1

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

Construction is Commenced After September 18, 1978

§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/hrh)) 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/hrh) 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 the requirement 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) and (2through (3) 

of this section. 

(1) Heat Affected facilities (i.e. heat recovery steam generators used with duct burners and) associated 

with an electric utility combined cycle gasa stationary combustion turbine that are capable of 

combusting more than 73 MW (250 MMBtu/hrh) 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 useused 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 KKKKKKK, 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.

§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 

Comment [CF1]: Simplify title

Comment [CF2]: Clarify heat input of an IGCC

facility

Comment [CF3]: Fix typo

Comment [CF4]: Exempt owner/operators of

MWC & CISWI from the criteria pollutant standards

under subpart Da. Could have startup burners

greater than 250 MMBtu/hr that would make them

applicable to Da.

Comment [CF5]: Delete definitions not used in

Da
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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 purchase power means the lesser of the following:

(a) The sum of available system capacity in all neighboring companies.

(b) The sum of the rated capacities of the power interconnection devices between the principal company 

and all neighboring companies, minus the sum of the electric power load on these interconnections.

(c) The rated capacity of the power transmission lines between the power interconnection devices and 

the electric generating units (the unit in the principal company that has the malfunctioning flue gas 

desulfurization system and the unit(s) in the neighboring company supplying replacement electrical

power) less the electric power load on these transmission lines.

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. 

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 on or before February 2829, 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 steam-generating 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. 

Cogeneration, also known as “combined heat and power,” means a steam-generating unit that 

simultaneously produces both electric (or mechanical) and useful thermal energy from the same primary 

energy source.

Combined cycle gas turbine means a stationary turbine combustion system where heat from the turbine 

exhaust gases is recovered by a steam generating unit. 

Dry flue gas desulfurization technology or dry FGD means a sulfur dioxide control system that is 

located downstream of the steam generating unit and removes sulfur oxides (SO2) from the combustion 
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gases of the steam generating unit by contacting the combustion gases with an alkaline reagent and 

water, whether introduced separately or as a premixed slurry or solution and forming a dry powder 

material. This definition includes devices where the dry powder material is subsequently converted to 

another form. Alkaline slurries or solutions used in dry FGD technology include, but are not limited to, 

lime and sodium.

Combined heat and power, also known as “cogeneration,” means a steam-generating unit that 

simultaneously produces both electric (or 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 company means the largest interconnected organization, business, or governmental entity 

that generates electric power for sale ( e.g. , a holding company with operating subsidiary companies).

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. 

Emergency condition means that period of time when:

(1) The electric generation output of an affected facility with a malfunctioning flue gas desulfurization 

system cannot be reduced or electrical output must be increased because:

(i) All available system capacity in the principal company interconnected with the affected facility is 

being operated, and

(ii) All available purchase power interconnected with the affected facility is being obtained, or

(2) The electric generation demand is being shifted as quickly as possible from an affected facility with 

a malfunctioning flue gas desulfurization system to one or more electrical generating units held in 

reserve by the principal company or by a neighboring company, or

(3) An affected facility with a malfunctioning flue gas desulfurization system becomes the only 

available unit to maintain a part or all of the principal company's system emergency reserves and the 

unit is operated in spinning reserve at the lowest practical electric generation load consistent with not 

causing significant physical damage to the unit. If the unit is operated at a higher load to meet load 

demand, an emergency condition would not exist unless the conditions under paragraph (1) of this 

definition apply.
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Emission limitation means any emissions limit or operating limit. 

Emission rate period means any calendar month included in a 12-month rolling average period.

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 derived from coal or petroleum 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 output means the gross useful work performed by the steam generated and, for an IGCC electric 

utility steam generating unit, the work performed by the stationary combustion turbines. For a unit 

generating only electricity, the gross useful work performed is the gross electrical output from the unit's

turbine/generator sets. For a cogeneration unit, the gross useful work performed is the gross electrical or 

mechanical output 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).

Gross energy output means:

(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 

Comment [CF6]: Remove condition of derived

from coal or petroleum to include natural gas and

gasified materials

Coke‐oven gas is not derived for the purpose of

creating useful heat. It would still be considered a

gaseous fuel is burned in an affected facility burning

natural gas.

Comment [CF7]: Amend definition of gross

output to account for primary potential difference

in gross output from otherwise similar facilities –

the feed pumps can be driven by steam or

electricity.  

IGCC difference in gross efficiency can be accounted

for by measuring auxiliary load of gas compressors.

CHP given 5% credit to account for transmission and

distribution benefits
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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.

Interconnected means that two or more electric generating units are electrically tied together by a 

network of power transmission lines, and other power transmission equipment.

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:

(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic 

formations beneath the earth's surface, of which the principal constituent is methane; or

(2) Liquid petroleum gas, as defined by the American Society of Testing and Materials in ASTM D1835 

(incorporated by reference, see §60.17); or

(3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural 

gas must either be composed of at least 70 percent methane by volume or have a gross calorific value 

between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 1,150 Btu per dry standard 

cubic foot).

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 system capacity means the sum of the net electric generating capability (not necessarily equal to 

rated capacity) of all electric generating equipment owned by an electric utility company (including 

steam generating units, internal combustion engines, gas turbines, nuclear units, hydroelectric units, and 

all other electric generating equipment) plus firm contractual purchases that are interconnected to the 

affected facility that has the malfunctioning flue gas desulfurization system. The electric generating 

capability of equipment under multiple ownership is prorated based on ownership unless the 

proportional entitlement to electric output is otherwise established by contractual arrangement.

Comment [CF8]: Add in provision to allow initial

operation on natural gas/distillate oil during

construction. Might be economic to run the

combined cycle facility on natural gas during

construction/repair of the gasification system.

Switch NSPS applicability could be a permitting

hassle without any environmental benefit.

Comment [CF9]: Make consistent with part 75

definition of natural gas
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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 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) and:. For sulfur dioxide (SO2) the potential combustion concentration is 

determined under §60.50Da(c).

(1) For particulate matter (PM) is:

(i) 3,000 ng/J (7.0 lb/MMBtu) heat input for solid fuel; and

(ii) 73 ng/J (0.17 lb/MMBtu) heat input for liquid fuels.

(2) For sulfur dioxide (SO2) is determined under §60.50Da(c).

(3) For nitrogen oxides (NOX) is:

(i) 290 ng/J (0.67 lb/MMBtu) heat input for gaseous fuels;

(ii) 310 ng/J (0.72 lb/MMBtu) heat input for liquid fuels; and

(iii) 990 ng/J (2.30 lb/MMBtu) heat input for solid fuels.

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. 

Principal company means the electric utility company or companies which own the affected facility.

Comment [CF10]: Add definition for optional

net output based standard

Comment [CF11]: Add petroleum coke under

petroleum to be consistent with the EGU MACT.

Included under “coal” for industrial boiler NSPS.

Comment [CF12]: Deleted % reduction

requirements so no longer need
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Resource recovery unit means a facility that combusts more than 75 percent non-fossil fuel on a 

quarterly (calendar) heat input basis. 

Responsible official means responsible official as defined in 40 CFR 70.2.

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. 

Spare flue gas desulfurization system module means a separate system of SO2emission control 

equipment capable of treating an amount of flue gas equal to the total amount of flue gas generated by 

an affected facility when operated at maximum capacity divided by the total number of nonspare flue 

gas desulfurization modules in the system.

Spinning reserve means the sum of the unutilized net generating capability of all units of the electric 

utility company that are synchronized to the power distribution system and that are capable of 

immediately accepting additional load. The electric generating capability of equipment under multiple 

ownership is prorated based on ownership unless the proportional entitlement to electric output is 

otherwise established by contractual arrangement.

SteamSteam 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 fossil-fuel-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 fossil-fuel-fired steam generators associated with combined cycle gas 

turbines; nuclear steam generators are not included).) plus any integrated equipment that provides either 

useful thermal output to the boiler or electrical output to power auxiliary equipment.

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).

System emergency reserves means an amount of electric generating capacity equivalent to the rated 

capacity of the single largest electric generating unit in the electric utility company (including steam 

generating units, internal combustion engines, gas turbines, nuclear units, hydroelectric units, and all 

other electric generating equipment) which is interconnected with the affected facility that has the 

malfunctioning flue gas desulfurization system. The electric generating capability of equipment under 

multiple ownership is prorated based on ownership unless the proportional entitlement to electric output 

is otherwise established by contractual arrangement.

System load means the entire electric demand of an electric utility company's service area interconnected 

with the affected facility that has the malfunctioning flue gas desulfurization system plus firm 

contractual sales to other electric utility companies. Sales to other electric utility companies ( e.g. , 

emergency power) not on a firm contractual basis may also be included in the system load when no 

available system capacity exists in the electric utility company to which the power is supplied for sale.

Wet flue gas desulfurization technology or wet FGD means a SO2controlSO2 control system that is 

located downstream of the steam generating unit and removes sulfur oxides from the combustion gases 

of the steam generating unit by contacting the combustion 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. 

Comment [CF13]: Modify definition to include

integrated fuel cells or combustion turbines used for

feedwater heating . Would also include facilities

used for providing heat for CS, etc.
8

§60.42Da StandardStandards for particulate matter (PM). 

(a) OnExcept 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, 

noan owner or operator subject to the provisions of this subpartof an affected facility shall not cause to 

be discharged into the atmosphere from any affected facility for which construction, reconstruction, or 

modification commenced before or on February 28March 1, 2005, any gases that contain PM in excess 

of: 13 ng/J (0.030 lb/MMBtu) heat input.

(1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel;

(2) 1 percent of the potential combustion concentration (99 percent reduction) when combusting solid 

fuel; and

(3) 30 percent of potential combustion concentration (70 percent reduction) when combusting liquid 

fuel.

(b) On(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, noan owner or operator subject to the provisions of this subpartan affected facility shall not 

cause to be discharged into the atmosphere from any affected facility 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. Owners and operators

(1) An owner or operator of an affected facility that electelects to install, calibrate, maintain, and operate 

a continuous emissions monitoring system (CEMS) for measuring PM emissions according to the 

requirements of this subpart areis 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 is exempt from the 

opacity standard specified in paragraph (b) of this section.

(c) Except as provided in paragraphparagraphs (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 for which construction, reconstruction, or modification 

commenced after February 28, 2005, any gases that contain PM in excess of: 

(1) 13 ng/J (0.03030 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel, 

and 

(2)(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 

Comment [CF14]: Remove since no longer

required as alternative to numerical limit

Comment [CF15]: Exempt owner/operators of

facilities only burning natural gas from the opacity

standard

Comment [CF16]: Fix Typo
9

reduction) for an affected facility for which construction or reconstruction commenced after February 

28, 2005 when combusting solid, liquid, or gaseous fuel, or 

(3)(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) for an 

affected facility for which modification commenced after February 28, 2005 when combusting solid, 

liquid, or gaseous fuel. 

(e) Except as provided in paragraph (f) of this section, no 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, no owner or operator shall 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:

(A) 11 ng/J ( 0.090 lb/MWh) gross energy output; or

(B) 12 ng/J (0.097 lb/MWh) net energy output.

(ii) For an affected facility which commenced modification, any gases that contain PM in excess of 13

ng/J (0.015 lb/MMBtu) heat input.

(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 of 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.

§60.43Da StandardStandards 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); or

(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.;

Comment [CF17]: Require same startup and

shutdown work practice standards as the EGU

NESHAP

Comment [CF18]: Exempt natural gas & low

sulfur oil boilers from the PM limit.

Comment [CF19]: Commercial demonstration

alternate standards
10

(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.

(c) [RESERVED]

(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; 

(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 solidderived fuels). 

(f) The emission reduction requirementsSO2 standards under this section do not apply to anyan owner or 

operator of an affected facility that is operated under an SO2commercialSO2 commercial 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 

Comment [CF20]: Add option for

owner/operators of facilities presently covered by

Da to comply with standard for “new” modified

sources. Might co‐fire with biomass and 70%

reduction on a small amount of fossil fuel could be

difficult.  

Comment [CF21]: Deleting/reserving since

never used
11

(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 that commenced 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 SO2 in excess of the applicable emission 

limitation specified in paragraphs (i)(1) through (3) of this section. 

(1) For an affected facility for which commenced construction commenced after February 28, 2005, any 

gases that contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; or 

(ii) 5 percent of the potential combustion concentration (95 percent reduction) on a 30-day rolling 

average basis.).

(2) For an affected facility for which commenced reconstruction commenced after February 28, 2005, 

any gases that contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis; or 

(iii) 5 percent of the potential combustion concentration (95 percent reduction) on a 30-day rolling 

average basis.).

(3) For an affected facility for which commenced modification commenced after February 28, 2005, any 

gases that contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 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.).

(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 commencedfor 

which 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 causedcause to 

Comment [CF22]: Simplify wording by including

date only once.  Don’t need “30‐day rolling average

basis” since stated elsewhere.
12

be discharged into the atmosphere from that affected facility any gases that contain SO2 in excess of the 

applicable emission limitation specified in paragraphs (j)(1) through (3) of this section. 

(1) For an affected facility for which commenced construction commenced after February 28, 2005, any 

gases that contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; or 

(ii) 6 percent of the potential combustion concentration (94 percent reduction) on a 30-day rolling 

average basis.).

(2) For an affected facility for which commenced reconstruction commenced after February 28, 2005, 

any gases that contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 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 commenced modification commenced after February 28, 2005, any 

gases that contain SO2 in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; 

(ii) 65 ng/J (0.15 lb/MMBtu) heat 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 that commencedfor 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 SO2 in excess of the applicable emission limitation 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 SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat 

input.

(2) For an affected facility that burns other than solid or solid-derived fuel, the owner or operator shall 

not cause to be discharged into the atmosphere any gases that contain SO2 in excess of 230 ng/J (0.54 

lb/MMBtu) heat input.

(l) Except as provided in paragraphs (j) and (m) of this section, on and after the date on 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 SO2 in 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 SO2

in excess of either:

(i) 130 ng/J (1.0 lb/MWh) gross energy output; or
13

(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 SO2 in 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). 

(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 

SO2 in excess of the applicable emissions limit specified in paragraphs (n)(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 SO2 in excess of 520 ng/J (1.2 lb/MMBtu) heat 

input on a 30-day rolling average basis. 

(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 SO2 in excess of if the affected 

facility or 230 ng/J (0.54 lb/MMBtu) heat input on a 30-day rolling average basis. 

§60.44Da StandardStandards for nitrogen oxides (NOX). 

(a) OnExcept 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, except as provided under paragraphs (b), (d), (e), and (f) of this 

section, 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 

NOX in excess of the emissions limit listed in the following emission limits, basedtable as applicable to 

the fuel type combusted and as determined on a 30-day rolling average basis, except as provided under 

§60.48Da(j)(1):

(1) NOXemission limits.

Fuel type 

Emission 

limit for heat 

input 

ng/J lb/M

MBtu

Gaseous fuels: 

Coal-derived fuels 210 0.50 
14

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 input emission limit2 260 0.60 

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) NOXreduction requirement.

Fuel type Percent reduction of potential combustion

concentration

Gaseous fuels 25

Liquid fuels 30

Solid fuels 65

(b) The emission limitations under paragraph (a) of this section do not apply to any affected facility 

which is combusting coal-derived liquid fuel and is operating under a commercial demonstration permit 

issued by the Administrator in accordance with the provisions of §60.47Da.

Comment [CF23]: No longer need % reduction

in addition to numerical requirement.
15

(c) Except as provided under paragraphs (d), (e), and (f) of this section, when(2) When two or more 

fuels are combusted simultaneously, the applicable standard is determined by proration using the 

following formula: 

Where: 

En= Applicable standard for NOXwhen 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) [Reserved]

(c) [Reserved]

(d)(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, no owner or operator of an affected facility that 

commenced construction after July 9, 1997, but before or on February 28, 2005 shall cause to be 

discharged into the atmosphere any gases that contain NOX(expressed as NO2) in excess of 200 ng/J (1.6 

lb/MWh) gross energy output, based on a 30-day rolling average basis, except as provided under 

§60.48Da(k).

(2) 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 affected facility for which 

reconstruction commenced after July 9, 1997, but before or on February 28, 2005 shall cause to be 

discharged into the atmosphere any gases that contain NOX(expressed as NO2) in excess of 65 ng/J (0.15 

lb/MMBtu) heat input, based on a 30-day rolling average basis.

(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-day rolling average 

basis.

(1) For an affected facility which commenced construction, any gases that contain NOX in excess of 200 

ng/J (1.6 lb/MWh) gross energy output.
16

(2) For an affected facility which commenced reconstruction, any gases that contain NOX in excess of 65 

ng/J (0.15 lb/MMBtu) heat input.

(e) Except for an IGCC electric utility steam generating unit meeting the requirements of as provided in 

paragraphs (f) and (h) of this section, on and after February 28, 2005, the ownerdate on which the initial 

performance test is completed or operatorrequired 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 not cause to be discharged into the 

atmosphere from that affected facility any gases that contain NOX (expressed as NO2) in excess of 130 

ng/J (the applicable emissions limit specified in paragraphs (e)(1.0 lb/MWh) gross energy output) 

through (3) of this section as determined on a 30-day rolling average basis, except as provided under 

§60.48Da(k). 

(21) For an affected facility for which reconstruction commenced after February 28, 2005, the owner or 

operator shall not cause to be discharged into the atmosphereconstruction, any gases that contain 

NOX(expressed as NO2) in excess of 130 ng/J (1.0 lb/MWh) gross energy output.

(2) For an affected facility which commenced reconstruction, any gases that contain NOX in excess of 

either: 

(i) 130 ng/J (1.0 lb/MWh) gross energy output on a 30-day rolling average basis; or 

(ii) 47 ng/J (0.11 lb/MMBtu) heat input on a 30-day rolling average basis. 

(3) For an affected facility for which commenced modification commenced after February 28, 2005, the 

owner or operator shall not cause to be discharged into the atmosphere, any gases that contain 

NOX(expressed as NO2) in excess of either: 

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis; or 

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30-day rolling average basis. 

(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 on a 30-day rolling average basis. 

(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 on a 30-day rolling average 

basis. 

(3) In cases when during a 30-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.
17

(g) Except as provided in paragraph (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 

NOX in excess of either:

(i) 88 ng/J (0.70 lb/MWh) gross energy output; or

(ii) 95 ng/J (0.76 lb/MWh) net energy output.

(2) For an affected facility which commenced 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 NOX in 

excess of either:

(i) 110 ng/J (0.85 lb/MWh) gross energy output; or

(ii) 120 ng/J (0.92 lb/MWh) net energy output.

(3) For an affected facility which commenced modification, any gases that contain NOX in excess of 140

ng/J (1.1 lb/MWh) gross energy output.

(h) The NOX emissions 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.

§60.45Da Standard for mercury (Hg).

(a) For each coal-fired electric utility steam generating unit other than an IGCC electric utility steam 

generating unit, 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, modification, or reconstruction commenced after January 30, 2004, any gases that contain 

mercury (Hg) emissions in excess of each Hg emissions limit in paragraphs (a)(1) through (5) of this 

section that applies to you. The Hg emissions limits in paragraphs (a)(1) through (5) of this section are 

based on a 12-month rolling average basis using the procedures in §60.50Da(h).

(1) For each coal-fired electric utility steam generating unit that burns only bituminous coal, you must 

not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 20 

× 10−6 pound per megawatt hour (lb/MWh) or 0.020 lb/gigawatt-hour (GWh) on an output basis. The 

International System of Units (SI) equivalent is 0.0025 ng/J.

(2) For each coal-fired electric utility steam generating unit that burns only subbituminous coal:

(i) If your unit is located in a county-level geographical area receiving greater than 25 inches per year 

(in/yr) mean annual precipitation, based on the most recent publicly available U.S. Department of 

Agriculture 30-year data, you must not discharge into the atmosphere any gases from a new affected 

source that contain Hg in excess of 66 × 10−6 lb/MWh or 0.066 lb/GWh on an output basis. The SI 

equivalent is 0.0083 ng/J.

(ii) If your unit is located in a county-level geographical area receiving less than or equal to 25 in/yr 

mean annual precipitation, based on the most recent publicly available U.S. Department of Agriculture 

Comment [CF24]: Delete vacated CAMR

provision
18

30-year data, you must not discharge into the atmosphere any gases from a new affected source that 

contain Hg in excess of 97 × 10−6 lb/MWh or 0.097 lb/GWh on an output basis. The SI equivalent is 

0.0122 ng/J.

(3) For each coal-fired electric utility steam generating unit that burns only lignite, you must not 

discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 175 × 

10−6 lb/MWh or 0.175 lb/GWh on an output basis. The SI equivalent is 0.0221 ng/J.

(4) For each coal-burning electric utility steam generating unit that burns only coal refuse, you must not 

discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 16 × 

10−6 lb/MWh or 0.016 lb/GWh on an output basis. The SI equivalent is 0.0020 ng/J.

(5) For each coal-fired electric utility steam generating unit that burns a blend of coals from different 

coal ranks ( i.e. , bituminous coal, subbituminous coal, lignite) or a blend of coal and coal refuse, you 

must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess 

of the unit-specific Hg emissions limit established according to paragraph (a)(5)(i) or (ii) of this section, 

as applicable to the affected unit.

(i) If you operate a coal-fired electric utility steam generating unit that burns a blend of coals from 

different coal ranks or a blend of coal and coal refuse, you must not discharge into the atmosphere any 

gases from a new affected source that contain Hg in excess of the computed weighted Hg emissions 

limit based on the Btu, MWh, or MJ) contributed by each coal rank burned during the compliance period 

and its applicable Hg emissions limit in paragraphs (a)(1) through (4) of this section as determined using 

Equation 1 in this section. For each affected source, you must comply with the weighted Hg emissions 

limit calculated using Equation 1 in this section based on the total Hg emissions from the unit and the 

total Btu, MWh, or MJ contributed by all fuels burned during the compliance period.

Where:

ELb= Total allowable Hg in lb/MWh that can be emitted to the atmosphere from any affected source 

being averaged according to this paragraph.

ELi= Hg emissions limit for the subcategory i (coal rank) that applies to affected source, lb/MWh;

HHi= For each affected source, the Btu, MWh, or MJ contributed by the corresponding subcategory i 

(coal rank) burned during the compliance period; and

n = Number of subcategories (coal ranks) being averaged for an affected source.

(ii) If you operate a coal-fired electric utility steam generating unit that burns a blend of coals from 

different coal ranks or a blend of coal and coal refuse together with one or more non-regulated, 

supplementary fuels, you must not discharge into the atmosphere any gases from a new affected source 

that contain Hg in excess of the computed weighted Hg emission limit based on the Btu, MWh, or MJ 

contributed by each coal rank burned during the compliance period and its applicable Hg emissions limit 

in paragraphs (a)(1) through (4) of this section as determined using Equation 1 in this section. For each 

affected source. You must comply with the weighted Hg emissions limit calculated using Equation 1 in 

this section based on the total Hg emissions from the unit contributed by both regulated and 
19

nonregulated fuels burned during the compliance period and the total Btu, MWh, or MJ contributed by 

both regulated and nonregulated fuels burned during the compliance period.

§60.45Da Alternative standards for combined nitrogen oxides (NOX) and carbon monoxide (CO).

(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 NOX emissions limits specified in 

§60.44Da may elect to meet the applicable standards for combined NOX and carbon monoxide 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-day rolling average 

basis.

(1) For an affected facility which commenced construction or reconstruction, any gases that contain 

NOX plus CO in excess of either:

(i) 140 ng/J (1.1 lb/MWh) gross energy output; or

(ii) 150 ng/J (1.2 lb/MWh) net energy output.

(2) For an affected facility which commenced 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 NOX plus 

CO in excess of either:

(i) 160 ng/J (1.3 lb/MWh) gross energy output; or

(ii) 170 ng/J (1.4 lb/MWh) net energy output.(3) For an affected facility which commenced 

modification, any gases that contain NOX plus CO in excess of 190 ng/J (1.5 lb/MWh) gross energy 

output.

§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 SO2 

emission reduction requirements under §60.43Da(c) but must, as a minimum, reduce SO2 emissions to 

20 percent of the potential combustion concentration (80 percent reduction) for each 24-hour period of 

steam generator operation and to less than 520 ng/J (1.20 lb/MMBtu) heat input on a 30-day rolling 

average basis. 

(c) An owner or operator of aan affected facility that uses fluidized bed combustion electric utility steam 

generator (atmospheric or pressurized) and who is issued a commercial demonstration permit by the 

Administrator is not subject to the SO2 emission reduction requirements under §60.43Da(a) but must, as 

a minimum, reduce SO2 emissions to 15 percent of the potential combustion concentration (85 percent 

Comment [CF25]: New section to cover

combined NOx + CO standard.
20

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 

(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 SO2 standards or emission reduction requirements under §60.43Da but must, as a 

minimum, reduce SO2 emissions to 5 percent of the potential combustion concentration (95 percent 

reduction) or to less than 180 ng/J (1.4 lb/MWh) gross energy output on a 30-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 who is issued a commercial demonstration permit by the Administrator is not 

subject to the NOX standards or emission reduction requirements under §60.44Da but must, as a 

minimum, either reduce NOX emissions to less than 130 ng/J (1.0 lb/MWh) or the combined NOX plus 

CO emissions to less than 180 ng/J (1.4 lb/MWh) gross energy output on a 30-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

Comment [CF26]: New commercial

demonstration permit exemptions
21

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

§60.48Da Compliance provisions. 

(a) Compliance with the PM emission limitation under §60.42Da(a)(1) constitutes compliance with the 

percent reduction requirements for PM under §60.42Da(a)(2) and (3).

(b) Compliance with the NOXemission limitation under §60.44Da(a)(1) constitutes compliance with the 

percent reduction requirements under §60.44Da(a)(2).

(ca) For affected facilities for which construction, modification, or reconstruction commenced before 

May 4, 2011, Tthe applicable PM emission standards and opacity standards under §60.42Da, SO2

emission standards under §60.43Da, and the NOX emission standards under §60.44Da, under §60.45Da

apply at all times except during periods of startup, shutdown, or malfunction. The sulfur dioxide 

emission standards under §60.43Da apply at all times except during periods of startup, shutdown, or 

when both emergency conditions exist and the procedures under paragraph (d) of this section are 

implemented.For affected facilities for which construction, modification, or reconstruction commenced 

after May 3, 2011, the applicable SO2 emission standards under §60.43Da, NOX emission standards

under §60.44Da, and NOX plus CO emission standards under §60.45Da apply at all times. The 

applicable PM emission standards and opacity standards under §60.42Da apply at all times except 

during periods of startup and shutdown.

(d) During emergency conditions in the principal company, an affected facility with a malfunctioning 

flue gas desulfurization system may be operated if SO2emissions are minimized by:

(1) Operating all operable flue gas desulfurization system modules, and bringing back into operation any 

malfunctioned module as soon as repairs are completed,

(2) Bypassing flue gases around only those flue gas desulfurization system modules that have been taken 

out of operation because they were incapable of any SO2emission reduction or which would have 

suffered significant physical damage if they had remained in operation, and

(3) Designing, constructing, and operating a spare flue gas desulfurization system module for an affected 

facility larger than 365 MW (1,250 MMBtu/hr) heat input (approximately 125 MW electrical output 

capacity). The Administrator may at his discretion require the owner or operator within 60 days of 

notification to demonstrate spare module capability. To demonstrate this capability, the owner or 

operator must demonstrate compliance with the appropriate requirements under paragraph under 

§60.43Da(a), (b), (d), (e), and (h) for any period of operation lasting from 24 hours to 30 days when:

(i) Any one flue gas desulfurization module is not operated,

(ii) The affected facility is operating at the maximum heat input rate,

(iii) The fuel fired during the 24-hour to 30-day period is representative of the type and average sulfur 

content of fuel used over a typical 30-day period, and

(iv) The owner or operator has given the Administrator at least 30 days notice of the date and period of 

time over which the demonstration will be performed.

(eb) After the initial performance test required under §60.8, compliance with the applicable SO2

emission standardslimitations and percentage reduction requirements under §60.43Da, and the NOX

emission standardslimitations under §60.44Da, and NOX plus CO emission standards under §60.45Da

Comment [CF27]: Include all periods of

operation.  

Removing emergency conditions for existing

facilities.  

Comment [CF28]: Amended procedures for

calculating emissions rates divides total emissions

by total output over a 30‐day period (total

emissions/total output & not average of hourly

rates). Minimizes periods of startup and shutdown

since less mass of emissions at lower operational

rates.  

Comment [CF29]: Do not need % reduction

compliance language anymore – deleted

requirements.

Comment [CF30]: Removed emergency

conditions and just use malfunctions
22

isare 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 

day average emission rate for both SO2,and NOX, and NOX plus CO as applicable, and a new percent 

reduction for SO2 are calculated to show compliance with the standards. 

(cf) For the initial performance test required under §60.8, compliance with the SO2 emission limitations 

and percent reduction requirements under §60.43Da, and the NOX emission limitation under §60.44Da,

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

and percent reduction for SO2 for 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-day rolling average SO2 and NOX emissions limits is 

determined by calculating the arithmetic average of all hourly emission rates for SO2 and NOX for 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-day rolling average SO2 and NOX emissions limits is determined by 

dividing the sum of the SO2 and NOX emissions for the 30 successive boiler operating days divided 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 SO2 percentage reduction requirements is determined based on 

the average inlet and outlet SO2 emission rates for the 30 successive boiler operating days. For affected 

facilities for which construction, modification, or reconstruction commenced after May 3, 2011,

compliance with applicable SO2 percentage reduction requirements is determined based on the “as fired” 

total potential emissions and the total outlet SO2 emissions for the 30 successive boiler operating days.

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

4, 2011, compliance with 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, and malfunction. Daily averages are only calculated for boiler 

operating days that have non-out-of-control data for at least 18 hours of unit operation during which the 

standard applies. Instead, all of the non-out-of-control hourly emission rates of the operating day(s) not 

meeting the minimum 18 hours non-out-of-control data daily average requirement are averaged with all 

of the non-out-of-control hourly emission rates of the next boiler operating day with 18 hours or more 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, compliance with applicable 

daily average PM emissions limits is determined by dividing the sum of the PM emissions for the 30 

successive boiler operating days by the sum of the gross useful output or net energy output, as 

applicable, for the 30 successive boiler operating days. 

(g) The owner or operator of an affected facility subject to emission limitations in this subpart shall 

determine compliance as follows:

(1) Compliance with applicable 30-day rolling average SO2and NOXemission limitations is determined 

by calculating the arithmetic average of all hourly emission rates for SO2and NOXfor the 30 successive 
23

boiler operating days, except for data obtained during startup, shutdown, malfunction (NOXonly), or 

emergency conditions (SO2only).

(2) Compliance with applicable SO2percentage reduction requirements is determined based on the 

average inlet and outlet SO2emission rates for the 30 successive boiler operating days.

(3) Compliance with applicable daily average PM emission limitations 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, and malfunction. Averages are only calculated for boiler operating 

days that have valid data for at least 18 hours of unit operation during which the standard applies.

Instead, all of the valid hourly emission rates of the operating day(s) not meeting the minimum 18 hours 

valid data daily average requirement are averaged with all of the valid hourly emission rates of the next 

boiler operating day with 18 hours or more of valid PM CEMS data to determine compliance.

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

3, 2011, compliance with applicable 30-day rolling average NOX plus CO emissions limit is determined 

by dividing the sum of the NOX plus CO emissions for the 30 successive boiler operating days by the 

sum of the gross energy output or net energy output, as applicable, for the 30 successive boiler operating 

days.

(h) If an owner or operator has not obtained the minimum quantity of emission data as required under 

§60.49Da of this subpart, compliance of the affected facility with the emission requirements under 

§§60.43Da and 60.44Da of this subpart for the day on which the 30-day period ends may be determined 

by the Administrator by following the applicable procedures in section 7 of Method 19 of appendix A of 

this part. 

(i) Compliance provisions for sources subject to §60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), (f), or (f) .g).

The owner or operator of an affected facility subject to §60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), or (f) 

shall calculate NOX emissions as 1.194 × 10−7 lb/scf-ppm times the average hourly NOX output 

concentration in ppm (measured according to the provisions of §60.49Da(c)), times the average hourly 

flow rate (measured in scfh, according to the provisions of §60.49Da(l) or §60.49Da(m)), divided by the 

average hourly gross energy output (measured according to the provisions of §60.49Da(k)).)) or the 

average hourly net energy output, as applicable. Alternatively, for oil-fired and gas-fired units, NOX 

emissions may be calculated by multiplying the hourly NOX emission rate in lb/MMBtu (measured by 

the CEMS required under §§60.49Da(c) and (d)), by the hourly heat input rate (measured according to 

the provisions of §60.49Da(n)), and dividing the result by the average gross energy output (measured 

according to the provisions of §60.49Da(k)).)) or the average hourly net energy output, as applicable.

(j) Compliance provisions for duct burners subject to §60.44Da(a)(1) . To determine compliance with 

the emissions limits for 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 
24

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: 

Where: 

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

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/hr (dscf/hr); 

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

Osg = Average hourly gross energy output from steam generating unit, J (MWh/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. 

Comment [CF31]: Fix typo
25

(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: 

Where: 

E = Emission rate of NOX from 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/hr (dscf/hr); 

and 

Occ= Average hourly gross energy output from entire combined cycle unit, J (MWh/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/hr) 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: 

Where: 

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

ERsg= Average hourly emission rate of NOX exiting the steam generating unit heat input calculated using 

appropriate F factor as described in Method 19 of appendix A of this part, ng/J (lb/MMBtu); 

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

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

Comment [CF32]: Fix typo
26

(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) Compliance provisions for sources subject to §60.45Da. The owner or operator of an affected facility 

subject to §60.45Da (new sources constructed or reconstructed after January 30, 2004) shall calculate 

the Hg emission rate (lb/MWh) for each calendar month of the year, using hourly Hg concentrations 

measured according to the provisions of §60.49Da(p) in conjunction with hourly stack gas volumetric 

flow rates measured according to the provisions of §60.49Da(l) or (m), and hourly gross electrical 

outputs, determined according to the provisions in §60.49Da(k). Compliance with the applicable 

standard under §60.45Da is determined on a 12-month rolling average basis.

(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), 

or (j)(3)(i).), (l)(1)(i), (l)(1)(ii), or (l)(2). The owner or operator of an affected facility subject to 

§60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), or (j)(3)(i) shall calculate SO2emissionsSO2

emissions as 1.660 × 10–7lb/scf-ppm times the average hourly SO2outputSO2 output concentration in 

ppm (measured according to the provisions of §60.49Da(b)), times the average hourly flow rate 

(measured according to the provisions of §60.49Da(l) or §60.49Da(m)), divided by the average hourly 

gross energy output (measured according to the provisions of §60.49Da(k)).)) or the average hourly net 

energy output, as applicable. Alternatively, for oil-fired and gas-fired units, SO2 emissions may be 

calculated by multiplying the hourly SO2 emission rate (in lb/MMBtu), measured by the CEMS required 

under §60.49Da, by the hourly heat input rate (measured according to the provisions of §60.49Da(n)), 

and dividing the result by the average gross energy output (measured according to the provisions of 

§60.49Da(k)).)) or the average hourly net energy output, as applicable.

(n) Compliance provisions for sources subject to §60.42Da(c)(1) or (e) . The owner or operator of an 

affected facility subject to §60.42Da(c)(1) 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 

divideddividing by the average hourly gross energy output (measured according to the provisions of 

§60.49Da(k)). Compliance with)) or the emission limit is determined by calculating the arithmetic 

average of the hourly emission rates computed for each boiler operating day.net energy output, as 

applicable. 

(o) Compliance provisions for sources subject to §60.42Da(c)(2) or (d) . Except as provided for in 

paragraph (p) of this section, the owner or operator of an affected facility for which construction, 

reconstruction, or modification commenced after February 28, 2005, shall demonstrate compliance with 

each applicable emission 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 

Comment [CF33]: Delete since CAMR vacated
27

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. 

(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 
28

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 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 
29

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.) 

(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 sitespecific 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 
30

according to the site-specific 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. 

(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 
31

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, validnon-out-of-control CEMS hourly averages shall be obtained for 75 percent of all 

operating hours on a 30-day rolling average basis. Beginning on January 1, 2012, validnon-out-ofcontrol CEMS hourly averages shall be obtained for 90 percent of all operating hours on a 30-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. 

(7) All validnon-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 

Comment [CF34]: Consistent with Part 75

monitoring
32

systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to 

provide, as necessary, validnon-out-of-control emissions data for a minimum of 90 percent (only 75 

percent is required prior to January 1, 2012) of all operating hours per 30-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(b). To determine compliance with the NOX

plus CO emissions limit, the owner or operator shall use the procedures specified in paragraphs (r)(1) 

through (3) of this section.

(1) Calculate NOX emissions as 1.194 × 10−7 lb/scf-ppm times the average hourly NOX output 

concentration in ppm (measured according to the provisions of §60.49Da(c)), times the average hourly 

flow rate (measured in scfh, according to the provisions of §60.49Da(l) or §60.49Da(m)), divided by the 

average hourly gross energy output (measured according to the provisions of §60.49Da(k)) or the 

average hourly net energy output, as applicable. (2) Calculate CO emissions by multiplying the average 

hourly CO output concentration (measured according to the provisions of §60.49Da(u), by the average 

hourly flow rate (measured according to the provisions of §60.49Da(l) or §60.49Da(m)), and dividing by 

the average hourly gross energy output (measured according to the provisions of §60.49Da(k)) or the 

average hourly net energy output, as applicable. 

(3) Calculate NOX plus CO emissions by summing the NOX emissions results from paragraph (r)(1) of 

this section plus the NOX 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 emission limitations were being 

exceeded. Off-shift and overtime labor were used, to the extent practicable to make these repairs; and
33

(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

(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. 

(a) 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 

applicable requirements in paragraphs (a)(1) through (3) of this section. 

(1) Except as provided for in paragraphparagraphs (a)(2), and (4) of this section, the owner or operator 

of an affected facility, subject to an opacity standard in §60.42a(b) 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 SO2

control system), alternate parameters indicative of the PM control system's performance and/or good 

combustion are monitored (subject to the approval of the Administrator). 

Comment [CF35]: Clarify COMS not required for

facilities not subject to an opacity standard
34

(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 (iiiiv) 

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; or

(iii) The affected facility meets all of the conditions specified in paragraphs (a)(2)(iii)(A) through (C) of 

this section..; or

(A) No post-combustion technology (except a wet scrubber) is used for reducing PM, SO2, or carbon 

monoxide (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. 

(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 operatorsoperator 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. The permitting authority may exempt owners or operators of affected facilities 

burning only natural gas from the opacity monitoring requirements.

(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)(DC) of this section, as determined by the most recent Method 9 of appendix A–4 of this part 

performance test results. 

(A) If no visible emissions are observed,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; 

Comment [CF36]: Add ESP model to COMS

exemption options

Comment [CF37]: No longer need since

proposing to exempt natural gas‐fired EGUs from

the opacity standard.

Comment [CF38]: Allow flexibility to account

for intermittent use of fuels with an opacity

standard.
35

(B) If visible emissions are observed but 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 6 calendar months from the date that the most recent performance test was conducted;

(C (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 

(DC) 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). 

(B) If no visible emissions are observed for 3010 operating days during which an opacity standard is 

applicable, observations can be reduced to once every 7 operating days during which an opacity standard 

is applicable. If any visible emissions are observed, daily observations shall be resumed. 

(iv) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of 

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

subsequent Method 9 of appendix A–4 performance tests, elect to perform subsequent monitoring using 

a digital opacity compliance system according to a site-specific monitoring plan approved by the 

Administrator. The observations shall 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. 
36

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

not required to operate a COMS provided that the affected facility meets the conditions in either 

paragraph (4)(i) or (4)(ii) of this section.

(i) The affected facility burns only gaseous fuels and/or liquid fuels (excluding residue oil) with a 

potential SO2 emissions rate 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 sitespecific 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 §60.51a(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.

(b) 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 SO2emissionsSO2 emissions, except where natural 

gas isand/or liquid fuels (excluding residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 

lb/MMBtu) or less are the only fuelfuels combusted, as follows: 

(1) Sulfur dioxide emissions are monitored at both the inlet and outlet of the SO2controlSO2 control

device. 

(2) For a facility that qualifies under the numerical limit provisions of §60.43Da(d), (i), (j), or (k) 

SO2emissions SO2 emissions are only monitored as discharged to the atmosphere. 

(3) An “as fired” fuel monitoring system (upstream of coal pulverizers) meeting the requirements of 

Method 19 of appendix A of this part may be used to determine potential SO2emissions in place of a 

continuous SO2emission monitor at the inlet to the SO2control device as required under paragraph (b)(1) 

of this section. 

(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 

Comment [CF39]: Add flexibility for permitting

authority to approve site specific opacity monitoring

plan

Comment [CF40]: Allow PM CPMS for NESHAP

PM monitoring to qualify for COMS exemption

Comment [CF41]: Add exemption for low sulfur

oil form the SO2 CEMS requirement. Do we need to

add a fuel sampling/receipts requirement

Comment [CF42]: Since adding additional

numerical limits it is simpler to just refer the entire

section.
37

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 or 

emergency conditions, and, 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. 

(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. 
38

(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. 
39

(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. 

(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 thean output-based standard under 

§§60.42Da(c), 60.43Da(i), 60.43Da(j), 60.44Da(d)(1), and 60.44Da(e)..

(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 affected facilities generating process steam in combination with electrical generation, the gross 

energy output is determined from the gross electrical output measured in accordance with paragraph

(k)(1) of this section plus 75 percent of the gross thermal output (measured relative to ISO conditions) of 

the process steam measured in accordance with paragraph (k)(2) of this section.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 under §60.42Da, §60.43Da, §60.44Da, or §60.45Da shall install, certify, operate, and maintain 

Comment [CF43]: Simplify since adding new

paragraphs

Comment [CF44]: Simplify
40

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. 

(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) The owner or operator of an affected facility demonstrating compliance with an Hg limit in 

§60.45Da shall install and operate a CEMS to measure and record the concentration of Hg in the exhaust 

gases from each stack according to the requirements in paragraphs (p)(1) through (p)(3) of this section. 

Alternatively, for an affected facility that is also subject to the requirements of subpart I of part 75 of 

this chapter, the owner or operator may install, certify, maintain, operate and quality-assure the data 

from a Hg CEMS according to §75.10 of this chapter and appendices A and B to part 75 of this chapter, 

in lieu of following the procedures in paragraphs (p)(1) through (p)(3) of this section.

(1) The owner or operator must install, operate, and maintain each CEMS according to Performance 

Specification 12A in appendix B to this part.

(2) The owner or operator must conduct a performance evaluation of each CEMS according to the 

requirements of §60.13 and Performance Specification 12A in appendix B to this part.

(3) The owner or operator must operate each CEMS according to the requirements in paragraphs 

(p)(3)(i) through (iv) of this section.

(i) As specified in §60.13(e)(2), each CEMS must complete a minimum of one cycle of operation 

(sampling, analyzing, and data recording) for each successive 15-minute period.

(ii) The owner or operator must reduce CEMS data as specified in §60.13(h).

(iii) The owner or operator shall use all valid data points collected during the hour to calculate the hourly 

average Hg concentration.

(iv) The owner or operator must record the results of each required certification and quality assurance 

test of the CEMS.

(4) Mercury CEMS data collection must conform to paragraphs (p)(4)(i) through (iv) of this section.

Comment [CF45]: Delete since CAMR vacated
41

(i) For each calendar month in which the affected unit operates, valid hourly Hg concentration data, 

stack gas volumetric flow rate data, moisture data (if required), and electrical output data (i.e., valid data 

for all of these parameters) shall be obtained for at least 75 percent of the unit operating hours in the 

month.

(ii) Data reported to meet the requirements of this subpart shall not include hours of unit startup, 

shutdown, or malfunction. In addition, for an affected facility that is also subject to subpart I of part 75 

of this chapter, data reported to meet the requirements of this subpart 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.

(iii) If valid data are obtained for less than 75 percent of the unit operating hours in a month, you must 

discard the data collected in that month and replace the data with the mean of the individual monthly 

emission rate values determined in the last 12 months. In the 12-month rolling average calculation, this 

substitute Hg emission rate shall be weighted according to the number of unit operating hours in the 

month for which the data capture requirement of §60.49Da(p)(4)(i) was not met.

(iv) Notwithstanding the requirements of paragraph (p)(4)(iii) of this section, if valid data are obtained 

for less than 75 percent of the unit operating hours in another month in that same 12-month rolling 

average cycle, discard the data collected in that month and replace the data with the highest individual 

monthly emission rate determined in the last 12 months. In the 12-month rolling average calculation, 

this substitute Hg emission rate shall be weighted according to the number of unit operating hours in the 

month for which the data capture requirement of §60.49Da(p)(4)(i) was not met.

(q) As an alternative to the CEMS required in paragraph (p) of this section, the owner or operator may 

use a sorbent trap monitoring system (as defined in §72.2 of this chapter) to monitor Hg concentration, 

according to the procedures described in §75.15 of this chapter and appendix K to part 75 of this 

chapter.

(r) For Hg CEMS that measure Hg concentration on a dry basis or for sorbent trap monitoring systems, 

the emissions data must be corrected for the stack gas moisture content. A certified continuous moisture 

monitoring system that meets the requirements of §75.11(b) of this chapter is acceptable for this 

purpose. Alternatively, the appropriate default moisture value, as specified in §75.11(b) or §75.12(b) of 

this chapter, may be used.

(p) [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); 
42

(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 the output-based 

emissions limitation under §60.42Da(c)(1) shall shall install, certify, operate, and maintain a CEMS for 

measuring PM emissions according to the requirements of paragraph (v) of this section. An owner or 

operator of an affected facility demonstrating compliance with the input-based emission limitation 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. An owner or operator of an affected facility 

demonstrating compliance with the input-based emission limitation in §60.42Da(a)(1) or §60.42Da(c)(2) 

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, validnon-out-of-control 1-hour CO emissions averages must be obtained for at least 

90 percent of the operating hours on a 30-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. 

(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. 
43

(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) After July 1, 2011, within 90 days after the date of completing each performance evaluation 

required by paragraph (v) of this section, the owner or operator of the affected facility must either 

submit the test data to EPA by successfully entering the data electronically into EPA's WebFIRE data 

base available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main or mail a copy to: United 

States Environmental Protection Agency; Energy Strategies Group; 109 TW Alexander DR; Mail Code: 

D243–01; RTP, NC 27711.

(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 

Comment [CF46]: Updated language for

electronic reporting
44

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 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. 

§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. 
45

(b) The owner or operator shall In conducting the performance tests to determine compliance with the 

PM standards 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 follows:specified in paragraphs (b)(1)(i) through (iii) of this section.

(1i) 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. 

(2ii) For the particular matterPM concentration, Method 5 of appendix A of this part shall be used atfor 

an affected facilities withoutfacility that does not use a wet FGD systems and. For an affected facility 

that uses a wet FGD system, Method 5B of appendix A of this part shall be used afterdownstream of the

wet FGD systems. 

(iA) 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). 

(iiB) 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 O2 

concentration. The O2 sample shall be obtained simultaneously with, and at the same traverse points as, 

the particulate run. If the particulate run has more than 12 traverse points, the O2 traverse points may be 

reduced to 12 provided that Method 1 of appendix A of this part is used to locate the 12 O2 traverse 

points. If the grab sampling procedure is used, the O2 concentration for the run shall be the arithmetic 

mean of the sample O2 concentrations at all traverse points. 

(2) In conjunction with a performance test performed according to the requirements in paragraph (b)(1) 

of this section, the owner or 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. 
46

(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. 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) Electric utility combined cycle gas turbines that are not designed to burn fuels containing 50 percent 

(by heat input) or more solid derived fuel not meeting the definition of natural gas are performance 

tested for PM, SO2, and NOXusing the procedures of Method 19 of appendix A–7 of this part. The 

SO2and NOXemission 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.

(g) For the purposes of determining compliance with the emission limits in §60.45Da, the owner or 

operator of an electric utility steam generating unit which is also a cogeneration unit shall use the 

procedures in paragraphs (g)(1) and (2) of this section to calculate emission rates based on electrical 

output to the grid plus 75 percent of the equivalent electrical energy (measured relative to ISO 

conditions) in the unit's process stream.

(1) All conversions from Btu/hr unit input to MW unit output must use equivalents found in 40 CFR 

60.40(a)(1) for electric utilities ( i.e. , 250 MMBtu/hr input to an electric utility steam generating unit is 

equivalent to 73 MW input to the electric utility steam generating unit); 73 MW input to the electric 

utility steam generating unit is equivalent to 25 MW output from the boiler electric utility steam 

Comment [CF47]: Deleted CAMR provision
47

generating unit; therefore, 250 MMBtu input to the electric utility steam generating unit is equivalent to 

25 MW output from the electric utility steam generating unit).

(2) Use the Equation 5 in this section to determine the cogeneration Hg emission rate over a specific 

compliance period.

Where:

ERcogen= Cogeneration Hg emission rate over a compliance period in lb/MWh;

E = Mass of Hg emitted from the stack over the same compliance period (lb);

Vgrid= Amount of energy sent to the grid over the same compliance period (MWh); and

Vprocess= Amount of energy converted to steam for process use over the same compliance period (MWh).

(h) The owner or operator shall determine compliance with the Hg limit in §60.45Da according to the 

procedures in paragraphs (h)(1) through (3) of this section.

(1) The initial performance test shall be commenced by the applicable date specified in §60.8(a). The 

required CEMS must be certified prior to commencing the test. The performance test consists of 

collecting hourly Hg emission data (lb/MWh) with the CEMS for 12 successive months of unit 

operation (excluding hours of unit startup, shutdown and malfunction). The average Hg emission rate is 

calculated for each month, and then the weighted, 12-month average Hg emission rate is calculated 

according to paragraph (h)(2) or (h)(3) of this section, as applicable. If, for any month in the initial 

performance test, the minimum data capture requirement in §60.49Da(p)(4)(i) is not met, the owner or 

operator shall report a substitute Hg emission rate for that month, as follows. For the first such month, 

the substitute monthly Hg emission rate shall be the arithmetic average of all valid hourly Hg emission 

rates recorded to date. For any subsequent month(s) with insufficient data capture, the substitute 

monthly Hg emission rate shall be the highest valid hourly Hg emission rate recorded to date. When the 

12-month average Hg emission rate for the initial performance test is calculated, for each month in 

which there was insufficient data capture, the substitute monthly Hg emission rate shall be weighted 

according to the number of unit operating hours in that month. Following the initial performance test, 

the owner or operator shall demonstrate compliance by calculating the weighted average of all monthly 

Hg emission rates (in lb/MWh) for each 12 successive calendar months, excluding data obtained during 

startup, shutdown, or malfunction.

(2) If a CEMS is used to demonstrate compliance, follow the procedures in paragraphs (h)(2)(i) through 

(iii) of this section to determine the 12-month rolling average.

(i) Calculate the total mass of Hg emissions over a month (M), in lb, using either Equation 6 in 

paragraph (h)(2)(i)(A) of this section or Equation 7 in paragraph (h)(2)(i)(B) of this section, in 

conjunction with Equation 8 in paragraph (h)(2)(i)(C) of this section.

(A) If the Hg CEMS measures Hg concentration on a wet basis, use Equation 6 below to calculate the 

Hg mass emissions for each valid hour:

Where:
48

Eh= Hg mass emissions for the hour, (lb);

K = Units conversion constant, 6.24 × 10−11 lb-scm/μgm-scf;

Ch= Hourly Hgconcentration, wet basis, (μgm/scm);

Qh= Hourly stack gas volumetric flow rate, (scfh); and

th= Unit operating time, i.e., the fraction of the hour for which the unit operated. For example, th = 0.50 

for a half-hour of unit operation and 1.00 for a full hour of operation.

(B) If the Hg CEMS measures Hg concentration on a dry basis, use Equation 7 below to calculate the Hg 

mass emissions for each valid hour:

Where:

Eh= Hg mass emissions for the hour, (lb);

K = Units conversion constant, 6.24 × 10−11lb-scm/μgm-scf;

Ch= Hourly Hg concentration, dry basis, (μgm/dscm);

Qh= Hourly stack gas volumetric flow rate, (scfh);

th= Unit operating time, i.e. , the fraction of the hour for which the unit operated; and

Bws= Stack gas moisture content, expressed as a decimal fraction ( e.g. , for 8 percent H2O, Bws= 0.08).

(C) Use Equation 8, below, to calculate M, the total mass of Hg emitted for the month, by summing the 

hourly masses derived from Equation 6 or 7 (as applicable):

Where:

M = Total Hg mass emissions for the month, (lb);

Eh= Hg mass emissions for hour “h”, from Equation 6 or 7 of this section, (lb); and

n = Number of unit operating hours in the month with valid CE and electrical output data, excluding 

hours of unit startup, shutdown and malfunction.

(ii) Calculate the monthly Hg emission rate on an output basis (lb/MWh) using Equation 9, below. For a 

cogeneration unit, use Equation 5 in paragraph (g) of this section instead.

Where:

ER = Monthly Hg emission rate, (lb/MWh);

M = Total mass of Hg emissions for the month, from Equation 8, above, (lb); and

P = Total electrical output for the month, for the hours used to calculate M, (MWh).
49

(iii) Until 12 monthly Hg emission rates have been accumulated, calculate and report only the monthly 

averages. Then, for each subsequent calendar month, use Equation 10 below to calculate the 12-month 

rolling average as a weighted average of the Hg emission rate for the current month and the Hg emission 

rates for the previous 11 months, with one exception. Calendar months in which the unit does not 

operate (zero unit operating hours) shall not be included in the 12-month rolling average.

Where:

Eavg= Weighted 12-month rolling average Hg emission rate, (lb/MWh);

ERi= Monthly Hg emission rate, for month “i”, (lb/MWh); and

n = Number of unit operating hours in month “i” with valid CEM and electrical output data, excluding 

hours of unit startup, shutdown, and malfunction.

(3) If a sorbent trap monitoring system is used in lieu of a Hg CEMS, as described in §75.15 of this 

chapter and in appendix K to part 75 of this chapter, calculate the monthly Hg emission rates using 

Equations 7 through 9 of this section, except that for a particular pair of sorbent traps, Chin Equation 7 

shall be the flow-proportional average Hg concentration measured over the data collection period.

(i) Daily calibration drift (CD) tests and quarterly accuracy determinations shall be performed for Hg 

CEMS in accordance with Procedure 1 of appendix F to this part. For the CD assessments, you may use 

either elemental mercury or mercuric chloride (Hg° HgCl2) standards. The four quarterly accuracy 

determinations shall consist of one RATA and three measurement error (ME) tests using 

HgCl2standards, as described in section 8.3 of Performance Specification 12–A in appendix B to this 

part (note: Hg° standards may be used if the Hg monitor does not have a converter). Alternatively, the 

owner or operator may implement the applicable daily, weekly, quarterly, and annual quality assurance 

(QA) requirements for Hg CEMS in appendix B to part 75 of this chapter, in lieu of the QA procedures 

in appendices B and F to this part. Annual RATA of sorbent trap monitoring systems shall be performed 

in accordance with appendices A and B to part 75 of this chapter, and all other quality assurance 

requirements specified in appendix K to part 75 of this chapter shall be met for sorbent trap monitoring 

systems.

§60.51Da Reporting requirements.

(a) For SO2, NOX, PM, and HgNOX plus 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) are submittedmust 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. 
50

(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, malfunction (NOXonly), emergency conditions (SO2only), 

or other reasons, and justification for excluding data for reasons other than startup, shutdown, 

malfunction, or emergency conditionsor 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. 

(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) If any standards under In addition to the applicable requirements in §60.743Da are exceeded during 

emergency conditions because of control system malfunction, the owner or operator of thean 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 a signed statement: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) Indicating if emergency conditions existed and requirements under §60.48Da(d) were met during 

each period, and 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 (c)(1)(i) 

through (iii) of this section.

(i) Dates and time intervals of all opacity observation periods;
51

(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]

(2) Listing the following information:

(i) Time periods the emergency condition existed;

(ii) Electrical output and demand on the owner or operator's electric utility system and the affected 

facility;

(iii) Amount of power purchased from interconnected neighboring utility companies during the 

emergency period;

(iv) Percent reduction in emissions achieved;

(v) Atmospheric emission rate (ng/J) of the pollutant discharged; and

(vi) Actions taken to correct control system malfunction.

(e) If fuel pretreatment credit toward the SO2 emission standard under §60.43Da is claimed, the owner or 

operator of the affected facility shall submit a signed statement: 

(1) Indicating what percentage cleaning credit was 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, SO2 or NOX emissions data are not available, the owner or 

operator of the affected facility shall submit a signed statement indicating if any changes were made in 

operation of the emission control system during the period of data unavailability. Operations of the 

control system and affected facility during periods of data unavailability are to be compared with 

operation of the control system and affected facility before and following the period of data 

unavailability. 

(g) For Hg, the following information shall be reported to the Administrator:

(1) Company name and address;

(2) Date of report and beginning and ending dates of the reporting period;

(3) The applicable Hg emission limit (lb/MWh); and

(4) For each month in the reporting period:

(i) The number of unit operating hours;

(ii) The number of unit operating hours with valid data for Hg concentration, stack gas flow rate, 

moisture (if required), and electrical output;

(iii) The monthly Hg emission rate (lb/MWh);

(iv) The number of hours of valid data excluded from the calculation of the monthly Hg emission rate, 

due to unit startup, shutdown and malfunction; and
52

(v) The 12-month rolling average Hg emission rate (lb/MWh); and

(5) The data assessment report (DAR) required by appendix F to this part, or an equivalent summary of 

QA test results if the QA of part 75 of this chapter are implemented.

(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 SO2 and/or 

NOX and/or opacity and/or Hg in lieu of submitting the written reports required under paragraphs (b), 

(g), and (i) of this section. The format 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. Before submitting reports in the electronic 

format, the owner or operator shall coordinate with the permitting authority to obtain their agreement to 

submit reports in this alternative format. 

§60.52Da Recordkeeping requirements. 

(a) The owner or operator of an affected facility subject to the emissions limitations in §60.45Da shall 

provide notifications in accordance with §60.7(a) and shall maintain records of all information needed to 

demonstrate compliance including performance tests, monitoring data, fuel analyses, and calculations, 

consistent with the requirements of §60.7(f).

(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. 
53

(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.