Subpart D—Standards of Performance for Fossil-Fuel-Fired Steam Generators for Which 

Construction Is Commenced After August 17, 1971

§60.40 Applicability and designation of affected facility. 

(a) The affected facilities to which the provisions of this subpart apply are: 

(1) Each fossil-fuel-fired steam generating unit of more than 73 megawatts (MW) heat input rate (250 

million British thermal units per hour (MMBtu/hr)). 

(2) Each fossil-fuel and wood-residue-fired steam generating unit capable of firing fossil fuel at a heat 

input rate of more than 73 MW (250 MMBtu/hr). 

(b) Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of 

combustible materials, other than fossil fuels as defined in this subpart, shall not bring that unit under 

the applicability of this subpart. 

(c) Except as provided in paragraph (d) of this section, any facility under paragraph (a) of this section 

that commenced construction or modification after August 17, 1971, is subject to the requirements of 

this subpart. 

(d) The requirements of §§60.44 (a)(4), (a)(5), (b) and (d), and 60.45(f)(4)(vi) are applicable to lignitefired steam generating units that commenced construction or modification after December 22, 1976. 

(e) Any facility covered under either subpart Da or KKKK is not covered under this subpart. 

§60.41 Definitions. 

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

subpart A of this part. 

Boiler operating day means a 24-hour period between 12 midnight and the following midnight during 

which any fuel is combusted at any time in the steam-generating unit. It is not necessary for fuel to be 

combusted the entire 24-hour period. 

Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by ASTM D388 

(incorporated by reference, see §60.17). 

Coal refuse means waste-products of coal mining, cleaning, and coal preparation operations (e.g. culm, 

gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material. 

Fossil fuel means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived 

from such materials for the purpose of creating useful heat. 

Fossil fuel and wood residue-fired steam generating unit means a furnace or boiler used in the process 

of burning fossil fuel and wood residue for the purpose of producing steam by heat transfer. 

Fossil-fuel-fired steam generating unit means a furnace or boiler used in the process of burning fossil 

fuel for the purpose of producing steam by heat transfer. 

Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at 

least 70 percent methane by volume or that has a gross calorific value between 35 and 41 megajoules 

(MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a 

gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur 

per 100 standard cubic feet. Finally, natural gas does not include the following gaseous fuels: landfill 

gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, 

or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating 

value.

Comment [CF1]: Simplify title.

Comment [CF2]: Adjusting applicability since

heat recovery steam generators covered under Da

reverted to D after they were exempted from Da.  

The intent of KKKK is to cover the HRSG in combined

cycle and CHP facilities and to exempt them from all

boiler NSPS.

Comment [CF3]: Definition required for PM

exemption.
Wood residue means bark, sawdust, slabs, chips, shavings, mill trim, and other wood products derived 

from wood processing and forest management operations. 

§60.42 Standard for particulate matter (PM). 

(a) Except as provided under paragraphs (b), (c), (d), and (e) of this section, oOn and after the date on 

which the performance test required to be conducted by §60.8 is completed, no owner or operator 

subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any 

affected facility any gases that: 

(1) Contain PM in excess of 43 nanograms per joule (ng/J) heat input (0.10 lb/MMBtu) derived from 

fossil fuel or fossil fuel and wood residue. 

(2) Exhibit greater than 20 percent opacity except for one six-minute period per hour of not more than 

27 percent opacity. 

(b)(1) On or after December 28, 1979, no owner or operator shall cause to be discharged into the 

atmosphere from the Southwestern Public Service Company's Harrington Station #1, in Amarillo, TX, 

any gases which exhibit greater than 35 percent opacity, except that a maximum or 42 percent opacity 

shall be permitted for not more than 6 minutes in any hour. 

(2) Interstate Power Company shall not cause to be discharged into the atmosphere from its Lansing 

Station Unit No. 4 in Lansing, IA, any gases which exhibit greater than 32 percent opacity, except that a 

maximum of 39 percent opacity shall be permitted for not more than six minutes in any hour. 

(c) As an alternate to meeting the requirements of paragraph (a) of this section, an owner or operator that 

elects to install, calibrate, maintain, and operate a continuous emissions monitoring systems (CEMS) for 

measuring PM emissions can petition the Administrator (in writing) to comply with §60.42Da(a) of 

subpart Da of this part. If the Administrator grants the petition, the source will from then on (unless the 

unit is modified or reconstructed in the future) have to comply with the requirements in §60.42Da(a) of 

subpart Da of this part.

(d) An owner and operator of an affected facility that combusts only natural gas is exempt from the PM 

and opacity standards specified in paragraph (a) of this section.

(e) An owner or operator of an affected facility that combusts only gaseous or liquid fossil fuel 

(excluding residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and that 

does not use post-combustion technology to reduce emissions of SO2 or PM is exempt from the PM 

standards specified in paragraph (a) of this section.

§60.43 Standard for sulfur dioxide (SO2). 

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

performance test required to be conducted by §60.8 is completed, no owner or operator subject to the 

provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any 

gases that contain SO2in excess of: 

(1) 340 ng/J heat input (0.80 lb/MMBtu) derived from liquid fossil fuel or liquid fossil fuel and wood 

residue. 

(2) 520 ng/J heat input (1.2 lb/MMBtu) derived from solid fossil fuel or solid fossil fuel and wood 

residue, except as provided in paragraph (e) of this section. 

(b) Except as provided under paragraph (d) of this section, when different fossil fuels are burned 

simultaneously in any combination, the applicable standard (in ng/J) shall be determined by proration 

using the following formula: 

Comment [CF4]: Owner/operators of natural

gas‐fired facilities also presently subject to the

opacity & PM standard.

Comment [CF5]: Exempt owners/operators of

facilities burning natural gas from the PM & opacity

standards.

Comment [CF6]: Exempt owners/operators of

facilities burning natural gas and low sulfur oil from

the PM standard.
Where: 

PSSO2= Prorated standard for SO2when burning different fuels simultaneously, in ng/J heat input derived 

from all fossil fuels or from all fossil fuels and wood residue fired; 

y = Percentage of total heat input derived from liquid fossil fuel; and 

z = Percentage of total heat input derived from solid fossil fuel. 

(c) Compliance shall be based on the total heat input from all fossil fuels burned, including gaseous 

fuels. 

(d) As an alternate to meeting the requirements of paragraphs (a) and (b) of this section, an owner or 

operator can petition the Administrator (in writing) to comply with §60.43Da(i)(3) of subpart Da of this 

part or comply with §60.42b(k)(4) of subpart Db of this part, as applicable to the affected source. If the 

Administrator grants the petition, the source will from then on (unless the unit is modified or 

reconstructed in the future) have to comply with the requirements in §60.43Da(i)(3) of subpart Da of 

this part or §60.42b(k)(4) of subpart Db of this part, as applicable to the affected source. 

(e) Units 1 and 2 (as defined in appendix G of this part) at the Newton Power Station owned or operated 

by the Central Illinois Public Service Company will be in compliance with paragraph (a)(2) of this 

section if Unit 1 and Unit 2 individually comply with paragraph (a)(2) of this section or if the combined 

emission rate from Units 1 and 2 does not exceed 470 ng/J (1.1 lb/MMBtu) combined heat input to Units 

1 and 2. 

§60.44 Standard for nitrogen oxides (NOX). 

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

performance test required to be conducted by §60.8 is completed, no owner or operator subject to the 

provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility any 

gases that contain NOX, expressed as NO2in excess of: 

(1) 86 ng/J heat input (0.20 lb/MMBtu) derived from gaseous fossil fuel. 

(2) 129 ng/J heat input (0.30 lb/MMBtu) derived from liquid fossil fuel, liquid fossil fuel and wood 

residue, or gaseous fossil fuel and wood residue. 

(3) 300 ng/J heat input (0.70 lb/MMBtu) derived from solid fossil fuel or solid fossil fuel and wood 

residue (except lignite or a solid fossil fuel containing 25 percent, by weight, or more of coal refuse). 

(4) 260 ng/J heat input (0.60 lb MMBtu) derived from lignite or lignite and wood residue (except as 

provided under paragraph (a)(5) of this section). 

(5) 340 ng/J heat input (0.80 lb MMBtu) derived from lignite which is mined in North Dakota, South 

Dakota, or Montana and which is burned in a cyclone-fired unit. 

(b) Except as provided under paragraphs (c), (d), and (e) of this section, when different fossil fuels are 

burned simultaneously in any combination, the applicable standard (in ng/J) is determined by proration 

using the following formula: 
Where: 

PSNOX= Prorated standard for NOXwhen burning different fuels simultaneously, in ng/J heat input 

derived from all fossil fuels fired or from all fossil fuels and wood residue fired; 

w = Percentage of total heat input derived from lignite; 

x = Percentage of total heat input derived from gaseous fossil fuel; 

y = Percentage of total heat input derived from liquid fossil fuel; and 

z = Percentage of total heat input derived from solid fossil fuel (except lignite). 

(c) When a fossil fuel containing at least 25 percent, by weight, of coal refuse is burned in combination 

with gaseous, liquid, or other solid fossil fuel or wood residue, the standard for NOXdoes not apply. 

(d) Except as provided under paragraph (e) of this section, cyclone-fired units which burn fuels 

containing at least 25 percent of lignite that is mined in North Dakota, South Dakota, or Montana remain 

subject to paragraph (a)(5) of this section regardless of the types of fuel combusted in combination with 

that lignite. 

(e) As an alternate to meeting the requirements of paragraphs (a), (b), and (d) of this section, an owner 

or operator can petition the Administrator (in writing) to comply with §60.44Da(e)(3) of subpart Da of 

this part. If the Administrator grants the petition, the source will from then on (unless the unit is 

modified or reconstructed in the future) have to comply with the requirements in §60.44Da(e)(3) of 

subpart Da of this part. 

§60.45 Emissions and fuel monitoring. 

(a) Each owner or operator of an affected facility subject to the applicable emissions standard shall 

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

opacity and a CEMS for measuring SO2 emissions, NOX emissions, and either oxygen (O2) or carbon 

dioxide (CO2) except as provided in paragraph (b) of this section. 

(b) Certain of the CEMS and COMS requirements under paragraph (a) of this section do not apply to 

owners or operators under the following conditions: 

(1) For a fossil-fuel-fired steam generator that burnscombusts only gaseous or liquid fossil fuel 

(excluding residual oil) with potential SO2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less and that 

does not use post-combustion technology to reduce emissions of SO2 or PM, CEMS COMS for 

measuring the opacity of emissions and CEMS for measuring SO2 emissions are not required if the 

owner or operator monitors SO2 emissions by fuel sampling and analysis or fuel receipts. 

(2) For a fossil-fuel-fired steam generator that does not use a flue gas desulfurization device, a CEMS 

for measuring SO2emissions is not required if the owner or operator monitors SO2emissions by fuel 

sampling and analysis. 

(3) Notwithstanding §60.13(b), installation of a CEMS for NOXmay be delayed until after the initial 

performance tests under §60.8 have been conducted. If the owner or operator demonstrates during the 

performance test that emissions of NOXare less than 70 percent of the applicable standards in §60.44, a 

CEMS for measuring NOXemissions is not required. If the initial performance test results show that 

NOXemissions are greater than 70 percent of the applicable standard, the owner or operator shall install a 

CEMS for NOXwithin one year after the date of the initial performance tests under §60.8 and comply 

with all other applicable monitoring requirements under this part. 

(4) If an owner or operator is not required to and electsdoes not install any CEMS for sulfur oxidesSO2

and NOX, as provided under paragraphs (b)(1) and (b)(3) or paragraphs (b)(2) and (b)(3) of this section a 

CEMS for measuring either O2 or CO2 is not required. 

Comment [CF7]: Clarify that COMS exemption

for opacity monitoring
(5) For affected facilities using a An owner or operator may petition the Administrator (in writing) to 

install a PM CEMS, a bag leak detection system to monitor the performance of a fabric filter (baghouse) 

according to the most current requirements in section §60.48Da of this part, or 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 a COMS is not required as an alternative to the 

CEMS for monitoring opacity emissions.

(6) A CEMS COMS for measuring the opacity of emissions is not required for an affected facility fossil 

fuel-fired steam generator 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 0.30 weight percent sulfur, and is operated such that emissions of CO to the 

atmosphere from the affected source are maintained at levels less than or equal to 0.15 lb/MMBtu on a 

boiler operating day average basis. Owners and operators of affected sources electing to comply with 

this paragraph must demonstrate compliance according to the procedures specified in paragraphs 

(b)(6)(i) through (iv) of this section. 

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

(b)(6)(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 boiler operating day by 

multiplying the average hourly CO output concentration measured by the CO CEMS times the 

corresponding average hourly flue gas flow rate and divided by the corresponding average hourly 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 boiler operating day. 

(iii) You must evaluate the preceding 24-hour average CO emission level each boiler 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 (b)(6) 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. 

(7) An owner or operator of an affected facility subject to an opacity standard under §60.42 that elects to 

not use a COMS because the affected facility burns only fuels as specified under paragraph (b)(1) of this 

section, monitors PM emissions as specified under paragraph (b)(5) of this section, or monitors CO 

emissions as specified under paragraph (b)(6) of this section, 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 

Comment [CF8]: Add bag leak detection system

and ESP model to COMS exemption options
applicable limit in §60.42 by April 29, 2011 or within 45 days after stopping use of an existing COMS, 

whichever is later, and shall comply with either paragraph (b)(7)(i), (b)(7)(ii), or (b)(7)(iii) 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. 

The permitting authority may exempt owners or operators of affected facilities burning only natural gas 

from the opacity monitoring requirements.

(i) Except as provided in paragraph (b)(7)(ii) or (b)(7)(iii) 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 (b)(7) of this section according to the applicable schedule in paragraphs (b)(7)(i)(A) through 

(b)(7)(i)(D) of this section, as determined by the most recent Method 9 of appendix A–4 of this part 

performance test results. 

(A) If no visible emissions are observed, a subsequent Method 9 of appendix A–4 of this part 

performance test must be completed within 12 calendar months from the date that the most recent 

performance test was conducted or within 45 days of the next day that fuel with an opacity standard is 

combusted, whichever is later; 

(B) If 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; 

(C) 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 

(D) 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. 

(ii) 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 test, elect to perform subsequent 

monitoring using Method 22 of appendix A–7 of this part according to the procedures specified in 

paragraphs (b)(7)(ii)(A) and (B) of this section. 

(A) The owner or operator shall conduct 10 minute observations (during normal operation) each 

operating day the affected facility fires fuel for which an opacity standard is applicable using Method 22 

of appendix A–7 of this part and demonstrate that the sum of the occurrences of any visible emissions is 

not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute period). If the sum 

of the occurrence of any visible emissions is greater than 30 seconds during the initial 10 minute 

observation, immediately conduct a 30 minute observation. If the sum of the occurrence of visible 

emissions is greater than 5 percent of the observation period ( i.e. , 90 seconds per 30 minute period), the 

owner or operator shall either document and adjust the operation of the facility and demonstrate within 

24 hours that the sum of the occurrence of visible emissions is equal to or less than 5 percent during a 30 

minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of appendix A–4 of this part 

performance test using the procedures in paragraph (b)(7) of this section within 45 calendar days 

according to the requirements in §60.46(b)(3). 

Comment [CF9]: No longer necessary since

natural gas‐fired facilities exempt from the opacity

standard.

Comment [CF10]: Allow flexibility to account

for intermittent use of fuels with an opacity

standard.
(B) 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. 

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

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

subsequent Method 9 of appendix A–4 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 (b)(7)(ii) 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. 

(c) For performance evaluations under §60.13(c) and calibration checks under §60.13(d), the following 

procedures shall be used: 

(1) Methods 6, 7, and 3B of appendix A of this part, as applicable, shall be used for the performance 

evaluations of SO2and NOXcontinuous monitoring systems. Acceptable alternative methods for Methods 

6, 7, and 3B of appendix A of this part are given in §60.46(d). 

(2) Sulfur dioxide or nitric oxide, as applicable, shall be used for preparing calibration gas mixtures 

under Performance Specification 2 of appendix B to this part. 

(3) For affected facilities burning fossil fuel(s), the span value for a continuous monitoring system 

measuring the opacity of emissions shall be 80, 90, or 100 percent. For a continuous monitoring system 

measuring sulfur oxides or NOXthe span value shall be determined using one of the following 

procedures: 

(i) Except as provided under paragraph (c)(3)(ii) of this section, SO2and NOXspan values shall be 

determined as follows: 

Fossil fuel 

In parts per million 

Span value for SO2 Span value for NOX

Gas (1) 500. 

Liquid 1,000 500. 

Solid 1,500 1,000. 

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

1

Not applicable. 

Where: 

x = Fraction of total heat input derived from gaseous fossil fuel; 

y = Fraction of total heat input derived from liquid fossil fuel; and 

z = Fraction of total heat input derived from solid fossil fuel. 
(ii) As an alternative to meeting the requirements of paragraph (c)(3)(i) of this section, the owner or 

operator of an affected facility may elect to use the SO2and NOXspan values determined according to 

sections 2.1.1 and 2.1.2 in appendix A to part 75 of this chapter. 

(4) All span values computed under paragraph (c)(3)(i) of this section for burning combinations of fossil 

fuels shall be rounded to the nearest 500 ppm. Span values that are computed under paragraph (c)(3)(ii) 

of this section shall be rounded off according to the applicable procedures in section 2 of appendix A to 

part 75 of this chapter. 

(5) For a fossil-fuel-fired steam generator that simultaneously burns fossil fuel and nonfossil fuel, the 

span value of all CEMS shall be subject to the Administrator's approval. 

(d) [Reserved] 

(e) For any CEMS installed under paragraph (a) of this section, the following conversion procedures 

shall be used to convert the continuous monitoring data into units of the applicable standards (ng/J, 

lb/MMBtu): 

(1) When a CEMS for measuring O2is selected, the measurement of the pollutant concentration and 

O2concentration shall each be on a consistent basis (wet or dry). Alternative procedures approved by the 

Administrator shall be used when measurements are on a wet basis. When measurements are on a dry 

basis, the following conversion procedure shall be used: 

Where E, C, F, and %O2are determined under paragraph (f) of this section. 

(2) When a CEMS for measuring CO2is selected, the measurement of the pollutant concentration and 

CO2concentration shall each be on a consistent basis (wet or dry) and the following conversion 

procedure shall be used: 

Where E, C, Fcand %CO2are determined under paragraph (f) of this section. 

(f) The values used in the equations under paragraphs (e)(1) and (2) of this section are derived as 

follows: 

(1) E = pollutant emissions, ng/J (lb/MMBtu). 

(2) C = pollutant concentration, ng/dscm (lb/dscf), determined by multiplying the average concentration 

(ppm) for each one-hour period by 4.15 × 104

 M ng/dscm per ppm (2.59 × 10−9M lb/dscf per ppm) 

where M = pollutant molecular weight, g/g-mole (lb/lb-mole). M = 64.07 for SO2and 46.01 for NOX. 

(3) %O2, %CO2= O2or CO2volume (expressed as percent), determined with equipment specified under 

paragraph (a) of this section. 

(4) F, Fc= a factor representing a ratio of the volume of dry flue gases generated to the calorific value of 

the fuel combusted (F), and a factor representing a ratio of the volume of CO2generated to the calorific 

value of the fuel combusted (Fc), respectively. Values of F and Fcare given as follows: 

(i) For anthracite coal as classified according to ASTM D388 (incorporated by reference, see §60.17), F 

= 2,723 × 10−17dscm/J (10,140 dscf/MMBtu) and Fc= 0.532 × 10−17scm CO2/J (1,980 scf CO2/MMBtu). 
(ii) For subbituminous and bituminous coal as classified according to ASTM D388 (incorporated by 

reference, see §60.17), F = 2.637 × 10−7

dscm/J (9,820 dscf/MMBtu) and Fc= 0.486 × 10−7scm CO2/J 

(1,810 scf CO2/MMBtu). 

(iii) For liquid fossil fuels including crude, residual, and distillate oils, F = 2.476 × 10−7

dscm/J (9,220 

dscf/MMBtu) and Fc= 0.384 × 10−7

scm CO2/J (1,430 scf CO2/MMBtu). 

(iv) For gaseous fossil fuels, F = 2.347 × 10−7

dscm/J (8,740 dscf/MMBtu). For natural gas, propane, and 

butane fuels, Fc= 0.279 × 10−7

scm CO2/J (1,040 scf CO2/MMBtu) for natural gas, 0.322 × 10−7scm 

CO2/J (1,200 scf CO2/MMBtu) for propane, and 0.338 × 10−7

scm CO2/J (1,260 scf CO2/MMBtu) for 

butane. 

(v) For bark F = 2.589 × 10−7

dscm/J (9,640 dscf/MMBtu) and Fc= 0.500 × 10−7scm CO2/J (1,840 scf 

CO2/MMBtu). For wood residue other than bark F = 2.492 × 10−7

dscm/J (9,280 dscf/MMBtu) and Fc= 

0.494 × 10−7

scm CO2/J (1,860 scf CO2/MMBtu). 

(vi) For lignite coal as classified according to ASTM D388 (incorporated by reference, see §60.17), F = 

2.659 × 10−7

dscm/J (9,900 dscf/MMBtu) and Fc= 0.516 × 10−7scm CO2/J (1,920 scf CO2/MMBtu). 

(5) The owner or operator may use the following equation to determine an F factor (dscm/J or 

dscf/MMBtu) on a dry basis (if it is desired to calculate F on a wet basis, consult the Administrator) or 

Fc factor (scm CO2/J, or scf CO2/MMBtu) on either basis in lieu of the F or Fcfactors specified in 

paragraph (f)(4) of this section: 

(i) %H, %C, %S, %N, and %O are content by weight of hydrogen, carbon, sulfur, nitrogen, and 

O2(expressed as percent), respectively, as determined on the same basis as GCV by ultimate analysis of 

the fuel fired, using ASTM D3178 or D3176 (solid fuels), or computed from results using ASTM 

D1137, D1945, or D1946 (gaseous fuels) as applicable. (These five methods are incorporated by 

reference, see §60.17.) 

(ii) GVC is the gross calorific value (kJ/kg, Btu/lb) of the fuel combusted determined by the ASTM test 

methods D2015 or D5865 for solid fuels and D1826 for gaseous fuels as applicable. (These three 

methods are incorporated by reference, see §60.17.) 

(iii) For affected facilities which fire both fossil fuels and nonfossil fuels, the F or Fc value shall be 

subject to the Administrator's approval. 
(6) For affected facilities firing combinations of fossil fuels or fossil fuels and wood residue, the F or Fc 

factors determined by paragraphs (f)(4) or (f)(5) of this section shall be prorated in accordance with the 

applicable formula as follows: 

Where: 

Xi= Fraction of total heat input derived from each type of fuel (e.g. natural gas, bituminous coal, wood 

residue, etc.); 

Fior (Fc)i= Applicable F or Fcfactor for each fuel type determined in accordance with paragraphs (f)(4) 

and (f)(5) of this section; and 

n = Number of fuels being burned in combination. 

(g) Excess emission and monitoring system performance reports shall be submitted to the Administrator 

semiannually for each six-month period in the calendar year. All semiannual reports shall be postmarked 

by the 30th day following the end of each six-month period. Each excess emission and MSP report shall 

include the information required in §60.7(c). Periods of excess emissions and monitoring systems (MS) 

downtime that shall be reported are defined as follows: 

(1) Opacity . Excess emissions are defined as any six-minute period during which the average opacity of 

emissions exceeds 20 percent opacity, except that one six-minute average per hour of up to 27 percent 

opacity need not be reported. 

(i) For sources subject to the opacity standard of §60.42(b)(1), excess emissions are defined as any sixminute period during which the average opacity of emissions exceeds 35 percent opacity, except that 

one six-minute average per hour of up to 42 percent opacity need not be reported. 

(ii) For sources subject to the opacity standard of §60.42(b)(2), excess emissions are defined as any sixminute period during which the average opacity of emissions exceeds 32 percent opacity, except that 

one six-minute average per hour of up to 39 percent opacity need not be reported. 

(2) Sulfur dioxide. Excess emissions for affected facilities are defined as: 

(i) For affected facilities electing not to comply with §60.43(d), any three-hour period during which the 

average emissions (arithmetic average of three contiguous one-hour periods) of SO2as measured by a 

CEMS exceed the applicable standard in §60.43; or 

(ii) For affected facilities electing to comply with §60.43(d), any 30 operating day period during which 

the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of SO2as 

measured by a CEMS exceed the applicable standard in §60.43. Facilities complying with the 30-day 

SO2standard shall use the most current associated SO2compliance and monitoring requirements in 

§§60.48Da and 60.49Da of subpart Da of this part or §§60.45b and 60.47b of subpart Db of this part, as 

applicable. 

(3) Nitrogen oxides. Excess emissions for affected facilities using a CEMS for measuring NOXare 

defined as: 

(i) For affected facilities electing not to comply with §60.44(e), any three-hour period during which the 

average emissions (arithmetic average of three contiguous one-hour periods) exceed the applicable 

standards in §60.44; or 
(ii) For affected facilities electing to comply with §60.44(e), any 30 operating day period during which 

the average emissions (arithmetic average of all one-hour periods during the 30 operating days) of 

NOXas measured by a CEMS exceed the applicable standard in §60.44. Facilities complying with the 

30-day NOXstandard shall use the most current associated NOXcompliance and monitoring requirements 

in §§60.48Da and 60.49Da of subpart Da of this part. 

(4) Particulate matter. Excess emissions for affected facilities using a CEMS for measuring PM are 

defined as any boiler operating day period during which the average emissions (arithmetic average of all 

operating one-hour periods) exceed the applicable standards in §60.42. Affected facilities using PM 

CEMS must follow the most current applicable compliance and monitoring provisions in §§60.48Da and 

60.49Da of subpart Da of this part. 

(h) The owner or operator of an affected facility subject to the opacity limits in §60.42 that elects to 

monitor emissions according to the requirements in §60.45(b)(7) shall maintain records according to the 

requirements specified in paragraphs (h)(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 (h)(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 (h)(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. 

§60.46 Test methods and procedures. 

(a) In conducting the performance tests required in §60.8, and subsequent performance tests as requested 

by the EPA Administrator, the owner or operator shall use as reference methods and procedures the test 

methods in appendix A of this part or other methods and procedures as specified in this section, except 

as provided in §60.8(b). Acceptable alternative methods and procedures are given in paragraph (d) of 

this section. 

(b) The owner or operator shall determine compliance with the PM, SO2, and NOXstandards in §§60.42, 

60.43, and 60.44 as follows: 
(1) The emission rate (E) of PM, SO2, or NOXshall be computed for each run using the following 

equation: 

Where: 

E = Emission rate of pollutant, ng/J (1b/million Btu); 

C = Concentration of pollutant, ng/dscm (1b/dscf); 

%O2= O2concentration, percent dry basis; and 

Fd= Factor as determined from Method 19 of appendix A of this part. 

(2) Method 5 of appendix A of this part shall be used to determine the PM concentration (C) at affected 

facilities without wet flue-gas-desulfurization (FGD) systems and Method 5B of appendix A of this part 

shall be used to determine the PM concentration (C) after FGD systems. 

(i) The sampling time and sample volume for each run shall be at least 60 minutes and 0.85 dscm (30 

dscf). The probe and filter holder heating systems in the sampling train shall be set to provide an average 

gas temperature of 160±14 °C (320±25 °F). 

(ii) The emission rate correction factor, integrated or grab sampling and analysis procedure of Method 

3B of appendix A of this part shall be used to determine the O2concentration (%O2). The O2sample shall 

be obtained simultaneously with, and at the same traverse points as, the particulate sample. If the grab 

sampling procedure is used, the O2concentration for the run shall be the arithmetic mean of the sample 

O2concentrations at all traverse points. 

(iii) If the particulate run has more than 12 traverse points, the O2traverse points may be reduced to 12 

provided that Method 1 of appendix A of this part is used to locate the 12 O2traverse points. 

(3) Method 9 of appendix A of this part and the procedures in §60.11 shall be used to determine opacity. 

(4) Method 6 of appendix A of this part shall be used to determine the SO2concentration. 

(i) The sampling site shall be the same as that selected for the particulate sample. The sampling location 

in the duct shall be at the centroid of the cross section or at a point no closer to the walls than 1 m (3.28 

ft). The sampling time and sample volume for each sample run shall be at least 20 minutes and 0.020 

dscm (0.71 dscf). Two samples shall be taken during a 1-hour period, with each sample taken within a 

30-minute interval. 

(ii) The emission rate correction factor, integrated sampling and analysis procedure of Method 3B of 

appendix A of this part shall be used to determine the O2concentration (%O2). The O2sample shall be 

taken simultaneously with, and at the same point as, the SO2sample. The SO2emission rate shall be 

computed for each pair of SO2and O2samples. The SO2emission rate (E) for each run shall be the 

arithmetic mean of the results of the two pairs of samples. 

(5) Method 7 of appendix A of this part shall be used to determine the NOXconcentration. 

(i) The sampling site and location shall be the same as for the SO2sample. Each run shall consist of four 

grab samples, with each sample taken at about 15-minute intervals. 

(ii) For each NOXsample, the emission rate correction factor, grab sampling and analysis procedure of 

Method 3B of appendix A of this part shall be used to determine the O2concentration (%O2). The sample 

shall be taken simultaneously with, and at the same point as, the NOXsample. 
(iii) The NOXemission rate shall be computed for each pair of NOXand O2samples. The NOXemission 

rate (E) for each run shall be the arithmetic mean of the results of the four pairs of samples. 

(c) When combinations of fossil fuels or fossil fuel and wood residue are fired, the owner or operator (in 

order to compute the prorated standard as shown in §§60.43(b) and 60.44(b)) shall determine the 

percentage (w, x, y, or z) of the total heat input derived from each type of fuel as follows: 

(1) The heat input rate of each fuel shall be determined by multiplying the gross calorific value of each 

fuel fired by the rate of each fuel burned. 

(2) ASTM Methods D2015, or D5865 (solid fuels), D240 (liquid fuels), or D1826 (gaseous fuels) (all of 

these methods are incorporated by reference, see §60.17) shall be used to determine the gross calorific 

values of the fuels. The method used to determine the calorific value of wood residue must be approved 

by the Administrator. 

(3) Suitable methods shall be used to determine the rate of each fuel burned during each test period, and 

a material balance over the steam generating system shall be used to confirm the rate. 

(d) The owner or operator may use the following as alternatives to the reference methods and procedures 

in this section or in other sections as specified: 

(1) The emission rate (E) of PM, SO2and NOXmay be determined by using the Fc factor, provided that 

the following procedure is used: 

(i) The emission rate (E) shall be computed using the following equation: 

Where: 

E = Emission rate of pollutant, ng/J (lb/MMBtu); 

C = Concentration of pollutant, ng/dscm (lb/dscf); 

%CO2= CO2concentration, percent dry basis; and 

Fc= Factor as determined in appropriate sections of Method 19 of appendix A of this part. 

(ii) If and only if the average Fc factor in Method 19 of appendix A of this part is used to calculate E and 

either E is from 0.97 to 1.00 of the emission standard or the relative accuracy of a continuous emission 

monitoring system is from 17 to 20 percent, then three runs of Method 3B of appendix A of this part 

shall be used to determine the O2and CO2concentration according to the procedures in paragraph 

(b)(2)(ii), (4)(ii), or (5)(ii) of this section. Then if Fo(average of three runs), as calculated from the 

equation in Method 3B of appendix A of this part, is more than ±3 percent than the average Fovalue, as 

determined from the average values of Fdand Fcin Method 19 of appendix A of this part, i.e. , Foa= 0.209 

(Fda/Fca), then the following procedure shall be followed: 

(A) When Fois less than 0.97 Foa, then E shall be increased by that proportion under 0.97 Foa, e.g. , if Fois 

0.95 Foa, E shall be increased by 2 percent. This recalculated value shall be used to determine 

compliance with the emission standard. 

(B) When Fois less than 0.97 Foaand when the average difference (d) between the continuous monitor 

minus the reference methods is negative, then E shall be increased by that proportion under 0.97 Foa, e.g. 

, if Fois 0.95 Foa, E shall be increased by 2 percent. This recalculated value shall be used to determine 

compliance with the relative accuracy specification. 
(C) When Fois greater than 1.03 Foaand when the average difference d is positive, then E shall be 

decreased by that proportion over 1.03 Foa, e.g. , if Fois 1.05 Foa, E shall be decreased by 2 percent. This 

recalculated value shall be used to determine compliance with the relative accuracy specification. 

(2) For Method 5 or 5B of appendix A–3 of this part, Method 17 of appendix A–6 of this part may be 

used at facilities with or without wet FGD systems if the stack gas temperature at the sampling location 

does not exceed an average temperature of 160 °C (320 °F). The procedures of sections 8.1 and 11.1 of 

Method 5B of appendix A–3 of this part may be used with Method 17 of appendix A–6 of this part only 

if it is used after wet FGD systems. Method 17 of appendix A–6 of this part shall not be used after wet 

FGD systems if the effluent gas is saturated or laden with water droplets. 

(3) Particulate matter and SO2may be determined simultaneously with the Method 5 of appendix A of 

this part train provided that the following changes are made: 

(i) The filter and impinger apparatus in sections 2.1.5 and 2.1.6 of Method 8 of appendix A of this part is 

used in place of the condenser (section 2.1.7) of Method 5 of appendix A of this part. 

(ii) All applicable procedures in Method 8 of appendix A of this part for the determination of 

SO2(including moisture) are used: 

(4) For Method 6 of appendix A of this part, Method 6C of appendix A of this part may be used. Method 

6A of appendix A of this part may also be used whenever Methods 6 and 3B of appendix A of this part 

data are specified to determine the SO2emission rate, under the conditions in paragraph (d)(1) of this 

section. 

(5) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may 

be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run shall 

be at least 1 hour and the integrated sampling approach shall be used to determine the O2concentration 

(%O2) for the emission rate correction factor. 

(6) For Method 3 of appendix A of this part, Method 3A or 3B of appendix A of this part may be used. 

(7) For Method 3B of appendix A of this part, Method 3A of appendix A of this part may be used.