1

Subpart Db—Standards of Performance for Industrial-Commercial-Institutional Steam 

Generating Units 

§60.40b Applicability and delegation of authority. 

(a) The affected facility to which this subpart applies is each steam generating unit that commences 

construction, modification, or reconstruction after June 19, 1984, and that has a heat input capacity from 

fuels combusted in the steam generating unit of greater than 29 megawatts (MW) (100 million British 

thermal units per hour (MMBtu/hr)). 

(b) Any affected facility meeting the applicability requirements under paragraph (a) of this section and 

commencing construction, modification, or reconstruction after June 19, 1984, but on or before June 19, 

1986, is subject to the following standards: 

(1) Coal-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 

MMBtu/hr), inclusive, are subject to the particulate matter (PM) and nitrogen oxides (NOX) standards 

under this subpart. 

(2) Coal-fired affected facilities having a heat input capacity greater than 73 MW (250 MMBtu/hr) and 

meeting the applicability requirements under subpart D (Standards of performance for fossil-fuel-fired 

steam generators; §60.40) are subject to the PM and NOXstandards under this subpart and to the sulfur 

dioxide (SO2) standards under subpart D (§60.43). 

(3) Oil-fired affected facilities having a heat input capacity between 29 and 73 MW (100 and 250 

MMBtu/hr), inclusive, are subject to the NOXstandards under this subpart. 

(4) Oil-fired affected facilities having a heat input capacity greater than 73 MW (250 MMBtu/hr) and 

meeting the applicability requirements under subpart D (Standards of performance for fossil-fuel-fired 

steam generators; §60.40) are also subject to the NOX standards under this subpart and the PM and 

SO2standards under subpart D (§60.42 and §60.43). 

(c) Affected facilities that also meet the applicability requirements under subpart J (Standardsor subpart 

Ja of performance for petroleum refineries; §60.104) arethis part are subject to the PM and NOX

standards under this subpart and the SO2 standards under subpart J (§60.104).or subpart Ja or this part, 

as applicable.

(d) Affected facilities that also meet the applicability requirements under subpart E (Standards of 

performance for incinerators; §60.50) are subject to the NOXand PM standards under this subpart. 

(e) Steam generating units meeting the applicability requirements under subpart Da (Standards of 

performance for electric utility steam generating units; §60.40Da) are not subject to this subpart. 

(f) Any change to an existing steam generating unit for the sole purpose of combusting gases containing 

total reduced sulfur (TRS) as defined under §60.281 is not considered a modification under §60.14 and 

the steam generating unit is not subject to this subpart. 

(g) In delegating implementation and enforcement authority to a State under section 111(c) of the Clean 

Air Act, the following authorities shall be retained by the Administrator and not transferred to a State. 

(1) Section 60.44b(f). 

(2) Section 60.44b(g). 

(3) Section 60.49b(a)(4). 

Comment [CF1]: Add subpart Ja exemption.  
2

(h) Any affected facility that meets the applicability requirements and is subject to subpart Ea, subpart 

Eb, subpart AAAA, or subpart AAAACCCC of this part is not covered bysubject to this subpart. 

(i) Heat Affected facilities (i.e. heat recovery steam generators) that are associated with combined cycle 

gasstationary combustion turbines and that meet the applicability requirements of subpart KKKK of this 

part are not subject to this subpart. This subpart will continue to apply to all other affected facilities (i.e. 

heat recovery steam generators with duct burners) that are capable of combusting more than 29 MW 

(100 MMBtu/hr) heat input of fossil fuel. If the affected facility (i.e. heat recovery steam generator) is 

subject to this subpart, only emissions resulting from combustion of fuels in the steam generating unit 

are subject to this subpart. (The gasstationary combustion turbine emissions are subject to subpart GG or 

KKKK, as applicable, of this part.) 

(j) Any affected facility meeting the applicability requirements under paragraph (a) of this section and 

commencing construction, modification, or reconstruction after June 19, 1986 is not subject to subpart D 

(Standards of Performance for Fossil-Fuel-Fired Steam Generators, §60.40). 

(k) Any affected facility that meets the applicability requirements and is subject to an EPA approved 

State or Federal section 111(d)/129 plan implementing subpart Cb or subpart BBBB of this part is not 

covered by this subpart. 

(l) Affected facilities that also meet the applicability requirements under subpart BB (Standards of 

Performance for Kraft Pulp Mills) are subject to the SO2 and NOX standards under this subpart and the 

PM standards under subpart BB.

(m) Temporary boilers are not subject to this subpart.

§60.41b Definitions. 

As used in this subpart, all terms not defined herein shall have the meaning given them in the Clean Air 

Act and in subpart A of this part. 

Annual capacity factor means the ratio between the actual heat input to a steam generating unit from the 

fuels listed in §60.42b(a), §60.43b(a), or §60.44b(a), as applicable, during a calendar year and the 

potential heat input to the steam generating unit had it been operated for 8,760 hours during a calendar 

year at the maximum steady state design heat input capacity. In the case of steam generating units that 

are rented or leased, the actual heat input shall be determined based on the combined heat input from all 

operations of the affected facility in a calendar year. 

Byproduct/waste means any liquid or gaseous substance produced at chemical manufacturing plants, 

petroleum refineries, or pulp and paper mills (except natural gas, distillate oil, or residual oil) and 

combusted in a steam generating unit for heat recovery or for disposal. Gaseous substances with carbon 

dioxide (CO2) levels greater than 50 percent or carbon monoxide levels greater than 10 percent are not 

byproduct/waste for the purpose of this subpart. 

Chemical manufacturing plants mean industrial plants that are classified by the Department of 

Commerce under Standard Industrial Classification (SIC) Code 28. 

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), coal 

refuse, and petroleum coke. Coal-derived synthetic fuels, including but not limited to solvent refined 

coal, gasified coal not meeting the definition of natural gas, coal-oil mixtures, coke oven gas, and coalwater mixtures, are also included in this definition for the purposes of this subpart. 

Comment [CF2]: Exempt owner/operators of

CISWI facilities from subpart Db

Comment [CF3]: Exempting black liquor

recovery boilers from the PM limit. The recent

round of amendments brought them under the PM

limit since they have an ESP to control PM and burn

low sulfur oil. The subpart BB limit is similar to the

pre 2005 standard.

Comment [CF4]: Exempt temporary boilers

burning fuels with low emissions.
3

Coal refuse means any byproduct of coal mining or coal cleaning operations with an ash content greater 

than 50 percent, by weight, and a heating value less than 13,900 kJ/kg (6,000 Btu/lb) on a dry basis. 

Cogeneration , also known as combined heat and power, means a facility that simultaneously produces 

both electric (or mechanical) and useful thermal energy from the same primary energy source. 

Coke oven gas means the volatile constituents generated in the gaseous exhaust during the carbonization 

of bituminous coal to form coke. 

Combined cycle system means a system in which a separate source, such as a gas turbine, internal 

combustion engine, kiln, etc., provides exhaust gas to a steam generating unit. 

Conventional technology means wet flue gas desulfurization (FGD) technology, dry FGD technology, 

atmospheric fluidized bed combustion technology, and oil hydrodesulfurization technology. 

Distillate oil means fuel oils that contain 0.05 weight percent nitrogen or less and comply with the 

specifications for fuel oil numbers 1 and 2, as defined by the American Society of Testing and Materials 

in ASTM D396 (incorporated by reference, see §60.17) or), diesel fuel oil numbers 1 and 2, as defined 

by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see 

§60.17).), kerosine, as defined by the American Society of Testing and Materials in ASTM D3699 

(incorporated by reference, see §60.17), biodiesel as defined by the American Society of Testing and 

Materials in ASTM D6751 (incorporated by reference, see §60.17), or biodiesel blends as defined by the 

American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see §60.17).

Dry flue gas desulfurization technology means a SO2control system that is located downstream of the 

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

by contacting the combustion gases with an alkaline 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 flue gas desulfurization technology include but are not limited to lime and sodium. 

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 steam generating unit. 

Emerging technology means any SO2control system that is not defined as a conventional technology 

under this section, and for which the owner or operator of the facility has applied to the Administrator 

and received approval to operate as an emerging technology under §60.49b(a)(4). 

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. 

Fluidized bed combustion technology means combustion of fuel in a bed or series of beds (including but 

not limited to bubbling bed units and circulating bed units) of limestone aggregate (or other sorbent 

materials) in which these materials are forced upward by the flow of combustion air and the gaseous 

products of combustion. 

Fuel pretreatment means a process that removes a portion of the sulfur in a fuel before combustion of 

the fuel in a steam generating unit. 

Full capacity means operation of the steam generating unit at 90 percent or more of the maximum 

steady-state design heat input capacity. 

Comment [CF5]: Expand definitions to include

other similar fuels.  Need to amend 60.17 as well.
4

Gaseous fuel means any fuel that is a gas at ISO conditions. This includes, but is not limited to, natural 

gas and gasified coal (including coke oven gas). 

Gross output means the gross useful work performed by the steam generated. For units generating only 

electricity, the gross useful work performed is the gross electrical output from the turbine/generator set. 

For cogeneration units, 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). 

Heat input means heat derived from combustion of fuel in a steam generating unit and does not include 

the heat derived from preheated combustion air, recirculated flue gases, or exhaust gases from other 

sources, such as gas turbines, internal combustion engines, kilns, etc. 

Heat release rate means the steam generating unit design heat input capacity (in MW or Btu/hr) divided 

by the furnace volume (in cubic meters or cubic feet); the furnace volume is that volume bounded by the 

front furnace wall where the burner is located, the furnace side waterwall, and extending to the level just 

below or in front of the first row of convection pass tubes. 

Heat transfer medium means any material that is used to transfer heat from one point to another point. 

High heat release rate means a heat release rate greater than 730,000 J/sec-m3

 (70,000 Btu/hr-ft3 ). 

ISO Conditions means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a pressure of 

101.3 kilopascals. 

Lignite means a type of coal classified as lignite A or lignite B by the American Society of Testing and 

Materials in ASTM D388 (incorporated by reference, see §60.17). 

Low heat release rate means a heat release rate of 730,000 J/sec-m3

 (70,000 Btu/hr-ft3 ) or less. 

Mass-feed stoker steam generating unit means a steam generating unit where solid fuel is introduced 

directly into a retort or is fed directly onto a grate where it is combusted. 

Maximum heat input capacity means the ability of a steam generating unit to combust a stated maximum 

amount of fuel on a steady state basis, as determined by the physical design and characteristics of the 

steam generating unit. 

Municipal-type solid waste means refuse, more than 50 percent of which is waste consisting of a mixture 

of paper, wood, yard wastes, food wastes, plastics, leather, rubber, and other combustible materials, and 

noncombustible materials such as glass and rock. 

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) Liquefied petroleum gas, as defined by the American Society for 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). 
5

Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the 

Commonwealth of Puerto Rico, or the Northern Mariana Islands. 

Oil means crude oil or petroleum or a liquid fuel derived from crude oil or petroleum, including distillate 

and residual oil. 

Petroleum refinery means industrial plants as classified by the Department of Commerce under Standard 

Industrial Classification (SIC) Code 29. 

Potential sulfur dioxide emission rate means the theoretical SO2emissions (nanograms per joule (ng/J) 

or lb/MMBtu heat input) that would result from combusting fuel in an uncleaned state and without using 

emission control systems. For gasified coal or oil that is desulfurized prior to combustion, the Potential 

sulfur dioxide emission rate is the theoretical SO2emissions (ng/J or lb/MMBtu heat input) that would 

result from combusting fuel in a cleaned state without using any post combustion emission control 

systems. 

Process heater means a device that is primarily used to heat a material to initiate or promote a chemical 

reaction in which the material participates as a reactant or catalyst. 

Pulp and paper mills means industrial plants that are classified by the Department of Commerce under 

North American Industry Classification System (NAICS) Code 322 or Standard Industrial Classification 

(SIC) Code 26. 

Pulverized coal-fired steam generating unit means a steam generating unit in which pulverized coal is 

introduced into an air stream that carries the coal to the combustion chamber of the steam generating 

unit where it is fired in suspension. This includes both conventional pulverized coal-fired and 

micropulverized coal-fired steam generating units. 

Residual oil means crude oil, fuel oil numbers 1 and 2 that have a nitrogen content greater than 0.05 

weight percent, and all fuel oil numbers 4, 5 and 6, as defined by the American Society of Testing and 

Materials in ASTM D396 (incorporated by reference, see §60.17). 

Spreader stoker steam generating unit means a steam generating unit in which solid fuel is introduced to 

the combustion zone by a mechanism that throws the fuel onto a grate from above. Combustion takes 

place both in suspension and on the grate. 

Steam generating unit means a device that combusts any fuel or byproduct/waste and produces steam or 

heats water or heats any heat transfer medium. This term includes any municipal-type solid waste 

incinerator with a heat recovery steam generating unit or any steam generating unit that combusts fuel 

and is part of a cogeneration system or a combined cycle system. This term does not include process 

heaters as they are defined in this subpart. 

Steam generating unit operating day means a 24-hour period between 12:00 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 continuously for the entire 24-hour period. 

Temporary boiler means a steam generating unit that combusts natural gas and/or distillate oil with a 

potential SO2 emissions rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit is designed to, and 

is capable of, being carried or moved from one location to another by means of, for example, wheels, 

skids, carrying handles, dollies, trailers, or platforms. A steam generating unit is not a temporary boiler 

if any one of the following conditions exists:

(1) The equipment is attached to a foundation.

Comment [CF6]: Need definition for new

exemption.
6

(2) The steam generating unit or a replacement remains at a location for more than 180 consecutive 

days. Any temporary boiler that replaces a temporary boiler at a location and performs the same or 

similar function will be included in calculating the consecutive time period.

(3) The equipment is located at a seasonal facility and operates during the full annual operating period of 

the seasonal facility, remains at the facility for at least 2 years, and operates at that facility for at least 3 

months each year.

(4) The equipment is moved from one location to another in an attempt to circumvent the residence time 

requirements of this definition. 

Very low sulfur oil means for units constructed, reconstructed, or modified on or before February 28, 

2005, oil that contains no more than 0.5 weight percent sulfur or that, when combusted without 

SO2emission control, has a SO2emission rate equal to or less than 215 ng/J (0.5 lb/MMBtu) heat input. 

For units constructed, reconstructed, or modified after February 28, 2005 and not located in a 

noncontinental area, very low sulfur oil means oil that contains no more than 0.30 weight percent sulfur 

or that, when combusted without SO2emission control, has a SO2emission rate equal to or less than 140 

ng/J (0.32 lb/MMBtu) heat input. For units constructed, reconstructed, or modified after February 28, 

2005 and located in a noncontinental area, very low sulfur oil means oil that contains no more than 0.5 

weight percent sulfur or that, when combusted without SO2emission control, has a SO2emission rate 

equal to or less than 215 ng/J (0.50 lb/MMBtu) heat input. 

Wet flue gas desulfurization technology means a SO2control system that is located downstream of the 

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

by contacting the combustion gas 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 flue gas desulfurization technology include, but 

are not limited to, lime, limestone, and sodium. 

Wet scrubber system means any emission control device that mixes an aqueous stream or slurry with the 

exhaust gases from a steam generating unit to control emissions of PM or SO2. 

Wood means wood, wood residue, bark, or any derivative fuel or residue thereof, in any form, including, 

but not limited to, sawdust, sanderdust, wood chips, scraps, slabs, millings, shavings, and processed 

pellets made from wood or other forest residues. 

§60.42b Standard for sulfur dioxide (SO2). 

(a) Except as provided in paragraphs (b), (c), (d), or (j) of this section, on and after the date on which the 

performance test is completed or required to be completed under §60.8, whichever comes first, no owner 

or operator of an affected facility that commenced construction, reconstruction, or modification on or 

before February 28, 2005, that combusts coal or oil shall cause to be discharged into the atmosphere any 

gases that contain SO2in excess of 87 ng/J (0.20 lb/MMBtu) or 10 percent (0.10) of the potential 

SO2emission rate (90 percent reduction) and the emission limit determined according to the following 

formula: 

Where: 

Es= SO2emission limit, in ng/J or lb/MMBtu heat input; 
7

Ka= 520 ng/J (or 1.2 lb/MMBtu); 

Kb= 340 ng/J (or 0.80 lb/MMBtu); 

Ha= Heat input from the combustion of coal, in J (MMBtu); and 

Hb= Heat input from the combustion of oil, in J (MMBtu). 

For facilities complying with the percent reduction standard, only the heat input supplied to the affected 

facility from the combustion of coal and oil is counted in this paragraph. No credit is provided for the 

heat input to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, 

or other fuels or heat derived from exhaust gases from other sources, such as gas turbines, internal 

combustion engines, kilns, etc. 

(b) On and after the date on which the 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 on or before February 28, 2005, that combusts coal refuse 

alone in a fluidized bed combustion steam generating unit shall cause to be discharged into the 

atmosphere any gases that contain SO2in excess of 87 ng/J (0.20 lb/MMBtu) or 20 percent (0.20) of the 

potential SO2emission rate (80 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. If coal or oil 

is fired with coal refuse, the affected facility is subject to paragraph (a) or (d) of this section, as 

applicable. For facilities complying with the percent reduction standard, only the heat input supplied to 

the affected facility from the combustion of coal and oil is counted in this paragraph. No credit is 

provided for the heat input to the affected facility from the combustion of natural gas, wood, municipaltype solid waste, or other fuels or heat derived from exhaust gases from other sources, such as gas 

turbines, internal combustion engines, kilns, etc. 

(c) On and after the date on which the performance test is completed or is required to be completed 

under §60.8, whichever comes first, no owner or operator of an affected facility that combusts coal or 

oil, either alone or in combination with any other fuel, and that uses an emerging technology for the 

control of SO2emissions, shall cause to be discharged into the atmosphere any gases that contain SO2in 

excess of 50 percent of the potential SO2emission rate (50 percent reduction) and that contain SO2in 

excess of the emission limit determined according to the following formula: 

Where: 

Es= SO2 emission limit, in ng/J or lb/MM Btu heat input; 

Kc= 260 ng/J (or 0.60 lb/MMBtu); 

Kd= 170 ng/J (or 0.40 lb/MMBtu); 

Hc= Heat input from the combustion of coal, in J (MMBtu); and 

Hd= Heat input from the combustion of oil, in J (MMBtu). 

For facilities complying with the percent reduction standard, only the heat input supplied to the affected 

facility from the combustion of coal and oil is counted in this paragraph. No credit is provided for the 

heat input to the affected facility from the combustion of natural gas, wood, municipal-type solid waste, 

or other fuels, or from the heat input derived from exhaust gases from other sources, such as gas 

turbines, internal combustion engines, kilns, etc. 
8

(d) On and after the date on which the performance test is completed or required to be completed under 

§60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, 

reconstruction, or modification on or before February 28, 2005 and listed in paragraphs (d)(1), (2), (3), 

or (4) of this section shall cause to be discharged into the atmosphere any gases that contain SO2in 

excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected facility combusts coal, or 215 ng/J (0.5 

lb/MMBtu) heat input if the affected facility combusts oil other than very low sulfur oil. Percent 

reduction requirements are not applicable to affected facilities under paragraphs (d)(1), (2), (3) or (4) of 

this section. For facilities complying with paragraphs (d)(1), (2), or (3) of this section, only the heat 

input supplied to the affected facility from the combustion of coal and oil is counted in this paragraph. 

No credit is provided for the heat input to the affected facility from the combustion of natural gas, wood, 

municipal-type solid waste, or other fuels or heat derived from exhaust gases from other sources, such as 

gas turbines, internal combustion engines, kilns, etc. 

(1) Affected facilities that have an annual capacity factor for coal and oil of 30 percent (0.30) or less and 

are subject to a federally enforceable permit limiting the operation of the affected facility to an annual 

capacity factor for coal and oil of 30 percent (0.30) or less; 

(2) Affected facilities located in a noncontinental area; or 

(3) Affected facilities combusting coal or oil, alone or in combination with any fuel, in a duct burner as 

part of a combined cycle system where 30 percent (0.30) or less of the heat entering the steam 

generating unit is from combustion of coal and oil in the duct burner and 70 percent (0.70) or more of 

the heat entering the steam generating unit is from the exhaust gases entering the duct burner; or 

(4) The affected facility burns coke oven gas alone or in combination with natural gas or very low sulfur 

distillate oil. 

(e) Except as provided in paragraph (f) of this section, compliance with the emission limits, fuel oil 

sulfur limits, and/or percent reduction requirements under this section are determined on a 30-day 

rolling average basis. 

(f) Except as provided in paragraph (j)(2) of this section, compliance with the emission limits or fuel oil 

sulfur limits under this section is determined on a 24-hour average basis for affected facilities that (1) 

have a federally enforceable permit limiting the annual capacity factor for oil to 10 percent or less, (2) 

combust only very low sulfur oil, and (3) do not combust any other fuel. 

(g) Except as provided in paragraph (i) of this section and §60.45b(a), the SO2emission limits and 

percent reduction requirements under this section apply at all times, including periods of startup, 

shutdown, and malfunction. 

(h) Reductions in the potential SO2emission rate through fuel pretreatment are not credited toward the 

percent reduction requirement under paragraph (c) of this section unless:

(1) Fuel pretreatment results in a 50 percent or greater reduction in potential SO2emissions and

(2) Emissions from the pretreated fuel (without combustion or post-combustion SO2control) are equal to 

or less than the emission limits specified in paragraph (c) of this section.

(h) [RESERVED]

(i) An affected facility subject to paragraph (a), (b), or (c) of this section may combust very low sulfur 

oil or natural gas when the SO2control system is not being operated because of malfunction or 

maintenance of the SO2control system. 

Comment [CF7]: Remove restriction on fuel

pretreatement
9

(j) Percent reduction requirements are not applicable to affected facilities combusting only very low 

sulfur oil. The owner or operator of an affected facility combusting very low sulfur oil shall demonstrate 

that the oil meets the definition of very low sulfur oil by: (1) Following the performance testing 

procedures as described in §60.45b(c) or §60.45b(d), and following the monitoring procedures as 

described in §60.47b(a) or §60.47b(b) to determine SO2emission rate or fuel oil sulfur content; or (2) 

maintaining fuel records as described in §60.49b(r). 

(k)(1) Except as provided in paragraphs (k)(2), (k)(3), and (k)(4) of this section, on and after the date on 

which the initial performance test is completed or is required to be completed under §60.8, whichever 

date comes first, no owner or operator of an affected facility that commences construction, 

reconstruction, or modification after February 28, 2005, and that combusts coal, oil, natural gas, a 

mixture of these fuels, or a mixture of these fuels with any other fuels shall cause to be discharged into 

the atmosphere any gases that contain SO2in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 8 percent 

(0.08) of the potential SO2emission rate (92 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. 

For facilities complying with the percent reduction standard and paragraph (k)(3) of this section, only 

the heat input supplied to the affected facility from the combustion of coal and oil is counted in 

paragraph (k) of this section. No credit is provided for the heat input to the affected facility from the 

combustion of natural gas, wood, municipal-type solid waste, or other fuels or heat derived from exhaust 

gases from other sources, such as gas turbines, internal combustion engines, kilns, etc. 

(2) Units firing only very low sulfur oil, gaseous fuel, a mixture of these fuels, or a mixture of these 

fuels with any other fuels with a potential SO2emission rate of 140 ng/J (0.32 lb/MMBtu) heat input or 

less are exempt from the SO2emissions limit in paragraph (k)(1) of this section. 

(3) Units that are located in a noncontinental area and that combust coal, oil, or natural gas shall not 

discharge any gases that contain SO2in excess of 520 ng/J (1.2 lb/MMBtu) heat input if the affected 

facility combusts coal, or 215 ng/J (0.50 lb/MMBtu) heat input if the affected facility combusts oil or 

natural gas. 

(4) As an alternative to meeting the requirements under paragraph (k)(1) of this section, modified 

facilities that combust coal or a mixture of coal with other fuels shall not cause to be discharged into the 

atmosphere any gases that contain SO2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent 

(0.10) of the potential SO2 emission rate (90 percent reduction) and 520 ng/J (1.2 lb/MMBtu) heat input. 

§60.43b Standard for particulate matter (PM). 

(a) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever comes first, no owner or operator of an affected facility that 

commenced construction, reconstruction, or modification on or before February 28, 2005 that combusts 

coal or combusts mixtures of coal with other fuels, shall cause to be discharged into the atmosphere 

from that affected facility any gases that contain PM in excess of the following emission limits: 

(1) 22 ng/J (0.051 lb/MMBtu) heat input, (i) If the affected facility combusts only coal, or 

(ii) If the affected facility combusts coal and other fuels and has an annual capacity factor for the other 

fuels of 10 percent (0.10) or less. 

(2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility combusts coal and other fuels and has an 

annual capacity factor for the other fuels greater than 10 percent (0.10) and is subject to a federally 

enforceable requirement limiting operation of the affected facility to an annual capacity factor greater 

than 10 percent (0.10) for fuels other than coal. 

(3) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts coal or coal and other fuels and 
10

(i) Has an annual capacity factor for coal or coal and other fuels of 30 percent (0.30) or less, 

(ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less, 

(iii) Has a federally enforceable requirement limiting operation of the affected facility to an annual 

capacity factor of 30 percent (0.30) or less for coal or coal and other solid fuels, and 

(iv) Construction of the affected facility commenced after June 19, 1984, and before November 25, 

1986. 

(4) An affected facility burning coke oven gas alone or in combination with other fuels not subject to a 

PM standard under §60.43b and not using a post-combustion technology (except a wet scrubber) for 

reducing PM or SO2emissions is not subject to the PM limits under §60.43b(a). 

(b) On and after the date on which the performance test is completed or required to be completed under 

§60.8, whichever comes first, no owner or operator of an affected facility that commenced construction, 

reconstruction, or modification on or before February 28, 2005, and that combusts oil (or mixtures of oil 

with other fuels) and uses a conventional or emerging technology to reduce SO2emissions shall cause to 

be discharged into the atmosphere from that affected facility any gases that contain PM in excess of 43 

ng/J (0.10 lb/MMBtu) heat input. 

(c) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever comes first, no owner or operator of an affected facility that 

commenced construction, reconstruction, or modification on or before February 28, 2005, and that 

combusts wood, or wood with other fuels, except coal, shall cause to be discharged from that affected 

facility any gases that contain PM in excess of the following emission limits: 

(1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has an annual capacity factor greater than 

30 percent (0.30) for wood. 

(2) 86 ng/J (0.20 lb/MMBtu) heat input if (i) The affected facility has an annual capacity factor of 30 

percent (0.30) or less for wood; 

(ii) Is subject to a federally enforceable requirement limiting operation of the affected facility to an 

annual capacity factor of 30 percent (0.30) or less for wood; and 

(iii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less. 

(d) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility that 

combusts municipal-type solid waste or mixtures of municipal-type solid waste with other fuels, shall 

cause to be discharged into the atmosphere from that affected facility any gases that contain PM in 

excess of the following emission limits: 

(1) 43 ng/J (0.10 lb/MMBtu) heat input; 

(i) If the affected facility combusts only municipal-type solid waste; or 

(ii) If the affected facility combusts municipal-type solid waste and other fuels and has an annual 

capacity factor for the other fuels of 10 percent (0.10) or less. 

(2) 86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts municipal-type solid waste or 

municipal-type solid waste and other fuels; and 

(i) Has an annual capacity factor for municipal-type solid waste and other fuels of 30 percent (0.30) or 

less; 
11

(ii) Has a maximum heat input capacity of 73 MW (250 MMBtu/hr) or less; 

(iii) Has a federally enforceable requirement limiting operation of the affected facility to an annual 

capacity factor of 30 percent (0.30) or less for municipal-type solid waste, or municipal-type solid waste 

and other fuels; and 

(iv) Construction of the affected facility commenced after June 19, 1984, but on or before November 25, 

1986. 

(e) For the purposes of this section, the annual capacity factor is determined by dividing the actual heat 

input to the steam generating unit during the calendar year from the combustion of coal, wood, or 

municipal-type solid waste, and other fuels, as applicable, by the potential heat input to the steam 

generating unit if the steam generating unit had been operated for 8,760 hours at the maximum heat 

input capacity. 

(f) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility that can 

combustcombusts coal, oil, wood, or mixtures of these fuels with any other fuels shall cause to be 

discharged into the atmosphere any gases that 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 

operatorsAn 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 and are subjectis subject to a federally enforceable PM limit of 0.030 

lb/MMBtu or less areis exempt from the opacity standard specified in this paragraph. 

(g) The PM and opacity standards apply at all times, except during periods of startup, shutdown, or 

malfunction. 

(h)(1) Except as provided in paragraphs (h)(2), (h)(3), (h)(4), (h)(5), and (h)(6) of this section, on and 

after the date on which the initial performance test is completed or is 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, and that combusts coal, oil, wood, 

a mixture of these fuels, or a mixture of these fuels with any other fuels shall cause to be discharged into 

the atmosphere from that affected facility any gases that contain PM in excess of 13 ng/J (0.030 

lb/MMBtu) heat input, 

(2) As an alternative to meeting the requirements of paragraph (h)(1) of this section, the owner or 

operator of an affected facility for which modification commenced after February 28, 2005, 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, no owner or operator of an affected facility that 

commences modification after February 28, 2005 shall cause to be discharged into the atmosphere from 

that affected facility any gases that contain PM in excess of both: 

(i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion of coal, oil, wood, a mixture of 

these fuels, or a mixture of these fuels with any other fuels; and 

(ii) 0.2 percent of the combustion concentration (99.8 percent reduction) when combusting coal, oil, 

wood, a mixture of these fuels, or a mixture of these fuels with any other fuels. 

(3) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility that 

commences modification after February 28, 2005, and that combusts over 30 percent wood (by heat 

input) on an annual basis and has a maximum heat input capacity of 73 MW (250 MMBtu/h) or less 

Comment [CF8]: Clarify opacity does not apply

when burning natural gas
12

shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in 

excess of 43 ng/J (0.10 lb/MMBtu) heat input. 

(4) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility that 

commences modification after February 28, 2005, and that combusts over 30 percent wood (by heat 

input) on an annual basis and has a maximum heat input capacity greater than 73 MW (250 MMBtu/h) 

shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in 

excess of 37 ng/J (0.085 lb/MMBtu) heat input. 

(5) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, an owner or operator of an affected facility not 

located in a noncontinental area that commences construction, reconstruction, or modification after 

February 28, 2005, and that combusts only oil that contains no more than 0.30 weight percent sulfur, 

coke oven gas, a mixture of these fuels, or either fuel (or a mixture of these fuels) in combination with 

other fuels not subject to a PM standard in §60.43b and not using a post-combustion technology (except 

a wet scrubber) to reduce SO2or PM emissions is not subject to the PM limits in (h)(1) of this section. 

(6) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, an owner or operator of an affected facility located 

in a noncontinental area that commences construction, reconstruction, or modification after February 28, 

2005, and that combusts only oil that contains no more than 0.5 weight percent sulfur, coke oven gas, a 

mixture of these fuels, or either fuel (or a mixture of these fuels) in combination with other fuels not 

subject to a PM standard in §60.43b and not using a post-combustion technology (except a wet scrubber) 

to reduce SO2or PM emissions is not subject to the PM limits in (h)(1) of this section. 

§60.44b Standard for nitrogen oxides (NOX). 

(a) Except as provided under paragraphs (k) and (l) of this section, on and after the date on which the 

initial performance test is completed or is required to be completed under §60.8, whichever date comes 

first, no owner or operator of an affected facility that is subject to the provisions of this section and that 

combusts only coal, oil, or natural gas shall cause to be discharged into the atmosphere from that 

affected facility any gases that contain NOX(expressed as NO2) in excess of the following emission 

limits: 

Fuel/steam generating unit type 

Nitrogen oxide emission limits 

(expressed as NO2) heat input 

ng/J lb/MMBTuMMB

tu

(1) Natural gas and distillate oil, except (4): 

(i) Low heat release rate 43 0.10 

(ii) High heat release rate 86 0.20 

(2) Residual oil: 

(i) Low heat release rate 130 0.30 

(ii) High heat release rate 170 0.40 
13

(3) Coal: 

(i) Mass-feed stoker 210 0.50 

(ii) Spreader stoker and fluidized bed combustion 260 0.60 

(iii) Pulverized coal 300 0.70 

(iv) Lignite, except (v) 260 0.60 

(v) Lignite mined in North Dakota, South Dakota, or 

Montana and combusted in a slag tap furnace 340 0.80 

(vi) Coal-derived synthetic fuels 210 0.50 

(4) Duct burner used in a combined cycle system: 

(i) Natural gas and distillate oil 86 0.20 

(ii) Residual oil 170 0.40 

(b) Except as provided under paragraphs (k) and (l) of this section, on and after the date on which the 

initial performance test is completed or is required to be completed under §60.8, whichever date comes 

first, no owner or operator of an affected facility that simultaneously combusts mixtures of only coal, 

oil, or natural gas shall cause to be discharged into the atmosphere from that affected facility any gases 

that contain NOX in excess of a limit determined by the use of the following formula: 

Where: 

En= NOXemission limit (expressed as NO2), ng/J (lb/MMBtu); 

ELgo= Appropriate emission limit from paragraph (a)(1) for combustion of natural gas or distillate oil, 

ng/J (lb/MMBtu); 

Hgo= Heat input from combustion of natural gas or distillate oil, J (MMBtu); 

ELro= Appropriate emission limit from paragraph (a)(2) for combustion of residual oil, ng/J 

(lb/MMBtu); 

Hro= Heat input from combustion of residual oil, J (MMBtu); 

ELc= Appropriate emission limit from paragraph (a)(3) for combustion of coal, ng/J (lb/MMBtu); and 

Hc= Heat input from combustion of coal, J (MMBtu). 

(c) Except as provided under paragraph (d) and (l) of this section, on and after the date on which the 

initial performance test is completed or is required to be completed under §60.8, whichever date comes 

first, no owner or operator of an affected facility that simultaneously combusts coal or, oil, or a mixture 

of these fuels with natural gas, (or any combination of the three),, and wood, municipal-type solid waste, 

or any other fuel shall cause to be discharged into the atmosphere any gases that contain NOXinNOX in

excess of the emission limit for the coal or, oil, or mixtures of these fuels with natural gas (or any 

combination of the three), combusted in the affected facility, as determined pursuant to paragraph (a) or 

Comment [CF9]: Clarify applicability
14

(b) of this section, unless the . This standard does not apply to an affected facility has an annual capacity 

factor for coal or oil, or mixture of these fuels with natural gas of 10 percent (0.10) or less andthat is 

subject to and in compliance with a federally enforceable requirement that limits operation of the 

affected facility to an annual capacity factor of 10 percent (0.10) or less for coal, oil, or a mixture of 

these fuels with natural gas. (or any combination of the three).

(d) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility that 

simultaneously combusts natural gas and/or distillate oil with a potential SO2 emissions rate of 26 ng/J 

(0.060 lb/MMBtu) or less with wood, municipal-type solid waste, or other solid fuel, except coal, shall 

cause to be discharged into the atmosphere from that affected facility any gases that contain NOXinNOX

in excess of 130 ng/J (0.30 lb/MMBtu) heat input unless the affected facility has an annual capacity 

factor for natural gas, distillate oil, or a mixture of these fuels of 10 percent (0.10) or less and is subject 

to a federally enforceable requirement that limits operation of the affected facility to an annual capacity 

factor of 10 percent (0.10) or less for natural gas, distillate oil, or a mixture of these fuels. 

(e) Except as provided under paragraph (l) of this section, on and after the date on which the initial 

performance test is completed or is required to be completed under §60.8, whichever date comes first, 

no owner or operator of an affected facility that simultaneously combusts only coal, oil, or natural gas 

with byproduct/waste shall cause to be discharged into the atmosphere any gases that contain 

NOXinNOX in excess of the emission limit determined by the following formula unless the affected 

facility has an annual capacity factor for coal, oil, and natural gas of 10 percent (0.10) or less and is 

subject to a federally enforceable requirement that limits operation of the affected facility to an annual 

capacity factor of 10 percent (0.10) or less: 

Where: 

En= NOXemission limit (expressed as NO2), ng/J (lb/MMBtu); 

ELgo= Appropriate emission limit from paragraph (a)(1) for combustion of natural gas or distillate oil, 

ng/J (lb/MMBtu); 

Hgo= Heat input from combustion of natural gas, distillate oil and gaseous byproduct/waste, J (MMBtu); 

ELro= Appropriate emission limit from paragraph (a)(2) for combustion of residual oil and/or 

byproduct/waste, ng/J (lb/MMBtu); 

Hro= Heat input from combustion of residual oil, J (MMBtu); 

ELc= Appropriate emission limit from paragraph (a)(3) for combustion of coal, ng/J (lb/MMBtu); and 

Hc= Heat input from combustion of coal, J (MMBtu). 

(f) Any owner or operator of an affected facility that combusts byproduct/waste with either natural gas 

or oil may petition the Administrator within 180 days of the initial startup of the affected facility to 

establish a NOXemission limit that shall apply specifically to that affected facility when the 

byproduct/waste is combusted. The petition shall include sufficient and appropriate data, as determined 

by the Administrator, such as NOXemissions from the affected facility, waste composition (including 

nitrogen content), and combustion conditions to allow the Administrator to confirm that the affected 

Comment [CF10]: Clarification of the

requirements.

Comment [CF11]: Add low sulfur distillate as

alternative to NG to increase flexibility for

owners/operators of wood‐fired boilers.  Low sulfur

distillate combusts clean enough to qualify for low

capacity factor exemption.

Comment [CF12]: Clarify applicability
15

facility is unable to comply with the emission limits in paragraph (e) of this section and to determine the 

appropriate emission limit for the affected facility. 

(1) Any owner or operator of an affected facility petitioning for a facility-specific NOXemission limit 

under this section shall: 

(i) Demonstrate compliance with the emission limits for natural gas and distillate oil in paragraph (a)(1) 

of this section or for residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, by 

conducting a 30-day performance test as provided in §60.46b(e). During the performance test only 

natural gas, distillate oil, or residual oil shall be combusted in the affected facility; and 

(ii) Demonstrate that the affected facility is unable to comply with the emission limits for natural gas 

and distillate oil in paragraph (a)(1) of this section or for residual oil in paragraph (a)(2) or (l)(1) of this 

section, as appropriate, when gaseous or liquid byproduct/waste is combusted in the affected facility 

under the same conditions and using the same technological system of emission reduction applied when 

demonstrating compliance under paragraph (f)(1)(i) of this section. 

(2) The NOXemission limits for natural gas or distillate oil in paragraph (a)(1) of this section or for 

residual oil in paragraph (a)(2) or (l)(1) of this section, as appropriate, shall be applicable to the affected 

facility until and unless the petition is approved by the Administrator. If the petition is approved by the 

Administrator, a facility-specific NOXemission limit will be established at the NOXemission level 

achievable when the affected facility is combusting oil or natural gas and byproduct/waste in a manner 

that the Administrator determines to be consistent with minimizing NOXemissions. In lieu of amending 

this subpart, a letter will be sent to the facility describing the facility-specific NOXlimit. The facility 

shall use the compliance procedures detailed in the letter and make the letter available to the public. If 

the Administrator determines it is appropriate, the conditions and requirements of the letter can be 

reviewed and changed at any point. 

(g) Any owner or operator of an affected facility that combusts hazardous waste (as defined by 40 CFR 

part 261 or 40 CFR part 761) with natural gas or oil may petition the Administrator within 180 days of 

the initial startup of the affected facility for a waiver from compliance with the NOXemission limit that 

applies specifically to that affected facility. The petition must include sufficient and appropriate data, as 

determined by the Administrator, on NOXemissions from the affected facility, waste destruction 

efficiencies, waste composition (including nitrogen content), the quantity of specific wastes to be 

combusted and combustion conditions to allow the Administrator to determine if the affected facility is 

able to comply with the NOXemission limits required by this section. The owner or operator of the 

affected facility shall demonstrate that when hazardous waste is combusted in the affected facility, 

thermal destruction efficiency requirements for hazardous waste specified in an applicable federally 

enforceable requirement preclude compliance with the NOXemission limits of this section. The 

NOXemission limits for natural gas or distillate oil in paragraph (a)(1) of this section or for residual oil 

in paragraph (a)(2) or (l)(1) of this section, as appropriate, are applicable to the affected facility until and 

unless the petition is approved by the Administrator. (See 40 CFR 761.70 for regulations applicable to 

the incineration of materials containing polychlorinated biphenyls (PCB's).) In lieu of amending this 

subpart, a letter will be sent to the facility describing the facility-specific NOXlimit. The facility shall use 

the compliance procedures detailed in the letter and make the letter available to the public. If the 

Administrator determines it is appropriate, the conditions and requirements of the letter can be reviewed 

and changed at any point. 

(h) For purposes of paragraph (i) of this section, the NOXstandards under this section apply at all times 

including periods of startup, shutdown, or malfunction. 
16

(i) Except as provided under paragraph (j) of this section, compliance with the emission limits under this 

section is determined on a 30-day rolling average basis. 

(j) Compliance with the emission limits under this section is determined on a 24-hour average basis for 

the initial performance test and on a 3-hour average basis for subsequent performance tests for any 

affected facilities that: 

(1) Combust, alone or in combination, only natural gas, distillate oil, or residual oil with a nitrogen 

content of 0.30 weight percent or less; 

(2) Have a combined annual capacity factor of 10 percent or less for natural gas, distillate oil, and 

residual oil with a nitrogen content of 0.30 weight percent or less; and 

(3) Are subject to a federally enforceable requirement limiting operation of the affected facility to the 

firing of natural gas, distillate oil, and/or residual oil with a nitrogen content of 0.30 weight percent or 

less and limiting operation of the affected facility to a combined annual capacity factor of 10 percent or 

less for natural gas, distillate oil, and residual oil with a nitrogen content of 0.30 weight percent or less. 

(k) Affected facilities that meet the criteria described in paragraphs (j)(1), (2), and (3) of this section, 

and that have a heat input capacity of 73 MW (250 MMBtu/hr) or less, are not subject to the 

NOXemission limits under this section. 

(l) On and after the date on which the initial performance test is completed or is required to be 

completed under §60.8, whichever date comes first, no owner or operator of an affected facility that 

commenced construction or reconstruction after July 9, 1997 shall cause to be discharged into the 

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

following limits: 

(1) If86 ng/J (0.20 lb/MMBtu) heat input if the affected facility combusts coal, oil, or natural gas, a 

mixture (or any combination of these fuels, or a mixture of these fuelsthe three), alone or with any other 

fuels: A limit of 86 ng/J (0.20 lb/MMBtu) heat input unless the . The affected facility has an annual 

capacity factor for coal, oil, and natural gas of 10 percent (0.10) or less and is not subject to this limit if 

it is subject to and in compliance with a federally enforceable requirement that limits operation of the 

facility to an annual capacity factor of 10 percent (0.10) or less for coal, oil, and natural gas; (or any 

combination of the three); or 

(2) If the affected facility has a low heat release rate and combusts natural gas or distillate oil in excess 

of 30 percent of the heat input on a 30-day rolling average from the combustion of all fuels, a limit 

determined by use of the following formula: 

Where: 

En= NOXemission limit, (lb/MMBtu); 

Hgo= 30-day heat input from combustion of natural gas or distillate oil; and 

Hr= 30-day heat input from combustion of any other fuel. 

(3) After February 27, 2006, units where more than 10 percent of total annual output is electrical or 

mechanical may comply with an optional limit of 270 ng/J (2.1 lb/MWh) gross energy output, based on 

a 30-day rolling average. Units complying with this output-based limit must demonstrate compliance 

Comment [CF13]: Clarification of rule language
17

according to the procedures of §60.48Da(i) of subpart Da of this part, and must monitor emissions 

according to §60.49Da(c), (k), through (n) of subpart Da of this part. 

§60.45b Compliance and performance test methods and procedures for sulfur dioxide. 

(a) The SO2emission standards in §60.42b apply at all times. Facilities burning coke oven gas alone or in 

combination with any other gaseous fuels or distillate oil are allowed to exceed the limit 30 operating 

days per calendar year for SO2control system maintenance. 

(b) In conducting the performance tests required under §60.8, the owner or operator shall use the 

methods and procedures in appendix A (including fuel certification and sampling) 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. The 30-day notice required in §60.8(d) applies only to the initial performance 

test unless otherwise specified by the Administrator. 

(c) The owner or operator of an affected facility shall conduct performance tests to determine 

compliance with the percent of potential SO2emission rate (% Ps) and the SO2emission rate (Es) pursuant 

to §60.42b following the procedures listed below, except as provided under paragraph (d) and (k) of this 

section. 

(1) The initial performance test shall be conducted over 30 consecutive operating days of the steam 

generating unit. Compliance with the SO2standards shall be determined using a 30-day average. The first 

operating day included in the initial performance test shall be scheduled within 30 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. 

(2) If only coal, only oil, or a mixture of coal and oil is combusted, the following procedures are used: 

(i) The procedures in Method 19 of appendix A–7 of this part are used to determine the hourly 

SO2emission rate (Eho) and the 30-day average emission rate (Eao). The hourly averages used to compute 

the 30-day averages are obtained from the CEMS of §60.47b(a) or (b). 

(ii) The percent of potential SO2emission rate (%Ps) emitted to the atmosphere is computed using the 

following formula: 

Where: 

%Ps= Potential SO2emission rate, percent; 

%Rg= SO2removal efficiency of the control device as determined by Method 19 of appendix A of this 

part, in percent; and 

%Rf= SO2removal efficiency of fuel pretreatment as determined by Method 19 of appendix A of this 

part, in percent. 

(3) If coal or oil is combusted with other fuels, the same procedures required in paragraph (c)(2) of this 

section are used, except as provided in the following: 

(i) An adjusted hourly SO2emission rate (Ehoo

 ) is used in Equation 19–19 of Method 19 of appendix A 

of this part to compute an adjusted 30-day average emission rate (Eaoo

 ). The Eho° is computed using the 

following formula: 
18

Where: 

Ehoo

 = Adjusted hourly SO2emission rate, ng/J (lb/MMBtu); 

Eho= Hourly SO2emission rate, ng/J (lb/MMBtu); 

Ew= SO2concentration in fuels other than coal and oil combusted in the affected facility, as determined 

by the fuel sampling and analysis procedures in Method 19 of appendix A of this part, ng/J (lb/MMBtu). 

The value Ewfor each fuel lot is used for each hourly average during the time that the lot is being 

combusted; and 

Xk= Fraction of total heat input from fuel combustion derived from coal, oil, or coal and oil, as 

determined by applicable procedures in Method 19 of appendix A of this part. 

(ii) To compute the percent of potential SO2emission rate (%Ps), an adjusted %Rg(%Rg

o

 ) is computed 

from the adjusted Eaoo

 from paragraph (b)(3)(i) of this section and an adjusted average SO2inlet rate (Eai

o

) using the following formula: 

To compute Eai

o

 , an adjusted hourly SO2inlet rate (Ehi

o

 ) is used. The Ehi

o

 is computed using the 

following formula: 

Where: 

Ehi

o

 = Adjusted hourly SO2inlet rate, ng/J (lb/MMBtu); and 

Ehi= Hourly SO2inlet rate, ng/J (lb/MMBtu). 

(4) The owner or operator of an affected facility subject to paragraph (c)(3) of this section does not have 

to measure parameters Ewor Xkif the owner or operator elects to assume that Xk= 1.0. Owners or 

operators of affected facilities who assume Xk= 1.0 shall: 

(i) Determine %Psfollowing the procedures in paragraph (c)(2) of this section; and 

(ii) Sulfur dioxide emissions (Es) are considered to be in compliance with SO2emission limits under 

§60.42b. 

(5) The owner or operator of an affected facility that qualifies under the provisions of §60.42b(d) does 

not have to measure parameters Ewor Xkin paragraph (c)(3) of this section if the owner or operator of the 

affected facility elects to measure SO2emission rates of the coal or oil following the fuel sampling and 

analysis procedures in Method 19 of appendix A–7 of this part. 

(d) Except as provided in paragraph (j) of this section, the owner or operator of an affected facility that 

combusts only very low sulfur oil, natural gas, or a mixture of these fuels, has an annual capacity factor 
19

for oil of 10 percent (0.10) or less, and is subject to a federally enforceable requirement limiting 

operation of the affected facility to an annual capacity factor for oil of 10 percent (0.10) or less shall: 

(1) Conduct the initial performance test over 24 consecutive steam generating unit operating hours at 

full load; 

(2) Determine compliance with the standards after the initial performance test based on the arithmetic 

average of the hourly emissions data during each steam generating unit operating day if a CEMS is used, 

or based on a daily average if Method 6B of appendix A of this part or fuel sampling and analysis 

procedures under Method 19 of appendix A of this part are used. 

(e) The owner or operator of an affected facility subject to §60.42b(d)(1) shall demonstrate the 

maximum design capacity of the steam generating unit by operating the facility at maximum capacity 

for 24 hours. This demonstration will be made during the initial performance test and a subsequent 

demonstration may be requested at any other time. If the 24-hour average firing rate for the affected 

facility is less than the maximum design capacity provided by the manufacturer of the affected facility, 

the 24-hour average firing rate shall be used to determine the capacity utilization rate for the affected 

facility, otherwise the maximum design capacity provided by the manufacturer is used. 

(f) For the initial performance test required under §60.8, compliance with the SO2emission limits and 

percent reduction requirements under §60.42b is based on the average emission rates and the average 

percent reduction for SO2for the first 30 consecutive steam generating unit operating days, except as 

provided under paragraph (d) of this section. The initial performance test is the only test for 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 steam generating unit operating day of the 30 

successive steam generating unit operating days is completed within 30 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. The boiler load during the 30-day period does not have to be the maximum 

design load, but must be representative of future operating conditions and include at least one 24-hour 

period at full load. 

(g) After the initial performance test required under §60.8, compliance with the SO2emission limits and 

percent reduction requirements under §60.42b is based on the average emission rates and the average 

percent reduction for SO2for 30 successive steam generating unit operating days, except as provided 

under paragraph (d). A separate performance test is completed at the end of each steam generating unit 

operating day after the initial performance test, and a new 30-day average emission rate and percent 

reduction for SO2are calculated to show compliance with the standard. 

(h) Except as provided under paragraph (i) of this section, the owner or operator of an affected facility 

shall use all valid SO2emissions data in calculating %Psand Ehounder paragraph (c), of this section 

whether or not the minimum emissions data requirements under §60.46b are achieved. All valid 

emissions data, including valid SO2emission data collected during periods of startup, shutdown and 

malfunction, shall be used in calculating %Psand Ehopursuant to paragraph (c) of this section. 

(i) During periods of malfunction or maintenance of the SO2control systems when oil is combusted as 

provided under §60.42b(i), emission data are not used to calculate %Psor Esunder §60.42b(a), (b) or (c), 

however, the emissions data are used to determine compliance with the emission limit under §60.42b(i). 

(j) The owner or operator of an affected facility that only combusts very low sulfur oil, natural gas, or a 

mixture of these fuels with any other fuels not subject to an SO2standard is not subject to the compliance 

and performance testing requirements of this section if the owner or operator obtains fuel receipts as 

described in §60.49b(r). 
20

(k) The owner or operator of an affected facility seeking to demonstrate compliance in §§60.42b(d)(4), 

60.42b(j), 60.42b(k)(2), and 60.42b(k)(3) (when not burning coal) shall follow the applicable procedures 

in §60.49b(r). 

§60.46b Compliance and performance test methods and procedures for particulate matter and 

nitrogen oxides. 

(a) The PM emission standards and opacity limits under §60.43b apply at all times except during periods 

of startup, shutdown, or malfunction. The NOXemission standards under §60.44b apply at all times. 

(b) Compliance with the PM emission standards under §60.43b shall be determined through 

performance testing as described in paragraph (d) of this section, except as provided in paragraph (i) of 

this section. 

(c) Compliance with the NOXemission standards under §60.44b shall be determined through 

performance testing under paragraph (e) or (f), or under paragraphs (g) and (h) of this section, as 

applicable. 

(d) To determine compliance with the PM emission limits and opacity limits under §60.43b, the owner 

or operator of an affected facility shall conduct an initial performance test as required under §60.8, and 

shall conduct subsequent performance tests as requested by the Administrator, using the following 

procedures and reference methods: 

(1) Method 3A or 3B of appendix A–2 of this part is used for gas analysis when applying Method 5 of 

appendix A–3 of this part or Method 17 of appendix A–6 of this part. 

(2) Method 5, 5B, or 17 of appendix A of this part shall be used to measure the concentration of PM as 

follows: 

(i) Method 5 of appendix A of this part shall be used at affected facilities without wet flue gas 

desulfurization (FGD) systems; and 

(ii) Method 17 of appendix A–6 of this part may be used at facilities with or without wet scrubber 

systems provided the stack gas temperature does not exceed a 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 a wet FGD system. Do not use Method 17 of 

appendix A–6 of this part after wet FGD systems if the effluent is saturated or laden with water droplets. 

(iii) Method 5B of appendix A of this part is to be used only after wet FGD systems. 

(3) Method 1 of appendix A of this part is used to select the sampling site and the number of traverse 

sampling points. The sampling time for each run is at least 120 minutes and the minimum sampling 

volume is 1.7 dscm (60 dscf) except that smaller sampling times or volumes may be approved by the 

Administrator when necessitated by process variables or other factors. 

(4) For Method 5 of appendix A of this part, the temperature of the sample gas in the probe and filter 

holder is monitored and is maintained at 160±14 °C (320±25 °F). 

(5) For determination of PM emissions, the oxygen (O2) or CO2sample is obtained simultaneously with 

each run of Method 5, 5B, or 17 of appendix A of this part by traversing the duct at the same sampling 

location. 

(6) For each run using Method 5, 5B, or 17 of appendix A of this part, the emission rate expressed in 

ng/J heat input is determined using: 

(i) The O2or CO2measurements and PM measurements obtained under this section; 
21

(ii) The dry basis F factor; and 

(iii) The dry basis emission rate calculation procedure contained in Method 19 of appendix A of this 

part. 

(7) Method 9 of appendix A of this part is used for determining the opacity of stack emissions. 

(e) To determine compliance with the emission limits for NOXrequired under §60.44b, the owner or 

operator of an affected facility shall conduct the performance test as required under §60.8 using the 

continuous system for monitoring NOXunder §60.48(b). 

(1) For the initial compliance test, NOXfrom the steam generating unit are monitored for 30 successive 

steam generating unit operating days and the 30-day average emission rate is used to determine 

compliance with the NOXemission standards under §60.44b. The 30-day average emission rate is 

calculated as the average of all hourly emissions data recorded by the monitoring system during the 30-

day test period. 

(2) Following the date on which the initial performance test is completed or is required to be completed 

in §60.8, whichever date comes first, the owner or operator of an affected facility which combusts coal 

(except as specified under §60.46b(e)(4)) or which combusts residual oil having a nitrogen content 

greater than 0.30 weight percent shall determine compliance with the NOXemission standards in §60.44b 

on a continuous basis through the use of a 30-day rolling average emission rate. A new 30-day rolling 

average emission rate is calculated for each steam generating unit operating day as the average of all of 

the hourly NOXemission data for the preceding 30 steam generating unit operating days. 

(3) Following the date on which the initial performance test is completed or is required to be completed 

under §60.8, whichever date comes first, the owner or operator of an affected facility that has a heat 

input capacity greater than 73 MW (250 MMBtu/hr) and that combusts natural gas, distillate oil, or 

residual oil having a nitrogen content of 0.30 weight percent or less shall determine compliance with the 

NOXstandards under §60.44b on a continuous basis through the use of a 30-day rolling average emission 

rate. A new 30-day rolling average emission rate is calculated each steam generating unit operating day 

as the average of all of the hourly NOXemission data for the preceding 30 steam generating unit 

operating days. 

(4) Following 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 affected facility that has a heat 

input capacity of 73 MW (250 MMBtu/hr) or less and that combusts natural gas, distillate oil, gasified 

coal, or residual oil having a nitrogen content of 0.30 weight percent or less shall upon request 

determine compliance with the NOXstandards in §60.44b through the use of a 30-day performance test. 

During periods when performance tests are not requested, NOXemissions data collected pursuant to 

§60.48b(g)(1) or §60.48b(g)(2) are used to calculate a 30-day rolling average emission rate on a daily 

basis and used to prepare excess emission reports, but will not be used to determine compliance with the 

NOXemission standards. A new 30-day rolling average emission rate is calculated each steam generating 

unit operating day as the average of all of the hourly NOXemission data for the preceding 30 steam 

generating unit operating days. 

(5) If the owner or operator of an affected facility that combusts residual oil does not sample and analyze 

the residual oil for nitrogen content, as specified in §60.49b(e), the requirements of §60.48b(g)(1) apply 

and the provisions of §60.48b(g)(2) are inapplicable. 
22

(f) To determine compliance with the emissions limits for NOXrequired by §60.44b(a)(4) or §60.44b(l) 

for duct burners used in combined cycle systems, either of the procedures described in paragraph (f)(1) 

or (2) of this section may be used: 

(1) The owner or operator of an affected facility shall conduct the performance test required under §60.8 

as follows: 

(i) The emissions rate (E) of NOXshall be computed using Equation 1 in this section: 

Where: 

E = Emissions rate of NOXfrom the duct burner, ng/J (lb/MMBtu) heat input; 

Esg= Combined effluent emissions rate, in ng/J (lb/MMBtu) heat input using appropriate F factor as 

described in Method 19 of appendix A of this part; 

Hg= Heat input rate to the combustion turbine, in J/hr (MMBtu/hr); 

Hb= Heat input rate to the duct burner, in J/hr (MMBtu/hr); and 

Eg= Emissions rate from the combustion turbine, in ng/J (lb/MMBtu) heat input calculated using 

appropriate F factor as described in Method 19 of appendix A of this part. 

(ii) Method 7E of appendix A of this part shall be used to determine the NOXconcentrations. Method 3A 

or 3B of appendix A of this part shall be used to determine O2concentration. 

(iii) The owner or operator shall identify and demonstrate to the Administrator's satisfaction suitable 

methods to determine the average hourly heat input rate to the combustion turbine and the average 

hourly heat input rate to the affected duct burner. 

(iv) Compliance with the emissions limits under §60.44b(a)(4) or §60.44b(l) is determined by the threerun average (nominal 1-hour runs) for the initial and subsequent performance tests; or 

(2) The owner or operator of an affected facility may elect to determine compliance on a 30-day rolling 

average basis by using the CEMS specified under §60.48b for measuring NOXand O2and meet the 

requirements of §60.48b. The sampling site shall be located at the outlet from the steam generating unit. 

The NOXemissions rate at the outlet from the steam generating unit shall constitute the NOXemissions 

rate from the duct burner of the combined cycle system. 

(g) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) shall demonstrate 

the maximum heat input capacity of the steam generating unit by operating the facility at maximum 

capacity for 24 hours. The owner or operator of an affected facility shall determine the maximum heat 

input capacity using the heat loss method or the heat input method described in sections 5 and 7.3 of the 

ASME Power Test Codes 4.1 (incorporated by reference, see §60.17). This demonstration of maximum 

heat input capacity shall be made during the initial performance test for affected facilities that meet the 

criteria of §60.44b(j). It shall be made 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 start-up of each 

facility, for affected facilities meeting the criteria of §60.44b(k). Subsequent demonstrations may be 

required by the Administrator at any other time. If this demonstration indicates that the maximum heat 

input capacity of the affected facility is less than that stated by the manufacturer of the affected facility, 

the maximum heat input capacity determined during this demonstration shall be used to determine the 
23

capacity utilization rate for the affected facility. Otherwise, the maximum heat input capacity provided 

by the manufacturer is used. 

(h) The owner or operator of an affected facility described in §60.44b(j) that has a heat input capacity 

greater than 73 MW (250 MMBtu/hr) shall: 

(1) Conduct an initial performance test as required under §60.8 over a minimum of 24 consecutive steam 

generating unit operating hours at maximum heat input capacity to demonstrate compliance with the 

NOXemission standards under §60.44b using Method 7, 7A, 7E of appendix A of this part, or other 

approved reference methods; and 

(2) Conduct subsequent performance tests once per calendar year or every 400 hours of operation 

(whichever comes first) to demonstrate compliance with the NOXemission standards under §60.44b over 

a minimum of 3 consecutive steam generating unit operating hours at maximum heat input capacity 

using Method 7, 7A, 7E of appendix A of this part, or other approved reference methods. 

(i) The owner or operator of an affected facility seeking to demonstrate compliance with the PM limit in 

paragraphs §60.43b(a)(4) or §60.43b(h)(5) shall follow the applicable procedures in §60.49b(r). 

(j) In place of PM testing with Method 5 or 5B of appendix A–3 of this part, or Method 17 of appendix 

A–6 of this part, an owner or operator may elect to install, calibrate, maintain, and operate a CEMS for 

monitoring PM emissions discharged to the atmosphere and record the output of the system. The owner 

or operator of an affected facility who elects to continuously monitor PM emissions instead of 

conducting performance testing using Method 5 or 5B of appendix A–3 of this part or Method 17 of 

appendix A–6 of this part shall comply with the requirements specified in paragraphs (j)(1) through 

(j)(14) of this section. 

(1) Notify the Administrator one month before starting use of the system. 

(2) Notify the Administrator one month before stopping use of the system. 

(3) The monitor shall be installed, evaluated, and operated in accordance with §60.13 of subpart A of 

this part. 

(4) 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 

notification to the Administrator of use of the CEMS if the owner or operator was previously 

determining compliance by Method 5, 5B, or 17 of appendix A of this part performance tests, whichever 

is later. 

(5) The owner or operator of an affected facility shall conduct an initial performance test for PM 

emissions as required under §60.8 of subpart A of this part. Compliance with the PM emission limit 

shall be determined by using the CEMS specified in paragraph (j) of this section to measure PM and 

calculating a 24-hour block arithmetic average emission concentration using EPA Reference Method 19 

of appendix A of this part, section 4.1. 

(6) Compliance with the PM emission limit shall be determined based on the 24-hour daily (block) 

average of the hourly arithmetic average emission concentrations using CEMS outlet data. 

(7) At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraphs (j)(7)(i) of 

this section for 75 percent of the total operating hours per 30-day rolling average. 

(i) At least two data points per hour shall be used to calculate each 1-hour arithmetic average. 

(ii) [Reserved] 
24

(8) The 1-hour arithmetic averages required under paragraph (j)(7) of this section shall be expressed in 

ng/J or lb/MMBtu heat input 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. 

(9) All valid CEMS data shall be used in calculating average emission concentrations even if the 

minimum CEMS data requirements of paragraph (j)(7) of this section are not met. 

(10) The CEMS shall be operated according to Performance Specification 11 in appendix B of this part. 

(11) During the correlation testing runs 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 continuous emission monitors 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. 

(12) 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. 

(13) When PM emissions data are not obtained because of CEMS breakdowns, repairs, calibration 

checks, and zero and span adjustments, emissions data shall be obtained by using other monitoring 

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

provide, as necessary, valid emissions data for a minimum of 75 percent of total operating hours per 30-

day rolling average. 

(14) After July 1, 2011, within 90 days after completing a correlation testing run, the owner or operator 

of an affected facility shall either successfully enter the test data into EPA's WebFIRE data base located 

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.

(14) 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.

§60.47b Emission monitoring for sulfur dioxide. 

(a) Except as provided in paragraphs (b) and (f) of this section, the owner or operator of an affected 

facility subject to the SO2standards in §60.42b shall install, calibrate, maintain, and operate CEMS for 

measuring SO2concentrations and either O2or CO2concentrations and shall record the output of the 

systems. For units complying with the percent reduction standard, the SO2and either O2or 

CO2concentrations shall both be monitored at the inlet and outlet of the SO2control device. If the owner 

or operator has installed and certified SO2and O2or CO2CEMS 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 

Comment [CF14]: Updated language for

electronic reporting.
25

ongoing quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this 

chapter, those CEMS may be used to meet the requirements of this section, provided that: 

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

collected simultaneously; and 

(2) 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 

(3) The reporting requirements of §60.49b are met. SO2and CO2(or O2) data used to meet the 

requirements of §60.49b shall not include substitute data values derived from the missing data 

procedures in subpart D of part 75 of this chapter, nor shall the SO2data have been bias adjusted 

according to the procedures of part 75 of this chapter. 

(b) As an alternative to operating CEMS as required under paragraph (a) of this section, an owner or 

operator may elect to determine the average SO2emissions and percent reduction by: 

(1) Collecting coal or oil samples in an as-fired condition at the inlet to the steam generating unit and 

analyzing them for sulfur and heat content according to Method 19 of appendix A of this part. Method 

19 of appendix A of this part provides procedures for converting these measurements into the format to 

be used in calculating the average SO2input rate, or 

(2) Measuring SO2according to Method 6B of appendix A of this part at the inlet or outlet to the 

SO2control system. An initial stratification test is required to verify the adequacy of the Method 6B of 

appendix A of this part sampling location. The stratification test shall consist of three paired runs of a 

suitable SO2and CO2measurement train operated at the candidate location and a second similar train 

operated according to the procedures in section 3.2 and the applicable procedures in section 7 of 

Performance Specification 2. Method 6B of appendix A of this part, Method 6A of appendix A of this 

part, or a combination of Methods 6 and 3 or 3B of appendix A of this part or Methods 6C and 3A of 

appendix A of this part are suitable measurement techniques. If Method 6B of appendix A of this part is 

used for the second train, sampling time and timer operation may be adjusted for the stratification test as 

long as an adequate sample volume is collected; however, both sampling trains are to be operated 

similarly. For the location to be adequate for Method 6B of appendix A of this part 24-hour tests, the 

mean of the absolute difference between the three paired runs must be less than 10 percent. 

(3) A daily SO2emission rate, ED, shall be determined using the procedure described in Method 6A of 

appendix A of this part, section 7.6.2 (Equation 6A–8) and stated in ng/J (lb/MMBtu) heat input. 

(4) The mean 30-day emission rate is calculated using the daily measured values in ng/J (lb/MMBtu) for 

30 successive steam generating unit operating days using equation 19–20 of Method 19 of appendix A 

of this part. 

(c) The owner or operator of an affected facility shall obtain emission data for at least 75 percent of the 

operating hours in at least 22 out of 30 successive boiler operating days. If this minimum data 

requirement is not met with a single monitoring system, the owner or operator of the affected facility 

shall supplement the emission data with data collected with other monitoring systems as approved by the 

Administrator or the reference methods and procedures as described in paragraph (b) of this section. 

(d) The 1-hour average SO2emission rates measured by the CEMS required by paragraph (a) of this 

section and required under §60.13(h) is expressed in ng/J or lb/MMBtu heat input and is used to 

calculate the average emission rates under §60.42(b). Each 1-hour average SO2emission rate must be 
26

based on 30 or more minutes of steam generating unit operation. The hourly averages shall be calculated 

according to §60.13(h)(2). Hourly SO2emission rates are not calculated if the affected facility is operated 

less than 30 minutes in a given clock hour and are not counted toward determination of a steam 

generating unit operating day. 

(e) The procedures under §60.13 shall be followed for installation, evaluation, and operation of the 

CEMS. 

(1) Except as provided for in paragraph (e)(4) of this section, all CEMS shall be operated in accordance 

with the applicable procedures under Performance Specifications 1, 2, and 3 of appendix B of this part. 

(2) Except as provided for in paragraph (e)(4) of this section, quarterly accuracy determinations and 

daily calibration drift tests shall be performed in accordance with Procedure 1 of appendix F of this part. 

(3) For affected facilities combusting coal or oil, alone or in combination with other fuels, the span value 

of the SO2CEMS at the inlet to the SO2control device is 125 percent of the maximum estimated hourly 

potential SO2emissions of the fuel combusted, and the span value of the CEMS at the outlet to the 

SO2control device is 50 percent of the maximum estimated hourly potential SO2emissions of the fuel 

combusted. Alternatively, SO2span values determined according to section 2.1.1 in appendix A to part 

75 of this chapter may be used. 

(4) As an alternative to meeting the requirements of requirements of paragraphs (e)(1) and (e)(2) of this 

section, the owner or operator may elect to implement the following alternative data accuracy 

assessment procedures: 

(i) For all required CO2and O2monitors and for SO2and NOXmonitors with span values greater than or 

equal to 100 ppm, the daily calibration error test and calibration adjustment procedures described in 

sections 2.1.1 and 2.1.3 of appendix B to part 75 of this chapter may be followed instead of the CD 

assessment procedures in Procedure 1, section 4.1 of appendix F to this part. 

(ii) For all required CO2and O2monitors and for SO2and NOXmonitors 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; and 

(iii) For SO2, CO2, and O2monitoring systems and for NOXemission rate monitoring systems, 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 
27

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. 

(f) The owner or operator of an affected facility that combusts very low sulfur oil or is demonstrating 

compliance under §60.45b(k) is not subject to the emission monitoring requirements under paragraph (a) 

of this section if the owner or operator maintains fuel records as described in §60.49b(r). 

§60.48b Emission monitoring for particulate matter and nitrogen oxides. 

(a) Except as provided in paragraph (j) of this section, the owner or operator of an affected facility 

subject to the opacity standard under §60.43b shall install, calibrate, maintain, and operate a continuous 

opacity monitoring system (COMS) for measuring the opacity of emissions discharged to the 

atmosphere and record the output of the system. The owner or operator of an affected facility subject to 

an opacity standard under §60.43b and meeting the conditions under paragraphs (j)(1), (2), (3), (4), (5), 

or (5)6) of this section who elects not to use a COMS shall conduct a performance test using Method 9 

of appendix A–4 of this part and the procedures in §60.11 to demonstrate compliance with the 

applicable limit in §60.43b by April 29, 2011, within 45 days of stopping use of an existing COMS, or 

within 180 days after initial startup of the facility, whichever is later, and shall comply with either 

paragraphs (a)(1), (a)(2), or (a)(3) of this section. The observation period for Method 9 of appendix A-4 

of this part performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are 

less than 10 percent and all individual 15-second observations are less than or equal to 20 percent during 

the initial 60 minutes of observation. 

(1) Except as provided in paragraph (a)(2) and (a)(3) 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) of this section according to the applicable schedule in paragraphs (a)(1)(i) through (a)(1)(iv) of this 

section, as determined by the most recent Method 9 of appendix A–4 of this part performance test 

results. 

(i) If no visible emissions are observed, 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; 

(ii) 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 or within 

45 days of the next day that fuel with an opacity standard is combusted, whichever is later; 

(iii) 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 

(iv) 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. 

(2) 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 

Comment [CF15]: Allow flexibility to account

for intermittent use of fuels with an opacity

standard.
28

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)(2)(i) and (ii) of this section. 

(i) 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) of this section within 45 calendar days according 

to the requirements in §60.46d(d)(7). 

(ii) If no visible emissions are observed for 30 10 operating days during which an opacity standard is 

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

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

(3) 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)(2) of this section. For reference purposes in preparing the monitoring plan, see OAQPS 

“Determination of Visible Emission Opacity from Stationary Sources Using Computer-Based 

Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection 

Agency (U.S. EPA); Office of Air Quality and Planning Standards; Sector Policies and Programs 

Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document is 

also available on the Technology Transfer Network (TTN) under Emission Measurement Center 

Preliminary Methods. 

(b) Except as provided under paragraphs (g), (h), and (i) of this section, the owner or operator of an 

affected facility subject to a NOXstandard under §60.44b shall comply with either paragraphs (b)(1) or 

(b)(2) of this section. 

(1) Install, calibrate, maintain, and operate CEMS for measuring NOXand O2(or CO2) emissions 

discharged to the atmosphere, and shall record the output of the system; 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 §60.49b. Data reported to meet the requirements of §60.49b 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. 

(c) The CEMS required under paragraph (b) of this section shall be operated and data recorded during 

all periods of operation of the affected facility except for CEMS breakdowns and repairs. Data is 

recorded during calibration checks, and zero and span adjustments. 

Comment [CF16]: Reduce number of required

operating days with no visible emissions to begin

reduced monitoring
29

(d) The 1-hour average NOXemission rates measured by the continuous NOXmonitor required by 

paragraph (b) of this section and required under §60.13(h) shall be expressed in ng/J or lb/MMBtu heat 

input and shall be used to calculate the average emission rates under §60.44b. The 1-hour averages shall 

be calculated using the data points required under §60.13(h)(2). 

(e) The procedures under §60.13 shall be followed for installation, evaluation, and operation of the 

continuous monitoring systems. 

(1) For affected facilities combusting coal, wood or municipal-type solid waste, the span value for a 

COMS shall be between 60 and 80 percent. 

(2) For affected facilities combusting coal, oil, or natural gas, the span value for NOXis determined using 

one of the following procedures: 

(i) Except as provided under paragraph (e)(2)(ii) of this section, NOXspan values shall be determined as 

follows: 

Fuel Span values for NOX

(ppm) 

Natural gas 500. 

Oil 500. 

Coal 1,000. 

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

Where: 

x = Fraction of total heat input derived from natural gas; 

y = Fraction of total heat input derived from oil; and 

z = Fraction of total heat input derived from coal. 

(ii) As an alternative to meeting the requirements of paragraph (e)(2)(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. 

(3) All span values computed under paragraph (e)(2)(i) of this section for combusting mixtures of 

regulated fuels are rounded to the nearest 500 ppm. Span values computed under paragraph (e)(2)(ii) of 

this section shall be rounded off according to section 2.1.2 in appendix A to part 75 of this chapter. 

(f) When NOXemission data are not obtained because of CEMS breakdowns, repairs, calibration checks 

and zero and span adjustments, emission data will be obtained by using standby monitoring systems, 

Method 7 of appendix A of this part, Method 7A of appendix A of this part, or other approved reference 

methods to provide emission data for a minimum of 75 percent of the operating hours in each steam 

generating unit operating day, in at least 22 out of 30 successive steam generating unit operating days. 

(g) The owner or operator of an affected facility that has a heat input capacity of 73 MW (250 

MMBtu/hr) or less, and that has an annual capacity factor for residual oil having a nitrogen content of 

0.30 weight percent or less, natural gas, distillate oil, gasified coal, or any mixture of these fuels, greater 

than 10 percent (0.10) shall: 

(1) Comply with the provisions of paragraphs (b), (c), (d), (e)(2), (e)(3), and (f) of this section; or 
30

(2) Monitor steam generating unit operating conditions and predict NOXemission rates as specified in a 

plan submitted pursuant to §60.49b(c). 

(h) The owner or operator of a duct burner, as described in §60.41b, that is subject to the NOXstandards 

in §60.44b(a)(4), §60.44b(e), or §60.44b(l) is not required to install or operate a continuous emissions 

monitoring system to measure NOXemissions. 

(i) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) is not required to 

install or operate a CEMS for measuring NOXemissions. 

(j) The owner or operator of an affected facility that meets the conditions in either paragraph (j)(1), (2), 

(3), (4), (5), (6), or (67) of this section is not required to install or operate a COMS if: 

(1) The affected facility uses a PM CEMS to monitor PM emissions; or 

(2) The affected facility burns only liquid (excluding residual oil) or gaseous fuels with potential 

SO2emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and does not use a post-combustion technology 

to reduce SO2or PM emissions. The owner or operator must maintain fuel records of the sulfur content 

of the fuels burned, as described under §60.49b(r); or 

(3) The affected facility burns coke oven gas alone or in combination with fuels meeting the criteria in 

paragraph (j)(2) of this section and does not use a post-combustion technology to reduce SO2or PM 

emissions; or 

(4) The affected facility does not use post-combustion technology (except a wet scrubber) for reducing 

PM, SO2, or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less 

than or equal to 0.30 weight percent sulfur, and is operated such that emissions of CO to the atmosphere 

from the affected facility are maintained at levels less than or equal to 0.15 lb/MMBtu on a steam 

generating unit operating day average basis. Owners and operators of affected facilities electing to 

comply with this paragraph must demonstrate compliance according to the procedures specified in 

paragraphs (j)(4)(i) through (iv) of this section; or 

(i) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs 

(j)(4)(i)(A) through (D) of this section. 

(A) 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. 

(B) 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). 

(C) At a minimum, valid 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). 

(D) 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. 

(ii) You must calculate the 1-hour average CO emissions levels for each steam generating unit 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 heat 

input to the affected source. The 24-hour average CO emission level is determined by calculating the 

arithmetic average of the hourly CO emission levels computed for each steam generating unit operating 

day. 
31

(iii) You must evaluate the preceding 24-hour average CO emission level each steam generating unit 

operating day excluding periods of affected source startup, shutdown, or malfunction. If the 24-hour 

average CO emission level is greater than 0.15 lb/MMBtu, 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 0.15 lb/MMBtu or less. 

(iv) You must record the CO measurements and calculations performed according to paragraph (j)(4) 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 0.15 lb/MMBtu, and the 

date, time, and description of the corrective action. 

(5) The affected facility uses a bag leak detection system to monitor the performance of a fabric filter 

(baghouse) according to the most recentcurrent requirements in section §60.48Da of this part; or 

(6)(6) The affected facility uses an ESP as the primary PM control device 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; or

(7) The affected facility burns only gaseous fuels or fuel oils that contain less than or equal to 0.30 

weight percent sulfur and 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. 

(k) Owners or operators complying with the PM emission limit by using a PM CEMS must calibrate, 

maintain, operate, and record the output of the system for PM emissions discharged to the atmosphere as 

specified in §60.46b(j). The CEMS specified in paragraph §60.46b(j) shall be operated and data 

recorded during all periods of operation of the affected facility except for CEMS breakdowns and 

repairs. Data is recorded during calibration checks, and zero and span adjustments.

(l) An owner or operator of an affected facility that is subject to an opacity standard under §60.43b(f) is 

not required to operate a COMS provided that the unit 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 is not required to operate a COMS. This monitoring plan must include procedures and criteria 

for establishing and monitoring specific parameters for the affected facility indicative of compliance 

with the opacity standard. For testing performed as part of this site-specific monitoring plan, the 

permitting authority may require as an alternative to the notification and reporting requirements 

specified in §§60.8 and 60.11 that the owner or operator submit any deviations with the excess 

emissions report required under §60.49b(h).

§60.49b Reporting and recordkeeping requirements. 

(a) The owner or operator of each affected facility shall submit notification of the date of initial startup, 

as provided by §60.7. This notification shall include: 

(1) The design heat input capacity of the affected facility and identification of the fuels to be combusted 

in the affected facility; 

(2) If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor 

for any fuel or mixture of fuels under §§60.42b(d)(1), 60.43b(a)(2), (a)(3)(iii), (c)(2)(ii), (d)(2)(iii), 

60.44b(c), (d), (e), (i), (j), (k), 60.45b(d), (g), 60.46b(h), or 60.48b(i); 

Comment [CF17]: Add ESP model to COMS

exemption options

Comment [CF18]: Add flexibility of monitoring

plan – similar to subpart Dc
32

(3) The annual capacity factor at which the owner or operator anticipates operating the facility based on 

all fuels fired and based on each individual fuel fired; and 

(4) Notification that an emerging technology will be used for controlling emissions of SO2. The 

Administrator will examine the description of the emerging technology and will determine whether the 

technology qualifies as an emerging technology. In making this determination, the Administrator may 

require the owner or operator of the affected facility to submit additional information concerning the 

control device. The affected facility is subject to the provisions of §60.42b(a) unless and until this 

determination is made by the Administrator. 

(b) The owner or operator of each affected facility subject to the SO2, PM, and/or NOX emission limits 

under §§60.42b, 60.43b, and 60.44b shall submit to the Administrator the performance test data from the 

initial performance test and the performance evaluation of the CEMS using the applicable performance 

specifications in appendix B of this part. The owner or operator of each affected facility described in 

§60.44b(j) or §60.44b(k) shall submit to the Administrator the maximum heat input capacity data from 

the demonstration of the maximum heat input capacity of the affected facility. 

(c) The owner or operator of each affected facility subject to the NOX standard in §60.44b who seeks to 

demonstrate compliance with those standards through the monitoring of steam generating unit operating 

conditions in the provisions of §60.48b(g)(2) shall submit to the Administrator for approval a plan that 

identifies the operating conditions to be monitored in §60.48b(g)(2) and the records to be maintained in 

§60.49b(g). This plan shall be submitted to the Administrator for approval within 360 days of the initial 

startup of the affected facility. An affected facility burning coke oven gas alone or in combination with 

other gaseous fuels or distillate oil shall submit this plan to the Administrator for approval within 360 

days of the initial startup of the affected facility or by November 30, 2009, whichever date comes later. 

If the plan is approved, the owner or operator shall maintain records of predicted nitrogen oxide 

emission rates and the monitored operating conditions, including steam generating unit load, identified 

in the plan. The plan shall: 

(1) Identify the specific operating conditions to be monitored and the relationship between these 

operating conditions and NOX emission rates ( i.e. , ng/J or lbs/MMBtu heat input). Steam generating 

unit operating conditions include, but are not limited to, the degree of staged combustion ( i.e. , the ratio 

of primary air to secondary and/or tertiary air) and the level of excess air ( i.e. , flue gas O2level); 

(2) Include the data and information that the owner or operator used to identify the relationship between 

NOX emission rates and these operating conditions; and 

(3) Identify how these operating conditions, including steam generating unit load, will be monitored 

under §60.48b(g) on an hourly basis by the owner or operator during the period of operation of the 

affected facility; the quality assurance procedures or practices that will be employed to ensure that the 

data generated by monitoring these operating conditions will be representative and accurate; and the 

type and format of the records of these operating conditions, including steam generating unit load, that 

will be maintained by the owner or operator under §60.49b(g). 

(d) Except as provided in paragraph (d)(2) of this section, the owner or operator of an affected facility 

shall record and maintain records as specified in paragraph (d)(1) of this section. 

(1) The owner or operator of an affected facility shall record and maintain records of the amounts of 

each fuel combusted during each day and calculate the annual capacity factor individually for coal, 

distillate oil, residual oil, natural gas, wood, and municipal-type solid waste for the reporting period. The 

annual capacity factor is determined on a 12-month rolling average basis with a new annual capacity 

factor calculated at the end of each calendar month. 
33

(2) As an alternative to meeting the requirements of paragraph (d)(1) of this section, the owner or 

operator of an affected facility that is subject to a federally enforceable permit restricting fuel use to a 

single fuel such that the facility is not required to continuously monitor any emissions (excluding 

opacity) or parameters indicative of emissions may elect to record and maintain records of the amount of 

each fuel combusted during each calendar month. 

(e) For an affected facility that combusts residual oil and meets the criteria under §§60.46b(e)(4), 

60.44b(j), or (k), the owner or operator shall maintain records of the nitrogen content of the residual oil 

combusted in the affected facility and calculate the average fuel nitrogen content for the reporting 

period. The nitrogen content shall be determined using ASTM Method D4629 (incorporated by 

reference, see §60.17), or fuel suppliers. If residual oil blends are being combusted, fuel nitrogen 

specifications may be prorated based on the ratio of residual oils of different nitrogen content in the fuel 

blend. 

(f) For an affected facility subject to the opacity standard in §60.43b, the owner or operator shall 

maintain records of opacity. In addition, an owner or operator that elects to monitor emissions according 

to the requirements in §60.48b(a) shall maintain records according to the requirements specified in 

paragraphs (f)(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 (f)(1)(i) through (iii) of 

this section. 

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

(ii) Name, affiliation, and copy of current visible emission reading certification for each visible emission 

observer participating in the performance test; and 

(iii) Copies of all visible emission observer opacity field data sheets;.

(2) For each performance test conducted using Method 22 of appendix A–4 of this part, the owner or 

operator shall keep the records including the information specified in paragraphs (f)(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. 

(g) Except as provided under paragraph (p) of this section, the owner or operator of an affected facility 

subject to the NOX standards under §60.44b shall maintain records of the following information for each 

steam generating unit operating day: 

(1) Calendar date; 
34

(2) The average hourly NOX emission rates (expressed as NO2) (ng/J or lb/MMBtu heat input) measured 

or predicted; 

(3) The 30-day average NOX emission rates (ng/J or lb/MMBtu heat input) calculated at the end of each 

steam generating unit operating day from the measured or predicted hourly nitrogen oxide emission rates 

for the preceding 30 steam generating unit operating days; 

(4) Identification of the steam generating unit operating days when the calculated 30-day average NOX 

emission rates are in excess of the NOX emissions standards under §60.44b, with the reasons for such 

excess emissions as well as a description of corrective actions taken; 

(5) Identification of the steam generating unit operating days for which pollutant data have not been 

obtained, including reasons for not obtaining sufficient data and a description of corrective actions 

taken; 

(6) Identification of the times when emission data have been excluded from the calculation of average 

emission rates and the reasons for excluding data; 

(7) Identification of “F” factor used for calculations, method of determination, and type of fuel 

combusted; 

(8) Identification of the times when the pollutant concentration exceeded full span of the CEMS; 

(9) Description of any modifications to the CEMS that could affect the ability of the CEMS to comply 

with Performance Specification 2 or 3; and 

(10) Results of daily CEMS drift tests and quarterly accuracy assessments as required under appendix F, 

Procedure 1 of this part. 

(h) The owner or operator of any affected facility in any category listed in paragraphs (h)(1) or (2) of 

this section is required to submit excess emission reports for any excess emissions that occurred during 

the reporting period. 

(1) Any affected facility subject to the opacity standards in §60.43b(f) or to the operating parameter 

monitoring requirements in §60.13(i)(1). 

(2) Any affected facility that is subject to the NOX standard of §60.44b, and that: 

(i) Combusts natural gas, distillate oil, gasified coal, or residual oil with a nitrogen content of 0.3 weight 

percent or less; or 

(ii) Has a heat input capacity of 73 MW (250 MMBtu/hr) or less and is required to monitor NOX 

emissions on a continuous basis under §60.48b(g)(1) or steam generating unit operating conditions 

under §60.48b(g)(2). 

(3) For the purpose of §60.43b, excess emissions are defined as all 6-minute periods during which the 

average opacity exceeds the opacity standards under §60.43b(f). 

(4) For purposes of §60.48b(g)(1), excess emissions are defined as any calculated 30-day rolling average 

NOX emission rate, as determined under §60.46b(e), that exceeds the applicable emission limits in 

§60.44b. 

(i) The owner or operator of any affected facility subject to the continuous monitoring requirements for 

NOX under §60.48(b) shall submit reports containing the information recorded under paragraph (g) of 

this section. 
35

(j) The owner or operator of any affected facility subject to the SO2standards under §60.42b shall submit 

reports. 

(k) For each affected facility subject to the compliance and performance testing requirements of §60.45b 

and the reporting requirement in paragraph (j) of this section, the following information shall be reported 

to the Administrator: 

(1) Calendar dates covered in the reporting period; 

(2) Each 30-day average SO2 emission rate (ng/J or lb/MMBtu heat input) measured during the reporting 

period, ending with the last 30-day period; reasons for noncompliance with the emission standards; and 

a description of corrective actions taken; For an exceedance due to maintenance of the SO2 control 

system covered in paragraph 60.45b(a), the report shall identify the days on which the maintenance was 

performed and a description of the maintenance; 

(3) Each 30-day average percent reduction in SO2 emissions calculated during the reporting period, 

ending with the last 30-day period; reasons for noncompliance with the emission standards; and a 

description of corrective actions taken; 

(4) Identification of the steam generating unit operating days that coal or oil was combusted and for 

which SO2 or diluent (O2 or CO2) data have not been obtained by an approved method for at least 75 

percent of the operating hours in the steam generating unit operating day; justification for not obtaining 

sufficient data; and description of corrective action taken; 

(5) Identification of the times when emissions data have been excluded from the calculation of average 

emission rates; justification for excluding data; and description of corrective action taken if data have 

been excluded for periods other than those during which coal or oil were not combusted in the steam 

generating unit; 

(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 the CEMS that could affect the ability of the CEMS to comply 

with Performance Specification 2 or 3; 

(10) Results of daily CEMS drift tests and quarterly accuracy assessments as required under appendix F, 

Procedure 1 of this part; and 

(11) The annual capacity factor of each fired as provided under paragraph (d) of this section. 

(l) For each affected facility subject to the compliance and performance testing requirements of 

§60.45b(d) and the reporting requirements of paragraph (j) of this section, the following information 

shall be reported to the Administrator: 

(1) Calendar dates when the facility was in operation during the reporting period; 

(2) The 24-hour average SO2 emission rate measured for each steam generating unit operating day 

during the reporting period that coal or oil was combusted, ending in the last 24-hour period in the 

quarter; reasons for noncompliance with the emission standards; and a description of corrective actions 

taken; 
36

(3) Identification of the steam generating unit operating days that coal or oil was combusted for which 

S02 or diluent (O2 or CO2) data have not been obtained by an approved method for at least 75 percent of 

the operating hours; justification for not obtaining sufficient data; and description of corrective action 

taken; 

(4) Identification of the times when emissions data have been excluded from the calculation of average 

emission rates; justification for excluding data; and description of corrective action taken if data have 

been excluded for periods other than those during which coal or oil were not combusted in the steam 

generating unit; 

(5) Identification of “F” factor used for calculations, method of determination, and type of fuel 

combusted; 

(6) Identification of times when hourly averages have been obtained based on manual sampling 

methods; 

(7) Identification of the times when the pollutant concentration exceeded full span of the CEMS; 

(8) Description of any modifications to the CEMS that could affect the ability of the CEMS to comply 

with Performance Specification 2 or 3; and 

(9) Results of daily CEMS drift tests and quarterly accuracy assessments as required under Procedure 1 

of appendix F 1 of this part. If the owner or operator elects to implement the alternative data assessment 

procedures described in §§60.47b(e)(4)(i) through (e)(4)(iii), 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 §§60.47b(e)(4)(i) through (e)(4)(iii). 

(m) For each affected facility subject to the SO2standards in §60.42(b) for which the minimum amount 

of data required in §60.47b(c) were not obtained during the reporting period, the following information 

is reported to the Administrator in addition to that required under paragraph (k) of this section: 

(1) The number of hourly averages available for outlet emission rates and inlet emission rates; 

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

determined in Method 19 of appendix A of this part, section 7; 

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

mean inlet emission rate, as calculated in Method 19 of appendix A of this part, section 7; and 

(4) The ratio of the lower confidence limit for the mean outlet emission rate and the allowable emission 

rate, as determined in Method 19 of appendix A of this part, section 7. 

(n) If a percent removal efficiency by fuel pretreatment (i.e. , %Rf) is used to determine the overall 

percent reduction ( i.e. , %Ro) under §60.45b, the owner or operator of the affected facility shall submit 

a signed statement with the report. 

(1) Indicating what removal efficiency by fuel pretreatment (i.e. , %Rf) was credited during the reporting 

period; 

(2) Listing the quantity, heat content, and date each pre-treated fuel shipment was received during the 

reporting period, 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 reporting period; 

(3) Documenting the transport of the fuel from the fuel pretreatment facility to the steam generating unit; 

and 
37

(4) Including a signed statement from the owner or operator of the fuel pretreatment facility certifying 

that the percent removal efficiency achieved by fuel pretreatment was determined in accordance with the 

provisions of Method 19 of appendix A of this part and listing the heat content and sulfur content of 

each fuel before and after fuel pretreatment. 

(o) All records required under this section shall be maintained by the owner or operator of the affected 

facility for a period of 2 years following the date of such record. 

(p) The owner or operator of an affected facility described in §60.44b(j) or (k) shall maintain records of 

the following information for each steam generating unit operating day: 

(1) Calendar date; 

(2) The number of hours of operation; and 

(3) A record of the hourly steam load. 

(q) The owner or operator of an affected facility described in §60.44b(j) or §60.44b(k) shall submit to 

the Administrator a report containing: 

(1) The annual capacity factor over the previous 12 months; 

(2) The average fuel nitrogen content during the reporting period, if residual oil was fired; and 

(3) If the affected facility meets the criteria described in §60.44b(j), the results of any NOX emission 

tests required during the reporting period, the hours of operation during the reporting period, and the 

hours of operation since the last NOX emission test. 

(r) The owner or operator of an affected facility who elects to use the fuel based compliance alternatives 

in §60.42b or §60.43b shall either: 

(1) The owner or operator of an affected facility who elects to demonstrate that the affected facility 

combusts only very low sulfur oil, natural gas, wood, a mixture of these fuels, or any of these fuels (or a 

mixture of these fuels) in combination with other fuels that are known to contain an insignificant amount 

of sulfur in §60.42b(j) or §60.42b(k) shall obtain and maintain at the affected facility fuel receipts (such 

as a current, valid purchase contract, tariff sheet, or transportation contract) from the fuel supplier that 

certify that the oil meets the definition of distillate oil and gaseous fuel meets the definition of natural 

gas as defined in §60.41b and the applicable sulfur limit. For the purposes of this section, the distillate 

oil need not meet the fuel nitrogen content specification in the definition of distillate oil. Reports shall be 

submitted to the Administrator certifying that only very low sulfur oil meeting this definition, natural 

gas, wood, and/or other fuels that are known to contain insignificant amounts of sulfur were combusted 

in the affected facility during the reporting period; or 

(2) The owner or operator of an affected facility who elects to demonstrate compliance based on fuel 

analysis in §60.42b or §60.43b shall develop and submit a site-specific fuel analysis plan to the 

Administrator for review and approval no later than 60 days before the date you intend to demonstrate 

compliance. Each fuel analysis plan shall include a minimum initial requirement of weekly testing and 

each analysis report shall contain, at a minimum, the following information: 

(i) The potential sulfur emissions rate of the representative fuel mixture in ng/J heat input; 

(ii) The method used to determine the potential sulfur emissions rate of each constituent of the mixture. 

For distillate oil and natural gas a fuel receipt or tariff sheet is acceptable; 

(iii) The ratio of different fuels in the mixture; and 

Comment [CF19]: Allow tariff sheets similar to

subpart KKKK  
38

(iv) The owner or operator can petition the Administrator to approve monthly or quarterly sampling in 

place of weekly sampling. 

(s) Facility specific NOX standard for Cytec Industries Fortier Plant's C.AOG incinerator located in 

Westwego, Louisiana: 

(1) Definitions . 

Oxidation zone is defined as the portion of the C.AOG incinerator that extends from the inlet of the 

oxidizing zone combustion air to the outlet gas stack. 

Reducing zone is defined as the portion of the C.AOG incinerator that extends from the burner section to 

the inlet of the oxidizing zone combustion air. 

Total inlet air is defined as the total amount of air introduced into the C.AOG incinerator for combustion 

of natural gas and chemical by-product waste and is equal to the sum of the air flow into the reducing 

zone and the air flow into the oxidation zone. 

(2) Standard for nitrogen oxides . (i) When fossil fuel alone is combusted, the NOXemission limit for 

fossil fuel in §60.44b(a) applies. 

(ii) When natural gas and chemical by-product waste are simultaneously combusted, the NOXemission 

limit is 289 ng/J (0.67 lb/MMBtu) and a maximum of 81 percent of the total inlet air provided for 

combustion shall be provided to the reducing zone of the C.AOG incinerator. 

(3) Emission monitoring . (i) The percent of total inlet air provided to the reducing zone shall be 

determined at least every 15 minutes by measuring the air flow of all the air entering the reducing zone 

and the air flow of all the air entering the oxidation zone, and compliance with the percentage of total 

inlet air that is provided to the reducing zone shall be determined on a 3-hour average basis. 

(ii) The NOXemission limit shall be determined by the compliance and performance test methods and 

procedures for NOXin §60.46b(i). 

(iii) The monitoring of the NOXemission limit shall be performed in accordance with §60.48b. 

(4) Reporting and recordkeeping requirements . (i) The owner or operator of the C.AOG incinerator 

shall submit a report on any excursions from the limits required by paragraph (a)(2) of this section to the 

Administrator with the quarterly report required by paragraph (i) of this section. 

(ii) The owner or operator of the C.AOG incinerator shall keep records of the monitoring required by 

paragraph (a)(3) of this section for a period of 2 years following the date of such record. 

(iii) The owner of operator of the C.AOG incinerator shall perform all the applicable reporting and 

recordkeeping requirements of this section. 

(t) Facility-specific NOXstandard for Rohm and Haas Kentucky Incorporated's Boiler No. 100 located in 

Louisville, Kentucky: 

(1) Definitions . 

Air ratio control damper is defined as the part of the low NOXburner that is adjusted to control the split 

of total combustion air delivered to the reducing and oxidation portions of the combustion flame. 

Flue gas recirculation line is defined as the part of Boiler No. 100 that recirculates a portion of the 

boiler flue gas back into the combustion air. 

(2) Standard for nitrogen oxides . (i) When fossil fuel alone is combusted, the NOXemission limit for 

fossil fuel in §60.44b(a) applies. 
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(ii) When fossil fuel and chemical by-product waste are simultaneously combusted, the NOXemission 

limit is 473 ng/J (1.1 lb/MMBtu), and the air ratio control damper tee handle shall be at a minimum of 5 

inches (12.7 centimeters) out of the boiler, and the flue gas recirculation line shall be operated at a 

minimum of 10 percent open as indicated by its valve opening position indicator. 

(3) Emission monitoring for nitrogen oxides . (i) The air ratio control damper tee handle setting and the 

flue gas recirculation line valve opening position indicator setting shall be recorded during each 8-hour 

operating shift. 

(ii) The NOXemission limit shall be determined by the compliance and performance test methods and 

procedures for NOXin §60.46b. 

(iii) The monitoring of the NOXemission limit shall be performed in accordance with §60.48b. 

(4) Reporting and recordkeeping requirements . (i) The owner or operator of Boiler No. 100 shall 

submit a report on any excursions from the limits required by paragraph (b)(2) of this section to the 

Administrator with the quarterly report required by §60.49b(i). 

(ii) The owner or operator of Boiler No. 100 shall keep records of the monitoring required by paragraph 

(b)(3) of this section for a period of 2 years following the date of such record. 

(iii) The owner of operator of Boiler No. 100 shall perform all the applicable reporting and 

recordkeeping requirements of §60.49b. 

(u) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant in Elkton, Virginia . (1) This 

paragraph (u) applies only to the pharmaceutical manufacturing facility, commonly referred to as the 

Stonewall Plant, located at Route 340 South, in Elkton, Virginia (“site”) and only to the natural gas-fired 

boilers installed as part of the powerhouse conversion required pursuant to 40 CFR 52.2454(g). The 

requirements of this paragraph shall apply, and the requirements of §§60.40b through 60.49b(t) shall not 

apply, to the natural gas-fired boilers installed pursuant to 40 CFR 52.2454(g). 

(i) The site shall equip the natural gas-fired boilers with low NOXtechnology. 

(ii) The site shall install, calibrate, maintain, and operate a continuous monitoring and recording system 

for measuring NOXemissions discharged to the atmosphere and opacity using a continuous emissions 

monitoring system or a predictive emissions monitoring system. 

(iii) Within 180 days of the completion of the powerhouse conversion, as required by 40 CFR 52.2454, 

the site shall perform a performance test to quantify criteria pollutant emissions. 

(2) [Reserved] 

(v) The owner or operator of an affected facility may submit electronic quarterly reports for SO2and/or 

NOXand/or opacity in lieu of submitting the written reports required under paragraphs (h), (i), (j), (k) or 

(l) 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. 

(w) The reporting period for the reports required under this subpart is each 6 month period. All reports 

shall be submitted to the Administrator and shall be postmarked by the 30th day following the end of the 

reporting period. 
40

(x) Facility-specific NOXstandard for Weyerhaeuser Company's No. 2 Power Boiler located in New 

Bern, North Carolina: 

(1) Standard for nitrogen oxides . (i) When fossil fuel alone is combusted, the NOXemission limit for 

fossil fuel in §60.44b(a) applies. 

(ii) When fossil fuel and chemical by-product waste are simultaneously combusted, the NOXemission 

limit is 215 ng/J (0.5 lb/MMBtu). 

(2) Emission monitoring for nitrogen oxides . (i) The NOXemissions shall be determined by the 

compliance and performance test methods and procedures for NOXin §60.46b. 

(ii) The monitoring of the NOXemissions shall be performed in accordance with §60.48b. 

(3) Reporting and recordkeeping requirements . (i) The owner or operator of the No. 2 Power Boiler 

shall submit a report on any excursions from the limits required by paragraph (x)(2) of this section to the 

Administrator with the quarterly report required by §60.49b(i). 

(ii) The owner or operator of the No. 2 Power Boiler shall keep records of the monitoring required by 

paragraph (x)(3) of this section for a period of 2 years following the date of such record. 

(iii) The owner or operator of the No. 2 Power Boiler shall perform all the applicable reporting and 

recordkeeping requirements of §60.49b. 

(y) Facility-specific NOXstandard for INEOS USA's AOGI located in Lima, Ohio: 

(1) Standard for NO X. (i) When fossil fuel alone is combusted, the NOXemission limit for fossil fuel in 

§60.44b(a) applies. 

(ii) When fossil fuel and chemical byproduct/waste are simultaneously combusted, the NOXemission 

limit is 645 ng/J (1.5 lb/MMBtu). 

(2) Emission monitoring for NO X. (i) The NOXemissions shall be determined by the compliance and 

performance test methods and procedures for NOXin §60.46b. 

(ii) The monitoring of the NOXemissions shall be performed in accordance with §60.48b. 

(3) Reporting and recordkeeping requirements . (i) The owner or operator of the AOGI shall submit a 

report on any excursions from the limits required by paragraph (y)(2) of this section to the Administrator 

with the quarterly report required by paragraph (i) of this section. 

(ii) The owner or operator of the AOGI shall keep records of the monitoring required by paragraph 

(y)(3) of this section for a period of 2 years following the date of such record. 

(iii) The owner or operator of the AOGI shall perform all the applicable reporting and recordkeeping 

requirements of this section.