1

Subpart Da—Standards of Performance for Electric Utility Steam Generating Units 

§ 60.40Da Applicability and designation of affected facility. 

(a) Except as specified in paragraph (e) of this section, the 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 subject to subpart GG or KKKK of this part if both of the conditions 

specified in paragraphs (b)(1) and (2) of this section are met. 

(1) The IGCC electric utility steam generating unit is capable 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 commenced 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 other fuel (fossil or nonfossil) shall not bring 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 paragraphs (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 than 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 subject 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 shall 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 according 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. 
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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 period 

between 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 utility 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 coal 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 mechanical) 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 combined cycle gas turbine means any combined cycle gas turbine used for electric generation 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. Any steam distribution system 

that is constructed for the purpose of providing steam to a steam electric generator that 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 field, 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 conditions 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 standard 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 gas  
3

(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 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); 

(2) For facilities constructed, reconstructed, or modified after May 3, 2011, the gross electrical or mechanical 

output from the affected facility 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); 

(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 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). Auxiliary loads that are associated with power production are determined 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 electric utility steam 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 according 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 the following gaseous fuels: landfill gas, digester 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 sulfur 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 parasitic load associated with power production. 

Parasitic load includes, but is not limited 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 amended
4

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 Islands, 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 quality assurance audit that indicates 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 quality assurance audit following corrective 

action that demonstrates that the instrument is measuring and recording within the applicable performance 

specifications. 

Petroleum for facilities constructed, reconstructed, or modified before May 4, 2011, means crude oil or a fuel 

derived from crude oil, including, but not limited to, distillate 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 combustion concentration means the theoretical emissions (nanograms 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 (SO2) the potential combustion concentration 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 electric utility combined cycle 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, reconstructed, or modified before May 4, 2011, means any 

furnace, 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 any 

furnace, 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 SO2control 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 gases 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 include, 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 (0.030 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 elects to install, calibrate, maintain, 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 cause to be discharged into 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 construction, reconstruction, or modification commenced 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 construction 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 combustion 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 performance test is completed or required to be completed under 

§60.8, whichever date comes first, nothe 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 commenced 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 inputthe 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 meets the conditions in either paragraphs (f)(1) or (2) of this 

section is exempt from the PM emissions limits in this section. 

(1) The affected facility combusts only gaseous or liquid fuels (excluding residual oil) with potential SO2

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 SO2 or PM. 

(2) The affected facility is operated under a PM commercial 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 SO2in 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 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 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 SO2in 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 SO2in 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 any 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 limited to 340 ng/J (0.80 lb/MMBtu) heat input from any affected facility which 

is located in a noncontinental area and combusts liquid or gaseous fuels (excluding solid-derived fuels). 

(f) The SO2standards under this section do not apply to an owner or operator of an affected facility that is operated 

under an SO2commercial demonstration permit issued by the Administrator 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 SO2to the atmosphere are greater than 260 ng/J (0.60 lb/MMBtu) heat input 

(2) If emissions of SO2to the atmosphere are equal to or less than 260 ng/J (0.60 lb/MMBtu) heat input: 

Where: 

Es= Prorated SO2emission limit (ng/J heat input); 

%Ps= Percentage of potential SO2emission 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 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 for which construction, reconstruction, or modification commenced 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 SO2in 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 SO2in 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 SO2in 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 SO2in 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 combustion 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 SO2in 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 

SO2in 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 which reconstruction commenced after February 28, 2005, any gases that contain 

SO2in 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 input 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 commenced after February 28, 2005, any gases that contain 

SO2in 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 input 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 performance 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 commenced 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 SO2in excess of 

the applicable emissions limit specified in paragraphs (k)(1) and (2) of this section. 

(1) For an affected facility that burns solid or solid-derived fuel, the owner or operator shall not cause to be 

discharged into the atmosphere any gases that contain SO2in 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 SO2in 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 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 May 3, 

2011, shall cause to be discharged into the atmosphere from that affected facility, any gases that contain SO2in 

excess of the applicable emissions limit specified in paragraphs (l)(1) and (2) of this section. 

(1) For an affected facility which commenced construction or reconstruction, any gases that contain SO2in 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 SO2in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy output; or 

(ii) 10 percent of the potential combustion concentration (90 percent reduction). 
9

(m) 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 located in a noncontinental area 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 SO2in excess of the applicable emissions 

limit specified in paragraphs (m)(1) and (2) of this section. 

(1) For an affected facility that burns solid or solid-derived fuel, the owner or operator shall not cause to be 

discharged into the atmosphere any gases that contain SO2in 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 SO2in 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 (NOX). 

(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 cause to be discharged into the atmosphere from any affected facility for which 

construction, reconstruction, or modification commenced before July 10, 1997 any gases that contain 

NOX(expressed as NO2) 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 NOXin 

excess of the emissions limit listed in the following table as applicable to the fuel type combusted and as 

determined on a 30-boiler operating 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 furnace2

340 0.80 

Any fuel containing more than 25%, by weight, lignite not subject to the 340 ng/J heat 260 0.60 
10

input emission limit2

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 combusted simultaneously in an affected facility, the applicable emissions limit 

(En) is determined by proration using the following formula: 

View or download PDF 

Where: 

En = Applicable NOXemissions limit when multiple fuels are combusted 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 combustion of fuels subject to the 130 ng/J heat input standard; 

y = Percentage of total heat input derived from the combustion 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 commenced construction, reconstruction, or modification after July 9, 1997, but before 

March 1, 2005, shall cause to be discharged into the atmosphere from that affected facility any gases that contain 

NOX(expressed as NO2) 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 NOXin excess of 200 ng/J (1.6 

lb/MWh) gross energy output. 

(2) For an affected facility which commenced reconstruction, any gases that contain NOXin 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 NOX(expressed as NO2) 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 NOXin 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 NOXin 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 NOXin 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 performance test is completed or required to be completed under 

§60.8, whichever date 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 NOX(expressed as NO2) in excess of 130 ng/J (1.0 

lb/MWh) gross energy output. 

(2) When burning liquid fuel exclusively or in combination 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 NOX(expressed as NO2) 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 NOX(expressed as NO2) 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 discharged into the atmosphere from that affected facility any gases that contain NOX(expressed 

as NO2) in excess of the applicable emissions limit specified in paragraphs (g)(1) through (3) of this section. 

(1) For an affected facility which commenced construction or reconstruction, any gases that contain NOXin 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 construction 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 NOXin 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 NOXin excess of 140 ng/J (1.1 

lb/MWh) gross energy output. 

(h) The NOXemissions limits under this section do not apply to an owner or operator 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 NOXemissions limits specified in §60.44Da may elect to 

meet the applicable standards for combined NOXand CO specified in paragraph (b) of this section. 

(b) On and after the date on which the initial performance 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 NOX(expressed as NO2) 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 construction or reconstruction, any gases that contain NOXplus 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 construction 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 NOXplus 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 NOXplus 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 proposing to demonstrate an emerging 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 SO2emission reduction 

requirements under §60.43Da(c) but must, as a minimum, reduce SO2emissions 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 SO2emission 

reduction requirements under §60.43Da(a) but must, as a minimum, reduce SO2emissions 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 NOXemission 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 total equivalent MW electrical generation capacity for all 

commercial demonstration plants may not exceed 15,000 MW. 

Technology Pollutant Equivalent electrical capacity 
13

(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 uses 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 demonstration permit by the Administrator is not subject to 

the SO2standards or emission reduction requirements under §60.43Da but must, as a minimum, reduce 

SO2emissions 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 controls who is issued a commercial demonstration permit by 

the Administrator is not subject to the NOXstandards or emission reduction requirements under §60.44Da but 

must, as a minimum, reduce NOXemissions to less than 130 ng/J (1.0 lb/MWh) or the combined NOXplus 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 SO2 1,000 

Multi-pollutant Emission Control NOX 1,000 

Multi-pollutant Emission Control PM 1,000 

Pressurized Fluidized Bed Combustion SO2 1,000 

Pressurized Fluidized Bed Combustion NOX 1,000 

Pressurized Fluidized Bed Combustion PM 1,000 

Advanced Combustion Controls NOX 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, modification, or reconstruction commenced before May 4, 2011, 

the applicable PM emissions limit and opacity standard under §60.42Da, SO2emissions limit under §60.43Da, and 

NOX 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 SO2emissions limit under §60.43Da, NOX emissions limit under §60.44Da, and NOX 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 SO2emissions limit and 

percentage reduction requirements under §60.43Da, NOXemissions limit under §60.44Da, and NOXplus 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 SO2, NOXor NOXplus CO as applicable, 

and a new percent reduction for SO2are calculated to demonstrate compliance with the standards. 

(c) For the initial performance test required under §60.8, compliance with the applicable SO2emissions limits and 

percentage reduction requirements under §60.43Da, the NOXemissions limits under §60.44Da, and the NOXplus 

CO emissions limits under §60.45Da is based on the average emission rates for SO2, NOX, CO, and percent 

reduction for SO2for the first 30 successive boiler operating days. The initial performance test is the only test in 

which at least 30 days prior notice is required unless otherwise specified by the Administrator. 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 achieving the maximum production 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, modification, or reconstruction commenced before May 4, 2011, 

compliance with applicable 30-boiler operating day rolling average SO2and NOXemissions limits is determined by 

calculating the arithmetic average of all hourly emission rates for SO2and NOXfor the 30 successive boiler 

operating days, except for data obtained during startup, shutdown, 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 SO2and NOXemissions limits is determined by dividing the sum of the SO2and 

NOXemissions 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, modification, or reconstruction commenced before May 4, 2011, 

compliance with applicable SO2percentage reduction requirements is determined based on the average inlet and 

outlet SO2emission 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 SO2percentage 

reduction requirements is determined based on the “as fired” total potential emissions and the total outlet 

SO2emissions for the 30 successive boiler operating days. 

(f) For affected facilities for which construction, modification, or reconstruction commenced before May 4, 2011, 

compliance with the applicable daily average PM emissions limits is determined by calculating the arithmetic 

average of all hourly emission rates for PM each boiler operating day, except for data obtained during startup, 

shutdown, orand malfunction periods. Daily averages are only calculated for boiler operating days that have nonout-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-ofcontrol hourly emission rates of the next boiler operating day with 18 hours or more of 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 limits 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 procedures
15

(g) For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, 

compliance with applicable 30-boiler operating day rolling average NOXplus CO emissions limit is determined by 

dividing the sum of the NOXplus 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 NOXemissions as 1.194 × 10−7

lb/scf-ppm times the average hourly NOXoutput 

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, NOXemissions may be calculated by 

multiplying the hourly NOXemission 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 NOXrequired 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 both 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 NOXand oxygen (O2) (or carbon dioxide (CO2)) and meet the 

requirements of §60.49Da. Alternatively, data from a NOXemission rate ( i.e. , NOX-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 NOXemission rate at the outlet from the steam generating unit shall 

constitute the NOXemission 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 NOXrequired 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 NOXemission limitation in §60.44Da(d)(1) or (e)(1) as follows: 

(i) The emission rate (E) of NOXshall be computed using Equation 2 in this section: 

View or download PDF 

Where: 

E = Emission rate of NOXfrom the duct burner, ng/J (lb/MWh) gross energy output; 
16

Csg= Average hourly concentration of NOXexiting the steam generating unit, ng/dscm (lb/dscf); 

Cte= Average hourly concentration of NOXin the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf); 

Qsg= Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/h (dscf/h); 

Qte= Average hourly volumetric flow rate of exhaust gas from combustion turbine, dscm/h (dscf/h); 

Osg= 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 NOXconcentrations (Csgand Cte). Method 

2, 2F or 2G of appendix A of this part, as appropriate, shall be used to determine the volumetric flow rates 

(Qsgand Qte) of the exhaust gases. The volumetric 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 NOXemission 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 NOXemission 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 NOXshall be computed using Equation 3 in this section: 

View or download PDF 

Where: 

E = Emission rate of NOXfrom the duct burner, ng/J (lb/MWh) gross energy output; 

Csg= Average hourly concentration of NOXexiting the steam generating unit, ng/dscm (lb/dscf); 

Qsg= Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/h (dscf/h); and 

Occ= Average hourly gross energy output from entire combined cycle unit, J/h (MW). 

(ii) The CEMS specified under §60.49Da for measuring NOXand O2(or CO2) shall be used to determine the 

average hourly NOXconcentrations (Csg). The continuous flow monitoring system specified in §60.49Da(l) or 

§60.49Da(m) shall be used to determine the volumetric flow rate (Qsg) 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 

(Occ), which is the combined output from the combustion 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 NOXemissions 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 

NOXshall be computed using Equation 4 in this section: 
17

View or download PDF 

Where: 

E = Emission rate of NOXfrom the duct burner, ng/J (lb/MWh) gross energy output; 

ERsg= Average hourly emission rate of NOXexiting 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); 

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

Occ= 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 NOXemissions limits by measuring the emissions combined with the 

emissions from the other unit(s) utilizing 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 emissions 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 SO2emissions as 1.660 × 10−7

lb/scf-ppm times 

the average hourly SO2output 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, SO2emissions may be 

calculated by multiplying the hourly SO2emission 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, shallmust demonstrate compliance with each applicable 

emissions limit according to the requirements in paragraphs (o)(1) through (o)(5) of this section. 

(1) You must conduct a performance test to demonstrate initial compliance with the 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 day. Requests for additional 30 day extensions shall be granted by the relevant air 

division or office director of the appropriate 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 filter (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 averaging 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 level 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, shutdown, or malfunction. If the measured 24-hour average 

opacity emission level is greater than the baseline opacity level determined in paragraph (o)(2)(iii) of this section, 

you must initiate investigation of the relevant equipment 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 scrubber 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 the 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 this 
19

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 precipitator (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 must 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 limit. You must submit the site-specific monitoring plan 

for approval by the permitting authority. For reference purposes in preparing the monitoring plan, see the OAQPS 

“Compliance Assurance Monitoring (CAM) Protocol for 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 for the preceding boiler operating day excluding periods of affected facility startup, 

shutdown, or malfunction. If the values for one or more of the model parameters exceed the applicable baseline 

levels determined according to your approved site-specific 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 the 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 waiver 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 performance 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 the permitting authority for approval a site-specific monitoring plan for each 

bag 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 detection system will be maintained, including a routine maintenance 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 may allow owners and operators more 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 explains why it is not feasible to alleviate this condition 

within 3 hours of the time the alarm occurs, and demonstrates that the requested time will ensure alleviation of 

this condition as expeditiously as practicable. 

(iii) For each bag leak detection system, you must initiate procedures to determine 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 whatever 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 otherwise 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 detection system adjustments, including the date 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 alarms, the time that procedures to determine the cause of 

the alarm were initiated, if procedures were initiated within 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 the 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 reduction 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 notification 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 compliance with this subpart 

according to the requirements in paragraph (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 shall 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 all 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 the 

Administrator 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 operating 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 NOXplus CO 

emissions limit, the owner or operator shall use the procedures specified in paragraphs (r)(1) through (3) of this 

section. 

(1) Calculate NOXemissions as 1.194 × 10−7

lb/scf-ppm times the average hourly NOXoutput 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 NOXplus CO emissions by summing the NOXemissions 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 may 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; and 
23

(vi) All emissions monitoring and control systems were kept in operation if at all possible, 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 been prepared, the purpose of which is to determine, correct, and eliminate 

the primary causes of the malfunction and the excess emissions resulting from the malfunction event at issue. The 

analysis shall also specify, using best monitoring methods 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 civil penalties for that malfunction. The owner or operator 

seeking to assert an affirmative 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 extension of this deadline for up to 30 additional days by submitting 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) mustshall monitor 

the opacity of emissions discharged from the affected facility to the atmosphere according to the applicable 

requirements in paragraphs (a)(1) through (34) 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 FGD system). If opacity interference is experienced at all locations (both at the 

inlet and outlet of the SO2control 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 liquid fuels (excluding residual oil) with potential SO2 emissions 

rates of 26 ng/J (0.060 lb/MMBtu) or less, and does not use a post-combustion technology to reduce emissions of 

SO2 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, SO2, 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 ESP 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 meets 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 less than or equal to 20 percent, 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 using 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 document 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 shallmust 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 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 

Preliminary Methods.

(4) An owner or operator of an affected facility that is subject to an opacity standard under §60.42Da(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) withwhere thea

potential SO2 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 permitting 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 notification 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 installs, 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 according 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 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 

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 SO2 emissions, except where only natural gasgaseous and/or liquid 

fuels (excluding residual oil) with where the potential SO2 emissions rates 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 SO2control device. 

(2) For a facility that qualifies under the numerical limit provisions of §60.43Da, SO2emissions 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 SO2emissions in place of a continuous SO2emission 

monitor at the inlet to the SO2control 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 SO2CEMS 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 CO2or O2continuous 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 SO2emission limit in lb/MMBtu under §60.43Da: 

(A) When relative accuracy testing is conducted, SO2concentration data and CO2(or O2) data are collected 

simultaneously; and 

(B) In addition to meeting the applicable SO2and CO2(or O2) 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 when the RA is calculated on a lb/MMBtu basis; and 

(iii) The reporting requirements of §60.51Da are met. The SO2and, if required, CO2(or O2) 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 SO2data have been bias adjusted according to the procedures of 

part 75 of this chapter. 

(c)(1) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS, and 

record the output of the system, for measuring NOXemissions discharged to the atmosphere; or 

(2) If the owner or operator has installed a NOXemission 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 complying with an output based limit shall install, calibrate, 

maintain, and operate a CEMS, and record the output of the system, for measuring the O2or carbon dioxide (CO2) 

content of the flue gases at each location where SO2or NOXemissions are monitored. For affected facilities subject 

to a lb/MMBtu SO2emission limit under §60.43Da, if the owner or operator has installed and certified a CO2or 

O2monitoring 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 SO2concentration 

monitoring system described in paragraph (b) of this section, to determine the SO2emission rate in lb/MMBtu. 

SO2data 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 percent 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 SO2concentration at the same location as 

the SO2monitor. 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 NOXconcentration at the same location as 

the NOXmonitor. 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 O2or CO2concentration at the same location as the O2or CO2monitor. 

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 O2, SO2, and NOXconcentrations, 

respectively. 

(2) SO2or NOX(NO), as applicable, shall be used for preparing the calibration gas mixtures (in N2, as applicable) 

under Performance Specification 2 of appendix B of this part. 

(3) For affected facilities burning only fossil fuel, the span value for a COMS is between 60 and 80 percent. Span 

values for a CEMS measuring NOXshall be determined using one of the following procedures: 

(i) Except as provided under paragraph (i)(3)(ii) of this section, NOXspan values shall be determined as follows: 

Fossil fuel 

Span values for NOX

(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 NOXspan 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 fossil 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 SO2CEMS at the inlet to the SO2control 

device is 125 percent of the maximum estimated hourly potential emissions of the fuel fired, and the outlet of the 

SO2control device is 50 percent of maximum estimated hourly potential emissions of the fuel fired. For affected 

facilities determining span values under paragraph (i)(3)(ii) of this section, SO2span 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 electricity generation shall install, 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 process 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 combination 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 demonstrating compliance with an output-based standard shall 

install, certify, operate, and maintain 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 monitoring 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 NOXstandards of 

§60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate a CEMS to measure NOXemissions; 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 interface 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 affected facility demonstrating compliance with thean output-based emissions 

limitationlimit under §60.42Da shallmust 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 maintain 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 volume corrected to 3 percent 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 calibration 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 investigation 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 performance 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 O2(or CO2) 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 O2(or CO2), 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/chief/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 SO2, NOX, CO2, and O2CEMS to meet the requirements 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 SO2, NOX, CO2, and 

O2CEMS 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 alternative data accuracy assessment procedures. For all required CO2and 

O2CEMS and for SO2and NOXCEMS 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 criteria 
31

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 

SO2and NOXspan 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 

CO2and O2CEMS and for SO2and NOXCEMS 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 section 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 out-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 SO2and NOXspan 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 alternative data accuracy assessment procedures. For SO2, CO2, and 

O2CEMS and for NOXCEMS, 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 SO2(regardless of the SO2emission level during the RATA), and for NOXwhen the average 

NOXemission 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 SO2and NOX. Acceptable 

alternative methods are given in paragraph (e) of this section. 

(b) In conducting the performance tests to determine compliance with the PM emissions 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 (O2) 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 this 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 correction factor, integrated or grab sampling and analysis 

procedures of Method 3B of appendix A of this part shall be used to determine the O2concentration. The 

O2sample 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 O2traverse points may be reduced to 12 provided that Method 

1 of appendix A of this part is used to locate the 12 O2traverse points. If the grab sampling procedure is used, the 

O2concentration for the run shall be the arithmetic mean of the sample O2concentrations 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 operator of an affected facility for which construction, 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 SO2standards in §60.43Da as follows: 

(1) The percent of potential SO2emissions (%Ps) to the atmosphere shall be computed using the following 

equation: 

Where: 

%Ps = Percent of potential SO2emissions, percent; 

%Rf = Percent reduction from fuel pretreatment, percent; and 

%Rg = Percent reduction by SO2control system, percent. 

(2) The procedures in Method 19 of appendix A of this part may be used to determine percent reduction (%Rf) of 

sulfur by such processes as fuel pretreatment (physical coal cleaning, hydrodesulfurization of fuel oil, etc.), coal 

pulverizers, and bottom and fly ash interactions. This determination is optional. 

(3) The procedures in Method 19 of appendix A of this part shall be used to determine the percent SO2reduction 

(%Rg) of any SO2control 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 SO2control device and the average 

SO2input 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 SO2and CO2or O2. 

(d) The owner or operator shall determine compliance with the NOXstandard 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 NOX. 

(2) The continuous monitoring system in §60.49Da(c) and (d) shall be used to determine the concentrations of 

NOXand CO2or O2. 

(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 systems 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 water droplets. 

(2) The Fcfactor (CO2) 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 CO2shall be determined in the same manner as the 

O2concentration. 

(f) The owner or operator of an Eelectric utility combined cycle gas turbines that are not designed to burn fuels 

containing 50 percent (by heat input) or more solid derived fuel does not meeting the definition of natural gasan 

IGCC must conduct are performance tested for PM, SO2, and NOX using the procedures of Method 19 of 

appendix A–7 of this part. The SO2and NOX 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 SO2, NOX, PM, and NOXplus CO emissions, the performance test 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 SO2and NOXthe following information is reported to the Administrator for each 24-hour period. 

(1) Calendar date. 

(2) The average SO2and NOXemission 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 combustion concentration of SO2for 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 operation of the facility; justification 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 could affect the ability of the CEMS to comply with 

Performance Specifications 2 or 3. 

(c) If the minimum quantity of emission data as required by §60.49Da is not obtained for any 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 (ni) as 

applicable. 

(2) The standard deviation of hourly averages for outlet emission rates (so) and inlet emission rates (si) as 

applicable. 

(3) The lower confidence limit for the mean outlet emission rate (Eo*) and the upper confidence limit for the mean 

inlet emission rate (Ei*) 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 (Eo*) and the allowable emission rate 

(Estd) as applicable. 

(d) In addition to the applicable requirements 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 from 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 emission 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 SO2emission 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 taken 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 facility; and the total quantity and total heat content of all 

fuels received at the affected facility during the previous quarter. 

(f) For any periods for which opacity, SO2or NOXemissions 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 data unavailability are to be compared with operation of the control 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 opacity standard and the date 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 required 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 facility may submit electronic quarterly reports for SO2and/or NOXand/or 

opacity in lieu of submitting the written reports required under paragraphs (b) and (i) of this section. The format 
35

of each quarterly electronic report shall be coordinated with the permitting 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 affected 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 emission 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]