Title 40—Protection of Environment--Volume 1
PART 75—CONTINUOUS EMISSION MONITORING
§ 75.1   Purpose and scope.
(a) Purpose. The purpose of this part is to establish requirements for the monitoring, recordkeeping, and reporting of sulfur dioxide (SO 2 ), nitrogen oxides (NO X ), and carbon dioxide (CO 2 ) emissions, volumetric flow, and opacity data from affected units under the Acid Rain Program pursuant to sections 412 and 821 of the CAA, 42 U.S.C. 7401-7671q as amended by Public Law 101-549 (November 15, 1990) [the Act]. In addition, this part sets forth provisions for the monitoring, recordkeeping, and reporting of NO X mass emissions with which EPA, individual States, or groups of States may require sources to comply in order to demonstrate compliance with a NO X mass emission reduction program, to the extent these provisions are adopted as requirements under such a program.
(b) Scope. (1) The regulations established under this part include general requirements for the installation, certification, operation, and maintenance of continuous emission or opacity monitoring systems and specific requirements for the monitoring of SO 2 emissions, volumetric flow, NO X emissions, opacity, CO 2 emissions and SO 2 emissions removal by qualifying Phase I technologies. Specifications for the installation and performance of continuous emission monitoring systems, certification tests and procedures, and quality assurance tests and procedures are included in appendices A and B to this part. Criteria for alternative monitoring systems and provisions to account for missing data from certified continuous emission monitoring systems or approved alternative monitoring systems are also included in the regulation.
(2) Statistical estimation procedures for missing data are included in appendix C to this part. Optional protocols for estimating SO 2 mass emissions from gas-fired or oil-fired units and NO X emissions from gas-fired peaking or oil-fired peaking units are included in appendices D and E, respectively, to this part. Requirements for recording and recordkeeping of monitoring data and for quarterly electronic reporting also are specified. Procedures for conversion of monitoring data into units of the standard are included in appendix F to this part. Procedures for the monitoring and calculation of CO 2 emissions are included in appendix G of this part.
§ 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 or NO 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 mass emission reduction program, to the extent these provisions are adopted as requirements under such a program.
§ 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).
§ 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 mass emissions become applicable on the deadlines specified in the applicable State or federal NO X mass emission reduction program, to the extent these provisions are adopted as requirements under such a program. In accordance with § 75.20, the owner or operator of each existing affected unit shall ensure that all monitoring systems required by this part for monitoring SO 2 , NO X , CO 2 , opacity, moisture and volumetric flow are installed and that all certification tests are completed no later than the following dates (except as provided in paragraphs (d) through (i) of this section):
(1) For a unit listed in table 1 of § 73.10(a) of this chapter, November 15, 1993.
(2) For a substitution or a compensating unit that is designated under an approved substitution plan or reduced utilization plan pursuant to § 72.41 or § 72.43 of this chapter, or for a unit that is designated an early election unit under an approved NO X compliance plan pursuant to part 76 of this chapter, that is not conditionally approved and that is effective for 1995, the earlier of the following dates:
(i) January 1, 1995; or
(ii) 90 days after the issuance date of the Acid Rain permit (or date of approval of permit revision) that governs the unit and contains the approved substitution plan, reduced utilization plan, or NO X compliance plan.
(3) For either a Phase II unit, other than a gas-fired unit or an oil-fired unit, or a substitution or compensating unit that is not a substitution or compensating unit under paragraph (a)(2) of this section: January 1, 1995.
(4) For a gas-fired Phase II unit or an oil-fired Phase II unit, January 1, 1995, except that installation and certification tests for continuous emission monitoring systems for NO X and CO 2 or excepted monitoring systems for NO X under appendix E or CO 2 estimation under appendix G of this part shall be completed as follows:
(i) For an oil-fired Phase II unit or a gas-fired Phase II unit located in an ozone nonattainment area or the ozone transport region, not later than July 1, 1995; or
(ii) For an oil-fired Phase II unit or a gas-fired Phase II unit not located in an ozone nonattainment area or the ozone transport region, not later than January 1, 1996.
(5) For combustion sources seeking to enter the Opt-in Program in accordance with part 74 of this chapter, the expiration date of a combustion source's opt-in permit under § 74.14(e) of this chapter.
(b) In accordance with § 75.20, the owner or operator of each new affected unit shall ensure that all monitoring systems required under this part for monitoring of SO 2 , NO X , CO 2 , opacity, and volumetric flow are installed and all certification tests are completed on or before the later of the following dates:
(1) January 1, 1995, except that for a gas-fired unit or oil-fired unit located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NO X and CO 2 monitoring systems shall be July 1, 1995 and for a gas-fired unit or an oil-fired unit not located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NO X and CO 2 monitoring systems shall be January 1, 1996; or
(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 , NO X , CO 2 , opacity, and volumetric flow are installed and all certification tests are completed on or before the later of the following dates:
(1) January 1, 1995, except that for a gas-fired unit or oil-fired unit located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NO X and CO 2 monitoring systems shall be July 1, 1995 and for a gas-fired unit or an oil-fired unit not located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NO X and CO 2 monitoring systems shall be January 1, 1996; or
(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 , NO X , CO 2 , opacity, and volumetric flow rate required under this part (or under the applicable State or Federal mass emissions reduction program) are installed and that all required certification tests are completed no later than 90 unit operating days or 180 calendar days (whichever occurs first) after the date that the unit recommences commercial operation, notice of which date shall be provided under § 75.61(a)(3) or § 75.61(a)(7), as applicable. The owner or operator shall determine and report SO 2 concentration, NO X emission rate, CO 2 concentration, and flow rate data (as applicable) for all unit operating hours after the applicable compliance date until all of the required certification tests are successfully completed, using either:
(1) The maximum potential concentration of SO 2 (as defined in section 2.1.1.1 of appendix A to this part), the maximum potential NO X emission rate, as defined in § 72.2 of this chapter, the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to this part, or the maximum potential CO 2 concentration, as defined in section 2.1.3.1 of appendix A to this part; or
(2) The conditional data validation provisions of § 75.20(b)(3); or
(3) Reference methods under § 75.22(b); or
(4) Another procedure approved by the Administrator pursuant to a petition under § 75.66.
(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 emission controls, after the applicable deadline in paragraph (a), (b), or (c) of this section:
(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., the SO 2 , NO X , CO 2 , O 2 , opacity, volumetric flow rate, and moisture monitoring systems, as applicable) are completed not later than 90 unit operating days or 180 calendar days (whichever occurs first) after:
(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 emission controls, the date that reagent is first injected into the flue gas desulfurization system or the add-on NO X emission controls, as applicable, notice of which date shall be provided under subpart G of this part.
(2) The owner or operator shall determine and report, as applicable, SO 2 concentration, NO X concentration, NO X emission rate, CO 2 concentration, O 2 concentration, volumetric flow rate, and moisture data for all unit or stack operating hours after emissions first pass through the new stack or flue, or reagent is first injected into the flue gas desulfurization system or add-on NO X emission controls, as applicable, until all required certification and/or recertification and/or diagnostic tests are successfully completed, using:
(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 emission controls, quality-assured data recorded on the high measurement scale of the monitor that measures the pollutant being removed by the add-on emission controls ( i.e., SO 2 or NO X , as applicable), if, pursuant to section 2 of appendix A to this part, two spans and ranges are required for that monitor and if the high measurement scale of the monitor has been certified according to § 75.20(c), section 6 of appendix A to this part, and, if applicable, paragraph (e)(4)(i) of this section. Data recorded on the certified high scale that ordinarily would be required to be recorded on the low scale, pursuant to section 2.1.1.4(g) or 2.1.2.4(f) of appendix A to this part, may be reported as quality-assured for a period not to exceed 60 unit or stack operating days after the date and hour that reagent is first injected into the control device, after which one or more of the options provided in paragraphs (e)(2)(ii), (e)(2)(iii), (e)(2)(iv) and (e)(2)(vi) of this section must be used to report SO 2 or NO X concentration data (as applicable) for each operating hour in which these low emissions occur, until certification testing of the low scale of the monitor is successfully completed; or
(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 emission controls, the owner or operator shall either:
(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., SO 2 or NO X , as applicable):
(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 ) The first unit or stack operating hour after successful completion of all of the certification tests in accordance with paragraph (e)(4)(i)(A) of this section; or
( 2 ) The hour of the probationary calibration error test (see § 75.20(b)(3)(ii)), if conditional data validation is used and all of the certification tests are successfully completed in accordance with paragraph (e)(4)(i)(A) of this section, with no test failures. If any required test is failed or aborted or is otherwise not in accordance with paragraph (e)(4)(i)(A) of this section, data validation shall be done according to § 75.20(b)(3)(vii).
(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 ) The first unit or stack operating hour after successful completion of all of the certification tests in accordance with paragraph (e)(4)(ii)(A) of this section; or
( 2 ) The hour of the probationary calibration error test ( see § 75.20(b)(3)(ii)), if conditional data validation is used and all of the certification tests are successfully completed in accordance with paragraph (e)(4)(ii)(A) of this section, with no test failures. If any required test is failed or aborted or is otherwise not in accordance with paragraph (e)(4)(ii)(A) of this section, data validation shall be done according to § 75.20(b)(3)(vii).
(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 emission rate data for all unit operating hours that the backup fuel is combusted using either:
(1) The fuel-specific maximum potential NO X emission rate, as defined in § 72.2 of this chapter; or
(2) Reference methods under § 75.22(b) of this part; or
(3) Another procedure approved by the Administrator pursuant to a petition under § 75.66.
(g) The provisions of this paragraph shall apply unless an owner or operator is exempt from certifying a fuel flowmeter for use during combustion of emergency fuel under section 2.1.4.3 of appendix D to this part, in which circumstance the provisions of section 2.1.4.3 of appendix D shall apply. In accordance with § 75.20, whenever the owner or operator of a gas-fired or oil-fired unit uses an excepted monitoring system under appendix D or E of this part and combusts emergency fuel as defined in § 72.2 of this chapter, then the owner or operator shall ensure that a fuel flowmeter measuring emergency fuel is installed and the required certification tests for excepted monitoring systems are completed by no later than 30 unit operating days after the first date after January 1, 1995 that the unit combusts emergency fuel. For all unit operating hours that the unit combusts emergency fuel after January 1, 1995 until the owner or operator installs a flowmeter for emergency fuel and successfully completes all required certification tests, the owner or operator shall determine and report SO 2 mass emission data using either:
(1) The maximum potential fuel flow rate, as described in appendix D of this part, and the maximum sulfur content of the fuel, as described in section 2.1.1.1 of appendix A of this part;
(2) Reference methods under § 75.22(b) of this part; or
(3) Another procedure approved by the Administrator pursuant to a petition under § 75.66.
(h) [Reserved]
(i) In accordance with § 75.20, the owner or operator of each affected unit at which SO 2 concentration is measured on a dry basis or at which moisture corrections are required to account for CO 2 emissions, NO X emission rate in lb/mmBtu, heat input, or NO X mass emissions for units in a NO X mass reduction program, shall ensure that the continuous moisture monitoring system required by this part is installed and that all applicable initial certification tests required under § 75.20(c)(5), (c)(6), or (c)(7) for the continuous moisture monitoring system are completed no later than the following dates:
(1) April 1, 2000, for a unit that is existing and has commenced commercial operation by January 2, 2000;
(2) For a new affected unit which has not commenced commercial operation by January 2, 2000, 90 unit operating days or 180 calendar days (whichever occurs first) after the date the unit commences commercial operation; or
(3) For an existing unit that is shutdown and is not yet operating by April 1, 2000, 90 unit operating days or 180 calendar days (whichever occurs first) after the date that the unit recommences commercial operation.
(j) If the certification tests required under paragraph (b) or (c) of this section have not been completed by the applicable compliance date, the owner or operator shall determine and report SO 2 concentration, NO X emission rate, CO 2 concentration, and flow rate data for all unit operating hours after the applicable compliance date in this paragraph until all required certification tests are successfully completed using either:
(1) The maximum potential concentration of SO 2 , as defined in section 2.1.1.1 of appendix A to this part, the maximum potential NO X emission rate, as defined in § 72.2 of this chapter, the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to this part, or the maximum potential CO 2 concentration, as defined in section 2.1.3.1 of appendix A to this part;
(2) Reference methods under § 75.22(b); or
(3) Another procedure approved by the Administrator pursuant to a petition under § 75.66.
§ 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 , NO X or CO 2 to the atmosphere without accounting for all such emissions in accordance with the provisions of §§ 75.10 through 75.19.
(e) No owner or operator of an affected unit shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording SO 2 , NO X , or CO 2 emissions discharged to the atmosphere, except for periods of recertification, or periods when calibration, quality assurance, or maintenance is performed pursuant to § 75.21 and appendix B of this part.
(f) No owner or operator of an affected unit shall retire or permanently discontinue use of the continuous emission monitoring system, any component thereof, the continuous opacity monitoring system, or any other approved emission monitoring system under this part, except under any one of the following circumstances:
(1) During the period that the unit is covered by an approved retired unit exemption under § 72.8 of this chapter that is in effect; or
(2) The owner or operator is monitoring emissions from the unit with another certified monitoring system or an excepted methodology approved by the Administrator for use at that unit that provides emissions data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(3) The designated representative submits notification of the date of recertification testing of a replacement monitoring system in accordance with §§ 75.20 and 75.61, and the owner or operator recertifies thereafter a replacement monitoring system in accordance with § 75.20.
§ 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. The materials are available for purchase at the corresponding address noted below and are available for inspection at the Public Information Reference Unit of the U.S. EPA, 401 M St., SW., Washington, DC and at the Library (MD-35), U.S. EPA, Research Triangle Park, North Carolina or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.
(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 postings for Sections 1, 2, 3, 4, Appendices, Spreadsheets, and the “Read before downloading Section 2” revision posted August 27, 1999): EPA-600/R-97/121, EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards, September 1997, as amended August 25, 1999, U.S. Environmental Protection Agency, for § 75.21, and appendix A to this part.
§§ 75.7-75.8   [Reserved]
§ 75.10   General operating requirements.
(a) Primary Measurement Requirement. The owner or operator shall measure opacity, and all SO 2 , NO X , and CO 2 emissions for each affected unit as follows:
(1) To determine SO 2 emissions, the owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a SO 2 continuous emission monitoring system and a flow monitoring system with an automated data acquisition and handling system for measuring and recording SO 2 concentration (in ppm), volumetric gas flow (in scfh), and SO 2 mass emissions (in lb/hr) discharged to the atmosphere, except as provided in §§ 75.11 and 75.16 and subpart E of this part;
(2) To determine NO X emissions, the owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a NO X -diluent continuous emission monitoring system (consisting of a NO X pollutant concentration monitor and an O 2 or CO 2 diluent gas monitor) with an automated data acquisition and handling system for measuring and recording NO X concentration (in ppm), O 2 or CO 2 concentration (in percent O 2 or CO 2 ) and NO X emission rate (in lb/mmBtu) discharged to the atmosphere, except as provided in §§ 75.12 and 75.17 and subpart E of this part. The owner or operator shall account for total NO X emissions, both NO and NO 2 , either by monitoring for both NO and NO 2 or by monitoring for NO only and adjusting the emissions data to account for NO 2 ;
(3) The owner or operator shall determine CO 2 emissions by using one of the following options, except as provided in § 75.13 and subpart E of this part:
(i) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a CO 2 continuous emission monitoring system and a flow monitoring system with an automated data acquisition and handling system for measuring and recording CO 2 concentration (in ppm or percent), volumetric gas flow (in scfh), and CO 2 mass emissions (in tons/hr) discharged to the atmosphere;
(ii) The owner or operator shall determine CO 2 emissions based on the measured carbon content of the fuel and the procedures in appendix G of this part to estimate CO 2 emissions (in ton/day) discharged to the atmosphere; or
(iii) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a flow monitoring system and a CO 2 continuous emission monitoring system that uses an O 2 concentration monitor to determine CO 2 emissions (according to the procedures in appendix F of this part) with an automated data acquisition and handling system for measuring and recording O 2 concentration (in percent), CO 2 concentration (in percent), volumetric gas flow (in scfh), and CO 2 mass emissions (in tons/hr) discharged to the atmosphere;
(4) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements in this part, a continuous opacity monitoring system with the automated data acquisition and handling system for measuring and recording the opacity of emissions (in percent opacity) discharged to the atmosphere, except as provided in §§ 75.14 and 75.18; and
(5) A single certified flow monitoring system may be used to meet the requirements of paragraphs (a)(1) and (a)(3) of this section. A single certified diluent monitor may be used to meet the requirements of paragraphs (a)(2) and (a)(3) of this section. A single automated data acquisition and handling system may be used to meet the requirements of paragraphs (a)(1) through (a)(4) of this section.
(b) Primary Equipment Performance Requirements. The owner or operator shall ensure that each continuous emission monitoring system required by this part meets the equipment, installation, and performance specifications in appendix A to this part; and is maintained according to the quality assurance and quality control procedures in appendix B to this part; and shall record SO 2 and NO X emissions in the appropriate units of measurement ( i.e. , lb/hr for SO 2 and lb/mmBtu for NO X ).
(c) Heat Input Rate Measurement Requirement. The owner or operator shall determine and record the heat input rate, in units of mmBtu/hr, to each affected unit for every hour or part of an hour any fuel is combusted following the procedures in appendix F to this part.
(d) Primary equipment hourly operating requirements. The owner or operator shall ensure that all continuous emission and opacity monitoring systems required by this part are in operation and monitoring unit emissions or opacity at all times that the affected unit combusts any fuel except as provided in § 75.11(e) and during periods of calibration, quality assurance, or preventive maintenance, performed pursuant to § 75.21 and appendix B of this part, periods of repair, periods of backups of data from the data acquisition and handling system, or recertification performed pursuant to § 75.20. The owner or operator shall also ensure, subject to the exceptions above in this paragraph, that all continuous opacity monitoring systems required by this part are in operation and monitoring opacity during the time following combustion when fans are still operating, unless fan operation is not required to be included under any other applicable Federal, State, or local regulation, or permit. The owner or operator shall ensure that the following requirements are met:
(1) The owner or operator shall ensure that each continuous emission monitoring system is capable of completing a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-min interval. The owner or operator shall reduce all SO 2 concentrations, volumetric flow, SO 2 mass emissions, CO 2 concentration, O 2 concentration, CO 2 mass emissions (if applicable), NO X concentration, and NO X emission rate data collected by the monitors to hourly averages. Hourly averages shall be computed using at least one data point in each fifteen minute quadrant of an hour, where the unit combusted fuel during that quadrant of an hour. Notwithstanding this requirement, an hourly average may be computed from at least two data points separated by a minimum of 15 minutes (where the unit operates for more than one quadrant of an hour) if data are unavailable as a result of the performance of calibration, quality assurance, or preventive maintenance activities pursuant to § 75.21 and appendix B of this part, or backups of data from the data acquisition and handling system, or recertification, pursuant to § 75.20. The owner or operator shall use all valid measurements or data points collected during an hour to calculate the hourly averages. All data points collected during an hour shall be, to the extent practicable, evenly spaced over the hour.
(2) The owner or operator shall ensure that each continuous opacity monitoring system is capable of completing a minimum of one cycle of sampling and analyzing for each successive 10-sec period and one cycle of data recording for each successive 6-min period. The owner or operator shall reduce all opacity data to 6-min averages calculated in accordance with the provisions of part 51, appendix M of this chapter, except where the applicable State implementation plan or operating permit requires a different averaging period, in which case the State requirement shall satisfy this Acid Rain Program requirement.
(3) Failure of an SO 2 , CO 2 , or O 2 emissions concentration monitor, NO X concentration monitor, flow monitor, moisture monitor, or NO X -diluent continuous emission monitoring system to acquire the minimum number of data points for calculation of an hourly average in paragraph (d)(1) of this section shall result in the failure to obtain a valid hour of data and the loss of such component data for the entire hour. For a NO X -diluent monitoring system, an hourly average NO X emission rate in lb/mmBtu is valid only if the minimum number of data points is acquired by both the NO X pollutant concentration monitor and the diluent monitor (O 2 or CO 2 ). For a moisture monitoring system consisting of one or more oxygen analyzers capable of measuring O 2 on a wet-basis and a dry-basis, an hourly average percent moisture value is valid only if the minimum number of data points is acquired for both the wet-and dry-basis measurements. If a valid hour of data is not obtained, the owner or operator shall estimate and record emissions, moisture, or flow data for the missing hour by means of the automated data acquisition and handling system, in accordance with the applicable procedure for missing data substitution in subpart D of this part.
(e) Optional backup monitor requirements. If the owner or operator chooses to use two or more continuous emission monitoring systems, each of which is capable of monitoring the same stack or duct at a specific affected unit, or group of units using a common stack, then the owner or operator shall designate one monitoring system as the primary monitoring system, and shall record this information in the monitoring plan, as provided for in § 75.53. The owner or operator shall designate the other monitoring system(s) as backup monitoring system(s) in the monitoring plan. The backup monitoring system(s) shall be designated as redundant backup monitoring system(s), non-redundant backup monitoring system(s), or reference method backup system(s), as described in § 75.20(d). When the certified primary monitoring system is operating and not out-of-control as defined in § 75.24, only data from the certified primary monitoring system shall be reported as valid, quality-assured data. Thus, data from the backup monitoring system may be reported as valid, quality-assured data only when the backup is operating and not out-of-control as defined in § 75.24 (or in the applicable reference method in appendix A of part 60 of this chapter) and when the certified primary monitoring system is not operating (or is operating but out-of-control). A particular monitor may be designated both as a certified primary monitor for one unit and as a certified redundant backup monitor for another unit.
(f) Minimum measurement capability requirement. The owner or operator shall ensure that each continuous emission monitoring system is capable of accurately measuring, recording, and reporting data, and shall not incur an exceedance of the full scale range, except as provided in sections 2.1.1.5, 2.1.2.5, and 2.1.4.3 of appendix A to this part.
(g) Minimum recording and recordkeeping requirements. The owner or operator shall record and the designated representative shall report the hourly, daily, quarterly, and annual information collected under the requirements of this part as specified in subparts F and G of this part.
§ 75.11   Specific provisions for monitoring SO2emissions.
(a) Coal-fired units. The owner or operator shall meet the general operating requirements in § 75.10 for an SO 2 continuous emission monitoring system and a flow monitoring system for each affected coal-fired unit while the unit is combusting coal and/or any other fuel, except as provided in paragraph (e) of this section, in § 75.16, and in subpart E of this part. During hours in which only gaseous fuel is combusted in the unit, the owner or operator shall comply with the applicable provisions of paragraph (e)(1), (e)(2), or (e)(3) of this section.
(b) Moisture correction. Where SO 2 concentration is measured on a dry basis, the owner or operator shall either:
(1) Report the appropriate fuel-specific default moisture value for each unit operating hour, selected from among the following: 3.0%, for anthracite coal; 6.0% for bituminous coal; 8.0% for sub-bituminous coal; 11.0% for lignite coal; 13.0% for wood 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 mass emissions (in lb/hr) using the procedures in appendix F to this part. The following continuous moisture monitoring systems are acceptable: a continuous moisture sensor; an oxygen analyzer (or analyzers) capable of measuring O 2 both on a wet basis and on a dry basis; or a stack temperature sensor and a moisture look-up table, i.e., a psychrometric chart (for saturated gas streams following wet scrubbers or other demonstrably saturated gas streams, only). The moisture monitoring system shall include as a component the automated data acquisition and handling system (DAHS) for recording and reporting both the raw data (e.g., hourly average wet-and dry-basis O 2 values) and the hourly average values of the stack gas moisture content derived from those data. When a moisture look-up table is used, the moisture monitoring system shall be represented as a single component, the certified DAHS, in the monitoring plan for the unit or common stack.
(c) Unit with no location for a flow monitor meeting siting requirements. Where no location exists that satisfies the minimum physical siting criteria in appendix A to this part for installation of a flow monitor in either the stack or the ducts serving an affected unit or installation of a flow monitor in either the stack or ducts is demonstrated to the satisfaction of the Administrator to be technically infeasible, either:
(1) The designated representative shall petition the Administrator for an alternative method for monitoring volumetric flow in accordance with § 75.66; or
(2) The owner or operator shall construct a new stack or modify existing ductwork to accommodate the installation of a flow monitor, and the designated representative shall petition the Administrator for an extension of the required certification date given in § 75.4 and approval of an interim alternative flow monitoring methodology in accordance with § 75.66. The Administrator may grant existing Phase I affected units an extension to January 1, 1995, and existing Phase II affected units an extension to January 1, 1996 for the submission of the certification application for the purpose of constructing a new stack or making substantial modifications to ductwork for installation of a flow monitor; or
(3) The owner or operator shall install a flow monitor in any existing location in the stack or ducts serving the affected unit at which the monitor can achieve the performance specifications of this part.
(d) Gas-fired and oil-fired units. The owner or operator of an affected unit that qualifies as a gas-fired or oil-fired unit, as defined in § 72.2 of this chapter, based on information submitted by the designated representative in the monitoring plan, shall measure and record SO 2 emissions:
(1) By meeting the general operating requirements in § 75.10 for an SO 2 continuous emission monitoring system and flow monitoring system. If this option is selected, the owner or operator shall comply with the applicable provisions in paragraph (e)(1), (e)(2), or (e)(3) of this section during hours in which the unit combusts only gaseous fuel;
(2) By providing other information satisfactory to the Administrator using the applicable procedures specified in appendix D to this part for estimating hourly SO 2 mass emissions; or
(3) By using the low mass emissions excepted methodology in § 75.19(c) for estimating hourly SO 2 mass emissions if the affected unit qualifies as a low mass emissions unit under § 75.19(a) and (b). If this option is selected for SO 2 , the LME methodology must also be used for NO X and CO 2 when these parameters are required to be monitored by applicable program(s).
(e) Special considerations during the combustion of gaseous fuels. The owner or operator of an affected unit that uses a certified flow monitor and a certified diluent gas (O 2 or CO 2 ) monitor to measure the unit heat input rate shall, during any hours in which the unit combusts only gaseous fuel, determine SO 2 emissions in accordance with paragraph (e)(1) or (e)(3) of this section, as applicable.
(1) If the gaseous fuel qualifies for a default SO 2 emission rate under Section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix D to this part, the owner or operator may determine SO 2 emissions by using Equation F-23 in appendix F to this part. Substitute into Equation F-23 the hourly heat input, calculated using the certified flow monitoring system and the certified diluent monitor (according to the applicable equation in section 5.2 of appendix F to this part), in conjunction with the appropriate default SO 2 emission rate from section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix D to this part. When this option is chosen, the owner or operator shall perform the necessary data acquisition and handling system tests under § 75.20(c), and shall meet all quality control and quality assurance requirements in appendix B to this part for the flow monitor and the diluent monitor; or
(2) [Reserved]
(3) The owner or operator may determine SO 2 mass emissions by using a certified SO 2 continuous monitoring system, in conjunction with the certified flow rate monitoring system. However, if the gaseous fuel is very low sulfur fuel (as defined in § 72.2 of this chapter), the SO 2 monitoring system shall meet the following quality assurance provisions when the very low sulfur fuel is combusted:
(i) When conducting the daily calibration error tests of the SO 2 monitoring system, as required by section 2.1.1 in appendix B of this part, the zero-level calibration gas shall have an SO 2 concentration of 0.0 percent of span. This restriction does not apply if gaseous fuel is burned in the affected unit only during unit startup.
(ii) EPA recommends that the calibration response of the SO 2 monitoring system be adjusted, either automatically or manually, in accordance with the procedures for routine calibration adjustments in section 2.1.3 of appendix B to this part, whenever the zero-level calibration response during a required daily calibration error test exceeds the applicable performance specification of the instrument in section 3.1 of appendix A to this part ( i.e. , ±2.5 percent of the span value or ±5 ppm, whichever is less restrictive).
(iii) Any bias-adjusted hourly average SO 2 concentration of less than 2.0 ppm recorded by the SO 2 monitoring system shall be adjusted to a default value of 2.0 ppm, for reporting purposes. Such adjusted hourly averages shall be considered to be quality-assured data, provided that the monitoring system is operating and is not out-of-control with respect to any of the quality assurance tests required by appendix B of this part ( i.e. , daily calibration error, linearity and relative accuracy test audit).
(iv) In accordance with the requirements of section 2.1.1.2 of appendix A to this part, for units that sometimes burn gaseous fuel that is very low sulfur fuel (as defined in § 72.2 of this chapter) and at other times burn higher sulfur fuel(s) such as coal or oil, a second low-scale SO 2 measurement range is not required when the very low sulfur gaseous fuel is combusted. For units that burn only gaseous fuel that is very low sulfur fuel and burn no other type(s) of fuel(s), the owner or operator shall set the span of the SO 2 monitoring system to a value no greater than 200 ppm.
(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 emission rate for each fuel, mixture or combination, and if the Administrator approves the petition.
(f) Other units. The owner or operator of an affected unit that combusts wood, refuse, or other material in addition to oil or gas shall comply with the monitoring provisions for coal-fired units specified in paragraph (a) of this section, except where the owner or operator has an approved petition to use the provisions of paragraph (e)(1) of this section.
§ 75.12   Specific provisions for monitoring NOXemission rate.
(a) Coal-fired units, gas-fired nonpeaking units or oil-fired nonpeaking units. The owner or operator shall meet the general operating requirements in § 75.10 of this part for a NO X continuous emission monitoring system (CEMS) for each affected coal-fired unit, gas-fired nonpeaking unit, or oil-fired nonpeaking unit, except as provided in paragraph (d) of this section, § 75.17, and subpart E of this part. The diluent gas monitor in the NO X -diluent CEMS may measure either O 2 or CO 2 concentration in the flue gases.
(b) Moisture correction. If a correction for the stack gas moisture content is needed to properly calculate the NO X emission rate in lb/mmBtu, e.g., if the NO X pollutant concentration monitor measures on a different moisture basis from the diluent monitor, the owner or operator shall either report a fuel-specific default moisture value for each unit operating hour, as provided in § 75.11(b)(1), or shall install, operate, maintain, and quality assure a continuous moisture monitoring system, as defined in § 75.11(b)(2). Notwithstanding this requirement, if Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is used to measure NO X emission rate, the following fuel-specific default moisture percentages shall be used in lieu of the default values specified in § 75.11(b)(1): 5.0%, for anthracite coal; 8.0% for bituminous coal; 12.0% for sub-bituminous coal; 13.0% for lignite coal; 15.0% for wood and 18.0% for natural gas (boilers, only).
(c) Determination of NO X emission rate. The owner or operator shall calculate hourly, quarterly, and annual NO X emission rates (in lb/mmBtu) by combining the NO X concentration (in ppm), diluent concentration (in percent O 2 or CO 2 ), and percent moisture (if applicable) measurements according to the procedures in appendix F to this part.
(d) Gas-fired peaking units or oil-fired peaking units. The owner or operator of an affected unit that qualifies as a gas-fired peaking unit or oil-fired peaking unit, as defined in § 72.2 of this chapter, based on information submitted by the designated representative in the monitoring plan shall comply with one of the following:
(1) Meet the general operating requirements in § 75.10 for a NO X continuous emission monitoring system; or
(2) Provide information satisfactory to the Administrator using the procedure specified in appendix E of this part for estimating hourly NO X emission rate. However, if in the years after certification of an excepted monitoring system under appendix E of this part, a unit's operations exceed a capacity factor of 20 percent in any calendar year or exceed a capacity factor of 10.0 percent averaged over three years, the owner or operator shall install, certify, and operate a NO X -diluent continuous emission monitoring system no later than December 31 of the following calendar year. If the required CEMS has not been installed and certified by that date, the owner or operator shall report the maximum potential NO X emission rate (MER) (as defined in § 72.2 of this chapter) for each unit operating hour, starting with the first unit operating hour after the deadline and continuing until the CEMS has been provisionally certified.
(e) Low mass emissions units. Notwithstanding the requirements of paragraphs (a) and (d) of this section, the owner or operator of an affected unit that qualifies as a low mass emissions unit under § 75.19(a) and (b) shall comply with one of the following:
(1) Meet the general operating requirements in § 75.10 for a NO X continuous emission monitoring system;
(2) Meet the requirements specified in paragraph (d)(2) of this section for using the excepted monitoring procedures in appendix E to this part, if applicable; or
(3) Use the low mass emissions excepted methodology in § 75.19(c) for estimating hourly NO X emission rate and hourly NO X mass emissions, if applicable under § 75.19(a) and (b). If this option is selected for NO X , the LME methodology must also be used for SO 2 and CO 2 when these parameters are required to be monitored by applicable program(s).
(f) Other units. The owner or operator of an affected unit that combusts wood, refuse, or other material in addition to oil or gas shall comply with the monitoring provisions specified in paragraph (a) of this section.
§ 75.13   Specific provisions for monitoring CO2emissions.
(a) CO 2 continuous emission monitoring system. If the owner or operator chooses to use the continuous emission monitoring method, then the owner or operator shall meet the general operating requirements in § 75.10 for a CO 2 continuous emission monitoring system and flow monitoring system for each affected unit. The owner or operator shall comply with the applicable provisions specified in §§ 75.11(a) through (e) or § 75.16, except that the phrase “CO 2 continuous emission monitoring system” shall apply rather than “SO 2 continuous emission monitoring system,” the phrase “CO 2 concentration” shall apply rather than “SO 2 concentration,” the term “maximum potential concentration of CO 2 ” shall apply rather than “maximum potential concentration of SO 2 ,” and the phrase “CO 2 mass emissions” shall apply rather than “SO 2 mass emissions.”
(b) Determination of CO 2 emissions using appendix G to this part. If the owner or operator chooses to use the appendix G method, then the owner or operator shall follow the procedures in appendix G to this part for estimating daily CO 2 mass emissions based on the measured carbon content of the fuel and the amount of fuel combusted. For units with wet flue gas desulfurization systems or other add-on emissions controls generating CO 2 , the owner or operator shall use the procedures in appendix G to this part to estimate both combustion-related emissions based on the measured carbon content of the fuel and the amount of fuel combusted and sorbent-related emissions based on the amount of sorbent injected. The owner or operator shall calculate daily, quarterly, and annual CO 2 mass emissions (in tons) in accordance with the procedures in appendix G to this part.
(c) Determination of CO 2 mass emissions using an O 2 monitor according to appendix F to this part. If the owner or operator chooses to use the appendix F method, then the owner or operator shall determine hourly CO 2 concentration and mass emissions with a flow monitoring system; a continuous O 2 concentration monitor; fuel F and F c factors; and, where O 2 concentration is measured on a dry basis (or where Equation F-14b in appendix F to this part is used to determine CO 2 concentration), either, a continuous moisture monitoring system, as specified in § 75.11(b)(2), or a fuel-specific default moisture percentage (if applicable), as defined in § 75.11(b)(1); and by using the methods and procedures specified in appendix F to this part. For units using a common stack, multiple stack, or bypass stack, the owner or operator may use the provisions of § 75.16, except that the phrase “CO 2 continuous emission monitoring system” shall apply rather than “SO 2 continuous emission monitoring system,” the term “maximum potential concentration of CO 2 ” shall apply rather than “maximum potential concentration of SO 2 ,” and the phrase “CO 2 mass emissions” shall apply rather than “SO 2 mass emissions.”
(d) Determination of CO 2 mass emissions from low mass emissions units. The owner or operator of a unit that qualifies as a low mass emissions unit under § 75.19(a) and (b) shall comply with one of the following:
(1) Meet the general operating requirements in § 75.10 for a CO 2 continuous emission monitoring system and flow monitoring system;
(2) Meet the requirements specified in paragraph (b) or (c) of this section for use of the methods in appendix G or F to this part, respectively; or
(3) Use the low mass emissions excepted methodology in § 75.19(c) for estimating hourly CO 2 mass emissions, if applicable under § 75.19(a) and (b). If this option is selected for CO 2 , the LME methodology must also be used for NO X and SO 2 when these parameters are required to be monitored by applicable program(s).
§ 75.14   Specific provisions for monitoring opacity.
(a) Coal-fired units and oil-fired units. The owner or operator shall meet the general operating provisions in § 75.10 of this part for a continuous opacity monitoring system for each affected coal-fired or oil-fired unit, except as provided in paragraphs (b), (c), and (d) of this section and in § 75.18. Each continuous opacity monitoring system shall meet the design, installation, equipment, and performance specifications in Performance Specification 1 in appendix B to part 60 of this chapter. Any continuous opacity monitoring system previously certified to meet Performance Specification 1 shall be deemed certified for the purposes of this part.
(b) Unit with wet flue gas pollution control system. If the owner or operator can demonstrate that condensed water is present in the exhaust flue gas stream and would impede the accuracy of opacity measurements, then the owner or operator of an affected unit equipped with a wet flue gas pollution control system for SO 2 emissions or particulates is exempt from the opacity monitoring requirements of this part.
(c) Gas-fired units. The owner or operator of an affected unit that qualifies as gas-fired, as defined in § 72.2 of this chapter, based on information submitted by the designated representative in the monitoring plan is exempt from the opacity monitoring requirements of this part. Whenever a unit previously categorized as a gas-fired unit is recategorized as another type of unit by changing its fuel mix, the owner or operator shall install, operate, and certify a continuous opacity monitoring system as required by paragraph (a) of this section by December 31 of the following calendar year.
(d) Diesel-fired units and dual-fuel reciprocating engine units. The owner or operator of an affected diesel-fired unit or a dual-fuel reciprocating engine unit is exempt from the opacity monitoring requirements of this part.
(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.
§ 75.15   [Reserved]
§ 75.16   Special provisions for monitoring emissions from common, bypass, and multiple stacks for SO2emissions and heat input determinations.
(a) [Reserved]
(b) Common stack procedures. The following procedures shall be used when more than one unit uses a common stack:
(1) Unit utilizing common stack with other affected unit(s). When a Phase I or Phase II affected unit utilizes a common stack with one or more other Phase I or Phase II affected units, but no nonaffected units, the owner or operator shall either:
(i) Install, certify, operate, and maintain an SO 2 continuous emission monitoring system and flow monitoring system in the duct to the common stack from each affected unit; or
(ii) Install, certify, operate, and maintain an SO 2 continuous emission monitoring system and flow monitoring system in the common stack and combine emissions for the affected units for recordkeeping and compliance purposes.
(2) Unit utilizing common stack with nonaffected unit(s). When one or more Phase I or Phase II affected units utilizes a common stack with one or more nonaffected units, the owner or operator shall either:
(i) Install, certify, operate, and maintain an SO 2 continuous emission monitoring system and flow monitoring system in the duct to the common stack from each Phase I and Phase II unit; or
(ii) Install, certify, operate, and maintain an SO 2 continuous emission monitoring system and flow monitoring system in the common stack; and
(A) Designate the nonaffected units as opt-in units in accordance with part 74 of this chapter and combine emissions for recordkeeping and compliance purposes; or
(B) Install, certify, operate, and maintain an SO 2 continuous emission monitoring system and flow monitoring system in the duct from each nonaffected unit; determine SO 2 mass emissions from the affected units as the difference between SO 2 mass emissions measured in the common stack and SO 2 mass emissions measured in the ducts of the nonaffected units, not to be reported as an hourly average value less than zero; combine emissions for the Phase I and Phase II affected units for recordkeeping and compliance purposes; and calculate and report SO 2 mass emissions from the Phase I and Phase II affected units, pursuant to an approach approved by the Administrator, such that these emissions are not underestimated; or
(C) Record the combined emissions from all units as the combined SO 2 mass emissions for the Phase I and Phase II affected units for recordkeeping and compliance purposes; or
(D) Petition through the designated representative and provide information satisfactory to the Administrator on methods for apportioning SO 2 mass emissions measured in the common stack to each of the units using the common stack and on reporting the SO 2 mass emissions. The Administrator may approve such demonstrated substitute methods for apportioning and reporting SO 2 mass emissions measured in a common stack whenever the demonstration ensures that there is a complete and accurate accounting of all emissions regulated under this part and, in particular, that the emissions from any affected unit are not underestimated.
(c) Unit with bypass stack. Whenever any portion of the flue gases from an affected unit can be routed through a bypass stack so as to avoid the installed SO 2 continuous emission monitoring system and flow monitoring system, the owner or operator shall either:
(1) Install, certify, operate, and maintain separate SO 2 continuous emission monitoring systems and flow monitoring systems on the main stack and the bypass stack and calculate SO 2 mass emissions for the unit as the sum of the SO 2 mass emissions measured at the two stacks; or
(2) Monitor SO 2 mass emissions at the main stack using SO 2 and flow rate monitoring systems and measure SO 2 mass emissions at the bypass stack using the reference methods in § 75.22(b) for SO 2 and flow rate and calculate SO 2 mass emissions for the unit as the sum of the emissions recorded by the installed monitoring systems on the main stack and the emissions measured by the reference method monitoring systems; or
(3) Install, certify, operate, and maintain SO 2 and flow rate monitoring systems only on the main stack. If this option is chosen, report the following values for each hour during which emissions pass through the bypass stack: the maximum potential concentration of SO 2 as determined under section 2.1.1.1 of appendix A to this part (or, if available, the SO 2 concentration measured by a certified monitor located at the control device inlet may be reported instead), and the hourly volumetric flow rate value that would be substituted for the flow monitor installed on the main stack or flue under the missing data procedures in subpart D of this part if data from the flow monitor installed on the main stack or flue were missing for the hour. The maximum potential SO 2 concentration may be specific to the type of fuel combusted in the unit during the bypass ( see § 75.33(b)(5)). The option in this paragraph, (c)(3), may only be used if use of the bypass stack is limited to unit startup, emergency situations (e.g., malfunction of a flue gas desulfurization system), and periods of routine maintenance of the flue gas desulfurization system or maintenance on the main stack. If this option is chosen, it is not necessary to designate the exhaust configuration as a multiple stack configuration in the monitoring plan required under § 75.53, with respect to SO 2 or any other parameter that is monitored only at the main stack. Calculate SO 2 mass emissions for the unit as the sum of the emissions calculated with the substitute values and the emissions recorded by the SO 2 and flow monitoring systems installed on the main stack.
(d) Unit with multiple stacks or ducts. When the flue gases from an affected unit utilize two or more ducts feeding into two or more stacks (that may include flue gases from other affected or nonaffected units), or when the flue gases utilize two or more ducts feeding into a single stack and the owner or operator chooses to monitor in the ducts rather than the stack, the owner or operator shall either:
(1) Install, certify, operate, and maintain an SO 2 continuous emission monitoring system and flow monitoring system in each duct feeding into the stack or stacks and determine SO 2 mass emissions from each affected unit as the sum of the SO 2 mass emissions recorded for each duct; or
(2) Install, certify, operate, and maintain an SO 2 continuous emission monitoring system and flow monitoring system in each stack. Determine SO 2 mass emissions from each affected unit as the sum of the SO 2 mass emissions recorded for each stack. Notwithstanding the prior sentence, if another unit also exhausts flue gases to one or more of the stacks, the owner or operator shall also comply with the applicable common stack requirements of this section to determine and record SO 2 mass emissions from the units using that stack and shall calculate and report SO 2 mass emissions from the affected units and stacks, pursuant to an approach approved by the Administrator, such that these emissions are not underestimated.
(e) Heat input rate. The owner or operator of an affected unit using a common stack, bypass stack, or multiple stacks shall account for heat input rate according to the following:
(1) The owner or operator of an affected unit using a common stack, bypass stack, or multiple stack with a diluent monitor and a flow monitor on each stack may use the flow rate and diluent monitors to determine the heat input rate for the affected unit, using the procedures specified in paragraphs (b) through (d) of this section, except that the term “heat input rate” shall apply rather than “SO 2 mass emissions” or “emissions” and the phrase “a diluent monitor and a flow monitor” shall apply rather than “SO 2 continuous emission monitoring system and flow monitoring system.” The applicable equation in appendix F to this part shall be used to calculate the heat input rate from the hourly flow rate, diluent monitor measurements, and (if the equation in appendix F requires a correction for the stack gas moisture content) hourly moisture measurements. Notwithstanding the options for combining heat input rate in paragraph (b)(1)(ii) and (b)(2)(ii) of this section, the owner or operator of an affected unit with a diluent monitor and a flow monitor installed on a common stack to determine the combined heat input rate at the common stack shall also determine and report heat input rate to each individual unit, according to paragraph (e)(3) of this section.
(2) In the event that an owner or operator of a unit with a bypass stack does not install and certify a diluent monitor and flow monitoring system in a bypass stack, the owner or operator shall determine total heat input rate to the unit for each unit operating hour during which the bypass stack is used according to the missing data provisions for heat input rate under § 75.36 or the procedures for calculating heat input rate from fuel sampling and analysis in section 5.5 of appendix F to this part.
(3) The owner or operator of an affected unit with a diluent monitor and a flow monitor installed on a common stack to determine heat input rate at the common stack may choose to apportion the heat input rate from the common stack to each affected unit utilizing the common stack by using either of the following two methods, provided that all of the units utilizing the common stack are combusting fuel with the same F-factor found in section 3 of appendix F of this part. The heat input rate may be apportioned either by using the ratio of load (in MWe) for each individual unit to the total load for all units utilizing the common stack or by using the ratio of steam 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 mass emission reduction program must also meet the requirements for monitoring heat input rate in §§ 75.71, 75.72 and 75.75.
§ 75.17   Specific provisions for monitoring emissions from common, bypass, and multiple stacks for NOXemission rate.
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 mass emission reduction program must also meet the provisions for monitoring NO X emission rate in §§ 75.71 and 75.72.
(a) Unit utilizing common stack with other affected unit(s). When an affected unit utilizes a common stack with one or more affected units, but no nonaffected units, the owner or operator shall either:
(1) Install, certify, operate, and maintain a NO X continuous emission monitoring system in the duct to the common stack from each affected unit; or
(2) Install, certify, operate, and maintain a NO X continuous emission monitoring system in the common stack and follow the appropriate procedure in paragraphs (a)(2) (i) through (iii) of this section, depending on whether or not the units are required to comply with a NO X emission limitation (in lb/mmBtu, annual average basis) pursuant to section 407(b) of the Act (referred to hereafter as “NO X emission limitation”).
(i) When each of the affected units has a NO X emission limitation, the designated representative shall submit a compliance plan to the Administrator that indicates:
(A) Each unit will comply with the most stringent NO X emission limitation of any unit utilizing the common stack; or
(B) Each unit will comply with the applicable NO X emission limitation by averaging its emissions with the other unit(s) utilizing the common stack, pursuant to the emissions averaging plan submitted under part 76 of this chapter; or
(C) Each unit's compliance with the applicable NO X emission limit will be determined by a method satisfactory to the Administrator for apportioning to each of the units the combined NO X emission rate (in lb/mmBtu) measured in the common stack and for reporting the NO X emission rate, as provided in a petition submitted by the designated representative. The Administrator may approve such demonstrated substitute methods for apportioning and reporting NO X emission rate measured in a common stack whenever the demonstration ensures that there is a complete and accurate estimation of all emissions regulated under this part and, in particular, that the emissions from any unit with a NO X emission limitation are not underestimated.
(ii) When none of the affected units has a NO X emission limitation, the owner or operator and the designated representative have no additional obligations pursuant to section 407 of the Act and may record and report a combined NO X emission rate (in lb/mmBtu) for the affected units utilizing the common stack.
(iii) When at least one of the affected units has a NO X emission limitation and at least one of the affected units does not have a NO X emission limitation, the owner or operator shall either:
(A) Install, certify, operate, and maintain NO X and diluent monitors in the ducts from the affected units; or
(B) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined NO X emission rate (in lb/mmBtu) measured in the common stack on each of the units. The Administrator may approve such demonstrated substitute methods for apportioning the combined NO X emission rate measured in a common stack whenever the demonstration ensures complete and accurate estimation of all emissions regulated under this part.
(b) Unit utilizing common stack with nonaffected unit(s). When one or more affected units utilizes a common stack with one or more nonaffected units, the owner or operator shall either:
(1) Install, certify, operate, and maintain a NO X -diluent continuous emission monitoring system in the duct from each affected unit; or
(2) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined NO X emission rate (in lb/mmBtu) measured in the common stack for each of the units. The Administrator may approve such demonstrated substitute methods for apportioning the combined NO X emission rate measured in a common stack whenever the demonstration ensures complete and accurate estimation of all emissions regulated under this part.
(c) Unit with multiple stacks or ducts. When the flue gases from an affected unit discharge to the atmosphere through two or more stacks or when flue gases from an affected unit utilize two or more ducts feeding into a single stack and the owner or operator chooses to monitor in the ducts rather than the stack, the owner or operator shall monitor the NO X emission rate in a way that is representative of each affected unit. Where another unit also exhausts flue gases to one or more of the stacks where monitoring systems are installed, the owner or operator shall also comply with the applicable common stack monitoring requirements of this section. The owner or operator shall either:
(1) Install, certify, operate, and maintain a NO X -diluent continuous emission monitoring system and a flow monitoring system in each stack or duct and determine the NO X emission rate for the unit as the Btu-weighted average of the NO X emission rates measured in the stacks or ducts using the heat input estimation procedures in appendix F to this part. Alternatively, for units that are eligible to use the procedures of appendix D to this part, the owner or operator may monitor heat input and NO X emission rate at the unit level, in lieu of installing flow monitors on each stack or duct. If this alternative unit-level monitoring is performed, report, for each unit operating hour, the highest emission rate measured by any of the NO X -diluent monitoring systems installed on the individual stacks or ducts as the hourly NO X emission rate for the unit, and report the hourly unit heat input as determined under appendix D to this part. Also, when this alternative unit-level monitoring is performed, the applicable NO X missing data procedures in §§ 75.31 or 75.33 shall be used for each unit operating hour in which a quality-assured NO X emission rate is not obtained for one or more of the individual stacks or ducts; or
(2) Provided that the products of combustion are well-mixed, install, certify, operate, and maintain a NO X continuous emission monitoring system in one stack or duct from the affected unit and record the monitored value as the NO X emission rate for the unit. The owner or operator shall account for NO X emissions from the unit during all times when the unit combusts fuel. Therefore, this option shall not be used if the monitored stack or duct can be bypassed ( e.g., by using dampers). Follow the procedure in § 75.17(d) for units with bypass stacks. Further, this option shall not be used unless the monitored NO X emission rate truly represents the NO X emissions discharged to the atmosphere ( e.g., the option is disallowed if there are any additional NO X emission controls downstream of the monitored location).
(d) Unit with a main stack and bypass stack configuration. For an affected unit with a discharge configuration consisting of a main stack and a bypass stack, the owner or operator shall either:
(1) Follow the procedures in paragraph (c)(1) of this section; or
(2) Install, certify, operate, and maintain a NO X -diluent CEMS only on the main stack. If this option is chosen, it is not necessary to designate the exhaust configuration as a multiple stack configuration in the monitoring plan required under § 75.53, with respect to NO X or any other parameter that is monitored only at the main stack. For each unit operating hour in which the bypass stack is used and the emissions are either uncontrolled (or the add-on controls are not documented to be operating properly), report the maximum potential NO X emission rate (as defined in § 72.2 of this chapter). The maximum potential NO X emission rate may be specific to the type of fuel combusted in the unit during the bypass (see § 75.33(c)(8)). Alternatively, for a unit with NO X add-on emission controls, for each unit operating hour in which the bypass stack is used and the add-on NO X emission controls are not bypassed, the owner or operator may report the maximum controlled NO X emission rate (MCR) instead of the maximum potential NO X emission rate provided that the add-on controls are documented to be operating properly, as described in the quality assurance/quality control program for the unit, required by section 1 in appendix B of this part. To provide the necessary documentation, the owner or operator shall record parametric data to verify the proper operation of the NO X add-on emission controls as described in § 75.34(d). Furthermore, the owner or operator shall calculate the MCR using the procedure described in section 2.1.2.1(b) of appendix A to this part where the words “maximum potential NO X emission rate (MER)” shall apply instead of the words “maximum controlled NO X emission rate (MCR)” and by using the NO X MEC in the calculations instead of the NO X MPC.
§ 75.18   Specific provisions for monitoring emissions from common and by-pass stacks for opacity.
(a) Unit using common stack. When an affected unit utilizes a common stack with other affected units or nonaffected units, the owner or operator shall comply with the applicable monitoring provision in this paragraph, as determined by existing Federal, State, or local opacity regulations.
(1) Where another regulation requires the installation of a continuous opacity monitoring system upon each affected unit, the owner or operator shall install, certify, operate, and maintain a continuous opacity monitoring system meeting Performance Specification 1 in appendix B to part 60 of this chapter (referred to hereafter as a “certified continuous opacity monitoring system”) upon each unit.
(2) Where another regulation does not require the installation of a continuous opacity monitoring system upon each affected unit, and where the affected source is not subject to any existing Federal, State, or local opacity regulations, the owner or operator shall install, certify, operate, and maintain a certified continuous opacity monitoring system upon each common stack for the combined effluent.
(b) Unit using bypass stack. Where any portion of the flue gases from an affected unit can be routed so as to bypass the installed continuous opacity monitoring system, the owner or operator shall install, certify, operate, and maintain a certified continuous opacity monitoring system on each bypass stack flue, duct, or stack gas stream unless either:
(1) An applicable Federal, State, or local opacity regulation or permit exempts the unit from a requirement to install a continuous opacity monitoring system in the bypass stack; or
(2) A continuous opacity monitoring system is already installed and certified at the inlet of the add-on emissions controls.
(3) The owner or operator monitors opacity using method 9 of appendix A of part 60 of this chapter whenever emissions pass through the bypass stack. Method 9 shall be used in accordance with the applicable State regulations.
§ 75.19   Optional SO2, NOX, and CO2emissions calculation for low mass emissions (LME) units.
(a) Applicability and qualification. (1) For units that meet the requirements of this paragraph (a)(1) and paragraphs (a)(2) and (b) of this section, the low mass emissions (LME) excepted methodology in paragraph (c) of this section may be used in lieu of continuous emission monitoring systems or, if applicable, in lieu of methods under appendices D, E, and G to this part, for the purpose of determining unit heat input, NO X , SO 2 , and CO 2 mass emissions, and NO X emission rate under this part. If the owner or operator of a qualifying unit elects to use the LME methodology, it must be used for all parameters that are required to be monitored by the applicable program(s). For example, for an Acid Rain Program LME unit, the methodology must be used to estimate SO 2 , NO X , and CO 2 mass emissions, NO X emission rate, and unit heat input.
(i) A low mass emissions unit is an affected unit that is gas-fired, or oil-fired (as defined in § 72.2 of this chapter), and for which:
(A) An initial demonstration is provided, in accordance with paragraph (a)(2) of this section, which shows that the unit emits:
( 1 ) No more than 25 tons of SO 2 annually and less than 100 tons of NO X annually, for Acid Rain Program affected units. If the unit is also subject to the provisions of subpart H of this part, no more than 50 of the allowable annual tons of NO X may be emitted during the ozone season; or
( 2 ) Less than 100 tons of NO X annually and no more than 50 tons of NO X during the ozone season, for non-Acid Rain Program units subject to the provisions of subpart H of this part, for which the owner or operator reports emissions data on a year-round basis, in accordance with § 75.74(a) or § 75.74(b); or
( 3 ) No more than 50 tons of NO X per ozone season, for non-Acid Rain Program units subject to the provisions of subpart H of this part, for which the owner or operator reports emissions data only during the ozone season, in accordance with § 75.74(b); and
(B) An annual demonstration is provided thereafter, using one of the allowable methodologies in paragraph (c) of this section, showing that the low mass emissions unit continues to emit no more than the applicable number of tons of SO 2 and/or NO X specified in paragraph (a)(1)(i)(A) of this section.
(C) This paragraph, (a)(1)(i)(C), applies only to a unit that is subject to an SO 2 emission limitation under the Acid Rain Program, and that combusts a gaseous fuel other than pipeline natural gas or natural gas (as defined in § 72.2 of this chapter). The owner or operator of such a unit must quantify the sulfur content and variability of the gaseous fuel by performing the demonstration described in section 2.3.6 of appendix D to this part, in order for the unit to qualify for LME unit status. If the results of that demonstration show that the gaseous fuel qualifies under paragraph (b) of section 2.3.6 to use a default SO 2 emission rate to report SO 2 mass emissions under this part, the unit is eligible for LME unit status.
(ii) Each qualifying LME unit must start using the low mass emissions excepted methodology as follows:
(A) For a unit that reports emission data on a year-round basis, begin using the methodology in the first unit operating hour in the calendar year designated in the certification application as the first year that the methodology will be used; or
(B) For a unit that is subject to Subpart H of this part and that reports only during the ozone season according to § 75.74(c), begin using the methodology in the first unit operating hour in the ozone season designated in the certification application as the first ozone season that the methodology will be used.
(C) For a new or newly-affected unit, see paragraph (b)(4) of this section for additional guidance.
(2) A unit may initially qualify as a low mass emissions unit if the designated representative submits a certification application to use the LME methodology (as described in § 75.63(a)(1)(ii) and in this paragraph, (a)(2)) and the Administrator (or permitting authority, as applicable) certifies the use of such methodology. The certification application shall be submitted no later than 45 days prior to the date on which use of the low mass emissions methodology is expected to commence, and the application must contain:
(i) A statement identifying the projected date on which the LME methodology will first be used. The projected commencement date shall be consistent with paragraphs (a)(1)(ii) and (b)(4) of this section, as applicable; and
(ii) Either:
(A) Actual SO 2 and/or NO X mass emissions data (as applicable) for each of the three calendar years (or ozone seasons) prior to the calendar year in which the certification application is submitted demonstrating to the satisfaction of the Administrator or (if applicable) the permitting authority, that the unit emitted less than the applicable number of tons of SO 2 and/or NO X specified in paragraph (a)(1)(i)(A) of this section. For the purposes of this paragraph, (a)(2)(ii)(A), the required actual SO 2 or NO X mass emissions for each qualifying year or ozone season shall be determined using the SO 2 , NO X and heat input data reported to the Administrator in the electronic quarterly reports required under § 75.64 or under the Ozone Transport Commission (OTC) NO X Budget Trading Program. Notwithstanding this requirement, in the absence of such electronic reports, an estimate of the actual emissions for each of the previous three years (or ozone seasons) shall be provided, using either the maximum rated heat input methodology described in paragraph (c)(3)(i) of this section or procedures consistent with the long term fuel flow heat input methodology described in paragraph (c)(3)(ii) of this section, in conjunction with the appropriate SO 2 or NO X emission rate from paragraph (c)(1)(i) of this section for SO 2 , and paragraph (c)(1)(ii) or (c)(1)(iv) of this section for NO X . Alternatively, the initial estimate of the NO X emission rate may be based on historical emission test data that is representative of operation at normal load or historical data from a CEMS certified under part 60 of this chapter or under a state CEM program; or
(B) When the three full years (or ozone seasons) of actual SO 2 and NO X mass emissions data (or reliable estimates thereof) described under paragraph (a)(2)(ii)(A) of this section do not exist, the designated representative may submit an application to use the low mass emissions excepted methodology based upon a combination of actual historical SO 2 and NO X mass emissions data and projected SO 2 and NO X mass emissions, totaling three years (or ozone seasons). Except as provided in paragraph (a)(3) of this section, actual data must be used for any years (or ozone seasons) in which such data exists and projected data should be used for any remaining future years (or ozone seasons) needed to provide emissions data for three consecutive calendar years (or ozone seasons). For example, if a unit commenced operation two years ago, the designated representative may submit actual, historical data for the previous two years and one year of projected emissions for the current calendar year or, for a new unit, the designated representative may submit three years of projected emissions, beginning with the current calendar year. Any actual or projected annual emissions must demonstrate to the satisfaction of the Administrator that the unit will emit less than the applicable number of tons of SO 2 and/or NO X specified in paragraph (a)(1)(i)(A) of this section. Projected emissions shall be calculated using either the appropriate default emission rates from paragraphs (c)(1)(i) and (c)(1)(ii) of this section (or, alternatively for NO X , a conservative estimate of the NO X emission rate, as described in paragraph (a)(4) of this section), in conjunction with projections of unit operating hours or fuel type and fuel usage, according to one of the allowable calculation methodologies in paragraph (c) of this section; and
(iii) A description of the methodology from paragraph (c) of this section that will be used to demonstrate on-going compliance under paragraph (b) of this section; and
(iv) Appropriate documentation demonstrating that the unit is eligible to use projected emissions to qualify for LME status under paragraph (a)(3) of this section (if applicable).
(3) In the following circumstances, projected emissions for a future year (or years) may be used in lieu of the actual emissions data from one (or more) of the three years (or ozone seasons) preceding the year of the certification application:
(i) If the owner or operator takes an enforceable permit restriction on the number of annual or ozone season unit operating hours for the future year (or years), such that the unit will emit no more than the applicable number of tons of SO 2 and/or NO X specified in paragraph (a)(1)(i)(A) of this section; or
(ii) If the actual emissions for one (or more) of the three years (or ozone seasons) prior to the year of the certification application is not representative of the present and expected future emissions from the unit, because the owner or operator has recently installed emission controls on the unit.
(4) When the owner or operator elects to demonstrate initial LME qualification and on-going compliance using a fuel-and-unit-specific NO X emission rate in accordance with paragraph (c)(1)(iv) of this section, there will be instances (e.g., for a new or newly-affected unit) where it is not possible to determine that NO X emission rate prior to submitting the certification application. In such cases, if the generic default NO X emission rates in Table LM-2 of this section are inappropriately high for the unit, the owner or operator may use a more representative, but conservatively high estimate of the expected NO X emission rate, for the purposes of the initial monitoring plan submittal and to calculate the unit's projected annual or ozone season emissions under paragraph (a)(2)(ii)(B) of this section. For example, the NO X emission rate could, as described in paragraph (a)(2)(ii)(A) of this section, be estimated using historical CEM data or historical emission test data that is representative of operation at normal load. The NO X emission limit specified in the operating permit for the unit could also be used to estimate the NO X emission rate (except for units equipped with SCR or SNCR), or, consistent with paragraph (c)(1)(iv)(C)( 4 ) of this section, for a unit that uses SCR or SNCR to control NO X emissions, an estimated default NO X emission rate of 0.15 lb/mmBtu could be used. However, these estimated NO X emission rates may not be used for reporting purposes in the time period extending from the first hour in which the LME methodology is used to the date and hour on which the fuel-and-unit-specific NO X emission rate testing is completed. Rather, in that interval, the owner or operator shall either report the appropriate default NO X emission rate from Table LM-2, or shall report the maximum potential NO X emission rate, calculated in accordance with § 72.2 of this chapter and section 2.1.2.1 of appendix A to this part. Then, beginning with the first unit operating hour after completion of the tests, the appropriate default NO X emission rate(s) obtained from the fuel-and-unit-specific testing shall be used for emissions reporting.
(b) On-going qualification and disqualification. (1) Once a low mass emissions unit has qualified for and has started using the low mass emissions excepted methodology, an annual demonstration is required, showing that the unit continues to emit no more than the applicable number of tons of SO 2 and/or NO X specified in paragraph (a)(1)(i)(A) of this section. The calculation methodology used for the annual demonstration shall be the methodology described in the certification application under paragraph (a)(2)(iii) of this section.
(2) If any low mass emissions unit fails to provide the required annual demonstration under paragraph (b)(1) of this section, such that the calculated cumulative emissions for the unit exceed the applicable number of tons of SO 2 and/or NO X specified in paragraph (a)(1)(i)(A) of this section at the end of any calendar year or ozone season, then:
(i) The low mass emissions unit shall be disqualified from using the low mass emissions excepted methodology; and
(ii) The owner or operator of the low mass emissions unit shall install and certify monitoring systems that meet the requirements of §§ 75.11, 75.12, and 75.13, and shall report SO 2 (Acid Rain Program units, only), NO X , and CO 2 (Acid Rain Program units, only) emissions data and heat input data from such monitoring systems by December 31 of the calendar year following the year in which the unit exceeded the number of tons of SO 2 and/or NO X specified in paragraph (a)(1)(i)(A) of this section; and
(iii) If the required monitoring systems have not been installed and certified by the applicable deadline in paragraph (b)(2)(ii) of this section, the owner or operator shall report the following values for each unit 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 emissions, in lb/hr, calculated using the applicable default SO 2 emission rate from paragraph (c)(1)(i) of this section and the maximum potential hourly unit heat input; the CO 2 emissions, in tons/hr, calculated using the applicable default CO 2 emission rate from paragraph (c)(1)(iii) of this section and the maximum potential hourly unit heat input; and the maximum potential NO X emission rate, as defined in § 72.2 of this chapter.
(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 (Acid Rain Program units, only), NO X , and CO 2 (Acid Rain Program units, only) and flow (if necessary) monitoring systems that meet the requirements of §§ 75.11, 75.12, and 75.13 prior to a change to such fuel, and shall report emissions data from such monitoring systems beginning with the date and hour on which the new fuel is first combusted in the unit. If the required monitoring systems are not installed and certified prior to the fuel switch, the owner or operator shall report (as applicable) the maximum potential concentration of SO 2 , CO 2 and NO X , the maximum potential NO X emission rate, the maximum potential flowrate, the maximum potential hourly heat input and the maximum (or minimum, if appropriate) potential moisture percentage, from the date and hour of the fuel switch until the monitoring systems are certified or until probationary calibration error tests of the monitors are passed and the conditional data validation procedures in § 75.20(b)(3) begin to be used. All maximum and minimum potential values shall be specific to the new fuel and shall be determined in a manner consistent with section 2 of appendix A to this part and § 72.2 of this chapter. The owner or operator must notify the Administrator (or the permitting authority) in the case where a unit switches fuels without previously having installed and certified a SO 2 , NO X and CO 2 monitoring system meeting the requirements of §§ 75.11, 75.12, and 75.13.
(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 mass reduction program under subpart H of this part. For newly-affected units, the records in paragraph (c)(2) of this section shall be kept as follows:
(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 mass reduction program under subpart H of this part, begin keeping the records as of the first hour of unit operation following the date on which the unit becomes an affected unit;
(ii) Use these records to determine the cumulative heat input and SO 2 , CO 2 , and/or NO X mass emissions in order to continue to qualify as a low mass emissions unit; and
(iii) Determine the cumulative SO 2 and/or NO X mass emissions according to paragraph (c) of this section using the same procedures used after the certification deadline for the unit, for purposes of demonstrating eligibility to use the excepted methodology set forth in this section. For example, use the default emission rates in Tables LM-1, LM-2, and LM-3 of this section or use the fuel-and-unit-specific NO X emission rate determined according to paragraph (c)(1)(iv) of this section. For Acid Rain Program LME units, the Administrator will not count SO 2 mass emissions calculated for the period between commencement of commercial operation and the certification deadline for the unit under § 75.4 against SO 2 allowances to be held in the unit account.
(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 and/or NO X specified in paragraph (a)(1)(i)(A) of this section. Further, the designated representative or authorized account representative must certify in the application that the unit operation for the years or ozone seasons for which the emissions were monitored are representative of the projected future operation of the unit.
(c) Low mass emissions excepted methodology, calculations, and values —(1) 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 emission rate for use in calculating hourly SO 2 mass emissions under this section. Alternatively, for fuel oil combustion, a lower, fuel-specific SO 2 emission factor may be used in lieu of the applicable emission factor from Table LM-1, if a federally enforceable permit condition is in place that limits the sulfur content of the oil. If this alternative is chosen, the fuel-specific SO 2 emission rate in lb/mmBtu shall be calculated by multiplying the fuel sulfur content limit (weight percent sulfur) by 1.01. In addition, the owner or operator shall periodically determine the sulfur content of the oil combusted in the unit, using one of the oil sampling and analysis options described in section 2.2 of appendix D to this part, and shall keep records of these fuel sampling results in a format suitable for inspection and auditing. Alternatively, the required oil sampling and associated recordkeeping may be performed using a consensus standard (e.g., ASTM, API, etc.) that is prescribed in the unit's Federally-enforceable operating permit, in an applicable State regulation, or in another applicable Federal regulation. If the unit combusts gaseous fuel(s) other than natural gas, the owner or operator shall use the procedures in section 2.3.6 of appendix D to this part to document the total sulfur content of each such fuel and to determine the appropriate default SO2 emission rate for each such fuel.
(ii) If the unit combusts only natural gas and/or fuel oil, use either the appropriate NO X emission factor from Table LM-2 of this section, or a fuel-and-unit-specific NO X emission rate determined according to paragraph (c)(1)(iv) of this section, to calculate hourly NO X mass emissions under this section. If the unit combusts a gaseous fuel other than pipeline natural gas or natural gas, the owner or operator shall determine a fuel-and-unit-specific NO X emission rate according to paragraph (c)(1)(iv) of this section.
(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 emission rate for use in calculating hourly CO 2 mass emissions under this section (Acid Rain Program units, only). If the unit combusts a gaseous fuel other than pipeline natural gas or natural gas, the owner or operator shall determine a fuel-and-unit-specific CO 2 emission rate for the fuel, as follows:
(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 emission rate. Rearrange the equation, solving it for the ratio of W CO2 /H (this ratio will yield an emission rate, in units of tons/mmBtu). Then, substitute the carbon-based F-factor determined in paragraph (c)(1)(iii)(A) of this section into the rearranged equation to determine the default CO 2 emission rate for the unit.
(iv) In lieu of using the default NO X emission rate from Table LM-2 of this section, the owner or operator may, for each fuel combusted by a low mass emissions unit, determine a fuel-and-unit-specific NO X emission rate for the purpose of calculating NO X mass emissions under this section. This option may be used by any unit which qualifies to use the low mass emission excepted methodology under paragraph (a) of this section, and also by groups of units which combust fuel from a common source of supply and which use the long term fuel flow methodology under paragraph (c)(3)(ii) of this section to determine heat input. The testing must be completed in a timely manner, such that the test results are reported electronically no later than the end of the calendar year or ozone season in which the LME methodology is first used. If this option is chosen, the following procedures shall be used.
(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 emission rate by conducting a four load NO X emission rate test procedure as specified in section 2.1 of appendix E to this part, for each type of fuel combusted in the unit. For a group of units sharing a common fuel supply, the appendix E testing must be performed on each individual unit in the group, unless some or all of the units in the group belong to an identical group of units, as defined in paragraph (c)(1)(iv)(B) of this section, in which case, representative testing may be conducted on units in the identical group of units, as described in paragraph (c)(1)(iv)(B) of this section. For the purposes of this section, make the following modifications to the appendix E test procedures:
( 1 ) Do not measure the heat input as required under 2.1.3 of appendix E to this part.
( 2 ) Do not plot the test results as specified under 2.1.6 of appendix E to this part.
( 3 ) Do not correct the NO X concentration to 15% O 2 .
( 4 ) If the testing is performed on an uncontrolled diffusion flame turbine, a correction to the observed average NO X concentration from each run of the test must be applied using the following Equation LM-1a.
(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 ) To be considered identical, all low mass emission units must be of the same size (based on maximum rated hourly heat input), manufacturer and model, and must have the same history of modifications (e.g., have the same controls installed, the same types of burners and have undergone major overhauls at the same frequency (based on hours of operation)). Also, under similar operating conditions, the stack or turbine outlet temperature of each unit must be within ±50 degrees Fahrenheit of the average stack or turbine outlet temperature for all of the units.
( 2 ) If all of the low mass emission units in the group qualify as identical, then representative testing of the units in the group may be performed according to Table LM-4 of this section.
( 3 ) [Reserved]
( 4 ) If the acceptance criteria in paragraph (c)(1)(iv)(B)( 1 ) of this section are not met then the group of low mass emission units is not considered an identical group of units and individual appendix E testing of each unit is required.
( 5 ) Fuel and unit specific NO X emission rates determined according to paragraphs (c)(1)(iv)(F) and (c)(1)(iv)(G) of this section may be used in lieu of appendix E testing for one or more low mass emission units in a group of identical units.
(C) Based on the results of the part 75 appendix E testing, determine the fuel-and-unit-specific NO X emission rate as follows:
( 1 ) Except for LME units that use selective catalytic reduction (SCR) or selective non-catalytic reduction (SNCR) to control NO X emissions, the highest three-run average NO X emission rate obtained at any load in the appendix E test for a particular type of fuel shall be the fuel-and-unit-specific NO X emission rate, for that type of fuel.
( 2 ) [Reserved]
( 3 ) For a group of identical low mass emissions units (except for units that use SCR or SNCR to control NO X emissions), the fuel-and-unit-specific NO X emission rate for all units in the group, for a particular type of fuel, shall be the highest three-run average NO X emission rate obtained at any tested load from any unit tested in the group, for that type of fuel.
( 4 ) Except as provided in paragraphs (c)(1)(iv)(C)( 7 ) and (c)(1)(iv)(C)( 8 ) of this section, for an individual low mass emissions unit which uses SCR or SNCR to control NO X emissions, the fuel-and-unit-specific NO X emission rate for each type of fuel combusted in the unit shall be the higher of:
( i ) The highest three-run average emission rate from any load of the appendix E test for that type of fuel; or
( ii ) 0.15 lb/mmBtu.
( 5 ) [Reserved]
( 6 ) Except as provided in paragraphs (c)(1)(iv)(C)( 7 ) and (c)(1)(iv)(C)( 8 ) of this section, for a group of identical low mass emissions units that are all equipped with SCR or SNCR to control NO X emissions, the fuel-and-unit-specific NO X emission rate for each unit in the group of units, for a particular type of fuel, shall be the higher of:
( i ) The highest three-run average NO X emission rate at any load from all appendix E tests of all tested units in the group, for that type of fuel; or
( ii ) 0.15 lb/mmBtu.
( 7 ) Notwithstanding the requirements of paragraphs (c)(1)(iv)(C)( 4 ) and (c)(1)(iv)(C)( 6 ) of this section, for a unit (or group of identical units) equipped with SCR (or SNCR) and water (or steam) injection to control NO X emissions:
( i ) If the appendix E testing is performed when the water (or steam) injection is in use and either upstream of the SCR or SNCR or during a time period when the SCR or SNCR is out of service; then
( ii ) The highest three-run average emission rate from the appendix E testing may be used as the fuel-and-unit-specific NO X emission rate for the unit (or, if applicable, for each unit in the group), for each unit operating hour in which the water-to-fuel ratio is within the acceptable range established during the appendix E testing.
( 8 ) Notwithstanding the requirements of paragraphs (c)(1)(iv)(C)( 4 ) and (c)(1)(iv)(C)( 6 ) of this section, for a unit (or group of identical units) equipped with SCR (or SNCR) and uses dry low-NO X technology to control NO X emissions:
( i ) If the appendix E testing is performed during a time period when the dry low-NO X controls are in use, but the SCR or SNCR is out of service; then
( ii ) The highest three-run average emission rate from the appendix E testing may be used as the fuel-and-unit-specific NO X emission rate for the unit (or, if applicable, for each unit in the group), for each unit operating hour in which the parametric data described in paragraph (c)(1)(iv)(H)( 2 ) of this section demonstrate that the dry low-NO X controls are operating in the premixed or low-NO X mode.
( 9 ) For an individual combustion turbine (or a group of identical turbines) that operate principally at base load (or at a set point temperature), but are capable of operating at a higher peak load (or higher internal operating temperature), the fuel-and-unit-specific NO X emission rate for the unit (or for each unit in the group) shall be as follows:
( i ) If the testing is done only at base load, use the three-run average NO X emission rate for base load operating hours and 1.15 times that emission rate for peak load operating hours; or
( ii ) If the testing is done at both base load and peak load, use the three-run average NO X emission rate from the base load testing for base load operating hours and the three-run average NO X emission rate from the peak load testing for peak load operating hours.
(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 emission rate, the owner or operator shall determine a new fuel-and-unit-specific NO X emission rate every five years (20 calendar quarters), unless changes in the fuel supply, physical changes to the unit, changes in the manner of unit operation, or changes to the emission controls occur which may cause a significant increase in the unit's actual NO X emission rate. If such changes occur, the fuel-and-unit-specific NO X emission rate(s) shall be re-determined according to paragraph (c)(1)(iv) of this section. Testing shall be done at the number of loads specified in paragraph (c)(1)(iv)(A) or (c)(1)(iv)(I) of this section, as applicable. If a low mass emissions unit belongs to a group of identical units and it is required to retest to determine a new fuel-and-unit-specific NO X emission rate because of changes in the fuel supply, physical changes to the unit, changes in the manner of unit operation or changes to the emission controls occur which may cause a significant increase in the unit's actual NO X emission rate, any other unit in that group of identical units is not required to re-determine the fuel-and-unit-specific NO X emission rate unless such unit also undergoes changes in the fuel supply, physical changes to the unit, changes in the manner of unit operation or changes to the emission controls occur which may cause a significant increase in the unit's actual NO X emission rates.
(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 emission rate(s) are determined shall meet the quality assurance and quality control provisions of paragraph (e) of this section.
(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 emission rate(s). However, fuel-and-unit-specific NO X emission rates from historical testing may not be used longer than five years after the appendix E testing was conducted.
(G) Low mass emissions units for which at least 3 years of quality-assured NO X emission rate data from a NO X -diluent CEMS that meets the quality assurance requirements of either: this part, or appendix F to part 60 of this chapter, or a comparable State CEM program, and corresponding fuel usage data are available may determine fuel-and-unit-specific NO X emission rates from the actual data using the following procedure. Separate the actual NO X emission rate data into groups, according to the type of fuel combusted. Discard data from periods when multiple fuels were combusted. Each fuel-specific data set must contain at least 168 hours of data and must represent all normal operating ranges of the unit when combusting the fuel. Sort the data in each fuel-specific data set in ascending order according to NO X emission rate. Determine the 95th percentile NO X emission rate for each data set as defined in § 72.2 of this chapter. Use the 95th percentile value for each data set as the fuel-and-unit-specific NO X emission rate, except that for a unit that uses SCR or SNCR for NO X emission control, if the 95th percentile value is less than 0.15 lb/mmBtu, a value of 0.15 lb/mmBtu shall be used as the fuel-and-unit-specific NO X emission rate.
(H) For low mass emission units with add-on NO X emission controls, and for units that use dry low-NO X technology, the owner or operator shall, during every hour of unit operation during the test period, monitor and record parameters, as required under paragraph (e)(5) of this section, which indicate that the NO X emission controls are operating properly. After the test period, these same parameters shall be monitored and recorded and kept for all operating hours in order to determine whether the NO X controls are operating properly and to allow the determination of the correct NO X emission rate as required under paragraph (c)(1)(iv) of this section.
( 1 ) For low mass emission units with steam or water injection, the steam-to-fuel or water-to-fuel ratio used during the testing must be documented. The water-to-fuel or steam-to-fuel ratio must be maintained during unit operations for a unit to use the fuel and unit specific NO X emission rate determined during the test. Owners or operators must include in the monitoring plan the acceptable range of the water-to-fuel or steam-to-fuel ratio, which will be used to indicate hourly, proper operation of the NO X controls for each unit. The water-to-fuel or steam-to-fuel ratio shall be monitored and recorded during each hour of unit operation. If the water-to-fuel or steam-to-fuel ratio is not within the acceptable range in a given hour the fuel and unit specific NO X emission rate may not be used for that hour, and the appropriate default NO X emission rate from Table LM-2 shall be reported instead.
( 2 ) For a low mass emissions unit that uses dry low-NO X premix technology to control NO X emissions, proper operation of the emission controls means that the unit is in the low-NO X or premixed combustion mode, and fired with natural gas. Evidence of operation in the low-NO X or premixed mode shall be provided by monitoring the appropriate turbine operating parameters. These parameters may include percentage of full load, turbine exhaust temperature, combustion reference temperature, compressor discharge pressure, fuel and air valve positions, dynamic pressure pulsations, internal guide vane (IGV) position, and flame detection or flame scanner condition. The acceptable values and ranges for all parameters monitored shall be specified in the monitoring plan for the unit, and the parameters shall be monitored during each subsequent operating hour. If one or more of these parameters is not within the acceptable range or at an acceptable value in a given operating hour, the fuel-and-unit-specific NO X emission rate may not be used for that hour, and the appropriate default NO X emission rate from Table LM-2 shall be reported instead. When the unit is fired with oil the appropriate default value from Table LM-2 shall be reported.
( 3 ) For low mass emission units with other types of add-on NO X controls, appropriate parameters and the acceptable range of the parameters which indicate hourly proper operation of the NO X controls must be specified in the monitoring plan. These parameters shall be monitored during each subsequent operating hour. If any of these parameters are not within the acceptable range in a given operating hour, the fuel and unit specific NO X emission rates may not be used in that hour, and the appropriate default NO X emission rate from Table LM-2 shall be reported instead.
(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 emission rate for a unit (or for each unit in a group of identical units) may be performed at fewer than four loads, under the following circumstances:
( 1 ) Testing may be done at one load level if the data analysis described in paragraph (c)(1)(iv)(J) of this section is performed and the results show that the unit has operated (or all units in the group of identical units have operated) at a single load level for at least 85.0 percent of all operating hours in the previous three years (12 calendar quarters) prior to the calendar quarter of the appendix E testing. For combustion turbines that are operated to produce approximately constant output (in MW) but which use internal operating and exhaust temperatures and not the actual output in MW to control the operation of the turbine, the internal operating temperature set point may be used as a surrogate for load in demonstrating that the unit qualifies for single-load testing. If the data analysis shows that the unit does not qualify for single-load testing, testing may be done at two (or three) load levels if the unit has operated (or if all units in the group of identical units have operated) cumulatively at two (or three) load levels for at least 85.0 percent of all operating hours in the previous three years; or
( 2 ) If a multiple-load appendix E test was initially performed for a unit (or group of identical units) to determine the fuel-and-unit specific NO X emission rate, then the periodic retests required under paragraph (c)(1)(iv)(D) of this section may be single-load tests, performed at the load level for which the highest average NO X emission rate was obtained in the initial test.
( 3 ) The initial appendix E testing may be performed at a single load, between 75 and 100 percent of the maximum sustainable load defined in the monitoring plan for the unit, if the average annual capacity factor of the LME unit, when calculated according to the definition of “capacity factor” in § 72.2 of this chapter, is 2.5 percent or less for the three calendar years immediately preceding the year of the testing, and that the annual capacity factor does not exceed 4.0 percent in any of those three years. Similarly, for a LME unit that reports emissions data on an ozone season-only basis, the initial appendix E testing may be performed at a single load between 75 and 100 percent of the maximum sustainable load if the 2.5 and 4.0 percent capacity factor requirements are met for the three ozone seasons immediately preceding the date of the emission testing (see § 75.74(c)(11)). For a group of identical LME units, any unit(s) in the group that meet the 2.5 and 4.0 percent capacity factor requirements may perform the initial appendix E testing at a single load between 75 and 100 percent of the maximum sustainable load.
( 4 ) The retest of any LME unit may be performed at a single load between 75 and 100 percent of the maximum sustainable load if, for the three calendar years immediately preceding the year of the retest (or, if applicable, the three ozone seasons immediately preceding the date of the retest), the applicable capacity factor requirements described in paragraph (c)(1)(iv)(I)( 3 ) of this section are met.
( 5 ) Alternatively, for combustion turbines, the single-load testing described in paragraphs (c)(1)(iv)(I)( 3 ) and (c)(1)(iv)(I)( 4 ) of this section may be performed at the highest attainable load level corresponding to the season of the year in which the testing is conducted.
( 6 ) In all cases where the alternative single-load testing option described in paragraphs (c)(1)(iv)(I)( 3 ) through (c)(1)(iv)(I)( 5 ) of this section is used, the owner or operator shall keep records documenting that the required capacity factor requirements were met.
(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 ) or (c)(1)(iv)(J)( 2 ) of this section, as applicable.
( 1 ) Determine the range of operation of the unit, according to section 6.5.2.1 of appendix A to this part. Divide the range of operation into four equal load bands. For example, if the range of operation extends from 20 MW to 100 MW, the four equal load bands would be: band #1: from 20 MW to 40 MW; band #2: from 41 MW to 60 MW; band #3: from 61 MW to 80 MW; and band #4: from 81 to 100 MW. Then, perform a historical load analysis for all unit operating hours in the 12 calendar quarters preceding the quarter of the test. Alternatively, for sources that report emissions data only during the ozone season, the historical load analysis may be based on unit operation in the previous three ozone seasons, rather than unit operation in the previous 12 calendar quarters. Determine the percentage of the data that fall into each load band. For a unit that is not part of a group of identical units, if 85.0% or more of the data fall into one load band, single-load testing may be performed at any point within that load band. For a group of identical units, if each unit in the group meets the 85.0% criterion, then representative single-load testing within the load band may be performed. If the 85.0% criterion cannot be met to qualify for single-load testing but this criterion can be met cumulatively for two (or three) load levels, then testing may be performed at two (or three) loads instead of four.
( 2 ) For a combustion turbine that uses exhaust temperature and not the actual output in megawatts to control the operation of the turbine (or for a group of identical units of this type), the owner or operator must document that the unit (or each unit in the group) has operated within ±10% of the set point temperature for 85.0% of the operating hours in the previous 12 calendar quarters to qualify for single-load testing. Alternatively, for sources that report emissions data only during the ozone season, the historical set point temperature analysis may be based on unit operation in the previous three ozone seasons, rather than unit operation in the previous 12 calendar quarters. When the set point temperature is used rather than unit load to justify single-load testing, the designated representative shall certify in the monitoring plan for the unit that this is the normal manner of unit operation and shall document the setpoint temperature.
(2) Records of operating time, fuel usage, unit output and NO X emission control operating status. The owner or operator shall keep the following records on-site, for three years, in a form suitable for inspection, except that for unmanned facilities, the records may be kept at a central location, rather than on-site:
(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 emission controls of any kind and each unit that uses dry low-NO X technology, the owner or operator shall keep hourly records of the hourly value of the parameter(s) specified in (c)(1)(iv)(H) of this section used to indicate proper operation of the unit's NO X controls.
(3) Heat input. Hourly, quarterly and annual heat input for a low mass emissions unit shall be determined using either the maximum rated hourly heat input method under paragraph (c)(3)(i) of this section or the long term fuel flow method under paragraph (c)(3)(ii) of this section.
(i) Maximum rated hourly heat input method. (A) For the purposes of the mass emission calculation methodology of paragraph (c)(3) of this section, HI hr , the hourly heat input (mmBtu) to a low mass emissions unit shall be deemed to equal the maximum rated hourly heat input, as defined in § 72.2 of this chapter, multiplied by the operating time of the unit for each hour. The owner or operator may choose to record and report partial operating hours or may assume that a unit operated for a whole hour for each hour the unit operated. However, the owner or operator of a unit may petition the Administrator under § 75.66 for a lower value for maximum rated hourly heat input than that defined in § 72.2 of this chapter. The Administrator may approve such lower value if the owner or operator demonstrates that either the maximum hourly heat input specified by the manufacturer or the highest observed hourly heat input, or both, are not representative, and such a lower value is representative, of the unit's current capabilities because modifications have been made to the unit, limiting its capacity permanently.
(B) The quarterly heat input, HI qtr , in mmBtu, shall be determined using Equation LM-1:
(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. The owner or operator may, for the purpose of demonstrating that a low mass emissions unit or group of low mass emission units sharing a common fuel supply meets the requirements of this section, use records of long-term fuel flow, to calculate hourly heat input to a low mass emissions unit.
(A) This option may be used for a group of low mass emission units only if:
( 1 ) The low mass emission units combust fuel from a common source of supply; and
( 2 ) Records are kept of the total amount of fuel combusted by the group of low mass emission units and the hourly output (in megawatts or pounds of steam) from each unit in the group; and
( 3 ) All of the units in the group are low mass emission units.
(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 ) Fuel billing records (for low mass emission units, or groups of low mass emission units, which purchase fuel from non-affiliated sources);
( 2 ) 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 (Reaffirmed, March 2001); Section 4-Standard Practice for Level Measurement of Liquid Hydrocarbons on Marine Vessels by Automatic Tank Gauging, First Edition April 1995 (Reaffirmed, September 2000); 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; Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B, December 1961 (Reaffirmed August 1987, October 1992) (all incorporated by reference under § 75.6 of this part); or
( 3 ) A fuel flow meter certified and maintained according to appendix D to this part.
(C) Except as provided in paragraph (c)(3)(ii)(C)( 3 ) of this section, for each fuel combusted during a quarter, the gross calorific value of the fuel shall be determined by either:
( 1 ) Using the applicable procedures for gas and oil analysis in sections 2.2 and 2.3 of appendix D to this part. If this option is chosen the highest gross calorific value recorded during the previous calendar year shall be used (or, for a new or newly-affected unit, if there are no sample results from the previous year, use the highest GCV from the samples taken in the current year); or
( 2 ) Using the appropriate default gross calorific value listed in Table LM-5 of this section.
( 3 ) For gaseous fuels other than pipeline natural gas or natural gas, the GCV sampling frequency shall be daily unless the results of a demonstration under section 2.3.5 of appendix D to this part show that the fuel has a low GCV variability and qualifies for monthly sampling. If daily GCV sampling is required, use the highest GCV obtained in the calendar quarter as GCV max in Equation LM-3, of this section.
(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 ) Using the procedures in section 2.2.6 of appendix D to this part. If this option is chosen, use the highest specific gravity value recorded during the previous calendar year (or, for a new or newly-affected unit, if there are no sample results from the previous year, use the highest specific gravity from the samples taken in the current year); or
( 2 ) Using the appropriate default specific gravity value in Table LM-6 of this section.
(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.
(F) Use Eq. LM-4 to calculate HI qtr-total , the quarterly heat input (mmBtu) for all fuels. HI qtr-total shall be the sum of the HI fuel-qtr values determined using Equations LM-2 and LM-3.
(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 ) values for all calendar quarters in the year to date. 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 cumulative ozone season heat input shall be the sum of the quarterly heat input values for the second and third calendar quarters of the year.
(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.
(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 to each hour of unit operation using either Equation LM-7 or LM-8:
(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 to each hour of operation using either Equation LM-7a or LM-8a:
all-units loads (from Eq. LM-5) for all units in the group (MW).
all-units loads (from Eq. LM-6) for all units in the group (klb of steam/hr)
(4) Calculation of SO 2 , NO X and CO 2 mass emissions. The owner or operator shall, for the purpose of demonstrating that a low mass emissions unit meets the requirements of this section, calculate SO 2 , NO X and CO 2 mass emissions in accordance with the following.
(i) SO 2 mass emissions. (A) The hourly SO 2 mass emissions (lbs) for a low mass emissions unit (Acid Rain Program units, only) shall be determined using Equation LM-9 and the appropriate fuel-based SO 2 emission factor for the fuels combusted in that hour. If more than one fuel is combusted in the hour, use the highest emission factor for all of the fuels combusted in the hour. If records are missing as to which fuel was combusted in the hour, use the highest emission factor for all of the fuels capable of being combusted in the unit.
(B) The quarterly SO 2 mass emissions (tons) for the low mass emissions unit shall be the sum of all the hourly SO 2 mass emissions in the quarter, as determined under paragraph (c)(4)(i)(A) of this section, divided by 2000 lb/ton.
(C) The year-to-date cumulative SO 2 mass emissions (tons) for the low mass emissions unit shall be the sum of the quarterly SO 2 mass emissions, as determined under paragraph (c)(4)(i)(B) of this section, for all of the calendar quarters in the year to date.
(ii)(A) The hourly NO X mass emissions for the low mass emissions unit (lbs) shall be determined using Equation LM-10. If more than one fuel is combusted in the hour, use the highest emission rate for all of the fuels combusted in the hour. If records are missing as to which fuel was combusted in the hour, use the highest emission factor for all of the fuels capable of being combusted in the unit. For low mass emission units with NO X emission controls of any kind and for which a fuel-and-unit-specific NO X emission rate is determined under paragraph (c)(1)(iv) of this section, for any hour in which the parameters under paragraph (c)(1)(iv)(A) of this section do not show that the NO X emission controls are operating properly, use the NO X emission rate from Table LM-2 of this section for the fuel combusted during the hour with the highest NO X emission rate.
(B) The quarterly NO X mass emissions (tons) for the low mass emissions unit shall be the sum of all of the hourly NO X mass emissions in the quarter, as determined under paragraph (c)(4)(ii)(A) of this section, divided by 2000 lb/ton.
(C) The year-to-date cumulative NO X mass emissions (tons) for the low mass emissions unit shall be the sum of the quarterly NO X mass emissions, as determined under paragraph (c)(4)(ii)(B) of this section, for all of the calendar quarters in the year to date. 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 ozone season NO X mass emissions for the unit shall be the sum of the quarterly NO X mass emissions, as determined under paragraph (c)(4)(ii)(B) of this section, for the second and third calendar quarters of the year, and the second quarter report shall include emissions data only for May and June.
(D) The quarterly and cumulative NO X emission rate in lb/mmBtu (if required by the applicable program(s)) shall be determined as follows. Calculate the quarterly NO X emission rate by taking the arithmetic average of all of the hourly EF NO X values. Calculate the cumulative (year-to-date) NO X emission rate by taking the arithmetic average of the quarterly NO X emission rates.
(iii) CO 2 Mass Emissions. (A) The hourly CO 2 mass emissions (tons) for the affected low mass emissions unit (Acid Rain Program units, only) shall be determined using Equation LM-11 and the appropriate fuel-based CO 2 emission factor from Table LM-3 of this section for the fuel being combusted in that hour. If more than one fuel is combusted in the hour, use the highest emission factor for all of the fuels combusted in the hour. If records are missing as to which fuel was combusted in the hour, use the highest emission factor for all of the fuels capable of being combusted in the unit.
(B) The quarterly CO 2 mass emissions (tons) for the low mass emissions unit shall be the sum of all of the hourly CO 2 mass emissions in the quarter, as determined under paragraph (c)(4)(iii)(A)of this section.
(C) The year-to-date cumulative CO 2 mass emissions (tons) for the low mass emissions unit shall be the sum of all of the quarterly CO 2 mass emissions, as determined under paragraph (c)(4)(iii)(B) of this section, for all of the calendar quarters in the year to date.
(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 ) of this section to determine fuel usage, the owner or operator shall keep, at the facility, a copy of the standard used and shall keep records, for three years, of all measurements obtained for each quarter using the methodology.
(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 emission rates are determined in accordance with paragraph (c)(1)(iv) of this section, the owner or operator shall keep, at the facility, records which document the results of all NO X emission rate tests conducted according to appendix E to this part. If CEMS data are used to determine the fuel-and-unit-specific NO X emission rates under paragraph (c)(1)(iv)(G) of this section, the owner or operator shall keep, at the facility, records of the CEMS data and the data analysis performed to determine a fuel-and-unit-specific NO X emission rate. The appendix E test records and historical CEMS data records shall be kept until the fuel and unit specific NO X emission rates are re-determined.
(5) For each low mass emissions unit for which fuel-and-unit-specific NO X emission rates are determined in accordance with paragraph (c)(1)(iv) of this section and which has add-on NO X emission controls of any kind or uses dry low-NO X technology, the owner or operator shall develop and keep on-site a quality assurance plan which explains the procedures used to document proper operation of the NO X emission controls. The plan shall include the parameters monitored (e.g., water-to-fuel ratio) and the acceptable ranges for each parameter used to determine proper operation of the unit's NO X controls.
(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 Emission Factors (lb/mmBtu) for Various Fuel Types
Table LM-2—NO X Emission Rates (lb/mmBtu) for Various Boiler/Fuel Types
Table LM-3—CO 2 Emission Factors (ton/mmBtu) for Gas and Oil
Table LM-4—Identical Unit Testing Requirements
Table LM-5—Default Gross Calorific Values (GCVs) for Various Fuels
Table LM-6—Default Specific Gravity Values for Fuel Oil