1

Subpart Dc—Standards of Performance for Small Industrial-Commercial-Institutional Steam 

Generating Units 

§60.40c Applicability and delegation of authority. 

(a) Except as provided in paragraphs (d), (e), (f), and (g) of this section, the affected facility to which 

this subpart applies is each steam generating unit for which construction, modification, or reconstruction 

is commenced after June 9, 1989 and that has a maximum design heat input capacity of 29 megawatts 

(MW) (100 million British thermal units per hour (MMBtu/hrh)) or less, but greater than or equal to 2.9 

MW (10 MMBtu/hrh). 

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

Air Act, §60.48c(a)(4) shall be retained by the Administrator and not transferred to a State. 

(c) Steam generating units that meet the applicability requirements in paragraph (a) of this section are 

not subject to the sulfur dioxide (SO2) or particulate matter (PM) emission limits, performance testing 

requirements, or monitoring requirements under this subpart (§§60.42c, 60.43c, 60.44c, 60.45c, 60.46c, 

or 60.47c) during periods of combustion research, as defined in §60.41c. 

(d) Any temporary change to an existing steam generating unit for the purpose of conducting 

combustion research is not considered a modification under §60.14. 

(e) Heat Affected facilities (i.e. heat recovery steam generators and fuel heaters) that are associated with 

combined cycle gasstationary combustion turbines and 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 heat 

recovery steam generators, fuel heaters, and other affected facilities that are capable of combusting more 

than or equal to 2.9 MW (10 MMBtu/hrh) heat input of fossil fuel but less than or equal to 29 MW (100 

MMBtu/hrh) heat input of fossil fuel. If the heat recovery steam generator, fuel heater, or other affected 

facility 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). 

(f) Any affected facility covered bythat meets the applicability requirements and is subject to subpart 

AAAA or subpart CCCC of this part is not subject byto this subpart. 

(g) Any facility covered bythat meets the applicability requirements and is subject to an EPA approved 

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

subpart. 

(h) Affected facilities that also meet the applicability requirements under subpart J or subpart Ja of this 

part are subject to the PM and NOX standards under this subpart and the SO2 standards under subpart J

or subpart Ja of this part, as applicable.

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

§60.41c 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 an 

individual fuel or combination of fuels during a period of 12 consecutive calendar months and the 

potential heat input to the steam generating unit from all fuels had the steam generating unit been 

operated for 8,760 hours during that 12-month period at the maximum design heat input capacity. In the 

case of steam generating units that are rented or leased, the actual heat input shall be determined based 

Comment [CF1]: Clarify broad definition to be

consistent with broad definition of affected facility

under KKKK – fuel heater, etc.

Comment [CF2]: Exempt owner/operators of

CISWI facilities from subpart Dc  

Comment [CF3]: Similar exemption/rational as

in Db to avoid double coverage.

Comment [CF4]: Exempt temporary boilers that

burn fuels with lower emission rates
2

on the combined heat input from all operations of the affected facility during a period of 12 consecutive 

calendar months. 

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 derived from coal for the purposes of creating 

useful heat, including but not limited to solvent refined coal, gasified coal not meeting the definition of 

natural gas, coal-oil mixtures, and coal-water mixtures, are also included in this definition for the 

purposes of this subpart. 

Coal refuse means any by-product 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 kilojoules per kilogram (kJ/kg) (6,000 

Btu per pound (Btu/lb) on a dry basis. 

Cogeneration steam generating unit means a steam generating unit that simultaneously produces both 

electrical (or mechanical) and thermal energy from the same primary energy source.

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

internal combustion engine, or kiln) provides exhaust gas to a steam generating unit. 

Combustion research means the experimental firing of any fuel or combination of fuels in a steam 

generating unit for the purpose of conducting research and development of more efficient combustion or 

more effective prevention or control of air pollutant emissions from combustion, provided that, during 

these periods of research and development, the heat generated is not used for any purpose other than 

preheating combustion air for use by that steam generating unit ( i.e. , the heat generated is released to 

the atmosphere without being used for space heating, process heating, driving pumps, preheating 

combustion air for other units, generating electricity, or any other purpose). 

Conventional technology means wet flue gas desulfurization technology, dry flue gas desulfurization 

technology, atmospheric fluidized bed combustion technology, and oil hydrodesulfurization technology. 

Distillate oil means fuel oil that complies with the specifications for fuel oil numbers 1 or 2, as defined 

by the American Society for Testing and Materials in ASTM D396 (incorporated by reference, see 

§60.17) or), diesel fuel oil numbers 1 or 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 between the steam 

generating unit and the exhaust vent or stack, and that 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 reagents used in dry flue gas desulfurization systems include, but are not limited to, lime 

and sodium compounds. 

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. 

Comment [CF5]: Delete since not used in

subpart Dc.

Comment [CF6]: Expand definitions to include

other similar fuels.   
3

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 affected facility has received approval 

from the Administrator to operate as an emerging technology under §60.48c(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 a device wherein fuel is distributed onto a bed (or series of 

beds) of limestone aggregate (or other sorbent materials) for combustion; and these materials are forced 

upward in the device by the flow of combustion air and the gaseous products of combustion. Fluidized 

bed combustion technology includes, but is not limited to, bubbling bed units and circulating bed units. 

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. 

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 stationary gas turbines, internal combustion engines, and kilns). 

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

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

maximum amount of fuel (or combination of fuels) on a steady state basis as determined by the physical 

design and characteristics of the steam generating unit. 

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 (LP) 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). 

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 oil and residual oil. 

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. 

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. 

Residual oil means crude oil, fuel oil that does not comply with the specifications under the definition of 

distillate oil, and all fuel oil numbers 4, 5, and 6, as defined by the American Society for Testing and 

Materials in ASTM D396 (incorporated by reference, see §60.17). 
4

Steam generating unit means a device that combusts any fuel and produces steam or heats water or heats 

any heat transfer medium. This term includes any duct burner that combusts fuel and is part of a 

combined cycle system. This term does not include process heaters as 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 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.

(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. 

Wet flue gas desulfurization technology means an SO2control system that is located between the steam 

generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases 

of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution and 

forming a liquid material. This definition includes devices where the liquid material is subsequently 

converted to another form. Alkaline reagents used in wet flue gas desulfurization systems include, but 

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

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. 

§60.42c Standard for sulfur dioxide (SO2). 

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

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 combusts only coal shall neither: cause to be discharged 

into the atmosphere from the affected facility any gases that contain SO2in excess of 87 ng/J (0.20 

lb/MMBtu) heat input or 10 percent (0.10) of the potential SO2emission rate (90 percent reduction), nor 

cause to be discharged into the atmosphere from the affected facility any gases that contain SO2in excess 

of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is combusted with other fuels, the affected facility shall 

neither: cause to be discharged into the atmosphere from the affected facility any gases that contain 

SO2in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO2emission 

rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected facility any 

Comment [CF7]: Need definition for exemption

– limited to fuels with lower emission rates
5

gases that contain SO2in excess of the emission limit is determined pursuant to paragraph (e)(2) of this 

section. 

(b) Except as provided in paragraphs (c) and (e) of this section, on and after the date on which the 

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: 

(1) Combusts only coal refuse alone in a fluidized bed combustion steam generating unit shall neither: 

(i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in 

excess of 87 ng/J (0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential SO2emission rate (80 

percent reduction); nor 

(ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in 

excess of SO2in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is fired with coal refuse, the 

affected facility subject to paragraph (a) of this section. If oil or any other fuel (except coal) is fired with 

coal refuse, the affected facility is subject to the 87 ng/J (0.20 lb/MMBtu) heat input SO2emissions limit 

or the 90 percent SO2reduction requirement specified in paragraph (a) of this section and the emission 

limit is determined pursuant to paragraph (e)(2) of this section. 

(2) Combusts only coal and that uses an emerging technology for the control of SO2emissions shall 

neither: 

(i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in 

excess of 50 percent (0.50) of the potential SO2emission rate (50 percent reduction); nor 

(ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO2in 

excess of 260 ng/J (0.60 lb/MMBtu) heat input. If coal is combusted with other fuels, the affected 

facility is subject to the 50 percent SO2reduction requirement specified in this paragraph and the 

emission limit determined pursuant to paragraph (e)(2) of this section. 

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

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

alone or in combination with any other fuel, and is listed in paragraphs (c)(1), (2), (3), or (4) of this 

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

SO2in excess of the emission limit determined pursuant to paragraph (e)(2) of this section. Percent 

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

(1) Affected facilities that have a heat input capacity of 22 MW (75 MMBtu/hrh) or less.;

(2) Affected facilities that have an annual capacity for coal of 55 percent (0.55) or less and are subject 

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

factor for coal of 55 percent (0.55) or less.; 

(3) Affected facilities located in a noncontinental area.; or

(4) Affected facilities that combust coal 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 in the 

duct burner and 70 percent (0.70) or more of the heat entering the steam generating unit is from exhaust 

gases entering the duct burner. 

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

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

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

excess of 215 ng/J (0.50 lb/MMBtu) heat input from oil; or, as an alternative, no owner or operator of an Comment [CF8]: Clarify that cannot dilute with

natural gas
6

affected facility that combusts oil shall combust oil in the affected facility that contains greater than 0.5 

weight percent sulfur. The percent reduction requirements are not applicable to affected facilities under 

this paragraph. 

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

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

oil, or coal and oil with any other fuel shall cause to be discharged into the atmosphere from that 

affected facility any gases that contain SO2in excess of the following: 

(1) The percent of potential SO2emission rate or numerical SO2emission rate required under paragraph 

(a) or (b)(2) of this section, as applicable, for any affected facility that 

(i) Combusts coal in combination with any other fuel; 

(ii) Has a heat input capacity greater than 22 MW (75 MMBtu/hrh); and 

(iii) Has an annual capacity factor for coal greater than 55 percent (0.55); and 

(2) The emission limit determined according to the following formula for any affected facility that 

combusts coal, oil, or coal and oil with any other fuel: 

Where: 

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

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

Kb= 260 ng/J (0.60 lb/MMBtu); 

Kc= 215 ng/J (0.50 lb/MMBtu); 

Ha= Heat input from the combustion of coal, except coal combusted in an affected facility subject to 

paragraph (b)(2) of this section, in Joules (J) [MMBtu]; 

Hb= Heat input from the combustion of coal in an affected facility subject to paragraph (b)(2) of this 

section, in J (MMBtu); and 

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

(f) Reduction in the potential SO2emission rate through fuel pretreatment is not credited toward the 

percent reduction requirement under paragraph (b)(2) of this section unless:

(1) Fuel pretreatment results in a 50 percent (0.50) or greater reduction in the potential SO2emission 

rate; and

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

equal to or less than the emission limits specified under paragraph (b)(2) of this section.

(f) [RESERVED]

(g) Except as provided in paragraph (h) of this section, compliance with the percent reduction 

requirements, fuel oil sulfur limits, and emission limits of this section shall be determined on a 30-day 

rolling average basis. 

Comment [CF9]: Remove restriction of fuel

pretreatement.
7

(h) For affected facilities listed under paragraphs (h)(1), (2), (3), or (3)4) of this section, compliance 

with the emission limits or fuel oil sulfur limits under this section may be determined based on a 

certification from the fuel supplier, as described under §60.48c(f), as applicable. 

(1) Distillate oil-fired affected facilities with heat input capacities between 2.9 and 29 MW (10 and 100 

MMBtu/hrh). 

(2) Residual oil-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 

MMBtu/hrh). 

(3) Coal-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 

MMBtu/hrh).

(4) Other fuels-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 

MMBtu/h). 

(i) The SO2emission limits, fuel oil sulfur limits, and percent reduction requirements under this section 

apply at all times, including periods of startup, shutdown, and malfunction. 

(j) For affected facilities located in noncontinental areas and affected 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 under this section. No credit is provided for the heat input to the affected facility 

from wood or other fuels or for heat derived from exhaust gases from other sources, such as stationary 

gas turbines, internal combustion engines, and kilns. 

§60.43c Standard for particulate matter (PM). 

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

under §60.8, whichever date comes first, no owner or operator 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 and has a heat input capacity of 8.7 MW (30 MMBtu/hrh) or 

greater, 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 if the affected facility combusts only coal, or combusts coal 

with 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 with other fuels, 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. 

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

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

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

combusts mixtures of wood with other fuels (except coal) and has a heat input capacity of 8.7 MW (30 

MMBtu/hrh) or greater, shall cause to be discharged into the atmosphere from that affected facility any 

gases that contain PM in excess of the following emissions limits: 

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

greater than 30 percent (0.30); or 

(2) 130 ng/J (0.30 lb/MMBtu) heat input if the affected facility has an annual capacity factor for wood of 

30 percent (0.30) or less and is subject to a federally enforceable requirement limiting operation of the 

affected facility to an annual capacity factor for wood of 30 percent (0.30) or less. 

Comment [CF10]: Add to be consistent with

60.48c(f)
8

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

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

combustcombusts coal, wood, or oil and has a heat input capacity of 8.7 MW (30 MMBtu/hrh) or greater 

shall cause to be discharged into the atmosphere from that affected facility 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 operators of an affected facility that elect 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 subject to a federally enforceable PM limit of 0.030 lb/MMBtu 

or less are exempt from the opacity standard specified in this paragraph. 

(d) The PM and opacity standards under this section apply at all times, except during periods of startup, 

shutdown, or malfunction. 

(e)(1) 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, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels and has a heat 

input capacity of 8.7 MW (30 MMBtu/hrh) or greater 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, 

except as provided in paragraphs (e)(2), (e)(3), and (e)(4) of this section. 

(2) As an alternative to meeting the requirements of paragraph (e)(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, whichever date comes first, 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 heat input capacity of 8.7 MW (30 MMBtu/hrh) or greater 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, an(4) An owner or operator of an affected facility 

that commences construction, reconstruction, or modification after February 28, 2005, and that combusts 

only oil that contains no more than 0.50 weight percent sulfur or a mixture of 0.50 weight percent sulfur 

oil with other fuels not subject to a PM standard under §60.43c and not using a post-combustion 

technology (except a wet scrubber) to reduce PM or SO2 emissions is not subject to the PM limit in this 

section. 

§60.44c Compliance and performance test methods and procedures for sulfur dioxide. 

Comment [CF11]: Clarify opacity standard does

not apply when firing natural gas

Comment [CF12]: Introduction not necessary
9

(a) Except as provided in paragraphs (g) and (h) of this section and §60.8(b), performance tests required 

under §60.8 shall be conducted following the procedures specified in paragraphs (b), (c), (d), (e), and (f) 

of this section, as applicable. 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. 

(b) The initial performance test required under §60.8 shall be conducted over 30 consecutive operating 

days of the steam generating unit. Compliance with the percent reduction requirements and SO2emission 

limits under §60.42c 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 affect facility will be operated, but not later than 180 days after the initial startup of the 

facility. The steam generating unit load during the 30-day period does not have to be the maximum 

design heat input capacity, but must be representative of future operating conditions. 

(c) After the initial performance test required under paragraph (b) of this section and §60.8, compliance 

with the percent reduction requirements and SO2emission limits under §60.42c is based on the average 

percent reduction and the average SO2emission rates for 30 consecutive steam generating unit operating 

days. A separate performance test is completed at the end of each steam generating unit operating day, 

and a new 30-day average percent reduction and SO2emission rate are calculated to show compliance 

with the standard. 

(d) If only coal, only oil, or a mixture of coal and oil is combusted in an affected facility, the procedures 

in Method 19 of appendix A of this part are used to determine the hourly SO2emission rate (Eho) and the 

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

obtained from the CEMS. Method 19 of appendix A of this part shall be used to calculate Eaowhen using 

daily fuel sampling or Method 6B of appendix A of this part. 

(e) If coal, oil, or coal and oil are combusted with other fuels: 

(1) An adjusted Eho(Ehoo) is used in Equation 19–19 of Method 19 of appendix A of this part to compute 

the adjusted Eao(Eaoo). The Ehoo is computed using the following formula: 

Where: 

Ehoo = Adjusted Eho, 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 fuel sampling and analysis procedures in Method 9 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. 

The owner or operator does not have to measure Ewif the owner or operator elects to assume Ew= 0. 

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

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

(2) The owner or operator of an affected facility that qualifies under the provisions of §60.42c(c) or (d) 

(where percent reduction is not required) does not have to measure the parameters Ewor Xkif the owner 

or operator of the affected facility elects to measure emission rates of the coal or oil using the fuel 

sampling and analysis procedures under Method 19 of appendix A of this part. 
10

(f) Affected facilities subject to the percent reduction requirements under §60.42c(a) or (b) shall 

determine compliance with the SO2emission limits under §60.42c pursuant to paragraphs (d) or (e) of 

this section, and shall determine compliance with the percent reduction requirements using the following 

procedures: 

(1) If only coal is combusted, the percent of potential SO2emission rate is computed using the following 

formula: 

Where: 

%Ps= Potential SO2emission rate, in 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. 

(2) If coal, oil, or coal and oil are combusted with other fuels, the same procedures required in paragraph 

(f)(1) of this section are used, except as provided for in the following: 

(i) To compute the %Ps, an adjusted %Rg(%Rgo) is computed from Eaoo from paragraph (e)(1) of this 

section and an adjusted average SO2inlet rate (Eaio) using the following formula: 

Where: 

%Rgo = Adjusted %Rg, in percent; 

Eaoo = Adjusted Eao, ng/J (lb/MMBtu); and 

Eaio = Adjusted average SO2inlet rate, ng/J (lb/MMBtu). 

(ii) To compute Eaio, an adjusted hourly SO2inlet rate (Ehio) is used. The Ehio is computed using the 

following formula: 

Where: 

Ehio = Adjusted Ehi, ng/J (lb/MMBtu); 

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

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

by 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 
11

combusted. The owner or operator does not have to measure Ewif the owner or operator elects to assume 

Ew= 0; and 

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

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

(g) For oil-fired affected facilities where the owner or operator seeks to demonstrate compliance with 

the fuel oil sulfur limits under §60.42c based on shipment fuel sampling, the initial performance test 

shall consist of sampling and analyzing the oil in the initial tank of oil to be fired in the steam generating 

unit to demonstrate that the oil contains 0.5 weight percent sulfur or less. Thereafter, the owner or 

operator of the affected facility shall sample the oil in the fuel tank after each new shipment of oil is 

received, as described under §60.46c(d)(2). 

(h) For affected facilities subject to §60.42c(h)(1), (2), or (3) where the owner or operator seeks to 

demonstrate compliance with the SO2standards based on fuel supplier certification, the performance test 

shall consist of the certification from the fuel supplier, as described in §60.48c(f), as applicable. 

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

SO2standards under §60.42c(c)(2) shall demonstrate the maximum design heat input capacity of the 

steam generating unit by operating the steam generating unit at this capacity for 24 hours. This 

demonstration shall be made during the initial performance test, and a subsequent demonstration may be 

requested at any other time. If the demonstrated 24-hour average firing rate for the affected facility is 

less than the maximum design heat input capacity stated by the manufacturer of the affected facility, the 

demonstrated 24-hour average firing rate shall be used to determine the annual capacity factor for the 

affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer shall 

be used. 

(j) The owner or operator of an affected facility shall use all valid SO2emissions data in calculating 

%Psand Ehounder paragraphs (d), (e), or (f) of this section, as applicable, whether or not the minimum 

emissions data requirements under §60.46c(f) are achieved. All valid emissions data, including valid 

data collected during periods of startup, shutdown, and malfunction, shall be used in calculating %Psor 

Ehopursuant to paragraphs (d), (e), or (f) of this section, as applicable. 

§60.45c Compliance and performance test methods and procedures for particulate matter. 

(a) The owner or operator of an affected facility subject to the PM and/or opacity standards under 

§60.43c shall conduct an initial performance test as required under §60.8, and shall conduct subsequent 

performance tests as requested by the Administrator, to determine compliance with the standards using 

the following procedures and reference methods, except as specified in paragraph (c) of this section. 

(1) Method 1 of appendix A of this part shall be used to select the sampling site and the number of 

traverse sampling points. 

(2) Method 3A or 3B of appendix A–2 of this part shall be used for gas analysis when applying Method 

5 or 5B of appendix A–3 of this part or 17 of appendix A–6 of this part. 

(3) 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 may be used only at affected facilities without wet scrubber 

systems. 

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

systems provided the stack gas temperature does not exceed a temperature of 160 °C (320 °F). The 
12

procedures of Sections 8.1 and 11.1 of Method 5B of appendix A of this part may be used in Method 17 

of appendix A of this part only if Method 17 of appendix A of this part is used in conjunction with a wet 

scrubber system. Method 17 of appendix A of this part shall not be used in conjunction with a wet 

scrubber system if the effluent is saturated or laden with water droplets. 

(iii) Method 5B of appendix A of this part may be used in conjunction with a wet scrubber system. 

(4) The sampling time for each run shall be at least 120 minutes and the minimum sampling volume 

shall be 1.7 dry standard cubic meters (dscm) [60 dry standard cubic feet (dscf)] except that smaller 

sampling times or volumes may be approved by the Administrator when necessitated by process 

variables or other factors. 

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

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

(6) For determination of PM emissions, an oxygen (O2) or carbon dioxide (CO2) measurement shall be 

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. 

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

ng/J (lb/MMBtu) heat input shall be determined using: 

(i) The O2or CO2measurements and PM measurements obtained under this section, (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. 

(8) Method 9 of appendix A–4 of this part shall be used for determining the opacity of stack emissions. 

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

standards under §60.43c(b)(2) shall demonstrate the maximum design heat input capacity of the steam 

generating unit by operating the steam generating unit at this capacity for 24 hours. This demonstration 

shall be made during the initial performance test, and a subsequent demonstration may be requested at 

any other time. If the demonstrated 24-hour average firing rate for the affected facility is less than the 

maximum design heat input capacity stated by the manufacturer of the affected facility, the 

demonstrated 24-hour average firing rate shall be used to determine the annual capacity factor for the 

affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer shall 

be used. 

(c) 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 install, calibrate, maintain, and operate a CEMS and shall comply with 

the requirements specified in paragraphs (c)(1) through (c)(14) of this section. 

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

(2) Notify the Administrator 1 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. 
13

(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 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 (d) 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 paragraph (c)(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] 

(8) The 1-hour arithmetic averages required under paragraph (c)(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 (c)(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 on a 

30-day rolling average. 

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

required by paragraph (c)(11) of this section, the owner or operator of the affected facility must either 

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

base available at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main or mail a copy to: United 
14

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.

(d) The owner or operator of an affected facility seeking to demonstrate compliance under §60.43c(e)(4) 

shall follow the applicable procedures under §60.48c(f). For residual oil-fired affected facilities, fuel 

supplier certifications are only allowed for facilities with heat input capacities between 2.9 and 8.7 MW 

(10 to 30 MMBtu/hrh). 

§60.46c Emission monitoring for sulfur dioxide. 

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

facility subject to the SO2emission limits under §60.42c shall install, calibrate, maintain, and operate a 

CEMS for measuring SO2concentrations and either O2or CO2concentrations at the outlet of the 

SO2control device (or the outlet of the steam generating unit if no SO2control device is used), and shall 

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

reduction requirements under §60.42c shall measure SO2concentrations and either O2or 

CO2concentrations at both the inlet and outlet of the SO2control device. 

(b) The 1-hour average SO2emission rates measured by a CEMS shall be expressed in ng/J or lb/MMBtu 

heat input and shall be used to calculate the average emission rates under §60.42c. Each 1-hour average 

SO2emission rate must be based on at least 30 minutes of operation, and shall be calculated using the 

data points required under §60.13(h)(2). Hourly SO2emission rates are not calculated if the affected 

facility is operated less than 30 minutes in a 1-hour period and are not counted toward determination of a 

steam generating unit operating day. 

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

CEMS. 

(1) 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) 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 subject to the percent reduction requirements under §60.42c, the span value of 

the SO2CEMS at the inlet to the SO2control device shall be 125 percent of the maximum estimated 

hourly potential SO2emission rate of the fuel combusted, and the span value of the SO2CEMS at the 

outlet from the SO2control device shall be 50 percent of the maximum estimated hourly potential 

SO2emission rate of the fuel combusted. 

(4) For affected facilities that are not subject to the percent reduction requirements of §60.42c, the span 

value of the SO2CEMS at the outlet from the SO2control device (or outlet of the steam generating unit if 

no SO2control device is used) shall be 125 percent of the maximum estimated hourly potential 

SO2emission rate of the fuel combusted. 

Comment [CF13]: Updated language for

electronic reporting.
15

(d) As an alternative to operating a CEMS at the inlet to the SO2control device (or outlet of the steam 

generating unit if no SO2control device is used) as required under paragraph (a) of this section, an owner 

or operator may elect to determine the average SO2emission rate by sampling the fuel prior to 

combustion. As an alternative to operating a CEMS at the outlet from the SO2control device (or outlet of 

the steam generating unit if no SO2control device is used) as required under paragraph (a) of this section, 

an owner or operator may elect to determine the average SO2emission rate by using Method 6B of 

appendix A of this part. Fuel sampling shall be conducted pursuant to either paragraph (d)(1) or (d)(2) of 

this section. Method 6B of appendix A of this part shall be conducted pursuant to paragraph (d)(3) of 

this section. 

(1) For affected facilities combusting coal or oil, coal or oil samples shall be collected daily in an asfired condition at the inlet to the steam generating unit and analyzed for sulfur content and heat content 

according the 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. 

(2) As an alternative fuel sampling procedure for affected facilities combusting oil, oil samples may be 

collected from the fuel tank for each steam generating unit immediately after the fuel tank is filled and 

before any oil is combusted. The owner or operator of the affected facility shall analyze the oil sample to 

determine the sulfur content of the oil. If a partially empty fuel tank is refilled, a new sample and 

analysis of the fuel in the tank would be required upon filling. Results of the fuel analysis taken after 

each new shipment of oil is received shall be used as the daily value when calculating the 30-day rolling 

average until the next shipment is received. If the fuel analysis shows that the sulfur content in the fuel 

tank is greater than 0.5 weight percent sulfur, the owner or operator shall ensure that the sulfur content 

of subsequent oil shipments is low enough to cause the 30-day rolling average sulfur content to be 0.5 

weight percent sulfur or less. 

(3) Method 6B of appendix A of this part may be used in lieu of CEMS to measure SO2at the inlet or 

outlet of 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 §3.2 and the applicable procedures in section 7 of 

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

6A of appendix A of this part, or a combination of Methods 6 and 3 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 (0.10). 

(e) The monitoring requirements of paragraphs (a) and (d) of this section shall not apply to affected 

facilities subject to §60.42c(h) (1), (2), or (3) where the owner or operator of the affected facility seeks 

to demonstrate compliance with the SO2standards based on fuel supplier certification, as described under 

§60.48c(f), as applicable. 

(f) The owner or operator of an affected facility operating a CEMS pursuant to paragraph (a) of this 

section, or conducting as-fired fuel sampling pursuant to paragraph (d)(1) of this section, shall obtain 

emission data for at least 75 percent of the operating hours in at least 22 out of 30 successive steam 

generating unit operating days. If this minimum data requirement is not met with a single monitoring 
16

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. 

§60.47c Emission monitoring for particulate matter. 

(a) Except as provided in paragraphs (c), (d), (e), and (f), and (g) of this section, the owner or operator of 

an affected facility combusting coal, oil, or wood that is subject to the opacity standards under §60.43c 

shall install, calibrate, maintain, and operate a continuous opacity monitoring system (COMS) for 

measuring the opacity of the 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 in §60.43c(c) and 

that is not required to install a COMS due to paragraphs (c), (d), (e), or (f), of this section that 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 §60.43c 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 

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 

Comment [CF14]: Allow flexibility to account

for intermittent use of fuels with an opacity

standard.
17

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 §60.45c(a)(8). 

(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) All COMS shall be operated in accordance with the applicable procedures under Performance 

Specification 1 of appendix B of this part. The span value of the opacity COMS shall be between 60 and 

80 percent. 

(c) Owners and operators of an affected facilities that burn only distillate oil that contains no more than 

0.5 weight percent sulfur and/or liquid or gaseous fuels with potential sulfur dioxide emission rates of 26 

ng/J (0.060 lb/MMBtu) heat input or less and that do not use a post-combustion technology to reduce 

SO2 or PM emissions and that are subject to an opacity standard in §60.43c(c) are not required to 

operate a COMS if they follow the applicable procedures in §60.48c(f). 

(d) 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 §60.45c(c). The CEMS specified in paragraph §60.45c(c) 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. 

(e) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and 

that 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 0.5 

weight percent sulfur, and is operated such that emissions of CO discharged to the atmosphere from the 

affected facility are maintained at levels less than or equal to 0.15 lb/MMBtu on a boiler operating day 

average basis is not required to operate a COMS. Owners and operators of affected facilities electing to 

Comment [CF15]: Decrease required number of

days without visible emissions to reduce burden to

regulated community
18

comply with this paragraph must demonstrate compliance according to the procedures specified in 

paragraphs (e)(1) through (4) of this section; or 

(1) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs 

(e)(1)(i) through (iv) of this section. 

(i) The CO CEMS must be installed, certified, maintained, and operated according to the provisions in 

§60.58b(i)(3) of subpart Eb of this part. 

(ii) Each 1-hour CO emissions average is calculated using the data points generated by the CO CEMS 

expressed in parts per million by volume corrected to 3 percent oxygen (dry basis). 

(iii) At a minimum, 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). 

(iv) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be 

performed in accordance with procedure 1 in appendix F of this part. 

(2) You must calculate the 1-hour average CO emissions levels for each 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. 

(3) 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. 

(4) You must record the CO measurements and calculations performed according to paragraph (e) 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. 

(f) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and 

that uses a bag leak detection system to monitor the performance of a fabric filter (baghouse) according 

to the most recent requirements in section §60.48Da of this part is not required to operate a COMS.

(g) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and 

that burns only gaseous fuels or fuel oils that contain less than or equal to 0.5 weight percent sulfur and 

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. 

(f) An owner or operator of an affected facility that is subject to an opacity standard in under §60.43c(c) 

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

paragraphs (f)(1), (2), or (3) of this section.
19

(1) The affected facility uses a fabric filter (baghouse) as the primary PM control device and, the owner 

or operator operates a bag leak detection system to monitor the performance of the fabric filter 

according to the requirements in section §60.48Da of this part

(2) The affected facility uses an ESP as the primary PM control device, and the owner or operator uses 

an ESP predictive model to monitor the performance of the ESP developed in accordance and operated 

according to the requirements in section §60.48Da of this part.

(3) The affected facility burns only gaseous fuels and/or fuel oils that contain no greater than 0.5 weight 

percent sulfur, and the owner or operator operates the unit according to a written site-specific monitoring 

plan approved by the permitting authority. This monitoring plan must include procedures and criteria for 

establishing and monitoring specific parameters for the affected facility indicative of compliance with 

the opacity standard. For testing performed as part of this site-specific monitoring plan, the permitting 

authority may require as an alternative to the notification and reporting requirements specified in §§60.8 

and 60.11 that the owner or operator submit any deviations with the excess emissions report required 

under §60.48c(c). 

§60.48c Reporting and recordkeeping requirements. 

(a) The owner or operator of each affected facility shall submit notification of the date of construction or 

reconstruction and actual startup, as provided by §60.7 of this part. This notification shall include: 

(1) The design heat input capacity of the affected facility and identification of 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 §60.42c, or §60.43c. 

(3) The annual capacity factor at which the owner or operator anticipates operating the affected facility 

based on all fuels fired and based on each individual fuel fired. 

(4) Notification if an emerging technology will be used for controlling SO2emissions. The Administrator 

will examine the description of the control device 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 §60.42c(a) or (b)(1), unless and until this determination is 

made by the Administrator. 

(b) The owner or operator of each affected facility subject to the SO2emission limits of §60.42c, or the 

PM or opacity limits of §60.43c, shall submit to the Administrator the performance test data from the 

initial and any subsequent performance tests and, if applicable, the performance evaluation of the CEMS 

and/or COMS using the applicable performance specifications in appendix B of this part. 

(c) In addition to the applicable requirements in §60.7, the owner or operator of an affected facility 

subject to the opacity limits in §60.43c(c) shall submit excess emission reports for any excess emissions 

from the affected facility that occur during the reporting period and maintain records according to the 

requirements specified in paragraphs (c)(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 (c)(1)(i) through (iii) of 

this section. 

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

Comment [CF16]: Add ESP model to COMS

exemption options

Comment [CF17]: Clarify can burn gaseous fuels

along with low S oil

Comment [CF18]: Add additional flexibility for

the permitting authority to reduce burden to the

regulated community
20

(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 (c)(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 

(d) The owner or operator of each affected facility subject to the SO2emission limits, fuel oil sulfur 

limits, or percent reduction requirements under §60.42c shall submit reports to the Administrator. 

(e) The owner or operator of each affected facility subject to the SO2emission limits, fuel oil sulfur 

limits, or percent reduction requirements under §60.42c shall keep records and submit reports as 

required under paragraph (d) of this section, including the following information, as applicable. 

(1) Calendar dates covered in the reporting period. 

(2) Each 30-day average SO2emission rate (ng/J or lb/MMBtu), or 30-day average sulfur content (weight 

percent), calculated during the reporting period, ending with the last 30-day period; reasons for any 

noncompliance with the emission standards; and a description of corrective actions taken. 

(3) Each 30-day average percent of potential SO2emission rate calculated during the reporting period, 

ending with the last 30-day period; reasons for any noncompliance with the emission standards; and a 

description of the corrective actions taken. 

(4) Identification of any steam generating unit operating days for which SO2or diluent (O2or 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 a description of corrective actions taken. 

(5) Identification of any times when emissions data have been excluded from the calculation of average 

emission rates; justification for excluding data; and a description of corrective actions 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 the F factor used in calculations, method of determination, and type of fuel 

combusted. 

(7) Identification of whether averages have been obtained based on CEMS rather than manual sampling 

methods. 

(8) If a CEMS is used, identification of any times when the pollutant concentration exceeded the full 

span of the CEMS. 
21

(9) If a CEMS is used, description of any modifications to the CEMS that could affect the ability of the 

CEMS to comply with Performance Specifications 2 or 3 of appendix B of this part. 

(10) If a CEMS is used, results of daily CEMS drift tests and quarterly accuracy assessments as required 

under appendix F, Procedure 1 of this part. 

(11) If fuel supplier certification is used to demonstrate compliance, records of fuel supplier certification 

as described under paragraph (f)(1), (2), (3), or (4) of this section, as applicable. In addition to records of 

fuel supplier certifications, the report shall include a certified statement signed by the owner or operator 

of the affected facility that the records of fuel supplier certifications submitted represent all of the fuel 

combusted during the reporting period. 

(f) Fuel supplier certification shall include the following information: 

(1) For distillate oil: 

(i) The name of the oil supplier; 

(ii) A statement from the oil supplier that the oil complies with the specifications under the definition of 

distillate oil in §60.41c; and 

(iii) The sulfur content or maximum sulfur content of the oil. 

(2) For residual oil: 

(i) The name of the oil supplier; 

(ii) The location of the oil when the sample was drawn for analysis to determine the sulfur content of the 

oil, specifically including whether the oil was sampled as delivered to the affected facility, or whether 

the sample was drawn from oil in storage at the oil supplier's or oil refiner's facility, or other location; 

(iii) The sulfur content of the oil from which the shipment came (or of the shipment itself); and 

(iv) The method used to determine the sulfur content of the oil. 

(3) For coal: 

(i) The name of the coal supplier; 

(ii) The location of the coal when the sample was collected for analysis to determine the properties of 

the coal, specifically including whether the coal was sampled as delivered to the affected facility or 

whether the sample was collected from coal in storage at the mine, at a coal preparation plant, at a coal 

supplier's facility, or at another location. The certification shall include the name of the coal mine (and 

coal seam), coal storage facility, or coal preparation plant (where the sample was collected); 

(iii) The results of the analysis of the coal from which the shipment came (or of the shipment itself) 

including the sulfur content, moisture content, ash content, and heat content; and 

(iv) The methods used to determine the properties of the coal. 

(4) For other fuels: 

(i) The name of the supplier of the fuel; 

(ii) The potential sulfur emissions rate or maximum potential sulfur emissions rate of the fuel in ng/J 

heat input; and 

(iii) The method used to determine the potential sulfur emissions rate of the fuel. 
22

(g)(1) Except as provided under paragraphs (g)(2) and (g)(3) of this section, the owner or operator of 

each affected facility shall record and maintain records of the amount of each fuel combusted during 

each operating day. 

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

operator of an affected facility that combusts only natural gas, wood, fuels using fuel certification in 

§60.48c(f) to demonstrate compliance with the SO2standard, fuels not subject to an emissions standard 

(excluding opacity), or a mixture of these fuels may elect to record and maintain records of the amount 

of each fuel combusted during each calendar month. 

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

operator of an affected facility or multiple affected facilities located on a contiguous property unit where 

the only fuels combusted in any steam generating unit (including steam generating units not subject to 

this subpart) at that property are natural gas, wood, distillate oil meeting the most current requirements 

in §60.42C to use fuel certification to demonstrate compliance with the SO2standard, and/or fuels, 

excluding coal and residual oil, not subject to an emissions standard (excluding opacity) may elect to 

record and maintain records of the total amount of each steam generating unit fuel delivered to that 

property during each calendar month. 

(h) The owner or operator of each affected facility subject to a federally enforceable requirement 

limiting the annual capacity factor for any fuel or mixture of fuels under §60.42c or §60.43c shall 

calculate the annual capacity factor individually for each fuel combusted. The annual capacity factor is 

determined on a 12-month rolling average basis with a new annual capacity factor calculated at the end 

of the calendar month. 

(i) All records required under this section shall be maintained by the owner or operator of the affected 

facility for a period of two years following the date of such record. 

(j) The reporting period for the reports required under this subpart is each six-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.