity at traverse point both accounting and not accounting for wall effects (ft/sec); and (M) Probe identification number. (iv) For each RATA using Method 6C, 7E, or 3A in appendix A to part 60 of this chapter to determine SO 2 X 2 2 (A) Pollutant or diluent gas being measured; (B) Span of reference method analyzer; (C) Type of reference method system (e.g., extractive or dilution type); (D) Reference method dilution factor (dilution type systems, only); (E) Reference gas concentrations (zero, mid, and high gas levels) used for the 3-point pre-test analyzer calibration error test (or, for dilution type reference method systems, for the 3-point pre-test system calibration error test) and for any subsequent recalibrations; (F) Analyzer responses to the zero-, mid-, and high-level calibration gases during the 3-point pre-test analyzer (or system) calibration error test and during any subsequent recalibration(s); (G) Analyzer calibration error at each gas level (zero, mid, and high) for the 3-point pre-test analyzer (or system) calibration error test and for any subsequent recalibration(s) (percent of span value); (H) Upscale gas concentration (mid or high gas level) used for each pre-run or post-run system bias check or (for dilution type reference method systems) for each pre-run or post-run system calibration error check; (I) Analyzer response to the calibration gas for each pre-run or post-run system bias (or system calibration error) check; (J) The arithmetic average of the analyzer responses to the zero-level gas, for each pair of pre- and post-run system bias (or system calibration error) checks; (K) The arithmetic average of the analyzer responses to the upscale calibration gas, for each pair of pre- and post-run system bias (or system calibration error) checks; (L) The results of each pre-run and each post-run system bias (or system calibration error) check using the zero-level gas (percentage of span value); (M) The results of each pre-run and each post-run system bias (or system calibration error) check using the upscale calibration gas (percentage of span value); (N) Calibration drift and zero drift of analyzer during each RATA run (percentage of span value); (O) Moisture basis of the reference method analysis; (P) Moisture content of stack gas, in percent, during each test run (if needed to convert to moisture basis of CEMS being tested); (Q) Unadjusted (raw) average pollutant or diluent gas concentration for each run; (R) Average pollutant or diluent gas concentration for each run, corrected for calibration bias (or calibration error) and, if applicable, corrected for moisture; (S) The F-factor used to convert reference method data to units of lb/mmBtu (if applicable); (T) Date(s) of the latest analyzer interference test(s); (U) Results of the latest analyzer interference test(s); (V) Date of the latest NO 2 (W) Results of the latest NO 2 (X) For each calibration gas cylinder used during each RATA, record the cylinder gas vendor, cylinder number, expiration date, pollutant(s) in the cylinder, and certified gas concentration(s). (v) For each test run of each moisture determination using Method 4 in appendix A to part 60 of this chapter (or its allowable alternatives), whether the determination is made to support a gas RATA, to support a flow RATA, or to quality assure the data from a continuous moisture monitoring system, record the following data elements (as applicable to the moisture measurement method used): (A) Test number; (B) Run number; (C) The beginning date, hour, and minute of the run; (D) The ending date, hour, and minute of the run; (E) Unit operating level (low, mid, high, or normal, as appropriate); (F) Moisture measurement method; (G) Volume of H 2 (H) Mass of H 2 (I) Dry gas meter calibration factor; (J) Average dry gas meter temperature (°F); (K) Barometric pressure (inches of mercury); (L) Differential pressure across the orifice meter (inches of H 2 (M) Initial and final dry gas meter readings (ft 3 (N) Total sample gas volume, corrected to standard conditions (dscf); and (O) Percentage of moisture in the stack gas (percent H 2 (vi) The raw data and calculated results for any stratification tests performed in accordance with sections 6.5.6.1 through 6.5.6.3 of appendix A to this part. (vii) [Reserved] (viii) [Reserved] (ix) For a unit with a flow monitor installed on a rectangular stack or duct, if a site-specific default or measured wall effects adjustment factor (WAF) is used to correct the stack gas volumetric flow rate data to account for velocity decay near the stack or duct wall, the owner or operator shall keep records of the following for each flow RATA performed with EPA Method 2 in appendices A-1 and A-2 to part 60 of this chapter, subsequent to the WAF determination: (A) Monitoring system ID; (B) Test number; (C) Operating level; (D) RATA end date and time; (E) Number of Method 1 traverse points; and (F) Wall effects adjustment factor (WAF), to the nearest 0.0001. (8) For each certified continuous emission monitoring system, continuous opacity monitoring system, excepted monitoring system, or alternative monitoring system, the date and description of each event which requires certification, recertification, or certain diagnostic testing of the system and the date and type of each test performed. If the conditional data validation procedures of § 75.20(b)(3) are to be used to validate and report data prior to the completion of the required certification, recertification, or diagnostic testing, the date and hour of the probationary calibration error test shall be reported to mark the beginning of conditional data validation. (9) When hardcopy relative accuracy test reports, certification reports, recertification reports, or semiannual or annual reports for gas or flow rate CEMS are required or requested under § 75.60(b)(6) or § 75.63, the reports shall include, at a minimum, the following elements (as applicable to the type(s) of test(s) performed): (i) Summarized test results. (ii) DAHS printouts of the CEMS data generated during the calibration error, linearity, cycle time, and relative accuracy tests. (iii) For pollutant concentration monitor or diluent monitor relative accuracy tests at normal operating load: (A) The raw reference method data from each run, i.e., the data under paragraph (a)(7)(iv)(Q) of this section (usually in the form of a computerized printout, showing a series of one-minute readings and the run average); (B) The raw data and results for all required pre-test, post-test, pre-run and post-run quality assurance checks ( i.e. (C) The raw data and results for any moisture measurements made during the relative accuracy testing, i.e., the data under paragraphs (a)(7)(v)(A) through (a)(7)(v)(O) of this section; and (D) Tabulated, final, corrected reference method run data ( i.e. (iv) For relative accuracy tests for flow monitors: (A) The raw flow rate reference method data, from Reference Method 2 (or its allowable alternatives) under appendix A to part 60 of this chapter, including auxiliary moisture data (often in the form of handwritten data sheets), i.e., the data under paragraphs (a)(7)(ii)(A) through (a)(7)(ii)(T), paragraphs (a)(7)(iii)(A) through (a)(7)(iii)(M), and, if applicable, paragraphs (a)(7)(v)(A) through (a)(7)(v)(O) of this section; and (B) The tabulated, final volumetric flow rate values used in the relative accuracy calculations (determined from the flow rate reference method data and other necessary measurements, such as moisture, stack temperature and pressure), along with the equations used to convert the raw data to the final values and example calculations to demonstrate how the test data were reduced. (v) Calibration gas certificates for the gases used in the linearity, calibration error, and cycle time tests and for the calibration gases used to quality assure the gas monitor reference method data during the relative accuracy test audit. (vi) Laboratory calibrations of the source sampling equipment. (vii) A copy of the test protocol used for the CEMS certifications or recertifications, including narrative that explains any testing abnormalities, problematic sampling, and analytical conditions that required a change to the test protocol, and/or solutions to technical problems encountered during the testing program. (viii) Diagrams illustrating test locations and sample point locations (to verify that locations are consistent with information in the monitoring plan). Include a discussion of any special traversing or measurement scheme. The discussion shall also confirm that sample points satisfy applicable acceptance criteria. (ix) Names of key personnel involved in the test program, including test team members, plant contacts, agency representatives and test observers on site. (x) For testing involving use of EPA Protocol gases, the owner or operator shall record in electronic and hardcopy format the following information, as applicable: (A) On and after September 26, 2011, for each gas monitor, for both low and high measurement ranges, record the following information for the mid-level or high-level EPA Protocol gas (as applicable) that is used for daily calibration error tests, and the low-, mid-, and high-level gases used for quarterly linearity checks. For O 2 ( 1 ( 2 ( 3 ( 4 ( 5 (B) On and after September 26, 2011, for each usage of Reference Method 3A in appendix A-2 to part 60 of this chapter, or Method 6C or 7E in appendix A-4 to part 60 of this chapter performed using EPA Protocol gas for the certification, recertification, routine quality assurance or diagnostic testing (reportable diagnostics, only) of a Part 75 monitoring system, record the information required by paragraphs (a)(9)(x)(A)( 1 5 (xi) On and after March 27, 2012, for all RATAs performed pursuant to § 75.74(c)(2)(ii), section 6.5 of appendix A to this part and section 2.3.1 of appendix B to this part, and for all NO X (A) The name, telephone number and e-mail address of the Air Emission Testing Body; (B) The name of each on-site Qualified Individual, as defined in § 72.2 of this chapter; (C) For the reference method(s) that were performed, the date(s) that each on-site Qualified Individual took and passed the relevant qualification exam(s) required by ASTM D7036-04 (incorporated by reference, see (D) The name and e-mail address of each qualification exam provider. (10) Whenever reference methods are used as backup monitoring systems pursuant to § 75.20(d)(3), the owner or operator shall record the following information: (i) For each test run using Reference Method 2 (or its allowable alternatives in appendix A to part 60 of this chapter) to determine volumetric flow rate, record the following data elements (as applicable to the measurement method used): (A) Unit or stack identification number; (B) Reference method system and component identification numbers; (C) Run date and hour; (D) The data in paragraph (a)(7)(ii) of this section, except for paragraphs (a)(7)(ii)(A), (F), (H), (L) and (Q) through (T); and (E) The data in paragraph (a)(7)(iii), except on a run basis. (ii) For each reference method test run using Method 6C, 7E, or 3A in appendix A to part 60 of this chapter to determine SO 2 X 2 2 (A) Unit or stack identification number; (B) The reference method system and component identification numbers; (C) Run number; (D) Run start date and hour; (E) Run end date and hour; (F) The data in paragraphs (a)(7)(iv)(B) through (I) and (L) through (O); and (G) Stack gas density adjustment factor (if applicable). (iii) For each hour of each reference method test run using Method 6C, 7E, or 3A in appendix A to part 60 of this chapter to determine SO 2 X 2 2 (A) Unit or stack identification number; (B) The reference method system and component identification numbers; (C) Run number; (D) Run date and hour; (E) Pollutant or diluent gas being measured; (F) Unadjusted (raw) average pollutant or diluent gas concentration for the hour; and (G) Average pollutant or diluent gas concentration for the hour, adjusted as appropriate for moisture, calibration bias (or calibration error) and stack gas density. (11) For each other quality-assurance test or other quality assurance activity, the owner or operator shall record the following (as applicable): (i) Component/system identification code; (ii) Parameter; (iii) Test or activity completion date and hour; (iv) Test or activity description; (v) Test result; (vi) Reason for test; and (vii) Test code. (12) For each request for a quality assurance test extension or exemption, for any loss of exempt status, and for each single-load flow RATA claim pursuant to section 2.3.1.3(c)(3) of appendix B to this part, the owner or operator shall record the following (as applicable): (i) For a RATA deadline extension or exemption request: (A) Monitoring system identification code; (B) Date of last RATA; (C) RATA expiration date without extension; (D) RATA expiration date with extension; (E) Type of RATA extension of exemption claimed or lost; (F) Year to date hours of usage of fuel other than very low sulfur fuel; (G) Year to date hours of non-redundant back-up CEMS usage at the unit/stack; and (H) Quarter and year. (ii) For a linearity test or flow-to-load ratio test quarterly exemption: (A) Component-system identification code; (B) Type of test; (C) Basis for exemption; (D) Quarter and year; and (E) Span scale. (iii) [Reserved] (iv) For a fuel flowmeter accuracy test extension: (A) Component-system identification code; (B) Date of last accuracy test; (C) Accuracy test expiration date without extension; (D) Accuracy test expiration date with extension; (E) Type of extension; (F) Quarter and year; and (G) On and after April 27, 2011, fuel code for Ozone Season Only reporters under § 75.74(c). (v) For a single-load (or single-level) flow RATA claim: (A) Monitoring system identification code; (B) Ending date of last annual flow RATA; (C) The relative frequency (percentage) of unit or stack operation at each load (or operating) level (low, mid, and high) since the previous annual flow RATA, to the nearest 0.1 percent; (D) End date of the historical load (or operating level) data collection period; and (E) Indication of the load (or operating) level (low, mid or high) claimed for the single-load flow RATA. (13) An indication that data have been excluded from a periodic span and range evaluation of an SO 2 X (14) [Reserved] (15) On and after March 27, 2012, for all RATAs performed pursuant to § 75.74(c)(2)(ii), section 6.5 of appendix A to this part or section 2.3.1 of appendix B to this part, the owner or operator shall record in electronic format the following information as provided by the AETB: (i) The name, telephone number and e-mail address of the Air Emission Testing Body; (ii) The name of each on-site Qualified Individual, as defined in § 72.2 of this chapter; (iii) For the reference method(s) that were performed, the date(s) that each on-site Qualified Individual took and passed the relevant qualification exam(s) required by ASTM D7036-04 (incorporated by reference, see (iv) The name and e-mail address of each qualification exam provider. (b) Excepted monitoring systems for gas-fired and oil-fired units. (1) For certification and quality assurance testing of fuel flowmeters tested against a reference fuel flow rate ( i.e. (i) Unit or common pipe header identification code; (ii) Component and system identification codes of the fuel flowmeter being tested (on and after January 1, 2009, only the component identification code is required); (iii) Date and hour of test completion, for a test performed in-line at the unit; (iv) Date and hour of flowmeter reinstallation, for laboratory tests; (v) Test number; (vi) Upper range value of the fuel flowmeter; (vii) Flowmeter measurements during accuracy test (and mean of values), including units of measure; (viii) Reference flow rates during accuracy test (and mean of values), including units of measure; (ix) Level of fuel flowrate test during runs (low, mid or high); (x) Average flowmeter accuracy for low and high fuel flowrates and highest flowmeter accuracy of any level designated as mid, expressed as a percent of upper range value; (xi) Indicator of whether test method was a lab comparison to reference meter or an in-line comparison against a master meter; (xii) Test result (aborted, pass, or fail); and (xiii) Description of fuel flowmeter calibration specification or procedure (in the certification application, or periodically if a different method is used for annual quality assurance testing). (2) For each transmitter or transducer accuracy test for an orifice-, nozzle-, or venturi-type flowmeter used under section 2.1.6 of appendix D to this part: (i) Component and system identification codes of the fuel flowmeter being tested (on and after January 1, 2009, only the component identification code is required); (ii) Completion date and hour of test; (iii) For each transmitter or transducer: transmitter or transducer type (differential pressure, static pressure, or temperature); the full-scale value of the transmitter or transducer, transmitter input (pre-calibration) prior to accuracy test, including units of measure; and expected transmitter output during accuracy test (reference value from NIST-traceable equipment), including units of measure; (iv) For each transmitter or transducer tested: output during accuracy test, including units of measure; transmitter or transducer accuracy as a percent of the full-scale value; and transmitter output level as a percent of the full-scale value; (v) Average flowmeter accuracy at low and high level fuel flowrates and highest flowmeter accuracy of any level designated as mid fuel flowrate, expressed as a percent of upper range value; (vi) Test result (pass, fail, or aborted); (vii) Test number; and (viii) Accuracy determination methodology. (3) For each visual inspection of the primary element or transmitter or transducer accuracy test for an orifice-, nozzle-, or venturi-type flowmeter under sections 2.1.6.1 through 2.1.6.4 of appendix D to this part: (i) Date of inspection/test; (ii) Hour of completion of inspection/test; (iii) Component and system identification codes of the fuel flowmeter being inspected/tested; and (iv) Results of inspection/test (pass or fail). (4) For fuel flowmeters that are tested using the optional fuel flow-to-load ratio procedures of section 2.1.7 of appendix D to this part: (i) Test data for the fuel flowmeter flow-to-load ratio or gross heat rate check, including: (A) Component/system identification code (on and after January 1, 2009, only the monitoring system identification code is required); (B) Calendar year and quarter; (C) Indication of whether the test is for fuel flow-to-load ratio or gross heat rate; (D) Quarterly average absolute percent difference between baseline for fuel flow-to-load ratio (or baseline gross heat rate and hourly quarterly fuel flow-to-load ratios (or gross heat rate value); (E) Test result; (F) Number of hours used in the analysis; (G) Number of hours excluded due to co-firing; (H) Number of hours excluded due to ramping; (I) Number of hours excluded in lower 25.0 percent range of operation; and (J) Test number. (ii) Reference data for the fuel flowmeter flow-to-load ratio or gross heat rate evaluation, including: (A) Completion date and hour of most recent primary element inspection or test number of the most recent primary element inspection (as applicable); (on and after January 1, 2009, the test number of the most recent primary element inspection is required in lieu of the completion date and hour for the most recent primary element inspection); (B) Completion date and hour of most recent flow meter of transmitter accuracy test or test number of the most recent flowmeter or transmitter accuracy test (as applicable); (on and after January 1, 2009, the test number of the most recent flowmeter or transmitter accuracy test is required in lieu of the completion date and hour for the most recent flowmeter or transmitter accuracy test); (C) Beginning date and hour of baseline period; (D) Completion date and hour of baseline period; (E) Average fuel flow rate, in 100 scfh for gas and lb/hr for oil; (F) Average load, in megawatts, 1000 lb/hr of steam, or mmBtu/hr thermal output; (G) Baseline fuel flow-to-load ratio, in the appropriate units of measure (if using fuel flow-to-load ratio); (H) Baseline gross heat rate if using gross heat rate, in the appropriate units of measure (if using gross heat rate check); (I) Number of hours excluded from baseline data due to ramping; (J) Number of hours excluded from baseline data in lower 25.0 percent of range of operation; (K) Average hourly heat input rate; (L) Flag indicating baseline data collection is in progress and that fewer than four calendar quarters have elapsed since the quarter of the last flowmeter QA test; (M) Number of hours excluded due to co-firing; and (N) Monitoring system identification code. (5) For gas-fired peaking units or oil-fired peaking units using the optional procedures of appendix E to this part, for each initial performance, periodic, or quality assurance/quality control-related test: (i) For each run of emission data, record the following data: (A) Unit or common pipe identification code; (B) Monitoring system identification code for appendix E system (on and after January 1, 2009, component identification codes shall be reported in addition to the monitoring system identification code); (C) Run start date and time; (D) Run end date and time; (E) Total heat input during the run (mmBtu); (F) NO X (G) Response time of the O 2 X (H) Type of fuel(s) combusted during the run. This requirement remains in effect through December 31, 2008; (I) Heat input rate (mmBtu/hr) during the run; (J) Test number; (K) Run number; (L) Operating level during the run; (M) NO X (N) Diluent concentration recorded by the reference method during the run; and (O) Moisture measurement for the run (if applicable). (ii) For each run during which oil or mixed fuels are combusted record the following data: (A) Unit or common pipe identification code; (B) Monitoring system identification code for oil monitoring system (on and after January 1, 2009, component identification codes shall be reported in addition to the monitoring system identification code); (C) Run start date and time; (D) Run end date and time; (E) Mass flow or volumetric flow of oil, in the units of measure for the type of fuel flowmeter; (F) Gross calorific value of oil in the appropriate units of measure; (G) Density of fuel oil in the appropriate units of measure (if density is used to convert oil volume to mass); (H) Hourly heat input (mmBtu) during run from oil; (I) Test number; (J) Run number; and (K) Operating level during the run. (iii) For each run during which gas or mixed fuels are combusted record the following data: (A) Unit or common pipe identification code; (B) Monitoring system identification code for gas monitoring system (on and after January 1, 2009, component identification codes shall be reported in addition to the monitoring system identification code); (C) Run start date and time; (D) Run end date and time; (E) Volumetric flow of gas (100 scf); (F) Gross calorific value of gas (Btu/100 scf); (G) Hourly heat input (mmBtu) during run from gas; (H) Test number; (I) Run number; and (J) Operating level during the run. (iv) For each operating level at which runs were performed: (A) Completion date and time of last run for operating level (as applicable). This requirement remains in effect through December 31, 2008; (B) Type of fuel(s) combusted during test; (C) Average heat input rate at that operating level (mmBtu/hr); (D) Arithmetic mean of NO X (E) F-factor used in calculations of NO X (F) Unit operating parametric data related to NO X 2 (G) Test number; (H) Operating level for runs; and (I) Component identification code (required on and after January 1, 2009). (6) On and after March 27, 2012, for all stack testing performed pursuant to section 2.1 of appendix E to this part, the owner or operator shall record in electronic format the following information as provided by the AETB: (i) The name, telephone number and e-mail address of the Air Emission Testing Body; (ii) The name of each on-site Qualified Individual, as defined in § 72.2 of this chapter; (iii) For the reference method(s) that were performed, the date(s) that each on-site Qualified Individual took and passed the relevant qualification exam(s) required by ASTM D7036-04 (incorporated by reference, see (iv) The name and e-mail address of each qualification exam provider. (c) Except as otherwise provided in § 75.58(b)(3)(i), for units with add-on SO 2 X (1) A list of operating parameters for the add-on emission controls, including parameters in § 75.58(b), appropriate to the particular installation of add-on emission controls; and (2) The range of each operating parameter in the list that indicates the add-on emission controls are properly operating. (d) Excepted monitoring for low mass emissions units under § 75.19(c)(1)(iv). 2 X 2 (1) For each run of each test performed using the procedures of section 2.1 of appendix E to this part, record the following data: (i) Unit or common pipe identification code; (ii) Run start date and time; (iii) Run end date and time; (iv) NO X (v) Response time of the O 2 X (vi) Type of fuel(s) combusted during the run; (vii) Test number; (viii) Run number; (ix) Operating level during the run; (x) NO X (xi) Diluent concentration recorded by the reference method during the run; (xii) Moisture measurement for the run (if applicable); and (xiii) An indicator (“flag”) if the run is used to calculate the highest 3-run average NO X (2) For each single-load or multiple-load appendix E test, record the following: (i) The three-run average NO X (ii) An indicator that the average NO X X (iii) The default NO X X (iv) An indicator that the add-on NO X (v) Parameter data indicating the use and efficacy of control equipment during the test; and (vi) Indicator of whether the testing was done at base load, peak load or both (if appropriate); and (vii) The default NO X (3) For each unit in a group of identical units qualifying for reduced testing under § 75.19(c)(1)(iv)(B), record the following data: (i) The unique group identification code assigned to the group. This code must include the ORIS code of one of the units in the group; (ii) The ORIS code or facility identification code for the unit; (iii) The plant name of the facility at which the unit is located, consistent with the facility's monitoring plan; (iv) The identification code for the unit, consistent with the facility's monitoring plan; (v) A record of whether or not the unit underwent fuel and unit-specific testing for purposes of establishing a fuel and unit-specific NO X (vi) The completion date of the fuel and unit-specific test performed for purposes of establishing a fuel and unit-specific NO X (vii) The fuel and unit-specific NO X (viii) The type of fuel combusted for the units during testing and represented by the resulting default NO X (ix) The control status for the units during testing and represented by the resulting default NO X (x) Documentation supporting the qualification of all units in the group for reduced testing, in accordance with the criteria established in § 75.19(c)(1)(iv)(B)( 1 (xi) Purpose of group tests; (xii) On and after April 27, 2011, the number of tests for group; and (xiii) On and after April 27, 2011, the number of units in group. (4) On and after March 27, 2012, for all NO X (i) The name, telephone number and e-mail address of the Air Emission Testing Body; (ii) The name of each on-site Qualified Individual, as defined in § 72.2 of this chapter; (iii) For the reference method(s) that were performed, the date(s) that each on-site Qualified Individual took and passed the relevant qualification exam(s) required by ASTM D7036-04 (incorporated by reference, see (iv) The name and e-mail address of each qualification exam provider. (e) DAHS Verification. [64 FR 28614, May 26, 1999, as amended at 67 FR 40442, June 12, 2002; 70 FR 28683, May 18, 2005; 63 FR 4354, Jan. 24, 2008; 76 FR 17315, Mar. 28, 2011] Subpart G—Reporting Requirements § 75.60 General provisions. (a) The designated representative for any affected unit subject to the requirements of this part shall comply with all reporting requirements in this section and with the signatory requirements of § 72.21 of this chapter for all submissions. (b) Submissions. (1) Initial certifications. (2) Recertifications. (3) Monitoring plans. (4) Electronic quarterly reports. (5) Other petitions and communications. (6) Semiannual or annual RATA reports. (7) Routine appendix E retest reports. (c) Confidentiality of data. (1) All emission data reported in quarterly reports under § 75.64 shall remain public information. (2) For information submitted under this part other than emission data submitted in quarterly reports, the designated representative must assert a claim of confidentiality at the time of submission for any information he or she wishes to have treated as confidential business information (CBI) under subpart B of part 2 of this chapter. Failure to assert a claim of confidentiality at the time of submission may result in disclosure of the information by EPA without further notice to the designated representative. (3) Any claim of confidentiality for information submitted in quarterly reports under § 75.64 must include substantiation of the claim. Failure to provide substantiation may result in disclosure of the information by EPA without further notice. (4) As provided under subpart B of part 2 of this chapter, EPA may review information submitted to determine whether it is entitled to confidential treatment even when confidentiality claims are initially received. The EPA will contact the designated representative as part of such a review process. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26538, May 17, 1995; 64 FR 28620, May 26, 1999; 67 FR 40442, June 12, 2002; 73 FR 4356, Jan. 24, 2008; 76 FR 17316, Mar. 28, 2011] § 75.61 Notifications. (a) Submission. (1) Initial certification and recertification test notifications. X (i) Notification of initial certification testing and full recertification. Initial certification test notifications and notifications of full recertification testing under § 75.20(b)(2) shall be submitted not later than 21 days prior to the first scheduled day of certification or recertification testing. In emergency situations when full recertification testing is required following an uncontrollable failure of equipment that results in lost data, notice shall be sufficient if provided within 2 business days following the date when testing is scheduled. Testing may be performed on a date other than that already provided in a notice under this subparagraph as long as notice of the new date is provided either in writing or by telephone or other means at least 7 days prior to the original scheduled test date or the revised test date, whichever is earlier. (ii) Notification of certification retesting, and partial recertification testing. (iii) Repeat of testing without notice. (iv) Waiver from notification requirements. (2) New unit, newly affected unit, new stack, or new flue gas desulfurization system operation notification. (i) Notification of the planned date shall be submitted not later than 45 days prior to the date the unit commences commercial operation or becomes affected, or not later than 45 days prior to the date when a new stack or flue gas desulfurization system exhausts emissions to the atmosphere. (ii) If the date when the unit commences commercial operation or becomes affected, or the date when the new stack or flue gas desulfurization system exhausts emissions to the atmosphere, whichever is applicable, changes from the planned date, a notification of the actual date shall be submitted not later than 7 days following: The date the unit commences commercial operation or becomes affected, or the date when a new stack or flue gas desulfurization system exhausts emissions to the atmosphere. (3) Unit shutdown and recommencement of commercial operation. (i) For planned unit shutdowns (e.g., extended maintenance outages), written notification of the planned shutdown date shall be provided at least 21 days prior to the applicable compliance date, and written notification of the planned date of recommencement of commercial operation shall be provided at least 21 days in advance of unit restart. If the actual shutdown date or the actual date of recommencement of commercial operation differs from the planned date, written notice of the actual date shall be submitted no later than 7 days following the actual date of shutdown or of recommencement of commercial operation, as applicable; (ii) For unplanned unit shutdowns (e.g., forced outages), written notification of the actual shutdown date shall be provided no more than 7 days after the shutdown, and written notification of the planned date of recommencement of commercial operation shall be provided at least 21 days in advance of unit restart. If the actual date of recommencement of commercial operation differs from the expected date, written notice of the actual date shall be submitted no later than 7 days following the actual date of recommencement of commercial operation. (4) Use of backup fuels for appendix E procedures. (5) Periodic relative accuracy test audits, appendix E retests, and low mass emissions unit retests. (i) Written notification under paragraph (a) (5) of this section may be provided either by mail or by facsimile. In addition, written notification may be provided by electronic mail, provided that the respective State agency or office of EPA agrees that this is an acceptable form of notification. (ii) Notwithstanding the notice requirements under paragraph (a)(5) of this section, the owner or operator may elect to repeat a periodic relative accuracy test, appendix E restest, or low mass emissions unit retest immediately, without additional notification whenever the owner or operator has determined that a test was failed, or that a second test is necessary in order to attain a reduced relative accuracy test frequency. (iii) Waiver from notification requirements. (6) Notice of combustion of emergency fuel under appendix D or E. (7) Long-term cold storage and recommencement of commercial operation. (i) Whenever an affected unit has been placed into long-term cold storage, written notification of the date and hour that the unit was shutdown and a statement from the designated representative stating that the shutdown is expected to last for at least two years from that date, in accordance with the definition for long-term cold storage of a unit as provided in § 72.2 of this chapter. (ii) Whenever an affected unit that has been placed into long-term cold storage is expected to resume operation, written notification shall be submitted 45 calendar days prior to the planned date of recommencement of commercial operation. If the actual date of recommencement of commercial operation differs from the expected date, written notice of the actual date shall be submitted no later than 7 days following the actual date of recommencement of commercial operation. (8) Certification deadline date for new or newly affected units. 2 X (b) The owner or operator or designated representative shall submit notification of certification tests and recertification tests for continuous opacity monitoring systems as specified in § 75.20(c)(8) to the State or local air pollution control agency. (c) If the Administrator determines that notification substantially similar to that required in this section is required by any other State or local agency, the owner or operator or designated representative may send the Administrator a copy of that notification to satisfy the requirements of this section, provided the ORISPL unit identification number(s) is denoted. [60 FR 26538, May 17, 1995, as amended at 61 FR 25582, May 22, 1996; 61 FR 59162, Nov. 22, 1996; 64 FR 28620, May 26, 1999; 67 FR 40442, 40443, June 12, 2002; 73 FR 4356, Jan. 24, 2008; 76 FR 17316, Mar. 28, 2011] § 75.62 Monitoring plan submittals. (a) Submission Electronic. (2) Hardcopy. (b) Contents. (c) Format. (d) On and after April 27, 2011, consistent with § 72.21 of this chapter, a hardcopy cover letter signed by the Designated Representative (DR) shall accompany each hardcopy monitoring plan submittal. The cover letter shall include the certification statement described in § 72.21(b) of this chapter, and shall be submitted to the applicable EPA Regional Office and to the appropriate State or local air pollution control agency. For electronic monitoring plan submittals to the Administrator, a cover letter is not required. However, at his or her discretion, the DR may include important explanatory text or comments with an electronic monitoring plan submittal, so long as the information is provided in an electronic format that is compatible with the other data required to be reported under this section. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26539, May 17, 1995; 64 FR 28621, May 26, 1999; 67 FR 40443, June 12, 2002; 73 FR 4356, Jan. 24, 2008; 76 FR 17316, Mar. 28, 2011] § 75.63 Initial certification or recertification application. (a) Submission. (1) Initial certifications. (A) To the Administrator, the electronic information required by paragraph (b)(1) of this section. Except for subpart E applications for alternative monitoring systems or unless specifically requested by the Administrator, do not submit a hardcopy of the test data and results to the Administrator. (B) To the applicable EPA Regional Office and the appropriate State and/or local air pollution control agency, the hardcopy information required by paragraph (b)(2) of this section. (ii) For units for which the owner or operator is applying for certification approval of the optional excepted methodology under § 75.19 for low mass emissions units, submit, no later than 45 days prior to commencing use of the methodology: (A) To the Administrator, the electronic low mass emission qualification information required by § 75.53(f)(5)(i) or § 75.53(h)(4)(i) (as applicable) and paragraph (b)(1)(i) of this section; and (B) To the applicable EPA Regional Office and appropriate State and/or local air pollution control agency, the hardcopy information required by § 75.19(a)(2) and § 75.53(f)(5)(ii) or § 75.53(h)(4)(ii) (as applicable), the hardcopy results of any appendix E (of this part) tests or any CEMS data analysis used to derive a fuel-and-unit-specific default NO X (2) Recertifications and diagnostic testing. (ii) Within 45 days after completing all recertification tests under § 75.20(b), submit the hardcopy information required by paragraph (b)(2) of this section to the applicable EPA Regional Office and the appropriate State and/or local air pollution control agency. The applicable EPA Regional Office or appropriate State or local air pollution control agency may waive the requirement to provide hardcopy recertification test and data results. The applicable EPA Regional Office or the appropriate State or local air pollution control agency may also discontinue the waiver and reinstate the requirement of this paragraph to provide a hardcopy report of the recertification test data and results. (iii) Notwithstanding the requirements of paragraphs (a)(2)(i) and (a)(2)(ii) of this section, for an event for which the Administrator determines that only diagnostic tests ( see (b) Contents. (1) Electronic. (ii) The results of the test(s) required by § 75.20, including the type of test conducted, testing date, information required by § 75.59, and the results of any failed tests that affect data validation. (2) Hardcopy. (ii) The results of the test(s) required by § 75.20, including the type of test conducted, testing date, information required by § 75.59(a)(9), and the results of any failed tests that affect data validation. (iii) [Reserved] (iv) Designated representative signature certifying the accuracy of the submission. (c) Format. (d) Consistent with § 72.21 of this chapter, a hardcopy cover letter signed by the Designated Representative (DR) shall accompany the hardcopy portion of each certification or recertification application. The cover letter shall include the certification statement described in § 72.21(b) of this chapter, and shall be submitted to the applicable EPA Regional Office and to the appropriate State or local air pollution control agency. For the electronic portion of a certification or recertification application submitted to the Administrator, a cover letter is not required. However, at his or her discretion, the DR may include important explanatory text or comments with the electronic portion of a certification or recertification application, so long as the information is provided in an electronic format compatible with the other data required to be reported under this section. [64 FR 28621, May 26, 1999, as amended at 67 FR 40443, June 12, 2002; 73 FR 4357, Jan. 24, 2008; 76 FR 17317, Mar. 28, 2011] § 75.64 Quarterly reports. (a) Electronic submission. (1) Facility information: (i) Identification, including: (A) Facility/ORISPL number; (B) Calendar quarter and year for the data contained in the report; and (C) Version of the electronic data reporting format used for the report. (ii) Location, including: (A) Plant name and facility ID; (B) EPA AIRS facility system ID; (C) State facility ID; (D) Source category/type; (E) Primary SIC code; (F) State postal abbreviation; (G) County code; and (H) Latitude and longitude. (2) The information and hourly data required in § 75.53 and §§ 75.57 through 75.59, excluding the following: (i) Descriptions of adjustments, corrective action, and maintenance; (ii) Information which is incompatible with electronic reporting (e.g., field data sheets, lab analyses, quality control plan); (iii) Opacity data listed in or § 75.57(f), and in § 75.59(a)(8); (iv) For units with SO 2 X (v) [Reserved] (vi) Information required by § 75.57(h) concerning the causes of any missing data periods and the actions taken to cure such causes; (vii) Hardcopy monitoring plan information required by § 75.53 and hardcopy test data and results required by § 75.59; (viii) Records of flow monitor and moisture monitoring system polynomial equations, coefficients, or “K” factors required by § 75.59(a)(5)(vi) or § 75.59(a)(5)(vii); (ix) Daily fuel sampling information required by § 75.58(c)(3)(i) for units using assumed values under appendix D; (x) Information required by §§ 75.59(b)(1)(vi), (vii), (viii), (ix), and (xiii), and (b)(2)(iii) and (iv) concerning fuel flowmeter accuracy tests and transmitter/transducer accuracy tests; (xi) Stratification test results required as part of the RATA supplementary records under § 75.59(a)(7); (xii) Data and results of RATAs that are aborted or invalidated due to problems with the reference method or operational problems with the unit and data and results of linearity checks that are aborted or invalidated due to problems unrelated to monitor performance; and (xiii) Supplementary RATA information required under § 75.59(a)(7), except that: (A) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for flow RATAs at circular or rectangular stacks (or ducts) in which angular compensation for yaw and/or pitch angles is used ( i.e. (B) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for any flow RATA run at a circular stack in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is determined by direct measurement; (C) The data under § 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs at circular stacks in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a default wall effects adjustment factor is applied; and (D) The data under § 75.59(a)(7)(ix)(A) through (F) shall be reported for all flow RATAs at rectangular stacks or ducts in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is applied. (3) Facility identification information, including: (i) Facility/ORISPL number; (ii) Calendar quarter and year for the data contained in the report; and (iii) Version of the electronic data reporting format used for the report. (4) In accordance with § 75.62(a)(1), if any monitoring plan information required in § 75.53 requires an update, either under § 75.53(b) or elsewhere in this part, submission of the electronic monitoring plan update shall be completed prior to or concurrent with the submittal of the quarterly electronic data report for the appropriate quarter in which the update is required. (5) The daily calibration error test and daily interference check information required in § 75.59(a)(1) and (a)(2) must always be included in the electronic quarterly emissions report. All other certification, quality assurance, and quality control information in § 75.59 that is not excluded from electronic reporting under paragraph (a)(2) or (a)(7) of this section shall be submitted separately, either prior to or concurrent with the submittal of the relevant electronic quarterly emissions report. However, reporting of the information in § 75.59(a)(9)(x) is not required until September 26, 2011, and reporting of the information in § 75.59(a)(15), (b)(6), and (d)(4) is not required until March 27, 2012. (6) The information and hourly data required in §§ 75.57 through 75.59, and daily calibration error test data, daily interference check, and off-line calibration demonstration information required in § 75.59(a)(1) and (2). (7) Notwithstanding the requirements of paragraphs (a)(4) through (a)(6) of this section, the following information is excluded from electronic reporting: (i) Descriptions of adjustments, corrective action, and maintenance; (ii) Information which is incompatible with electronic reporting (e.g., field data sheets, lab analyses, quality control plan); (iii) Opacity data listed in § 75.57(f), and in § 75.59(a)(8); (iv) For units with SO 2 X (v) Information required by § 75.57(h) concerning the causes of any missing data periods and the actions taken to cure such causes; (vi) Hardcopy monitoring plan information required by § 75.53 and hardcopy test data and results required by § 75.59; (vii) Records of flow monitor and moisture monitoring system polynomial equations, coefficients, or “K” factors required by § 75.59(a)(5)(vi) or § 75.59(a)(5)(vii); (viii) Daily fuel sampling information required by § 75.58(c)(3)(i) for units using assumed values under appendix D of this part; (ix) Information required by §§ 75.59(b)(1)(vi), (vii), (viii), (ix), and (xiii), and (b)(2)(iii) and (iv) concerning fuel flowmeter accuracy tests and transmitter/transducer accuracy tests; (x) Stratification test results required as part of the RATA supplementary records under § 75.59(a)(7); (xi) Data and results of RATAs that are aborted or invalidated due to problems with the reference method or operational problems with the unit and data and results of linearity checks that are aborted or invalidated due to problems unrelated to monitor performance; (xii) Supplementary RATA information required under § 75.59(a)(7)(i) through § 75.59(a)(7)(v), except that: (A) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for flow RATAs at circular or rectangular stacks (or ducts) in which angular compensation for yaw and/or pitch angles is used ( i.e. (B) The applicable data elements under § 75.59(a)(7)(ii)(A) through (T) and under § 75.59(a)(7)(iii)(A) through (M) shall be reported for any flow RATA run at a circular stack in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is determined by direct measurement; (C) The data under § 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs at circular stacks in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a default wall effects adjustment factor is applied; and (D) The data under § 75.59(a)(7)(ix)(A) through (F) shall be reported for all flow RATAs at rectangular stacks or ducts in which Method 2 in appendices A-1 and A-2 to part 60 of this chapter is used and a wall effects adjustment factor is applied; and (xiii) The certification required by section 6.1.2(b) of appendix A to this part and recorded under § 75.57(a)(7). (8) Tons (rounded to the nearest tenth) of SO 2 2 (9) Average NO X X (10) Tons of CO 2 2 (11) Total heat input (mmBtu) for quarter and cumulative heat input for calendar year. (12) Unit or stack or common pipe header operating hours for quarter and cumulative unit or stack or common pipe header operating hours for calendar year. (13) For low mass emissions units for which the owner or operator is using the optional low mass emissions methodology in § 75.19(c) to calculate NO X X X (14) For low mass emissions units using the optional long term fuel flow methodology under § 75.19(c), for each quarter report the long term fuel flow for each fuel according to § 75.58(f)(2). (15) For units using the optional fuel flow to load procedure in section 2.1.7 of appendix D to this part, report both the fuel flow-to-load baseline data and the results of the fuel flow-to-load test each quarter. (b) The designated representative shall affirm that the component/system identification codes and formulas in the quarterly electronic reports, submitted to the Administrator pursuant to § 75.53, represent current operating conditions. (c) Compliance certification. 2 X (d) Electronic format. (e) [Reserved] (f) Method of submission. (g) At his or her discretion, the DR may include important explanatory text or comments with an electronic quarterly report submittal, so long as the information is provided in a format that is compatible with the other data required to be reported under this section. [64 FR 28622, May 26, 1999, as amended at 67 FR 40444, June 12, 2002; 73 FR 4357, Jan. 24, 2008; 76 FR 17317, Mar. 28, 2011] § 75.65 Opacity reports. The owner or operator or designated representative shall report excess emissions of opacity recorded under § 75.57(f) to the applicable State or local air pollution control agency. [64 FR 28623, May 26, 1999, as amended at 67 FR 40444, June 12, 2002] § 75.66 Petitions to the Administrator. (a) General. (b) Alternative flow monitoring method petition. (1) Identification of the affected unit(s); (2) Description of why the minimum siting criteria cannot be met within the existing ductwork or stack(s). This description shall include diagrams of the existing ductwork or stack, as well as documentation of any attempts to locate a flow monitor; and (3) Description of proposed alternative method for monitoring flow. (c) Alternative to standards incorporated by reference. (1) A description of why the prescribed standard is not being used; (2) A description and diagram(s) of any equipment and procedures used in the proposed alternative; (3) Information demonstrating that the proposed alternative produces data acceptable for use in the Acid Rain Program, including accuracy and precision statements, NIST traceability certificates or protocols, or other supporting data, as applicable to the proposed alternative. (d) Alternative monitoring system petitions. (e) Parametric monitoring procedure petitions. (1) Publish a notice in the Federal Register (2) Notify interested parties of receipt of a parametric monitoring petition. (f) [Reserved] (g) Petitions for emissions or heat input apportionments. (1) A description of the units, including their fuel type, their boiler type, and their categorization as Phase I units, substitution units, compensating units, Phase II units, new units, or non-affected units; (2) A formula describing how the emissions or heat input are to be apportioned to which units; (3) A description of the methods and parameters used to apportion the emissions or heat input; and (4) Any other information necessary to demonstrate that the apportionment method accurately measures emissions or heat input and does not underestimate emissions or heat input from affected units. (h) Partial recertification petition. (1) Identification of the monitoring system(s) being changed; (2) A description of the changes being made to the system; (3) An explanation of why the changes are being made; and (4) A description of the possible effect upon the monitoring system's ability to measure, record, and report emissions. (i) [Reserved] (j) Petition for alternative method of accounting for emissions prior to completion of certification tests. (1) Identification of the affected unit(s); (2) A detailed explanation of the alternative method to account for emissions of the following parameters, as applicable: SO 2 X 2 X (3) A demonstration that the proposed alternative does not underestimate emissions. (k) Petition for an alternative to the stabilization criteria for the cycle time test in section 6.4 of appendix A to this part. (l) Any other petitions to the Administrator under this part. (1) Identification of the affected plant and unit(s); (2) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement; (3) A description and diagram of any equipment and procedures used in the proposed alternative, if applicable; (4) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and is consistent with the purposes of this part and of section 412 of the Act and that any adverse effect of approving such alternative will be de minimis (5) Any other relevant information that the Administrator may require. [58 FR 3701, Jan. 11, 1993,as amended at 60 FR 26540, 26569, May 17, 1995; 61 FR 59162, Nov. 20, 1996; 64 FR 28623, May 26, 1999; 67 FR 40444, June 12, 2002; 73 FR 4358, Jan. 24, 2008] § 75.67 Retired units petitions. (a) [Reserved] (b) For combustion sources seeking to enter the Opt-in Program in accordance with part 74 of this chapter that will be permanently retired and governed upon entry into the Opt-in Program by a thermal energy plan in accordance with § 74.47 of this chapter, an exemption from the requirements of this part, including the requirement to install and certify a continuous emissions monitoring system, may be obtained from the Administrator if the designated representative submits to the Administrator a petition for such an exemption prior to the deadline in § 75.4 by which the continuous emission or opacity monitoring systems must complete the required certification tests. [60 FR 17131, Apr. 4, 1995, as amended at 60 FR 26541, May 17, 1995; 62 FR 55487, Oct. 24, 1997] § 75.68 Temporary modifications to otherwise applicable quality-assurance requirements during the COVID-19 national emergency. (a) Notwithstanding any other provision of this part, during and following the emergency period defined in paragraph (a)(1) of this section, the provisions of this section shall apply for purposes of reporting the data that are required to be reported under this part and completing the tests that are required to be completed under this part. (1) For purposes of this section, the emergency period begins on March 13, 2020, the date of the declaration of a national emergency concerning the novel coronavirus disease (COVID-19) outbreak by the President of the United States in accordance with 50 U.S.C. 1621, and concludes 60 days after the date of termination of the national emergency by Congress or the President in accordance with 50 U.S.C. 1622, provided that the emergency period under this section shall not extend past the expiration of the effectiveness of this section. (2) The provisions of this section shall apply with respect to the following tests that are required to be completed under this part: (i) Any quality-assurance test of a continuous emission monitoring system required under appendix B to this part or § 75.74(c). (ii) Any quality-assurance test of a fuel flowmeter required under section 2.1.6 of appendix D to this part or § 75.74(c). (iii) Any certification or recertification test of a continuous emission monitoring system required under § 75.20 or § 75.70(d). (iv) Any certification test of a fuel flowmeter required under section 2.1.5 of appendix D to this part or § 75.70(d). (v) Any periodic analysis of fuel sulfur content, density, or gross calorific value required under section 2.2 or 2.3 of appendix D to this part, provided that there have been no changes in the fuel supply since the most recent previous fuel analysis that would reasonably be expected to cause a change in such fuel characteristics. (vi) Any periodic retest of NO X (vii) Any periodic retest of fuel-and-unit-specific NO X (3) Following a failure to complete by the applicable deadline (or by the end of any grace period following the deadline) any required quality-assurance test or tests described in paragraph (a)(2)(i) or (ii) of this section for any continuous emission monitoring system or fuel flowmeter under this part, for any subsequent operating hour in the emergency period prior to completion of the test or tests in accordance with paragraph (a)(6)(i) of this section, the owner or operator of an affected unit may continue to report data determined using measurements obtained from the continuous emission monitoring system or fuel flowmeter as valid, provided that the following conditions are met: (i) But for the failure to complete the quality-assurance test or tests, the data obtained from the monitoring system would be considered valid without the benefit of the provisions of this section; (ii) The reason for failure to complete each such quality-assurance test is travel, plant access, or other safety restrictions implemented to address the COVID-19 national emergency; and (iii) The owner or operator creates and maintains the records specified in paragraph (a)(7)(i) of this section and the designated representative submits the notifications required under paragraphs (a)(7)(ii) and (iii) of this section. (4) Following a failure to complete by the applicable deadline any required certification or recertification test or tests described in paragraph (a)(2)(iii) or (iv) of this section for any continuous emission monitoring system or fuel flowmeter under this part, for any subsequent operating hour in an emergency period prior to completion of the test or tests in accordance with paragraph (a)(6)(i) of this section, the owner or operator of an affected unit may continue to report data determined using measurements obtained from the continuous emission monitoring system or fuel flowmeter as conditionally valid provided that the following conditions are met: (i) But for the failure to complete the certification or recertification test or tests, the data obtained from the monitoring system would be considered conditionally valid without the benefit of the provisions of this section; (ii) The reason for failure to complete each such certification or recertification test is travel, plant access, or other safety restrictions implemented to address the COVID-19 national emergency; and (iii) The owner or operator creates and maintains the records specified in paragraph (a)(7)(i) of this section and the designated representative submits the notifications required under paragraphs (a)(7)(ii) and (iii) of this section. (5) Following a failure to complete by the applicable deadline any required periodic analysis of fuel characteristics under appendix D to this part described in paragraph (a)(2)(v) of this section or any required periodic NO X X X (i) But for the failure to complete the appendix D fuel analysis or the appendix E or LME NO X (ii) The reason for failure to complete each such appendix D fuel analysis or appendix E or LME NO X (iii) The owner or operator creates and maintains the records specified in paragraph (a)(7)(i) of this section and the designated representative submits the notifications required under paragraphs (a)(7)(ii) and (iii) of this section. (6)(i) Each quality-assurance test, certification or recertification test, appendix D fuel analysis, and appendix E or LME NO X (ii) If a test or analysis for which a deadline is established under paragraph (a)(6)(i) of this section is not completed by that deadline, the test or analysis shall be completed as soon as practicable thereafter, and for each operating hour following that deadline until completion of the test or analysis, the owner or operator shall report substitute data as if the originally applicable deadline for the test or analysis were the deadline under paragraph (a)(6)(i) of this section. (iii) For purposes of determining the applicable deadline for the next quality-assurance test, appendix D fuel analysis, or appendix E or LME NO X X (7) The following recordkeeping and reporting requirements shall apply to any use of the procedures under paragraphs (a)(3) through (6) of this section: (i) The owner or operator of an affected unit reporting data under paragraph (a)(3), (4), or (5) of this section shall maintain records documenting the reasons for failure to complete by the applicable deadline each test or analysis referenced in such paragraph and demonstrating that such failure is caused by travel, plant access, or other safety restrictions implemented to address the COVID-19 national emergency. The owner or operator shall also maintain records documenting when any such travel, plant access, or other safety restrictions impairing the ability to complete testing or analyses for that unit ceased to apply. The records shall be maintained on site at the source in a form suitable for inspection for a period of three years from the date of each record. (ii) By five business days after the applicable deadline for a test or analysis referenced in paragraph (a)(3), (4), or (5) of this section, the designated representative shall submit to the Administrator, by email transmitted to [email protected], (A) Facility ID (ORIS); (B) Facility name; (C) Monitoring location ID and/or unit ID; (D) Identification of the quality-assurance test, certification or recertification test, appendix D fuel analysis, or appendix E or LME NO X (E) Identification of the applicable deadline for the test or analysis under part 75 (not including any applicable grace period); (F) A detailed explanation of the reason for failure to complete the test or analysis by the applicable deadline under part 75, including an explanation of how such failure is caused by travel, plant access, or other safety restrictions implemented to address the COVID-19 national emergency; (G) The certification statements in § 72.21(b)(1) and (2) of this chapter. (iii) By five business days after the completion in accordance with paragraph (a)(6)(i) or (ii) of this section of a delayed test or analysis referenced in paragraph (a)(3), (4), or (5) of this section, the designated representative shall submit to the Administrator, by email transmitted to [email protected], (A) Facility ID (ORIS); (B) Facility name; (C) Monitoring location ID and/or unit ID; (D) Identification of the quality-assurance test, certification or recertification test, appendix D fuel analysis, or appendix E or LME NO X (E) Identification of the date as of which travel, plant access, or other safety restrictions previously impairing the ability to complete the delayed test or analysis for the unit no longer applied; (F) Identification of the date as of which the test or analysis was completed in accordance with paragraph (a)(6)(i) or (ii) of this section; and (G) The certification statements in § 72.21(b)(1) and (2) of this chapter. (iv) With respect to any test or analysis of a type that is required to be performed more frequently than once per unit operating quarter, a series of such required tests or analyses may be treated as a single test or analysis for purposes of a notification submitted under paragraph (a)(7)(ii) or (iii) of this section, with the notification under paragraph (a)(7)(ii) to be submitted by five business days after the first failure to perform such a test or analysis by the applicable deadline and the notification under paragraph (a)(7)(iii) to be submitted by five business days after the first completion of such a test or analysis in accordance with paragraph (a)(6)(i) or (ii) of this section. (v) A notification submitted under paragraph (a)(7)(ii) or (iii) of this section may include information for more than one required test for a given unit or monitoring location, provided that each item of information required to be included in such notification pursuant to paragraphs (a)(7)(ii)(D) through (F) of this section or paragraphs (a)(7)(iii)(D) through (F) of this section is provided separately for each required test included in the notification. (vi) No claim of confidentiality may be asserted with respect to any information included in a notification submitted under paragraph (a)(7)(ii) or (iii) of this section. (vii) Notwithstanding the deadlines for submission of notifications in paragraphs (a)(7)(ii), (iii), and (iv) of this section, no such notification from any owner or operator shall be due less than 30 days after the effective date of this section. (b) The requirements of this section are effective from April 22, 2020 and, except for those in paragraphs (a)(6)(ii) and (iii) and (a)(7)(i) of this section, shall cease to have effect October 19, 2020. [85 FR 22372, Apr. 22, 2020] Subpart H—NO X Source: 63 FR 57507, Oct. 27, 1998, unless otherwise noted. § 75.70 NO X (a) Applicability. X (1) For purposes of this subpart, the term “affected unit” shall mean any unit that is subject to a State or federal NO X X X (2) In addition, the provisions of subparts A, C, D, E, F, and G and appendices A through G of this part applicable to NO X X X X X X 2 2 X (b) Compliance dates. X (c) Prohibitions. (2) No owner or operator of an affected unit or a non-affected unit under § 75.72(b)(2)(ii) shall operate the unit so as to discharge, or allow to be discharged emissions of NO X (3) No owner or operator of an affected unit or a non-affected unit under § 75.72(b)(2)(ii) shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording NO X (4) No owner or operator of an affected unit or a non-affected unit under § 75.72(b)(2)(ii) shall retire or permanently discontinue use of the continuous emission monitoring system, any component thereof, or any other approved emission monitoring system under this part, except under any one of the following circumstances: (i) During the period that the unit is covered by a retired unit exemption that is in effect under the State or federal NO X (ii) The owner or operator is monitoring NO X (iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system in accordance with § 75.61. (d) Initial certification and recertification procedures. X (2) The owner or operator of an affected unit that is not subject to an Acid Rain emissions limitation shall comply with the initial certification and recertification procedures established by an applicable State or federal NO X X X X X (e) Quality assurance and quality control requirements. X X X (f) Missing data procedures. (1) For an owner or operator using a continuous emissions monitoring system, substitute for missing data in accordance with the applicable missing data procedures in §§ 75.31 through 75.37 whenever the unit combusts fuel and: (i) A valid, quality-assured hour of NO X X (ii) A valid, quality-assured hour of flow data (in scfh) has not been measured and recorded for a unit from a certified flow monitor or by an approved alternative monitoring system under subpart E of this part; (iii) A valid, quality-assured hour of heat input rate data (in mmBtu/hr) has not been measured and recorded for a unit from a certified flow monitor and a certified diluent (CO 2 2 X X (iv) A valid, quality-assured hour of NO X X X X X X (v) A valid, quality-assured hour of moisture data (in percent H 2 (2) For an owner or operator using an excepted monitoring system under appendix D or E of this part, substitute for missing data in accordance with the missing data procedures in section 2.4 of appendix D to this part or in section 2.5 of appendix E to this part whenever the unit combusts fuel and: (i) A valid, quality-assured hour of fuel flow rate data has not been measured and recorded by a certified fuel flowmeter that is part of an excepted monitoring system under appendix D or E of this part; or (ii) A fuel sample value for gross calorific value, or if necessary, density or specific gravity, from a sample taken an analyzed in accordance with appendix D of this part is not available; or (iii) A valid, quality-assured hour of NO X (g) Reporting data prior to initial certification. X (1) For units that the owner or operator intends to monitor for NO X X X (2) For units that the owner or operator intends to monitor for NO X X X (3) For any unit, the reference methods under § 75.22 of this part. (4) For any unit using the low mass emission excepted monitoring methodology under § 75.19, the procedures in paragraphs (g)(1) or (2) of this section. (5) Any unit using the procedures in paragraph (g)(2) of this section that is required to report heat input for purposes of allocating allowances shall also report the maximum potential hourly heat input of the unit, as defined in § 72.2 of this chapter. (6) For any unit using continuous emissions monitors, the conditional data validation procedures in § 75.20(b)(3)(ii) through (b)(3)(ix). (h) Petitions. X X (2) Notwithstanding paragraph (h)(1) of this section, petitions requesting an alternative to a requirement concerning any additional CEMS required solely to meet the common stack provisions of § 75.72 shall be submitted to the permitting authority and the Administrator and shall be governed by paragraph (h)(3)(ii) of this section. Such a petition shall meet the requirements of § 75.66 and any additional requirements established by an applicable State or federal NO X (3)(i) The designated representative of an affected unit that is not subject to an Acid Rain emissions limitation may submit a petition to the permitting authority and the Administrator requesting an alternative to any requirement of this subpart. Such a petition shall meet the requirements of § 75.66 and any additional requirements established by an applicable State or federal NO X (ii) Use of an alternative to any requirement of this subpart is in accordance with this subpart only to the extent that it is approved by the Administrator and by the permitting authority if required by an applicable State or federal NO X [63 FR 57507, Oct. 27, 1998, as amended at 64 FR 28624, May 26, 1999; 67 FR 40444, June 12, 2002] § 75.71 Specific provisions for monitoring NO X X (a) Coal-fired units. (1) Meet the general operating requirements in § 75.10 for a NO X X 2 2 X 2 2 (2) Meet the general operating requirements in § 75.10 for a NO X X X X 2 2 (b) Moisture correction. X X X (2) If a correction for the stack gas moisture content is needed to properly calculate NO X X X 2 X (3) If a correction for the stack gas moisture content is needed to properly calculate NO X X (c) Gas-fired nonpeaking units or oil-fired nonpeaking units. (1) Meet the requirements of paragraph (a) of this section and, if applicable, paragraph (b) of this section; or (2) Meet the general operating requirements in § 75.10 for a NO X X (3) Meet the requirements of the low mass emission excepted methodology under paragraph (e)(2) of this section and under § 75.19, if applicable. (d) Gas-fired or oil-fired peaking units. (1) Meet the requirements of paragraph (c) of this section; or (2) Use the procedures in appendix D to this part for determining hourly heat input and the procedure specified in appendix E to this part for estimating hourly NO X X X X (e) Low mass emissions units. X X X X (f) Other units. [63 FR 57508, Oct. 27, 1998, as amended at 64 FR 28624, May 26, 1999; 67 FR 40444, 40445, June 12, 2002; 67 FR 53505, Aug. 16, 2002; 73 FR 4358, Jan. 24, 2008] § 75.72 Determination of NO X The owner or operator of an affected unit shall either: calculate hourly NO X X X X X X X X (a) Unit utilizing common stack with other affected unit(s). (1) Install, certify, operate, and maintain a NO X X (i) Apportion the common stack heat input rate to the individual units according to the procedures in § 75.16(e)(3); or (ii) Install, certify, operate, and maintain a flow monitoring system and diluent monitor in the duct to the common stack from each unit; or (iii) If any of the units using the common stack are eligible to use the procedures in appendix D to this part, (A) Use the procedures in appendix D to this part to determine heat input rate for that unit; and (B) Install, certify, operate, and maintain a flow monitoring system and a diluent monitor in the duct to the common stack for each remaining unit; or (2) Install, certify, operate, and maintain a NO X (i) Install, certify, operate, and maintain a flow monitoring system in the duct to the common stack from each unit; or (ii) For any unit using the common stack and eligible to use the procedures in appendix D to this part, (A) Use the procedures in appendix D to determine heat input rate for that unit; and (B) Install, certify, operate, and maintain a flow monitoring system in the duct to the common stack for each remaining unit. (b) Unit utilizing common stack with nonaffected unit(s). (1) Install, certify, operate, and maintain a NO X (i) Install, certify, operate, and maintain a flow monitoring system in the duct to the common stack from each affected unit; or (ii) For any affected unit using the common stack and eligible to use the procedures in appendix D to this part, (A) Use the procedures in appendix D to determine heat input for that unit; however, for a common pipe configuration, the heat input apportionment provisions in section 2.1.2 of appendix D to this part shall not be used to meet the NO X (B) Install, certify, operate, and maintain a flow monitoring system in the duct to the common stack for each remaining affected unit that exhausts to the common stack; or (2) Install, certify, operate, and maintain a NO X (i) Designate the nonaffected units as affected units in accordance with the applicable State or federal NO X (ii) Install, certify, operate, and maintain a flow monitoring system in the common stack and a NO X X X X X (A) Install, certify, operate, and maintain a flow monitoring system in the duct from each nonaffected unit or, (B) For any nonaffected unit exhausting to the common stack and otherwise eligible to use the procedures in appendix D to this part, determine heat input rate using the procedures in appendix D for that unit. However, for a common pipe serving both affected and non-affected units, the heat input rate apportionment provisions in section 2.1.2 of appendix D to this part shall not be used to meet the NO X (iii) Install a flow monitoring system in the common stack and record the combined emissions from all units as the combined NO X (iv) Submit a petition to the permitting authority and the Administrator to allow use of a method for apportioning NO X X X (c) Unit with a main stack and a bypass stack. X X (1) Install, certify, operate, and maintain separate NO X X X (2) Monitor NO X X X X X X (3) Install, certify, operate, and maintain a NO X X X X 2 2 X X X X X X X X X X X X (d) Unit with multiple stack or duct configuration. (1) Install, certify, operate, and maintain a NO X X X X (2) Install, certify, operate, and maintain a NO X X X (3) If the unit is eligible to use the procedures in appendix D to this part and if the conditions and restrictions of § 75.17(c)(2) are fully met, install, certify, operate, and maintain a NO X (e) Units using a NO X concentration monitoring system and a flow monitoring system to determine NO X mass. X X X X X (1) Install, certify, operate, and maintain a CO 2 2 (i) Apportion heat input rate from the common stack to each unit according to § 75.16(e)(3), where all units utilizing the common stack are affected units, or (ii) Measure heat input rate to each affected unit, using a flow monitor and a CO 2 2 (2) For units that are eligible to use appendix D to this part, use the procedures in appendix D to this part to determine heat input rate for the unit. However, the use of a fuel flowmeter in a common pipe header and the provisions of sections 2.1.2.1 and 2.1.2.2 of appendix D to this part are not applicable to any unit that is using the provisions of this subpart to monitor, record, and report NO X X (f) Procedures for apportioning hourly NO X mass emission rate to the unit level. X X X (g) Procedures for apportioning heat input to the unit level. X [63 FR 57507, Oct. 27, 1998, as amended at 67 FR 40445, June 12, 2002; 73 FR 4358, Jan. 24, 2008; 88 FR 36895, June 5, 2023] § 75.73 Recordkeeping and reporting. (a) General recordkeeping provisions. (1) The information required in §§ 75.57(a)(2), (a)(4), (a)(5), (a)(6), (b), (c)(2), (d), (g), and (h). (2) The information required in §§ 75.58(b)(2) or (b)(3) (for units with add-on NO X (3) For each hour when the unit is operating, NO X (4) During the second and third calendar quarters, cumulative ozone season heat input and cumulative ozone season operating hours. (5) Heat input and NO X (6) Specific heat input record provisions for gas-fired or oil-fired units using the procedures in appendix D to this part. (7) Specific NO X record provisions for gas-fired or oil-fired units using the optional low mass emissions excepted methodology in § 75.19. (i) Date and hour; (ii) If one type of fuel is combusted in the hour, fuel type (pipeline natural gas, natural gas, residual oil, or diesel fuel) or, if more than one type of fuel is combusted in the hour, the fuel type which results in the highest emission factors for NO X (iii) Average hourly NO X (iv) Hourly NO X (8) Formulas from monitoring plan for total NO X (b) Certification, quality assurance and quality control record provisions. (c) Monitoring plan recordkeeping provisions General provisions. X (2) Monitoring plan updates. (3) Contents of the monitoring plan. (d) General reporting provisions. X (2) The designated representative for an affected unit shall submit the following for each affected unit or group of units monitored at a common stack and each non-affected unit under § 75.72(b)(2)(ii): (i) Initial certification and recertification applications in accordance with § 75.70(d); (ii) Monitoring plans in accordance with paragraph (e) of this section; and (iii) Quarterly reports in accordance with paragraph (f) of this section. (3) Other petitions and communications. (4) Quality assurance RATA reports. (5) Notifications. (6) Routine appendix E retest reports. (e) Monitoring plan reporting Electronic submission. (2) Hardcopy submission. (f) Quarterly reports Electronic submission. (i) Facility information: (A) Identification, including: ( 1 ( 2 ( 3 (B) [Reserved] (ii) The information and hourly data required in paragraphs (a) and (b) of this section, except for: (A) Descriptions of adjustments, corrective action, and maintenance; (B) Information which is incompatible with electronic reporting (e.g., field data sheets, lab analyses, quality control plan); (C) For units with NO X (D) Information required by § 75.57(h) concerning the causes of any missing data periods and the actions taken to cure such causes; (E) Hardcopy monitoring plan information required by § 75.53 and hardcopy test data and results required by § 75.59; (F) Records of flow polynomial equations and numerical values required by § 75.59(a)(5)(vi); (G) Daily fuel sampling information required by § 75.58(c)(3)(i) for units using assumed values under appendix D to this part; (H) Information required by § 75.59(b)(2) concerning transmitter or transducer accuracy tests; (I) Stratification test results required as part of the RATA supplementary records under § 75.59(a)(7); (J) Data and results of RATAs that are aborted or invalidated due to problems with the reference method or operational problems with the unit and data and results of linearity checks that are aborted or invalidated due to operational problems with the unit; and (K) Supplementary RATA information required under § 75.59(a)(7), except that: ( 1 i.e. ( 2 ( 3 ( 4 (iii) Average NO X X (iv) Tons of NO X X X (v) During the second and third calendar quarters, cumulative heat input for the ozone season. (vi) Unit or stack or common pipe header operating hours for quarter, cumulative unit, stack or common pipe header operating hours for calendar year, and, during the second and third calendar quarters, cumulative operating hours during the ozone season. (vii) Reporting period heat input. (viii) New reporting frequency and begin date of the new reporting frequency (if applicable). (ix) On and after on January 1, 2024, for a unit subject to subpart GGGGG of part 97 of this chapter or a state implementation plan approved under § 52.38(b)(12) of this chapter and determining NO X X (x) On and after January 1, 2024, for a unit that is subject to subpart GGGGG of part 97 of this chapter or a state implementation plan approved under § 52.38(b)(12) of this chapter, that lists coal or a solid coal-derived fuel as a fuel in the unit's monitoring plan under § 75.53 for any portion of the ozone season in the year for which data are being reported, that serves a generator of 100 MW or larger nameplate capacity, and that is not a circulating fluidized bed boiler, provided that through December 31, 2029, the requirements under this paragraph (f)(1)(x) shall apply to a unit in a given calendar year only if the unit also was equipped with selective catalytic reduction controls on or before September 30 of the previous year: (A) Daily NO X (B) Daily heat input (mmBtu) for each day of the reporting period; (C) Daily average NO X (D) Daily NO X X (E) Cumulative NO X X (F) Cumulative NO X X (2) Verification of identification codes and formulas. (3) Compliance certification. (i) The monitoring data submitted were recorded in accordance with the applicable requirements of this part, including the quality assurance procedures and specifications; and (ii) With regard to a unit with add-on emission controls and for all hours where data are substituted in accordance with § 75.34(a)(1), the add-on emission controls were operating within the range of parameters listed in the monitoring plan and the substitute values do not systematically underestimate NO X (4) Electronic format, method of submission, and explanatory information. [64 FR 28624, May 26, 1999, as amended at 67 FR 40446, June 12, 2002; 73 FR 4359, Jan. 24, 2008; 88 FR 36896, June 5, 2023] § 75.74 Annual and ozone season monitoring and reporting requirements. (a) Annual monitoring requirement. X (2) The owner or operator of an affected unit subject to a State or federal NO X (b) Ozone season monitoring requirements. (1) Meet the requirements of this subpart on an annual basis; or (2) Meet the requirements of this subpart during the ozone season, except as specified in paragraph (c) of this section. (c) If the owner or operator of an affected unit chooses to meet the requirements of this subpart on less than an annual basis in accordance with paragraph (b)(2) of this section, then: (1) The owner or operator of a unit that uses continuous emissions monitoring systems or a fuel flowmeter to meet any of the requirements of this subpart shall quality assure the hourly ozone season emission data required by this subpart. To achieve this, the owner or operator shall operate, maintain and calibrate each required CEMS and shall perform diagnostic testing and quality assurance testing of each required CEMS or fuel flowmeter according to the applicable provisions of paragraphs (c)(2) through (c)(5) of this section. Except where otherwise noted, the provisions of paragraphs (c)(2) and (c)(3) of this section apply instead of the quality assurance provisions in sections 2.1 through 2.3 of appendix B to this part, and shall be used in lieu of those appendix B provisions. (2) Quality assurance requirements prior to the ozone season. (i) For each required gas monitor ( i.e. X 2 2 2 2 2 (A) Conduct each linearity check in accordance with the general procedures in section 6.2 of appendix A to this part, except that the data validation procedures in sections 6.2(a) through (f) of appendix A do not apply. (B) Each linearity check shall be done “hands-off,” as described in section 2.2.3(c) of appendix B to this part. (C) In the time period extending from the date and hour in which the linearity check is passed through April 30, the owner or operator shall operate and maintain the CEMS and shall perform daily calibration error tests of the CEMS in accordance with section 2.1 of appendix B to this part. When a calibration error test is failed, as described in section 2.1.4 of appendix B to this part, corrective actions shall be taken. The additional calibration error test provisions of section 2.1.3 of appendix B to this part shall be followed. (D) If the linearity check is not completed by April 30, data validation shall be determined in accordance with paragraph (c)(3)(ii)(E) of this section. (ii) For each required CEMS ( i.e. X X (A) Conduct each RATA in accordance with the applicable procedures in sections 6.5 through 6.5.10 of appendix A to this part, except that the data validation procedures in sections 6.5(f)(1) through (f)(6) do not apply, and, for flow rate monitoring systems, the required RATA load level(s) (or operating level(s)) shall be as specified in this paragraph. (B) Each RATA shall be done “hands-off,” as described in section 2.3.2 (c) of appendix B to this part. The provisions in section 2.3.1.4 of appendix B to this part, pertaining to the number of allowable RATA attempts, shall apply. (C) For flow rate monitoring systems installed on peaking units or bypass stacks and for flow monitors exempted from multiple-level RATA testing under section 6.5.2(e) of appendix A to this part, a single-load (or single-level) RATA is required. For all other flow rate monitoring systems, a 2-load (or 2-level) RATA is required at the two most frequently-used load or operating levels (as defined under section 6.5.2.1 of appendix A to this part), with the following exceptions. Except for flow monitors exempted from 3-level RATA testing under section 6.5.2(e) of appendix A to this part, a 3-load flow RATA is required at least once every five years and is also required if the flow monitor polynomial coefficients or K factor(s) are changed prior to conducting the flow RATA required under this paragraph. (D) A bias test of each required NO X X (E) In the time period extending from the hour of completion of the required RATA through April 30, the owner or operator shall operate and maintain the CEMS by performing, at a minimum, the following activities: ( 1 ( 2 X (F) Data validation. ( 1 ( 2 (3) Quality assurance requirements within the ozone season. (i) Daily calibration error tests and (if applicable) interference checks of each CEMS required by this subpart shall be performed in accordance with sections 2.1.1 and 2.1.2 of appendix B to this part. The applicable provisions in sections 2.1.3, 2.1.4 and 2.1.5 of appendix B to this part, pertaining, respectively, to additional calibration error tests and calibration adjustments, data validation, and quality assurance of data with respect to daily assessments, shall also apply. (ii) For each gas monitor required by this subpart, linearity checks shall be performed in the second and third calendar quarters, as follows: (A) For the second calendar quarter, the pre-ozone season linearity check required under paragraph (c)(2)(i) of this section shall be performed by April 30. (B) For the third calendar quarter, a linearity check shall be performed and passed no later than July 30. (C) Conduct each linearity check in accordance with the general procedures in section 6.2 of appendix A to this part, except that the data validation procedures in sections 6.2(a) through (f) of appendix A do not apply. (D) Each linearity check shall be done “hands-off,” as described in section 2.2.3(c) of appendix B to this part. (E) Data Validation. i.e. ( 1 ( 2 (F) A pre-season linearity check performed and passed in April satisfies the linearity check requirement for the second quarter. (G) The third quarter linearity check requirement in paragraph (c)(3)(ii)(B) of this section is waived if: ( 1 ( 2 (iii) For each flow monitoring system required by this subpart, except for flow monitors installed on non-load-based units that do not produce electrical or thermal output, flow-to-load ratio tests are required in the second and third calendar quarters, in accordance with section 2.2.5 of appendix B to this part. If the flow-to-load ratio test for the second calendar quarter is failed, the owner or operator shall follow the procedures in section 2.2.5(c)(8) of appendix B to this part. If the flow-to-load ratio test for the third calendar quarter is failed, data from the flow monitor shall be considered invalid at the beginning of the next ozone season unless, prior to May 1 of the next calendar year, the owner or operator has either successfully implemented Option 1 in section 2.2.5.1 of appendix B to this part or Option 2 in section 2.2.5.2 of appendix B to this part, or unless a flow RATA has been performed and passed in accordance with paragraph (c)(2)(ii) of this section. (iv) For each differential pressure-type flow monitor used to meet the requirements of this subpart, quarterly leak checks are required in the second and third calendar quarters, in accordance with section 2.2.2 of appendix B to this part. For the second calendar quarter of the year, only the unit or stack operating hours in the months of May and June shall be used to determine whether the second calendar quarter is a QA operating quarter (as defined in § 72.2 of this chapter). Data validation for quarterly flow monitor leak checks shall be done in accordance with section 2.2.3(g) of appendix B to this part. If the leak check for the third calendar quarter is failed and a subsequent leak check is not passed by the end of the ozone season, then data from the flow monitor shall be considered invalid at the beginning of the next ozone season unless a leak check is passed prior to May 1 of the next calendar year. (v) A fuel flow-to-load ratio test in section 2.1.7 of appendix D to this part shall be performed in the second and third calendar quarters if, for a unit using a fuel flowmeter to determine heat input under this subpart, the owner or operator has elected to use the fuel flow-to-load ratio test to extend the deadline for the next fuel flowmeter accuracy test. Automatic deadline extensions may be claimed for the two calendar quarters outside the ozone season (the first and fourth calendar quarters), since a fuel flow-to-load ratio test is not required in those quarters. If a fuel flow-to-load ratio test is failed, follow the applicable procedures and data validation provisions in section 2.1.7.4 of appendix D to this part. If the fuel flow-to-load ratio test for the third calendar quarter is failed, data from the fuel flowmeter shall be considered invalid at the beginning of the next ozone season unless the requirements of section 2.1.7.4 of appendix D to this part have been fully met prior to May 1 of the next calendar year. (vi)-(viii) [Reserved] (ix) If, for any required CEMS, diagnostic linearity checks or RATAs other than those required by this section are performed during the ozone season, use the applicable data validation procedures in section 2.2.3 (for linearity checks) or 2.3.2 (for RATAs) of appendix B to this part. (x) If any required CEMS is recertified within the ozone season, use the data validation provisions in § 75.20(b)(3) and, if applicable, paragraphs (c)(3)(xi) and (c)(3)(xii) of this section. (xi) If, at the end of the second quarter of any calendar year, a required quality assurance, diagnostic, or recertification test of a monitoring system has not been completed, and if data contained in the quarterly report are conditionally valid pending the results of test(s) to be completed in a subsequent quarter, the owner or operator shall indicate this by means of a suitable conditionally valid data flag in the electronic quarterly report for the second calendar quarter. The owner or operator shall resubmit the report for the second quarter if the required quality assurance, diagnostic, or recertification test is subsequently failed. In the resubmitted report, the owner or operator shall use the appropriate missing data routine in §§ 75.31 through § 75.37 to replace with substitute data each hour of conditionally valid data that was invalidated by the failed quality assurance, diagnostic, or recertification test. Alternatively, if any required quality assurance, diagnostic, or recertification test is not completed by the end of the second calendar quarter but is completed no later than 30 days after the end of that quarter ( i.e. (xii) If, at the end of the third quarter of any calendar year, a required quality assurance, diagnostic or recertification test of a monitoring system has not been completed, and if data contained in the quarterly report are conditionally valid pending the results of test(s) to be completed, the owner or operator shall do one of the following: (A) If the results of the required tests are not available within 30 days of the end of the third calendar quarter and cannot be submitted with the quarterly report for the third calendar quarter, then the test results are considered to be missing and the owner or operator shall use the appropriate missing data routine in §§ 75.31 through § 75.37 to replace with substitute data each hour of conditionally valid data in the third quarter report. In addition, if the data in the second quarterly report were flagged as conditionally valid at the end of the quarter, pending the results of the same missing tests, the owner or operator shall resubmit the report for the second quarter and shall use the appropriate missing data routine in §§ 75.31 through § 75.37 to replace with substitute data each hour of conditionally valid data associated with the missing quality assurance, diagnostic, or recertification tests; or (B) If the required quality assurance, diagnostic, or recertification tests are completed no later than 30 days after the end of the third calendar quarter, the test data and results may be submitted with the third quarter report even though the test date(s) are from the fourth calendar quarter. In this instance, if the required tests are passed in accordance with the conditional data validation provisions of § 75.20(b)(3), all conditionally valid data associated with the tests shall be reported as quality-assured. If the tests are failed, the owner or operator shall use the appropriate missing data routine in §§ 75.31 through § 75.37 to replace with substitute data each hour of conditionally valid data associated with the failed test(s). In addition, if the data in the second quarterly report were flagged as conditionally valid at the end of the quarter, pending the results of the same failed test(s), the owner or operator shall resubmit the report for the second quarter and shall use the appropriate missing data routine in §§ 75.31 through § 75.37 to replace with substitute data each hour of conditionally valid data associated with the failed test(s). (4) The owner or operator of a unit using the procedures in appendix D of this part to determine heat input rate is required to maintain fuel flowmeters only during the ozone season, except that for purposes of determining the deadline for the next periodic quality assurance test on the fuel flowmeter, the owner or operator shall include all fuel flowmeter QA operating quarters (as defined in § 72.2) for the entire calendar year, not just fuel flowmeter QA operating quarters in the ozone season. For each calendar year, the owner or operator shall record, for each fuel flowmeter, the number of fuel flowmeter QA operating quarters. The owner or operator shall include all calendar quarters in the year when determining the deadline for visual inspection of the primary fuel flowmeter element, as specified in section 2.1.6(c) of appendix D to this part. (5) The owner or operator of a unit using the procedures in appendix D of this part to determine heat input rate is only required to sample fuel for the purposes of determining density and GCV during the ozone season, except that: (i) The owner or operator of a unit that performs sampling from the fuel storage tank upon delivery must sample the tank between the date and hour of the most recent delivery before the first date and hour that the unit operates in the ozone season and the first date and hour that the unit operates in the ozone season. (ii) The owner or operator of a unit that performs sampling upon delivery from the delivery vehicle must ensure that all shipments received during the calendar year are sampled. (iii) The owner or operator of a unit that performs sampling on each day the unit combusts fuel or that performs fuel sampling continuously must sample the fuel starting on the first day the unit operates during the ozone season. The owner or operator then shall use that sampled value for all hours of combustion during the first day of unit operation, continuing until the date and hour of the next sample. (6) The owner or operator shall, in accordance with § 75.73, record and report the hourly data required by this subpart and shall record and report the results of all required quality assurance tests, as follows: (i) All hourly emission data for the period of time from May 1 through September 30 of each calendar year shall be recorded and reported. For missing data purposes, only the data recorded in the time period from May 1 through September 30 shall be considered quality-assured; (ii) The results of all daily calibration error tests and flow monitor interference checks performed in the time period from May 1 through September 30 shall be recorded and reported; (iii) For the time periods described in paragraphs (c)(2)(i)(C) and (c)(2)(ii)(E) of this section, hourly emission data and the results of all daily calibration error tests and flow monitor interference checks shall be recorded. The owner or operator may opt to report unit operating data, daily calibration error test and flow monitor interference check results, and hourly emission data in the time period from April 1 through April 30. However, only the data recorded in the time period from May 1 through September 30 shall be used for NO X (iv) The results of all required quality assurance tests (RATAs, linearity checks, flow-to-load ratio tests and leak checks) performed during the ozone season shall be reported in the appropriate ozone season quarterly report; and (v) The results of RATAs (and any other quality assurance test(s) required under paragraph (c)(2) or (c)(3) of this section) which affect data validation for the current ozone season, but which were performed outside the ozone season ( i.e. (7) The owner or operator shall use only quality-assured data from within ozone seasons in the substitute data procedures under subpart D of this part and section 2.4.2 of appendix D to this part. (i) The lookback periods (e.g., 2160 quality-assured monitor operating hours for a NO X X (ii) The applicable missing data procedures of §§ 75.31 through 75.37 shall be used, with one exception. When a fuel which has a significantly higher NO X X X X X X X X (iii) In order to apply the missing data routines described in §§ 75.31 through 75.37 on an ozone season-only basis, the procedures in those sections shall be modified as follows: (A) The use of the initial missing data procedures in § 75.31 shall commence with the first unit operating hour in the first ozone season for which emissions data are required to be reported under § 75.64. (B) In § 75.31(a), the phrases “During the first 720 quality-assured monitor operating hours within the ozone season” and “during the first 2,160 quality-assured monitor operating hours within the ozone season” apply respectively instead of the phrases “During the first 720 quality-assured monitor operating hours” and “during the first 2,160 quality-assured monitor operating hours”. (C) In § 75.32(a), the phrases “the first 720 quality-assured monitor operating hours within the ozone season” and “the first 2,160 quality-assured monitor operating hours within the ozone season” apply, respectively, instead of the phrases “the first 720 quality-assured monitor operating hours” and “the first 2,160 quality-assured monitor operating hours”. (D) In § 75.32(a)(1), the phrase “Following initial certification, prior to completion of 3,672 unit (or stack) operating hours within the ozone season” applies instead of the phrase “Prior to completion of 8,760 unit (or stack) operating hours following initial certification”. (E) In Equation 8, the phrase “Total unit operating hours within the ozone season” applies instead of the phrase “Total unit operating hours”. (F) In § 75.32(a)(2), the phrase “3,672 unit (or stack) operating hours within the ozone season” applies instead of the phrase “8,760 unit (or stack) operating hours”. (G) In the numerator of Equation 9, the phrase “Total unit operating hours within the ozone season” applies instead of the phrase “Total unit operating hours”, and the phrase “3,672 unit operating hours within the ozone season” applies instead of the phrase “8,760 unit operating hours”. In the denominator of Equation 9, the number “3,672” applies instead of “8,760”. (H) Use the following instead of the first three sentences in § 75.32(a)(3): “When calculating percent monitor data availability using Equation 8 or 9, the owner or operator shall include all unit or stack operating hours within the ozone season, and all monitor operating hours within the ozone season for which quality-assured data were recorded by a certified primary monitor; a certified redundant or non-redundant backup monitor or a reference method for that unit; or by an approved alternative monitoring system under subpart E of this part. No hours from more than three years (26,280 clock hours) earlier shall be used in Equation 9. For a unit that has accumulated fewer than 3,672 ozone season operating hours in the previous three years, use the following: in the numerator of Equation 9 use ‘Total unit operating hours within the ozone season for which quality-assured data were recorded in the previous three years’; and in the denominator of Equation 9 use ‘Total unit operating hours within the ozone season, in the previous three years’ ” (I) In § 75.33(a), the phrases “the first 720 quality-assured monitor operating hours within the ozone season” and “the first 2,160 quality-assured monitor operating hours within the ozone season” apply, respectively, instead of the phrases “the first 720 quality-assured monitor operating hours” and “the first 2,160 quality-assured monitor operating hours”. (J) Instead of the last sentence of § 75.33(a), use “For the purposes of missing data substitution, the owner or operator of a unit shall use only quality-assured monitor operating hours of data that were recorded within the ozone season and no more than three years (26,280 clock hours) prior to the date and time of the missing data period.” (K) In §§ 75.33(b), 75.33(c), 75.35, 75.36, and 75.37, the phrases “720 quality-assured monitor operating hours within the ozone season” and “2,160 quality-assured monitor operating hours within the ozone season” apply, respectively, instead of the phrases “720 quality-assured monitor operating hours” and “2,160 quality-assured monitor operating hours”. (L) In § 75.34(a)(3) and (a)(5), the phrases “720 quality-assured monitor operating hours within the ozone season” and “2160 quality-assured monitor operating hours within the ozone season” apply instead of “720 quality-assured monitor operating hours” and “2160 quality-assured monitor operating hours”, respectively. (8) The owner or operator of a unit with NO X X X X (i) For units that can combust more than one fuel, the fuel or fuels combusted each hour; and (ii) For units with add-on emission controls, using the missing data options in §§ 75.34(a)(1) through 75.34(a)(5), the range of operating parameters for add-on emission controls (as defined in the quality assurance/quality control program for the unit required by section 1 in appendix B to this part) and information for verifying proper operation of the add-on emission controls during missing data periods, as described in § 75.34(d). (9) The designated representative shall certify with each quarterly report that NO X X X (10) Units may qualify to use the low mass emissions excepted monitoring methodology in § 75.19 on an ozone season basis. In order to be allowed to use this methodology, a unit may not emit more than 50 tons of NO X 3 X (11) Units may qualify to use the optional NO X [63 FR 57507, Oct. 27, 1998, as amended at 64 FR 28627, May 26, 1999; 67 FR 40446, 40447, June 12, 2002; 67 FR 57274, Sept. 9, 2002; 73 FR 4360, Jan. 24, 2008] § 75.75 Additional ozone season calculation procedures. (a) The owner or operator of a unit that is required to calculate daily or ozone season heat input shall do so by summing the unit's hourly heat input determined according to the procedures in this part for all hours in which the unit operated during the day or ozone season. (b) The owner or operator of a unit that is required to determine daily or ozone season NO X X [88 FR 36896, June 5, 2023] Appendix A to Part 75—Specifications and Test Procedures 1. Installation and Measurement Location 1.1 Gas Monitors (a) Following the procedures in section 8.1.1 of Performance Specification 2 in appendix B to part 60 of this chapter, install the pollutant concentration monitor or monitoring system at a location where the pollutant concentration and emission rate measurements are directly representative of the total emissions from the affected unit. Select a representative measurement point or path for the monitor probe(s) (or for the path from the transmitter to the receiver) such that the SO 2 2 2 X X X see (b) It is recommended that monitor measurements be made at locations where the exhaust gas temperature is above the dew-point temperature. If the cause of failure to meet the relative accuracy tests is determined to be the measurement location, relocate the monitor probe(s). 1.1.1 Point Monitors Locate the measurement point (1) within the centroidal area of the stack or duct cross section, or (2) no less than 1.0 meter from the stack or duct wall. 1.1.2 Path Monitors Locate the measurement path (1) totally within the inner area bounded by a line 1.0 meter from the stack or duct wall, or (2) such that at least 70.0 percent of the path is within the inner 50.0 percent of the stack or duct cross-sectional area, or (3) such that the path is centrally located within any part of the centroidal area. 1.2 Flow Monitors Install the flow monitor in a location that provides representative volumetric flow over all operating conditions. Such a location is one that provides an average velocity of the flue gas flow over the stack or duct cross section, provides a representative SO 2 1/2 1.2.1 Acceptability of Monitor Location The installation of a flow monitor is acceptable if either (1) the location satisfies the minimum siting criteria of method 1 in appendix A to part 60 of this chapter (i.e., the location is greater than or equal to eight stack or duct diameters downstream and two diameters upstream from a flow disturbance; or, if necessary, two stack or duct diameters downstream and one-half stack or duct diameter upstream from a flow disturbance), or (2) the results of a flow profile study, if performed, are acceptable (i.e., there are no cyclonic (or swirling) or stratified flow conditions), and the flow monitor also satisfies the performance specifications of this part. If the flow monitor is installed in a location that does not satisfy these physical criteria, but nevertheless the monitor achieves the performance specifications of this part, then the location is acceptable, notwithstanding the requirements of this section. 1.2.2 Alternative Monitoring Location Whenever the owner or operator successfully demonstrates that modifications to the exhaust duct or stack (such as installation of straightening vanes, modifications of ductwork, and the like) are necessary for the flow monitor to meet the performance specifications, the Administrator may approve an interim alternative flow monitoring methodology and an extension to the required certification date for the flow monitor. Where no location exists that satisfies the physical siting criteria in section 1.2.1, where the results of flow profile studies performed at two or more alternative flow monitor locations are unacceptable, or where installation of a flow monitor in either the stack or the ducts is demonstrated to be technically infeasible, the owner or operator may petition the Administrator for an alternative method for monitoring flow. 2. Equipment Specifications 2.1 Instrument Span and Range In implementing sections 2.1.1 through 2.1.6 of this appendix, set the measurement range for each parameter (SO 2 X 2 2 2 2 X 2 X 2 X 2 X 2.1.1 SO 2 Determine, as indicated in sections 2.1.1.1 through 2.1.1.5 of this appendix the span value(s) and range(s) for an SO 2 2 2.1.1.1 Maximum Potential Concentration (a) Make an initial determination of the maximum potential concentration (MPC) of SO 2 i.e., or Where, MPC = Maximum potential concentration (ppm, wet basis). (To convert to dry basis, divide the MPC by 0.9.) MEC = Maximum expected concentration (ppm, wet basis). (To convert to dry basis, divide the MEC by 0.9). %S = Maximum sulfur content of fuel to be fired, wet basis, weight percent, as determined according to the applicable method in paragraph (c) of section 2.1.1.1. %O 2w %CO 2w GCV = Minimum gross calorific value of the fuel or blend to be combusted, based on historical fuel sampling and analysis data or, if applicable, based on the fuel contract specifications (Btu/lb). If based on fuel sampling and analysis, the GCV shall be determined according to the applicable method in paragraph (c) of section 2.1.1.1. 11.32 × 10 6 66.93 × 10 6 Note: All percent values to be inserted in the equations of this section are to be expressed as a percentage, not a fractional value (e.g., 3, not .03). (b) Alternatively, if a certified SO 2 2 2 2 2 (c) When performing fuel sampling to determine the MPC, use ASTM Methods: ASTM D129-00, ASTM D240-00, ASTM D1552-01, ASTM D2622-98, ASTM D3176-89 (Reapproved 2002), ASTM D3177-02 (Reapproved 2007), ASTM D4239-02, ASTM D4294-98, ASTM D5865-01a, or ASTM D5865-10 (all incorporated by reference under § 75.6). 2.1.1.2 Maximum Expected Concentration (a) Make an initial determination of the maximum expected concentration (MEC) of SO 2 2 2 2 2 (b) For each MEC determination, substitute into Equation A-1a or A-1b the highest sulfur content and minimum GCV value for that fuel or blend, based upon all available fuel sampling and analysis results from the previous 12 months (or more), or, if fuel sampling data are unavailable, based upon fuel contract(s). (c) Alternatively, if a certified SO 2 2 2 2 2 Where: MEC = Maximum expected concentration (ppm). MPC = Maximum potential concentration (ppm), as determined by Eq. A-1a or A-1b in section 2.1.1.1 of this appendix. RE = Expected average design removal efficiency of control equipment (%). 2.1.1.3 Span Value(s) and Range(s) Determine the high span value and the high full-scale range of the SO 2 2 2 2 2.1.1.4 Dual Span and Range Requirements For most units, the high span value based on the MPC, as determined under section 2.1.1.3 of this appendix will suffice to measure and record SO 2 2 2 (a) For units with SO 2 (b) For units that combust high- and low-sulfur primary and backup fuels (or blends) and have no SO 2 (c) When two SO 2 2 2 2 2 (d) The owner or operator shall designate the monitoring systems and components in the monitoring plan under § 75.53 as follows: when a single probe and sample interface are used, either designate the low and high monitor ranges as separate SO 2 2 2 2 2 2 2 2 2 2 2 2 2 (e) Each monitoring system designated as primary or redundant backup shall meet the initial certification and quality assurance requirements for primary monitoring systems in § 75.20(c) or § 75.20(d)(1), as applicable, and appendices A and B to this part, with one exception: relative accuracy test audits (RATAs) are required only on the normal range (for units with SO 2 (f) For dual span units with SO 2 2 2 (g) The high span value and range shall be determined in accordance with section 2.1.1.3 of this appendix. The low span value shall be obtained by multiplying the MEC by a factor no less than 1.00 and no greater than 1.25, and rounding the result upward to the next highest multiple of 10 ppm (or 100 ppm, as appropriate). For units that burn high- and low-sulfur primary and backup fuels or blends and have no SO 2 2 2 2 2.1.1.5 Adjustment of Span and Range For each affected unit or common stack, the owner or operator shall make a periodic evaluation of the MPC, MEC, span, and range values for each SO 2 2 (a) If the fuel supply, the composition of the fuel blend(s), the emission controls, or the manner of operation change such that the maximum expected or potential concentration changes significantly, adjust the span and range setting to assure the continued accuracy of the monitoring system. A “significant” change in the MPC or MEC means that the guidelines in section 2.1 of this appendix can no longer be met, as determined by either a periodic evaluation by the owner or operator or from the results of an audit by the Administrator. The owner or operator should evaluate whether any planned changes in operation of the unit may affect the concentration of emissions being emitted from the unit or stack and should plan any necessary span and range changes needed to account for these changes, so that they are made in as timely a manner as practicable to coordinate with the operational changes. Determine the adjusted span(s) using the procedures in sections 2.1.1.3 and 2.1.1.4 of this appendix (as applicable). Select the full-scale range(s) of the instrument to be greater than or equal to the new span value(s) and to be consistent with the guidelines of section 2.1 of this appendix. (b) Whenever a full-scale range is exceeded during a quarter and the exceedance is not caused by a monitor out-of-control period, proceed as follows: (1) For exceedances of the high range, report 200.0 percent of the current full-scale range as the hourly SO 2 (2) For units with two SO 2 2 (c) Whenever changes are made to the MPC, MEC, full-scale range, or span value of the SO 2 2.1.2 NO X Determine, as indicated in sections 2.1.2.1 through 2.1.2.5 of this appendix, the span and range value(s) for the NO X X 2.1.2.1 Maximum Potential Concentration (a) The maximum potential concentration (MPC) of NO X X Option 1: Use 800 ppm for coal-fired and 400 ppm for oil- or gas-fired units as the maximum potential concentration of NO X Option 2: Use the specific values based on boiler type and fuel combusted, listed in Table 2-1 or Table 2-2; For a new gas-fired or oil-fired combustion turbine, if a default MPC value of 50 ppm was previously selected from Table 2-2, that value may be used until March 31, 2003; Option 3: Use NO X Option 4: Use historical CEM data over the previous 720 (or more) unit operating hours when combusting the fuel or blend with the highest NO X Option 5: If a reliable estimate of the uncontrolled NO X (b) For the purpose of providing substitute data during NO X X X 2 2 2 2 2 2 X X 2 2 (c) Report the method of determining the initial MPC and the calculation of the maximum potential NO X (d) For units with add-on NO X X X X X X X 2 X X (e) If historical CEM data are used to determine the MPC, the data must, for uncontrolled units or units equipped with low-NO X X X X X X X X Table 2-1—Maximum Potential Concentration for NO X Unit type Maximum potential concentration for NO X Tangentially-fired dry bottom and fluidized bed 460 Wall-fired dry bottom, turbo-fired dry bottom, stokers 675 Roof-fired (vertically-fired) dry bottom, cell burners, arch-fired 975 Cyclone, wall-fired wet bottom, wet bottom turbo-fired 1200 Others ( 1 1 2.1.2.2 Maximum Expected Concentration (a) Make an initial determination of the maximum expected concentration (MEC) of NO X X e.g., X X X X X X (b) If NO X X X X X (c)If historical CEM data are used to determine the MEC value(s), the MEC for each type of fuel shall be based upon 720 (or more) hours of quality-assured data from the NO X X X X X X X X 2.1.2.3 Span Value(s) and Range(s) (a) Determine the high span value of the NO X X X (b) If an existing State, local, or federal requirement for span of a NO X (c) Select the full-scale range of the instrument to be consistent with section 2.1 of this appendix and to be greater than or equal to the high span value. Include the full-scale range setting and calculations of the MPC and span in the monitoring plan for the unit. 2.1.2.4 Dual Span and Range Requirements For most units, the high span value based on the MPC, as determined under section 2.1.2.3 of this appendix will suffice to measure and record NO X X X (a) Compare the MEC value(s) determined in section 2.1.2.2 of this appendix to the high full-scale range value determined in section 2.1.2.3 of this appendix. If the MEC values for all fuels (or blends) are ≥20.0 percent of the high range value, the high span and range values determined under section 2.1.2.3 of this appendix are sufficient, irrespective of which fuel or blend is combusted in the unit. If any of the MEC values is <20.0 percent of the high range value, two spans (low and high) are required, one based on the MPC and the other based on the MEC. (b) When two NO X X X X X X (c) The owner or operator shall designate the monitoring systems and components in the monitoring plan under § 75.53 as follows: when a single probe and sample interface are used, either designate the low and high ranges as separate NO X X X X X X X X X X X X X X (d) Each monitoring system designated as primary or redundant backup shall meet the initial certification and quality assurance requirements in § 75.20(c) (for primary monitoring systems), in § 75.20(d)(1) (for redundant backup monitoring systems) and appendices A and B to this part, with one exception: relative accuracy test audits (RATAs) are required only on the normal range (for dual span units with add-on NO X (e) For dual span units with add-on NO X X X (f) The high span and range shall be determined in accordance with section 2.1.2.3 of this appendix. The low span value shall be 100.0 to 125.0 percent of the MEC, rounded up to the next highest multiple of 10 ppm (or 100 ppm, if appropriate). If more than one MEC value (as determined in section 2.1.2.2 of this appendix) is <20.0 percent of the high full-scale range value, the low span value shall be based upon whichever MEC value is closest to 20.0 percent of the high range value. The low range must be greater than or equal to the low span value, and the required calibration gases for the low range must be selected based on the low span value. However, if the default high range option in paragraph (e) of this section is selected, the full-scale of the low measurement range shall not exceed five times the MEC value (where the MEC is rounded upward to the next highest multiple of 10 ppm). For units with two NO X X X 2.1.2.5 Adjustment of Span and Range For each affected unit or common stack, the owner or operator shall make a periodic evaluation of the MPC, MEC, span, and range values for each NO X X (a) If the fuel supply, emission controls, or other process parameters change such that the maximum expected concentration or the maximum potential concentration changes significantly, adjust the NO X X (b) Whenever a full-scale range is exceeded during a quarter and the exceedance is not caused by a monitor out-of-control period, proceed as follows: (1) For exceedances of the high range, report 200.0 percent of the current full-scale range as the hourly NO X (2) For units with two NO X X (c) Whenever changes are made to the MPC, MEC, full-scale range, or span value of the NO X X 2.1.3 CO 2 2 For an O 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2.1.3.1 Maximum Potential Concentration of CO 2 The MPC and MEC values for diluent monitors are subject to the same periodic review as SO 2 X For CO 2 2 2 2 2 2.1.3.2 Minimum Potential Concentration of O 2 The owner or operator of a unit that uses a flow monitor and an O 2 2 2 2 2 2.1.3.3 Adjustment of Span and Range The MPC and MEC values for diluent monitors are subject to the same periodic review as SO 2 X 2 2 2 2 2 2.1.4 Flow Monitors Select the full-scale range of the flow monitor so that it is consistent with section 2.1 of this appendix and can accurately measure all potential volumetric flow rates at the flow monitor installation site. 2.1.4.1 Maximum Potential Velocity and Flow Rate For this purpose, determine the span value of the flow monitor using the following procedure. Calculate the maximum potential velocity (MPV) using Equation A-3a or A-3b or determine the MPV (wet basis) from velocity traverse testing using Reference Method 2 (or its allowable alternatives) in appendix A to part 60 of this chapter. If using test values, use the highest average velocity (determined from the Method 2 traverses) measured at or near the maximum unit operating load (or, for units that do not produce electrical or thermal output, at the normal process operating conditions corresponding to the maximum stack gas flow rate). Express the MPV in units of wet standard feet per minute (fpm). For the purpose of providing substitute data during periods of missing flow rate data in accordance with §§ 75.31 and 75.33 and as required elsewhere in this part, calculate the maximum potential stack gas flow rate (MPF) in units of standard cubic feet per hour (scfh), as the product of the MPV (in units of wet, standard fpm) times 60, times the cross-sectional area of the stack or duct (in ft 2 or Where: MPV = maximum potential velocity (fpm, standard wet basis). F d F c 2 Hf = maximum heat input (mmBtu/minute) for all units, combined, exhausting to the stack or duct where the flow monitor is located. A = inside cross sectional area (ft 2 %O 2d %CO 2d %H 2 2.1.4.2 Span Values and Range Determine the span and range of the flow monitor as follows. Convert the MPV, as determined in section 2.1.4.1 of this appendix, to the same measurement units of flow rate that are used for daily calibration error tests (e.g., scfh, kscfh, kacfm, or differential pressure (inches of water)). Next, determine the “calibration span value” by multiplying the MPV (converted to equivalent daily calibration error units) by a factor no less than 1.00 and no greater than 1.25, and rounding up the result to at least two significant figures. For calibration span values in inches of water, retain at least two decimal places. Select appropriate reference signals for the daily calibration error tests as percentages of the calibration span value, as specified in section 2.2.2.1 of this appendix. Finally, calculate the “flow rate span value” (in scfh) as the product of the MPF, as determined in section 2.1.4.1 of this appendix, times the same factor (between 1.00 and 1.25) that was used to calculate the calibration span value. Round off the flow rate span value to the nearest 1000 scfh. Select the full-scale range of the flow monitor so that it is greater than or equal to the span value and is consistent with section 2.1 of this appendix. Include in the monitoring plan for the unit: calculations of the MPV, MPF, calibration span value, flow rate span value, and full-scale range (expressed both in scfh and, if different, in the measurement units of calibration). 2.1.4.3 Adjustment of Span and Range For each affected unit or common stack, the owner or operator shall make a periodic evaluation of the MPV, MPF, span, and range values for each flow rate monitor (at a minimum, an annual evaluation is required) and shall make any necessary span and range adjustments with corresponding monitoring plan updates, as described in paragraphs (a) through (c) of this section 2.1.4.3. Span and range adjustments may be required, for example, as a result of changes in the fuel supply, changes in the stack or ductwork configuration, changes in the manner of operation of the unit, or installation or removal of emission controls. In implementing the provisions in paragraphs (a) and (b) of this section 2.1.4.3, note that flow rate data recorded during short-term, non-representative operating conditions (e.g., a trial burn of a different type of fuel) shall be excluded from consideration. The owner or operator shall keep the results of the most recent span and range evaluation on-site, in a format suitable for inspection. Make each required span or range adjustment no later than 45 days after the end of the quarter in which the need to adjust the span or range is identified. (a) If the fuel supply, stack or ductwork configuration, operating parameters, or other conditions change such that the maximum potential flow rate changes significantly, adjust the span and range to assure the continued accuracy of the flow monitor. A “significant” change in the MPV or MPF means that the guidelines of section 2.1 of this appendix can no longer be met, as determined by either a periodic evaluation by the owner or operator or from the results of an audit by the Administrator. The owner or operator should evaluate whether any planned changes in operation of the unit may affect the flow of the unit or stack and should plan any necessary span and range changes needed to account for these changes, so that they are made in as timely a manner as practicable to coordinate with the operational changes. Calculate the adjusted calibration span and flow rate span values using the procedures in section 2.1.4.2 of this appendix. (b) Whenever the full-scale range is exceeded during a quarter, provided that the exceedance is not caused by a monitor out-of-control period, report 200.0 percent of the current full-scale range as the hourly flow rate for each hour of the full-scale exceedance. If the range is exceeded, make appropriate adjustments to the MPF, flow rate span, and range to prevent future full-scale exceedances. Calculate the new calibration span value by converting the new flow rate span value from units of scfh to units of daily calibration. A calibration error test must be performed and passed to validate data on the new range. (c) Whenever changes are made to the MPV, MPF, full-scale range, or span value of the flow monitor, as described in paragraphs (a) and (b) of this section, record and report (as applicable) the new full-scale range setting, calculations of the flow rate span value, calibration span value, MPV, and MPF in an updated monitoring plan for the unit. The monitoring plan update shall be made in the quarter in which the changes become effective. Record and report the adjusted calibration span and reference values as parts of the records for the calibration error test required by appendix B to this part. Whenever the calibration span value is adjusted, use reference values for the calibration error test that meet the requirements of section 2.2.2.1 of this appendix, based on the most recent adjusted calibration span value. Perform a calibration error test according to section 2.1.1 of appendix B to this part whenever making a change to the flow monitor span or range, unless the range change also triggers a recertification under § 75.20(b). 2.1.5 Minimum Potential Moisture Percentage Except as provided in section 2.1.6 of this appendix, the owner or operator of a unit that uses a continuous moisture monitoring system to correct emission rates and heat inputs from a dry basis to a wet basis (or vice-versa) shall, for the purpose of providing substitute data under § 75.37, use a default value of 3.0 percent H 2 2 2.1.6 Maximum Potential Moisture Percentage When Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is used to determine NO X 2 2 2.2 Design for Quality Control Testing 2.2.1 Pollutant Concentration and CO 2 2 (a) Design and equip each pollutant concentration and CO 2 2 (b) Design and equip each pollutant concentration or CO 2 2 2.2.2 Flow Monitors Design all flow monitors to meet the applicable performance specifications. 2.2.2.1 Calibration Error Test Design and equip each flow monitor to allow for a daily calibration error test consisting of at least two reference values: Zero to 20 percent of span or an equivalent reference value ( e.g., 2.2.2.2 Interference Check (a) Design and equip each flow monitor with a means to ensure that the moisture expected to occur at the monitoring location does not interfere with the proper functioning of the flow monitoring system. Design and equip each flow monitor with a means to detect, on at least a daily basis, pluggage of each sample line and sensing port, and malfunction of each resistance temperature detector (RTD), transceiver or equivalent. (b) Design and equip each differential pressure flow monitor to provide an automatic, periodic back purging (simultaneously on both sides of the probe) or equivalent method of sufficient force and frequency to keep the probe and lines sufficiently free of obstructions on at least a daily basis to prevent velocity sensing interference, and a means for detecting leaks in the system on at least a quarterly basis (manual check is acceptable). (c) Design and equip each thermal flow monitor with a means to ensure on at least a daily basis that the probe remains sufficiently clean to prevent velocity sensing interference. (d) Design and equip each ultrasonic flow monitor with a means to ensure on at least a daily basis that the transceivers remain sufficiently clean ( e.g., 3. Performance Specifications 3.1 Calibration Error (a) The calibration error performance specifications in this section apply only to 7-day calibration error tests under sections 6.3.1 and 6.3.2 of this appendix and to the offline calibration demonstration described in section 2.1.1.2 of appendix B to this part. The calibration error limits for daily operation of the continuous monitoring systems required under this part are found in section 2.1.4(a) of appendix B to this part. (b) The calibration error of SO 2 X 2 2 2 2 2 2 3.2 Linearity Check For SO 2 X 2 2 2 2 (1) The error in linearity for each calibration gas concentration (low-, mid-, and high-levels) shall not exceed or deviate from the reference value by more than 5.0 percent as calculated using equation A-4 of this appendix; or (2) The absolute value of the difference between the average of the monitor response values and the average of the reference values, | R-A| in equation A-4 of this appendix, shall be less than or equal to 0.5 percent CO 2 2 3.3 Relative Accuracy 3.3.1 Relative Accuracy for SO 2 (a) The relative accuracy for SO 2 (b) For affected units where the average of the reference method measurements of SO 2 3.3.2 Relative Accuracy for NO X (a) The relative accuracy for NO X (b) For affected units where the average of the reference method measurements of NO X 3.3.3 Relative Accuracy for CO 2 2 The relative accuracy for CO 2 2 2 2 2 2 3.3.4 Relative Accuracy for Flow Monitors (a) The relative accuracy of flow monitors shall not exceed 10.0 percent at any load (or operating) level at which a RATA is performed (i.e., the low, mid, or high level, as defined in section 6.5.2.1 of this appendix). (b) For affected units where the average of the flow reference method measurements of gas velocity at a particular load (or operating) level of the relative accuracy test audit is less than or equal to 10.0 fps, the difference between the mean value of the flow monitor velocity measurements and the reference method mean value in fps at that level shall not exceed ±2.0 fps, wherever the 10.0 percent relative accuracy specification is not achieved. 3.3.5 Combined SO 2 3.3.6 Relative Accuracy for Moisture Monitoring Systems The relative accuracy of a moisture monitoring system shall not exceed 10.0 percent. The relative accuracy test results are also acceptable if the difference between the mean value of the reference method measurements (in percent H 2 2 2 3.3.7 Relative Accuracy for NO X (a) The following requirement applies only to NO X X X X X (b) The relative accuracy for NO X X 3.4 Bias 3.4.1 SO 2 X X SO 2 X X X 2 X 2 X X X 3.4.2 Flow Monitors Flow monitors shall not be biased low as determined by the test procedure in section 7.6 of this appendix. The bias specification applies to all flow monitors including those measuring an average gas velocity of 10.0 fps or less. 3.5 Cycle Time The cycle time for pollutant concentration monitors, oxygen monitors used to determine percent moisture, and any other monitoring component of a continuous emission monitoring system that is required to perform a cycle time test shall not exceed 15 minutes. 4. Data Acquisition and Handling Systems (a) Automated data acquisition and handling systems shall read and record the entire range of pollutant concentrations and volumetric flow from zero through full-scale and provide a continuous, permanent record of all measurements and required information in an electronic format. These systems also shall have the capability of interpreting and converting the individual output signals from an SO 2 2 2 X X e.g., (b) Data acquisition and handling systems shall also compute and record: Monitor calibration error; any bias adjustments to SO 2 X X (c) For an excepted monitoring system under appendix D or E of this part, data acquisition and handling systems shall: (1) Read and record the full range of fuel flowrate through the upper range value; (2) Calculate and record intermediate values necessary to obtain emissions, such as mass fuel flowrate and heat input rate; (3) Calculate and record emissions in the appropriate units (e.g., lb/hr of SO 2 X (4) Predict and record NO X X (5) Calculate and record all missing data substitution values specified in appendix D or E of this part; and (6) Provide a continuous, permanent record of all measurements and required information in an electronic format. 5. Calibration Gas 5.1 Reference Gases For the purposes of part 75, calibration gases include the following: 5.1.1 Standard Reference Materials (SRM) These calibration gases may be obtained from the National Institute of Standards and Technology (NIST) at the following address: Quince Orchard and Cloppers Road, Gaithersburg, MD 20899-0001. 5.1.2 SRM-Equivalent Compressed Gas Primary Reference Material (PRM) Contact the Gas Metrology Team, Analytical Chemistry Division, Chemical Science and Technology Laboratory of NIST, at the address in section 5.1.1, for a list of vendors and cylinder gases. 5.1.3 NIST Traceable Reference Materials Contact the Gas Metrology Team, Analytical Chemistry Division, Chemical Science and Technology Laboratory of NIST, at the address in section 5.1.1, for a list of vendors and cylinder gases that meet the definition for a NIST Traceable Reference Material (NTRM) provided in § 72.2. 5.1.4 EPA Protocol Gases (a) An EPA Protocol gas is a calibration gas mixture prepared and analyzed according to Section 2 of the “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, as amended on August 25, 1999, EPA-600/R-97/121 (incorporated by reference, see (b) EPA Protocol gas concentrations must be certified by an EPA Protocol gas production site to have an analytical uncertainty (95-percent confidence interval) to be not more than plus or minus 2.0 percent (inclusive) of the certified concentration (tag value) of the gas mixture. The uncertainty must be calculated using the statistical procedures (or equivalent statistical techniques) that are listed in Section 2.1.8 of the “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, as amended on August 25, 1999, EPA-600/R-97/121 (incorporated by reference, see 5.1.5 Research Gas Mixtures Concentrations of research gas mixtures, as defined in § 72.2 of this chapter, must be certified by the National Institute of Standards and Technology to have an analytical uncertainty (95-percent confidence interval) calculated using the statistical procedures (or equivalent statistical techniques) that are listed in Section 2.1.8 of the “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, as amended on August 25, 1999, EPA-600/R-97/121 (incorporated by reference, see i.e., 5.1.6 Zero Air Material Zero air material is defined in § 72.2 of this chapter. 5.1.7 NIST/EPA-Approved Certified Reference Materials Existing certified reference materials (CRMs) that are still within their certification period may be used as calibration gas. 5.1.8 Gas Manufacturer's Intermediate Standards Gas manufacturer's intermediate standards is defined in § 72.2 of this chapter. 5.2 Concentrations Four concentration levels are required as follows. 5.2.1 Zero-level Concentration 0.0 to 20.0 percent of span, including span for high-scale or both low- and high-scale for SO 2 X 2 2 5.2.2 Low-level Concentration 20.0 to 30.0 percent of span, including span for high-scale or both low- and high-scale for SO 2 X 2 2 5.2.3 Mid-level Concentration 50.0 to 60.0 percent of span, including span for high-scale or both low- and high-scale for SO 2 X 2 2 5.2.4 High-level Concentration 80.0 to 100.0 percent of span, including span for high-scale or both low-and high-scale for SO 2 X 2 2 6. Certification Tests and Procedures 6.1 General Requirements 6.1.1 Pretest Preparation Install the components of the continuous emission monitoring system (i.e., pollutant concentration monitors, CO 2 2 6.1.2 Requirements for Air Emission Testing (a) On and after March 27, 2012, all relative accuracy test audits (RATAs) of CEMS under this part, and stack testing under § 75.19 and Appendix E to this part shall be conducted by an Air Emission Testing Body (AETB) which has provided to the owner or operator of a unit subject to this part the documentation required in paragraph (b) of this section, demonstrating its conformance to ASTM D7036-04 (incorporated by reference, see (b) The owner or operator shall obtain from the AETB a certification that as of the time of testing the AETB is operating in conformance with ASTM D7036-04 (incorporated by reference, see (1) A certificate of accreditation or interim accreditation for the relevant test methods issued by a recognized, national accreditation body; or (2) A letter of certification for the relevant test methods signed by a member of the senior management staff of the AETB. (c) The owner or operator shall obtain from the AETB the information required under §§ 75.59(a)(15), (b)(6), and (d)(4), as applicable. (d) While under no obligation to request the following information from an AETB, to review the information provided by the AETB in response to such a request, or to take any other action related to the response, the owner or operator may find it useful to request that AETBs complying with paragraph (b)(2) of this section provide a copy of the following: (1) The AETB's quality manual. For the purpose of application of 40 CFR part 2, subpart B, AETB's concerned about the potential for public access to confidential business information (CBI) may identify any information subject to such a claim in the copy provided; (2) The results of any internal audits performed by the AETB and any external audits of the AETB during the 12 month period through the previous calendar quarter; (3) Performance data (as defined in ASTM D7036-04 (incorporated by reference, see (4) Training records for all on-site technical personnel, including any Qualified Individuals, for the 12 month period through the previous calendar quarter. (e) All relative accuracy testing performed pursuant to § 75.74(c)(2)(ii), section 6.5 of appendix A to this part or section 2.3.1 of appendix B to this part, and stack testing under § 75.19 and Appendix E to this part shall be overseen and supervised on site by at least one Qualified Individual, as defined in § 72.2 of this chapter with respect to the methods employed in the test project. If the source owner or operator, or a State, local, or EPA observer, discovers while the test team is still on site, that at least one QI did not oversee and supervise the entire test (as qualified by this paragraph (e)), only those portions of the test that were overseen and supervised by at least one QI as described above may be used under this part. However, allowance is made for normal activities of a QI who is overseeing and supervising a test, e.g., (f) Except as provided in paragraph (e), no RATA performed pursuant to § 75.74(c)(2)(ii), section 6.5 of appendix A to this part or section 2.3.1 of appendix B to this part, and no stack test under § 75.19 or Appendix E to this part (or portion of such a RATA or stack test) conducted by an AETB (as defined in § 72.2) shall be invalidated under this part as a result of the failure of the AETB to conform to ASTM D7036-04 (incorporated by reference, see (g) An owner or operator who has requested information from an AETB under paragraph (d) of this part who believes that the information provided by the AETB was either incomplete or inaccurate may request the Administrator's assistance in remedying the alleged deficiencies. Upon such a request, if the Administrator concurs that the information submitted to a source subject to part 75 by an AETB under this section is either incomplete or inaccurate, the Administrator will provide the AETB a description of the deficiencies to be remedied. The Administrator's determination of completeness and accuracy of information will be solely based on the provisions of ASTM D7036-04 (incorporated by reference, see http://www.epa.gov/airmarkets/emissions/aetb.html [email protected] 6.2 Linearity Check (General Procedures) Check the linearity of each SO 2 X 2 2 2 X 2 X X X X X (a) For the initial certification of a CEMS, data from the monitoring system are considered invalid until all certification tests, including the linearity test, have been successfully completed, unless the conditional data validation procedures in § 75.20(b)(3) are used. When the procedures in § 75.20(b)(3) are followed, the words “initial certification” apply instead of “recertification,” and complete all of the initial certification tests by the applicable deadline in § 75.4, rather than within the time periods specified in § 75.20(b)(3)(iv) for the individual tests. (b) For the routine quality assurance linearity checks required by section 2.2.1 of appendix B to this part, use the data validation procedures in section 2.2.3 of appendix B to this part. (c) When a linearity test is required as a diagnostic test or for recertification, use the data validation procedures in § 75.20(b)(3). (d) For linearity tests of non-redundant backup monitoring systems, use the data validation procedures in § 75.20(d)(2)(iii). (e) For linearity tests performed during a grace period and after the expiration of a grace period, use the data validation procedures in sections 2.2.3 and 2.2.4, respectively, of appendix B to this part. (f) For all other linearity checks, use the data validation procedures in section 2.2.3 of appendix B to this part. 6.3 7-Day Calibration Error Test 6.3.1 Gas Monitor 7-Day Calibration Error Test The following monitors and ranges are exempted from the 7-day calibration error test requirements of this part: the SO 2 X 2 2 2 X 2 X 2 2 i.e., 2 X 2 2 (a) For initial certification, data from the monitor are considered invalid until all certification tests, including the 7-day calibration error test, have been successfully completed, unless the conditional data validation procedures in § 75.20(b)(3) are used. When the procedures in § 75.20(b)(3) are followed, the words “initial certification” apply instead of “recertification,” and complete all of the initial certification tests by the applicable deadline in § 75.4, rather than within the time periods specified in § 75.20(b)(3)(iv) for the individual tests. (b) When a 7-day calibration error test is required as a diagnostic test or for recertification, use the data validation procedures in § 75.20(b)(3). 6.3.2 Flow Monitor 7-day Calibration Error Test Flow monitors installed on peaking units (as defined in § 72.2 of this chapter) are exempted from the 7-day calibration error test requirements of this part. In all other cases, perform the 7-day calibration error test of a flow monitor, when required for certification, recertification or diagnostic testing, according to the following procedures. Introduce the reference signal corresponding to the values specified in section 2.2.2.1 of this appendix to the probe tip (or equivalent), or to the transducer. During the 7-day certification test period, conduct the calibration error test while the unit is operating once each unit operating day (as close to 24-hour intervals as practicable). In the event that unit outages occur after the commencement of the test, the 7 consecutive operating days need not be 7 consecutive calendar days. Record the flow monitor responses by means of the data acquisition and handling system. Calculate the calibration error using Equation A-6 of this appendix. Do not perform any corrective maintenance, repair, or replacement upon the flow monitor during the 7-day test period other than that required in the quality assurance/quality control plan required by appendix B to this part. Do not make adjustments between the zero and high reference level measurements on any day during the 7-day test. If the flow monitor operates within the calibration error performance specification (i.e., less than or equal to 3.0 percent error each day and requiring no corrective maintenance, repair, or replacement during the 7-day test period), the flow monitor passes the calibration error test. Record all maintenance activities and the magnitude of any adjustments. Record output readings from the data acquisition and handling system before and after all adjustments. Record and report all calibration error test results using the unadjusted flow rate measured in the calibration error test prior to resetting the calibration. Record all adjustments made during the 7-day period at the time the adjustment is made, and report them in the certification or recertification application. The status of emissions data from a flow monitor prior to and during a 7-day calibration error test period shall be determined as follows: (a) For initial certification, data from the monitor are considered invalid until all certification tests, including the 7-day calibration error test, have been successfully completed, unless the conditional data validation procedures in § 75.20(b)(3) are used. When the procedures in § 75.20(b)(3) are followed, the words “initial certification” apply instead of “recertification,” and complete all of the initial certification tests by the applicable deadline in § 75.4, rather than within the time periods specified in § 75.20(b)(3)(iv) for the individual tests. (b) When a 7-day calibration error test is required as a diagnostic test or for recertification, use the data validation procedures in § 75.20(b)(3). 6.3.3 For gas or flow monitors installed on peaking units, the exemption from performing the 7-day calibration error test applies as long as the unit continues to meet the definition of a peaking unit in § 72.2 of this chapter. However, if at the end of a particular calendar year or ozone season, it is determined that peaking unit status has been lost, the owner or operator shall perform a diagnostic 7-day calibration error test of each monitor installed on the unit, by no later than December 31 of the following calendar year. 6.4 Cycle Time Test Perform cycle time tests for each pollutant concentration monitor and continuous emission monitoring system while the unit is operating, according to the following procedures. Use a zero-level and a high-level calibration gas (as defined in section 5.2 of this appendix) alternately. To determine the downscale cycle time, measure the concentration of the flue gas emissions until the response stabilizes. Record the stable emissions value. Inject a zero-level concentration calibration gas into the probe tip (or injection port leading to the calibration cell, for in situ systems with no probe). Record the time of the zero gas injection, using the data acquisition and handling system (DAHS). Next, allow the monitor to measure the concentration of the zero gas until the response stabilizes. Record the stable ending calibration gas reading. Determine the downscale cycle time as the time it takes for 95.0 percent of the step change to be achieved between the stable stack emissions value and the stable ending zero gas reading. Then repeat the procedure, starting with stable stack emissions and injecting the high-level gas, to determine the upscale cycle time, which is the time it takes for 95.0 percent of the step change to be achieved between the stable stack emissions value and the stable ending high-level gas reading. Use the following criteria to assess when a stable reading of stack emissions or calibration gas concentration has been attained. A stable value is equivalent to a reading with a change of less than 2.0 percent of the span value for 2 minutes, or a reading with a change of less than 6.0 percent from the measured average concentration over 6 minutes. Alternatively, the reading is considered stable if it changes by no more than 0.5 ppm or 0.2% CO 2 2 X (a) For initial certification, data from the monitor are considered invalid until all certification tests, including the cycle time test, have been successfully completed, unless the conditional data validation procedures in § 75.20(b)(3) are used. When the procedures in § 75.20(b)(3) are followed, the words “initial certification” apply instead of “recertification,” and complete all of the initial certification tests by the applicable deadline in § 75.4, rather than within the time periods specified in § 75.20(b)(3)(iv) for the individual tests. (b) When a cycle time test is required as a diagnostic test or for recertification, use the data validation procedures in § 75.20(b)(3). 6.5 Relative Accuracy and Bias Tests (General Procedures) Perform the required relative accuracy test audits (RATAs) as follows for each CO 2 2 2 2 X X X 2 2 X X 2 X (a) Except as otherwise provided in this paragraph or in § 75.21(a)(5), perform each RATA while the unit (or units, if more than one unit exhausts into the flue) is combusting the fuel that is a normal primary or backup fuel for that unit (for some units, more than one type of fuel may be considered normal, e.g. (b) Perform each RATA at the load (or operating) level(s) specified in section 6.5.1 or 6.5.2 of this appendix or in section 2.3.1.3 of appendix B to this part, as applicable. (c) For monitoring systems with dual ranges, perform the relative accuracy test on the range normally used for measuring emissions. For units with add-on SO 2 X e.g., (d) Record monitor or monitoring system output from the data acquisition and handling system. (e) Complete each single-load relative accuracy test audit within a period of 168 consecutive unit operating hours, as defined in § 72.2 of this chapter (or, for CEMS installed on common stacks or bypass stacks, 168 consecutive stack operating hours, as defined in § 72.2 of this chapter). For 2-level and 3-level flow monitor RATAs, complete all of the RATAs at all levels, to the extent practicable, within a period of 168 consecutive unit (or stack) operating hours; however, if this is not possible, up to 720 consecutive unit (or stack) operating hours may be taken to complete a multiple-load flow RATA. (f) The status of emission data from the CEMS prior to and during the RATA test period shall be determined as follows: (1) For the initial certification of a CEMS, data from the monitoring system are considered invalid until all certification tests, including the RATA, have been successfully completed, unless the conditional data validation procedures in § 75.20(b)(3) are used. When the procedures in § 75.20(b)(3) are followed, the words “initial certification” apply instead of “recertification,” and complete all of the initial certification tests by the applicable deadline in § 75.4, rather than within the time periods specified in § 75.20(b)(3)(iv) for the individual tests. (2) For the routine quality assurance RATAs required by section 2.3.1 of appendix B to this part, use the data validation procedures in section 2.3.2 of appendix B to this part. (3) For recertification RATAs, use the data validation procedures in § 75.20(b)(3). (4) For quality assurance RATAs of non-redundant backup monitoring systems, use the data validation procedures in §§ 75.20(d)(2)(v) and (vi). (5) For RATAs performed during and after the expiration of a grace period, use the data validation procedures in sections 2.3.2 and 2.3.3, respectively, of appendix B to this part. (6) For all other RATAs, use the data validation procedures in section 2.3.2 of appendix B to this part. (g) For each SO 2 2 2 2 X X X 2 2 6.5.1 Gas Monitoring System RATAs (Special Considerations) (a) Perform the required relative accuracy test audits for each SO 2 2 2 2 X X X (b) For the initial certification of a gas monitoring system and for recertifications in which, in addition to a RATA, one or more other tests are required ( i.e., 6.5.2 Flow Monitor RATAs (Special Considerations) (a) Except as otherwise provided in paragraph (b) or (e) of this section, perform relative accuracy test audits for the initial certification of each flow monitor at three different exhaust gas velocities (low, mid, and high), corresponding to three different load levels or operating levels within the range of operation, as defined in section 6.5.2.1 of this appendix. For a common stack/duct, the three different exhaust gas velocities may be obtained from frequently used unit/load or operating level combinations for the units exhausting to the common stack. Select the three exhaust gas velocities such that the audit points at adjacent load or operating levels (i.e., low and mid or mid and high), in megawatts (or in thousands of lb/hr of steam production or in ft/sec, as applicable), are separated by no less than 25.0 percent of the range of operation, as defined in section 6.5.2.1 of this appendix. (b) For flow monitors on bypass stacks/ducts and peaking units, the flow monitor relative accuracy test audits for initial certification and recertification shall be single-load tests, performed at the normal load, as defined in section 6.5.2.1(d) of this appendix. (c) Flow monitor recertification RATAs shall be done at three load level(s) (or three operating levels), unless otherwise specified in paragraph (b) or (e) of this section or unless otherwise specified or approved by the Administrator. (d) The semiannual and annual quality assurance flow monitor RATAs required under appendix B to this part shall be done at the load level(s) (or operating levels) specified in section 2.3.1.3 of appendix B to this part. (e) For flow monitors installed on units that do not produce electrical or thermal output, the flow RATAs for initial certification or recertification may be done at fewer than three operating levels, if: (1) The owner or operator provides a technical justification in the hardcopy portion of the monitoring plan for the unit required under § 75.53(e)(2), demonstrating that the unit operates at only one level or two levels during normal operation (excluding unit startup and shutdown). Appropriate documentation and data must be provided to support the claim of single-level or two-level operation; and (2) The justification provided in paragraph (e)(1) of this section is deemed to be acceptable by the permitting authority. 6.5.2.1 Range of Operation and Normal Load (or Operating) Level(s) (a) The owner or operator shall determine the upper and lower boundaries of the “range of operation” as follows for each unit (or combination of units, for common stack configurations): (1) For affected units that produce electrical output (in megawatts) or thermal output (in klb/hr of steam production or mmBtu/hr), the lower boundary of the range of operation of a unit shall be the minimum safe, stable loads for any of the units discharging through the stack. Alternatively, for a group of frequently-operated units that serve a common stack, the sum of the minimum safe, stable loads for the individual units may be used as the lower boundary of the range of operation. The upper boundary of the range of operation of a unit shall be the maximum sustainable load. The “maximum sustainable load” is the higher of either: the nameplate or rated capacity of the unit, less any physical or regulatory limitations or other deratings; or the highest sustainable load, based on at least four quarters of representative historical operating data. For common stacks, the maximum sustainable load is the sum of all of the maximum sustainable loads of the individual units discharging through the stack, unless this load is unattainable in practice, in which case use the highest sustainable combined load for the units that discharge through the stack. Based on at least four quarters of representative historical operating data. The load values for the unit(s) shall be expressed either in units of megawatts of thousands of lb/hr of steam load or mmBtu/hr of thermal output; or (2) For affected units that do not produce electrical or thermal output, the lower boundary of the range of operation shall be the minimum expected flue gas velocity (in ft/sec) during normal, stable operation of the unit. The upper boundary of the range of operation shall be the maximum potential flue gas velocity (in ft/sec) as defined in section 2.1.4.1 of this appendix. The minimum expected and maximum potential velocities may be derived from the results of reference method testing or by using Equation A-3a or A-3b (as applicable) in section 2.1.4.1 of this appendix. If Equation A-3a or A-3b is used to determine the minimum expected velocity, replace the word “maximum” with the word “minimum” in the definitions of “MPV,” “H f 2d 2 2d (b) The operating levels for relative accuracy test audits shall, except for peaking units, be defined as follows: the “low” operating level shall be the first 30.0 percent of the range of operation; the “mid” operating level shall be the middle portion (>30.0 percent, but ≤60.0 percent) of the range of operation; and the “high” operating level shall be the upper end (>60.0 percent) of the range of operation. For example, if the upper and lower boundaries of the range of operation are 100 and 1100 megawatts, respectively, then the low, mid, and high operating levels would be 100 to 400 megawatts, 400 to 700 megawatts, and 700 to 1100 megawatts, respectively. (c) Units that do not produce electrical or thermal output are exempted from the requirements of this paragraph, (c). The owner or operator shall identify, for each affected unit or common stack (except for peaking units and units using the low mass emissions (LME) excepted methodology under § 75.19), the “normal” load level or levels (low, mid or high), based on the operating history of the unit(s). To identify the normal load level(s), the owner or operator shall, at a minimum, determine the relative number of operating hours at each of the three load levels, low, mid and high over the past four representative operating quarters. The owner or operator shall determine, to the nearest 0.1 percent, the percentage of the time that each load level (low, mid, high) has been used during that time period. A summary of the data used for this determination and the calculated results shall be kept on-site in a format suitable for inspection. For new units or newly-affected units, the data analysis in this paragraph may be based on fewer than four quarters of data if fewer than four representative quarters of historical load data are available. Or, if no historical load data are available, the owner or operator may designate the normal load based on the expected or projected manner of operating the unit. However, in either case, once four quarters of representative data become available, the historical load analysis shall be repeated. (d) Determination of normal load (or operating level) (1) Based on the analysis of the historical load data described in paragraph (c) of this section, the owner or operator shall, for units that produce electrical or thermal output, designate the most frequently used load level as the normal load level for the unit (or combination of units, for common stacks). The owner or operator may also designate the second most frequently used load level as an additional normal load level for the unit or stack. For peaking units and LME units, normal load designations are unnecessary; the entire operating load range shall be considered normal. If the manner of operation of the unit changes significantly, such that the designated normal load(s) or the two most frequently used load levels change, the owner or operator shall repeat the historical load analysis and shall redesignate the normal load(s) and the two most frequently used load levels, as appropriate. A minimum of two representative quarters of historical load data are required to document that a change in the manner of unit operation has occurred. Update the electronic monitoring plan whenever the normal load level(s) and the two most frequently-used load levels are redesignated. (2) For units that do not produce electrical or thermal output, the normal operating level(s) shall be determined using sound engineering judgment, based on knowledge of the unit and operating experience with the industrial process. (e) The owner or operator shall report the upper and lower boundaries of the range of operation for each unit (or combination of units, for common stacks), in units of megawatts or thousands of lb/hr or mmBtu/hr of steam production or ft/sec (as applicable), in the electronic monitoring plan required under § 75.53. Except for peaking units and LME units, the owner or operator shall indicate, in the electronic monitoring plan, the load level (or levels) designated as normal under this section and shall also indicate the two most frequently used load levels. 6.5.2.2 Multi-Load (or Multi-Level) Flow RATA Results For each multi-load (or multi-level) flow RATA, calculate the flow monitor relative accuracy at each operating level. If a flow monitor relative accuracy test is failed or aborted due to a problem with the monitor on any level of a 2-level (or 3-level) relative accuracy test audit, the RATA must be repeated at that load (or operating) level. However, the entire 2-level (or 3-level) relative accuracy test audit does not have to be repeated unless the flow monitor polynomial coefficients or K-factor(s) are changed, in which case a 3-level RATA is required (or, a 2-level RATA, for units demonstrated to operate at only two levels, under section 6.5.2(e) of this appendix). 6.5.3 [Reserved] 6.5.4 Calculations Using the data from the relative accuracy test audits, calculate relative accuracy and bias in accordance with the procedures and equations specified in section 7 of this appendix. 6.5.5 Reference Method Measurement Location Select a location for reference method measurements that is (1) accessible; (2) in the same proximity as the monitor or monitoring system location; and (3) meets the requirements of Performance Specification 2 in appendix B of part 60 of this chapter for SO 2 X 2 2 6.5.6 Reference Method Traverse Point Selection Select traverse points that ensure acquisition of representative samples of pollutant and diluent concentrations, moisture content, temperature, and flue gas flow rate over the flue cross section. To achieve this, the reference method traverse points shall meet the requirements of section 8.1.3 of Performance Specification 2 (“PS No. 2”) in appendix B to part 60 of this chapter (for SO 2 X 2 2 (a) For moisture determinations where the moisture data are used only to determine stack gas molecular weight, a single reference method point, located at least 1.0 meter from the stack wall, may be used. For moisture monitoring system RATAs and for gas monitor RATAs in which moisture data are used to correct pollutant or diluent concentrations from a dry basis to a wet basis (or vice-versa), single-point moisture sampling may only be used if the 12-point stratification test described in section 6.5.6.1 of this appendix is performed prior to the RATA for at least one pollutant or diluent gas, and if the test is passed according to the acceptance criteria in section 6.5.6.3(b) of this appendix. (b) For gas monitoring system RATAs, the owner or operator may use any of the following options: (1) At any location (including locations where stratification is expected), use a minimum of six traverse points along a diameter, in the direction of any expected stratification. The points shall be located in accordance with Method 1 in appendix A to part 60 of this chapter. (2) At locations where section 8.1.3 of PS No. 2 allows the use of a short reference method measurement line (with three points located at 0.4, 1.2, and 2.0 meters from the stack wall), the owner or operator may use an alternative 3-point measurement line, locating the three points at 4.4, 14.6, and 29.6 percent of the way across the stack, in accordance with Method 1 in appendix A to part 60 of this chapter. (3) At locations where stratification is likely to occur (e.g., following a wet scrubber or when dissimilar gas streams are combined), the short measurement line from section 8.1.3 of PS No. 2 (or the alternative line described in paragraph (b)(2) of this section) may be used in lieu of the prescribed “long” measurement line in section 8.1.3 of PS No. 2, provided that the 12-point stratification test described in section 6.5.6.1 of this appendix is performed and passed one time at the location (according to the acceptance criteria of section 6.5.6.3(a) of this appendix) and provided that either the 12-point stratification test or the alternative (abbreviated) stratification test in section 6.5.6.2 of this appendix is performed and passed prior to each subsequent RATA at the location (according to the acceptance criteria of section 6.5.6.3(a) of this appendix). (4) A single reference method measurement point, located no less than 1.0 meter from the stack wall and situated along one of the measurement lines used for the stratification test, may be used at any sampling location if the 12-point stratification test described in section 6.5.6.1 of this appendix is performed and passed prior to each RATA at the location (according to the acceptance criteria of section 6.5.6.3(b) of this appendix). (5) If Method 7E is used as the reference method for the RATA of a NO X 6.5.6.1 Stratification Test (a) With the unit(s) operating under steady-state conditions at the normal load level (or normal operating level), as defined in section 6.5.2.1 of this appendix, use a traversing gas sampling probe to measure the pollutant (SO 2 X 2 2 (b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this chapter to make the measurements. Data from the reference method analyzers must be quality-assured by performing analyzer calibration error and system bias checks before the series of measurements and by conducting system bias and calibration drift checks after the measurements, in accordance with the procedures of Methods 6C, 7E, and 3A. (c) Measure for a minimum of 2 minutes at each traverse point. To the extent practicable, complete the traverse within a 2-hour period. (d) If the load has remained constant (±3.0 percent) during the traverse and if the reference method analyzers have passed all of the required quality assurance checks, proceed with the data analysis. (e) Calculate the average NO X 2 2 2 X 2 2 2 6.5.6.2 Alternative (Abbreviated) Stratification Test (a) With the unit(s) operating under steady-state conditions at normal load level (or normal operating level), as defined in section 6.5.2.1 of this appendix, use a traversing gas sampling probe to measure the pollutant (SO 2 X 2 2 (b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this chapter to make the measurements. Data from the reference method analyzers must be quality-assured by performing analyzer calibration error and system bias checks before the series of measurements and by conducting system bias and calibration drift checks after the measurements, in accordance with the procedures of Methods 6C, 7E, and 3A. (c) Measure for a minimum of 2 minutes at each traverse point. To the extent practicable, complete the traverse within a 1-hour period. (d) If the load has remained constant (±3.0 percent) during the traverse and if the reference method analyzers have passed all of the required quality assurance checks, proceed with the data analysis. (e) Calculate the average NO X 2 2 2 X 2 2 2 6.5.6.3 Stratification Test Results and Acceptance Criteria (a) For each pollutant or diluent gas, the short reference method measurement line described in section 8.1.3 of PS No. 2 may be used in lieu of the long measurement line prescribed in section 8.1.3 of PS No. 2 if the results of a stratification test, conducted in accordance with section 6.5.6.1 or 6.5.6.2 of this appendix (as appropriate; see section 6.5.6(b)(3) of this appendix), show that the concentration at each individual traverse point differs by no more than ±10.0 percent from the arithmetic average concentration for all traverse points. The results are also acceptable if the concentration at each individual traverse point differs by no more than ±5ppm or ±0.5 percent CO 2 2 (b) For each pollutant or diluent gas, a single reference method measurement point, located at least 1.0 meter from the stack wall and situated along one of the measurement lines used for the stratification test, may be used for that pollutant or diluent gas if the results of a stratification test, conducted in accordance with section 6.5.6.1 of this appendix, show that the concentration at each individual traverse point differs by no more than ±5.0 percent from the arithmetic average concentration for all traverse points. The results are also acceptable if the concentration at each individual traverse point differs by no more than ±3 ppm or ±0.3 percent CO 2 2 (c) The owner or operator shall keep the results of all stratification tests on-site, in a format suitable for inspection, as part of the supplementary RATA records required under § 75.59(a)(7). 6.5.7 Sampling Strategy (a) Conduct the reference method tests allowed in section 6.5.10 of this appendix so they will yield results representative of the pollutant concentration, emission rate, moisture, temperature, and flue gas flow rate from the unit and can be correlated with the pollutant concentration monitor, CO 2 2 2 X X e.g., i.e., 2 2 2 i.e., 2 2 (b) To properly correlate individual SO 2 X 6.5.8 Correlation of Reference Method and Continuous Emission Monitoring System Confirm that the monitor or monitoring system and reference method test results are on consistent moisture, pressure, temperature, and diluent concentration basis (e.g., since the flow monitor measures flow rate on a wet basis, method 2 test results must also be on a wet basis). Compare flow-monitor and reference method results on a scfh basis. Also, consider the response times of the pollutant concentration monitor, the continuous emission monitoring system, and the flow monitoring system to ensure comparison of simultaneous measurements. For each relative accuracy test audit run, compare the measurements obtained from the monitor or continuous emission monitoring system (in ppm, percent CO 2 6.5.9 Number of Reference Method Tests Perform a minimum of nine sets of paired monitor (or monitoring system) and reference method test data for every required (i.e., certification, recertification, diagnostic, semiannual, or annual) relative accuracy test audit. For 2-level and 3-level relative accuracy test audits of flow monitors, perform a minimum of nine sets at each of the operating levels. Note: The tester may choose to perform more than nine sets of reference method tests. If this option is chosen, the tester may reject a maximum of three sets of the test results, as long as the total number of test results used to determine the relative accuracy or bias is greater than or equal to nine. Report all data, including the rejected CEMS data and corresponding reference method test results. 6.5.10 Reference Methods The following methods are from appendix A to part 60 of this chapter, and are the reference methods for performing relative accuracy test audits under this part: Method 1 or 1A in appendix A-1 to part 60 of this chapter for siting; Method 2 in appendix A-1 to part 60 of this chapter or its allowable alternatives in appendices A-1 and A-2 to part 60 of this chapter (except for Methods 2B and 2E in appendix A-1 to part 60 of this chapter) for stack gas velocity and volumetric flow rate; Methods 3, 3A or 3B in appendix A-2 to part 60 of this chapter for O 2 2 2 X X X 2 7. Calculations 7.1 Linearity Check Analyze the linearity data for pollutant concentration and CO 2 2 (Eq. A-4) where, LE = Percentage Linearity error, based upon the reference value. R = Reference value of Low-, mid-, or high-level calibration gas introduced into the monitoring system. A = Average of the monitoring system responses. 7.2 Calibration Error 7.2.1 Pollutant Concentration and Diluent Monitors For each reference value, calculate the percentage calibration error based upon instrument span for daily calibration error tests using the following equation: (Eq. A-5) where, CE = Calibration error as a percentage of the span of the instrument. R = Reference value of zero or upscale (high-level or mid-level, as applicable) calibration gas introduced into the monitoring system. A = Actual monitoring system response to the calibration gas. S = Span of the instrument, as specified in section 2 of this appendix. 7.2.2 Flow Monitor Calibration Error For each reference value, calculate the percentage calibration error based upon span using the following equation: where: CE = Calibration error as a percentage of span. R = Low or high level reference value specified in section 2.2.2.1 of this appendix. A = Actual flow monitor response to the reference value. S = Flow monitor calibration span value as determined under section 2.1.4.2 of this appendix. 7.3 Relative Accuracy for SO 2 2 2 X Analyze the relative accuracy test audit data from the reference method tests for SO 2 2 2 2 X X 7.3.1 Arithmetic Mean Calculate the arithmetic mean of the differences of a data set as follows: 7.3.2 Standard Deviation Calculate the standard deviation, S d (Eq. A-8) 7.3.3 Confidence Coefficient Calculate the confidence coefficient (one-tailed), cc, of a data set as follows. (eq. A-9) where, t 0.025 Table 7-1—t-Values n-1 t 0.025 n-1 t 0.025 n-1 t 0.025 1 12.706 12 2.179 23 2.069 2 4.303 13 2.160 24 2.064 3 3.182 14 2.145 25 2.060 4 2.776 15 2.131 26 2.056 5 2.571 16 2.120 27 2.052 6 2.447 17 2.110 28 2.048 7 2.365 18 2.101 29 2.045 8 2.306 19 2.093 30 2.042 9 2.262 20 2.086 40 2.021 10 2.228 21 2.080 60 2.000 11 2.201 22 2.074 >60 1.960 7.3.4 Relative Accuracy Calculate the relative accuracy of a data set using the following equation. (Eq. A-10) where, RM = Arithmetic mean of the reference method values. |d |cc| = The absolute value of the confidence coefficient. 7.4 Relative Accuracy for NO X Analyze the relative accuracy test audit data from the reference method tests for NO X 7.4.1 Data Preparation If C NOx X −7 NOx −8 2 2 c NOx 7.4.2 NO X For each test run in a data set, calculate the average NO X 7.4.3 Relative Accuracy Use the equations and procedures in section 7.3 above to calculate the relative accuracy for the NO X X X 7.5 Relative Accuracy for Combined SO 2 7.6 Bias Test and Adjustment Factor Test the following relative accuracy test audit data sets for bias: SO 2 X X X 7.6.1 Arithmetic Mean Calculate the arithmetic mean of the differences of the data set using Equation A-7 of this appendix. To calculate bias for an SO 2 X i 2 X i X i X 7.6.2 Standard Deviation Calculate the standard deviation, S d 7.6.3 Confidence Coefficient Calculate the confidence coefficient, cc, of the data set using equation A-9. 7.6.4 Bias Test If, for the relative accuracy test audit data set being tested, the mean difference, d 7.6.5 Bias Adjustment (a) If the monitor or monitoring system fails to meet the bias test requirement, adjust the value obtained from the monitor using the following equation: Where: CEM i Monitor CEM i Adjusted BAF = Bias adjustment factor, defined by: Where: BAF = Bias adjustment factor, calculated to the nearest thousandth. d CEM avg (b) For single-load RATAs of SO 2 X X X 2 X i.e., 2 X X (c) For 2-load or 3-load flow RATAs, when only one load level (low, mid or high) has been designated as normal under section 6.5.2.1 of this appendix and the bias test is passed at the normal load level, apply a BAF of 1.000 to the subsequent flow rate data. If the bias test is failed at the normal load level, use Equation A-12 to calculate the normal load BAF and then perform an additional bias test at the second most frequently-used load level, as determined under section 6.5.2.1 of this appendix. If the bias test is passed at this second load level, apply the normal load BAF to the subsequent flow rate data. If the bias test is failed at this second load level, use Equation A-12 to calculate the BAF at the second load level and apply the higher of the two BAFs (either from the normal load level or from the second load level) to the subsequent flow rate data. (d) For 2-load or 3-load flow RATAs, when two load levels have been designated as normal under section 6.5.2.1 of this appendix and the bias test is passed at both normal load levels, apply a BAF of 1.000 to the subsequent flow rate data. If the bias test is failed at one of the normal load levels but not at the other, use Equation A-12 to calculate the BAF for the normal load level at which the bias test was failed and apply that BAF to the subsequent flow rate data. If the bias test is failed at both designated normal load levels, use Equation A-12 to calculate the BAF at each normal load level and apply the higher of the two BAFs to the subsequent flow rate data. (e) Each time a RATA is passed and the appropriate bias adjustment factor has been determined, apply the BAF prospectively to all monitoring system data, beginning with the first clock hour following the hour in which the RATA was completed. For a 2-load flow RATA, the “hour in which the RATA was completed” refers to the hour in which the testing at both loads was completed; for a 3-load RATA, it refers to the hour in which the testing at all three loads was completed. (f) Use the bias-adjusted values in computing substitution values in the missing data procedure, as specified in subpart D of this part, and in reporting the concentration of SO 2 X 2 2 X X X X X (g) For units that do not produce electrical or thermal output, the provisions of paragraphs (a) through (f) of this section apply, except that the terms, “single-load”, “2-load”, “3-load”, and “load level” shall be replaced, respectively, with the terms, “single-level”, “2-level”, “3-level”, and “operating level”. 7.7 Reference Flow-to-Load Ratio or Gross Heat Rate (a) Except as provided in section 7.8 of this appendix, the owner or operator shall determine R ref ref ref Where: R ref Q ref L avg (b) In Equation A-13, for a common stack, determine L avg ref ref ref ref 2 ref ref (c) In addition to determining R ref ref 2 2 Where: (GHR) ref (Heat Input) avg L avg (d) In the calculation of (Heat Input) avg ref 7.8 Flow-to-Load Test Exemptions (a) For complex stack configuations (e.g., when the effluent from a unit is divided and discharges through multiple stacks in such a manner that the flow rate in the individual stacks cannot be correlated with unit load), the owner or operator may petition the Administrator under § 75.66 for an exemption from the requirements of section 7.7 of this appendix and section 2.2.5 fo appendix B to this part. The petition must include sufficient information and data to demonstrate that a flow-to-load or gross heat rate evaluation is infeasible for the complex stack configuration. (b) Units that do not produce electrical output (in megawatts) or thermal output (in klb of steam per hour) are exempted from the flow-to-load ratio test requirements of section 7.7 of this appendix and section 2.2.5 of appendix B to this part. Figure 1 to Appendix A—Linearity Error Determination Day Date and time Reference value Monitor value Difference Percent of reference value Low-level: Mid-level: High-level: Figure 2 to Appendix A—Relative Accuracy Determination (Pollutant Concentration Monitors) Run No. Date and time SO 2 c Date and time CO 2 c RM a M b Diff RM a M b Diff 1 2 3 4 5 6 7 8 9 10 11 12 Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-9). Relative Accuracy (Eq. A-10). a b c Figure 3 to Appendix A—Relative Accuracy Determination (Flow Monitors) Run No. Date and time Flow rate (Low) (scf/hr)* Date and time Flow rate (Normal) (scf/hr)* Date and time Flow rate (High) (scf/hr)* RM M Diff RM M Diff RM M Diff 1 2 3 4 5 6 7 8 9 10 11 12 Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-9). Relative Accuracy (Eq. A-10). * Make sure the RM and M data are on a consistent basis, either wet or dry. Figure 4 to Appendix A—Relative Accuracy Determination (NO X Run No. Date and time Reference method data NO X NO X a O 2 2 RM M Difference 1 2 3 4 5 6 7 8 9 10 11 12 Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-9). Relative Accuracy (Eq. A-10). a Figure 5—Cycle Time Date of test Component/system ID#: Analyzer type Serial Number High level gas concentration: ______ ppm/% (circle one) Zero level gas concentration: ______ ppm/% (circle one) Analyzer span setting: ______ ppm/% (circle one) Upscale: Stable starting monitor value: ______ ppm/% (circle one) Stable ending monitor reading: ______ ppm/% (circle one) Elapsed time: ______ seconds Downscale: Stable starting monitor value: ______ ppm/% (circle one) Stable ending monitor value: ______ ppm/% (circle one) Elapsed time: ______ seconds Component cycle time= ______ seconds System cycle time= ______ seconds A. To determine the upscale cycle time (Figure 6a), measure the flue gas emissions until the response stabilizes. Record the stabilized value (see section 6.4 of this appendix for the stability criteria). B. Inject a high-level calibration gas into the port leading to the calibration cell or thimble (Point B). Allow the analyzer to stabilize. Record the stabilized value. C. Determine the step change. The step change is equal to the difference between the final stable calibration gas value (Point D) and the stabilized stack emissions value (Point A). D. Take 95% of the step change value and add the result to the stabilized stack emissions value (Point A). Determine the time at which 95% of the step change occurred (Point C). E. Calculate the upscale cycle time by subtracting the time at which the calibration gas was injected (Point B) from the time at which 95% of the step change occurred (Point C). In this example, upscale cycle time = (11−5) = 6 minutes. F. To determine the downscale cycle time (Figure 6b) repeat the procedures above, except that a zero gas is injected when the flue gas emissions have stabilized, and 95% of the step change in concentration is subtracted from the stabilized stack emissions value. G. Compare the upscale and downscale cycle time values. The longer of these two times is the cycle time for the analyzer. Editorial Note: For Federal Register www.govinfo.gov. Appendix B to Part 75—Quality Assurance and Quality Control Procedures 1. Quality Assurance/Quality Control Program Develop and implement a quality assurance/quality control (QA/QC) program for the continuous emission monitoring systems, excepted monitoring systems approved under appendix D or E to this part, and alternative monitoring systems under subpart E of this part, and their components. At a minimum, include in each QA/QC program a written plan that describes in detail (or that refers to separate documents containing) complete, step-by-step procedures and operations for each of the following activities. Upon request from regulatory authorities, the source shall make all procedures, maintenance records, and ancillary supporting documentation from the manufacturer (e.g., software coefficients and troubleshooting diagrams) available for review during an audit. Electronic storage of the information in the QA/QC plan is permissible, provided that the information can be made available in hardcopy upon request during an audit. 1.1 Requirements for All Monitoring Systems 1.1.1 Preventive Maintenance Keep a written record of procedures needed to maintain the monitoring system in proper operating condition and a schedule for those procedures. This shall, at a minimum, include procedures specified by the manufacturers of the equipment and, if applicable, additional or alternate procedures developed for the equipment. 1.1.2 Recordkeeping and Reporting Keep a written record describing procedures that will be used to implement the recordkeeping and reporting requirements in subparts E, F, and G and appendices D and E to this part, as applicable. 1.1.3 Maintenance Records Keep a record of all testing, maintenance, or repair activities performed on any monitoring system or component in a location and format suitable for inspection. A maintenance log may be used for this purpose. The following records should be maintained: date, time, and description of any testing, adjustment, repair, replacement, or preventive maintenance action performed on any monitoring system and records of any corrective actions associated with a monitor's outage period. Additionally, any adjustment that recharacterizes a system's ability to record and report emissions data must be recorded (e.g., changing of flow monitor or moisture monitoring system polynomial coefficients, K factors or mathematical algorithms, changing of temperature and pressure coefficients and dilution ratio settings), and a written explanation of the procedures used to make the adjustment(s) shall be kept. 1.1.4 The provisions in section 6.1.2 of appendix A to this part shall apply to the annual RATAs described in § 75.74(c)(2)(ii) and to the semiannual and annual RATAs described in section 2.3 of this appendix. 1.2 Specific Requirements for Continuous Emissions Monitoring Systems 1.2.1 Calibration Error Test and Linearity Check Procedures Keep a written record of the procedures used for daily calibration error tests and linearity checks (e.g., how gases are to be injected, adjustments of flow rates and pressure, introduction of reference values, length of time for injection of calibration gases, steps for obtaining calibration error or error in linearity, determination of interferences, and when calibration adjustments should be made). Identify any calibration error test and linearity check procedures specific to the continuous emission monitoring system that vary from the procedures in appendix A to this part. 1.2.2 Calibration and Linearity Adjustments Explain how each component of the continuous emission monitoring system will be adjusted to provide correct responses to calibration gases, reference values, and/or indications of interference both initially and after repairs or corrective action. Identify equations, conversion factors and other factors affecting calibration of each continuous emission monitoring system. 1.2.3 Relative Accuracy Test Audit Procedures Keep a written record of procedures and details peculiar to the installed continuous emission monitoring systems that are to be used for relative accuracy test audits, such as sampling and analysis methods. 1.2.4 Parametric Monitoring for Units With Add-on Emission Controls The owner or operator shall keep a written (or electronic) record including a list of operating parameters for the add-on SO 2 X 2 X 1.3 Specific Requirements for Excepted Systems Approved Under Appendices D and E 1.3.1 Fuel Flowmeter Accuracy Test Procedures Keep a written record of the specific fuel flowmeter accuracy test procedures. These may include: standard methods or specifications listed in and of appendix D to this part and incorporated by reference under § 75.6; the procedures of sections 2.1.5.2 or 2.1.7 of appendix D to this part; or other methods approved by the Administrator through the petition process of § 75.66(c). 1.3.2 Transducer or Transmitter Accuracy Test Procedures Keep a written record of the procedures for testing the accuracy of transducers or transmitters of an orifice-, nozzle-, or venturi-type fuel flowmeter under section 2.1.6 of appendix D to this part. These procedures should include a description of equipment used, steps in testing, and frequency of testing. 1.3.3 Fuel Flowmeter, Transducer, or Transmitter Calibration and Maintenance Records Keep a record of adjustments, maintenance, or repairs performed on the fuel flowmeter monitoring system. Keep records of the data and results for fuel flowmeter accuracy tests and transducer accuracy tests, consistent with appendix D to this part. 1.3.4 Primary Element Inspection Procedures Keep a written record of the standard operating procedures for inspection of the primary element (i.e., orifice, venturi, or nozzle) of an orifice-, venturi-, or nozzle-type fuel flowmeter. Examples of the types of information to be included are: what to examine on the primary element; how to identify if there is corrosion sufficient to affect the accuracy of the primary element; and what inspection tools (e.g., baroscope), if any, are used. 1.3.5 Fuel Sampling Method and Sample Retention Keep a written record of the standard procedures used to perform fuel sampling, either by utility personnel or by fuel supply company personnel. These procedures should specify the portion of the ASTM method used, as incorporated by reference under § 75.6, or other methods approved by the Administrator through the petition process of § 75.66(c). These procedures should describe safeguards for ensuring the availability of an oil sample (e.g., procedure and location for splitting samples, procedure for maintaining sample splits on site, and procedure for transmitting samples to an analytical laboratory). These procedures should identify the ASTM analytical methods used to analyze sulfur content, gross calorific value, and density, as incorporated by reference under § 75.6, or other methods approved by the Administrator through the petition process of § 75.66(c). 1.3.6 Appendix E Monitoring System Quality Assurance Information Identify the recommended range of quality assurance- and quality control-related operating parameters. Keep records of these operating parameters for each hour of unit operation (i.e., fuel combustion). Keep a written record of the procedures used to perform NO X X 1.4 Requirements for Alternative Systems Approved Under Subpart E 1.4.1 Daily Quality Assurance Tests Explain how the daily assessment procedures specific to the alternative monitoring system are to be performed. 1.4.2 Daily Quality Assurance Test Adjustments Explain how each component of the alternative monitoring system will be adjusted in response to the results of the daily assessments. 1.4.3 Relative Accuracy Test Audit Procedures Keep a written record of procedures and details peculiar to the installed alternative monitoring system that are to be used for relative accuracy test audits, such as sampling and analysis methods. 2. Frequency of Testing A summary chart showing each quality assurance test and the frequency at which each test is required is located at the end of this appendix in Figure 1. 2.1 Daily Assessments Perform the following daily assessments to quality-assure the hourly data recorded by the monitoring systems during each period of unit operation, or, for a bypass stack or duct, each period in which emissions pass through the bypass stack or duct. These requirements are effective as of the date when the monitor or continuous emission monitoring system completes certification testing. 2.1.1 Calibration Error Test Except as provided in section 2.1.1.2 of this appendix, perform the daily calibration error test of each gas monitoring system (including moisture monitoring systems consisting of wet- and dry-basis O 2 2.1.1.1 On-line Daily Calibration Error Tests. 2.1.1.2 Off-line Daily Calibration Error Tests. (1) An initial demonstration test of the monitoring system is successfully completed and the results are reported in the quarterly report required under § 75.64 of this part. The initial demonstration test, hereafter called the “off-line calibration demonstration”, consists of an off-line calibration error test followed by an on-line calibration error test. Both the off-line and on-line portions of the off-line calibration demonstration must meet the calibration error performance specification in section 3.1 of appendix A of this part. Upon completion of the off-line portion of the demonstration, the zero and upscale monitor responses may be adjusted, but only toward the true values of the calibration gases or reference signals used to perform the test and only in accordance with the routine calibration adjustment procedures specified in the quality control program required under section 1 of appendix B to this part. Once these adjustments are made, no further adjustments may be made to the monitoring system until after completion of the on-line portion of the off-line calibration demonstration. Within 26 clock hours of the completion hour of the off-line portion of the demonstration, the monitoring system must successfully complete the first attempted calibration error test, i.e., the on-line portion of the demonstration. (2) For each monitoring system that has passed the off-line calibration demonstration, off-line calibration error tests may be used on a limited basis to validate data, in accordance with paragraph (2) in section 2.1.5.1 of this appendix. 2.1.2 Daily Flow Interference Check Perform the daily flow monitor interference checks specified in section 2.2.2.2 of appendix A of this part while the unit is in operation at normal, stable conditions. 2.1.3 Additional Calibration Error Tests and Calibration Adjustments (a) In addition to the daily calibration error tests required under section 2.1.1 of this appendix, a calibration error test of a monitor shall be performed in accordance with section 2.1.1 of this appendix, as follows: whenever a daily calibration error test is failed; whenever a monitoring system is returned to service following repair or corrective maintenance that could affect the monitor's ability to accurately measure and record emissions data; or after making certain calibration adjustments, as described in this section. Except in the case of the routine calibration adjustments described in this section, data from the monitor are considered invalid until the required additional calibration error test has been successfully completed. (b) Routine calibration adjustments of a monitor are permitted after any successful calibration error test. These routine adjustments shall be made so as to bring the monitor readings as close as practicable to the known tag values of the calibration gases or to the actual value of the flow monitor reference signals. An additional calibration error test is required following routine calibration adjustments where the monitor's calibration has been physically adjusted (e.g., by turning a potentiometer) to verify that the adjustments have been made properly. An additional calibration error test is not required, however, if the routine calibration adjustments are made by means of a mathematical algorithm programmed into the data acquisition and handling system. The EPA recommends that routine calibration adjustments be made, at a minimum, whenever the daily calibration error exceeds the limits of the applicable performance specification in appendix A to this part for the pollutant concentration monitor, CO 2 2 (c) Additional (non-routine) calibration adjustments of a monitor are permitted prior to (but not during) linearity checks and RATAs and at other times, provided that an appropriate technical justification is included in the quality control program required under section 1 of this appendix. The allowable non-routine adjustments are as follows. The owner or operator may physically adjust the calibration of a monitor (e.g., by means of a potentiometer), provided that the post-adjustment zero and upscale responses of the monitor are within the performance specifications of the instrument given in section 3.1 of appendix A to this part. An additional calibration error test is required following such adjustments to verify that the monitor is operating within the performance specifications at both the zero and upscale calibration levels. 2.1.4 Data Validation (a) An out-of-control period occurs when the calibration error of an SO 2 X 2 2 2 2 2 2 2 X X (b) An out-of-control period also occurs whenever interference of a flow monitor is identified. The out-of-control period begins with the hour of completion of the failed interference check and ends with the hour of completion of an interference check that is passed. (c) The results of any certification, recertification, diagnostic, or quality assurance test required under this part may not be used to validate the emissions data required under this part, if the test is performed using EPA Protocol gas from a production site that is not participating in the PGVP, except as provided in § 75.21(g)(7) or if the cylinder(s) are analyzed by an independent laboratory and shown to meet the requirements of section 5.1.4(b) of appendix A to this part. 2.1.5 Quality Assurance of Data With Respect to Daily Assessments When a monitoring system passes a daily assessment (i.e., daily calibration error test or daily flow interference check), data from that monitoring system are prospectively validated for 26 clock hours (i.e., 24 hours plus a 2-hour grace period) beginning with the hour in which the test is passed, unless another assessment (i.e. a daily calibration error test, an interference check of a flow monitor, a quarterly linearity check, a quarterly leak check, or a relative accuracy test audit) is failed within the 26-hour period. 2.1.5.1 Data Invalidation with Respect to Daily Assessments. (1) Data from a monitoring system are invalid, beginning with the first hour following the expiration of a 26-hour data validation period or beginning with the first hour following the expiration of an 8-hour start-up grace period (as provided under section 2.1.5.2 of this appendix), if the required subsequent daily assessment has not been conducted. (2) For a monitor that has passed the off-line calibration demonstration, a combination of on-line and off-line calibration error tests may be used to validate data from the monitor, as follows. For a particular unit (or stack) operating hour, data from a monitor may be validated using a successful off-line calibration error test if: (a) An on-line calibration error test has been passed within the previous 26 unit (or stack) operating hours; and (b) the 26 clock hour data validation window for the off-line calibration error test has not expired. If either of these conditions is not met, then the data from the monitor are invalid with respect to the daily calibration error test requirement. Data from the monitor shall remain invalid until the appropriate on-line or off-line calibration error test is successfully completed so that both conditions (a) and (b) are met. (3) For units with two measurement ranges (low and high) for a particular parameter, when separate analyzers are used for the low and high ranges, a failed or expired calibration on one of the ranges does not affect the quality-assured data status on the other range. For a dual-range analyzer (i.e., a single analyzer with two measurement scales), a failed calibration error test on either the low or high scale results in an out-of-control period for the monitor. Data from the monitor remain invalid until corrective actions are taken and “hands-off” calibration error tests have been passed on both ranges. However, if the most recent calibration error test on the high scale was passed but has expired, while the low scale is up-to-date on its calibration error test requirements (or vice-versa), the expired calibration error test does not affect the quality-assured status of the data recorded on the other scale. 2.1.5.2 Daily Assessment Start-Up Grace Period. (1) The unit must have resumed operation after being in outage for 1 or more hours (i.e., the unit must be in a start-up condition) as evidenced by a change in unit operating time from zero in one clock hour to an operating time greater than zero in the next clock hour. (2) For the monitoring system to be used to validate data during the grace period, the previous daily assessment of the same kind must have been passed on-line within 26 clock hours prior to the last hour in which the unit operated before the outage. In addition, the monitoring system must be in-control with respect to quarterly and semi-annual or annual assessments. If both of the above conditions are met, then a start-up grace period of up to 8 clock hours applies, beginning with the first hour of unit operation following the outage. During the start-up grace period, data generated by the monitoring system are considered quality-assured. For each monitoring system, a start-up grace period for a calibration error test or flow interference check ends when either: (1) a daily assessment of the same kind (i.e., calibration error test or flow interference check) is performed; or (2) 8 clock hours have elapsed (starting with the first hour of unit operation following the outage), whichever occurs first. 2.1.6 Data Recording Record and tabulate all calibration error test data according to month, day, clock-hour, and magnitude in either ppm, percent volume, or scfh. Program monitors that automatically adjust data to the corrected calibration values (e.g., microprocessor control) to record either: (1) The unadjusted concentration or flow rate measured in the calibration error test prior to resetting the calibration, or (2) the magnitude of any adjustment. Record the following applicable flow monitor interference check data: (1) Sample line/sensing port pluggage, and (2) malfunction of each RTD, transceiver, or equivalent. 2.2 Quarterly Assessments For each primary and redundant backup monitor or monitoring system, perform the following quarterly assessments. This requirement is applies as of the calendar quarter following the calendar quarter in which the monitor or continuous emission monitoring system is provisionally certified. 2.2.1 Linearity Check Unless a particular monitor (or monitoring range) is exempted under this paragraph or under section 6.2 of appendix A to this part, perform a linearity check, in accordance with the procedures in section 6.2 of appendix A to this part, for each primary and redundant backup SO 2 2 2 2 2 2.2.2 Leak Check For differential pressure flow monitors, perform a leak check of all sample lines (a manual check is acceptable) at least once during each QA operating quarter. For this test, the unit does not have to be in operation. Conduct the leak checks no less than 30 days apart, to the extent practicable. If a leak check is failed, follow the applicable data validation procedures in section 2.2.3(g) of this appendix. 2.2.3 Data Validation (a) A linearity check shall not be commenced if the monitoring system is operating out-of-control with respect to any of the daily or semiannual quality assurance assessments required by sections 2.1 and 2.3 of this appendix or with respect to the additional calibration error test requirements in section 2.1.3 of this appendix. (b) Each required linearity check shall be done according to paragraph (b)(1), (b)(2) or (b)(3) of this section: (1) The linearity check may be done “cold,” i.e., with no corrective maintenance, repair, calibration adjustments, re-linearization or reprogramming of the monitor prior to the test. (2) The linearity check may be done after performing only the routine or non-routine calibration adjustments described in section 2.1.3 of this appendix at the various calibration gas levels (zero, low, mid or high), but no other corrective maintenance, repair, re-linearization or reprogramming of the monitor. Trial gas injection runs may be performed after the calibration adjustments and additional adjustments within the allowable limits in section 2.1.3 of this appendix may be made prior to the linearity check, as necessary, to optimize the performance of the monitor. The trial gas injections need not be reported, provided that they meet the specification for trial gas injections in § 75.20(b)(3)(vii)(E)( 1 1 (3) The linearity check may be done after repair, corrective maintenance or reprogramming of the monitor. In this case, the monitor shall be considered out-of-control from the hour in which the repair, corrective maintenance or reprogramming is commenced until the linearity check has been passed. Alternatively, the data validation procedures and associated timelines in §§ 75.20(b)(3)(ii) through (ix) may be followed upon completion of the necessary repair, corrective maintenance, or reprogramming. If the procedures in § 75.20(b)(3) are used, the words “quality assurance” apply instead of the word “recertification”. (c) Once a linearity check has been commenced, the test shall be done hands-off. That is, no adjustments of the monitor are permitted during the linearity test period, other than the routine calibration adjustments following daily calibration error tests, as described in section 2.1.3 of this appendix. If a routine daily calibration error test is performed and passed just prior to a linearity test (or during a linearity test period) and a mathematical correction factor is automatically applied by the DAHS, the correction factor shall be applied to all subsequent data recorded by the monitor, including the linearity test data. (d) If a daily calibration error test is failed during a linearity test period, prior to completing the test, the linearity test must be repeated. Data from the monitor are invalidated prospectively from the hour of the failed calibration error test until the hour of completion of a subsequent successful calibration error test. The linearity test shall not be commenced until the monitor has successfully completed a calibration error test. (e) An out-of-control period occurs when a linearity test is failed (i.e., when the error in linearity at any of the three concentrations in the quarterly linearity check (or any of the six concentrations, when both ranges of a single analyzer with a dual range are tested) exceeds the applicable specification in section 3.2 of appendix A to this part) or when a linearity test is aborted due to a problem with the monitor or monitoring system. For a NO X (f) No more than four successive calendar quarters shall elapse after the quarter in which a linearity check of a monitor or monitoring system (or range of a monitor or monitoring system) was last performed without a subsequent linearity test having been conducted. If a linearity test has not been completed by the end of the fourth calendar quarter since the last linearity test, then the linearity test must be completed within a 168 unit operating hour or stack operating hour “grace period” (as provided in section 2.2.4 of this appendix) following the end of the fourth successive elapsed calendar quarter, or data from the CEMS (or range) will become invalid. (g) An out-of-control period also occurs when a flow monitor sample line leak is detected. The out-of-control period begins with the hour of the failed leak check and ends with the hour of a satisfactory leak check following corrective action. (h) For each monitoring system, report the results of all completed and partial linearity tests that affect data validation (i.e., all completed, passed linearity checks; all completed, failed linearity checks; and all linearity checks aborted due to a problem with the monitor, including trial gas injections counted as failed test attempts under paragraph (b)(2) of this section or under § 75.20(b)(3)(vii)(F)), in the quarterly report required under § 75.64. Note that linearity attempts which are aborted or invalidated due to problems with the reference calibration gases or due to operational problems with the affected unit(s) need not be reported. Such partial tests do not affect the validation status of emission data recorded by the monitor. A record of all linearity tests, trial gas injections and test attempts (whether reported or not) must be kept on-site as part of the official test log for each monitoring system. (i) The results of any certification, recertification, diagnostic, or quality assurance test required under this part may not be used to validate the emissions data required under this part, if the test is performed using EPA Protocol gas that was not from an EPA Protocol gas production site participating in the PGVP on the date the gas was procured either by the tester or by a reseller that sold to the tester the unaltered EPA Protocol gas, except as provided in § 75.21(g)(7) or if the cylinder(s) are analyzed by an independent laboratory and shown to meet the requirements of section 5.1.4(b) of appendix A to this part. 2.2.4 Linearity and Leak Check Grace Period (a) When a required linearity test or flow monitor leak check has not been completed by the end of the QA operating quarter in which it is due or if, due to infrequent operation of a unit or infrequent use of a required high range of a monitor or monitoring system, four successive calendar quarters have elapsed after the quarter in which a linearity check of a monitor or monitoring system (or range) was last performed without a subsequent linearity test having been done, the owner or operator has a grace period of 168 consecutive unit operating hours, as defined in § 72.2 of this chapter (or, for monitors installed on common stacks or bypass stacks, 168 consecutive stack operating hours, as defined in § 72.2 of this chapter) in which to perform a linearity test or leak check of that monitor or monitoring system (or range). The grace period begins with the first unit or stack operating hour following the calendar quarter in which the linearity test was due. Data validation during a linearity or leak check grace period shall be done in accordance with the applicable provisions in section 2.2.3 of this appendix. (b) If, at the end of the 168 unit (or stack) operating hour grace period, the required linearity test or leak check has not been completed, data from the monitoring system (or range) shall be invalid, beginning with the first unit operating hour following the expiration of the grace period. Data from the monitoring system (or range) remain invalid until the hour of completion of a subsequent successful hands-off linearity test or leak check of the monitor or monitoring system (or range). Note that when a linearity test or a leak check is conducted within a grace period for the purpose of satisfying the linearity test or leak check requirement from a previous QA operating quarter, the results of that linearity test or leak check may only be used to meet the linearity check or leak check requirement of the previous quarter, not the quarter in which the missed linearity test or leak check is completed. 2.2.5 Flow-to-Load Ratio or Gross Heat Rate Evaluation (a) Applicability and methodology. avg avg h Where: R h Q h L h avg (1) In Equation B-1, the owner or operator may use either bias-adjusted flow rates or unadjusted flow rates, provided that all of the ratios are calculated the same way. For a common stack, L h h 2 h (2) Alternatively, the owner or operator may calculate the hourly gross heat rates (GHR) in lieu of the hourly flow-to-load ratios. The hourly GHR shall be determined only for those hours in which quality-assured flow rate data and diluent gas (CO 2 2 where: (GHR) h (Heat Input) h L h avg (3) In Equation B-1a, the owner or operator may either use bias-adjusted flow rates or unadjusted flow rates in the calculation of (Heat Input) h (4) The owner or operator shall evaluate the calculated hourly flow-to-load ratios (or gross heat rates) as follows. A separate data analysis shall be performed for each primary and each redundant backup flow rate monitor used to record and report data during the quarter. Each analysis shall be based on a minimum of 168 acceptable recorded hourly average flow rates (i.e., at loads within ±10 percent of L avg (5) For each flow monitor, use Equation B-2 in this appendix to calculate E h h ref ref where: E h R h avg R ref (6) Equation B-2 shall be used in a consistent manner. That is, use R ref h ref h f h (b) Acceptable results. f avg avg avg avg f f f f (c) Recalculation of E f avg f (1) Any hour in which the type of fuel combusted was different from the fuel burned during the most recent normal-load RATA. For purposes of this determination, the type of fuel is different if the fuel is in a different state of matter (i.e., solid, liquid, or gas) than is the fuel burned during the RATA or if the fuel is a different classification of coal (e.g., bituminous versus sub-bituminous). Also, for units that co-fire different types of fuels, if the reference RATA was done while co-firing, then hours in which a single fuel was combusted may be excluded from the data analysis as different fuel hours (and vice-versa for co-fired hours, if the reference RATA was done while combusting only one type of fuel); (2) For a unit that is equipped with an SO 2 2 (3) Any hour in which “ramping” occurred, i.e., the hourly load differed by more than ±15.0 percent from the load during the preceding hour or the subsequent hour; (4) For a unit with a multiple stack discharge configuration consisting of a main stack and a bypass stack, any hour in which the flue gases were discharged through both stacks; (5) If a normal-load flow RATA was performed and passed during the quarter being analyzed, any hour prior to completion of that RATA; and (6) If a problem with the accuracy of the flow monitor was discovered during the quarter and was corrected (as evidenced by passing the abbreviated flow-to-load test in section 2.2.5.3 of this appendix), any hour prior to completion of the abbreviated flow-to-load test. (7) After identifying and excluding all non-representative hourly data in accordance with paragraphs (c)(1) through (6) of this section, the owner or operator may analyze the remaining data a second time. At least 168 representative hourly ratios or GHR values must be available to perform the analysis; otherwise, the flow-to-load (or GHR) analysis is not required for that monitor for that calendar quarter. (8) If, after re-analyzing the data, E f f f f 2.2.5.1 Option 1 Within 14 unit operating days of the end of the calendar quarter for which the E f (a) If the investigation fails to uncover a problem with the flow monitor, a RATA shall be performed in accordance with Option 2 in section 2.2.5.2 of this appendix. (b) If a problem with the flow monitor is identified through the investigation (including the need to re-linearize the monitor by changing the polynomial coefficients or K factor(s)), data from the monitor are considered invalid back to the first unit operating hour after the end of the calendar quarter for which E f f e.g., 2.2.5.2 Option 2 Perform a single-load RATA (at a load designated as normal under section 6.5.2.1 of appendix A to this part) of each flow monitor for which E f f f 2.2.5.3 Abbreviated Flow-to-Load Test (a) The following abbreviated flow-to-load test may be performed after any documented repair, component replacement, or other corrective maintenance to a flow monitor (except for changes affecting the linearity of the flow monitor, such as adjusting the flow monitor coefficients or K factor(s)) to demonstrate that the repair, replacement, or other maintenance has not significantly affected the monitor's ability to accurately measure the stack gas volumetric flow rate. Data from the monitoring system are considered invalid from the hour of commencement of the repair, replacement, or maintenance until either the hour in which the abbraviated flow-to-load test is passed, or the hour in which a probationary calibration error test is passed following completion of the repair, replacement, or maintenance and any associated adjustments to the monitor. If the latter option is selected, the abbreviated flow-to-load test shall be completed within 168 unit operating hours of the probationary calibration error test (or, for peaking units, within 30 unit operating days, if that is less restrictive). Data from the monitor are considered to be conditionally valid (as defined in § 72.2 of this chapter), beginning with the hour of the probationary calibration error test. (b) Operate the unit(s) in such a way as to reproduce, as closely as practicable, the exact conditions at the time of the most recent normal-load flow RATA. To achieve this, it is recommended that the load be held constant to within ±10.0 percent of the average load during the RATA and that the diluent gas (CO 2 2 2 2 f h f h (c) The results of the abbreviated flow-to-load test shall be considered acceptable, and no further action is required if the value of E f f 2.3 Semiannual and Annual Assessments For each primary and redundant backup monitoring system, perform relative accuracy assessments either semiannually or annually, as specified in section 2.3.1.1 or 2.3.1.2 of this appendix, for the type of test and the performance achieved. This requirement applies as of the calendar quarter following the calendar quarter in which the monitoring system is provisionally certified. A summary chart showing the frequency with which a relative accuracy test audit must be performed, depending on the accuracy achieved, is located at the end of this appendix in Figure 2. 2.3.1 Relative Accuracy Test Audit (RATA) 2.3.1.1 Standard RATA Frequencies (a) Except as otherwise specified in § 75.21(a)(6) or (a)(7) or in section 2.3.1.2 of this appendix, perform relative accuracy test audits semiannually, i.e., 2 2 2 2 2 2 X X (b) The relative accuracy test audit frequency of a CEMS may be reduced, as specified in section 2.3.1.2 of this appendix, for primary or redundant backup monitoring systems which qualify for less frequent testing. Perform all required RATAs in accordance with the applicable procedures and provisions in sections 6.5 through 6.5.2.2 of appendix A to this part and sections 2.3.1.3 and 2.3.1.4 of this appendix. 2.3.1.2 Reduced RATA Frequencies Relative accuracy test audits of primary and redundant backup SO 2 2 2 2 2 2 X X 2 (a) The relative accuracy during the audit of an SO 2 2 2 2 2 2 X X 2 (b) [Reserved] (c) The relative accuracy during the audit of a flow monitor is ≤7.5 percent at each operating level tested; (d) For low flow (≤10.0 fps, as measured by the reference method during the RATA) stacks/ducts, when the flow monitor fails to achieve a relative accuracy ≤7.5 percent during the audit, but the monitor mean value, calculated using Equation A-7 in appendix A to this part and converted back to an equivalent velocity in standard feet per second (fps), is within ±1.5 fps of the reference method mean value, converted to an equivalent velocity in fps; (e) For low SO 2 X 2 X 2 X (f) For units with low NO X X X (g) [Reserved] (h) For a CO 2 2 2 2 (i) When the relative accuracy of a continuous moisture monitoring system is ≤7.5 percent or when the mean difference between the reference method values from the RATA and the corresponding monitoring system values is within ±1.0 percent H 2 2.3.1.3 RATA Load (or Operating) Levels and Additional RATA Requirements (a) For SO 2 2 2 2 2 2 X X (b) For flow monitors installed on peaking units and bypass stacks, and for flow monitors that qualify to perform only single-level RATAs under section 6.5.2(e) of appendix A to this part, all required semiannual or annual relative accuracy test audits shall be single-load (or single-level) audits at the normal load (or operating level), as defined in section 6.5.2.1(d) of appendix A to this part. (c) For all other flow monitors, the RATAs shall be performed as follows: (1) An annual 2-load (or 2-level) flow RATA shall be done at the two most frequently used load levels (or operating levels), as determined under section 6.5.2.1(d) of appendix A to this part, or (if applicable) at the operating levels determined under section 6.5.2(e) of appendix A to this part. Alternatively, a 3-load (or 3-level) flow RATA at the low, mid, and high load levels (or operating levels), as defined under section 6.5.2.1(b) of appendix A to this part, may be performed in lieu of the 2-load (or 2-level) annual RATA. (2) If the flow monitor is on a semiannual RATA frequency, 2-load (or 2-level) flow RATAs and single-load (or single-level) flow RATAs at the normal load level (or normal operating level) may be performed alternately. (3) A single-load (or single-level) annual flow RATA may be performed in lieu of the 2-load (or 2-level) RATA if the results of an historical load data analysis show that in the time period extending from the ending date of the last annual flow RATA to a date that is no more than 21 days prior to the date of the current annual flow RATA, the unit (or combination of units, for a common stack) has operated at a single load level (or operating level) (low, mid, or high), for ≥85.0 percent of the time. Alternatively, a flow monitor may qualify for a single-load (or single-level) RATA if the 85.0 percent criterion is met in the time period extending from the beginning of the quarter in which the last annual flow RATA was performed through the end of the calendar quarter preceding the quarter of current annual flow RATA. (4) A 3-load (or 3-level) RATA, at the low-, mid-, and high-load levels (or operating levels), as determined under section 6.5.2.1 of appendix A to this part, shall be performed at least once every twenty consecutive calendar quarters, except for flow monitors that are exempted from 3-load (or 3-level) RATA testing under section 6.5.2(b) or 6.5.2(e) of appendix A to this part. (5) A 3-load (or 3-level) RATA is required whenever a flow monitor is re-linearized, i.e., (6) For all multi-level flow audits, the audit points at adjacent load levels or at adjacent operating levels ( e.g., (d) A RATA of a moisture monitoring system shall be performed whenever the coefficient, K factor or mathematical algorithm determined under section 6.5.7 of appendix A to this part is changed. 2.3.1.4 Number of RATA Attempts The owner or operator may perform as many RATA attempts as are necessary to achieve the desired relative accuracy test audit frequencies and/or bias adjustment factors. However, the data validation procedures in section 2.3.2 of this appendix must be followed. 2.3.2 Data Validation (a) A RATA shall not commence if the monitoring system is operating out-of-control with respect to any of the daily and quarterly quality assurance assessments required by sections 2.1 and 2.2 of this appendix or with respect to the additional calibration error test requirements in section 2.1.3 of this appendix. (b) Each required RATA shall be done according to paragraphs (b)(1), (b)(2) or (b)(3) of this section: (1) The RATA may be done “cold,” i.e., with no corrective maintenance, repair, calibration adjustments, re-linearization or reprogramming of the monitoring system prior to the test. (2) The RATA may be done after performing only the routine or non-routine calibration adjustments described in section 2.1.3 of this appendix at the zero and/or upscale calibration gas levels, but no other corrective maintenance, repair, re-linearization or reprogramming of the monitoring system. Trial RATA runs may be performed after the calibration adjustments and additional adjustments within the allowable limits in section 2.1.3 of this appendix may be made prior to the RATA, as necessary, to optimize the performance of the CEMS. The trial RATA runs need not be reported, provided that they meet the specification for trial RATA runs in § 75.20(b)(3)(vii)(E)( 2 2 (3) The RATA may be done after repair, corrective maintenance, re-linearization or reprogramming of the monitoring system. In this case, the monitoring system shall be considered out-of-control from the hour in which the repair, corrective maintenance, re-linearization or reprogramming is commenced until the RATA has been passed. Alternatively, the data validation procedures and associated timelines in §§ 75.20(b)(3)(ii) through (ix) may be followed upon completion of the necessary repair, corrective maintenance, re-linearization or reprogramming. If the procedures in § 75.20(b)(3) are used, the words “quality assurance” apply instead of the word “recertification.” (c) Once a RATA is commenced, the test must be done hands-off. No adjustment of the monitor's calibration is permitted during the RATA test period, other than the routine calibration adjustments following daily calibration error tests, as described in section 2.1.3 of this appendix. If a routine daily calibration error test is performed and passed just prior to a RATA (or during a RATA test period) and a mathematical correction factor is automatically applied by the DAHS, the correction factor shall be applied to all subsequent data recorded by the monitor, including the RATA test data. For 2-level and 3-level flow monitor audits, no linearization or reprogramming of the monitor is permitted in between load levels. (d) For single-load (or single-level) RATAs, if a daily calibration error test is failed during a RATA test period, prior to completing the test, the RATA must be repeated. Data from the monitor are invalidated prospectively from the hour of the failed calibration error test until the hour of completion of a subsequent successful calibration error test. The subsequent RATA shall not be commenced until the monitor has successfully passed a calibration error test in accordance with section 2.1.3 of this appendix. For multiple-load (or multiple-level) flow RATAs, each load level (or operating level) is treated as a separate RATA ( i.e., (e) For a RATA performed using the option in paragraph (b)(1) or (b)(2) of this section, if the RATA is failed (that is, if the relative accuracy exceeds the applicable specification in section 3.3 of appendix A to this part) or if the RATA is aborted prior to completion due to a problem with the CEMS, then the CEMS is out-of-control and all emission data from the CEMS are invalidated prospectively from the hour in which the RATA is failed or aborted. Data from the CEMS remain invalid until the hour of completion of a subsequent RATA that meets the applicable specification in section 3.3 of appendix A to this part. If the option in paragraph (b)(3) of this section to use the data validation procedures and associated timelines in §§ 75.20(b)(3)(ii) through(b)(3)(ix) has been selected, the beginning and end of the out-of-control period shall be determined in accordance with § 75.20(b)(3)(vii)(A) and (B). Note that when a RATA is aborted for a reason other than monitoring system malfunction ( see (f) For a 2-level or 3-level flow RATA, if, at any load level (or operating level), a RATA is failed or aborted due to a problem with the flow monitor, the RATA at that load level (or operating level) must be repeated. The flow monitor is considered out-of-control and data from the monitor are invalidated from the hour in which the test is failed or aborted and remain invalid until the passing of a RATA at the failed load level (or operating level), unless the option in paragraph (b)(3) of this section to use the data validation procedures and associated timelines in § 75.20(b)(3)(ii) through (b)(3)(ix) has been selected, in which case the beginning and end of the out-of-control period shall be determined in accordance with § 75.20(b)(3)(vii)(A) and (B). Flow RATA(s) that were previously passed at the other load level(s) (or operating level(s)) do not have to be repeated unless the flow monitor must be re-linearized following the failed or aborted test. If the flow monitor is re-linearized, a subsequent 3-load (or 3-level) RATA is required, except as otherwise provided in section 2.3.1.3(c)(5) of this appendix. (g) Data validation for failed RATAs for a CO 2 2 2 X X (1) For a CO 2 2 2 X 2 2 2 2 X 2 2 (2) This paragraph (g)(2) applies only to a NO X X X X X X X X X X X (h) For each monitoring system, report the results of all completed and partial RATAs that affect data validation (i.e., all completed, passed RATAs; all completed, failed RATAs; and all RATAs aborted due to a problem with the CEMS, including trial RATA runs counted as failed test attempts under paragraph (b)(2) of this section or under § 75.20(b)(3)(vii)(F)) in the quarterly report required under § 75.64. Note that RATA attempts that are aborted or invalidated due to problems with the reference method or due to operational problems with the affected unit(s) need not be reported. Such runs do not affect the validation status of emission data recorded by the CEMS. However, a record of all RATAs, trial RATA runs and RATA attempts (whether reported or not) must be kept on-site as part of the official test log for each monitoring system. (i) Each time that a hands-off RATA of an SO 2 x- X 2 X (j) Failure of the bias test does not result in the monitoring system being out-of-control. (k) The results of any certification, recertification, diagnostic, or quality assurance test required under this part may not be used to validate the emissions data required under this part, if the test is performed using EPA Protocol gas from a production site that is not participating in the PGVP, except as provided in § 75.21(g)(7) or if the cylinder(s) are analyzed by an independent laboratory and shown to meet the requirements of section 5.1.4(b) of appendix A to this part. 2.3.3 RATA Grace Period (a) The owner or operator has a grace period of 720 consecutive unit operating hours, as defined in § 72.2 of this chapter (or, for CEMS installed on common stacks or bypass stacks, 720 consecutive stack operating hours, as defined in § 72.2 of this chapter), in which to complete the required RATA for a particular CEMS whenever: (1) A required RATA has not been performed by the end of the QA operating quarter in which it is due; or (2) A required 3-load flow RATA has not been performed by the end of the calendar quarter in which it is due; or (3) For a unit which is conditionally exempted under § 75.21(a)(7) from the SO 2 2 (4) Eight successive calendar quarters have elapsed, following the quarter in which a RATA was last performed, without a subsequent RATA having been done, due either to infrequent operation of the unit(s) or frequent combustion of very low sulfur fuel, as defined in § 72.2 of this chapter (SO 2 (b) Except for SO 2 2 (c) If, at the end of the 720 unit (or stack) operating hour grace period, the RATA has not been completed, data from the monitoring system shall be invalid, beginning with the first unit operating hour following the expiration of the grace period. Data from the CEMS remain invalid until the hour of completion of a subsequent hands-off RATA. The deadline for the next test shall be either two QA operating quarters (if a semiannual RATA frequency is obtained) or four QA operating quarters (if an annual RATA frequency is obtained) after the quarter in which the RATA is completed, not to exceed eight calendar quarters. (d) When a RATA is done during a grace period in order to satisfy a RATA requirement from a previous quarter, the deadline for the next RATA shall determined as follows: (1) If the grace period RATA qualifies for a reduced, (i.e., annual), RATA frequency the deadline for the next RATA shall be set at three QA operating quarters after the quarter in which the grace period test is completed. (2) If the grace period RATA qualifies for the standard, (i.e., semiannual), RATA frequency the deadline for the next RATA shall be set at two QA operating quarters after the quarter in which the grace period test is completed. (3) Notwithstanding these requirements, no more than eight successive calendar quarters shall elapse after the quarter in which the grace period test is completed, without a subsequent RATA having been conducted. 2.3.4 Bias Adjustment Factor Except as otherwise specified in section 7.6.5 of appendix A to this part, if an SO 2 X X X 2.4 Recertification, Quality Assurance, RATA Frequency and Bias Adjustment Factors (Special Considerations) (a) When a significant change is made to a monitoring system such that recertification of the monitoring system is required in accordance with § 75.20(b), a recertification test (or tests) must be performed to ensure that the CEMS continues to generate valid data. In all recertifications, a RATA will be one of the required tests; for some recertifications, other tests will also be required. A recertification test may be used to satisfy the quality assurance test requirement of this appendix. For example, if, for a particular change made to a CEMS, one of the required recertification tests is a linearity check and the linearity check is successful, then, unless another such recertification event occurs in that same QA operating quarter, it would not be necessary to perform an additional linearity test of the CEMS in that quarter to meet the quality assurance requirement of section 2.2.1 of this appendix. For this reason, EPA recommends that owners or operators coordinate component replacements, system upgrades, and other events that may require recertification, to the extent practicable, with the periodic quality assurance testing required by this appendix. When a quality assurance test is done for the dual purpose of recertification and routine quality assurance, the applicable data validation procedures in § 75.20(b)(3) shall be followed. (b) Except as provided in section 2.3.3 of this appendix, whenever a passing RATA of a gas monitor is performed, or a passing 2-load (or 2-level) RATA or a passing 3-load (or 3-level) RATA of a flow monitor is performed (irrespective of whether the RATA is done to satisfy a recertification requirement or to meet the quality assurance requirements of this appendix, or both), the RATA frequency (semi-annual or annual) shall be established based upon the date and time of completion of the RATA and the relative accuracy percentage obtained. For 2-load (or 2-level) and 3-load (or 3-level) flow RATAs, use the highest percentage relative accuracy at any of the loads (or levels) to determine the RATA frequency. The results of a single-load (or single-level) flow RATA may be used to establish the RATA frequency when the single-load (or single-level) flow RATA is specifically required under section 2.3.1.3(b) of this appendix or when the single-load (or single-level) RATA is allowed under section 2.3.1.3(c) of this appendix for a unit that has operated at one load level (or operating level) for ≥85.0 percent of the time since the last annual flow RATA. No other single-load (or single-level) flow RATA may be used to establish an annual RATA frequency; however, a 2-load or 3-load (or a 2-level or 3-level) flow RATA may be performed at any time or in place of any required single-load (or single-level) RATA, in order to establish an annual RATA frequency. 2.5 Other Audits Affected units may be subject to relative accuracy test audits at any time. If a monitor or continuous emission monitoring system fails the relative accuracy test during the audit, the monitor or continuous emission monitoring system shall be considered to be out-of-control beginning with the date and time of completion of the audit, and continuing until a successful audit test is completed following corrective action. If a monitor or monitoring system fails the bias test during an audit, use the bias adjustment factor given by equations A-11 and A-12 in appendix A to this part to adjust the monitored data. Apply this adjustment factor from the date and time of completion of the audit until the date and time of completion of a relative accuracy test audit that does not show bias. Figure 1 to Appendix B of Part 75—Quality Assurance Test Requirements Test Basic QA test frequency requirements Daily * Quarterly * Semiannual or annual * Calibration Error Test (2 pt.) X Interference Check (flow) X Flow-to-Load Ratio X Leak Check (DP flow monitors) X Linearity Check * (3 pt.) X RATA (SO 2 X 2 2 2 1 X RATA (flow) 1 2 X * “Daily” means operating days, only. “Quarterly” means once every QA operating quarter. “Semiannual” means once every two QA operating quarters. “Annual” means once every four QA operating quarters. 1 2 Figure 2 to Appendix B of Part 75—Relative Accuracy Test Frequency Incentive System RATA Semiannual W Annual W SO 2 X Y 7.5% <RA ≤10.0% or ±15.0 ppm X RA ≤7.5% or ±12.0 ppm X NO X 7.5% <RA ≤10.0% or ±0.020 lb/mmBtu X RA ≤7.5% or ±0. 015 lb/mmBtu X Flow 7.5% <RA ≤10.0% or ±2.0 fps X RA ≤7.5% or ±1.5 fps X CO 2 2 7.5% <RA ≤10.0% or ±1.0% CO 2 2 X RA ≤7.5% or ±0.7% CO 2 2 X Moisture 7.5% <RA ≤10.0% or ±1.5% H 2 X RA ≤7.5% or ±1.0% H 2 X W 2 X 2 2 2 X Y X X [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26546, 26571, May 17, 1995; 61 FR 59165, Nov. 20, 1996; 64 FR 28644, May 26, 1999; 64 FR 37582, July 12, 1999; 67 FR 40456, 40457, June 12, 2002; 67 FR 53505, Aug. 16, 2002; 67 FR 57274, Sept. 9, 2002; 70 FR 28693, May 18, 2005; 72 FR 51528, Sept. 7, 2007; 73 FR 4367, Jan. 24, 2008; 76 FR 17321, Mar. 28, 2011] Appendix C to Part 75—Missing Data Estimation Procedures 1. Parametric Monitoring Procedure for Missing SO 2 X 1.1 Applicability The owner or operator of any affected unit equipped with post-combustion SO 2 X 2 X 2 X 2 X 2 X 2 X Base the empirical and process simulation methods or models on the fundamental chemistry and engineering principles involved in the treatment of pollutant gas. On a case-by-case basis, the Administrator may pre-certify commercially available process simulation methods and models. 1.2 Petition Requirements Continuously monitor, determine, and record hourly averages of the estimated SO 2 X 2 X 1.2.1 Parameters for Wet Flue Gas Desulfurization System 1.2.1.1 Number of scrubber modules in operation. 1.2.1.2 Total slurry rate to each scrubber module (gal per min). 1.2.1.3 In-line absorber pH of each scrubber module. 1.2.1.4 Pressure differential across each scrubber module (inches of water column). 1.2.1.5 Unit load (MWe). 1.2.1.6 Inlet and outlet SO 2 1.2.1.7 Percent solids in slurry for each scrubber module. 1.2.1.8 Any other parameters necessary to verify scrubber removal efficiency, if the Administrator determines the parameters above are not sufficient. 1.2.2 Parameters for Dry Flue Gas Desulfurization System 1.2.2.1 Number of scrubber modules in operation. 1.2.2.2 Atomizer slurry flow rate to each scrubber module (gal per min). 1.2.2.3 Inlet and outlet temperature for each scrubber module (°F). 1.2.2.4 Pressure differential across each scrubber module (inches of water column). 1.2.2.5 Unit load (MWe). 1.2.2.6 Inlet and outlet SO 2 1.2.2.7 Any other parameters necessary to verify scrubber removal efficiency, if the Administrator determines the parameters above are not sufficient. 1.2.3 Parameters for Other Flue Gas Desulfurization Systems If SO 2 1.2.4 Parameters for Post-Combustion NO X 1.2.4.1 Inlet air flow rate to the unit (boiler) (mcf/hr). 1.2.4.2 Excess oxygen concentration of flue gas at stack outlet (percent). 1.2.4.3 Carbon monoxide concentration of flue gas at stack outlet (ppm). 1.2.4.4 Temperature of flue gas at outlet of the unit (°F). 1.2.4.5 Inlet and outlet NO X X 1.2.4.6 Any other parameters specific to the emission reduction process necessary to verify the NO X 1.3 Correlation of Emissions With Parameters Establish a method for correlating hourly averages of the parameters identified above with the percent removal efficiency of the SO 2 X 2 Each parametric data substitution procedure should develop a data correlation procedure to verify the performance of the SO 2 X 2 X For NO X 1.4 Calculations 1.4.1 Use the following equation to calculate substitute data for filling in missing (outlet) SO 2 M o c (Eq. C-1) where, M o 2 I c 2 E = Removal efficiency of SO 2 1.4.2 Use the following equation to calculate substitute data for filling in missing (outlet) NO X M o c (Eq. C-2) where, M o X I c X E = Removal efficiency of post-combustion NO X 1.5 Missing Data 1.5.1 If both the inlet and the outlet SO 2 2 2 2 1.5.2 If both the inlet and outlet NO X X X X 1.6 Application Apply to the Administrator for approval and certification of the parametric substitution procedure for filling in missing SO 2 X 2. Load-based Procedure for Missing Flow Rate, NO X X 2.1 Applicability This procedure is applicable for data from all affected units for use in accordance with the provisions of this part to provide substitute data for volumetric flow rate (scfh), NO X X X X 2.2 Procedure 2.2.1 For a single unit, establish ten operating load ranges defined in terms of percent of the maximum hourly average gross load of the unit, in gross megawatts (MWge), as shown in Table C-1. (Do not use integrated hourly gross load in MW-hr.) For units sharing a common stack monitored with a single flow monitor, the load ranges for flow (but not for NO X Table C-1—Definition of Operating Load Ranges for Load-based Substitution Data Procedures Operating load range Percent of maximum hourly gross load or maximum hourly gross steam load (percent) 1 0-10 2 >10-20 3 >20-30 4 >30-40 5 >40-50 6 >50-60 7 >60-70 8 >70-80 9 >80-90 10 >90 2.2.2 Beginning with the first hour of unit operation after installation and certification of the flow monitor or the NO X X X 2.2.3 Beginning with the first hour of unit operation after installation and certification of the flow monitor or the NO X X X X 2.2.3.1 Average of the hourly flow rates reported by a flow monitor, in scfh. 2.2.3.2 The 90th percentile value of hourly flow rates, in scfh. 2.2.3.3 The 95th percentile value of hourly flow rates, in scfh. 2.2.3.4 The maximum value of hourly flow rates, in scfh. 2.2.3.5 Average of the hourly NO X X 2.2.3.6 The 90th percentile value of hourly NO X 2.2.3.7 The 95th percentile value of hourly NO X 2.2.3.8 The maximum value of hourly NO X 2.2.3.9 Average of the hourly NO X X X 2.2.3.10 The 90th percentile value of hourly NO X 2.2.3.11 The 95th percentile value of hourly NO X 2.2.3.12 The maximum value of hourly NO X 2.2.4 Calculate all monitor or continuous emission monitoring system data averages, maximum values, and percentile values determined by this procedure using bias adjusted values in the load ranges. 2.2.5 When a bias adjustment is necessary for the flow monitor and/or the NO X X X 2.2.6 Use the calculated monitor or monitoring system data averages, maximum values, and percentile values to substitute for missing flow rate and NO X X 3. Non-load-based Procedure for Missing Flow Rate, NO X X 3.1 Applicability For affected units that do not produce electrical output in megawatts or thermal output in klb/hr of steam, this procedure may be used in accordance with the provisions of this part to provide substitute data for volumetric flow rate (scfh), NO X X X X X 3.2 Procedure 3.2.1 For each monitored parameter (flow rate, NO X X X X 3.2.2 In the electronic quarterly report required under § 75.64, indicate for each hour of unit operation the operational bin associated with the NO X 3.2.3 The data acquisition and handling system must be capable of properly identifying and recording the operational bin number for each unit operating hour. The DAHS must also be capable of calculating and recording the following information (as applicable) for each unit operating hour of missing flow or NO X (a) The previous 2,160 quality-assured monitor operating hours (on a rolling basis), or (b) All previous quality-assured monitor operating hours in the previous 3 years: 3.2.3.1 Average of the hourly flow rates reported by a flow monitor (scfh). 3.2.3.2 The 90th percentile value of hourly flow rates (scfh). 3.2.3.3 The 95th percentile value of hourly flow rates (scfh). 3.2.3.4 The maximum value of hourly flow rates (scfh). 3.2.3.5 Average of the hourly NO X X 3.2.3.6 The 90th percentile value of hourly NO X 3.2.3.7 The 95th percentile value of hourly NO X 3.2.3.8 The maximum value of hourly NO X 3.2.3.9 Average of the hourly NO X X X 3.2.3.10 The 90th percentile value of hourly NO X 3.2.3.11 The 95th percentile value of hourly NO X 3.2.3.12 The maximum value of hourly NO X 3.2.4 When a bias adjustment is necessary for the flow monitor and/or the NO X X 3.2.5 Calculate all CEMS data averages, maximum values, and percentile values determined by this procedure using bias-adjusted values. 3.2.6 Use the calculated monitor or monitoring system data averages, maximum values, and percentile values to substitute for missing flow rate and NO X X [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26547, 26548, May 17, 1995; 63 FR 57313, Oct. 27, 1998; 64 FR 28652, May 26, 1999; 67 FR 40459, June 12, 2002] Appendix D to Part 75—Optional SO 2 1. Applicability 1.1 This protocol may be used in lieu of continuous SO 2 2 1.2 Pursuant to the procedures in § 75.20, complete all testing requirements to certify use of this protocol in lieu of a flow monitor and an SO 2 2. Procedure 2.1 Fuel Flowmeter Measurements For each hour when the unit is combusting fuel, measure and record the flow rate of fuel combusted by the unit, except as provided in section 2.1.4 of this appendix. Measure the flow rate of fuel with an in-line fuel flowmeter, and automatically record the data with a data acquisition and handling system, except as provided in section 2.1.4 of this appendix. 2.1.1 Measure the flow rate of each fuel entering and being combusted by the unit. If, on an annual basis, more than 5.0 percent of the fuel from the main pipe is diverted from the unit without being burned and that diversion occurs downstream of the fuel flowmeter, an additional in-line fuel flowmeter is required to account for the unburned fuel. In this case, record the flow rate of each fuel combusted by the unit as the difference between the flow measured in the pipe leading to the unit and the flow in the pipe diverting fuel away from the unit. However, the additional fuel flowmeter is not required if, on an annual basis, the total amount of fuel diverted away from the unit, expressed as a percentage of the total annual fuel usage by the unit is demonstrated to be less than or equal to 5.0 percent. The owner or operator may make this demonstration in the following manner: 2.1.1.1 For existing units with fuel usage data from fuel flowmeters, if data are submitted from a previous year demonstrating that the total diverted yearly fuel does not exceed 5% of the total fuel used; or 2.1.1.2 For new units which do not have historical data, if a letter is submitted signed by the designated representative certifying that, in the future, the diverted fuel will not exceed 5.0% of the total annual fuel usage; or 2.1.1.3 By using a method approved by the Administrator under § 75.66(d). 2.1.2 Install and use fuel flowmeters meeting the requirements of this appendix in a pipe going to each unit, or install and use a fuel flowmeter in a common pipe header (as defined in § 72.2). However, the use of a fuel flowmeter in a common pipe header and the provisions of sections 2.1.2.1 and 2.1.2.2 of this appendix shall not apply to any unit that is using the provisions of subpart H of this part to monitor, record, and report NO X X 2.1.2.1 Measure the fuel flow rate in the common pipe, and combine SO 2 2.1.2.2 Apportion the heat input rate measured at the common pipe to the individual units, using Equation F-21a, F-21b, or F-21d in appendix F to this part. 2.1.3 For a gas-fired unit or an oil-fired unit that continuously or frequently combusts a supplemental fuel for flame stabilization or safety purposes, measure the flow rate of the supplemental fuel with a fuel flowmeter meeting the requirements of this appendix. 2.1.4 Situations in Which Certified Flowmeter is Not Required 2.1.4.1 Start-up or Ignition Fuel For an oil-fired unit that uses gas solely for start-up or burner ignition, a gas-fired unit that uses oil solely for start-up or burner ignition, or an oil-fired unit that uses a different grade of oil solely for start-up or burner ignition, a fuel flowmeter for the start-up fuel is permitted but not required. Estimate the volume of oil combusted for each start-up or ignition either by using a fuel flowmeter or by using the dimensions of the storage container and measuring the depth of the fuel in the storage container before and after each start-up or ignition. A fuel flowmeter used solely for start-up or ignition fuel is not subject to the calibration requirements of sections 2.1.5 and 2.1.6 of this appendix. Gas combusted solely for start-up or burner ignition does not need to be measured separately. 2.1.4.2 Gas or Oil Flowmeter Used for Commercial Billing A gas or oil flowmeter used for commercial billing of natural gas or oil may be used to measure, record, and report hourly fuel flow rate. A gas or oil flowmeter used for commercial billing of natural gas or oil is not required to meet the certification requirements of section 2.1.5 of this appendix or the quality assurance requirements of section 2.1.6 of this appendix under the following circumstances: (a) The gas or oil flowmeter is used for commercial billing under a contract, provided that the company providing the gas or oil under the contract and each unit combusting the gas or oil do not have any common owners and are not owned by subsidiaries or affiliates of the same company; (b) The designated representative reports hourly records of gas or oil flow rate, heat input rate, and emissions due to combustion of natural gas or oil; (c) The designated representative also reports hourly records of heat input rate for each unit, if the gas or oil flowmeter is on a common pipe header, consistent with section 2.1.2 of this appendix; (d) The designated representative reports hourly records directly from the gas or oil flowmeter used for commercial billing if these records are the values used, without adjustment, for commercial billing, or reports hourly records using the missing data procedures of section 2.4 of this appendix if these records are not the values used, without adjustment, for commercial billing; and (e) The designated representative identifies the gas or oil flowmeter in the unit's monitoring plan. 2.1.4.3 Emergency Fuel The designated representative of a unit that is restricted by its Federal, State or local permit to combusting a particular fuel only during emergencies where the primary fuel is not available is exempt from certifying a fuel flowmeter for use during combustion of the emergency fuel. During any hour in which the emergency fuel is combusted, report the hourly heat input to be the maximum rated heat input of the unit for the fuel. Use the maximum potential sulfur content for the fuel (from Table D-6 of this appendix) and the fuel flow rate corresponding to the maximum hourly heat input to calculate the hourly SO 2 2 2.1.5 Initial Certification Requirement for all Fuel Flowmeters For the purposes of initial certification, each fuel flowmeter used to meet the requirements of this protocol shall meet a flowmeter accuracy of 2.0 percent of the upper range value (i.e. maximum fuel flow rate measurable by the flowmeter) across the range of fuel flow rate to be measured at the unit. Flowmeter accuracy may be determined under section 2.1.5.1 of this appendix for initial certification in any of the following ways (as applicable): by design (orifice, nozzle, and venturi-type flowmeters, only) or by measurement under laboratory conditions; by the manufacturer; by an independent laboratory; or by the owner or operator. Flowmeter accuracy may also be determined under section 2.1.5.2 of this appendix by in-line comparison against a reference flowmeter. 2.1.5.1 Use the procedures in the following standards to verify flowmeter accuracy or design, as appropriate to the type of flowmeter: ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi; ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters; 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) (excluding the modified flow-calculation method in part 3); Section 8, Calibration from American Gas Association Transmission Measurement Committee Report No. 7: Measurement of Gas by Turbine Meters (Second Revision, April 1996); ASME-MFC-5M-1985 (Reaffirmed 1994), Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters; ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters; ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles; ISO 8316: 1987(E) Measurement of Liquid Flow in Closed Conduits—Method by Collection of the Liquid in a Volumetric Tank; American Petroleum Institute (API) Manual of Petroleum Measurement Standards, Chapter 4—Proving Systems, Section 2—Pipe Provers (Provers Accumulating at Least 10,000 Pulses), Second Edition, March 2001, Section 3—Small Volume Provers, First Edition, July 1988, Reaffirmed October 1993, and Section 5—Master-Meter Provers, Second Edition, May 2000; American Petroleum Institute (API) Manual of Petroleum Measurement Standards, Chapter 22—Testing Protocol, Section 2—Differential Pressure Flow Measurement Devices, First Edition, August 2005; or ASME MFC-9M-1988 (Reaffirmed 2001), Measurement of Liquid Flow in Closed Conduits by Weighing Method, for all other flowmeter types (all incorporated by reference under § 75.6 of this part). The Administrator may also approve other procedures that use equipment traceable to National Institute of Standards and Technology standards. Document such procedures, the equipment used, and the accuracy of the procedures in the monitoring plan for the unit, and submit a petition signed by the designated representative under § 75.66(c). If the flowmeter accuracy exceeds 2.0 percent of the upper range value, the flowmeter does not qualify for use under this part. 2.1.5.2 (a) Alternatively, determine the flowmeter accuracy of a fuel flowmeter used for the purposes of this part by comparing it to the measured flow from a reference flowmeter which has been either designed according to the specifications of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix, or tested for accuracy during the previous 365 days, using a standard listed in section 2.1.5.1 of this appendix or other procedure approved by the Administrator under § 75.66 (all standards incorporated by reference under § 75.6). Any secondary elements, such as pressure and temperature transmitters, must be calibrated immediately prior to the comparison. Perform the comparison over a period of no more than seven consecutive unit operating days. Compare the average of three fuel flow rate readings over 20 minutes or longer for each meter at each of three different flow rate levels. The three flow rate levels shall correspond to: (1) Normal full unit operating load, (2) Normal minimum unit operating load, (3) A load point approximately equally spaced between the full and minimum unit operating loads, and (b) Calculate the flowmeter accuracy at each of the three flow levels using the following equation: Where: ACC = Flowmeter accuracy at a particular load level, as a percentage of the upper range value. R = Average of the three flow measurements of the reference flowmeter. A = Average of the three measurements of the flowmeter being tested. URV = Upper range value of fuel flowmeter being tested (i.e. maximum measurable flow). (c) Notwithstanding the requirement for calibration of the reference flowmeter within 365 days prior to an accuracy test, when an in-place reference meter or prover is used for quality assurance under section 2.1.6 of this appendix, the reference meter calibration requirement may be waived if, during the previous in-place accuracy test with that reference meter, the reference flowmeter and the flowmeter being tested agreed to within ±1.0 percent of each other at all levels tested. This exception to calibration and flowmeter accuracy testing requirements for the reference flowmeter shall apply for periods of no longer than five consecutive years (i.e., 20 consecutive calendar quarters). 2.1.5.3 If the flowmeter accuracy exceeds the specification in section 2.1.5 of this appendix, the flowmeter does not qualify for use for this appendix. Either recalibrate the flowmeter until the flowmeter accuracy is within the performance specification, or replace the flowmeter with another one that is demonstrated to meet the performance specification. Substitute for fuel flow rate using the missing data procedures in section 2.4.2 of this appendix until quality-assured fuel flow data become available. 2.1.5.4 For purposes of initial certification, when a flowmeter is tested against a reference fuel flow rate (i.e., fuel flow rate from another fuel flowmeter under section 2.1.5.2 of this appendix or flow rate from a procedure performed according to a standard incorporated by reference under section 2.1.5.1 of this appendix), report the results of flowmeter accuracy tests in a manner consistent with Table D-1. Table D-1—Table of Flowmeter Accuracy Results Test number:________ Test completion date 1 1 Reinstallation date 2 2 Unit or pipe ID: Component/System ID: Flowmeter serial number: Upper range value: Units of measure for flowmeter and reference flow readings: Measurement level (percent of URV) Run No. Time of run (HHMM) Candidate flowmeter reading Reference flow reading Percent Low (Minimum) level 1 ____ percent 3 2 3 Average Mid-level 1 ____ percent 3 2 3 Average High (Maximum) level 1 ____ percent 3 2 3 Average 1 2 3 2.1.6 Quality Assurance (a) Test the accuracy of each fuel flowmeter prior to use under this part and at least once every four fuel flowmeter QA operating quarters, as defined in § 72.2 of this chapter, thereafter. Notwithstanding these requirements, no more than 20 successive calendar quarters shall elapse after the quarter in which a fuel flowmeter was last tested for accuracy without a subsequent flowmeter accuracy test having been conducted. Test the flowmeter accuracy more frequently if required by manufacturer specifications. (b) Except for orifice-, nozzle-, and venturi-type flowmeters, perform the required flowmeter accuracy testing using the procedures in either section 2.1.5.1 or section 2.1.5.2 of this appendix. Each fuel flowmeter must meet the accuracy specification in section 2.1.5 of this appendix. (c) For orifice-, nozzle-, and venturi-type flowmeters, either perform the required flowmeter accuracy testing using the procedures in section 2.1.5.2 of this appendix or perform a transmitter accuracy test for the initial certification and once every four fuel flowmeter QA operating quarters thereafter. Perform a primary element visual inspection for the initial certification and once every 12 calendar quarters thereafter, according to the procedures in sections 2.1.6.1 through 2.1.6.4 of this appendix for periodic quality assurance. (d) Notwithstanding the requirements of this section, if the procedures of section 2.1.7 (fuel flow-to-load test) of this appendix are performed during each fuel flowmeter QA operating quarter, subsequent to a required flowmeter accuracy test or (if applicable) transmitter accuracy test and primary element inspection, those procedures may be used to meet the requirement for periodic quality assurance testing for a period of up to 20 calendar quarters from the previous accuracy test or (if applicable) transmitter accuracy test and primary element inspection. (e) When accuracy testing of the orifice, nozzle, or venturi meter is performed according to section 2.1.5.2 of this appendix, record the information displayed in Table D-1 in this section. At a minimum, record the overall accuracy results for the fuel flowmeter at the three flow rate levels specified in section 2.1.5.2 of this appendix. (f) Report the results of all fuel flowmeter accuracy tests, transmitter or transducer accuracy tests, and primary element inspections, as applicable, in the emissions report for the quarter in which the quality assurance tests are performed, using the electronic format specified by the Administrator under § 75.64. 2.1.6.1 Transmitter or Transducer Accuracy Test for Orifice-, Nozzle-, and Venturi-Type Flowmeters (a) Calibrate the differential pressure transmitter or transducer, static pressure transmitter or transducer, and temperature transmitter or transducer, as applicable, using equipment that has a current certificate of traceability to NIST standards. Check the calibration of each transmitter or transducer by comparing its readings to that of the NIST traceable equipment at least once at each of the following levels: the zero-level and at least two other upscale levels (e.g., “mid” and “high”), such that the full range of transmitter or transducer readings corresponding to normal unit operation is represented. For temperature transmitters, the zero and upscale levels may correspond to fixed reference points, such as the freezing point or boiling point of water. (b) Calculate the accuracy of each transmitter or transducer at each level tested, using the following equation: Where: ACC = Accuracy of the transmitter or transducer as a percentage of full-scale. R = Reading of the NIST traceable reference value (in milliamperes, inches of water, psi, or degrees). T = Reading of the transmitter or transducer being tested (in milliamperes, inches of water, psi, or degrees, consistent with the units of measure of the NIST traceable reference value). FS = Full-scale range of the transmitter or transducer being tested (in milliamperes, inches of water, psi, or degrees, consistent with the units of measure of the NIST traceable reference value). (c) If each transmitter or transducer meets an accuracy of 1.0 percent of its full-scale range at each level tested, the fuel flowmeter accuracy of 2.0 percent is considered to be met at all levels. If, however, one or more of the transmitters or transducers does not meet an accuracy of 1.0 percent of full-scale at a particular level, then the owner or operator may demonstrate that the fuel flowmeter meets the total accuracy specification of 2.0 percent at that level by using one of the following alternative methods. If, at a particular level, the sum of the individual accuracies of the three transducers is less than or equal to 4.0 percent, the fuel flowmeter accuracy specification of 2.0 percent is considered to be met for that level. Or, if at a particular level, the total fuel flowmeter accuracy is 2.0 percent or less, when calculated in accordance with Part 1 of American Gas Association Report No. 3, General Equations and Uncertainty Guidelines, the flowmeter accuracy requirement is considered to be met for that level. 2.1.6.2 Recordkeeping for Transmitter or Transducer Accuracy Results (a) Record the accuracy of the orifice, nozzle, or venturi meter or its individual transmitters or transducers and keep this information in a file at the site or other location suitable for inspection. Table D-2—Table of Flowmeter Transmitter or Transducer Accuracy Results Test number:________ Test completion date: ____________________ Unit or pipe ID: ____________ Flowmeter serial number: Component/System ID: Full-scale value: Units of measure: 3 Transducer/Transmitter Type (check one): ____ Differential Pressure ____ Static Pressure ____ Temperature Measurement level (percent of full-scale) Run number (if multiple runs) 2 Run time (HHMM) Transmitter/transducer input (pre-calibration) Expected transmitter/transducer output (reference) Actual transmitter/transducer output 3 Percent accuracy (percent of full-scale) Low (Minimum) level ____ percent 1 Mid-level ____ percent 1 (If tested at more than 3 levels) 2nd Mid-level ____ percent 1 (If tested at more than 3 levels) 3rd Mid-level ____ percent 1 High (Maximum) level ____ percent 1 1 2 3 2 (b)-(c) [Reserved] 2.1.6.3 Failure of Transducer(s) or Transmitter(s) If, during a transmitter or transducer accuracy test conducted according to section 2.1.6.1 of this appendix, the flowmeter accuracy specification of 2.0 percent is not met at any of the levels tested, repair or replace transmitter(s) or transducer(s) as necessary until the flowmeter accuracy specification has been achieved at all levels. (Note that only transmitters or transducers which are repaired or replaced need to be re-tested; however, the re-testing is required at all three measurement levels, to ensure that the flowmeter accuracy specification is met at each level). The fuel flowmeter is “out-of-control” and data from the flowmeter are considered invalid, beginning with the date and hour of the failed accuracy test and continuing until the date and hour of completion of a successful transmitter or transducer accuracy test at all levels. In addition, if, during normal operation of the fuel flowmeter, one or more transmitters or transducers malfunction, data from the fuel flowmeter shall be considered invalid from the hour of the transmitter or transducer failure until the hour of completion of a successful 3-level transmitter or transducer accuracy test. During fuel flowmeter out-of-control periods, provide data from another fuel flowmeter that meets the requirements of § 75.20(d) and section 2.1.5 of this appendix, or substitute for fuel flow rate using the missing data procedures in section 2.4.2 of this appendix. Record and report test data and results, consistent with sections 2.1.6.1 and 2.1.6.2 of this appendix and § 75.59. 2.1.6.4 Primary Element Inspection (a) Conduct a visual inspection of the orifice, nozzle, or venturi meter at least once every twelve calendar quarters. Notwithstanding this requirement, the procedures of section 2.1.7 of this appendix may be used to reduce the inspection frequency of the orifice, nozzle, or venturi meter to at least once every twenty calendar quarters. The inspection may be performed using a baroscope. If the visual inspection is failed (if the orifice, nozzle, or venturi meter has become damaged or corroded), then: (1) Replace the primary element with another primary element meeting the requirements of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both standards incorporated by reference under § 75.6). If the primary element size is changed, also calibrate the transmitters or transducers, consistent with the new primary element size; (2) Replace the primary element with another primary element, and demonstrate that the overall flowmeter accuracy meets the accuracy specification in section 2.1.5 of this appendix, using the procedures of section 2.1.5.2 of this appendix; or (3) Restore the damaged or corroded primary element to “as new” condition; determine the overall accuracy of the flowmeter, using either the specifications of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both standards incorporated by reference under § 75.6); and retest the transmitters or transducers prior to providing quality-assured data from the flowmeter. (b) Data from the fuel flowmeter are considered invalid, beginning with the date and hour of a failed visual inspection and continuing until the date and hour when: (1) The damaged or corroded primary element is replaced with another primary element meeting the requirements of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both standards incorporated by reference under § 75.6) and, if applicable, the transmitters have been successfully recalibrated; (2) The damaged or corroded primary element is replaced, and the overall accuracy of the flowmeter is demonstrated to meet the accuracy specification in section 2.1.5 of this appendix, using the procedures of section 2.1.5.2 of this appendix; or (3) The restored primary element is installed to meet the requirements of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both standards incorporated by reference under § 75.6) and its transmitters or transducers are retested to meet the accuracy specification in section 2.1.6.1 of this appendix. (c) During each period of invalid fuel flowmeter data described in paragraph (b) of this section, provide data from another fuel flowmeter that meets the requirements of § 75.20(d) and section 2.1.5 of this appendix, or substitute for fuel flow rate using the missing data procedures in section 2.4.2 of this appendix. 2.1.7 Fuel Flow-to-Load Quality Assurance Testing for Certified Fuel Flowmeters The procedures of this section may be used as an optional supplement to the quality assurance procedures in section 2.1.5.1, 2.1.5.2, 2.1.6.1, or 2.1.6.4 of this appendix when conducting periodic quality assurance testing of a certified fuel flowmeter. Note, however, that these procedures may not be used unless the 168-hour baseline data requirement of section 2.1.7.1 of this appendix has been met. If, following a flowmeter accuracy test or (if applicable) a flowmeter transmitter test and primary element inspection, the procedures of this section are performed during each subsequent fuel flowmeter QA operating quarter, as defined in § 72.2 of this chapter (excluding the quarter(s) in which the baseline data are collected), then these procedures may be used to meet the requirement for periodic quality assurance for a period of up to 20 calendar quarters from the previous periodic quality assurance procedure(s) performed according to sections 2.1.5.1, 2.1.5.2, or 2.1.6.1 through 2.1.6.4 of this appendix. The procedures of this section are not required for any quarter in which a flowmeter accuracy test or (if applicable) a transmitter accuracy test and a primary element inspection, are conducted. Notwithstanding the requirements of § 75.57(a), when using the procedures of this section, keep records of the test data and results from the previous flowmeter accuracy test under section 2.1.5.1 or 2.1.5.2 of this appendix, records of the test data and results from the previous transmitter or transducer accuracy test under section 2.1.6.1 of this appendix for orifice-, nozzle-, and venturi-type fuel flowmeters, and records of the previous visual inspection of the primary element required under section 2.1.6.4 of this appendix for orifice-, nozzle-, and venturi-type fuel flowmeters until the next flowmeter accuracy test, transmitter accuracy test, or visual inspection is performed, even if the previous flowmeter accuracy test, transmitter accuracy test, or visual inspection was performed more than three years previously. 2.1.7.1 Baseline Flow Rate-to-Load Ratio or Heat Input-to-Load Ratio (a) Determine R base where: R base Q base L avg (b) In Equation D-1b, for a fuel flowmeter installed on a common pipe header, L avg base base (c) Alternatively, a baseline value of the gross heat rate (GHR) may be determined in lieu of R base base Where: (GHR) base (Heat Input) avg L avg (d) Report the current value of R base base (e) If a unit co-fires different fuels ( e.g., base base avg 2.1.7.2 Data Preparation and Analysis (a) Evaluate the fuel flow rate-to-load ratio (or GHR) for each fuel flowmeter QA operating quarter, as defined in § 72.2 of this chapter. At the end of each fuel flowmeter QA operating quarter, use Equation D-1d in this appendix to calculate R h h where: R h Q h L h (b) For a fuel flowmeter installed on a common pipe header, Lh shall be the sum of the hourly operating loads of all units that receive fuel through the common pipe header. For a unit that receives the same type of fuel through multiple pipes, Q h h (c) Alternatively, calculate the hourly gross heat rates (GHR) in lieu of the hourly flow-to-load ratios. If this option is selected, calculate each hourly GHR value as follows: Where: (GHR) h (Heat Input) h L h (d) Evaluate the calculated flow rate-to-load ratios (or gross heat rates) as follows. (1) Perform a separate data analysis for each fuel flowmeter system following the procedures of this section. Base each analysis on a minimum of 168 hours of data. If, for a particular fuel flowmeter system, fewer than 168 hourly flow-to-load ratios (or GHR values) are available, or, if the baseline data collection period is still in progress at the end of the quarter and fewer than four calendar quarters have elapsed since the quarter in which the last successful fuel flowmeter system accuracy test was performed, a flow-to-load (or GHR) evaluation is not required for that flowmeter system for that calendar quarter. A one-quarter extension of the deadline for the next fuel flowmeter system accuracy test may be claimed for a quarter in which there is insufficient hourly data available to analyze or a quarter that ends with the baseline data collection period still in progress. (2) For a unit that normally co-fires different types of fuel (e.g., oil and natural gas), include the contribution of each type of fuel in the value of (Heat Input) h (e) For each hourly flow-to-load ratio or GHR value, calculate the percentage difference (percent D h Where: %D h R h R base (f) Consistently use R base h base h (g) Next, determine the arithmetic average of all of the hourly percent difference (percent D h Where: E f %D h q = Number of hours used in fuel flow-to-load (or GHR) evaluation. (h) When the quarterly average load value used in the data analysis is greater than 50 MWe (or 500 klb steam per hour), the results of a quarterly fuel flow rate-to-load (or GHR) evaluation are acceptable and no further action is required if the quarterly average percentage difference (E f f 2.1.7.3 Optional Data Exclusions (a) If E f h h (1) For units that do not normally co-fire fuels, any hour in which the unit combusted another fuel in addition to the fuel measured by the fuel flowmeter being tested; or (2) Any hour for which the load differed by more than ±15.0 percent from the load during either the preceding hour or the subsequent hour; or (3) For units that normally co-fire different fuels, any hour in which the unit burned only one type of fuel; or (4) Any hour for which the unit load was in the lower 25.0 percent of the range of operation, as defined in section 6.5.2.1 of appendix A to this part (unless operation in the lower 25.0 percent of the range is considered normal for the unit). (b) After identifying and excluding all non-representative hourly fuel flow-to-load ratios or GHR values, analyze the quarterly fuel flow rate-to-load data a second time. If fewer than 168 hourly fuel flow-to-load ratio or GHR values remain after the allowable data exclusions, a fuel flow-to-load ratio or GHR analysis is not required for that quarter, and a one-quarter extension of the fuel flowmeter accuracy test deadline may be claimed. 2.1.7.4 Consequences of Failed Fuel Flow-to-Load Ratio Test (a) If E f f (b) Substitute for fuel flow rate, for any hour when that fuel is combusted, using the missing data procedures in section 2.4.2 of this appendix, beginning with the first hour of the calendar quarter following the quarter for which E f base base base base 2.1.7.5 Test Results Report the results of each quarterly flow rate-to-load (or GHR) evaluation, as determined from Equation D-1g, in the electronic quarterly report required under § 75.64. Table D-3 is provided as a reference on the type of information to be recorded under § 75.59 and reported under § 75.64. Table D-3—Baseline Information and Test Results For Fuel Flow-to-Load Test 2.2 Oil Sampling and Analysis Perform sampling and analysis of oil to determine the following fuel properties for each type of oil combusted by a unit: percentage of sulfur by weight in the oil; gross calorific value (GCV) of the oil; and, if necessary, the density of the oil. Use the sulfur content, density, and gross calorific value, determined under the provisions of this section, to calculate SO 2 2.2.1 When combusting oil, use one of the following methods to sample the oil (see Table D-4): sample from the storage tank for the unit after each addition of oil to the storage tank, in accordance with section 2.2.4.2 of this appendix; or sample from the fuel lot in the shipment tank or container upon receipt of each oil delivery or from the fuel lot in the oil supplier's storage container, in accordance with section 2.2.4.3 of this appendix; or use the flow proportional sampling methodology in section 2.2.3 of this appendix; or use the daily manual sampling methodology in section 2.2.4.1 of this appendix. For purposes of this appendix, a fuel lot of oil is the mass or volume of product oil from one source (supplier or pretreatment facility), intended as one shipment or delivery (e.g., ship load, barge load, group of trucks, discrete purchase of diesel fuel through pipeline, etc.). A storage tank is a container at a plant holding oil that is actually combusted by the unit, such that no blending of any other fuel with the fuel in the storage tank occurs from the time that the fuel lot is transferred to the storage tank to the time when the fuel is combusted in the unit. 2.2.2 [Reserved] 2.2.3 Flow Proportional Sampling Conduct flow proportional oil sampling or continuous drip oil sampling in accordance with ASTM D4177-95 (Reapproved 2000), “Standard Practice for Automatic Sampling of Petroleum and Petroleum Products” (incorporated by reference under § 75.6), every day the unit is combusting oil. Extract oil at least once every hour and blend into a composite sample. The sample compositing period may not exceed 7 calendar days (168 hrs). Use the actual sulfur content (and where density data are required, the actual density) from the composite sample to calculate the hourly SO 2 2.2.4 Manual Sampling 2.2.4.1 Daily Samples Representative oil samples may be taken from the storage tank or fuel flow line manually every day that the unit combusts oil according to ASTM ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual Sampling of Petroleum and Petroleum Products (incorporated by reference under § 75.6 of this part). Use either the actual daily sulfur content or the highest fuel sulfur content recorded at that unit from the most recent 30 daily samples for the purpose of calculating SO 2 2.2.4.2 Sampling From a Unit's Storage Tank Take a manual sample after each addition of oil to the storage tank. Do not blend additional fuel with the sampled fuel prior to combustion. Sample according to the single tank composite sampling procedure or all-levels sampling procedure in ASTM ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual Sampling of Petroleum and Petroleum Products (incorporated by reference under § 75.6 of this part). Use the sulfur content and GCV value (and where required, the density) of either the most recent sample or one of the conservative assumed values described in section 2.2.4.3(c) of this appendix to calculate SO 2 (a) The most recent oil sample taken or (b) One of the conservative assumed values described in section 2.2.4.3(c) of this appendix. Follow the applicable provisions in section 2.2.4.3(d) of this appendix, regarding the use of assumed values. 2.2.4.3 Sampling From Each Delivery (a) Alternatively, an oil sample may be taken from— (1) The shipment tank or container upon receipt of each lot of fuel oil or (2) The supplier's storage container which holds the lot of fuel oil. (Note: a supplier need only sample the storage container once for sulfur content, GCV and, where required, the density so long as the fuel sulfur content and GCV do not change and no fuel is added to the supplier's storage container.) (b) For the purpose of this section, a lot is defined as a shipment or delivery (e.g., ship load, barge load, group of trucks, discrete purchase of diesel fuel through a pipeline, etc.) of a single fuel. (c) Oil sampling may be performed either by the owner or operator of an affected unit, an outside laboratory, or a fuel supplier, provided that samples are representative and that sampling is performed according to either the single tank composite sampling procedure or the all-levels sampling procedure in ASTM ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual Sampling of Petroleum and Petroleum Products (incorporated by reference under § 75.6 of this part). Except as otherwise provided in this section, calculate SO 2 (1) The highest value sampled during the previous calendar year (this option is allowed for any consistent fuel which comes from a single source whether or not the fuel is supplied under a contractual agreement) or (2) The maximum value indicated in the contract with the fuel supplier. Continue to use this assumed contract value unless and until the actual sampled sulfur content, density, or gross calorific value of a delivery exceeds the assumed value. (d) Continue using the assumed value(s), so long as the sample results do not exceed the assumed value(s). However, if the actual sampled sulfur content, gross calorific value, or density of an oil sample is greater than the assumed value for that parameter, then, consistent with section 2.3.7 of this appendix, begin to use the actual sampled value for sulfur content, gross calorific value, or density of fuel to calculate SO2 mass emission rate or heat input rate. Consider the sampled value to be the new assumed sulfur content, gross calorific value, or density. Continue using this new assumed value to calculate SO2 mass emission rate or heat input rate unless and until: it is superseded by a higher value from an oil sample; or (if applicable) it is superseded by a new contract in which case the new contract value becomes the assumed value at the time the fuel specified under the new contract begins to be combusted in the unit; or (if applicable) both the calendar year in which the sampled value exceeded the assumed value and the subsequent calendar year have elapsed. 2.2.5 For each oil sample that is taken on-site at the affected facility, split and label the sample and maintain a portion (at least 200 cc) of it throughout the calendar year and in all cases for not less than 90 calendar days after the end of the calendar year allowance accounting period. This requirement does not apply to oil samples taken from the fuel supplier's storage container, as described in section 2.2.4.3 of this appendix. Analyze oil samples for percent sulfur content by weight in accordance with ASTM D129-00, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), ASTM D1552-01, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), ASTM D2622-98, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence Spectrometry, ASTM D4294-98, Standard Test Method for Sulfur in Petroleum and Petroleum Products by Energy-Dispersive X-ray Fluorescence Spectrometry, or ASTM D5453-06, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and Engine Oil by Ultraviolet Fluorescence (all incorporated by reference under § 75.6 of this part). Alternatively, the oil samples may be analyzed for percent sulfur by any consensus standard method prescribed for the affected unit under part 60 of this chapter. 2.2.6 Where the flowmeter records volumetric flow rate rather than mass flow rate, analyze oil samples to determine the density or specific gravity of the oil. Determine the density or specific gravity of the oil sample in accordance with ASTM D287-92 (Reapproved 2000), Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), ASTM D1217-93 (Reapproved 1998), Standard Test Method for Density and Relative Density (Specific Gravity) of Liquids by Bingham Pycnometer, ASTM D1481-93 (Reapproved 1997), Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Lipkin Bicapillary Pycnometer, ASTM D1480-93 (Reapproved 1997), Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Bingham Pycnometer, ASTM D1298-99, Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, or ASTM D4052-96 (Reapproved 2002), Standard Test Method for Density and Relative Density of Liquids by Digital Density Meter (all incorporated by reference under § 75.6 of this part). Alternatively, the oil samples may be analyzed for density or specific gravity by any consensus standard method prescribed for the affected unit under part 60 of this chapter. 2.2.7 Analyze oil samples to determine the heat content of the fuel. Determine oil heat content in accordance with ASTM D240-00, ASTM D4809-00, ASTM D5865-01a, or D5865-10 (all incorporated by reference under § 75.6) or any other procedures listed in section 5.5 of appendix F of this part. Alternatively, the oil samples may be analyzed for heat content by any consensus standard method prescribed for the affected unit under part 60 of this chapter. 2.2.8 Results from the oil sample analysis must be available no later than thirty calendar days after the sample is composited or taken. However, during an audit, the Administrator may require that the results of the analysis be available as soon as practicable, and no later than 5 business days after receipt of a request from the Administrator. 2.3 SO 2 (a) Account for the hourly SO 2 (b) The procedures in sections 2.3.1 and 2.3.2 of this appendix, respectively, may be used to determine SO 2 2 2 2.3.1 Pipeline Natural Gas Combustion The owner or operator may determine the SO 2 2.3.1.1 SO 2 For a fuel that meets the definition of pipeline natural gas under § 72.2 of this chapter, the owner or operator may determine the SO 2 2 2.3.1.2 Hourly Heat Input Rate Calculate hourly heat input rate, in mmBtu/hr, for a unit combusting pipeline natural gas, using the procedures of section 3.4.1 of this appendix. Use the measured fuel flow rate from section 2.1 of this appendix and the gross calorific value from section 2.3.4.1 of this appendix in the calculations. 2.3.1.3 SO 2 For pipeline natural gas combustion, calculate the SO2 mass emission rate, in lb/hr, using Equation D-5 in section 3.3.2 of this appendix (when the default SO 2 2 2 2.3.1.4 Documentation that a Fuel is Pipeline Natural Gas (a) A fuel may initially qualify as pipeline natural gas, if information is provided in the monitoring plan required under § 75.53, demonstrating that the definition of pipeline natural gas in § 72.2 of this chapter has been met. The information must demonstrate that the fuel meets either the percent methane or GCV requirement and has a total sulfur content of 0.5 grains/100scf or less. The demonstration must be made using one of the following sources of information: (1) The gas quality characteristics specified by a purchase contract, tariff sheet, or by a pipeline transportation contract; or (2) Historical fuel sampling data for the previous 12 months, documenting the total sulfur content of the fuel and the GCV and/or percentage by volume of methane. The results of all sample analyses obtained by or provided to the owner or operator in the previous 12 months shall be used in the demonstration, and each sample result must meet the definition of pipeline natural gas in § 72.2 of this chapter, except where the results of at least 100 daily (or more frequent) total sulfur samples are provided by the fuel supplier. In that case you may opt to convert these data to monthly averages and then if, for each month, the average total sulfur content is 0.5 grains/100 scf or less, and if the GCV or percent methane requirement is also met, the fuel qualifies as pipeline natural gas. Alternatively, the fuel qualifies as pipeline natural gas if ≥98 percent of the 100 (or more) samples have a total sulfur content of 0.5 grains/100 scf or less and if the GCV or percent methane requirement is also met; or (3) If the requirements of paragraphs (a)(1) and (a)(2) of this section cannot be met, a fuel may initially qualify as pipeline natural gas if at least one representative sample of the fuel is obtained and analyzed for total sulfur content and for either the gross calorific value (GCV) or percent methane, and the results of the sample analysis show that the fuel meets the definition of pipeline natural gas in § 72.2 of this chapter. Use the sampling methods specified in sections 2.3.3.1.2 and 2.3.4 of this appendix. The required fuel sample may be obtained and analyzed by the owner or operator, by an independent laboratory, or by the fuel supplier. If multiple samples are taken, each sample must meet the definition of pipeline natural gas in § 72.2 of this chapter. (b) If the results of the fuel sampling under paragraph (a)(2) or (a)(3) of this section show that the fuel does not meet the definition of pipeline natural gas in § 72.2 of this chapter, but those results are believed to be anomalous, the owner or operator may document the reasons for believing this in the monitoring plan for the unit, and may immediately perform additional sampling. In such cases, a minimum of three additional samples must be obtained and analyzed, and the results of each sample analysis must meet the definition of pipeline natural gas. (c) If several affected units are supplied by a common source of gaseous fuel, a single sampling result may be applied to all of the units and it is not necessary to obtain a separate sample for each unit, provided that the composition of the fuel is not altered by blending or mixing it with other gaseous fuel(s) when it is transported from the sampling location to the affected units. For the purposes of this paragraph, the term “other gaseous fuel(s)” excludes compounds such as mercaptans when they are added in trace quantities for safety reasons. (d) If the results of fuel sampling and analysis under paragraph (a)(2), (a)(3), or (b) of this section show that the fuel does not qualify as pipeline natural gas, proceed as follows: (1) If the fuel still qualifies as natural gas under section 2.3.2.4 of this appendix, re-classify the fuel as natural gas and determine the appropriate default SO 2 (2) If the fuel does not qualify either as pipeline natural gas or natural gas, re-classify the fuel as “other gaseous fuel” and implement the procedures of section 2.3.3 of this appendix, within 180 days of the end of the quarter in which the disqualifying sample was taken. In addition, the owner or operator shall use Equation D-1h in this appendix to calculate a default SO 2 2 (e) If a fuel qualifies as pipeline natural gas based on the specifications in a fuel contract or tariff sheet, no additional, on-going sampling of the fuel's total sulfur content is required, provided that the contract or tariff sheet is current, valid and representative of the fuel combusted in the unit. If the fuel qualifies as pipeline natural gas based on fuel sampling and analysis, on-going sampling of the fuel's sulfur content is required annually and whenever the fuel supply source changes. For the purposes of this paragraph (e), sampling “annually” means that at least one sample is taken in each calendar year. If the results of at least 100 daily (or more frequent) total sulfur samples have been provided by the fuel supplier since the last annual assessment of the fuel's sulfur content, the data may be used as follows to satisfy the annual sampling requirement for the current year. If this option is chosen, all of the data provided by the fuel supplier shall be used. First, convert the data to monthly averages. Then, if, for each month, the average total sulfur content is 0.5 grains/100 scf or less, and if the GCV or percent methane requirement is also met, the fuel qualifies as pipeline natural gas. Alternatively, the fuel qualifies as pipeline natural gas if the analysis of the 100 (or more) total sulfur samples since the last annual assessment shows that ≥98 percent of the samples have a total sulfur content of 0.5 grains/100 scf or less and if the GCV or percent methane requirement is also met. The effective date of the annual total sulfur sampling requirement is January 1, 2003. (f) On-going sampling of the GCV of the pipeline natural gas is required under section 2.3.4.1 of this appendix. (g) For units that are required to monitor and report NO X 2.3.2 Natural Gas Combustion The owner or operator may determine the SO 2 2.3.2.1 SO 2 The owner or operator may account for SO 2 2 2 2.3.2.1.1 In lieu of daily sampling of the sulfur content of the natural gas, the owner or operator may either use the total sulfur content specified in a contract or tariff sheet as the SO 2 2 2 Where: ER = Default SO 2 S total GCV = Gross calorific value of the natural gas, Btu/100scf. 7000 = Conversion of grains/100scf to lb/100scf. 2.0 = Ratio of lb SO 2 10 6 2.3.2.1.2 [Reserved] 2.3.2.2 Hourly Heat Input Rate Calculate hourly heat input rate for natural gas combustion, in mmBtu/hr, using the procedures in section 3.4.1 of this appendix. Use the measured fuel flow rate from section 2.1 of this appendix and the gross calorific value from section 2.3.4.2 of this appendix in the calculations. 2.3.2.3 SO 2 For natural gas combustion, calculate the SO 2 2 2 2 2.3.2.4 Documentation that a Fuel Is Natural Gas (a) A fuel may initially qualify as natural gas, if information is provided in the monitoring plan required under § 75.53, demonstrating that the definition of natural gas in § 72.2 of this chapter has been met. The information must demonstrate that the fuel meets either the percent methane or GCV requirement and has a total sulfur content of 20.0 grains/100 scf or less. This demonstration must be made using one of the following sources of information: (1) The gas quality characteristics specified by a purchase contract, tariff sheet, or by a transportation contract; or (2) Historical fuel sampling data for the previous 12 months, documenting the total sulfur content of the fuel and the GCV and/or percentage by volume of methane. The results of all sample analyses obtained by or provided to the owner or operator in the previous 12 months shall be used in the demonstration, and each sample result must meet the definition of natural gas in § 72.2 of this chapter; or (3) If the requirements of paragraphs (a)(1) and (a)(2) of this section cannot be met, a fuel may initially qualify as natural gas if at least one representative sample of the fuel is obtained and analyzed for total sulfur content and for either the gross calorific value (GCV) or percent methane, and the results of the sample analysis show that the fuel meets the definition of natural gas in § 72.2 of this chapter. Use the sampling methods specified in sections 2.3.3.1.2 and 2.3.4 of this appendix. The required fuel sample may be obtained and analyzed by the owner or operator, by an independent laboratory, or by the fuel supplier. If multiple samples are taken, each sample must meet the definition of natural gas in § 72.2 of this chapter. (b) If the results of the fuel sampling under paragraph (a)(2) or (a)(3) of this section show that the fuel does not meet the definition of natural gas in § 72.2 of this chapter, but those results are believed to be anomalous, the owner or operator may document the reasons for believing this in the monitoring plan for the unit, and may immediately perform additional sampling. In such cases, a minimum of three additional samples must be obtained and analyzed, and the results of each sample analysis must meet the definition of natural gas. (c) If several affected units are supplied by a common source of gaseous fuel, a single sampling result may be applied to all of the units and it is not necessary to obtain a separate sample for each unit, provided that the composition of the fuel is not altered by blending or mixing it with other gaseous fuel(s) when it is transported from the sampling location to the affected units. For the purposes of this paragraph, the term “other gaseous fuel(s)” excludes compounds such as mercaptans when they are added in trace quantities for safety reasons. (d) If the results of fuel sampling and analysis under paragraph (a)(2), (a)(3), or (b) of this section show that the fuel does not qualify as natural gas, the owner or operator shall re-classify the fuel as “other gaseous fuel” and shall implement the procedures of section 2.3.3 of this appendix, within 180 days of the end of the quarter in which the disqualifying sample was taken. In addition, the owner or operator shall use Equation D-1h in this appendix to calculate a default SO 2 2 (e) If a fuel qualifies as natural gas based on the specifications in a fuel contract or tariff sheet, no additional, on-going sampling of the fuel's total sulfur content is required, provided that the contract or tariff sheet is current, valid and representative of the fuel combusted in the unit. If the fuel qualifies as natural gas based on fuel sampling and analysis, the owner or operator shall sample the fuel for total sulfur content at least annually and when the fuel supply source changes. For the purposes of this paragraph, (e), sampling “annually” means that at least one sample is taken in each calendar year. The effective date of the annual total sulfur sampling requirement is January 1, 2003. (f) On-going sampling of the GCV of the natural gas is required under section 2.3.4.2 of this appendix. (g) For units that are required to monitor and report NO X 2.3.3 SO 2 The owner or operator of a unit may determine SO 2 2.3.3.1 Sulfur Content Determination 2.3.3.1.1 Analyze the total sulfur content of the gaseous fuel in grains/100 scf, at the frequency specified in Table D-5 of this appendix. That is: for fuel delivered in discrete shipments or lots, sample each shipment or lot. For fuel transmitted by pipeline, sample hourly unless a demonstration is provided under section 2.3.6 of this appendix showing that the gaseous fuel qualifies for less frequent ( i.e., X 2.3.3.1.2 Use one of the following methods when using manual sampling (as applicable to the type of gas combusted) to determine the sulfur content of the fuel: ASTM D1072-06, Standard Test Method for Total Sulfur in Fuel Gases by Combustion and Barium Chloride Titration, ASTM D4468-85 (Reapproved 2006), Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, ASTM D5504-01, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence, ASTM D6667-04, Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, or ASTM D3246-96, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, (all incorporated by reference under § 75.6 of this part). Alternatively, the gas samples may be analyzed for percent sulfur by any consensus standard method prescribed for the affected unit under part 60 of this chapter. 2.3.3.1.3 The sampling and analysis of daily manual samples may be performed by the owner or operator, an outside laboratory, or the gas supplier. If hourly sampling with a gas chromatograph is required, or a source chooses to use an online gas chromatograph to determine daily fuel sulfur content, the owner or operator shall develop and implement a program to quality assure the data from the gas chromatograph, in accordance with the manufacturer's recommended procedures. The quality assurance procedures shall be kept on-site, in a form suitable for inspection. 2.3.3.1.4 Results of all sample analyses must be available no later than thirty calendar days after the sample is taken. 2.3.3.2 SO 2 Calculate the SO 2 2 2 2 2 2.3.3.3 Hourly Heat Input Rate Calculate the hourly heat input rate for combustion of the gaseous fuel, using the provisions in section 3.4.1 of this appendix. Use the measured fuel flow rate from section 2.1 of this appendix and the gross calorific value from section 2.3.4.3 of this appendix in the calculations. 2.3.4 Gross Calorific Values for Gaseous Fuels Determine the GCV of each gaseous fuel at the frequency specified in this section, using one of the following methods: ASTM D1826-94 (Reapproved 1998), ASTM D3588-98, ASTM D4891-89 (Reapproved 2006), GPA Standard 2172-96, Calculation of Gross Heating Value, Relative Density and Compressibility Factor for Natural Gas Mixtures from Compositional Analysis, or GPA Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (all incorporated by reference under § 75.6 of this part). Use the appropriate GCV value, as specified in section 2.3.4.1, 2.3.4.2, or 2.3.4.3 of this appendix, in the calculation of unit hourly heat input rates. Alternatively, the gas samples may be analyzed for heat content by any consensus standard method prescribed for the affected unit under part 60 of this chapter. 2.3.4.1 GCV of Pipeline Natural Gas Determine the GCV of fuel that is pipeline natural gas, as defined in § 72.2 of this chapter, at least once per calendar month. For GCV used in calculations use the specifications in Table D-5: either the value from the most recent monthly sample, the highest value specified in a contract or tariff sheet, or the highest value from the previous year. The fuel GCV value from the most recent monthly sample shall be used for any month in which that value is higher than a contract limit. If a unit combusts pipeline natural gas for less than 48 hours during a calendar month, the sampling and analysis requirement for GCV is waived for that calendar month. The preceding waiver is limited by the condition that at least one analysis for GCV must be performed for each quarter the unit operates for any amount of time. If multiple GCV samples are taken and analyzed in a particular month, the GCV values from all samples shall be averaged arithmetically to obtain the monthly GCV. Then, apply the monthly average GCV value as described in paragraph (c) in section 2.3.7 of this appendix. 2.3.4.2 GCV of Natural Gas Determine the GCV of fuel that is natural gas, as defined in § 72.2 of this chapter, on a monthly basis, in the same manner as described for pipeline natural gas in section 2.3.4.1 of this appendix. 2.3.4.3 GCV of Other Gaseous Fuels For gaseous fuels other than natural gas or pipeline natural gas, determine the GCV as specified in section 2.3.4.3.1, 2.3.4.3.2 or 2.3.4.3.3, as applicable. For reporting purposes, apply the results of the required periodic GCV samples in accordance with the provisions of section 2.3.7 of this appendix. 2.3.4.3.1 For a gaseous fuel that is delivered in discrete shipments or lots, determine the GCV for each shipment or lot. The determination may be made by sampling each delivery or by sampling the supply tank after each delivery. For sampling of each delivery, use the highest GCV in the previous year's samples. For sampling from the tank after each delivery, use either the most recent GCV sample, the maximum GCV specified in the fuel contract or tariff sheet, or the highest GCV from the previous year's samples. 2.3.4.3.2 For any gaseous fuel that does not qualify as pipeline natural gas or natural gas, which is not delivered in shipments or lots, and for which the owner or operator performs the 720 hour test under section 2.3.5 of this appendix, if the results of the test demonstrate that the gaseous fuel has a low GCV variability, determine the GCV at least monthly (as described in section 2.3.4.1 of this appendix). In calculations of hourly heat input for a unit, use either the most recent monthly sample, the maximum GCV specified in the fuel contract or tariff sheet, or the highest fuel GCV from the previous year's samples. 2.3.4.3.3 For any other gaseous fuel, determine the GCV at least daily and use the actual fuel GCV in calculations of unit hourly heat input. If an online gas chromatograph or on-line calorimeter is used to determine fuel GCV each day, the owner or operator shall develop and implement a program to quality assure the data from the gas chromatograph or on-line calorimeter, in accordance with the manufacturer's recommended procedures. The quality assurance procedures shall be kept on-site, in a form suitable for inspection. 2.3.5 Demonstration of Fuel GCV Variability (a) This optional demonstration may be made for any fuel which does not qualify as pipeline natural gas or natural gas, and is not delivered only in shipments or lots. The demonstration data may be used to show that monthly sampling of the GCV of the gaseous fuel or blend is sufficient, in lieu of daily GCV sampling. (b) To make this demonstration, proceed as follows. Provide a minimum of 720 hours of data, indicating the GCV of the gaseous fuel or blend (in Btu/100 scf). The demonstration data shall be obtained using either: hourly sampling and analysis using the methods in section 2.3.4 to determine GCV of the fuel; an on-line gas chromatograph capable of determining fuel GCV on an hourly basis; or an on-line calorimeter. For gaseous fuel produced by a variable process, the data shall be representative of and include all process operating conditions including seasonal and yearly variations in process which may affect fuel GCV. (c) The data shall be reduced to hourly averages. The mean GCV value and the standard deviation from the mean shall be calculated from the hourly averages. Specifically, the gaseous fuel is considered to have a low GCV variability, and monthly gas sampling for GCV may be used, if the mean value of the GCV multiplied by 1.075 is greater than the sum of the mean value and one standard deviation. If the gaseous fuel or blend does not meet this requirement, then daily fuel sampling and analysis for GCV, using manual sampling, a gas chromatograph or an on-line calorimeter is required. 2.3.6 Demonstration of Fuel Sulfur Variability (a) This demonstration may be made for any fuel which does not qualify as pipeline natural gas or natural gas, and is not delivered only in shipments or lots. The results of the demonstration may be used to show that daily sampling for sulfur in the fuel is sufficient, rather than hourly sampling. The procedures in this section may also be used to demonstrate that a particular gaseous fuel qualifies to use a default SO 2 2 (b) If the data are collected with an on-line GC, reduce the data to hourly average values of the total sulfur content of the fuel. If manual hourly sampling is used, the results of each hourly sample analysis shall be the total sulfur value for that hour. Express all hourly average values of total sulfur content in units of grains/100 scf. Use all of the hourly average values of total sulfur content in grains/100 scf to calculate the mean value and the standard deviation. Also determine the 90th percentile and maximum hourly values of the total sulfur content for the data set. If the standard deviation of the hourly values from the mean does not exceed 5.0 grains/100 scf, the fuel has a low sulfur variability. If the standard deviation exceeds 5.0 grains/100 scf, the fuel has a high sulfur variability. Based on the results of this determination, establish the required sampling frequency and SO 2 (1) If the gaseous fuel has a low sulfur variability (irrespective of the total sulfur content), the owner or operator may either perform daily sampling of the fuel's total sulfur content using manual sampling or a GC, or may report hourly SO 2 2 (2) If the gaseous fuel has a high sulfur variability, but the maximum hourly value of the total sulfur content does not exceed 20 grains/100 scf, the owner or operator may either perform hourly sampling of the fuel's total sulfur content using an on-line GC, or may report hourly SO 2 2 (3) If the gaseous fuel has a high sulfur variability and the maximum hourly value of the total sulfur content exceeds 20 grains/100 scf, the owner or operator shall perform hourly sampling of the fuel's total sulfur content, using an on-line GC. (4) Any gaseous fuel under paragraph (b)(1) or (b)(2) of this section, for which the owner or operator elects to use a default SO 2 2.3.7 Application of Fuel Sampling Results For reporting purposes, apply the results of the required periodic fuel samples described in Tables D-4 and D-5 of this appendix as follows. Use Equation D-1h to recalculate the SO 2 (a) For daily samples of total sulfur content or GCV: (1) If the actual value is to be used in the calculations, apply the results of each daily sample to all hours in the day on which the sample is taken; or (2) If the highest value in the previous 30 daily samples is to be used in the calculations, apply that value to all hours in the current day. If, for a particular unit, fewer than 30 daily samples have been collected, use the highest value from all available samples until 30 days of historical sampling results have been obtained. (b) For annual samples of total sulfur content: (1) For pipeline natural gas, use the results of annual sample analyses in the calculations only if the results exceed 0.5 grains/100 scf. In that case, if the fuel still qualifies as natural gas, follow the procedures in paragraph (b)(2) of this section. If the fuel does not qualify as natural gas, the owner or operator shall implement the procedures in section 2.3.3 of this appendix, in the time frame specified in sections 2.3.1.4(d) and 2.3.2.4(d) of this appendix; (2) For natural gas, if only one sample is taken, apply the results beginning at the date on which the sample was taken. If multiple samples are taken and averaged, apply the results beginning at the date on which the last sample used in the annual assessment was taken; (3) For other gaseous fuels with an annual sampling requirement under section 2.3.6(b)(4) of this appendix, use the sample results in the calculations only if the results exceed the 90th percentile value or maximum value (as applicable) from the 720-hour demonstration of fuel sulfur content and variability under section 2.3.6 of this appendix. (c) For monthly samples of the fuel GCV: (1) If the actual monthly value is to be used in the calculations and only one sample is taken, apply the results starting from the date on which the sample was taken. If multiple samples are taken and averaged, apply the monthly average GCV value to the entire month; or (2) If an assumed value (contract maximum or highest value from previous year's samples) is to be used in the calculations, apply the assumed value to all hours in each month of the quarter unless a higher value is obtained in a monthly GCV sample (or, if multiple samples are taken and averaged, if the monthly average exceeds the assumed value). In that case, if only one monthly sample is taken, use the sampled value, starting from the date on which the sample was taken. If multiple samples are taken and averaged, use the average value for the entire month in which the assumed value was exceeded. Consider the sample (or, if applicable, monthly average) results to be the new assumed value. Continue using the new assumed value unless and until one of the following occurs (as applicable to the reporting option selected): The assumed value is superseded by a higher value from a subsequent monthly sample (or by a higher monthly average); or the assumed value is superseded by a new contract in which case the new contract value becomes the assumed value at the time the fuel specified under the new contract begins to be combusted in the unit; or both the calendar year in which the new sampled value (or monthly average) exceeded the assumed value and the subsequent calendar year have elapsed. (d) For samples of gaseous fuel delivered in shipments or lots: (1) If the actual value for the most recent shipment is to be used in the calculations, apply the results of the most recent sample, from the date on which the sample was taken until the date on which the next sample is taken; or (2) If an assumed value (contract maximum or highest value from previous year's samples) is to be used in the calculations, apply the assumed value unless a higher value is obtained in a sample of a shipment. In that case, use the sampled value, starting from the date on which the sample was taken. Consider the sample results to be the new assumed value. Continue using the new assumed value unless and until: it is superseded by a higher value from a sample of a subsequent shipment; or (if applicable) it is superseded by a new contract in which case the new contract value becomes the assumed value at the time the fuel specified under the new contract begins to be combusted in the unit; or (if applicable) both the calendar year in which the sampled value exceeded the assumed value and the subsequent calendar year have elapsed. (e) When the owner or operator elects to use assumed values in the calculations, the results of periodic samples of sulfur content and GCV which show that the assumed value has not been exceeded need not be reported. Keep these sample results on file, in a format suitable for inspection. (f) Notwithstanding the requirements of paragraphs (b) through (d) of this section, in cases where the sample results are provided to the owner or operator by the supplier of the fuel, the owner or operator shall begin using the sampling results on the date of receipt of those results, rather than on the date that the sample was taken. 2.4 Missing Data Procedures. When data from the procedures of this part are not available, provide substitute data using the following procedures. 2.4.1 Missing Data for Oil and Gas Samples When fuel sulfur content, gross calorific value or, when necessary, density data are missing or invalid for an oil or gas sample taken according to the procedures in section 2.2.3, 2.2.4.1, 2.2.4.2, 2.2.4.3, 2.2.5, 2.2.6, 2.2.7, 2.3.3.1.2, or 2.3.4 of this appendix, then substitute the maximum potential sulfur content, density, or gross calorific value of that fuel from Table D-6 of this appendix. Except for the annual samples of fuel sulfur content required under sections 2.3.1.4(e), 2.3.2.4(e) and 2.3.6(b)(5) of this appendix, the missing data values in Table D-6 shall be reported whenever the results of a required sample of sulfur content, GCV or density is missing or invalid in the current calendar year, irrespective of which reporting option is selected (i.e., actual value, contract value or highest value from the previous year). For the annual samples of fuel sulfur content required under sections 2.3.1.4(e), 2.3.2.4(e) and 2.3.6(b)(5) of this appendix, if a valid annual sample has not been obtained by the end of a particular calendar year, the appropriate missing data value in Table D-6 shall be reported, beginning with the first unit operating hour in the next calendar year. The substitute data value(s) shall be used until the next valid sample for the missing parameter(s) is obtained. Note that only actual sample results shall be used to determine the “highest value from the previous year” when that reporting option is used; missing data values shall not be used in the determination. 2.4.2 Missing Data Procedures for Fuel Flow Rate Whenever data are missing from any primary fuel flowmeter system (as defined in § 72.2 of this chapter) and there is no backup system available to record the fuel flow rate, use the procedures in sections 2.4.2.2 and 2.4.2.3 of this appendix to account for the flow rate of fuel combusted at the unit for each hour during the missing data period. Alternatively, for a fuel flowmeter system used to measure the fuel combusted by a peaking unit, the simplified fuel flow missing data procedure in section 2.4.2.1 of this appendix may be used. Before using the procedures in sections 2.4.2.2 and 2.4.2.3 of this appendix, establish load ranges for the unit using the procedures of section 2 in appendix C to this part, except for units that do not produce electrical output (i.e., megawatts) or thermal output (e.g., klb of steam per hour). The owner or operator of a unit that does not produce electrical or thermal output shall either perform missing data substitution without segregating the fuel flow rate data into bins, or may petition the Administrator under § 75.66 for permission to segregate the data into operational bins. When load ranges are used for fuel flow rate missing data purposes, separate, fuel-specific databases shall be created and maintained. A database shall be kept for each type of fuel combusted in the unit, for the hours in which the fuel is combusted alone in the unit. An additional database shall be kept for each type of fuel, for the hours in which it is co-fired with any other type(s) of fuel(s). 2.4.2.1 Simplified Fuel Flow Rate Missing Data Procedure for Peaking Units If no fuel flow rate data are available for a fuel flowmeter system installed on a peaking unit (as defined in § 72.2 of this chapter), then substitute for each hour of missing data using the maximum potential fuel flow rate. The maximum potential fuel flow rate is the lesser of the following: (a) The maximum fuel flow rate the unit is capable of combusting or (b) The maximum flow rate that the fuel flowmeter can measure (i.e., the upper range value of the flowmeter). 2.4.2.2 Standard Missing Data Procedures—Single Fuel Hours For missing data periods that occur when only one type of fuel is being combusted, provide substitute data for each hour in the missing data period as follows. 2.4.2.2.1 If load-based missing data procedures are used, substitute the arithmetic average of the hourly fuel flow rate(s) measured and recorded by a certified fuel flowmeter system at the corresponding operating unit load range during the previous 720 operating hours in which the unit combusted only that same fuel. If no fuel flow rate data are available at the corresponding load range, use data from the next higher load range, if such data are available. If no quality-assured fuel flow rate data are available at either the corresponding load range or a higher load range, substitute the maximum potential fuel flow rate (as defined in section 2.4.2.1 of this appendix) for each hour of the missing data period. 2.4.2.2.2 For units that do not produce electrical or thermal output and therefore cannot use load-based missing data procedures, provide substitute data for each hour of the missing data period as follows. Substitute the arithmetic average of the hourly fuel flow rates measured and recorded by a certified fuel flowmeter system during the previous 720 operating hours in which the unit combusted only that same fuel. If no quality-assured fuel flow rate data are available, substitute the maximum potential fuel flow rate (as defined in section 2.4.2.1 of this appendix) for each hour of the missing data period. 2.4.2.3 Standard Missing Data Procedures—Multiple Fuel Hours For missing data periods that occur when two or more different types of fuel are being co-fired, provide substitute fuel flow rate data for each hour of the missing data period as follows. 2.4.2.3.1 If load-based missing data procedures are used, substitute the maximum hourly fuel flow rate measured and recorded by a certified fuel flowmeter system at the corresponding load range during the previous 720 operating hours when the fuel for which the flow rate data are missing was co-fired with any other type of fuel. If no such quality-assured fuel flow rate data are available at the corresponding load range, use data from the next higher load range (if available). If no quality-assured fuel flow rate data are available for co-fired hours, either at the corresponding load range or a higher load range, substitute the maximum potential fuel flow rate (as defined in section 2.4.2.1 of this appendix) for each hour of the missing data period. 2.4.2.3.2 For units that do not produce electrical or thermal output and therefore cannot use load-based missing data procedures, provide substitute fuel flow rate data for each hour of the missing data period as follows. Substitute the maximum hourly fuel flow rate measured and recorded by a certified fuel flowmeter system during the previous 720 operating hours in which the fuel for which the flow rate data are missing was co-fired with any other type of fuel. If no quality-assured fuel flow rate data for co-fired hours are available, substitute the maximum potential fuel flow rate (as defined in section 2.4.2.1 of this appendix) for each hour of the missing data period. 2.4.2.3.3 If, during an hour in which different types of fuel are co-fired, quality-assured fuel flow rate data are missing for two or more of the fuels being combusted, apply the procedures in section 2.4.2.3.1 or 2.4.2.3.2 of this appendix (as applicable) separately for each type of fuel. 2.4.2.3.4 If the missing data substitution required in section 2.4.2.3.1 or 2.4.2.3.2 causes the reported hourly heat input rate based on the combined fuel usage to exceed the maximum rated hourly heat input of the unit, adjust the substitute fuel flow rate value(s) so that the reported heat input rate equals the unit's maximum rated hourly heat input. Manual entry of the adjusted substitute data values is permitted. 2.4.3. In any case where the missing data provisions of this section require substitution of data measured and recorded more than three years (26,280 clock hours) prior to the date and time of the missing data period, use three years (26,280 clock hours) in place of the prescribed lookback period. In addition, for a new or newly-affected unit, until 720 hours of quality-assured fuel flowmeter data are available for the lookback periods described in sections 2.4.2.2 and 2.4.2.3 of this appendix, use all of the available fuel flowmeter data to determine the appropriate substitute data values. 3. Calculations Calculate hourly SO 2 2 2 2 2 3.1 SO 2 3.1.1 Use Equation D-2 to calculate SO 2 Where: SO 2rate-oil 2 OIL rate %S oil 2.0 = Ratio of lb SO 2 3.1.2 Record the SO 2 3.2 Mass Flow Rate Calculation for Volumetric Oil Flowmeters 3.2.1 Where the oil flowmeter records volumetric flow rate rather than mass flow rate, calculate and record the oil mass flow rate for each hourly period using hourly oil flow rate measurements and the density or specific gravity of the oil sample. 3.2.2 Convert density, specific gravity, or API gravity of the oil sample to density of the oil sample at the sampling location's temperature using ASTM D1250-07, Standard Guide for Use of the Petroleum Measurement Tables (incorporated by reference under (§ 75.6 of this part). 3.2.3 Where density of the oil is determined by the applicable ASTM procedures from section 2.2.6 of this appendix, use Equation D-3 to calculate the rate of the mass of oil consumed (in lb/hr): Where: OIL rate V oil-rate 3 D oil 3 3.3 SO 2 3.3.1 Use Equation D-4 to calculate the SO 2 Where: SO2rate-gas = Hourly mass rate of SO 2 GASrate = Hourly metered flow rate of gaseous fuel combusted, 100 scf/hr. Sgas = Sulfur content of gaseous fuel, in grain/100 scf. 2.0 = Ratio of lb SO 2 7000 = Conversion of grains/100 scf to lb/100 scf. 3.3.2 Use Equation D-5 to calculate the SO 2 where: SO 2 2 ER = SO 2 HI rate 3.3.3 Record the SO 2 3.4 Calculation of Heat Input Rate 3.4.1 Heat Input Rate for Gaseous Fuels (a) Determine total hourly gas flow or average hourly gas flow rate with a fuel flowmeter in accordance with the requirements of section 2.1 of this appendix and the fuel GCV in accordance with the requirements of section 2.3.4 of this appendix. If necessary perform the 720-hour test under section 2.3.5 to determine the appropriate fuel GCV sampling frequency. (b) Then, use Equation D-6 to calculate heat input rate from gaseous fuels for each hour. Where: HI rate-gas GAS rate GCV gas 10 6 (c) Note that when fuel flow is measured on an hourly totalized basis (e.g. a fuel flowmeter reports totalized fuel flow for each hour), before Equation D-6 can be used, the total hourly fuel usage must be converted from units of 100 scf to units of 100 scf/hr using Equation D-7: Where: GAS rate GAS unit t = Unit operating time, hour or fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator). 3.4.2 Heat Input Rate From the Combustion of Oil (a) Determine total hourly oil flow or average hourly oil flow rate with a fuel flowmeter, in accordance with the requirements of section 2.1 of this appendix. Determine oil GCV according to the requirements of section 2.2 of this appendix. Then, use Equation D-8 to calculate hourly heat input rate from oil for each hour: Where: HI rate-oil OIL rate GCV oil 10 6 (b) Note that when fuel flow is measured on an hourly totalized basis (e.g., a fuel flowmeter reports totalized fuel flow for each hour), before equation D-8 can be used, the total hourly fuel usage must be converted from units of lb to units of lb/hr, using equation D-9: Where: OIL rate OIL unit t = Unit operating time, hour or fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator). (c) For affected units that are not subject to an Acid Rain emissions limitation, but are regulated under a State or federal NO X rate oil rate oil 3.4.3 Apportioning Heat Input Rate to Multiple Units (a) Use the procedure in this section to apportion hourly heat input rate to two or more units using a single fuel flowmeter which supplies fuel to the units. The designated representative may also petition the Administrator under § 75.66 to use this apportionment procedure to calculate SO 2 2 (b) Determine total hourly fuel flow or flow rate through the fuel flowmeter supplying gas or oil fuel to the units. Convert fuel flow rates to units of 100 scf for gaseous fuels or to lb for oil, using the procedures of this appendix. Apportion the fuel to each unit separately based on hourly output of the unit in MW e Equation D-10 [Reserved] Equation D-11 [Reserved] (c) Use the total apportioned fuel flow calculated from Equation F-21a or F-21b to calculate the hourly unit heat input rate, using Equations D-6 and D-7 (for gas) or Equations D-8 and D-9 (for oil). 3.5 Conversion of Hourly Rates to Hourly, Quarterly, and Year-to-Date Totals 3.5.1 Hourly SO 2 Where: MSO 2 2 SO 2 2 ti = Time each gas or oil fuel was combusted for the hour (fuel usage time), fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator). 3.5.2 Quarterly Total SO 2 Sum the hourly SO 2 Where: M SO2-qtr 2 M SO2-hr 2 2000= Conversion factor from lb to tons. 3.5.3 Year to Date SO 2 Calculate and record SO 2 Where: M SO2-YTD 2 M SO2-qtr 2 3.5.4 Hourly Total Heat Input Rate and Heat Input from the Combustion of all Fuels 3.5.4.1 Determine the total heat input in mmBtu for each hour from the combustion of all fuels using Equation D-15: Where: HI hr HI rate-i t i 3.5.4.2 For reporting purposes, determine the heat input rate to each unit, in mmBtu/hr, for each hour from the combustion of all fuels using Equation D-15a: Where: HI rate-hr HI rate-i t i t u 3.5.5 Quarterly Heat Input Sum the hourly heat input values determined from equation D-15 for all hours in a quarter using Equation D-16: Where: HIqtr = Total heat input from all fuels combusted during the quarter, mmBtu. HIqtr = Hourly heat input determined using Equation D-15, mmBtu. 3.5.6 Year-to-Date Heat Input Calculate and record the total heat input in the year to date using Equation D-17. HI YTD HI qtr 3.6 Records and Reports Calculate and record quarterly and cumulative SO 2 2 [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26548, 26551, May 17, 1995; 61 FR 25585, May 22, 1996; 61 FR 59166, Nov. 20, 1996; 63 FR 57513, Oct. 27, 1998; 64 FR 28652, May 26, 1999; 64 FR 37582, July 12, 1999; 67 FR 40460, 40472, June 12, 2002; 67 FR 53505, Aug. 16, 2002; 73 FR 4369, Jan. 24, 2008; 76 FR 17324, Mar. 28, 2011; 76 FR 20536, Apr. 13, 2011; 77 FR 2460, Jan. 18, 2012] Editorial Note: At 67 FR 53505, Aug. 16, 2002, section 2.4.1 Table D-6 was amended. However, this table is a photographed graphic and the amendments could not be incorporated. Appendix E to Part 75—Optional NO X 1. Applicability 1.1 Unit Operation Requirements This NO X X X X X X 1.2 Certification 1.2.1 Pursuant to the procedures in § 75.20, complete all testing requirements to certify use of this protocol in lieu of a NO X 1.2.2 [Reserved] 2. Procedure 2.1 Initial Performance Testing Use the following procedures for: measuring NO X X 2 X 2.1.1 Load Selection Establish at least four approximately equally spaced operating load points, ranging from the maximum operating load to the minimum operating load. Select the maximum and minimum operating load from the operating history of the unit during the most recent two years. (If projections indicate that the unit's maximum or minimum operating load during the next five years will be significantly different from the most recent two years, select the maximum and minimum operating load based on the projected dispatched load of the unit.) For new gas-fired peaking units or new oil-fired peaking units, select the maximum and minimum operating load from the expected maximum and minimum load to be dispatched to the unit in the first five calendar years of operation. 2.1.2 NO X 2 Use the following procedures to measure NO X 2 X 2.1.2.1 For boilers, select an excess O 2 X X 2 X 2 2.1.2.2 For stationary gas turbines, sample at a minimum of 12 points per run at each load level. Locate the sample points according to Method 1 in appendix A-1 to part 60 of this chapter. For each fuel or consistent combination of fuels (and, optionally, for each combination of fuels), measure the NO X 2 2.1.2.3 Allow the unit to stabilize for a minimum of 15 minutes (or longer if needed for the NO X 2 X 2 2.1.3 Heat Input Measure the total heat input (mmBtu) and heat input rate during testing (mmBtu/hr) as follows: 2.1.3.1 When the unit is combusting fuel, measure and record the flow of fuel consumed. Measure the flow of fuel with an in-line flowmeter(s) and automatically record the data. If a portion of the flow is diverted from the unit without being burned, and that diversion occurs downstream of the fuel flowmeter, an in-line flowmeter is required to account for the unburned fuel. Install and calibrate in-line flow meters using the procedures and specifications contained in sections 2.1.2, 2.1.3, 2.1.4, and 2.1.5 of appendix D of this part. Correct any gaseous fuel flow rate measured at actual temperature and pressure to standard conditions of 68 °F and 29.92 inches of mercury. 2.1.3.2 For liquid fuels, analyze fuel samples taken according to the requirements of section 2.2 of appendix D of this part to determine the heat content of the fuel. Determine heat content of liquid or gaseous fuel in accordance with the procedures in appendix F of this part. Calculate the heat input rate during testing (mmBtu/hr) associated with each load condition in accordance with equations F-19 or F-20 in appendix F of this part and total heat input using equation E-1 of this appendix. Record the heat input rate at each heat input/load point. 2.1.4 Emergency Fuel The designated representative of a unit that is restricted by its federal, State or local permit to combusting a particular fuel only during emergencies where the primary fuel is not available may claim an exemption from the requirements of this appendix for testing the NO X X 2.1.5 Tabulation of Results Tabulate the results of each baseline correlation test for each fuel or, as applicable, combination of fuels, listing: time of test, duration, operating loads, heat input rate (mmBtu/hr), F-factors, excess oxygen levels, and NO X X X X X X 2.1.6 Plotting of Results Plot the tabulated results as an x-y graph for each fuel and (as applicable) combination of fuels combusted according to the following procedures. 2.1.6.1 Plot the heat input rate (mmBtu/hr) as the independent (or x) variable and the NO X 2.1.6.2 Units that co-fire gas and oil may be tested while firing gas only and oil only instead of testing with each combination of fuels. In this case, construct a graph for each fuel. 2.2 Periodic NO X Retest the NO X X X X X 2.3 Other Quality Assurance/Quality Control-Related NOx Emission Rate Testing When the operating levels of certain parameters exceed the limits specified below, or where the Administrator issues a notice requesting retesting because the NO X X X 2.3.1 For a stationary gas turbine, select at least four operating parameters indicative of the turbine's NO X X X 2.3.2 For a diesel or dual-fuel reciprocating engine, select at least four operating parameters indicative of the engine's NO X X X X 2.3.3 For boilers using the procedures in this appendix, the NO X 2 X 2.4 Procedures for Determining Hourly NO X 2.4.1 Record the time (hr. and min.), load (MWge or steam load in 1000 lb/hr, or mmBtu/hr thermal output), fuel flow rate and heat input rate (using the procedures in section 2.1.3 of this appendix) for each hour during which the unit combusts fuel. Calculate the total hourly heat input using equation E-1 of this appendix. Record the heat input rate for each fuel to the nearest 0.1 mmBtu/hr. During partial unit operating hours or during hours where more than one fuel is combusted, heat input must be represented as an hourly rate in mmBtu/hr, as if the fuel were combusted for the entire hour at that rate (and not as the actual, total heat input during that partial hour or hour) in order to ensure proper correlation with the NO X 2.4.2 Use the graph of the baseline correlation results (appropriate for the fuel or fuel combination) to determine the NO X X X 2.4.3 To determine the NO X X X X X 2.4.4 For each hour, record the critical quality assurance parameters, as identified in the monitoring plan, and as required by section 2.3 of this appendix from the date and hour of the completion of the most recent test for each type of fuel. 2.5 Missing Data Procedures Provide substitute data for each unit electing to use this alternative procedure whenever a valid quality-assured hour of NO X X 2.5.1 Use the procedures of this section whenever any of the quality assurance/quality control parameters exceeds the limits in section 2.3 of this appendix or whenever any of the quality assurance/quality control parameters are not available. 2.5.2 Substitute missing NO X X 2.5.2.1 If the measured heat input rate during any unit operating hour is higher than the highest heat input rate from the baseline correlation tests, the NO X 2.5.2.1.1 Substitute the higher of: the NO X X X X X 2.5.2.1.2 Substitute 1.25 times the highest NO X X 2.5.2.2 For a unit with add-on NO X X 2.5.2.3 When emergency fuel (as defined in § 72.2) is combusted in the unit, report the fuel-specific NO X X 2.5.2.4 Whenever 20 full calendar quarters have elapsed following the quarter of the last baseline correlation test for a particular type of fuel (or fuel mixture), without a subsequent baseline correlation test being done for that type of fuel (or fuel mixture), substitute the fuel-specific NO X 2.5.3 Maintain a record indicating which data are substitute data and the reasons for the failure to provide a valid quality-assured hour of NO X 2.5.4 Substitute missing data from a fuel flowmeter using the procedures in section 2.4.2 of appendix D to this part. 2.5.5 Substitute missing data for gross calorific value of fuel using the procedures in sections 2.4.1 of appendix D to this part. 3. Calculations 3.1 Heat Input Calculate the total heat input by summing the product of heat input rate and fuel usage time of each fuel, as in the following equation: Where: H T HI fuel 1,2,3,...last t 1,2,3....last 3.2 F-factors Determine the F-factors for each fuel or combination of fuels to be combusted according to section 3.3 of appendix F of this part. 3.3 NO X 3.3.1 Conversion from Concentration to Emission Rate Convert the NO X 2 X 3.3.2 Quarterly Average NO X Report the quarterly average emission rate (lb/mmBtu) as required in subpart G of this part. Calculate the quarterly average NO X 3.3.3 Annual Average NO X Report the average emission rate (lb/mmBtu) for the calendar year as required in subpart G of this part. Calculate the average NO X 3.3.4 Average NO X Where: E h X E f X f HI f H T t f Note: For hours where a fuel is combusted for only part of the hour, use the fuel flow rate or mass flow rate during the fuel usage time, instead of the total fuel flow or mass flow during the hour, when calculating heat input rate using Equation F-19 or F-20. 4. Quality Assurance/Quality Control Plan Include a section on the NO X X X 4.1 Submit a copy of the recommended range of operating parameter values, and the range of operating parameter values recorded during the previous NO X X 4.2 Keep records of these operating parameters for each hour of operation in order to demonstrate that a unit is remaining within the recommended operating range. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26551, May 17, 1995; 64 FR 28665, May 26, 1999; 67 FR 40473, 40474, June 12, 2002; 67 FR 53505, Aug. 16, 2002; 73 FR 4372, Jan. 24, 2008; 76 FR 17325, Mar. 28, 2011] Appendix F to Part 75—Conversion Procedures 1. Applicability Use the procedures in this appendix to convert measured data from a monitor or continuous emission monitoring system into the appropriate units of the standard. 2. Procedures for SO 2 Use the following procedures to compute hourly SO 2 2 2.1 When measurements of SO 2 2 Where: E h 2 K = 1.660 × 10 −7 2 C h 2 Q h 2.2 When measurements by the SO 2 2 where: E h 2 K = 1.660 × 10 −7 2 C hp 2 Q hs %H 2 2.3 Use the following equations to calculate total SO 2 (Eq. F-3) Where: E q 2 E h 2 t h n = Number of hourly SO 2 2000 = Conversion of 2000 lb per ton. Where: E a 2 E q 2 q = Quarters for which E q 2.4 Round all SO 2 3. Procedures for NO X Use the following procedures to convert continuous emission monitoring system measurements of NO X X X 2 2 3.1 When the NO X 2 (Eq. F-5) where, K, E, C h 2 3.2 When the NO X 2 (Eq. F-6) where: K, E, Ch, Fc, and %CO 2 When CO 2 X 3.3 Use the definitions listed below to derive values for the parameters in equations F-5 and F-6 of this appendix, or (if applicable) in the equations in Method 19 in appendix A-7 to part 60 of this chapter. 3.3.1 K = 1.194 × 10 −7 X 3.3.2 E = Pollutant emissions during unit operation, lb/mmBtu. 3.3.3 C h 3.3.4 %O 2 2 2 2 3.3.4.1 For boilers, a minimum concentration of 5.0 percent CO 2 2 2 2 2 2 2 2 2 2 2 2 3.3.4.2 If NO X 2w 2dc 2 2dc 2dc 2dc 3.3.5 F, F c 2 c c Table 1—F- and F c 1 Fuel F-factor F C 2 Coal (as defined by ASTM D388-99 2 Anthracite 10,100 1,970 Bituminous 9,780 1,800 Subbituminous 9,820 1,840 Lignite 9,860 1,910 Petroleum Coke 9,830 1,850 Tire Derived Fuel 10,260 1,800 Oil 9,190 1,420 Gas: Natural gas 8,710 1,040 Propane 8,710 1,190 Butane 8,710 1,250 Wood: Bark 9,600 1,920 Wood residue 9,240 1,830 1 2 3.3.6 Equations F-7a and F-7b may be used in lieu of the F or F c c 2 c c c c c (Eq. F-7a) (Eq. F-7b) 3.3.6.1 H, C, S, N, and O are content by weight of hydrogen, carbon, sulfur, nitrogen, and oxygen (expressed as percent), respectively, as determined on the same basis as the gross calorific value (GCV) by ultimate analysis of the fuel combusted using ASTM D3176-89 (Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and Coke, (solid fuels), ASTM D5291-02, Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, (liquid fuels) or computed from results using ASTM D1945-96 (Reapproved 2001), Standard Test Method for Analysis of Natural Gas by Gas Chromatography, or ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography, (gaseous fuels) as applicable. (All of these methods are incorporated by reference under § 75.6 of this part.) 3.3.6.2 GCV is the gross calorific value (Btu/lb) of the fuel combusted determined by ASTM D5865-01a or ASTM D5865-10, ASTM D240-00 or ASTM D4809-00, and ASTM D3588-98, ASTM D4891-89 (Reapproved 2006), GPA Standard 2172-96, GPA Standard 2261-00, or ASTM D1826-94 (Reapproved 1998), as applicable. (All of these methods are incorporated by reference under § 75.6.) 3.3.6.3 For affected units that combust a combination of a fuel (or fuels) listed in Table 1 in section 3.3.5 of this appendix with any fuel(s) not listed in Table 1, the F or F c 3.3.6.4 For affected units that combust combinations of fuels listed in Table 1 in section 3.3.5 of this appendix, prorate the F or F c Where, X i e.g. i i i i F i c i n = Number of fuels being combusted in combination. 3.3.6.5 As an alternative to prorating the F or Fc factor as described in section 3.3.6.4 of this appendix, a “worst-case” F or F c c c 3.4 Use the following equations to calculate the average NO X Where: E q X E i X n = Number of hourly rates during calendar quarter. Where: E a X E i X m = Number of hourly rates for which E i 3.5 Round all NO X 4. Procedures for CO 2 Use the following procedures to convert continuous emission monitoring system measurements of CO 2 2 2 2 2 2 4.1 When CO 2 2 Where: E h 2 K = 5.7 × 10 −7 2 2 C h 2 2 2 2 Q h 4.2 When CO 2 2 −7 2 h 2 hp 2 2 4.3 Use the following equations to calculate total CO 2 Where: E CO2q 2 E h 2 t h H R 2 Where: E CO2a 2 E CO2q 2 q = Quarters for which E CO2q 4.4 For an affected unit, when the owner or operator is continuously monitoring O 2 2 2 4.4.1 If the owner or operator elects to use data from an O 2 2 C 2 2 Where: CO 2d 2 F, F C c 20.9 = Percentage of O 2 O 2d 2 Where: CO 2w 2 O 2w 2 F, F c 20.9 = Percentage of O 2 %H 2 For any hour where Equation F-14a or F-14b results in a negative hourly average CO 2 2w 2 4.4.2 Determine CO 2 2 2 2 5. Procedures for Heat Input Use the following procedures to compute heat input rate to an affected unit (in mmBtu/hr or mmBtu/day): 5.1 Calculate and record heat input rate to an affected unit on an hourly basis, except as provided in sections 5.5 through 5.5.7. The owner or operator may choose to use the provisions specified in § 75.16(e) or in section 2.1.2 of appendix D to this part in conjunction with the procedures provided in sections 5.6 through 5.6.2 to apportion heat input among each unit using the common stack or common pipe header. 5.2 For an affected unit that has a flow monitor (or approved alternate monitoring system under subpart E of this part for measuring volumetric flow rate) and a diluent gas (O 2 2 5.2.1 When measurements of CO 2 Where: HI = Hourly heat input rate during unit operation, mmBtu/hr. Q w F c %CO 2w 2 2 5.2.2 When measurements of CO 2 Where: HI = Hourly heat input rate during unit operation, mmBtu/hr. Q h F c %CO 2d 2 2 %H 2 5.2.3 When measurements of O 2 Where: HI = Hourly heat input rate during unit operation, mmBtu/hr. Q w F = Dry basis F-factor, listed in section 3.3.5 of this appendix for each fuel, dscf/mmBtu. %O 2w 2 2 %H 2 5.2.4 When measurements of O 2 Where: HI = Hourly heat input rate during unit operation, mmBtu/hr. Q w F = Dry basis F-factor, listed in section 3.3.5 of this appendix for each fuel, dscf/mmBtu. %H 2 %O 2d 2 2 5.3 Heat Input Summation (for Heat Input Determined Using a Flow Monitor and Diluent Monitor) 5.3.1 Calculate total quarterly heat input for a unit or common stack using a flow monitor and diluent monitor to calculate heat input, using the following equation: Where: HI q HI i t i 5.3.2 Calculate total cumulative heat input for a unit or common stack using a flow monitor and diluent monitor to calculate heat input, using the following equation: Where: HI c HI q 5.3.3 Calculate total daily heat input for a unit using a flow monitor and diluent monitor to calculate heat input, using the following equation: Where: HI d HI h t h h = Designation of a particular hour. 5.4 [Reserved] 5.5 For a gas-fired or oil-fired unit that does not have a flow monitor and is using the procedures specified in appendix D to this part to monitor SO 2 X X 5.5.1 (a) When the unit is combusting oil, use the following equation to calculate hourly heat input rate: Where: HI o M o GCV O 10 6 (b) When performing oil sampling and analysis solely for the purpose of the missing data procedures in § 75.36, oil samples for measuring GCV may be taken weekly, and the procedures specified in appendix D to this part for determining the mass rate of oil consumed per hour are optional. 5.5.2 When the unit is combusting gaseous fuels, use the following equation to calculate heat input rate from gaseous fuels for each hour: Where: HI g Q g GCV g 10 6 5.5.3 When the unit is combusting coal, use the procedures, methods, and equations in sections 5.5.3.1-5.5.3.3 of this appendix to determine the heat input from coal for each 24-hour period. (All ASTM methods are incorporated by reference under § 75.6 of this part.) 5.5.3.1 Perform coal sampling daily according to section 5.3.2.2 in Method 19 in appendix A to part 60 of this chapter and use ASTM D2234-00, Standard Practice for Collection of a Gross Sample of Coal, (incorporated by reference under § 75.6 of this part) Type I, Conditions A, B, or C and systematic spacing for sampling. (When performing coal sampling solely for the purposes of the missing data procedures in § 75.36, use of ASTM D2234-00 is optional, and coal samples may be taken weekly.) 5.5.3.2 All ASTM methods are incorporated by reference under § 75.6. Use ASTM D2013-01 for preparation of a daily coal sample and analyze each daily coal sample for gross calorific value using ASTM D5865-01a or ASTM D5865-10. On-line coal analysis may also be used if the on-line analytical instrument has been demonstrated to be equivalent to the applicable ASTM methods under §§ 75.23 and 75.66. 5.5.3.3 Calculate the heat input from coal using the following equation: (Eq. F-21) where: HIc = Daily heat input from coal, mmBtu/day. Mc = Mass of coal consumed per day, as measured and recorded in company records, tons. GCV C 500 = Conversion of Btu/lb to mmBtu/ton. 5.5.4 For units obtaining heat input values daily instead of hourly, apportion the daily heat input using the fraction of the daily steam load or daily unit operating load used each hour in order to obtain HI i 5.5.5 If a daily fuel sampling value for gross calorific value is not available, substitute the maximum gross calorific value measured from the previous 30 daily samples. If a monthly fuel sampling value for gross calorific value is not available, substitute the maximum gross calorific value measured from the previous 3 monthly samples. 5.5.6 If a fuel flow value is not available, use the fuel flowmeter missing data procedures in section 2.4 of appendix D of this part. If a daily coal consumption value is not available, substitute the maximum fuel feed rate during the previous thirty days when the unit burned coal. 5.5.7 Results for samples must be available no later than thirty calendar days after the sample is composited or taken. However, during an audit, the Administrator may require that the results be available in five business days, or sooner if practicable. 5.6 Heat Input Rate Apportionment for Units Sharing a Common Stack or Pipe 5.6.1 Where applicable, the owner or operator of an affected unit that determines heat input rate at the unit level by apportioning the heat input monitored at a common stack or common pipe using megawatts shall apportion the heat input rate using the following equation: Where: HI i HI cs MW i t i t CS n = Total number of units using the common stack or pipe. i = Designation of a particular unit. 5.6.2 Where applicable, the owner or operator of an affected unit that determines the heat input rate at the unit level by apportioning the heat input rate monitored at a common stack or common pipe using steam load shall apportion the heat input rate using the following equation: Where: HI i HI CS SF = Gross steam load, lb/hr, or mmBtu/hr. t i t CS n = Total number of units using the common stack or pipe. i = Designation of a particular unit. 5.7 Heat Input Rate Summation for Units with Multiple Stacks or Pipes The owner or operator of an affected unit that determines the heat input rate at the unit level by summing the heat input rates monitored at multiple stacks or multiple pipes shall sum the heat input rates using the following equation: Where: HI Unit HI s t Unit t s s = Designation for a particular stack, duct, or pipe. 5.8 Alternate Heat Input Apportionment for Common Pipes As an alternative to using Equation F-21a or F-21b in section 5.6 of this appendix, the owner or operator may apportion the heat input rate at a common pipe to the individual units served by the common pipe based on the fuel flow rate to the individual units, as measured by uncertified fuel flowmeters. This option may only be used if a fuel flowmeter system that meets the requirements of appendix D to this part is installed on the common pipe. If this option is used, determine the unit heat input rates using the following equation: Where: HI i HI CP FF i t i t CP n = Total number of units using the common pipe. i = Designation of a particular unit. 6. Procedure for Converting Volumetric Flow to STP Use the following equation to convert volumetric flow at actual temperature and pressure to standard temperature and pressure. F STP Actual Std Stack Stack Std where: F STP F Actual T Std T Stack P Stack P Std 7. Procedures for SO 2 2 The owner or operator shall use Equation F-23 to calculate hourly SO 2 2 2 Where: E h 2 ER = Applicable SO 2 2 HI = Hourly heat input rate, determined using the procedures in section 5.2 of this appendix, mmBtu/hr. 8. Procedures for NO X Mass Emissions The owner or operator of a unit that is required to monitor, record, and report NO X X X X 8.1 The owner or operator may use the hourly NO X X X 8.1.1 If both NO X X (a) Use Equation F-24 to calculate the hourly NO X Where: M (NO X ) h X ER (NO X ) h X X HI h t h X (b) Use Equation F-24a to calculate the hourly NO X Where: E (NO X ) h X ER (NO X ) h X X HI h 8.1.2 If NO X where: HI CS t CS cs HI u t u p = Number of units that exhaust through the common stack. u = Designation of a particular unit. Use the hourly heat input rate at the common stack level and the hourly average NO X X 8.1.3 If a unit has multiple ducts and NO X X X 8.1.4 If a unit has multiple ducts and NO X X 8.2 Alternatively, the owner or operator may use the hourly NO X X X X X X 8.2.1 When the NO X X X Where: E (NO X ) h X K = 1.194 × 10 −7 X C hw X Q h 8.2.2 When NO X X X X Where: E (NO X ) h X K = 1.194 × 10 −7 X C hd X Q h %H 2 8.3 When hourly NO X X X X Where: M (NO X ) h X E h X t h 8.4 Use the following equations to calculate daily, quarterly, cumulative ozone season, and cumulative year-to-date NO X (a) When hourly NO X X Where: M (NO X ) time period X M (NO X ) h X p = The number of hours in the given time period (quarter, cumulative ozone season, cumulative year-to-date). (b) When hourly NO X X Where: M (NO X ) time period X E (NO X ) h X p = The number of hours in the given time period (quarter, cumulative ozone season, cumulative year-to-date). t h (c) To calculate daily NO X Where: M (NOX)d X E (NOX)h X t h h = Designation of a particular hour. 8.5 Specific provisions for monitoring NO X X X 8.5.1 The owner or operator may determine both NO X X 8.5.2 The owner or operator may determine the NO X X 8.5.3 Where applicable, the owner or operator of a unit that determines hourly NO X X Where: E (NOX)i X E (NOX)CS X HI i t i t CS n = Number of units using the common stack. i = Designation of a particular unit. 9. [Reserved] 10. Moisture Determination From Wet and Dry O 2 If a correction for the stack gas moisture content is required in any of the emissions or heat input calculations described in this appendix, and if the hourly moisture content is determined from wet- and dry-basis O 2 Where: % H 2 2 O 2d 2 O 2w 2 [58 FR 3701, Jan. 11, 1993; Redesignated and amended at 60 FR 26553, 26571, May 17, 1995; 61 FR 25585, May 22, 1996; 61 FR 59166, Nov. 20, 1996; 63 FR 57513, Oct. 27, 1998; 64 FR 28666, May 26, 1999; 64 FR 37582, July 12, 1999; 67 FR 40474, 40475, June 12, 2002; 67 FR 53505, Aug. 16, 2002; 70 FR 28695, May 18, 2005; 73 FR 4372, Jan. 24, 2008; 76 FR 17325, Mar. 28, 2011; 77 FR 2460, Jan. 18, 2012; 88 FR 36896, June 5, 2023] Appendix G to Part 75—Determination of CO 2 1. Applicability The procedures in this appendix may be used to estimate CO 2 2 2 2. Procedures for Estimating CO 2 Use the following procedures to estimate daily CO 2 2 2 2.1 Use the following equation to calculate daily CO 2 2 2 Where: Wco2 = CO 2 MW c MW o2 W c 2.1.1 Collect at least one fuel sample during each week that the unit combusts coal, one sample per each shipment or delivery for oil and diesel fuel, one fuel sample for each delivery for gaseous fuel in lots, one sample per day or per hour (as applicable) for each gaseous fuel that is required to be sampled daily or hourly for gross calorific value under section 2.3.5.6 of appendix D to this part, and one sample per month for each gaseous fuel that is required to be sampled monthly for gross calorific value under section 2.3.4.1 or 2.3.4.2 of appendix D to this part. Collect coal samples from a location in the fuel handling system that provides a sample representative of the fuel bunkered or consumed during the week. 2.1.2 Determine the carbon content of each fuel sample using one of the following methods: ASTM D3178-89 (Reapproved 2002) or ASTM D5373-02 (Reapproved 2007) for coal; ASTM D5291-02, Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, ultimate analysis of oil, or computations based upon ASTM D3238-95 (Reapproved 2000) and either ASTM D2502-92 (Reapproved 1996) or ASTM D2503-92 (Reapproved 1997) for oil; and computations based on ASTM D1945-96 (Reapproved 2001) or ASTM D1946-90 (Reapproved 2006) for gas (all incorporated by reference under § 75.6 of this part). 2.1.3 Use daily fuel feed rates from company records for all fuels and the carbon content of the most recent fuel sample under this section to determine tons of carbon per day from combustion of each fuel. (All ASTM methods are incorporated by reference under § 75.6.) Where more than one fuel is combusted during a calendar day, calculate total tons of carbon for the day from all fuels. 2.2 For an affected coal-fired unit, the estimate of daily CO 2 2.2.1 Determine the ash content of the weekly sample of coal using ASTM D3174-00, “Standard Test Method for Ash in the Analysis Sample of Coal and Coke from Coal” (incorporated by reference under § 75.6 of this part). 2.2.2 Sample and analyze the carbon content of the fly-ash according to ASTM D5373-02 (Reapproved 2007), Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke” (incorporated by reference under § 75.6 of this part). 2.2.3 Discount the estimate of daily CO 2 (Eq. G-2) where, W NCO2 2 W CO2 2 MW C02 MW c A% = Ash content of the coal sample, percent by weight. C% = Carbon content of ash, percent by weight. W COAL 2.2.4 The daily CO 2 W NCO2 W CO2 (Eq. G-3) where, W NCO2 2 .99 = Average fraction of coal converted into CO 2 W CO2 2 2.3 In lieu of using the procedures, methods, and equations in section 2.1 of this appendix, the owner or operator of an affected gas-fired or oil-fired unit (as defined under § 72.2 of this chapter) may use the following equation and records of hourly heat input to estimate hourly CO 2 (Eq. G-4) Where: WCO 2 2 MW CO 2 F c H = Hourly heat input in mmBtu, as calculated using the procedures in section 5 of appendix F of this part. Uf = 1/385 scf CO2/lb-mole at 14.7 psia and 68 °F. 3. Procedures for Estimating CO 2 When the affected unit has a wet flue gas desulfurization system, is a fluidized bed boiler, or uses other emission controls with sorbent injection, use either a CO 2 2 2 3.1 When limestone is the sorbent material, use the equations and procedures in either section 3.1.1 or 3.1.2 of this appendix. 3.1.1 Use the following equation to estimate daily CO 2 (Eq. G-5) where, SE CO2 2 W CaCO3 3 F u MW CO2 MW CaCO3 3.1.2 In lieu of using Equation G-5, any owner or operator who operates and maintains a certified SO 2 2 2 2 2 2 2 (Eq. G-6) where, SE CO2 2 MW CO2 MW SO2 W SO2 F u and (Eq. G-7) where: WSO 2 SO 20 2 %R = Overall percentage SO 2 3.2 When a sorbent material other than limestone is used, modify the equations, methods, and procedures in section 3.1 of this appendix as follows to estimate daily CO 2 3.2.1 Determine a site-specific value for F u 2 2 u 3.2.2 When using equation G-5, replace MW CaCO3 2 2 CaCO3 4. Procedures for Estimating Total CO 2 When the affected unit has a wet flue gas desulfurization system, is a fluidized bed boiler, or uses other emission controls with sorbent injection, use the following equation to obtain total daily CO 2 W t CO2 CO2 (Eq. G-8) where, W t 2 W CO2 2 SE CO2 2 5. Missing Data Substitution Procedures for Fuel Analytical Data Use the following procedures to substitute for missing fuel analytical data used to calculate CO 2 5.1-5.1.2 [Reserved] 5.2 Missing Carbon Content Data Use the following procedures to substitute for missing carbon content data. 5.2.1 In all cases (i.e., for weekly coal samples or composite oil samples from continuous sampling, for oil samples taken from the storage tank after transfer of a new delivery of fuel, for as-delivered samples of oil, diesel fuel, or gaseous fuel delivered in lots, and for gaseous fuel that is supplied by a pipeline and sampled monthly, daily or hourly for gross calorific value) when carbon content data is missing, report the appropriate default value from Table G-1. 5.2.2 The missing data values in Table G-1 shall be reported whenever the results of a required sample of fuel carbon content are either missing or invalid. The substitute data value shall be used until the next valid carbon content sample is obtained. 5.3 Gross Calorific Value Data For a gas-fired unit using the procedures of section 2.3 of this appendix to determine CO 2 [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26556, May 17, 1995; 61 FR 25585, May 22, 1996; 64 FR 28671, May 26, 1999; 67 FR 40475, June 12, 2002; 67 FR 57274, Sept. 9, 2002; 73 FR 4376, Jan. 24, 2008] 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]