1 Subpart Da—Standards of P erformance for Electric Utilit y Steam Generating Units § 60.40Da Applicability and designation of affected facility. (a) Except as specified in paragraph (e) of this section, th e affected facility to which this subpart applies is each electric utility steam generating unit: (1) That is capable of combusting more than 73 megawatts (MW) (250 million British thermal units per hour (MMBtu/hr)) heat input of fossil fuel (either alone or in combination with any other fuel); and (2) For which construction, modification, or reconstruction is commenced after September 18, 1978. (b) An IGCC electric utility steam generating unit (both the stationary combustion turbine and any associated duct burners) is subject to this part and is not su bject to subpart GG or KKKK of this part if both of th e condi tions specified in paragraphs (b)(1) and (2) of this section are met. (1) The IGCC electric utility steam generating unit is cap able of combusting more than 73 MW (250 MMBtu/h) heat input of fossil fuel (either alone or in combination with any other fuel) in the combustion turbine engine and associated heat recovery steam generator; and (2) The IGCC electric utility steam generating unit commence d construction, modification, or reconstruction after February 28, 2005. (c) Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of combustible materials, other than fossil fuels, shall not bring that unit under the applicability of this subpart. (d) Any change to an existing steam generating unit originally designed to fire gaseous or liquid fossil fuels, to accommodate the use of any othe r fuel (fossil or nonfossil) shall not bri ng that unit under the applicability of this subpart. (e) Applicability of this subpart to an electric utility combined cycle gas turbine other than an IGCC electric utility steam generating unit is as specified in pa ragraphs (e)(1) through (3) of this section. (1) Affected facilities ( i.e. heat recovery steam generators used with duct burners) associated with a stationary combustion turbine that are capable of combusting more th an 73 MW (250 MMBtu/h) heat input of fossil fuel are subject to this subpart except in cases when the affected facility ( i.e. heat recovery steam generator) meets the applicability requirements of and is subject to subpart KKKK of this part. (2) For heat recovery steam generators use with duct burners subject to this subpart, only emissions resulting from the combustion of fuels in the steam generating unit ( i.e. duct burners) are subject to the standards under this subpart. (The emissions resulting from the combustion of fuels in the stationary combustion turbine engine are subject to subpart GG or KKKK, as applicable, of this part.) (3) Any affected facility that meets the applicability requirements and is subj ect to subpart Eb or subpart CCCC of this part is not subject to the emission standards under subpart Da. [72 FR 32722, June 13, 2007, as amended at 74 FR 5078, Jan. 28, 2009; 77 FR 9448, Feb. 16, 2012]

§ 60.41Da Definitions. As used in this subpart, all terms not defined herein sh all have the meaning given them in the Act and in subpart A of this part. Affirmative defense means, in the context of an enforcement proceeding, a response or defense put forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding.

Anthracite means coal that is classified as anthracite accordi ng to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17). Available system capacity means the capacity determined by subtracting the system load and the system emergency reserves from the net system capacity.

Biomass means plant materials and animal waste.2 Bituminous coal means coal that is classified as bituminous according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17). Boiler operating day for units constructed, reconstructed, or modified before March 1, 2005, means a 24-hour period during which fossil fuel is combusted in a steam-generating unit for the entire 24 hours. For units constructed, reconstructed, or modified after February 28, 2005, boiler operating day means a 24-hour periodbetween 12 midnight and the following midnight during which any fuel is combusted at any time in the steamgenerating unit. It is not necessary for fuel to be combusted the entire 24-hour period.

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17) and coal refuse. Synthetic fuels derived from coal for the purpose of creating useful heat, including but not limited to solvent-refined coal, gasified coal (not meeting the definition of natural gas ) , coal-oil mixtures, and coal-water mixtures are included in this definition for the purposes of this subpart. Coal-fired electric utilit y steam generating unit means an electric utility steam generating unit that burns coal, coal refuse, or a synthetic gas derived from coal either exclusively, in any combination together, or in any combination with other fuels in any amount. Coal refuse means waste products of coal mining, physical co al cleaning, and coal preparation operations ( e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material. Combined cycle gas turbine means a stationary turbine combustion system where heat from the turbine exhaust gases is recovered by a steam generating unit. Combined heat and power, also known as “cogeneration,” means a steam-generating unit that simultaneously produces both electric (and mechan ical) and useful thermal energy from the same primary energy source.

Duct burner means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a stationary gas turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a heat recovery steam generating unit. Electric utility combin ed cycle gas turbine means any combined cycle gas turbine used for electric generation that is constructed for the purpose of supplying more than one-t hird of its potential electric output capacity and more than 25 MW net-electrical output to an y utility power distribution system fo r sale. Any steam distribution system that is constructed for the purpose of providing steam to a steam electric generator th at would produce electrical power for sale is also considered in determining the electrical energy output capacity of the affected facility. Electric utility steam-generating unit means any steam electric generating unit that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW net-electrical output to any utility power distribution system for sale. Also, any steam supplied to a steam distribution system for the purpose of providing steam to a steam-electric generator that would produce electrical energy for sale is considered in determining the electrical energy output capacity of the affected facility. Electrostatic precipitator or ESP means an add-on air pollution control device used to capture particulate matter (PM) by charging the particles using an electrostatic fi eld, collecting the particles using a grounded collecting surface, and transporting the particles into a hopper.

Emission limitation means any emissions limit or operating limit. Federally enforceable means all limitations and conditi ons that are enforceable by the Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State implementation plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24. Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat. Gaseous fuel means any fuel that is present as a gas at standa rd conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal. Gross energy output means: Comment [CF1]: Delete reference since the definition of natural gas does not include coal

‐ derived gas3 (1) For facilities constructed, reconstructed, or modified before May 4, 2011, the gross electrical or mechanical output from the affected facility plus 75 percent of the us eful thermal output measured relative to IS O conditions that is not used to generate additional electrical or me chanical output or to enhance the performance of the unit ( i.e., steam delivered to an industrial process); (2) For facilities constructed, reconstructed, or modified after May 3, 2011, the gross electrical or mechanical output from the affected facility minus any electricity us ed to power the feedwater pu mps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( i.e., steam delivered to an industrial process); (3) For combined heat and power facilities constructed, reconstructed, or modified after May 3, 2011, the gross electrical or mechanical output from the affected facility divided by 0.95 minus any electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( i.e., steam delivered to an industrial process); (4) For a IGCC electric utility generating unit that coproduces chemicals constructed, reconstructed, or modified after May 3, 2011, the gross useful work performed is the gross electrical or mechanical output from the unit minus electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) that are associated with power production plus 75 percent of the useful thermal output m easured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit ( i.e., steam delivered to an industrial process). Auxiliary loads that are asso ciated with power production are de termined based on the energy in the coproduced chemicals compared to the energy of the syngas combusted in combustion turbine engine and associated duct burners. 24-hour period means the period of time between 12:01 a.m. and 12:00 midnight. Integrated gasification combined cycle el ectric utility stea m generating unit or IGCC electric utility steam generating unit means an electric utility combined cycle gas turbine that is designed to burn fuels containing 50 percent (by heat input) or more solid-derived fuel not meeting the definition of natural gas. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction

, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the unit during operation.

ISO conditions means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a pressure of 101.3 kilopascals. Lignite means coal that is classified as lignite A or B accord ing to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17). Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas does not include th e following gaseous fuels: landfill gas, dige ster gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable su lfur content or heating value. Neighboring company means any one of those electric utility companies with one or more electric power interconnections to the principal company and which have geographically adjoining service areas. Net-electric output means the gross electric sales to the utility power distribution system minus purchased power on a calendar year basis. Net energy output means the gross energy output minus the parasi tic load associated with power production. Parasitic load includes, but is not limi ted to, the power required to operate the equipment used for fuel delivery systems, air pollution control systems, wastewater treatment systems, ash handling and disposal systems, and Comment [CF2]: Make definition consistent with final rule RTC

Comment [CF3]: Republish identical definition

to solicit comment

– not amended4 other controls ( i.e., pumps, fans, compressors, motors, instrumentation, and other ancillary equipment required to operate the affected facility).

Noncontinental area means the State of Hawaii, the Virgin Island s, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands. Out-of-control period means any period beginning with the quadrant corresponding to the completion of a daily calibration error, linearity check, or qua lity assurance audit that i ndicates that the instrument is not measuring and recording within the applicable performance specifications and ending with the quadrant corresponding to the completion of an additional calibration error, linearity check, or qua lity assurance audit following corrective action that demonstrates that the instrument is measuring and recording within the applicable performance specifications.

Petroleum for facilities constructed, reconstr ucted, or modified before May 4, 2011, means crude oil or a fuel derived from crude oil, including, but not limited to, dist illate oil, and residual oil. For units constructed, reconstructed, or modified after May 3, 2011, petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, distillate oil, residual oil, and petroleum coke.

Petroleum coke, also known as “petcoke,” means a carbonization product of high-boiling hydrocarbon fractions obtained in petroleum processing (heavy residues). Petroleum coke is typically derived from oil refinery coker units or other cracking processes.

Potential combusti on concentration means the theoretical emissions (nanogr ams per joule (ng/J), lb/MMBtu heat input) that would result from combustion of a fuel in an uncleaned state without emission control systems. For sulfur dioxide (SO 2 ) the potential combustion concentratio n is determined under §60.50Da(c).

Potential electrical output capacity means 33 percent of the maximum design heat input capacity of the steam generating unit, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr ( e.g. , a steam generating unit with a 100 MW (340 MMBtu/hr) fossil-fuel heat input capacity would have a 289,080 MWh 12 month potential electrical output capacity). For elec tric utility combined cycl e gas turbines the potential electrical output capacity is determined on the basis of the fossil-fuel firing capacity of the steam generator exclusive of the heat input and electrical power contribution by the gas turbine. Resource recovery unit means a facility that combusts more than 75 percent non-fossil fuel on a quarterly (calendar) heat input basis. Solid-derived fuel means any solid, liquid, or gaseous fuel derived from solid fuel for the purpose of creating useful heat and includes, but is not limited to, solvent refined coal, liquified coal, synthetic gas, gasified coal, gasified petroleum coke, gasified biomass, and gasified tire derived fuel. Steam generating unit for facilities constructed, r econstructed, or modified be fore May 4, 2011, means anyfurnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossilfuel-fired steam generators associated with combined cycle gas turbines; nuclear steam generators are not included). For units constructed, reconstructed, or modified after May 3, 2011, steam generating unit means anyfurnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossilfuel-fired steam generators associated with combined cycle gas turbines; nuclear steam generators are not included) plus any integrated combustion turbines and fuel cells.

Subbituminous coal means coal that is classified as subbituminous A, B, or C according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17). Wet flue gas desulfurization technology or wet FGD means a SO 2 control system that is located downstream of the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gase s with an alkaline slurry or solution and forming a liquid material. This definition applies to devices where the aqueous liquid material product of this contact is subsequently converted to other forms. Alkaline reagents used in wet FGD technology incl ude, but are not limited to, lime, limestone, and sodium. [72 FR 32722, June 13, 2007, as amended at 74 FR 5079, Jan. 28, 2009; 77 FR 9448, Feb. 16, 2012; 77 FR 23402, Apr. 19, 2012]5 §60.42Da Standards for particulate matter (PM). (a) Except as provided in paragraph (f) of this section, on and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, an owner or operator of an affected facility shall not cause to be discharged into the atmosphere from any affected facility for which construction, reconstruction, or modification commenced before March 1, 2005, any gases that contain PM in excess of 13 ng/J (0.03 0 lb/MMBtu) heat input. (b) Except as provided in paragraphs (b)(1) and (b)(2) of this section, on and after the date the initial PM performance test is completed or required to be completed under §60.8, whichever date comes first, an owner or operator of an affected facility shall not cause to be discharged into the atmosphere any gases which exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity. (1) An owner or operator of an affected facility that el ects to install, calibrate, main tain, and operate a continuous emissions monitoring system (CEMS) for measuring PM emissions according to the requirements of this subpart is exempt from the opacity standard specified in this paragraph (b) of this section. (2) An owner or operator of an affected facility that combusts only natural gas and/or synthetic gas that chemically meets the definition of natural gas is exempt from the opacity standard specified in paragraph (b) of this section. (c) Except as provided in paragraphs (d) and (f) of this section, on and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005, but before May 4, 2011, shall cau se to be discharged in to the atmosphere from that affected facility any gases that contain PM in excess of either: (1) 18 ng/J (0.14 lb/MWh) gross energy output; or (2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel. (d) As an alternative to meeting the requirements of paragraph (c) of this section, the owner or operator of an affected facility for which co nstruction, recons truction, or modification commence d after February 28, 2005, but before May 4, 2011, may elect to meet the requirements of this paragraph. On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of: (1) 13 ng/J (0.030 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel, and (2) For an affected facility that commenced constructi on or reconstruction, 0.1 percent of the combustion concentration determined according to the procedure in §60.48Da(o)(5) (99.9 percent reduction) when combusting solid, liquid, or gaseous fuel, or (3) For an affected facility that commenced modification , 0.2 percent of the combusti on concentration determined according to the procedure in §60.48Da(o)(5) (99.8 percent reduction) when combusting solid, liquid, or gaseous fuel. (e) Except as provided in paragraph (f) of this section, the owner or operator of an affected facility that commenced construction, reconstruction, or modification commenced after May 3, 2011, shall meet the requirements specified in paragraphs (e)(1) and (2) of this section. (1) On and after the date on which the initial performan ce test is completed or required to be completed under §60.8, whichever date comes first, n o the owner or operator shall not cause to be discharged into the atmosphere from that affected facility at all times except during periods of startup and shutdown, any gases that contain PM in excess of the applicable emissions limit specified in paragraphs (e)(1)(i) or (ii) of this section. (i) For an affected facility which co mmenced construction or reconstruction , any gases that contain PM in excess of either : Comment [CF4]: Correct inadvertent error

Comment [CF5]: Re

‐ proposed current definition of natural gas excludes synthetic natural gas. Amended language would exempt facilities burning synthetic natural gas from the opacity standard.

Comment [CF6]: Don’t need since specified in 60.48Da(f)6 (A) 11 ng/J (0.090 lb/MWh) gross energy output; or (B) 12 ng/J (0.097 lb/MWh) net energy output. (ii) For an affected facility which commenced modification, any gases that contain PM in excess of 13 ng/J (0.015 lb/MMBtu) heat input the emission limits specified in

. paragraphs (c) or (d) of this section. (2) During periods of startup and shutdown, the owner or operator shall meet the work practice standards specified in Table 3 to subpart UUUUU of part 63. (f) An owner or operator of an affected facility that meet s the conditions in either paragraphs (f)(1) or (2) of this section is exempt from the PM em issions limits in this section. (1) The affected facility combusts only gaseous or liquid fuels (excluding residual oil) with potential SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and that does not use a post-combustion technology to reduce emissions of SO 2 or PM. (2) The affected facility is operated under a PM commer cial demonstration permit issued by the Administrator according to the provisions of §60.47Da. [77 FR 9450, Feb. 16, 2012] § 60.43Da Standards for sulfur dioxide (SO2). (a) On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts solid fuel or solid-derived fuel and for which construction, reconstruction, or modification commenced before or on February 28, 2005, except as provided under paragraphs (c), (d), (f) or (h) of this section, any gases that contain SO 2 in excess of: (1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 percent of the potential combustion concentration (90 percent reduction); (2) 30 percent of the potential combustion concentration (70 percent reduction), when emissions are less than 260 ng/J (0.60 lb/MMBtu) heat input; (3) 180 ng/J (1.4 lb/MWh) gross energy output; or (4) 65 ng/J (0.15 lb/MMBtu) heat input. (b) On and after the date on which the initial performan ce test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts liquid or gaseous fuels (except for liquid or gaseous fuels derived from solid fuels and as provided under paragraphs (e) or (h) of this section) and for which construction, reconstruction, or modification commenced before or on February 28, 2005, any gases that contain SO 2 in excess of: (1) 340 ng/J (0.80 lb/MMBtu) heat input and 10 percent of the potential combustion concentration (90 percent reduction); or (2) 100 percent of the potential combustion concentration (zero percent reduction) when emissions are less than 86 ng/J (0.20 lb/MMBtu) heat input. (c) On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility which combusts solid solvent refined coal (SRC–I) any gases that contain SO 2 in excess of 520 ng/J (1.20 lb/MMBtu) heat input and 15 percent of the potential combustion concentration (85 percent reduction) except as provided under paragraph (f) of this section; compliance with the emission limitation is determined on a 30-day rolling average basis and compliance with the percent reduction requirement is determined on a 24-hour basis. (d) Sulfur dioxide emissions are limited to 520 ng/J (1.20 lb/MMBtu) heat input from an y affected facility which: (1) Combusts 100 percent anthracite; Comment [CF7]: Correct inadvertent error and maintain PM standard for modified facilities to 2005 requirements.7 (2) Is classified as a resource recovery unit; or (3) Is located in a noncontinental area and combusts solid fuel or solid-derived fuel. (e) Sulfur dioxide emissions are limite d to 340 ng/J (0.80 lb/MMBtu) heat i nput from any affected facility which is located in a noncontinental area and combusts liquid or gaseous fuels (excluding solid-derived fuels). (f) The SO 2 standards under this section do not apply to an owner or operator of an affected facility that is operated under an SO 2 commercial demonstration permit issued by the Admi nistrator in accordance with the provisions of §60.47Da. (g) Compliance with the emission limitation and percent reduction requirements under this section are both determined on a 30-day rolling average basis except as provided under paragraph (c) of this section. (h) When different fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula: (1) If emissions of SO 2 to the atmosphere are greater than 260 ng/J (0.60 lb/MMBtu) heat input

(2) If emissions of SO 2 to the atmosphere are equal to or less than 260 ng/J (0.60 lb/MMBtu) heat input:

Where:

E s = Prorated SO 2 emission limit (ng/J heat input);

%P s = Percentage of potential SO 2 emission allowed; x = Percentage of total heat input derived from the combustion of liquid or gaseous fuels (excluding solid-derived fuels); and y = Percentage of total heat input derived from the combustion of solid fuel (including solid-derived fuels). (i) Except as provided in paragraphs (j) and (k) of th is section, on and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, but before May 4, 2011, shall cause to be discharged into the atmo sphere from that affected facility, any gases that contain SO 2 in excess of the applicable emissions limit specified in paragraphs (i)(1) through (3) of this section. (1) For an affected facility which commenced construction, any gases that contain SO 2 in excess of either: (i) 180 ng/J (1.4 lb/MWh) gross energy output; or (ii) 5 percent of the potential combustion concentration (95 percent reduction). (2) For an affected facility which commenced reconstruction, any gases that contain SO 2 in excess of either: (i) 180 ng/J (1.4 lb/MWh) gross energy output; (ii) 65 ng/J (0.15 lb/MMBtu) heat input; or (iii) 5 percent of the potential combustion concentration (95 percent reduction). (3) For an affected facility which commenced modification, any gases that contain SO 2 in excess of either: (i) 180 ng/J (1.4 lb/MWh) gross energy output; (ii) 65 ng/J (0.15 lb/MMBtu) heat input; or (iii) 10 percent of the potential combustio n concentration (90 percent reduction).8 (j) On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification commenced after February 28, 2005, and that burns 75 percent or more (by heat input) coal refuse on a 12-month rolling average basis, shall caused to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of the applicable emission limitation specified in paragraphs (j)(1) through (3) of this section. (1) For an affected facility for which construction commenced after February 28, 2005, any gases that contain SO 2 in excess of either: (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; or (ii) 6 percent of the potential combustion concentration (94 percent reduction) on a 30-day rolling average basis. (2) For an affected facility for whic h reconstruction commenced after Februa ry 28, 2005, any gases that contain SO 2 in excess of either: (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; (ii) 65 ng/J (0.15 lb/MMBtu) heat inpu t on a 30-day rolling average basis; or (iii) 6 percent of the potential combustion concentration (94 percent reduction) on a 30-day rolling average basis. (3) For an affected facility for which modification comme nced after February 28, 20 05, any gases that contain SO 2 in excess of either: (i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; (ii) 65 ng/J (0.15 lb/MMBtu) heat inpu t on a 30-day rolling average basis; or (iii) 10 percent of the potential combustion concentration (90 percent reduction) on a 30-day rolling average basis. (k) On and after the date on which the initial performan ce test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility located in a noncontinental area for which construction, reconstruction, or modification commen ced after February 28, 2005, but before May 4, 2011, shall cause to be discharg ed into the atmosphere fr om that affected facility any gases that contain SO 2 in excess of the applicable emissions limit specified in paragraphs (k)(1) and (2) of this section. (1) For an affected facility that burn s solid or solid-derived fuel, the owne r or operator shal l not cause to be discharged into the atmosphere any gases that contain SO 2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input. (2) For an affected facility that burns other than solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO 2 in excess of 230 ng/J (0.54 lb/MMBtu) heat input. (l) Except as provided in paragraphs (j) and (m) of this section, on and after the date on whic h the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility for which construction, reconstruction, or modification commenced after May 3, 2011, shall cause to be discharged into the atmosphere from that affected facility, any gases that contain SO 2 in excess of the applicable emissions limit specified in paragraphs (l)(1) and (2) of this section. (1) For an affected facility which commenced constr uction or reconstruction, any gases that contain SO 2 in excess of either: (i) 130 ng/J (1.0 lb/MWh) gross energy output; or (ii) 140 ng/J (1.2 lb/MWh) net energy output; or (iii) 3 percent of the potential combustion concentration (97 percent reduction). (2) For an affected facility which commenced modification, any gases that contain SO 2 in excess of either: (i) 180 ng/J (1.4 lb/MWh) gross energy output; or (ii) 10 percent of the potential combusti on concentration (90 percent reduction).9 (m) On and after the date on which th e initial performance test is complete d or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility located in a noncontinental area for which construction, reconstruction, or modification commen ced after May 3, 2011, shall cause to be discharged into the atmosphere from that affect ed facility any gases that contain SO 2 in excess of the applicable emissions limit specified in paragraphs (m)(1) and (2) of this section. (1) For an affected facility that burn s solid or solid-derived fuel, the owne r or operator shal l not cause to be discharged into the atmosphere any gases that contain SO 2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input. (2) For an affected facility that burns other than solid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO 2 in excess of 230 ng/J (0.54 lb/MMBtu) heat input. [72 FR 32722, June 13, 2007, as amended at 77 FR 9450, Feb. 16, 2012] § 60.44Da Standards for nitrogen oxides (NO X ). (a) Except as provided in paragraph (h) of this section, on and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall ca use to be discharged into the atmosphe re from any affected facility for which construction, reconstruction, or modification commenced before July 10, 1997 any gases that contain NO X (expressed as NO 2 ) in excess of the applicable emissions limit in paragraphs (a)(1) and (2) of this section. (1) The owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO X in excess of the emissions limit listed in the following ta ble as applicable to the fuel type combusted and as determined on a 30-boiler operat ing day rolling average basis.

Fuel type Emission limit for heat input

ng/J lb/MMBtu

Gaseous fuels:

Coal-derived fuels 210 0.50

All other fuels 86 0.20

Liquid fuels:

Coal-derived fuels 210 0.50

Shale oil 210 0.50

All other fuels 130 0.30

Solid fuels:

Coal-derived fuels 210 0.50

Any fuel containing more than 25%, by weight, coal refuse ( 1 ) ( 1 )

Any fuel containing more than 25%, by weight, lignite if the lignite is mined in North Dakota, South Dakota, or Montana, and is combusted in a slag tap furnace 2 340 0.80

Any fuel containing more than 25%, by weight, lignite not subject to the 340 ng/J heat 260 0.6010 input emission limit 2

Subbituminous coal 210 0.50

Bituminous coal 260 0.60

Anthracite coal 260 0.60

All other fuels 260 0.60

1 Exempt from NOX standards and NOX monitoring requirements.

2 Any fuel containing less than 25%, by weight, lignite is not prorated but its percentage is added to the percentage of the predominant fuel. (2) When two or more fuels are combus ted simultaneously in an affected f acility, the applicable emissions limit (E n ) is determined by proration using the following formula:

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Where: En = Applicable NO X emissions limit when multiple fuels are co mbusted simultaneously (ng/J heat input); w = Percentage of total heat input derived from the combustion of fuels subject to the 86 ng/J heat input standard; x = Percentage of total heat input derived from the combus tion of fuels subject to the 130 ng/J heat input standard; y = Percentage of total heat input derived from the combus tion of fuels subject to the 210 ng/J heat input standard; z = Percentage of total heat input derived from the combustion of fuels subject to the 260 ng/J heat input standard; and v = Percentage of total heat input delivered from the combustion of fuels subject to the 340 ng/J heat input standard. (b)–(c) [Reserved] (d) Except as provided in paragraph (h) of this section, on and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commen ced construction, reconstruction, or mo dification after July 9, 1997, but before March 1, 2005, shall cause to be discha rged into the atmosphere from that a ffected facility any gases that contain NO X (expressed as NO 2 ) in excess of the applicable emissions limit specified in paragraphs (d)(1) and (2) of this section as determined on a 30-boiler operating day rolling average basis. (1) For an affected facility which commenced construction, any gases that contain NO X in excess of 200 ng/J (1.6 lb/MWh) gross energy output. (2) For an affected facility which commenced reconstruction, any gases that contain NO X in excess of 65 ng/J (0.15 lb/MMBtu) heat input. (e) Except as provided in paragraphs (f) and (h) of this section, on and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005 but before May 4, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO X (expressed as NO 2 ) in excess of the applicable emissions limit specified in paragraphs (e)(1) through (3) of this section as determined on a 30-boiler operating day rolling average basis. (1) For an affected facility which commenced construction, any gases that contain NO X in excess of 130 ng/J (1.0 lb/MWh) gross energy output.11 (2) For an affected facility which commenced reconstruction, any gases that contain NO X in excess of either: (i) 130 ng/J (1.0 lb/MWh) gross energy output; or (ii) 47 ng/J (0.11 lb/MMBtu) heat input. (3) For an affected facility which commenced modification, any gases that contain NO X in excess of either: (i) 180 ng/J (1.4 lb/MWh) gross energy output; or (ii) 65 ng/J (0.15 lb/MMBtu) heat input. (f) On and after the date on which the initial performanc e test is completed or requ ired to be completed under §60.8, whichever da te comes first, the owner or operator of an IGCC electric utility steam generating unit subject to the provisions of this subpart and for which construction, reconstruction, or modification commenced after February 28, 2005 but before May 4, 2011, shall meet the requirements specified in paragraphs (f)(1) through (3) of this section. (1) Except as provided for in paragraphs (f)(2) and (3) of this section, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO X (expressed as NO 2 ) in excess of 130 ng/J (1.0 lb/MWh) gross energy output. (2) When burning liquid fuel exclusively or in combina tion with solid-derived fuel such that the liquid fuel contributes 50 percent or more of the total heat input to the combined cycle combustion turbine, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO X (expressed as NO 2 ) in excess of 190 ng/J (1.5 lb/MWh) gross energy output. (3) In cases when during a 30-boiler operating day rolling average compliance period liquid fuel is burned in such a manner to meet the conditions in paragraph (f)(2) of this section for only a portion of the clock hours in the 30- day compliance period, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO X (expressed as NO 2 ) in excess of the computed weighted -average emissions limit based on the proportion of gross energy output (in MWh) generated during the compliance period for each of emissions limits in paragraphs (f)(1) and (2) of this section. (g) Except as provided in paragraphs (h) of this section and §60.45Da, on and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after May 3, 2011, shall cause to be discharg ed into the atmosphere fr om that affected facility any gases that contain NO X (expressed as NO 2 ) in excess of the applicable emissions limit specified in paragraphs (g)(1) through (3) of this section. (1) For an affected facility which commenced constr uction or reconstruction, any gases that contain NO X in excess of either: (i) 88 ng/J (0.70 lb/MWh) gross energy output; or (ii) 95 ng/J (0.76 lb/MWh) net energy output. (2) For an affected facility which commenced constructio n or reconstruction and that burns 75 percent or more coal refuse (by heat input) on a 12-month rolling average basis, any gases that contain NO X in excess of either: (i) 110 ng/J (0.85 lb/MWh) gross energy output; or (ii) 120 ng/J (0.92 lb/MWh) net energy output. (3) For an affected facility which commenced modification, any gases that contain NO X in excess of 140 ng/J (1.1 lb/MWh) gross energy output. (h) The NO X emissions limits under this section do not apply to an owner or operat or of an affected facility which is operating under a commercial demonstration permit issued by the Administrator in accordance with the provisions of §60.47Da. [77 FR 9451, Feb. 16, 2012] § 60.45Da Alternative standards for combined nitrogen oxides (NOX) and carbon monoxide (CO).12 (a) The owner or operator of an affected facility that commenced construction, reconstruction, or modification after May 3, 2011 as alternate to meeting the applicable NO X emissions limits specified in §60.44Da may elect to meet the applicable standards for combined NO X and CO specified in paragraph (b) of this section. (b) On and after the date on which the initial performan ce test is completed or required to be completed under §60.8 no owner or operator of an affected facility that commenced construction, reconstruction, or modification after May 3, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO X (expressed as NO 2 ) plus CO in excess of the applicable emissions limit specified in paragraphs (b)(1) through (3) of this section as determined on a 30-boiler operating day rolling average basis. (1) For an affected facility which commenced constr uction or reconstruction, any gases that contain NO X plus CO in excess of either: (i) 140 ng/J (1.1 lb/MWh) gross energy output; or (ii) 150 ng/J (1.2 lb/MWh) net energy output. (2) For an affected facility which commenced constructio n or reconstruction and that burns 75 percent or more coal refuse (by heat input) on a 12-month rolling average basis, any gases that contain NO X plus CO in excess of either: (i) 160 ng/J (1.3 lb/MWh) gross energy output; or (ii) 170 ng/J (1.4 lb/MWh) net energy output. (3) For an affected facility which commenced modification, any gases that contain NO X plus CO in excess of 190 ng/J (1.5 lb/MWh) gross energy output. [77 FR 9453, Feb. 16, 2012] § 60.46Da [Reserved] § 60.47Da Commercial demonstration permit. (a) An owner or operator of an affected facility proposi ng to demonstrate an emergi ng technology may apply to the Administrator for a commercial demonstration permit. The Administrator will issue a commercial demonstration permit in accordance with paragraph (e) of this section. Commercial demonstration permits may be issued only by the Administrator, and this authority will not be delegated. (b) An owner or operator of an affected facility that combusts solid solvent refined coal (SRC–I) and who is issued a commercial demonstration permit by the Administrator is not subject to the SO 2 emission reduction requirements under §60.43Da(c) but must, as a minimum, reduce SO 2 emissions to 20 percent of the potential combustion concentration (80 percent reduction) for each 24-hour period of steam generator operation and to less than 520 ng/J (1.20 lb/MMBtu ) heat input on a 30-day rolling average basis. (c) An owner or operator of an affected facility that uses fluidized bed combustion (atmospheric or pressurized) and who is issued a commercial demonstration permit by the Administrator is not subject to the SO 2 emission reduction requirements under §60.43Da(a) but must, as a minimum, reduce SO 2 emissions to 15 percent of the potential combustion concentration (85 percent reduction) on a 30-day rolling average basis and to less than 520 ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling average basis. (d) The owner or operator of an affected facility that combusts coal-derived liquid fuel and who is issued a commercial demonstration permit by the Administrator is not subject to the applicable NO X emission limitation and percent reduction under §60.44Da(a) but must, as a minimum, reduce emissions to less than 300 ng/J (0.70 lb/MMBtu) heat input on a 30-day rolling average basis. (e) Commercial demonstration permits may not exceed the following equivalent MW electrical generation capacity for any one technology category, and the tota l equivalent MW electrical generation capacity for all commercial demonstration plants may not exceed 15,000 MW.

Technology Pollutant Equivalent electrical capacity13 (MW electrical output)

Solid solvent refined coal (SCR I) SO2 6,000–10,000

Fluidized bed combustion (atmospheric) SO2 400–3,000

Fluidized bed combustion (pressurized) SO2 400–1,200

Coal liquification NOX 750–10,000

Total allowable for all technologies 15,000 (f) An owner or operator of an affected facility that us es a pressurized fluidized bed or a multi-pollutant emissions controls system who is issued a commercial demonstration permit by the Administrator is not subject to the total PM emission reduction requirements under §60.42Da but must, as a minimum, reduce PM emissions to less than 6.4 ng/J (0.015 lb/MMBtu) heat input. (g) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multi-pollutant emissions controls system who is issued a commercial de monstration permit by the Administrator is not subject to the SO 2 standards or emission reduction requirements under §60.43Da but must, as a minimum, reduce SO 2 emissions to 5 percent of the potential combustion concentration (95 percent reduction) or to less than 180 ng/J (1.4 lb/MWh) gross energy output on a 30-boiler operating day rolling average basis. (h) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multi-pollutant emissions control system or advanced combustion contro ls who is issued a commercial demonstration permit by the Administrator is not subject to the NO X standards or emission reduction requirements under §60.44Da but must, as a minimum, reduce NO X emissions to less than 130 ng/J (1.0 lb/MWh) or the combined NO X plus CO emissions to less than 180 ng/J (1.4 lb/MWh) gross energy output on a 30-boiler operating day rolling average basis. (i) Commercial demonstration permits may not exceed the following equivalent MW electrical generation capacity for any one technology category listed in the following table.

Technology Pollutant Equivalent electrical capacity (MW electrical output)

Multi-pollutant Emission Control SO 2 1,000

Multi-pollutant Emission Control NO X 1,000

Multi-pollutant Emission Control PM 1,000

Pressurized Fluidized Bed Combustion SO 2 1,000

Pressurized Fluidized Bed Combustion NO X 1,000

Pressurized Fluidized Bed Combustion PM 1,000

Advanced Combustion Controls NO X 1,000 [72 FR 32722, June 13, 2007, as amended at 77 FR 9450, Feb. 16, 2012] § 60.48Da Compliance provisions.14 (a) For affected facilities for which construction, modifi cation, or reconstruction comm enced before May 4, 2011, the applicable PM emissions limit a nd opacity standard under §60.42Da, SO 2 emissions limit under §60.43Da, and NO X emissions limit under §60.44Da apply at all times except during periods of startup, shutdown, or malfunction. For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, the applicable SO 2 emissions limit under §60.43Da, NO X emissions limit under §60.44Da, and NO X plus CO emissions limit under §60.45Da apply at all times. The applicable PM emissions limit and opacity standard under §60.42Da apply at all times except during periods of startup and shutdown. (b) After the initial performance test required under §60.8, compliance with the applicable SO 2 emissions limit and percentage reduction requirements under §60.43Da, NO X emissions limit under §60.44Da, and NO X plus CO emissions limit under §60.45Da is based on the average emission rate for 30 successive boiler operating days. A separate performance test is completed at the end of each boiler operating day after the initial performance test, and a new 30-boiler operating day rolling average emission rate for both SO 2 , NO X or NO X plus CO as applicable, and a new percent reduction for SO 2 are calculated to demonstrate compliance with the standards. (c) For the initial performance test required under §60.8, compliance with the applicable SO 2 emissions limits and percentage reduction requirements under §60.43Da, the NO X emissions limits under §60.44Da, and the NO X plus CO emissions limits under §60.45Da is based on the average emission rates for SO 2 , NO X , CO, and percent reduction for SO 2 for the first 30 successive boiler operating days. Th e initial performance test is the only test in which at least 30 days pr ior notice is required unless otherwise sp ecified by the Admini strator. The initial performance test is to be scheduled so that the first boiler operating day of the 30 successive boiler operating days is completed within 60 days after ach ieving the maximum produc tion rate at which the affected facility will be operated, but not later than 180 days after initial startup of the facility. (d) For affected facilities for which construction, modifi cation, or reconstr uction commenced befo re May 4, 2011, compliance with applicable 30-boiler operating day rolling average SO 2 and NO X emissions limits is determined by calculating the arithmetic average of all hourly emission rates for SO 2 and NO X for the 30 successive boiler operating days, except for data obtained during startup, s hutdown, or malfunction. For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, compliance with applicable 30-boiler operating day rolling average SO 2 and NO X emissions limits is determined by dividing the sum of the SO 2 and NO X emissions for the 30 successive boiler operating days by the sum of the gross energy output or net energy output, as applicable, for the 30 successive boiler operating days. (e) For affected facilities for which construction, modifi cation, or reconstruction comm enced before May 4, 2011, compliance with applicable SO 2 percentage reduction requirements is de termined based on the average inlet and outlet SO 2 emission rates for the 30 successive boiler operating days. For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, compliance with applicable SO 2 percentage reduction requirements is determined based on the “as fired” total potential emi ssions and the total outlet SO 2 emissions for the 30 successive boiler operating days. (f) For affected facilities for which co nstruction, modification, or reconstruc tion commenced before May 4, 2011, compliance with the applicable daily average PM emissions limit s is determined by cal culating the arithmetic average of all hourly emission rates f or PM each boiler operating day, except for data obtained during startup, shutdown, or and malfunction periods . Daily averages are only calculated for boiler operating days that have non

out-of-control periods totaling no more than 6 hours data for at least 18 hours of unit operation during which the standard applies. Instead, all of the non

- out

- of

- control hourly emission rates of the operating day(s) not meeting the minimum 18 hours non

- out

- of

- control data daily average requirement are averaged with all of the non

- out

- of

control hourly emission rates of the next boiler operating day with 18 hours or more o f non

- out

- of

- control PM CEMS data to determine compliance. For affected facilities for which construction

, modification, or reconstruction commenced after May 3, 2011 that elect to demonstrate compliance using PM CEMS , compliance with the applicable daily average PM emissions limit s in §60.42Da is determined on a 30-boiler operating day rolling average basis by calculating the arithmetic average of all hourly PM emission rates dividing the sum of the PM emissions for the 30 successive boiler operating days , except for data obtained during periods of startup and shutdown by the sum of the gross useful output or net energy output, as applicable, for the 30 successive boiler operating days

. Comment [CF8]: Clarify language to make easier

to understand

Comment [CF9]: Eliminate requirement to roll

over data to next operating day.

Comment [CF10]: Since startup and shutdown requirements use a work practice approach

– make the same as the NESHAP procedures15 (g) For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, compliance with applicable 30-boiler operating day rolling average NO X plus CO emissions limit is determined by dividing the sum of the NO X plus CO emissions for the 30 successive boiler operating days by the sum of the gross energy output or net energy output, as applicable, for the 30 successive boiler operating days. (h) If an owner or operator has not obtained the minimum quantity of emission data as required under §60.49Da of this subpart, compliance of the affected facility with the emission requirements under §§60.43Da and 60.44Da of this subpart for the day on which the 30-day period ends may be determined by the Administrator by following the applicable procedures in section 7 of Method 19 of appendix A of this part. (i) Compliance provisions for sources subject to §60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), (f), or (g). The owner or operator shall calculate NO X emissions as 1.194 × 10 − 7 lb/scf-ppm times the average hourly NO X output concentration in ppm (measured according to the provisions of §60.49Da(c)), times the average hourly flow rate (measured in scfh, according to the provisions of §60.49Da(l) or §60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)) or the average hourly net energy output, as applicable. Alternatively, for oil-fired and gas-fired units, NO X emissions may be calculated by multiplying the hourly NO X emission rate in lb/MMBtu (measured by the CEMS required under §60.49Da(c) and (d)), by the hourly heat input rate (measured according to the provisions of §60.49Da(n)), and dividing the result by the average gross energy output (measured according to the provisions of §60.49Da(k)) or the average hourly net energy output, as applicable. (j) Compliance provisions for duct burners subject to §60.44Da(a)(1) . To determine compliance with the emissions limits for NO X required by §60.44Da(a) for duct burners used in combined cycle systems, either of the procedures described in paragraph (j)(1) or (2) of this section may be used: (1) The owner or operator of an affected duct burner shall conduct the performance test required under §60.8 using the appropriate methods in appendix A of this part. Compliance with the emissions limits under §60.44Da(a)(1) is determined on the average of three (nominal 1-hour) runs for the initial and subsequent performance tests. During the performance test, one sampling site shall be located in the exhaust of the turbine prior to the duct burner. A second sampling site shall be located at the outlet from the heat recovery steam generating unit. Measurements shall be taken at bo th sampling sites during the performance test; or (2) The owner or operator of an affected duct burner may elect to determine compliance by using the CEMS specified under §60.49Da for measuring NO X and oxygen (O 2 ) (or carbon dioxide (CO 2 )) and meet the requirements of §60.49Da. A lternatively, data from a NO X emission rate ( i.e. , NO X -diluent) CEMS certified according to the provisions of §75.20(c) of this chapter and appendix A to part 75 of this chapter, and meeting the quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this chapter, may be used, with the following caveats. Data used to meet the requirements of §60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. The sampling site shall be located at the outlet from the steam generating unit. The NO X emission rate at the outlet from the steam generating unit shall constitute the NO X emission rate from the duct burner of the combined cycle system. (k) Compliance provisions for duct burners subject to §60.44Da(d)(1) or (e)(1) . To determine compliance with the emission limitation for NO X required by §60.44Da(d)(1) or (e)(1) for duct burners used in combined cycle systems, either of the procedures described in paragraphs (k)(1) and (2) of this section may be used: (1) The owner or operator of an affected duct burner used in combined cycle systems shall determine compliance with the applicable NO X emission limitation in §60.44Da(d)(1) or (e)(1) as follows: (i) The emission rate (E) of NO X shall be computed using Equation 2 in this section:

View or download PDF

Where:

E = Emission rate of NO X from the duct burner, ng/J (lb/MWh) gross energy output;16 C sg = Average hourly concentration of NO X exiting the steam generating unit, ng/dscm (lb/dscf);

C te = Average hourly concentration of NO X in the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf); Q sg = Average hourly volumetric flow rate of exhaus t gas from steam generating unit, dscm/h (dscf/h); Q te = Average hourly volumetric flow rate of exhaust gas from combustion turbine, dscm/h (dscf/h);

O sg = Average hourly gross energy output from steam generating unit, J/h (MW); and h = Average hourly fraction of the total heat input to the steam generating unit derived from the combustion of fuel in the affected duct burner. (ii) Method 7E of appendix A of this part shall be used to determine the NO X concentrations (C sg and C te ). Method 2, 2F or 2G of appendix A of this part, as appropriate, shall be used to determine the volumetric flow rates (Q sg and Q te ) of the exhaust gases. The volumetr ic flow rate measurements shall be taken at the same time as the concentration measurements. (iii) The owner or operator shall develop, demonstrate, and provide information satisfactory to the Administrator to determine the average hourly gross energy output from the steam generating unit, and the average hourly percentage of the total heat input to the steam generating unit derived from the combustion of fuel in the affected duct burner. (iv) Compliance with the applicable NO X emission limitation in §60.44Da(d)(1) or (e)(1) is determined by the three-run average (nominal 1-hour runs) for the initial and subsequent performance tests. (2) The owner or operator of an affected duct burner used in a combined cycle system may elect to determine compliance with the applicable NO X emission limitation in §60.44Da(d)(1) or (e)(1) on a 30-day rolling average basis as indicated in paragraphs (k)(2)(i) through (iv) of this section. (i) The emission rate (E) of NO X shall be computed using Equation 3 in this section:

View or download PDF

Where:

E = Emission rate of NO X from the duct burner, ng/J (lb/MWh) gross energy output;

C sg = Average hourly concentration of NO X exiting the steam generating unit, ng/dscm (lb/dscf); Q sg = Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/h (dscf/h); and

O cc = Average hourly gross energy output from entire combined cycle unit, J/h (MW). (ii) The CEMS specified under §60.49Da for measuring NO X and O 2 (or CO 2 ) shall be used to determine the average hourly NO X concentrations (C sg ). The continuous flow monitoring system specified in §60.49Da(l) or §60.49Da(m) shall be used to determine the volumetric flow rate (Q sg ) of the exhaust gas. If the option to use the flow monitoring system in §60.49Da(m) is selected, the flow rate data used to meet the requirements of §60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. The sampling site shall be located at the outlet from the steam generating unit. (iii) The continuous monitoring system specified under §60.49Da(k) for measuring and determining gross energy output shall be used to determine the average hourly gross energy output from the entire combined cycle unit (O cc ), which is the combined output from the co mbustion turbine and the steam generating unit. (iv) The owner or operator may, in lieu of installing, operating, and recording data from the continuous flow monitoring system specified in §60.49Da(l), determine the mass rate (lb/h) of NO X emissions by installing, operating, and maintaining continuous fuel flowmeters following the appropriate measurements procedures specified in appendix D of part 75 of this chapter. If this compliance option is selected, the emission rate (E) of NO X shall be computed using Equation 4 in this section:17 View or download PDF

Where:

E = Emission rate of NO X from the duct burner, ng/J (lb/MWh) gross energy output;

ER sg = Average hourly emission rate of NO X exiting the steam generating unit heat input calculated using appropriate F factor as described in Method 19 of appendix A of this part, ng/J (lb/MMBtu);

H cc = Average hourly heat input rate of entire combined cycle unit, J/h (MMBtu/h); and

O cc = Average hourly gross energy output from entire combined cycle unit, J/h (MW). (3) When an affected duct burner steam generating unit utilizes a common steam turbine with one or more affected duct burner steam generating units, the owner or operator shall either: (i) Determine compliance with the applicable NO X emissions limits by measuring th e emissions combined with the emissions from the other unit(s) utiliz ing the common steam turbine; or (ii) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined gross energy output from the steam turbine for each of the affected duct burners. The Administrator may approve such demonstrated substitute methods for apportioning the combined gross energy output measured at the steam turbine whenever the demonstration ensures accurate estimation of emi ssions regulated under this part. (l) [Reserved] (m) Compliance provisions for sources subject to §60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), (j)(3)(i), (l)(1)(i), (l)(1)(ii), or (l)(2). The owner or operator shall calculate SO 2 emissions as 1.660 × 10 − 7 lb/scf-ppm times the average hourly SO 2 output concentration in ppm (measured according to the provisions of §60.49Da(b)), times the average hourly flow rate (measured according to the provisions of §60.49Da(l) or §60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)) or the average hourly net energy output, as applicable. Alternatively, for oil-fired and gas-fired units, SO 2 emissions may be calculated by multiplying the hourly SO 2 emission rate (in lb/MMBtu), measured by the CEMS required under §60.49Da, by the hourly heat input rate (measured according to the provisions of §60.49Da(n)), and dividing the result by the average gross energy output (measured according to the provisions of §60.49Da(k)) or the average hourly net energy output, as applicable. (n) Compliance provisions for sources subject to §60.42Da(c)(1) or (e)(1)(i). The owner or operator shall calculate PM emissions by multiplying the average hourly PM output concentration (measured according to the provisions of §60.49Da(t)), by the average hourly flow rate (measured according to the provisions of §60.49Da(l) or §60.49Da(m)), and dividing by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)) or the average hourly net energy output, as applicable. (o) Compliance provisions for sources subject to §60.42Da(c)(2)

, or (d) , or (e)(1)(ii) . Except as provided for in paragraph (p) of this section, the owner or operator of an affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, shall must demonstrate compliance with each applicable emission s limit according to the requirements in paragraphs (o)(1) through (o)(5) of this section. (1) You must conduct a performance test to demonstrat e initial compliance with th e applicable PM emissions limit in §60.42Da (c)(2) or ( d ) by the applicable date specified in §60.8(a). Thereafter, you must conduct each subsequent performance test within 12 calendar months following the date the previous performance test was required to be conducted. You must conduct each performance test according to the requirements in §60.8 using the test methods and procedures in §60.50Da. The owner or operator of an affected facility that has not operated for 60 consecutive calendar days prior to the date that the subsequent performance test would have been required had the unit been operating is not required to perform the subsequent performance test until 30 calendar days after the next boiler operating da y. Requests for additional 30 day extensions shall be granted by the relevant air division or office director of the appropr iate Regional Office of the U.S. EPA. Comment [CF11]: Add specific requirements for post MATS new and reconstructed facilities in 60.49Da(t).

Comment [CF12]: Date not necessary since stated in applicable paragraphs.

Comment [CF13]: More general references so do not need to update references when the standards are updated.18 (2) You must monitor the performance of each electrostatic precipitator or fabric f ilter (baghouse) operated to comply with the applicable PM emissions limit in §60.42Da (c)(2) or (d) using a continuous opacity monitoring system (COMS) according to the requirements in paragraphs (o)(2)(i) through (vi) unless you elect to comply with one of the alternatives provided in paragraphs (o)(3) and (o)(4) of this section, as applicable to your control device. (i) Each COMS must meet Performance Specification 1 in 40 CFR part 60, appendix B. (ii) You must comply with the quality assurance requirements in paragraphs (o)(2)(ii)(A) through (E) of this section. (A) You must automatically (intrinsic to the opacity monitor) check the zero and upscale (span) calibration drifts at least once daily. For a particular COMS, the acceptable range of zero and upscale calibration materials is as defined in the applicable version of Performance Specification 1 in 40 CFR part 60, appendix B. (B) You must adjust the zero and span whenever the 24-hour zero drift or 24-hour span drift exceeds 4 percent opacity. The COMS must allow for the amount of excess zero and span drift measured at the 24-hour interval checks to be recorded and quantified. The optical surfaces exposed to the effluent gases must be cleaned prior to performing the zero and span drift adjustments, except for systems using automatic zero adjustments. For systems using automatic zero adjustments, the optical surfaces must be cleaned when the cumulative automatic zero compensation exceeds 4 percent opacity. (C) You must apply a method for producing a simulated zero opacity condition and an upscale (span) opacity condition using a certified neutral density filter or other related technique to produce a known obscuration of the light beam. All procedures applied must provide a system check of the analyzer internal optical surfaces and all electronic circuitry including the lamp and photodetector assembly. (D) Except during periods of system breakdowns, repairs, calibration checks, and zero and span adjustments, the COMS must be in continuous operation and must complete a minimum of one cycle of sampling and analyzing for each successive 10 second period and one cycle of data recording for each successive 6-minute period. (E) You must reduce all data from the COMS to 6-minute averages. Six-minute opacity averages must be calculated from 36 or more data points equally spaced over each 6-minute period. Data recorded during periods of system breakdowns, repairs, calibration checks, and zero and span adjustments must not be included in the data averages. An arithmetic or integrated average of all data may be used. (iii) During each performance test conducted according to paragraph (o)(1) of this section, you must establish an opacity baseline level. The value of the opacity baseline level is determined by aver aging all of the 6-minute average opacity values (reported to the nearest 0.1 percent opacity) from the COMS measurements recorded during each of the test run intervals conducted for the performance test, and then adding 2.5 percent opacity to your calculated average opacity value for all of the test runs . If your opacity baseline level is less than 5.0 percent, then the opacity baseline le vel is set at 5.0 percent. (iv) You must evaluate the preceding 24-hour average opacity level measured by the COMS each boiler operating day excluding periods of affected facility startup, shut down, or malfunction. If the measured 24-hour average opacity emission level is greater than the baseline opacity le vel determined in paragraph (o )(2)(iii) of this section, you must initiate investigation of the relevant equipm ent and control systems within 24 hours of the first discovery of the high opacity incident and take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the measured 24-hour average opacity to a level below the baseline opacity level. In cases when a wet scrubber is used in combination with another PM control device that serves as the primary PM control device, the wet sc rubber must be maintained and operated. (v) You must record the opacity measurements, calculations performed, and any corrective actions taken. The record of corrective action taken must include the date and time during which the measured 24-hour average opacity was greater than baseline opacity level, and th e date, time, and description of the corrective action. (vi) If the measured 24-hour average opacity for your affected facility remains at a level greater than the opacity baseline level after 7 boiler operating days, then you must conduct a new PM performance test according to paragraph (o)(1) of this section and establish a new opacity baseline value according to paragraph (o)(2) of this19 section. This new performance test must be conducted within 60 days of the date that the measured 24-hour average opacity was first determined to exceed the baseline opacity level unless a waiver is granted by the permitting authority. (3) As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner or operator may elect to monitor the performance of an electrostatic pr ecipitator (ESP) operated to comply with the applicable PM emissions limit in §60.42Da (c)(2) or (d) using an ESP predictive model developed in accordance with the requirements in paragraphs (o)(3)(i) through (v) of this section. (i) You must calibrate the ESP predictive model with each PM control device used to comply with the applicable PM emissions limit in §60.42Da (c)(2) or (d) operating under normal conditions. In cases when a wet scrubber is used in combination with an ESP to comply with the PM emissions limit, the wet scrubber mu st be maintained and operated. (ii) You must develop a site-specific monitoring plan that includes a description of the ESP predictive model used, the model input parameters, and the procedures and criteria for establishing monitoring parameter baseline levels indicative of compliance with the PM emissions li mit. You must submit the site-specific monitoring plan for approval by the permitting authority. For reference pu rposes in preparing the moni toring plan, see the OAQPS “Compliance Assurance Monitoring (CAM) Protocol fo r an Electrostatic Precipitator (ESP) Controlling Particulate Matter (PM) Emissions from a Coal-Fired Boiler.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality Planning and Standards; Sector Policies and Programs Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Continuous Emission Monitoring. (iii) You must run the ESP predictive model using the applicable input data each boiler operating day and evaluate the model output fo r the preceding bo iler operating da y excluding periods of a ffected facility startup, shutdown, or malfunction. If the values for one or more of the model parameters exceed the applicable baseline levels determined acco rding to your approved site-sp ecific monitoring plan, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of a model parameter deviation and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to return the model output to within th e applicable baseline levels. (iv) You must record the ESP predictive model inputs and outputs and any corrective actions taken. The record of corrective action taken must include the date and time during which the model output values exceeded the applicable baseline levels, and the date, time, and description of the corrective action. (v) If after 7 consecutive days a model parameter continues to exceed the applicable baseline level, then you must conduct a new PM performance test according to paragraph (o)(1) of this section. This new performance test must be conducted within 60 calendar days of the date that the model parameter was first determined to exceed its baseline level unless a wa iver is granted by the permitting authority. (4) As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner or operator may elect to monitor the perfo rmance of a fabric filter (baghouse) operated to comply with the applicable PM emissions limit in §60.42Da (c)(2) or (d) by using a bag leak detection system according to the requirements in paragraphs (o)(4)(i) through (v) of this section. (i) Each bag leak detection system must meet the specifications and requirements in paragraphs (o)(4)(i)(A) through (H) of this section. (A) The bag leak detection system must be certified by the manufacturer to be capable of detecting PM emissions at concentrations of 1 milligram per actual cubic meter (0.00044 grains per actual cubic foot) or less. (B) The bag leak detection system sensor must provide output of relative PM loadings. The owner or operator must continuously record the output from the bag leak detection system using electronic or other means ( e.g. , using a strip chart recorder or a data logger.)20 (C) The bag leak detection system must be equipped with an alarm system that will react when the system detects an increase in relative particulate loading over the alarm set point established according to paragraph (o)(4)(i)(D) of this section, and the alarm must be located such that it can be noticed by the appropriate plant personnel. (D) In the initial adjustment of the bag leak detection system, you must establish, at a minimum, the baseline output by adjusting the sensitivity (range) and the averaging period of the device, the alarm set points, and the alarm delay time. (E) Following initial adjustment, you must not adjust the averaging period, alarm set point, or alarm delay time without approval from the permitting authority except as provided in paragraph (d)(1)(vi) of this section. (F) Once per quarter, you may adjust the sensitivity of the bag leak detection system to account for seasonal effects, including temperature and humidity, according to the procedures identified in the site-specific monitoring plan required by paragraph (o)(4)(ii) of this section. (G) You must install the bag leak detection sensor downstream of the fabric filter and upstream of any wet scrubber. (H) Where multiple detectors are required, the system's instrumentation and alarm may be shared among detectors. (ii) You must develop and submit to th e permitting authority for ap proval a site-specific m onitoring plan for eachbag leak detection system. You must operate and maintain the bag leak detection system according to the sitespecific monitoring plan at all times. Each monitoring plan must describe the items in paragraphs (o)(4)(ii)(A) through (F) of this section. (A) Installation of the bag leak detection system; (B) Initial and periodic adjustment of the bag leak detection system, including how the alarm set-point will be established; (C) Operation of the bag leak detection system, including quality assurance procedures; (D) How the bag leak detec tion system will be ma intained, including a routine ma intenance schedule and spare parts inventory list; (E) How the bag leak detection system output will be recorded and stored; and (F) Corrective action procedures as specified in paragraph (o)(4)(iii) of this section. In approving the site-specific monitoring plan, the permitting authority ma y allow owners and operators mo re than 3 hours to alleviate a specific condition that causes an alarm if the owner or operator identifies in the monitoring plan this specific condition as one that could lead to an alarm, adequately ex plains why it is not feasible to alleviate this condition within 3 hours of the time the alarm occurs, and demonstr ates that the requested time will ensure alleviation of this condition as expeditiously as practicable. (iii) For each bag leak detec tion system, you must initiate procedures to dete rmine the cause of every alarm within 1 hour of the alarm. Except as provided in paragraph (o)(4)(ii)(F) of this section, you must alleviate the cause of the alarm within 3 hours of the alarm by taking whatev er corrective action(s) are necessary. Corrective actions may include, but are not limited to the following: (A) Inspecting the fabric filter for air leaks, torn or broken bags or filter media, or any other condition that may cause an increase in particulate emissions; (B) Sealing off defective bags or filter media; (C) Replacing defective bags or filter media or otherwise repairing the control device; (D) Sealing off a defective fabric filter compartment; (E) Cleaning the bag leak detection system probe or ot herwise repairing the bag leak detection system; or (F) Shutting down the process producing the particulate emissions.21 (iv) You must maintain records of the information specified in paragraphs (o)(4)(iv)(A) through (C) of this section for each bag leak detection system. (A) Records of the bag leak detection system output; (B) Records of bag leak det ection system adjustments, including the da te and time of the adjustment, the initial bag leak detection system settings, and the final bag leak detection system settings; and (C) The date and time of all bag leak detection system al arms, the time that procedures to determine the cause of the alarm were initiated, if procedures were initiated wi thin 1 hour of the alarm, the cause of the alarm, an explanation of the actions taken, the date and time the cause of the alarm was alleviated, and if the alarm was alleviated within 3 hours of the alarm. (v) If after any period composed of 30 boiler operating days during which the alarm rate exceeds 5 percent of the process operating time (excluding control device or process startup, shutdown, and malfunction), then you must conduct a new PM performance test according to paragraph (o)(1) of this section. This new performance test must be conducted within 60 calendar days of the date that th e alarm rate was first determined to exceed 5 percent limit unless a waiver is granted by the permitting authority. (5) An owner or operator of a modified affected facility electing to meet the emission limitations in §60.42Da(d) shall determine the percent re duction in PM by using the emission rate for PM determined by the performance test conducted according to the requirements in paragraph (o)(1) of this section and the ash content on a mass basis of the fuel burned during each performance test run as determined by analysis of the fuel as fired. (p) As an alternative to meeting the compliance provisions specified in paragraph (o) of this section, an owner or operator may elect to install, evaluate, maintain, and operate a CEMS measuring PM emissions discharged from the affected facility to the atmosphere and record the output of the system as specified in paragraphs (p)(1) through (p)(8) of this section. (1) The owner or operator shall submit a written notifi cation to the Administrator of intent to demonstrate compliance with this subpart by using a CEMS measuring PM. This notification shall be sent at least 30 calendar days before the initial startup of the monitor for compliance determination purposes. The owner or operator may discontinue operation of the monitor and instead return to demonstration of comp liance with this subpart according to the requirements in pa ragraph (o) of this section by submitting written notification to the Administrator of such intent at least 30 calendar days before shutdown of the monitor for compliance determination purposes. (2) Each CEMS shall be installed, evaluated, operated, and maintained according to the requirements in §60.49Da(v). (3) The initial performance evaluation sha ll be completed no later than 180 days after the date of initial startup of the affected facility, as specified under §60.8 of subpart A of this part or within 180 days of the date of notification to the Administrator required under paragraph (p)(1) of this section, whichever is later. (4) Compliance with the applicable emissions limit shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emissions concentrations using the continuous monitoring system outlet data. The 24-hour block arithmetic average emission concentration shall be calculated using EPA Reference Method 19 of appendix A of this part, section 4.1. (5) At a minimum, non-out-of-control CEMS hourly averages shall be obtained for 75 percent of all operating hours on a 30-boiler operating day rolling average basis. Beginning on January 1, 2012, non-out-of-control CEMS hourly averages shall be obtained for 90 percent of al l operating hours on a 30-boiler operating day rolling average basis. (i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average. (ii) [Reserved] (6) The 1-hour arithmetic averages required shall be expressed in ng/J, MMBtu/hr, or lb/MWh and shall be used to calculate the boiler operating day daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under §60.13(e)(2) of subpart A of this part.22 (7) All non-out-of-control CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS data requirements of paragraph (j)(5) of this section are not met. (8) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring systems as approved by theAdministrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, non-out-ofcontrol emissions data for a minimum of 90 percent (only 75 percent is required prior to January 1, 2012) of all operating hours per 30-boiler op erating day rolling average. (q) Compliance provisions for sources subject to §60.42Da(b) . An owner or operator of an affected facility subject to the opacity standard in §60.42Da(b) shall monitor the opacity of emissions discharged from the affected facility to the atmosphere according to the requirements in §60.49Da(a), as applicable to the affected facility. (r) Compliance provisions for sources subject to §60.45Da. To determine compliance with the NO X plus CO emissions limit, the owner or operator shall use the procedures specified in paragraphs (r)(1) through (3) of this section. (1) Calculate NO X emissions as 1.194 × 10 − 7 lb/scf-ppm times the average hourly NO X output concentration in ppm (measured according to the provisions of §60.49Da(c)), times the average hourly flow rate (measured in scfh, according to the provisions of §60.49Da(l) or §60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)) or the average hourly net energy output, as applicable. (2) Calculate CO emissions by multiplying the average hourly CO output concentration (measured according to the provisions of §60.49Da(u), by the average hourly flow rate (measured according to the provisions of §60.49Da(l) or §60.49Da(m)), and dividing by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)) or the average hourly net energy output, as applicable. (3) Calculate NO X plus CO emissions by summing the NO X emissions results from paragraph (r)(1) of this section plus the CO emissions results from paragraph (r)(2) of this section. (s) Affirmative defense for exceedance of emissions limit during malfunction. In response to an action to enforce the standards set forth in paragraph §§60.42Da, 60.43Da, 60.44Da, and 60.45Da, you may assert an affirmative defense to a claim for civil penalties for exceedances of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropriate penalties ma y be assessed, however, if you fail to meet your burden of proving all of the requirements in the affirmative defense as specified in paragraphs (s)(1) and (2) of this section. The affirmative defense shall not be available for claims for injunctive relief. (1) To establish the affirmative defense in any action to enforce such a limit, you must timely meet the notification requirements in paragraph (s)(2) of this section, and must prove by a preponderance of evidence that: (i) The excess emissions: (A) Were caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner; and (B) Could not have been prevented through careful planning, proper design, or better operation and maintenance practices; and (C) Did not stem from any activity or event that could have been foreseen and avoided, or planned for; and (D) Were not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and (ii) Repairs were made as expeditiously as possible when the applicable emissions limits were being exceeded. Off-shift and overtime labor were used, to the extent practicable to make these repairs; and (iii) The frequency, amount, and duration of the excess emissions (including any bypass) were minimized to the maximum extent practicable during periods of such emissions; and (iv) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, personal injury, or severe property damage; and (v) All possible steps were taken to minimize the impact of the excess emissions on ambient air quality, the environment, and human health; and23 (vi) All emissions monitoring and control systems were kept in operation if at all possibl e, consistent with safety and good air pollution control practices; and (vii) All of the actions in response to the excess emissions were documented by properly signed, contemporaneous operating logs; and (viii) At all times, the facility was operated in a manner consistent with good practices for minimizing emissions; and (ix) A written root cause analysis has b een prepared, th e purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the excess emissions re sulting from the malfuncti on event at issue. The analysis shall also specify, using best monitoring me thods and engineering judgment, the amount of excess emissions that were the result of the malfunction. (2) Notification. The owner or operator of the affected source experiencing an exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile (FAX) transmission as soon as possible, but no later than two business days after the initial occurrence of the malfunction or, if it is not possible to determine within two business days whether the malfunction caused or contributed to an exceedance, no later than two business days after the owner or operator knew or should have known that the malfunction caused or contributed to an exceedance, but, in no event later than two business days after the end of the averaging period, if it wishes to avail itself of an affirmative defense to ci vil penalties for that malfunction. The owner or operator seeking to assert an affirm ative defense shall also submit a written report to the Administrator within 45 days of the initial occurrence of the exceedance of the standard in §63.9991 to demonstrate, with all necessary supporting documentation, that it has met the requirements set forth in paragraph (s)(1) of this section. The owner or operator may seek an extens ion of this deadline for up to 30 additional days by submitt ing a written request to the Administrator before the expiration of the 45 day period. Until a request for an extension has been approved by the Administrator, the owner or operator is subject to the requirement to submit such report within 45 days of the initial occurrence of the exceedance. [72 FR 32722, June 13, 2007, as amended at 74 FR 5079, Jan. 28, 2009; 76 FR 3522, Jan. 20, 2011; 77 FR 9454, Feb. 16, 2012] § 60.49Da Emission monitoring. (a) An owner or operator of an affected facility subject to the opacity standard in §60.42Da (b) must shall monitor the opacity of emissions discharged from the affected facility to the atmosphere according to the applicable requirements in paragraphs (a)(1) through ( 3 4 ) of this section. (1) Except as provided for in paragraphs (a)(2) and (4) of this section, the owner or operator of an affected facility subject to an opacity standard, shall install, calibrate, maintain, and operate a COMS, and record the output of the system, for measuring the opacity of emissions discharged to the atmosphere. If opacity interference due to water droplets exists in the stack (for example, from the use of an FGD system), the opacity is monitored upstream of the interference (at the inlet to the F GD system). If opacity interference is experienced at all locations (both at the inlet and outlet of the SO 2 control system), alternate parameters indicative of the PM control system's performance and/or good combustion are monitored (subject to the approval of the Administrator). (2) As an alternative to the monitoring requirements in paragraph (a)(1) of this section, an owner or operator of an affected facility that meets the conditions in either paragraph (a)(2)(i), (ii), (iii), or (iv) of this section may elect to monitor opacity as specified in paragraph (a)(3) of this section. (i) The affected facility uses a fabric filter (baghouse) to meet the standards in §60.42Da and a bag leak detection system is installed and operated according to the requirements in paragraphs §60.48Da(o)(4)(i) through (v); (ii) The affected facility burns only gaseous or liqu id fuels (excluding residua l oil) with potential SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion technology to reduce emissions of SO 2 or PM; (iii) The affected facility meets all of the conditions specified in paragraphs (a)(2)(iii)(A) through (C) of this section.24 (A) No post-combustion technology (except a wet scrubber) is used for reducing PM, SO 2 , or CO emissions; (B) Only natural gas, gaseous fuels, or fuel oils that contain less than or equal to 0.30 weight percent sulfur are burned; and (C) Emissions of CO discharged to the atmosphere are maintained at levels less than or equal to 1.4 lb/MWh on a boiler operating day average basis as demonstrated by the use of a CEMS measuring CO emissions according to the procedures specified in paragraph (u) of this section; or (iv) The affected facility uses an ESP and uses an ES P predictive model to monitor the performance of the ESP developed in accordance and operated according to the most current requirements in section §60.48Da of this part. (3) The owner or operator of an affected facility that m eets the conditions in paragraph (a)(2) of this section may, as an alternative to using a COMS, elect to monitor visible emissions using the applicable procedures specified in paragraphs (a)(3)(i) through (iv) of this section. The opacity performance test requirement in paragraph (a)(3)(i) must be conducted by April 29, 2011, within 45 days after stopping use of an existing COMS, or within 180 days after initial startup of the facility, whichever is later. (i) The owner or operator shall conduct a performance test using Method 9 of appendix A–4 of this part and the procedures in §60.11. If during the initial 60 minutes of the observation all the 6-minute averages are less than 10 percent and all the individual 15-second observations are le ss than or equal to 20 per cent, then the observation period may be reduced from 3 hours to 60 minutes. (ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this section, the owner or operator shall conduct subsequent Method 9 of appendix A–4 of this part performance tests using the procedures in paragraph (a)(3)(i) of this section according to the applicable schedule in paragraphs (a)(3)(ii)(A) through (a)(3)(ii)(C) of this section, as determined by the most recent Method 9 of appendix A–4 of this part performance test results. (A) If the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 12 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later; (B) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 3 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later; or (C) If the maximum 6-minute average opacity is greater than 10 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 45 calendar days from the date that the most recent performance test was conducted. (iii) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 of this part performance tests, elect to perform subsequent monitoring using Method 22 of appendix A–7 of this part according to the procedures specified in paragraphs (a)(3)(iii)(A) and (B) of this section. (A) The owner or operator shall conduct 10 minute observations (during normal operation) each operating day the affected facility fires fuel for which an opacity standard is applicable usin g Method 22 of appendix A–7 of this part and demonstrate that the sum of the occurrences of any visible emissions is not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the occurrence of visible emissions is greater than 5 percent of the observation period ( i.e., 90 seconds per 30 minute period), the owner or operator shall either docume nt and adjust the operation of the facility and demonstrate within 24 hours that the sum of the occurrence of visible emissions is equal to or less than 5 percent during a 30 minute observation ( i.e., 90 seconds) or conduct a new Method 9 of appendix A–4 of this part performance test using the procedures in paragraph (a)(3)(i) of this section within 45 calendar days according to the requirements in §60.50Da(b)(3).25 (B) If no visible emissions are observed for 10 operating days during which an opacity standard is applicable, observations can be reduced to once every 7 operating days during which an opacity standard is applicable. If any visible emissions are observed, daily observations shall be resumed. (iv) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 performance tests, elect to perform subsequent monitoring using a digital opacity compliance system according to a site-specific monitoring plan approved by the Administrator. The observations shall must be similar, but not necessarily identical, to the requirements in paragraph (a)(3)(iii) of this section. For reference purposes in preparing the monitoring plan, see OAQ PS “Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Planning St andards; Sector Policies and Programs Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Preliminary Methods. (4) An owner or operator of an affected facility that is subject to an opacity standard under §60.42 D a (b) is not required to operate a COMS provided that affected facility meets the conditions in either paragraph (a)(4)(i) or (ii) of this section. (i) The affected facility combusts only gaseous fuels and/or liquid fuels (excluding residue oil) with where the a potential SO 2 emissions rate of each fuel is no greater than 26 ng/J (0.060 lb/MMBtu), and the unit operates according to a written site -specific monitoring plan approved by the perm itting authority. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affected facility indicative of compliance with the opacity standard. For testing performed as part of this site-specific monitoring plan, the permitting authority may require as an alternative to the notificatio n and reporting requirements specified in §§60.8 and 60.11 that the owner or operator submit any deviations with the excess emissions report required under §60.51Da(d). (ii) The owner or operator of the affected facility insta lls, calibrates, operates, and maintains a particulate matter continuous parametric monitoring system (PM CPMS) according to the requirements specified in subpart UUUUU of part 63. (iv) If the maximum 6

- minute opacity is less than 10 percent during the most recent Method 9 of appendix A

– 4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A

– 4 performance tests, elect to perform subsequent monitoring using a digital opacity compliance system accor ding to a site

- specific monitoring plan approved by the Administrator. The observations shall be similar, but not necessarily identical, to the requirements in paragraph (a)(3)(iii) of this section. For reference purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission Opacity from Stationary Sources Using Computer

- Based Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Planning Standa rds; Sector Policies and Programs Division; Measurement Policy Group (D243

– 02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emission Measurement Center Preliminary Methods. (b) The owner or operator of an affected facility shall must install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring SO 2 emissions, except where only natural gas gaseous and/or liquid fuels (excluding residual oil) with where the potential SO 2 emissions rate s of each fuel is 26 ng/J (0.060 lb/MMBtu) or less are the only fuels combusted, as follows: (1) Sulfur dioxide emissions are monitored at both the inlet and outlet of the SO 2 control device. (2) For a facility that qualifies under the numerical limit provisions of §60.43Da, SO 2 emissions are only monitored as discharged to the atmosphere. (3) An “as fired” fuel monitoring system (upstream of coal pulverizers) meeting the requirements of Method 19 of appendix A of this part may be used to determine potential SO 2 emissions in place of a continuous SO 2 emission monitor at the inlet to the SO 2 control device as required under paragraph (b)(1) of this section. Comment [CF14]: Listed in the wrong order in the electronic CFR

Comment [CF15]: Specify each individual fuel

Comment [CF16]: Exempt all low sulfur gaseous fuels (synthetic natural gas) from the SO2 CEMS requirement.

Clarify language that requirement is specific to each fuel and not the combined average emissions rate.26 (4) If the owner or operator has installed and certified a SO 2 CEMS according to the requirements of §75.20(c)(1) of this chapter and appendix A to part 75 of this chapter, and is continuing to meet the ongoing quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this chapter, that CEMS may be used to meet the requirements of this section, provided that: (i) A CO 2 or O 2 continuous monitoring system is installed, calibrated, maintained and operated at the same location, according to paragraph (d) of this section; and (ii) For sources subject to an SO 2 emission limit in lb/ MMBtu under §60.43Da: (A) When relative accuracy testing is conducted, SO 2 concentration data and CO 2 (or O 2 ) data are collected simultaneously; and (B) In addition to meeting the applicable SO 2 and CO 2 (or O 2 ) relative accuracy specifications in Figure 2 of appendix B to part 75 of this chapter, the relative accuracy (RA) standard in section 13.2 of Performance Specification 2 in appendix B to this part is met wh en the RA is calculated on a lb/MMBtu basis; and (iii) The reporting requirements of §60.51Da are met. The SO 2 and, if required, CO 2 (or O 2 ) data reported to meet the requirements of §60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of th is chapter, nor shall the SO 2 data have been bias adjusted according to the procedures of part 75 of this chapter. (c)(1) The owner or operator of an affected facility sh all install, calibrate, mainta in, and operate a CEMS, and record the output of the system, for measuring NO X emissions discharged to the atmosphere; or (2) If the owner or operator has installed a NO X emission rate CEMS to meet the requirements of part 75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this chapter, that CEMS may be used to meet the requirements of this section, except that the owner or operator shall also meet the requirements of §60.51Da. Data reported to meet the requirements of §60.51Da shall not include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. (d) The owner or operator of an affected facility not comp lying with an output based lim it shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring the O 2 or carbon dioxide (CO 2 ) content of the flue gases at each location where SO 2 or NO X emissions are monitored. For affected facilities subject to a lb/MMBtu SO 2 emission limit under §60.43Da, if the owner or operator has installed and certified a CO 2 or O 2 monitoring system according to §75.20(c) of this chapter and appendix A to part 75 of this chapter and the monitoring system continues to meet the applicable quality-assurance provisions of §75.21 of this chapter and appendix B to part 75 of this chapter, that CEMS may be used together with the part 75 SO 2 concentration monitoring system described in paragraph (b) of this section, to determine the SO 2 emission rate in lb/MMBtu. SO 2 data used to meet the requirements of §60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. (e) The CEMS under paragraphs (b), (c), and (d) of this section are operated and data recorded during all periods of operation of the affected facility including periods of startup, shutdown, and malfunction, except for CEMS breakdowns, repairs, calibration checks, and zero and span adjustments. (f)(1) For units that began construction, reconstruction, or modification on or before February 28, 2005, the owner or operator shall obtain emission data for at least 18 hours in at least 22 out of 30 successive boiler operating days. If this minimum data requirement cannot be met with CEMS, the owner or operator shall supplement emission data with other monitoring systems approved by the Administrator or the reference methods and procedures as described in paragraph (h) of this section. (2) For units that began construction, reconstruction, or modification after February 28, 2005, the owner or operator shall obtain emission data for at least 90 perc ent of all operating hours for each 30 successive boiler operating days. If this minimum data requirement cannot be met with a CEMS, the owner or operator shall supplement emission data with other monitoring systems approved by the Administrator or the reference methods and procedures as described in paragraph (h) of this section.27 (g) The 1-hour averages required under paragraph §60.13(h) are expressed in ng/J (lb/MMBtu) heat input and used to calculate the average emission rates under §60.48Da. The 1-hour averages are calculated using the data points required under §60.13(h)(2). (h) When it becomes necessary to supplement CEMS data to meet the minimum data requirements in paragraph (f) of this section, the owner or operator shall use the reference methods and procedures as specified in this paragraph. Acceptable alternative methods and procedures are given in paragraph (j) of this section. (1) Method 6 of appendix A of this part shall be used to determine the SO 2 concentration at the same location as the SO 2 monitor. Samples shall be taken at 60-minute intervals. The sampling time and sample volume for each sample shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Each sample represents a 1-hour average. (2) Method 7 of appendix A of this part shall be used to determine the NO X concentration at th e same location as the NO X monitor. Samples shall be taken at 30-minute intervals. The arithmetic average of two consecutive samples represents a 1-hour average. (3) The emission rate correction factor, integrated bag sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O 2 or CO 2 concentration at the same location as the O 2 or CO 2 monitor. Samples shall be taken for at least 30 minutes in each hour. Each sample represents a 1-hour average. (4) The procedures in Method 19 of appendix A of this part shall be used to compute each 1-hour average concentration in ng/J (lb/MMBtu) heat input. (i) The owner or operator shall use methods and procedures in this paragraph to conduct monitoring system performance evaluations under §60.13(c) and calibration checks under §60.13(d). Acceptable alternative methods and procedures are given in paragraph (j) of this section. (1) Methods 3B, 6, and 7 of appendix A of this part shall be used to determine O 2 , SO 2 , and NO X concentrations, respectively. (2) SO 2 or NO X (NO), as applicable, shall be used for pr eparing the calibration gas mixtures (in N 2 , as applicable) under Performance Specification 2 of appendix B of this part. (3) For affected facilities burning only fossil fuel, the sp an value for a COMS is betw een 60 and 80 percent. Span values for a CEMS measuring NO X shall be determined using one of the following procedures: (i) Except as provided under paragraph (i)(3)(ii) of this section, NO X span values shall be determined as follows:

Fossil fuel Span values for NO X (ppm)

Gas 500.

Liquid 500.

Solid 1,000.

Combination 500 (x + y) + 1,000z.

Where: x = Fraction of total heat input derived from gaseous fossil fuel, y = Fraction of total heat input derived from liquid fossil fuel, and z = Fraction of total heat input derived from solid fossil fuel. (ii) As an alternative to meeting the requirements of paragraph (i)(3)(i) of this section, the owner or operator of an affected facility may elect to use the NO X span values determined according to section 2.1.2 in appendix A to part 75 of this chapter.28 (4) All span values computed under paragraph (i)(3)(i) of this section for burning combinations of fossil fuels are rounded to the nearest 500 ppm. Span values computed under paragraph (i)(3)(ii) of this section shall be rounded off according to section 2.1.2 in appendix A to part 75 of this chapter. (5) For affected facilities burning foss il fuel, alone or in combination with non-fossil fuel and determining span values under paragraph (i)(3)(i) of this section, the span value of the SO 2 CEMS at the inlet to the SO 2 control device is 125 percent of the maximum estimated hourly potential emissions of the fuel fired, and the outlet of the SO 2 control device is 50 percent of maximum estimated hourly potential emissions of the fuel fired. For affected facilities determining span values under pa ragraph (i)(3)(ii) of this section, SO 2 span values shall be determined according to section 2.1.1 in appendix A to part 75 of this chapter. (j) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this section: (1) For Method 6 of appendix A of this part, Method 6A or 6B (whenever Methods 6 and 3 or 3B of appendix A of this part data are used) or 6C of appendix A of this part may be used. Each Method 6B of appendix A of this part sample obtained over 24 hours represents 24 1-hour averages. If Method 6A or 6B of appendix A of this part is used under paragraph (i) of this section, the conditions under §60.48Da(d)(1) apply; these conditions do not apply under paragraph (h) of this section. (2) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run shall be 1 hour. (3) For Method 3 of appendix A of this part, Method 3A or 3B of appendix A of this part may be used if the sampling time is 1 hour. (4) For Method 3B of appendix A of this part, Method 3A of appendix A of this part may be used. (k) The procedures specified in paragraphs (k)(1) through (3) of this section shall be used to determine gross energy output for sources demonstrating compliance with an output-based standard. (1) The owner or operator of an affected facility with el ectricity generation shall inst all, calibrate, maintain, and operate a wattmeter; measure gross electrical output in MWh on a continuous basis; and record the output of the monitor. (2) The owner or operator of an affected facility with pr ocess steam generation shall install, calibrate, maintain, and operate meters for steam flow, temperature, and pressure; measure gross process steam output in joules per hour (or Btu per hour) on a continuous basis; and record the output of the monitor. (3) For an affected facility generating process steam in co mbination with electrical generation, the gross energy output is determined according to the definition of “gross energy output” specified in §60.41Da that is applicable to the affected facility. (l) The owner or operator of an affected facility demons trating compliance with an ou tput-based standard shall install, certify, operate, and mainta in a continuous flow monitoring system meeting the requirements of Performance Specification 6 of appendix B of this part and the calibration drift (CD) assessment, relative accuracy test audit (RATA), and reporting provisions of procedure 1 of appendix F of this part, and record the output of the system, for measuring the volumetric flow rate of exhaust gases discharged to the atmosphere; or (m) Alternatively, data from a continuous flow monito ring system certified according to the requirements of §75.20(c) of this chapter and appendix A to part 75 of this chapter, and continuing to meet the applicable quality control and quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this chapter, may be used. Flow rate data reported to meet the requirements of §60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter. (n) 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 40 CFR 72.2, may use, as an alternative to the requirements specified in either paragraph (l) or (m) of this section, a fuel flow monitoring system certified and operated according to the requirements of appendix D of part 75 of this chapter.29 (o) The owner or operator of a duct burner, as described in §60.41Da, which is subject to the NO X standards of §60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate a CEMS to measure NO X emissions; a wattmeter to measure gross electrical output; meters to measure steam flow, temperature, and pressure; and a continuous flow monitoring system to measure the flow of exhaust gases discharged to the atmosphere. (p)–(r) [Reserved] (s) The owner or operator shall prepare and submit to the Administrator for approval a unit-specific monitoring plan for each monitoring system, at least 45 days before commencing certification testing of the monitoring systems. The owner or operator shall comply with the requirements in your plan. The plan must address the requirements in paragraphs (s)(1) through (6) of this section. (1) Installation of the CEMS sampling probe or other inte rface at a measurement location relative to each affected process unit such that the measurement is representative of the exhaust emissions ( e.g. , on or downstream of the last control device); (2) Performance and equipment specifications for the sample interface, the pollutant concentration or parametric signal analyzer, and the data collection and reduction systems; (3) Performance evaluation procedures and acceptance criteria ( e.g., calibrations, relative accuracy test audits (RATA), etc.); (4) Ongoing operation and maintenance procedures in accordance with the general requirements of §60.13(d) or part 75 of this chapter (as applicable); (5) Ongoing data quality assurance procedures in accordance with the general requirements of §60.13 or part 75 of this chapter (as applicable); and (6) Ongoing recordkeeping and reporting procedures in accordance with the requirements of this subpart. (t) The owner or operator of an affect ed facility demonstra ting compliance with the an output-based emissions limitation limit under §60.42Da shall must either install, certify, operate, and maintain a CEMS for measuring PM emissions according to the requirements of paragraph (v) of this section or install, calibrate, operate, and maintain a PM CPMS according to the requirements for new facilities specified in subpart UUUUU of part 63 of this chapter . An owner or operator of an affected facility demonstrating compliance with the input-based emissions limit in §60.42Da may install, certify, operate, and ma intain a CEMS for measuring PM emissions according to the requirements of paragraph (v) of this section. (u) The owner or operator of an affected facility using a CEMS measuring CO emissions to meet requirements of this subpart shall meet the requirements specified in paragraphs (u)(1) through (4) of this section. (1) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (u)(1)(i) through (iv) of this section. (i) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in §60.58b(i)(3) of subpart Eb of this part. (ii) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS expressed in parts per million by volu me corrected to 3 perc ent oxygen (dry basis). (iii) At a minimum, non-out-of-control 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-boiler operating day rolling average basis. The 1-hour averages are calculated using the data points required in §60.13(h)(2). (iv) Quarterly accuracy determinations and daily calibra tion drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part. (2) You must calculate the 1-hour average CO emissions levels for each boiler operating day by multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly useful energy output from the affected facility. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each boiler operating day. Comment [CF17]: Add in PM CPMS for all facilities complying with an output based PM standard.30 (3) You must evaluate the preceding 24-hour average CO emission level each boiler operating day excluding periods of affected facility startup, shutdown, or malfunction. If the 24-hour average CO emission level is greater than 1.4 lb/MWh, you must initiate in vestigation of the relevant equipment and control systems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 1.4 lb/MWh or less. (4) You must record the CO measurements and calculations performed according to paragraph (u)(3) of this section and any corrective actions taken. The record of corrective action taken must include the date and time during which the 24-hour average CO emission level was greater than 1.4 lb/MWh, and the date, time, and description of the corrective action. (v) The owner or operator of an affected facility using a CEMS measuring PM emissions to meet requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (v)(1) through (v)(4) of this section. (1) The owner or operator shall conduct a performanc e evaluation of the CEMS according to the applicable requirements of §60.13, Performance Specification 11 in appendix B of this part, and procedure 2 in appendix F of this part. (2) During each PM correlation testing run of the CEMS required by Performance Specification 11 in appendix B of this part, PM and O 2 (or CO 2 ) data shall be collected concurrently (or within a 30- to 60-minute period) by both the CEMS and performance tests conducted using the following test methods. (i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part shall be used; and (ii) For O 2 (or CO 2 ), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used. (3) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of this part. Relative Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years. (4) As of January 1, 2012, and within 90 days after the date of completing each performance test, as defined in §60.8, conducted to demonstrate compliance with this subpart, you must submit relative accuracy test audit ( i.e., reference method) data and performance test ( i.e., compliance test) data, except opacity data, electronically to EPA's Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/ch ief/ert/ert tool.html/ ) or other compatible electronic spreadsheet. Only data collected using test methods compatible with ERT are subject to this requirement to be submitted electronically into EPA's WebFire database. (w) The owner or operator using a SO 2 , NO X , CO 2 , and O 2 CEMS to meet the requiremen ts of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (w)(1) through (w)(5) of this section. (1) Except as provided for under paragraphs (w)(2), (w)(3), and (w)(4) of this section, each SO 2 , NO X , CO 2 , and O 2 CEMS required under paragraphs (b) through (d) of this section shall be installed, certified, and operated in accordance with the applicable procedures in Performance Specification 2 or 3 in appendix B to this part or according to the procedures in appendices A and B to part 75 of this chapter. Daily calibration drift assessments and quarterly accuracy determinations shall be done in accordance with Procedure 1 in appendix F to this part, and a data assessment report (DAR), prepared according to section 7 of Procedure 1 in appendix F to this part, shall be submitted with each compliance report required under §60.51Da. (2) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to implement the following al ternative data accuracy assessment procedures. For all required CO 2 and O 2 CEMS and for SO 2 and NO X CEMS with span values greater than or equal to 100 ppm, the daily calibration error test and calibration adjustment procedures described in sections 2.1.1 and 2.1.3 of appendix B to part 75 of this chapter may be followed instead of the CD assessment procedures in Procedure 1, section 4.1 of appendix F of this part. If this option is selected, the data validation and out-of-control provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75 of this chapter shall be followed instead of the excessive CD and out-of-control criteria31 in Procedure 1, section 4.3 of appendix F to this part. For the purposes of data validation under this subpart, the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part shall apply to SO 2 and NO X span values less than 100 ppm; (3) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to may elect to implement the following alternative data accuracy assessment procedures. For all required CO 2 and O 2 CEMS and for SO 2 and NO X CEMS with span values greater than 30 ppm, quarterly linearity checks may be performed in accordance with section 2.2.1 of appendix B to part 75 of this chapter, instead of performing the cylinder gas audits (CGAs) described in Procedure 1, section 5.1.2 of appendix F to this part. If this option is selected: The frequency of the linearity checks shall be as specified in section 2.2.1 of appendix B to part 75 of this chapter; the applicable linearity specifications in sec tion 3.2 of appendix A to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.2.3 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and ou t-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.2.4 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the cylinder gas audits described in Procedure 1, section 5.1.2 of appendix F to this part shall be performed for SO 2 and NO X span values less than or equal to 30 ppm; (4) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to may elect to implement the following alte rnative data accuracy assessment procedures. For SO 2 , CO 2 , and O 2 CEMS and for NO X CEMS, RATAs may be performed in accordance with section 2.3 of appendix B to part 75 of this chapter instead of following the procedures described in Procedure 1, section 5.1.1 of appendix F to this part. If this option is selected: The frequency of each RATA shall be as specified in section 2.3.1 of appendix B to part 75 of this chapter; the applicable relative accuracy specifications shown in Figure 2 in appendix B to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.3.2 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.3.3 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under this subpart, the relative accuracy specification in section 13.2 of Performance Specification 2 in appendix B to this part shall be met on a lb/MMBtu basis for SO 2 (regardless of the SO 2 emission level during the RATA), and for NO X when the average NO X emission rate measured by the reference method during the RATA is less than 0.100 lb/MMBtu; (5) If the owner or operator elects to implement the alternative data assessment procedures described in paragraphs (w)(2) through (w)(4) of this section, each data assessment report shall include a summary of the results of all of the RATAs, linearity checks, CGAs, and calibration error or drift assessments required by paragraphs (w)(2) through (w)(4) of this section. [72 FR 32722, June 13, 2007, as amended at 74 FR 5081, Jan. 28, 2009; 76 FR 3523, Jan. 20, 2011; 77 FR 9456, Feb. 16, 2012; 77 FR 23402, Apr. 19, 2012] § 60.50Da Compliance determination procedures and methods. (a) In conducting the performance tests required in §60.8, the owner or operator shall use as reference methods and procedures the methods in appendix A of this part or the methods and procedures as specified in this section, except as provided in §60.8(b). Section 60.8 (f) does not apply to this section for SO 2 and NO X . Acceptable alternative methods are given in paragraph (e) of this section. (b) In conducting the performance tests to determine comp liance with the PM emission s limits in §60.42Da, the owner or operator shall meet the requirements specified in paragraphs (b)(1) through (3) of this section. (1) The owner or operator shall measure filterable PM to determine compliance with the applicable PM emissions limit in §60.42Da as specified in paragraphs (b)(1)(i) through (ii) of this section. (i) The dry basis F factor (O 2 ) procedures in Method 19 of appendix A of this part shall be used to compute the emission rate of PM. (ii) For the PM concentration, Method 5 of appendix A of th is part shall be used for an affected facility that does not use a wet FGD. For an affected facility that uses a wet FGD, Method 5B of appendix A of this part shall be used downstream of the wet FGD.32 (A) The sampling time and sample volume for each run shall be at least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder heating system in the sampling train may be set to provide an average gas temperature of no greater than 160 ± 14 °C (320 ± 25 °F). (B) For each particulate run, the emission rate correct ion factor, integrated or grab sampling and analysis procedures of Method 3B of appendix A of this part shall be used to determine the O 2 concentration. The O 2 sample shall be obtained simultaneously with, and at the same traverse points as, the particulate run. If the particulate run has more than 12 traverse points, the O 2 traverse points may be reduced to 12 provided that Method 1 of appendix A of this part is used to locate the 12 O 2 traverse points. If the grab sampling procedure is used, the O 2 concentration for the run shall be the arithmetic mean of the sample O 2 concentrations at all traverse points. (2) In conjunction with a performance test performed according to the requirements in paragraph (b)(1) of this section, the owner or operat or of an affected facility for which cons truction, reconstruction, or modification commenced after May 3, 2011, shall measure condensable PM using Method 202 of appendix M of part 51. (3) Method 9 of appendix A of this part and the procedures in §60.11 shall be used to determine opacity. (c) The owner or operator shall determine compliance with the SO 2 standards in §60.43Da as follows: (1) The percent of potential SO 2 emissions (%Ps) to the atmosphere shall be computed using the following equation:

Where: %Ps = Percent of potential SO 2 emissions, percent; %Rf = Percent reduction from fuel pretreatment, percent; and %Rg = Percent reduction by SO 2 control system, percent. (2) The procedures in Method 19 of appendix A of this part may be used to determine percent reduction (%R f ) of sulfur by such processes as fuel pretreatment (physical coal cleaning, hydrodesulfurization of fuel oil, etc.), coal pulverizers, and bottom and fly ash interac tions. This determin ation is optional. (3) The procedures in Method 19 of appendix A of this part shall be used to determine the percent SO 2 reduction (%R g ) of any SO 2 control system. Alternatively, a combination of an “as fired” fuel monitor and emission rates measured after the control system, following the procedures in Method 19 of appendix A of this part, may be used if the percent reduction is calculated using the average emission rate from the SO 2 control device and the average SO 2 input rate from the “as fired” fuel analysis for 30 successive boiler operating days. (4) The appropriate procedures in Method 19 of appendix A of this part shall be used to determine the emission rate. (5) The CEMS in §60.49Da(b) and (d) shall be used to determine the concentrations of SO 2 and CO 2 or O 2 . (d) The owner or operator shall determine compliance with the NO X standard in §60.44Da as follows: (1) The appropriate procedures in Method 19 of appendix A of this part shall be used to determine the emission rate of NO X . (2) The continuous monitoring system in §60.49Da(c) and (d) shall be used to determine the concentrations of NO X and CO 2 or O 2 . (e) The owner or operator may use the following as alternatives to the reference methods and procedures specified in this section: (1) For Method 5 or 5B of appendix A–3 of this part, Method 17 of appendix A–6 of this part may be used at facilities with or without wet FGD syst ems if the stack temperature at the sampling location does not exceed an average temperature of 160 °C (320 °F). The procedures of sections 8.1 and 11.1 of Method 5B of appendix A–3 of this part may be used in Method 17 of appendix A–6 of this part only if it is used after wet FGD systems.33 Method 17 of appendix A–6 of this part shall not be used after wet FGD systems if the effluent is saturated or laden with wa ter droplets. (2) The F c factor (CO 2 ) procedures in Method 19 of appendix A of this part may be used to compute the emission rate of PM under the stipulations of §60.46(d)(1). The CO 2 shall be determined in the same manner as the O 2 concentration. (f) The owner or operator of an E e lectric utility combined cycle gas turbines that are not designed to burn fuels containing 50 percent (by heat input) or more solid de rived fuel does not meet ing the definition of natural gas an IGCC must conduct are performance test ed for PM, SO 2 , and NO X using the procedures of Method 19 of appendix A–7 of this part. The SO 2 and NO X emission rates calculations from the gas turbine used in Method 19 of appendix A–7 of this part are determined when the gas turbine is performance tested under subpart GG of this part. The potential uncontrolled PM emission rate from a gas turbine is defined as 17 ng/J (0.04 lb/MMBtu) heat input. [72 FR 32722, June 13, 2007, as amended at 74 FR 5083, Jan. 28, 2009; 77 FR 9458, Feb. 16, 2012] § 60.51Da Reporting requirements. (a) For SO 2 , NO X , PM, and NO X plus CO emissions, the performance te st data from the initial and subsequent performance test and from the performance evaluation of the continuous monitors (including the transmissometer) must be reported to the Administrator. (b) For SO 2 and NO X the following information is reported to the Administrator for each 24-hour period. (1) Calendar date. (2) The average SO 2 and NO X emission rates (ng/J, lb/MMBtu, or lb/MWh) for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance with the emission standards; and, description of corrective actions taken. (3) For owners or operators of affected facilities complying with the percent reduction requirement, percent reduction of the potential co mbustion concentration of SO 2 for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance with the standard; and, description of corrective actions taken. (4) Identification of the boiler operating days for which pollutant or diluent data have not been obtained by an approved method for at least 75 percent of the hours of op eration of the facility; jus tification for not obtaining sufficient data; and description of corrective actions taken. (5) Identification of the times when emissions data have been excluded from the calculation of average emission rates because of startup, shutdown, or malfunction. (6) Identification of “F” factor used for calculations, method of determination, and type of fuel combusted. (7) Identification of times when hourly averages have been obtained based on manual sampling methods. (8) Identification of the times when the pollutant concentration exceeded full span of the CEMS. (9) Description of any modifications to CEMS which co uld affect the ability of the CEMS to comply with Performance Specifications 2 or 3. (c) If the minimum quantity of emission da ta as required by §60.49D a is not obtained for an y 30 successive boiler operating days, the following information obtained under the requirements of §60.48Da(h) is reported to the Administrator for that 30-day period: (1) The number of hourly averages available for outlet emission rates (no) and inlet emission rates (n i ) as applicable. (2) The standard deviation of hourly averages for outlet emission rates (s o ) and inlet emission rates (s i ) as applicable. (3) The lower confidence limit for the mean outlet emission rate (E o *) and the upper confidence limit for the mean inlet emission rate (E i *) as applicable. Comment [CF18]: Tie to definition of IGCC instead of repeating definition.34 (4) The applicable potential combustion concentration. (5) The ratio of the upper confidence limit for the mean outlet emission rate (E o *) and the allowable emission rate (E std ) as applicable. (d) In addition to the applicable require ments in §60.7, the owner or operator of an affected facility subject to the opacity limits in §60.43c(c) and conducting performance tests using Method 9 of appendix A–4 of this part shall submit excess emission reports for any excess emissions fro m the affected facility that occur during the reporting period and maintain records according to the requirements specified in paragraph (d)(1) of this section. (1) For each performance test conducted using Method 9 of appendix A–4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (d)(1)(i) through (iii) of this section. (i) Dates and time intervals of all opacity observation periods; (ii) Name, affiliation, and copy of current visible emis sion reading certification for each visible emission observer participating in the performance test; and (iii) Copies of all visible emission observer opacity field data sheets. (2) [Reserved] (e) If fuel pretreatment credit toward the SO 2 emission standard under §60.43Da is claimed, the owner or operator of the affected facility shall submit a signed statement: (1) Indicating what percentage cleaning credit was ta ken for the calendar quarter, and whether the credit was determined in accordance with the provisions of §60.50Da and Method 19 of appendix A of this part; and (2) Listing the quantity, heat content, and date each pretreated fuel shipment was received during the previous quarter; the name and location of the fuel pretreatment fac ility; and the total quantity an d total heat content of all fuels received at the a ffected facility during the previous quarter. (f) For any periods for which opacity, SO 2 or NO X emissions data are not available, the owner or operator of the affected facility shall submit a signed statement indicating if any changes were made in operation of the emission control system during the period of data unavailability. Operations of the control system and affected facility during periods of da ta unavailability are to be comp ared with operation of the cont rol system and affected facility before and following the period of data unavailability. (g) [Reserved] (h) The owner or operator of the affected facility shall submit a signed statement indicating whether: (1) The required CEMS calibration, span, and drift checks or other periodic audits have or have not been performed as specified. (2) The data used to show compliance was or was not obtained in accordance with approved methods and procedures of this part and is representative of plant performance. (3) The minimum data requirements have or have not been met; or, the minimum data requirements have not been met for errors that were unavoidable. (4) Compliance with the standards has or has not been achieved during the reporting period. (i) For the purposes of the reports required under §60.7, periods of excess emissions are defined as all 6-minute periods during which the average opacity exceeds the applicable opacity standards under §60.42Da(b). Opacity levels in excess of the applicable op acity standard and the da te of such excesses are to be submitted to the Administrator each calendar quarter. (j) The owner or operator of an affected facility shall submit the written reports requ ired under this section and subpart A to the Administrator semiannually for each six-month period. All semiannual reports shall be postmarked by the 30th day following the end of each six-month period. (k) The owner or operator of an affected fac ility may submit electronic quarterly reports for SO 2 and/or NO X and/or opacity in lieu of submitting the written reports required under paragraphs (b) and (i) of this section. The format35 of each quarterly electro nic report shall be coordinated with the pe rmitting authority. The electronic report(s) shall be submitted no later than 30 days after the end of the calendar quarter and shall be accompanied by a certification statement from the owner or operator, indicating whether compliance with the applicable emission standards and minimum data requirements of this subpart was achieved during the reporting period. [72 FR 32722, June 13, 2007, as amended at 74 FR 5083, Jan. 28, 2009; 77 FR 9458, Feb. 16, 2012] § 60.52Da Recordkeeping requirements. (a) [Reserved] (b) The owner or operator of an affect ed facility subject to the opacity limits in §60.42Da(b) that elects to monitor emissions according to the requirements in §60.49Da(a)(3) shall maintain records according to the requirements specified in paragraphs (b)(1) through (3) of this section, as applicable to the visible emissions monitoring method used. (1) For each performance test conducted using Method 9 of appendix A–4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (b)(1)(i) through (iii) of this section. (i) Dates and time intervals of all opacity observation periods; (ii) Name, affiliation, and copy of current visible emis sion reading certification for each visible emission observer participating in the performance test; and (iii) Copies of all visible emission observer opacity field data sheets; (2) For each performance test conducted using Method 22 of appendix A–4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (b)(2)(i) through (iv) of this section. (i) Dates and time intervals of all visible emissions observation periods; (ii) Name and affiliation for each visible emission observer participating in the performance test; (iii) Copies of all visible emission observer opacity field data sheets; and (iv) Documentation of any adjustments made and the time the adjustments were completed to the affected facility operation by the owner or operator to demonstrate compliance with the applicable monitoring requirements. (3) For each digital opacity compliance system, the owner or operator shall maintain records and submit reports according to the requirements specified in the site-specific monitoring plan approved by the Administrator. [74 FR 5083, Jan. 28, 2009, as amended at 77 FR 9459, Feb. 16, 2012]