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Subpart C—General Stationary Fuel Combustion Sources

§98.30 Definition of the source category.

(a) Stationary fuel combustion sources are devices that combust solid, liquid, or gaseous 

fuel, generally for the purposes of producing electricity, generating steam, or providing useful 

heat or energy for industrial, commercial, or institutional use, or reducing the volume of waste by 

removing combustible matter. Stationary fuel combustion sources include, but are not limited to, 

boilers, simple and combined-cycle combustion turbines, engines, incinerators, and process 

heaters.

(b) This source category does not include:

(1) Portable equipment, as defined in §98.6.

(2) Emergency generators and emergency equipment, as defined in §98.6.

(3) Irrigation pumps at agricultural operations.

(4) Flares, unless otherwise required by provisions of another subpart of this part to use 

methodologies in this subpart.

(5) Electricity generating units that are subject to subpart D of this part.

(c) For a unit that combusts hazardous waste (as defined in §261.3 of this chapter), 

reporting of GHG emissions is not required unless either of the following conditions apply:

(1) Continuous emission monitors (CEMS) are used to quantify CO2 mass emissions.

(2) Any fuel listed in Table C-1 of this subpart is also combusted in the unit. In this case, 

report GHG emissions from combustion of all fuels listed in Table C-1 of this subpart.

(d) You are not required to report GHG emissions from pilot lights. A pilot light is a 

small auxiliary flame that ignites the burner of a combustion device when the control valve 

opens.
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§98.31 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains one or more 

stationary fuel combustion sources and the facility meets the applicability requirements of either 

§§98.2(a)(1), 98.2(a)(2), or 98.2(a)(3).

§98.32 GHGs to report.

You must report CO2, CH4, and N2O mass emissions from each stationary fuel 

combustion unit, except as otherwise indicated in this subpart.

§98.33 Calculating GHG emissions.

You must calculate CO2 emissions according to paragraph (a) of this section, and 

calculate CH4 and N2O emissions according to paragraph (c) of this section.

(a) CO2 emissions from fuel combustion. Calculate CO2 mass emissions by using one of 

the four calculation methodologies in paragraphs (a)(1) through (a)(4) of this section, subject to 

the applicable conditions, requirements, and restrictions set forth in paragraph (b) of this section. 

Alternatively, for units that meet the conditions of paragraph (a)(5) of this section, you may use 

CO2 mass emissions calculation methods from part 75 of this chapter, as described in paragraph 

(a)(5) of this section. For units that combust both biomass and fossil fuels, you must calculate 

and report CO2 emissions from the combustion of biomass separately using the methods in 

paragraph (e) of this section, except as otherwise provided in paragraphs (a)(5)(iv) and (e) of this 

section and in §98.36(d).

(1) Tier 1 Calculation Methodology. Calculate the annual CO2 mass emissions for each 

type of fuel by using Equation C-1, C-1a, or C-1b of this section (as applicable).
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(i) Use Equation C-1 except when natural gas billing records are used to quantify fuel 

usage and gas consumption is expressed in units of therms or million Btu. In that case, use 

Equation C-1a or C-1b, as applicable.

where:

CO2 = Annual CO2 mass emissions for the specific fuel type (metric tons).

Fuel = Mass or volume of fuel combusted per year, from company records as defined in 

§98.6 (express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, 

and volume in gallons for liquid fuel).

HHV = Default high heat value of the fuel, from Table C-1 of this subpart (mmBtu per 

mass or mmBtu per volume, as applicable).

EF = Fuel-specific default CO2 emission factor, from Table C-1 of this subpart (kg 

CO2/mmBtu).

1 × 10−3 = Conversion factor from kilograms to metric tons.

(ii) If natural gas consumption is obtained from billing records and fuel usage is 

expressed in therms, use Equation C-1a.

where:

CO2 = Annual CO2 mass emissions from natural gas combustion (metric tons).

Gas = Annual natural gas usage, from billing records (therms).

EF = Fuel-specific default CO2 emission factor for natural gas, from Table C-1 of this 

subpart (kg CO2/mmBtu).

0.1 = Conversion factor from therms to mmBtu
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1 × 10−3 = Conversion factor from kilograms to metric tons.

(iii) If natural gas consumption is obtained from billing records and fuel usage is 

expressed in mmBtu, use Equation C-1b.

where:

CO2 = Annual CO2 mass emissions from natural gas combustion (metric tons).

Gas = Annual natural gas usage, from billing records (mmBtu).

EF = Fuel-specific default CO2 emission factor for natural gas, from Table C-1 of this 

subpart (kg CO2/mmBtu).

1 × 10−3 = Conversion factor from kilograms to metric tons.

(2) Tier 2 Calculation Methodology. Calculate the annual CO2 mass emissions for each 

type of fuel by using either Equation C2a or C2c of this section, as appropriate.

(i) Equation C-2a of this section applies to any type of fuel listed in Table C-1 of the 

subpart, except for municipal solid waste (MSW). For MSW combustion, use Equation C-2c of 

this section.

Where:

CO2 = Annual CO2 mass emissions for a specific fuel type (metric tons).

Fuel = Mass or volume of the fuel combusted during the year, from company records as 

defined in §98.6 (express mass in short tons for solid fuel, volume in standard cubic feet for 

gaseous fuel, and volume in gallons for liquid fuel).
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HHV = Annual average high heat value of the fuel (mmBtu per mass or volume). The 

average HHV shall be calculated according to the requirements of paragraph (a)(2)(ii) of this 

section.

EF = Fuel-specific default CO2 emission factor, from Table C-1 of this subpart (kg 

CO2/mmBtu).

1 × 10−3 = Conversion factor from kilograms to metric tons.

(ii) The minimum required sampling frequency for determining the annual average HHV 

(e.g., monthly, quarterly, semi-annually, or by lot) is specified in §98.34. The method for 

computing the annual average HHV is a function of unit size and how frequently you perform or 

receive from the fuel supplier the results of fuel sampling for HHV. The method is specified in 

paragraph (a)(2)(ii)(A) or (a)(2)(ii)(B) of this section, as applicable.

(A) If the results of fuel sampling are received monthly or more frequently, then for each 

unit with a maximum rated heat input capacity greater than or equal to 100 mmBtu/hr (or for a 

group of units that includes at least one unit of that size), the annual average HHV shall be 

calculated using Equation C-2b of this section. If multiple HHV determinations are made in any 

month, average the values for the month arithmetically.

Where:

(HHV)annual = Weighted annual average high heat value of the fuel (mmBtu per mass or 

volume).
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(HHV)I = Measured high heat value of the fuel, for sample period “i” (which may be the 

arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data 

value (mmBtu per mass or volume).

(Fuel)I = Mass or volume of the fuel combusted during the sample period “i,” (e.g., 

monthly, quarterly, semi-annually, or by lot) from company records (express mass in short tons 

for solid fuel, volume in standard cubic feet (e.g., for gaseous fuel, and volume in gallons for 

liquid fuel).

n = Number of sample periods in the year.

(B) If the results of fuel sampling are received less frequently than monthly, or, for a unit 

with a maximum rated heat input capacity less than 100 mmBtu/hr (or a group of such units) 

regardless of the HHV sampling frequency, the annual average HHV shall either be computed 

according to paragraph (a)(2)(ii)(A) of this section or as the arithmetic average HHV for all 

values for the year (including valid samples and substitute data values under §98.35).

(iii) For units that combust municipal solid waste (MSW) and that produce steam, use 

Equation C-2c of this section. Equation C-2c of this section may also be used for any other solid 

fuel listed in Table C-1 of this subpart provided that steam is generated by the unit.

Where:

CO2 = Annual CO2 mass emissions from MSW or solid fuel combustion (metric tons).

Steam = Total mass of steam generated by MSW or solid fuel combustion during the 

reporting year (lb steam).

B = Ratio of the boiler's maximum rated heat input capacity to its design rated steam 

output capacity (mmBtu/lb steam).
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EF = Fuel-specific default CO2 emission factor, from Table C-1 of this subpart (kg 

CO2/mmBtu).

1 × 10−3 = Conversion factor from kilograms to metric tons.

(3) Tier 3 Calculation Methodology. Calculate the annual CO2 mass emissions for each 

fuel by using either Equation C3, C4, or C5 of this section, as appropriate.

(i) For a solid fuel, use Equation C-3 of this section.

Where:

CO2 = Annual CO2 mass emissions from the combustion of the specific solid fuel (metric 

tons).

Fuel = Annual mass of the solid fuel combusted, from company records as defined in 

§98.6 (short tons).

CC = Annual average carbon content of the solid fuel (percent by weight, expressed as a 

decimal fraction, e.g., 95% = 0.95). The annual average carbon content shall be determined using 

the same procedures as specified for HHV in paragraph (a)(2)(ii) of this section.

44/12 = Ratio of molecular weights, CO2 to carbon.

0.91 = Conversion factor from short tons to metric tons.

(ii) For a liquid fuel, use Equation C-4 of this section.

Where:

CO2 = Annual CO2 mass emissions from the combustion of the specific liquid fuel 

(metric tons).
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Fuel = Annual volume of the liquid fuel combusted (gallons). The volume of fuel 

combusted must be measured directly, using fuel flow meters calibrated according to §98.3(i). 

Fuel billing meters may be used for this purpose. Tank drop measurements may also be used.

CC = Annual average carbon content of the liquid fuel (kg C per gallon of fuel). The 

annual average carbon content shall be determined using the same procedures as specified for 

HHV in paragraph (a)(2)(ii) of this section.

44/12 = Ratio of molecular weights, CO2 to carbon.

0.001 = Conversion factor from kg to metric tons.

(iii) For a gaseous fuel, use Equation C-5 of this section.

Where:

CO2 = Annual CO2 mass emissions from combustion of the specific gaseous fuel (metric 

tons).

Fuel = Annual volume of the gaseous fuel combusted (scf). The volume of fuel 

combusted must be measured directly, using fuel flow meters calibrated according to §98.3(i). 

Fuel billing meters may be used for this purpose.

CC = Annual average carbon content of the gaseous fuel (kg C per kg of fuel). The 

annual average carbon content shall be determined using the same procedures as specified for 

HHV in paragraph (a)(2)(ii) of this section.

MW = Annual average molecular weight of the gaseous fuel (kg/kg-mole). The annual 

average molecular weight shall be determined using the same procedures as specified for HHV 

in paragraph (a)(2)(ii) of this section.
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MVC = Molar volume conversion factor at standard conditions, as defined in §98.6. Use 

849.5 scf per kg mole if you select 68 °F as standard temperature and 836.6 scf per kg mole if 

you select 60 °F as standard temperature.

44/12 = Ratio of molecular weights, CO2 to carbon.

0.001 = Conversion factor from kg to metric tons.

(iv) Fuel flow meters that measure mass flow rates may be used for liquid or gaseous 

fuels, provided that the fuel density is used to convert the readings to volumetric flow rates. The 

density shall be measured at the same frequency as the carbon content. You must measure the 

density using one of the following appropriate methods. You may use a method published by a 

consensus-based standards organization, if such a method exists, or you may use industry

standard practice. Consensus-based standards organizations include, but are not limited to, the 

following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National 

Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-

8020, http://www.ansi.org), the American Gas Association (AGA), 400 North Capitol Street, 

NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American 

Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, 

(800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, 

NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North 

American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, 

(713) 356-0060, http://www.api.org). The method(s) used shall be documented in the GHG 

Monitoring Plan required under §98.3(g)(5).
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(v) The following default density values may be used for fuel oil, in lieu of using the 

methods in paragraph (a)(3)(iv) of this section: 6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 

8.1 lb/gal for No. 6 oil.

(4) Tier 4 Calculation Methodology. Calculate the annual CO2 mass emissions from all 

fuels combusted in a unit, by using quality-assured data from continuous emission monitoring 

systems (CEMS).

(i) This methodology requires a CO2 concentration monitor and a stack gas volumetric 

flow rate monitor, except as otherwise provided in paragraph (a)(4)(iv) of this section. Hourly

measurements of CO2 concentration and stack gas flow rate are converted to CO2 mass emission 

rates in metric tons per hour.

(ii) When the CO2 concentration is measured on a wet basis, Equation C-6 of this section 

is used to calculate the hourly CO2 emission rates:

Where:

CO2 = CO2 mass emission rate (metric tons/hr).

CCO2 = Hourly average CO2 concentration (% CO2).

Q = Hourly average stack gas volumetric flow rate (scfh).

5.18 × 10−7 = Conversion factor (metric tons/scf/% CO2).

(iii) If the CO2 concentration is measured on a dry basis, a correction for the stack gas 

moisture content is required. You shall either continuously monitor the stack gas moisture 

content using a method described in §75.11(b)(2) of this chapter or use an appropriate default 

moisture percentage. For coal, wood, and natural gas combustion, you may use the default 

moisture values specified in §75.11(b)(1) of this chapter. Alternatively, for any type of fuel, you 
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may determine an appropriate site-specific default moisture value (or values), using 

measurements made with EPA Method 4—Determination Of Moisture Content In Stack Gases, 

in appendix A-3 to part 60 of this chapter. Moisture data from the relative accuracy test audit 

(RATA) of a CEMS may be used for this purpose. If this option is selected, the site-specific 

moisture default value(s) must represent the fuel(s) or fuel blends that are combusted in the unit 

during normal, stable operation, and must account for any distinct difference(s) in the stack gas 

moisture content associated with different process operating conditions. For each site-specific 

default moisture percentage, at least nine Method 4 runs are required, except where the option to 

use moisture data from a RATA is selected, and the applicable regulation allows a single 

moisture determination to represent two or more RATA runs. In that case, you may base the sitespecific moisture percentage on the number of moisture runs allowed by the RATA regulation. 

Calculate each site-specific default moisture value by taking the arithmetic average of the 

Method 4 runs. Each site-specific moisture default value shall be updated whenever the owner or 

operator believes the current value is non-representative, due to changes in unit or process 

operation, but in any event no less frequently than annually. Use the updated moisture value in 

the subsequent CO2 emissions calculations. For each unit operating hour, a moisture correction 

must be applied to Equation C-6 of this section as follows:

where:

CO2* = Hourly CO2 mass emission rate, corrected for moisture (metric tons/hr).

CO2 = Hourly CO2 mass emission rate from Equation C-6 of this section, uncorrected 

(metric tons/hr).
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%H2O = Hourly moisture percentage in the stack gas (measured or default value, as 

appropriate).

(iv) An oxygen (O2) concentration monitor may be used in lieu of a CO2 concentration 

monitor to determine the hourly CO2 concentrations, in accordance with Equation F-14a or F14b (as applicable) in appendix F to part 75 of this chapter, if the effluent gas stream monitored 

by the CEMS consists solely of combustion products (i.e., no process CO2 emissions or CO2

emissions from sorbent are mixed with the combustion products) and if only fuels that are listed 

in Table 1 in section 3.3.5 of appendix F to part 75 of this chapter are combusted in the unit. If 

the O2 monitoring option is selected, the F-factors used in Equations F-14a and F-14b shall be 

determined according to section 3.3.5 or section 3.3.6 of appendix F to part 75 of this chapter, as 

applicable. If Equation F-14b is used, the hourly moisture percentage in the stack gas shall be 

determined in accordance with paragraph (a)(4)(iii) of this section.

(v) Each hourly CO2 mass emission rate from Equation C-6 or C-7 of this section is 

multiplied by the operating time to convert it from metric tons per hour to metric tons. The 

operating time is the fraction of the hour during which fuel is combusted (e.g., the unit operating 

time is 1.0 if the unit operates for the whole hour and is 0.5 if the unit operates for 30 minutes in 

the hour). For common stack configurations, the operating time is the fraction of the hour during 

which effluent gases flow through the common stack.

(vi) The hourly CO2 mass emissions are then summed over each calendar quarter and the 

quarterly totals are summed to determine the annual CO2 mass emissions.

(vii) If both biomass and fossil fuel are combusted during the year, determine and report 

the biogenic CO2 mass emissions separately, as described in paragraph (e) of this section.
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(viii) If a portion of the flue gases generated by a unit subject to Tier 4 (e.g., a slip 

stream) is continuously diverted from the main flue gas exhaust system for the purpose of heat 

recovery or some other similar process, and then exhausts through a stack that is not equipped 

with the continuous emission monitors to measure CO2 mass emissions, CO2 emissions shall be 

determined as follows:

(A) At least once a year, use EPA Methods 2 and 3A, and (if necessary) Method 4 in 

appendices A-2 and A-3 to part 60 of this chapter to perform emissions testing at a set point that 

best represents normal, stable process operating conditions. A minimum of three one-hour 

Method 3A tests are required, to determine the CO2 concentration. A Method 2 test shall be 

performed during each Method 3A run, to determine the stack gas volumetric flow rate. If 

moisture correction is necessary, a Method 4 run shall also be performed during each Method 3A 

run. Important parametric information related to the stack gas flow rate (e.g., damper positions, 

fan settings, etc.) shall also be recorded during the test.

(B) Calculate a CO2 mass emission rate (in metric tons/hr) from the stack test data, using 

a version of Equation C-6 in paragraph (a)(4)(ii) of this section, modified as follows. In the 

Equation C-6 nomenclature, replace the words “Hourly average” in the definitions of “CCO2” and 

“Q” with the words “3-run average”. Substitute the arithmetic average values of CO2

concentration and stack gas flow rate from the emission testing into modified Equation C-6. If 

CO2 is measured on a dry basis, a moisture correction of the calculated CO2 mass emission rate 

is required. Use Equation C-7 in paragraph (a)(4)(ii) of this section to make this correction; 

replace the word “Hourly” with the words “3-run average” in the equation nomenclature.

(C) The results of each annual stack test shall be used in the GHG emissions calculations 

for the year of the test.
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(D) If, for the majority of the operating hours during the year, the diverted stream is 

withdrawn at a steady rate at or near the tested set point (as evidenced by fan and damper settings 

and/or other parameters), you may use the calculated CO2 mass emission rate from paragraph 

(a)(4)(viii)(B) of this section to estimate the CO2 mass emissions for all operating hours in which 

flue gas is diverted from the main exhaust system. Otherwise, you must account for the variation 

in the flow rate of the diverted stream, as described in paragraph (c)(4)(viii)(E) of this section.

(E) If the flow rate of the diverted stream varies significantly throughout the year, except 

as provided below, repeat the stack test and emission rate calculation procedures described in 

paragraphs (c)(4)(viii)(A) and (c)(4)(viii)(B) of this section at a minimum of two more set points 

across the range of typical operating conditions to develop a correlation between CO2 mass 

emission rate and the parametric data. If additional testing is not feasible, use the following 

approach to develop the necessary correlation. Assume that the average CO2 concentration 

obtained in the annual stack test is the same at all operating set points. Then, beginning with the 

measured flow rate from the stack test and the associated parametric data, perform an 

engineering analysis to estimate the stack gas flow rate at two or more additional set points. 

Calculate the CO2 mass emission rate at each set point.

(F) Calculate the annual CO2 mass emissions for the diverted stream as follows. For a 

steady-state process, multiply the number of hours in which flue gas was diverted from the main 

exhaust system by the CO2 mass emission rate from the stack test. Otherwise, using the best 

available information and engineering judgment, apply the most representative CO2 mass 

emission rate from the correlation in paragraph (c)(4)(viii)(E) of this section to determine the 

CO2 mass emissions for each hour in which flue gas was diverted, and sum the results. To 

simplify the calculations, you may count partial operating hours as full hours.
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(G) Finally, add the CO2 mass emissions from paragraph(c)(4)(viii)(F) of this section to 

the annual CO2 mass emissions measured by the CEMS at the main stack. Report this sum as the 

total annual CO2 mass emissions for the unit.

(H) The exact method and procedures used to estimate the CO2 mass emissions for the 

diverted portion of the flue gas exhaust stream shall be documented in the Monitoring Plan 

required under §98.3(g)(5).

(5) Alternative methods for certain units subject to Part 75 of this chapter. Certain units 

that are not subject to subpart D of this part and that report data to EPA according to part 75 of 

this chapter may qualify to use the alternative methods in this paragraph (a)(5), in lieu of using 

any of the four calculation methodology tiers.

(i) For a unit that combusts only natural gas and/or fuel oil, is not subject to subpart D of 

this part, monitors and reports heat input data year-round according to appendix D to part 75 of 

this chapter, but is not required by the applicable part 75 program to report CO2 mass emissions 

data, calculate the annual CO2 mass emissions for the purposes of this part as follows:

(A) Use the hourly heat input data from appendix D to part 75 of this chapter, together 

with Equation G-4 in appendix G to part 75 of this chapter to determine the hourly CO2 mass 

emission rates, in units of tons/hr;

(B) Use Equations F-12 and F-13 in appendix F to part 75 of this chapter to calculate the 

quarterly and cumulative annual CO2 mass emissions, respectively, in units of short tons; and

(C) Divide the cumulative annual CO2 mass emissions value by 1.1023 to convert it to 

metric tons.

(ii) For a unit that combusts only natural gas and/or fuel oil, is not subject to subpart D of 

this part, monitors and reports heat input data year-round according to §75.19 of this chapter but 
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is not required by the applicable part 75 program to report CO2 mass emissions data, calculate 

the annual CO2 mass emissions for the purposes of this part as follows:

(A) Calculate the hourly CO2 mass emissions, in units of short tons, using Equation LM11 in §75.19(c)(4)(iii) of this chapter.

(B) Sum the hourly CO2 mass emissions values over the entire reporting year to obtain 

the cumulative annual CO2 mass emissions, in units of short tons.

(C) Divide the cumulative annual CO2 mass emissions value by 1.1023 to convert it to 

metric tons.

(iii) For a unit that is not subject to subpart D of this part, uses flow rate and CO2 (or O2) 

CEMS to report heat input data year-round according to part 75 of this chapter, but is not 

required by the applicable part 75 program to report CO2 mass emissions data, calculate the 

annual CO2 mass emissions as follows:

(A) Use Equation F-11 or F-2 (as applicable) in appendix F to part 75 of this chapter to 

calculate the hourly CO2 mass emission rates from the CEMS data. If an O2 monitor is used, 

convert the hourly average O2 readings to CO2 using Equation F-14a or F-14b in appendix F to 

part 75 of this chapter (as applicable), before applying Equation F-11 or F-2.

(B) Use Equations F-12 and F-13 in appendix F to part 75 of this chapter to calculate the 

quarterly and cumulative annual CO2 mass emissions, respectively, in units of short tons.

(C) Divide the cumulative annual CO2 mass emissions value by 1.1023 to convert it to 

metric tons.

(iv) For units that qualify to use the alternative CO2 emissions calculation methods in 

paragraphs (a)(5)(i) through (a)(5)(iii) of this section, if both biomass and fossil fuel are 

combusted during the year, separate calculation and reporting of the biogenic CO2 mass 
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emissions (as described in paragraph (e) of this section) is optional, only for the 2010 reporting 

year, as provided in §98.3(c)(12).

(b) Use of the four tiers. Use of the four tiers of CO2 emissions calculation methodologies 

described in paragraph (a) of this section is subject to the following conditions, requirements, 

and restrictions:

(1) The Tier 1 Calculation Methodology:

(i) May be used for any fuel listed in Table C-1 of this subpart that is combusted in a unit 

with a maximum rated heat input capacity of 250 mmBtu/hr or less.

(ii) May be used for MSW in a unit of any size that does not produce steam, if the use of 

Tier 4 is not required.

(iii) May be used for solid, gaseous, or liquid biomass fuels in a unit of any size provided 

that the fuel is listed in Table C-1 of this subpart.

(iv) May not be used if you routinely perform fuel sampling and analysis for the fuel high 

heat value (HHV) or routinely receive the results of HHV sampling and analysis from the fuel 

supplier at the minimum frequency specified in §98.34(a), or at a greater frequency. In such 

cases, Tier 2 shall be used. This restriction does not apply to paragraphs (b)(1)(ii), (b)(1)(v), 

(b)(1)(vi), and (b)(1)(vii) of this section.

(v) May be used for natural gas combustion in a unit of any size, in cases where the 

annual natural gas consumption is obtained from fuel billing records in units of therms or 

mmBtu.

(vi) May be used for MSW combustion in a small, batch incinerator that burns no more 

than 1,000 tons per year of MSW.
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(vii) May be used for the combustion of MSW and/or tires in a unit, provided that no 

more than 10 percent of the unit's annual heat input is derived from those fuels, combined. 

Notwithstanding this requirement, if a unit combusts both MSW and tires and the reporter elects 

not to separately calculate and report biogenic CO2 emissions from the combustion of tires, Tier 

1 may be used for the MSW combustion, provided that no more than 10 percent of the unit's 

annual heat input is derived from MSW.

(viii) May be used for the combustion of a fuel listed in Table C-1 if the fuel is 

combusted in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr (or, 

pursuant to §98.36(c)(3), in a group of units served by a common supply pipe, having at least one 

unit with a maximum rated heat input capacity greater than 250 mmBtu/hr), provided that both of 

the following conditions apply:

(A) The use of Tier 4 is not required.

(B) The fuel provides less than 10 percent of the annual heat input to the unit, or if 

§98.36(c)(3) applies, to the group of units served by a common supply pipe.

(2) The Tier 2 Calculation Methodology:

(i) May be used for the combustion of any type of fuel in a unit with a maximum rated 

heat input capacity of 250 mmBtu/hr or less provided that the fuel is listed in Table C-1 of this 

subpart.

(ii) May be used in a unit with a maximum rated heat input capacity greater than 250 

mmBtu/hr for the combustion of natural gas and/or distillate fuel oil.

(iii) May be used for MSW in a unit of any size that produces steam, if the use of Tier 4 

is not required.

(3) The Tier 3 Calculation Methodology:
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(i) May be used for a unit of any size that combusts any type of fuel listed in Table C-1 of 

this subpart (except for MSW), unless the use of Tier 4 is required.

(ii) Shall be used for a unit with a maximum rated heat input capacity greater than 250 

mmBtu/hr that combusts any type of fuel listed in Table C-1 of this subpart (except MSW), 

unless either of the following conditions apply:

(A) The use of Tier 1 or 2 is permitted, as described in paragraphs (b)(1)(iii), (b)(1)(v), 

(b)(1)(viii), and (b)(2)(ii) of this section.

(B) The use of Tier 4 is required.

(iii) Shall be used for a fuel not listed in Table C-1 of this subpart if the fuel is combusted 

in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr (or, pursuant to 

§98.36(c)(3), in a group of units served by a common supply pipe, having at least one unit with a 

maximum rated heat input capacity greater than 250 mmBtu/hr), provided that both of the 

following conditions apply:

(A) The use of Tier 4 is not required.

(B) The fuel provides 10% or more of the annual heat input to the unit or, if §98.36(c)(3) 

applies, to the group of units served by a common supply pipe.

(iv) Shall be used when specified in another applicable subpart of this part, regardless of 

unit size.

(4) The Tier 4 Calculation Methodology:

(i) May be used for a unit of any size, combusting any type of fuel. Tier 4 may also be 

used for any group of stationary fuel combustion units, process units, or manufacturing units that 

share a common stack or duct.
Page 20 of 78

(ii) Shall be used if the unit meets all six of the conditions specified in paragraphs 

(b)(4)(ii)(A) through (b)(4)(ii)(F) of this section:

(A) The unit has a maximum rated heat input capacity greater than 250 mmBtu/hr, or if 

the unit combusts municipal solid waste and has a maximum rated input capacity greater than 

600 tons per day of MSW.

(B) The unit combusts solid fossil fuel or MSW as the primary fuel.

(C) The unit has operated for more than 1,000 hours in any calendar year since 2005.

(D) The unit has installed CEMS that are required either by an applicable Federal or State 

regulation or the unit's operating permit.

(E) The installed CEMS include a gas monitor of any kind or a stack gas volumetric flow 

rate monitor, or both and the monitors have been certified, either in accordance with the 

requirements of part 75 of this chapter, part 60 of this chapter, or an applicable State continuous 

monitoring program.

(F) The installed gas or stack gas volumetric flow rate monitors are required, either by an 

applicable Federal or State regulation or by the unit's operating permit, to undergo periodic 

quality assurance testing in accordance with either appendix B to part 75 of this chapter, 

appendix F to part 60 of this chapter, or an applicable State continuous monitoring program.

(iii) Shall be used for a unit with a maximum rated heat input capacity of 250 mmBtu/hr 

or less and for a unit that combusts municipal solid waste with a maximum rated input capacity

of 600 tons of MSW per day or less, if the unit meets all of the following three conditions:

(A) The unit has both a stack gas volumetric flow rate monitor and a CO2 concentration 

monitor.
Page 21 of 78

(B) The unit meets the conditions specified in paragraphs (b)(4)(ii)(B) through 

(b)(4)(ii)(D) of this section.

(C) The CO2 and stack gas volumetric flow rate monitors meet the conditions specified in 

paragraphs (b)(4)(ii)(E) and (b)(4)(ii)(F) of this section.

(iv) May apply to common stack or duct configurations where:

(A) The combined effluent gas streams from two or more stationary fuel combustion 

units are vented through a monitored common stack or duct. In this case, Tier 4 shall be used if 

all of the conditions in paragraph (b)(4)(iv)(A)(1) of this section or if the conditions in paragraph 

(b)(4)(iv)(A)(2) of this section are met.

(1) At least one of the units meets the requirements of paragraphs (b)(4)(ii)(A) through 

(b)(4)(ii)(C) of this section, and the CEMS installed at the common stack (or duct) meet the 

requirements of paragraphs (b)(4)(ii)(D) through (b)(4)(ii)(F) of this section.

(2) At least one of the units and the monitors installed at the common stack or duct meet 

the requirements of paragraph (b)(4)(iii) of this section.

(B) The combined effluent gas streams from a process or manufacturing unit and a 

stationary fuel combustion unit are vented through a monitored common stack or duct. In this 

case, Tier 4 shall be used if the combustion unit and the monitors installed at the common stack 

or duct meet the applicability criteria specified in paragraph (b)(4)(iv)(A)(1), or (b)(4)(iv)(A)(2) 

of this section.

(C) The combined effluent gas streams from two or more manufacturing or process units 

are vented through a common stack or duct. In this case, if any of the units is required by an 

applicable subpart of this part to use Tier 4, the CO2 mass emissions may be monitored at each 

individual unit, or the combined CO2 mass emissions may be monitored at the common stack or 
Page 22 of 78

duct. However, if it is not feasible to monitor the individual units, the combined CO2 mass 

emissions shall be monitored at the common stack or duct.

(5) The Tier 4 Calculation Methodology shall be used:

(i) Starting on January 1, 2010, for a unit that is required to report CO2 mass emissions 

beginning on that date, if all of the monitors needed to measure CO2 mass emissions have been 

installed and certified by that date.

(ii) No later than January 1, 2011, for a unit that is required to report CO2 mass emissions 

beginning on January 1, 2010, if all of the monitors needed to measure CO2 mass emissions have 

not been installed and certified by January 1, 2010. In this case, you may use Tier 2 or Tier 3 to 

report GHG emissions for 2010. However, if the required CEMS are certified some time in 2010, 

you need not wait until January 1, 2011 to begin using Tier 4. Rather, you may switch from Tier 

2 or Tier 3 to Tier 4 as soon as CEMS certification testing is successfully completed. If this 

reporting option is chosen, you must document the change in CO2 calculation methodology in 

the Monitoring Plan required under §98.3(g)(5) and in the GHG emissions report under §98.3(c). 

Data recorded by the CEMS during a certification test period in 2010 may be used for reporting 

under this part, provided that the following two conditions are met:

(A) The certification tests are passed in sequence, with no test failures.

(B) No unscheduled maintenance or repair of the CEMS is performed during the 

certification test period.

(iii) No later than 180 days following the date on which a change is made that triggers 

Tier 4 applicability under paragraph (b)(4)(ii) or (b)(4)(iii) of this section (e.g., a change in the 

primary fuel, manner of unit operation, or installed continuous monitoring equipment).
Page 23 of 78

(6) You may elect to use any applicable higher tier for one or more of the fuels 

combusted in a unit. For example, if a 100 mmBtu/hr unit combusts natural gas and distillate fuel 

oil, you may elect to use Tier 1 for natural gas and Tier 3 for the fuel oil, even though Tier 1 

could have been used for both fuels. However, for units that use either the Tier 4 or the 

alternative calculation methodology specified in paragraph (a)(5)(iii) of this section, CO2

emissions from the combustion of all fuels shall be based solely on CEMS measurements.

(c) Calculation of CH4 and N2O emissions from stationary combustion sources. You must 

calculate annual CH4 and N2O mass emissions only for units that are required to report CO2

emissions using the calculation methodologies of this subpart and for only those fuels that are 

listed in Table C-2 of this subpart.

(1) Use Equation C-8 of this section to estimate CH4 and N2O emissions for any fuels for 

which you use the Tier 1 or Tier 3 calculation methodologies for CO2, except when natural gas 

usage in units of therms or mmBtu is obtained from gas billing records. In that case, use 

Equation C-8a in paragraph (c)(1)(i) of this section or Equation C-8b in paragraph (c)(1)(ii) of 

this section (as applicable). For Equation C-8, use the same values for fuel consumption that you 

use for the Tier 1 or Tier 3 calculation.

Where:

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of 

fuel (metric tons).

Fuel = Mass or volume of the fuel combusted, either from company records or directly 

measured by a fuel flow meter, as applicable (mass or volume per year).
Page 24 of 78

HHV = Default high heat value of the fuel from Table C-1 of this subpart; alternatively, 

for Tier 3, if actual HHV data are available for the reporting year, you may average these data 

using the procedures specified in paragraph (a)(2)(ii) of this section, and use the average value in 

Equation C-8 (mmBtu per mass or volume).

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 of this 

subpart (kg CH4 or N2O per mmBtu).

1 × 10

−3 = Conversion factor from kilograms to metric tons.

(i) Use Equation C-8a to calculate CH4 and N2O emissions when natural gas usage is 

obtained from gas billing records in units of therms.

where:

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of natural gas (metric 

tons).

Fuel = Annual natural gas usage, from gas billing records (therms).

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 of this 

subpart (kg CH4 or N2O per mmBtu).

0.1 = Conversion factor from therms to mmBtu

1 × 10−3 = Conversion factor from kilograms to metric tons.

(ii) Use Equation C-8b to calculate CH4 and N2O emissions when natural gas usage is 

obtained from gas billing records in units of mmBtu.

CH4 or N2O = 1 × 10−3 * Fuel * EF (Eq. C-8b)

where:
Page 25 of 78

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of natural gas (metric 

tons).

Fuel = Annual natural gas usage, from gas billing records (mmBtu).

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 of this 

subpart (kg CH4 or N2O per mmBtu).

1 × 10−3 = Conversion factor from kilograms to metric tons.

(2) Use Equation C-9a of this section to estimate CH4 and N2O emissions for any fuels 

for which you use the Tier 2 Equation C-2a of this section to estimate CO2 emissions. Use the 

same values for fuel consumption and HHV that you use for the Tier 2 calculation.

Where:

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of 

fuel (metric tons).

Fuel = Mass or volume of the fuel combusted during the reporting year.

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting 

year (mmBtu per mass or volume).

EF = Fuel-specific default emission factor for CH4 or N2O, from Table C-2 of this 

subpart (kg CH4 or N2O per mmBtu).

1 × 10−3 = Conversion factor from kilograms to metric tons.

(3) Use Equation C-9b of this section to estimate CH4 and N2O emissions for any fuels 

for which you use Equation C-2c of this section to calculate the CO2 emissions. Use the same 

values for steam generation and the ratio “B” that you use for Equation C-2c.
Page 26 of 78

Where:

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a solid fuel (metric 

tons).

Steam = Total mass of steam generated by solid fuel combustion during the reporting 

year (lb steam).

B = Ratio of the boiler's maximum rated heat input capacity to its design rated steam 

output (mmBtu/lb steam).

EF = Fuel-specific emission factor for CH4 or N2O, from Table C-2 of this subpart (kg 

CH4 or N2O per mmBtu).

1 × 10−3 = Conversion factor from kilograms to metric tons.

(4) Use Equation C-10 of this section for: units subject to subpart D of this part; units that 

qualify for and elect to use the alternative CO2 mass emissions calculation methodologies 

described in paragraph (a)(5) of this section; and units that use the Tier 4 Calculation 

Methodology.

Where:

CH4 or N2O = Annual CH4 or N2O emissions from the combustion of a particular type of 

fuel (metric tons).

(HI)A = Cumulative annual heat input from combustion of the fuel (mmBtu).

EF = Fuel-specific emission factor for CH4 or N2O, from Table C-2 of this section (kg 

CH4 or N2O per mmBtu).

0.001 = Conversion factor from kg to metric tons.
Page 27 of 78

(i) If only one type of fuel listed in Table C-2 of this subpart is combusted during the 

reporting year, substitute the cumulative annual heat input from combustion of the fuel into 

Equation C-10 of this section to calculate the annual CH4 or N2O emissions. For units in the Acid 

Rain Program and units that report heat input data to EPA year-round according to part 75 of this 

chapter, obtain the cumulative annual heat input directly from the electronic data reports required 

under §75.64 of this chapter. For Tier 4 units, use the best available information, as described in 

paragraph (c)(4)(ii)(C) of this section, to estimate the cumulative annual heat input (HI)A.

(ii) If more than one type of fuel listed in Table C-2 of this subpart is combusted during 

the reporting year, use Equation C-10 of this section separately for each type of fuel, except as 

provided in paragraph (c)(4)(ii)(B) of this section. Determine the appropriate values of (HI)A as 

follows:

(A) For units in the Acid Rain Program and other units that report heat input data to EPA 

year-round according to part 75 of this chapter, obtain (HI)A for each type of fuel from the 

electronic data reports required under §75.64 of this chapter, except as otherwise provided in 

paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(D) of this section.

(B) For a unit that uses CEMS to monitor hourly heat input according to part 75 of this 

chapter, the value of (HI)A obtained from the electronic data reports under §75.64 of this chapter 

may be attributed exclusively to the fuel with the highest F-factor, when the reporting option in 

3.3.6.5 of appendix F to part 75 of this chapter is selected and implemented.

(C) For Tier 4 units, use the best available information (e.g., fuel feed rate measurements, 

fuel heating values, engineering analysis) to estimate the value of (HI)A for each type of fuel. 

Instrumentation used to make these estimates is not subject to the calibration requirements of 

§98.3(i) or to the QA requirements of §98.34.
Page 28 of 78

(D) Units in the Acid Rain Program and other units that report heat input data to EPA 

year-round according to part 75 of this chapter may use the best available information described 

in paragraph (c)(4)(ii)(C) of this section, to estimate (HI)A for each fuel type, whenever fuelspecific heat input values cannot be directly obtained from the electronic data reports under 

§75.64 of this chapter.

(5) When multiple fuels are combusted during the reporting year, sum the fuel-specific 

results from Equations C-8, C-8a, C-8b, C-9a, C-9b, or C-10 of this section (as applicable) to 

obtain the total annual CH4 and N2O emissions, in metric tons.

(6) Calculate the annual CH4 and N2O mass emissions from the combustion of blended 

fuels as follows:

(i) If the mass or volume of each component fuel in the blend is measured before the 

fuels are mixed and combusted, calculate and report CH4 and N2O emissions separately for each 

component fuel, using the applicable procedures in this paragraph (c).

(ii) If the mass or volume of each component fuel in the blend is not measured before the 

fuels are mixed and combusted, a reasonable estimate of the percentage composition of the 

blend, based on best available information, is required. Perform the following calculations for 

each component fuel “i” that is listed in Table C-2:

(A) Multiply (% Fuel)i, the estimated mass or volume percentage (decimal fraction) of 

component fuel “i”, by the total annual mass or volume of the blended fuel combusted during the 

reporting year, to obtain an estimate of the annual consumption of component “i”;

(B) Multiply the result from paragraph (c)(6)(ii)(A) of this section by the HHV of the fuel 

(default value or, if available, the measured annual average value), to obtain an estimate of the 

annual heat input from component “i”;
Page 29 of 78

(C) Calculate the annual CH4 and N2O emissions from component “i”, using Equation C8, C-8a, C-8b, C-9a, or C-10 of this section, as applicable;

(D) Sum the annual CH4 emissions across all component fuels to obtain the annual CH4

emissions for the blend. Similarly sum the annual N2O emissions across all component fuels to 

obtain the annual N2O emissions for the blend. Report these annual emissions totals.

(d) Calculation of CO2 from sorbent. (1) When a unit is a fluidized bed boiler, is 

equipped with a wet flue gas desulfurization system, or uses other acid gas emission controls 

with sorbent injection to remove acid gases, if the chemical reaction between the acid gas and the 

sorbent produces CO2 emissions, use Equation C-11 of this section to calculate the CO2

emissions from the sorbent, except when those CO2 emissions are monitored by CEMS. When a 

sorbent other than CaCO3 is used, determine site-specific values of R and MWS.

Where:

CO2 = CO2 emitted from sorbent for the reporting year (metric tons).

S = Limestone or other sorbent used in the reporting year, from company records (short 

tons).

R = The number of moles of CO2 released upon capture of one mole of the acid gas 

species being removed (R = 1.00 when the sorbent is CaCO3 and the targeted acid gas species is 

SO2).

MWCO2 = Molecular weight of carbon dioxide (44).

MWS = Molecular weight of sorbent (100 if calcium carbonate).

0.91 = Conversion factor from short tons to metric tons.
Page 30 of 78

(2) The total annual CO2 mass emissions reported for the unit shall include the CO2

emissions from the combustion process and the CO2 emissions from the sorbent.

(e) Biogenic CO2 emissions from combustion of biomass with other fuels. Use the 

applicable procedures of this paragraph (e) to estimate biogenic CO2 emissions from units that 

combust a combination of biomass and fossil fuels (i.e., either co-fired or blended fuels). 

Separate reporting of biogenic CO2 emissions from the combined combustion of biomass and 

fossil fuels is required for those biomass fuels listed in Table C-1 of this section and for 

municipal solid waste. In addition, when a biomass fuel that is not listed in Table C-1 is 

combusted in a unit that has a maximum rated heat input greater than 250 mmBtu/hr, if the 

biomass fuel accounts for 10% or more of the annual heat input to the unit, and if the unit does 

not use CEMS to quantify its annual CO2 mass emissions, then, pursuant to §98.33(b)(3)(iii), 

Tier 3 must be used to determine the carbon content of the biomass fuel and to calculate the 

biogenic CO2 emissions from combustion of the fuel. Notwithstanding these requirements, in 

accordance with §98.3(c)(12), separate reporting of biogenic CO2 emissions is optional for the 

2010 reporting year for units subject to subpart D of this part and for units that use the CO2 mass 

emissions calculation methodologies in part 75 of this chapter, pursuant to paragraph (a)(5) of 

this section. However, if the owner or operator opts to report biogenic CO2 emissions separately 

for these units, the appropriate method(s) in this paragraph (e) shall be used. Separate reporting 

of biogenic CO2 emissions from the combustion of tires is also optional, but may be reported by 

following the provisions of paragraph (e)(3) of this section.

(1) You may use Equation C-1 of this subpart to calculate the annual CO2 mass emissions 

from the combustion of the biomass fuels listed in Table C-1 of this subpart (except MSW and 

tires), in a unit of any size, including units equipped with a CO2 CEMS, except when the use of 
Page 31 of 78

Tier 2 is required as specified in paragraph (b)(1)(iv) of this section. Determine the quantity of 

biomass combusted using one of the following procedures in this paragraph (e)(1), as 

appropriate, and document the selected procedures in the Monitoring Plan under §98.3(g):

(i) Company records.

(ii) The procedures in paragraph (e)(4) of this section.

(iii) The best available information for premixed fuels that contain biomass and fossil 

fuels (e.g., liquid fuel mixtures containing biodiesel).

(2) You may use the procedures of this paragraph if the following three conditions are 

met: First, a CO2 CEMS (or a surrogate O2 monitor) and a stack gas flow rate monitor are used to

determine the annual CO2 mass emissions (either according to part 75 of this chapter, the Tier 4 

Calculation Methodology, or the alternative calculation methodology specified in paragraph 

(a)(5)(iii) of this section); second, neither MSW nor tires is combusted in the unit during the 

reporting year; and third, the CO2 emissions consist solely of combustion products (i.e., no 

process or sorbent emissions included).

(i) For each operating hour, use Equation C-12 of this section to determine the volume of 

CO2 emitted.

Where:

VCO2h = Hourly volume of CO2 emitted (scf).

(%CO2)h = Hourly average CO2 concentration, measured by the CO2 concentration 

monitor, or, if applicable, calculated from the hourly average O2 concentration (%CO2).

Qh = Hourly average stack gas volumetric flow rate, measured by the stack gas 

volumetric flow rate monitor (scfh).
Page 32 of 78

th = Source operating time (decimal fraction of the hour during which the source 

combusts fuel, i.e., 1.0 for a full operating hour, 0.5 for 30 minutes of operation, etc.).

100 = Conversion factor from percent to a decimal fraction.

(ii) Sum all of the hourly VCO2h values for the reporting year, to obtain Vtotal, the total 

annual volume of CO2 emitted.

(iii) Calculate the annual volume of CO2 emitted from fossil fuel combustion using 

Equation C-13 of this section. If two or more types of fossil fuel are combusted during the year, 

perform a separate calculation with Equation C-13 of this section for each fuel and sum the 

results.

Where:

Vff = Annual volume of CO2 emitted from combustion of a particular fossil fuel (scf).

Fuel = Total quantity of the fossil fuel combusted in the reporting year, from company

records, as defined in §98.6 (lb for solid fuel, gallons for liquid fuel, and scf for gaseous fuel).

Fc = Fuel-specific carbon based F-factor, either a default value from Table 1 in section 

3.3.5 of appendix F to part 75 of this chapter, or a site-specific value determined under section 

3.3.6 of appendix F to part 75 (scf CO2/mmBtu).

HHV = High heat value of the fossil fuel, from fuel sampling and analysis (annual 

average value in Btu/lb for solid fuel, Btu/gal for liquid fuel and Btu/scf for gaseous fuel, 

sampled as specified (e.g., monthly, quarterly, semi-annually, or by lot) in §98.34(a)(2)). The 

average HHV shall be calculated according to the requirements of paragraph (a)(2)(ii) of this 

section.

106= Conversion factor, Btu per mmBtu.
Page 33 of 78

(iv) Subtract Vff from Vtotal to obtain Vbio, the annual volume of CO2 from the combustion 

of biomass.

(v) Calculate the biogenic percentage of the annual CO2 emissions, expressed as a 

decimal fraction, using Equation C-14 of this section:

(vi) Calculate the annual biogenic CO2 mass emissions, in metric tons, by multiplying the 

results obtained from Equation C-14 of this section by the annual CO2 mass emissions in metric 

tons, as determined:

(A) Under paragraph (a)(4)(vi) of this section, for units using the Tier 4 Calculation 

Methodology.

(B) Under paragraph (a)(5)(iii)(B) of this section, for units using the alternative 

calculation methodology specified in paragraph (a)(5)(iii).

(C) From the electronic data report required under §75.64 of this chapter, for units in the 

Acid Rain Program and other units using CEMS to monitor and report CO2 mass emissions 

according to part 75 of this chapter. However, before calculating the annual biogenic CO2 mass 

emissions, multiply the cumulative annual CO2 mass emissions by 0.91 to convert from short 

tons to metric tons.

(3) You must use the procedures in paragraphs (e)(3)(i) through (e)(3)(iii) of this section 

to determine the annual biogenic CO2 emissions from the combustion of MSW, except as 

otherwise provided in paragraph (e)(3)(iv) of this section. These procedures also may be used for 

any unit that co-fires biomass and fossil fuels, including units equipped with a CO2 CEMS, and 

units for which optional separate reporting of biogenic CO2 emissions from the combustion of 

tires is selected.
Page 34 of 78

(i) Use an applicable CO2 emissions calculation method in this section to quantify the 

total annual CO2 mass emissions from the unit.

(ii) Determine the relative proportions of biogenic and non-biogenic CO2 emissions in the 

flue gas on a quarterly basis using the method specified in §98.34(d) (for units that combust 

MSW as the primary fuel or as the only fuel with a biogenic component) or in §98.34(e) (for 

other units, including units that combust tires).

(iii) Determine the annual biogenic CO2 mass emissions from the unit by multiplying the 

total annual CO2 mass emissions by the annual average biogenic decimal fraction obtained from 

§98.34(d) or §98.34(e), as applicable.

(iv) If the combustion of MSW and/or tires provides no more than 10 percent of the 

annual heat input to a unit, or if a small, batch incinerator combusts no more than 1,000 tons per 

year of MSW, you may estimate the annual biogenic CO2 emissions as follows, in lieu of 

following the procedures in paragraphs (e)(3)(i) through (e)(3)(iii) of this section:

(A) Calculate the total annual CO2 emissions from combustion of MSW and/or tires in 

the unit, using the Tier 1 calculation methodology in paragraph (a)(1) of this section.

(B) Multiply the result from paragraph (e)(3)(iv)(A) of this section by the appropriate 

default factor to determine the annual biogenic CO2 emissions, in metric tons. For MSW, use a 

default factor of 0.60 and for tires, use a default factor of 0.20.

(4) If Equation C-1 or Equation C-2a of this section is selected to calculate the annual 

biogenic mass emissions for wood, wood waste, or other solid biomass-derived fuel, Equation C15 of this section may be used to quantify biogenic fuel consumption, provided that all of the 

required input parameters are accurately quantified. Similar equations and calculation 
Page 35 of 78

methodologies based on steam generation and boiler efficiency may be used, provided that they

are documented in the GHG Monitoring Plan required by §98.3(g)(5).

Where:

(Fuel)p = Quantity of biomass consumed during the measurement period “p” (tons/year or 

tons/month, as applicable).

H = Average enthalpy of the boiler steam for the measurement period (Btu/lb).

S = Total boiler steam production for the measurement period (lb/month or lb/year, as 

applicable).

(HI)nb = Heat input from co-fired fossil fuels and non-biomass-derived fuels for the 

measurement period, based on company records of fuel usage and default or measured HHV 

values (Btu/month or Btu/year, as applicable).

(HHV)bio = Default or measured high heat value of the biomass fuel (Btu/lb).

(Eff)bio = Percent efficiency of biomass-to-energy conversion, expressed as a decimal 

fraction.

2000 = Conversion factor (lb/ton).

(5) For units subject to subpart D of this part and for units that use the methods in part 75 

of this chapter to quantify CO2 mass emissions in accordance with paragraph (a)(5) of this 

section, you may calculate biogenic CO2 emissions from the combustion of biomass fuels listed 

in Table C-1 of this subpart using Equation C-15a. This equation may not be used to calculate 

biogenic CO2 emissions from the combustion of tires or MSW; the methods described in 

paragraph (e)(3) of this section must be used for those fuels. Whenever (HI)A, the annual heat 

input from combustion of biomass fuel in Equation C-15a, cannot be determined solely from the 
Page 36 of 78

information in the electronic emissions reports under §75.64 of this chapter (e.g., in cases where 

a unit uses CEMS in combination with multiple F-factors, a worst-case F-factor, or a prorated Ffactor to report heat input rather than reporting heat input based on fuel type), use the best 

available information (as described in §§98.33(c)(4)(ii)(C) and (c)(4)(ii)(D)) to determine (HI)A.

CO2 = 0.001 * (HI)A * EF (Eq. C-15a)

where:

CO2 = Annual CO2 mass emissions from the combustion of a particular type of biomass 

fuel listed in Table C-1 (metric tons)

(HI)A = Annual heat input from the biomass fuel, obtained, where feasible, from the 

electronic emissions reports required under §75.64 of this chapter. Where this is not feasible use 

best available information, as described in §§98.33(c)(4)(ii)(C) and (c)(4)(ii)(D) (mmBtu)

EF = CO2 emission factor for the biomass fuel, from Table C-1 (kg CO2/mmBtu)

0.001 = Conversion factor from kg to metric tons

§98.34 Monitoring and QA/QC requirements.

The CO2 mass emissions data for stationary fuel combustion sources shall be monitored 

as follows:

(a) For the Tier 2 Calculation Methodology:

(1) All fuel samples shall be taken at a location in the fuel handling system that provides 

a sample representative of the fuel combusted. The fuel sampling and analysis may be performed 

by either the owner or operator or the supplier of the fuel.

(2) The minimum required frequency of the HHV sampling and analysis for each type of 

fuel or fuel mixture (blend) is specified in this paragraph. When the specified frequency for a 

particular fuel or blend is based on a specified time period (e.g., week, month, quarter, or half-
Page 37 of 78

year), fuel sampling and analysis is required only for those time periods in which the fuel or 

blend is combusted. The owner or operator may perform fuel sampling and analysis more often 

than the minimum required frequency, in order to obtain a more representative annual average 

HHV.

(i) For natural gas, semiannual sampling and analysis is required (i.e., twice in a calendar 

year, with consecutive samples taken at least four months apart).

(ii) For coal and fuel oil, and for any other solid or liquid fuel that is delivered in lots, 

analysis of at least one representative sample from each fuel lot is required. For fuel oil, as an 

alternative to sampling each fuel lot, a sample may be taken upon each addition of oil to the 

unit's storage tank. Flow proportional sampling, continuous drip sampling, or daily manual oil 

sampling may also be used, in lieu of sampling each fuel lot. If the daily manual oil sampling 

option is selected, sampling from a particular tank is required only on days when oil from the 

tank is combusted by the unit (or units) served by the tank. If you elect to sample from the 

storage tank upon each addition of oil to the tank, you must take at least one sample from each 

tank that is currently in service and whenever oil is added to the tank, for as long as the tank 

remains in service. You need not take any samples from a storage tank while it is out of service. 

Rather, take a sample when the tank is brought into service and whenever oil is added to the 

tank, for as long as the tank remains in service. If multiple additions of oil are made to a 

particular in-service tank on a given day (e.g., from multiple deliveries), one sample taken after 

the final addition of oil is sufficient. For the purposes of this section, a fuel lot is defined as a 

shipment or delivery of a single type of fuel (e.g., ship load, barge load, group of trucks, group of 

railroad cars, oil delivery via pipeline from a tank farm, etc.). However, if multiple deliveries of 

a particular type of fuel are received from the same supply source in a given calendar month, the 
Page 38 of 78

deliveries for that month may be considered, collectively, to comprise a fuel lot, requiring only 

one representative sample, subject to the following conditions:

(A) For coal, the “type” of fuel means the rank of the coal (i.e., anthracite, bituminous, 

sub-bituminous, or lignite). For fuel oil, the “type” of fuel means the grade number or 

classification of the oil (e.g., No. 1 oil, No. 2 oil, kerosene, Jet A fuel, etc.).

(B) The owner or operator shall document in the monitoring plan under §98.3(g)(5) how 

the monthly sampling of each type of fuel is performed.

(iii) For liquid fuels other than fuel oil, and for gaseous fuels other than natural gas 

(including biogas), sampling and analysis is required at least once per calendar quarter. To the 

extent practicable, consecutive quarterly samples shall be taken at least 30 days apart.

(iv) For other solid fuels (except MSW), weekly sampling is required to obtain composite 

samples, which are then analyzed monthly.

(v) For fuel blends that are received already mixed, or that are mixed on-site without 

measuring the exact amount of each component, as described in paragraph (a)(3)(ii) of this 

section, determine the HHV of the blend as follows. For blends of solid fuels (except MSW), 

weekly sampling is required to obtain composite samples, which are analyzed monthly. For 

blends of liquid or gaseous fuels, sampling and analysis is required at least once per calendar 

quarter. More frequent sampling is recommended if the composition of the blend varies 

significantly during the year.

(3) Special considerations for blending of fuels. In situations where different types of fuel 

listed in Table C-1 of this subpart (for example, different ranks of coal or different grades of fuel 

oil) are in the same state of matter (i.e., solid, liquid, or gas), and are blended prior to 
Page 39 of 78

combustion, use the following procedures to determine the appropriate CO2 emission factor and 

HHV for the blend.

(i) If the fuels to be blended are received separately, and if the quantity (mass or volume) 

of each fuel is measured before the fuels are mixed and combusted, then, for each component of 

the blend, calculate the CO2 mass emissions separately. Substitute into Equation C-2a of this 

subpart the total measured mass or volume of the component fuel (from company records), 

together with the appropriate default CO2 emission factor from Table C-1, and the annual 

average HHV, calculated according to §98.33(a)(2)(ii). In this case, the fact that the fuels are 

blended prior to combustion is of no consequence.

(ii) If the fuel is received as a blend (i.e., already mixed) or if the components are mixed 

on site without precisely measuring the mass or volume of each one individually, a reasonable 

estimate of the relative proportions of the components of the blend must be made, using the best 

available information (e.g., the approximate annual average mass or volume percentage of each 

fuel, based on the typical or expected range of values). Determine the appropriate CO2 emission 

factor and HHV for use in Equation C-2a of this subpart, as follows:

(A) Consider the blend to be the “fuel type,” measure its HHV at the frequency

prescribed in paragraph (a)(2)(v) of this section, and determine the annual average HHV value 

for the blend according to §98.33(a)(2)(ii).

(B) Calculate a heat-weighted CO2 emission factor, (EF)B, for the blend, using Equation 

C-16 of this section. The heat-weighting in Equation C-16 is provided by the default HHVs 

(from Table C-1) and the estimated mass or volume percentages of the components of the blend.

(C) Substitute into Equation C-2a of this subpart, the annual average HHV for the blend 

(from paragraph (a)(3)(ii)(A) of this section) and the calculated value of (EF)B, along with the 
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total mass or volume of the blend combusted during the reporting year, to determine the annual 

CO2 mass emissions from combustion of the blend.

where:

(EF)B = Heat-weighted CO2 emission factor for the blend (kg CO2/mmBtu)

(HHV)i = Default high heat value for fuel “i” in the blend, from Table C-1 (mmBtu per 

mass or volume)

(%Fuel)i = Estimated mass or volume percentage of fuel “i” (mass % or volume %, as 

applicable, expressed as a decimal fraction; e.g., 25% = 0.25)

(EF)i = Default CO2 emission factor for fuel “i” from Table C-1 (mmBtu per mass or 

volume)

(HHV)B = Annual average high heat value for the blend, calculated according to 

§98.33(a)(2)(ii) (mmBtu per mass or volume)

(iii) Note that for the case described in paragraph (a)(3)(ii) of this section, if measured 

HHV values for the individual fuels in the blend or for the blend itself are not routinely received 

at the minimum frequency prescribed in paragraph (a)(2) of this section (or at a greater 

frequency), and if the unit qualifies to use Tier 1, calculate (HHV)B*, the heat-weighted default 

HHV for the blend, using Equation C-17 of this section. Then, use Equation C-16 of this section, 

replacing the term (HHV)B with (HHV)B* in the denominator, to determine the heat-weighted 

CO2 emission factor for the blend. Finally, substitute into Equation C-1 of this subpart, the 

calculated values of (HHV)B* and (EF)B, along with the total mass or volume of the blend 

combusted during the reporting year, to determine the annual CO2 mass emissions from 

combustion of the blend.
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where:

(HHV)B* = Heat-weighted default high heat value for the blend (mmBtu per mass or 

Volume)

(HHV)i = Default high heat value for fuel “i” in the blend, from Table C-1 (mmBtu per 

mass or volume)

(%Fuel)i = Estimated mass or volume percentage of fuel “i” in the blend (mass % or 

volume %, as applicable, expressed as a decimal fraction)

(iv) If the fuel blend described in paragraph (a)(3)(ii) of this section consists of a mixture 

of fuel(s) listed in Table C-1 of this subpart and one or more fuels not listed in Table C-1, 

calculate CO2 and other GHG emissions only for the Table C-1 fuel(s), using the best available 

estimate of the mass or volume percentage(s) of the Table C-1 fuel(s) in the blend. In this case, 

Tier 1 shall be used, with the following modifications to Equations C-17 and C-1, to account for 

the fact that not all of the fuels in the blend are listed in Table C-1:

(A) In Equation C-17, apply the term (Fuel)i only to the Table C-1 fuels. For each Table 

C-1 fuel, (Fuel)i will be the estimated mass or volume percentage of the fuel in the blend, divided 

by the sum of the mass or volume percentages of the Table C-1 fuels. For example, suppose that 

a blend consists of two Table C-1 fuels (“A” and “B”) and one fuel type (“C”) not listed in the 

Table, and that the volume percentages of fuels A, B, and C in the blend, expressed as decimal 

fractions, are, respectively, 0.50, 0.30, and 0.20. The term (Fuel)i in Equation C-17 for fuel A 

will be 0.50/(0.50 + 0.30) = 0.625, and for fuel B, (Fuel)i will be 0.30/(0.50 + 0.30) = 0.375.

(B) In Equation C-1, the term “Fuel” will be equal to the total mass or volume of the 

blended fuel combusted during the year multiplied by the sum of the mass or volume percentages 
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of the Table C-1 fuels in the blend. For the example in paragraph (a)(3)(iv)(A) of this section, 

“Fuel” = (Annual volume of the blend combusted)(0.80).

(4) If, for a particular type of fuel, HHV sampling and analysis is performed more often 

than the minimum frequency specified in paragraph (a)(2) of this section, the results of all valid 

fuel analyses shall be used in the GHG emission calculations.

(5) If, for a particular type of fuel, valid HHV values are obtained at less than the 

minimum frequency specifed in paragraph (a)(2) of this section, appropriate substitute data 

values shall be used in the emissions calculations, in accordance with missing data procedures of 

§98.35.

(6) You must use one of the following appropriate fuel sampling and analysis methods. 

The HHV may be calculated using chromatographic analysis together with standard heating 

values of the fuel constituents, provided that the gas chromatograph is operated, maintained, and 

calibrated according to the manufacturer's instructions. Alternatively, you may use a method 

published by a consensus-based standards organization if such a method exists, or you may use 

industry standard practice to determine the high heat values. Consensus-based standards 

organizations include, but are not limited to, the following: ASTM International (100 Barr 

Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-

1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, 

NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American 

Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 

824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American 

Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000,
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http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org). The method(s) 

used shall be documented in the Monitoring Plan required under §98.3(g)(5).

(b) For the Tier 3 Calculation Methodology:

(1) You must calibrate each oil and gas flow meter according to §98.3(i) and the 

provisions of this paragraph (b)(1).

(i) Perform calibrations using any of the test methods and procedures in this paragraph 

(b)(1)(i). The method(s) used shall be documented in the Monitoring Plan required under 

§98.3(g)(5).

(A) You may use the calibration procedures specified by the flow meter manufacturer.

(B) You may use an appropriate flow meter calibration method published by a consensusbased standards organization, if such a method exists. Consensus-based standards organizations 

include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. 

Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, 

http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th 

floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 

824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American 

Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, 

http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).

(C) You may use an industry-accepted practice.
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(ii) In addition to the initial calibration required by §98.3(i), recalibrate each fuel flow 

meter (except as otherwise provided in paragraph (b)(1)(iii) of this section) according to one of 

the following. You may recalibrate annually, at the minimum frequency specified by the 

manufacturer, or at the interval specified by industry standard practice.

(iii) Fuel billing meters are exempted from the initial and ongoing calibration 

requirements of this paragraph and from the Monitoring Plan and recordkeeping requirements of 

§§98.3(g)(5)(i)(C), (g)(6), and (g)(7), provided that the fuel supplier and the unit combusting the 

fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same 

company. Meters used exclusively to measure the flow rates of fuels that are only used for unit 

startup are also exempted from the initial and ongoing calibration requirements of this paragraph.

(iv) For the initial calibration of an orifice, nozzle, or venturi meter; in-situ calibration of 

the transmitters is sufficient. A primary element inspection (PEI) shall be performed at least once 

every three years.

(v) For the continuously-operating units and processes described in §98.3(i)(6), the 

required flow meter recalibrations and, if necessary, the PEIs may be postponed until the next 

scheduled maintenance outage.

(vi) If a mixture of liquid or gaseous fuels is transported by a common pipe, you may

either separately meter each of the fuels prior to mixing, using flow meters calibrated according 

to §98.3(i), or consider the fuel mixture to be the “fuel type” and meter the mixed fuel, using a 

flow meter calibrated according to §98.3(i).

(2) Oil tank drop measurements (if used to determine liquid fuel use volume) shall be 

performed according to any an appropriate method published by a consensus-based standards 

organization (e.g., the American Petroleum Institute).
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(3) The carbon content and, if applicable, molecular weight of the fuels shall be 

determined according to the procedures in this paragraph (b)(3).

(i) All fuel samples shall be taken at a location in the fuel handling system that provides a 

sample representative of the fuel combusted. The fuel sampling and analysis may be performed 

by either the owner or operator or by the supplier of the fuel.

(ii) For each type of fuel, the minimum required frequency for collecting and analyzing 

samples for carbon content and (if applicable) molecular weight is specified in this paragraph. 

When the sampling frequency is based on a specified time period (e.g., week, month, quarter, or 

half-year), fuel sampling and analysis is required for only those time periods in which the fuel is 

combusted.

(A) For natural gas, semiannual sampling and analysis is required (i.e., twice in a 

calendar year, with consecutive samples taken at least four months apart).

(B) For coal and fuel oil and for any other solid or liquid fuel that is delivered in lots, 

analysis of at least one representative sample from each fuel lot is required. For fuel oil, as an 

alternative to sampling each fuel lot, a sample may be taken upon each addition of oil to the 

storage tank. Flow proportional sampling, continuous drip sampling, or daily manual oil 

sampling may also be used, in lieu of sampling each fuel lot. If the daily manual oil sampling 

option is selected, sampling from a particular tank is required only on days when oil from the 

tank is combusted by the unit (or units) served by the tank. If you elect to sample from the 

storage tank upon each addition of oil to the tank, you must take at least one sample from each 

tank that is currently in service and whenever oil is added to the tank, for as long as the tank 

remains in service. You need not take any samples from a storage tank while it is out of service. 

Rather, take a sample when the tank is brought into service and whenever oil is added to the 
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tank, for as long as the tank remains in service. If multiple additions of oil are made to a 

particular in service tank on a given day (e.g., from multiple deliveries), one sample taken after 

the final addition of oil is sufficient. For the purposes of this section, a fuel lot is defined as a 

shipment or delivery of a single type of fuel (e.g., ship load, barge load, group of trucks, group of 

railroad cars, oil delivery via pipeline from a tank farm, etc.). However, if multiple deliveries of 

a particular type of fuel are received from the same supply source in a given calendar month, the 

deliveries for that month may be considered, collectively, to comprise a fuel lot, requiring only 

one representative sample, subject to the following conditions:

(1) For coal, the “type” of fuel means the rank of the coal (i.e., anthracite, bituminous, 

sub-bituminous, or lignite). For fuel oil, the “type” of fuel means the grade number or 

classification of the oil (e.g., No. 1 oil, No. 2 oil, kerosene, Jet A fuel, etc.).

(2) The owner or operator shall document in the monitoring plan under §98.3(g)(5) how 

the monthly sampling of each type of fuel is performed.

(C) For liquid fuels other than fuel oil and for biogas, sampling and analysis is required at 

least once per calendar quarter. To the extent practicable, consecutive quarterly samples shall be 

taken at least 30 days apart.

(D) For other solid fuels (except MSW), weekly sampling is required to obtain composite 

samples, which are then analyzed monthly.

(E) For gaseous fuels other than natural gas and biogas (e.g., process gas), daily sampling 

and analysis to determine the carbon content and molecular weight of the fuel is required if 

continuous, on-line equipment, such as a gas chromatograph, is in place to make these 

measurements. Otherwise, weekly sampling and analysis shall be performed.
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(F) For mixtures (blends) of solid fuels, weekly sampling is required to obtain composite 

samples, which are analyzed monthly. For blends of liquid fuels, and for gas mixtures consisting 

only of natural gas and biogas, sampling and analysis is required at least once per calendar 

quarter. For gas mixtures that contain gases other than natural gas (including biogas), daily 

sampling and analysis to determine the carbon content and molecular weight of the fuel is 

required if continuous, on-line equipment is in place to make these measurements. Otherwise, 

weekly sampling and analysis shall be performed.

(iii) If, for a particular type of fuel, sampling and analysis for carbon content and 

molecular weight is performed more often than the minimum frequency specified in paragraph 

(b)(3) of this section, the results of all valid fuel analyses shall be used in the GHG emission 

calculations.

(iv) If, for a particular type of fuel, sampling and analysis for carbon content and 

molecular weight is performed at less than the minimum frequency specified in paragraph (b)(3) 

of this section, appropriate substitute data values shall be used in the emissions calculations, in 

accordance with the missing data procedures of §98.35.

(v) To calculate the CO2 mass emissions from combustion of a blend of fuels in the same 

state of matter (solid, liquid, or gas), you may either:

(A) Apply Equation C-3, C-4 or C-5 of this subpart (as applicable) to each component of 

the blend, if the mass or volume, the carbon content, and (if applicable), the molecular weight of 

each component are accurately measured prior to blending; or

(B) Consider the blend to be the “fuel type.” Then, at the frequency specified in 

paragraph (b)(3)(ii)(F) of this section, measure the carbon content and, if applicable, the 

molecular weight of the blend and calculate the annual average value of each parameter in the 
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manner described in §98.33(a)(2)(ii). Also measure the mass or volume of the blended fuel 

combusted during the reporting year. Substitute these measured values into Equation C-3, C-4, or 

C-5 of this subpart (as applicable).

(4) You must use one of the following appropriate fuel sampling and analysis methods. 

The results of chromatographic analysis of the fuel may be used, provided that the gas 

chromatograph is operated, maintained, and calibrated according to the manufacturer's 

instructions. Alternatively, you may use a method published by a consensus-based standards 

organization if such a method exists, or you may use industry standard practice to determine the 

carbon content and molecular weight (for gaseous fuel) of the fuel. Consensus-based standards 

organizations include, but are not limited to, the following: ASTM International (100 Barr 

Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-

1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, 

NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American 

Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 

824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American 

Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, 

http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org). The method(s) 

used shall be documented in the Monitoring Plan required under §98.3(g)(5).

(c) For the Tier 4 Calculation Methodology, the CO2, flow rate, and (if applicable) 

moisture monitors must be certified prior to the applicable deadline specified in §98.33(b)(5).
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(1) For initial certification, you may use any one of the following three procedures in this 

paragraph.

(i) §§75.20(c)(2), (c)(4), and (c)(5) through (c)(7) of this chapter and appendix A to part 

75 of this chapter.

(ii) The calibration drift test and relative accuracy test audit (RATA) procedures of 

Performance Specification 3 in appendix B to part 60 of this chapter (for the CO2 concentration 

monitor) and Performance Specification 6 in appendix B to part 60 of this chapter (for the 

continuous emission rate monitoring system (CERMS)).

(iii) The provisions of an applicable State continuous monitoring program.

(2) If an O2 concentration monitor is used to determine CO2 concentrations, the 

applicable provisions of part 75 of this chapter, part 60 of this chapter, or an applicable State 

continuous monitoring program shall be followed for initial certification and on-going quality

assurance, and all required RATAs of the monitor shall be done on a percent CO2 basis.

(3) For ongoing quality assurance, follow the applicable procedures in either appendix B 

to part 75 of this chapter, appendix F to part 60 of this chapter, or an applicable State continuous 

monitoring program. If appendix F to part 60 of this chapter is selected for on-going quality

assurance, perform daily calibration drift assessments for both the CO2 monitor (or surrogate O2

monitor) and the flow rate monitor, conduct cylinder gas audits of the CO2 concentration monitor 

in three of the four quarters of each year (except for non-operating quarters), and perform annual 

RATAs of the CO2 concentration monitor and the CERMS.

(4) For the purposes of this part, the stack gas volumetric flow rate monitor RATAs 

required by appendix B to part 75 of this chapter and the annual RATAs of the CERMS required 

by appendix F to part 60 of this chapter need only be done at one operating level, representing 
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normal load or normal process operating conditions, both for initial certification and for ongoing 

quality assurance.

(5) If, for any source operating hour, quality assured data are not obtained with a CO2

monitor (or surrogate O2 monitor), flow rate monitor, or (if applicable) moisture monitor, use 

appropriate substitute data values in accordance with the missing data provisions of §98.35.

(6) For certain applications where combined process emissions and combustion emissions 

are measured, the CO2 concentrations in the flue gas may be considerably higher than for 

combustion emissions alone. In such cases, the span of the CO2 monitor may, if necessary, be set 

higher than the specified levels in the applicable regulations. If the CO2 span value is set higher 

than 20 percent CO2, the cylinder gas audits of the CO2 monitor under appendix F to part 60 of 

this chapter may be performed at 40 to 60 percent and 80 to 100 percent of span, in lieu of the 

prescribed calibration levels of 5 to 8 percent CO2 and 10 to 14 percent CO2.

(7) Hourly average data from the CEMS shall be validated in a manner consistent with 

one of the following: §§60.13(h)(2)(i) through (h)(2)(vi) of this chapter; §75.10(d)(1) of this 

chapter; or the hourly data validation requirements of an applicable State CEM regulation.

(d) Except as otherwise provided in §98.33 (b)(1)(vi) and (b)(1)(vii), when municipal 

solid waste (MSW) is either the primary fuel combusted in a unit or the only fuel with a biogenic 

component combusted in the unit, determine the biogenic portion of the CO2 emissions using 

ASTM D6866-12 Standard Test Methods for Determining the Biobased Content of Solid, 

Liquid, and Gaseous Samples Using Radiocarbon Analysis (incorporated by reference, see 

§98.7) and ASTM D7459-08 Standard Practice for Collection of Integrated Samples for the 

Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide Emitted from Stationary

Emissions Sources (incorporated by reference, see §98.7). Perform the ASTM D7459-08 
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sampling and the ASTM D6866-12 analysis at least once in every calendar quarter in which 

MSW is combusted in the unit. Collect each gas sample during normal unit operating conditions 

for at least 24 total (not necessarily consecutive) hours, or longer if the facility deems it 

necessary to obtain a representative sample. Notwithstanding this requirement, if the types of 

fuels combusted and their relative proportions are consistent throughout the year, the minimum 

required sampling time may be reduced to 8 hours if at least two 8-hour samples and one 24-hour 

sample are collected under normal operating conditions, and arithmetic average of the biogenic 

fraction of the flue gas from the 8-hour samples (expressed as a decimal) is within ±5 percent of 

the biogenic fraction from the 24-hour test. There must be no overlapping of the 8-hour and 24-

hour test periods. Document the results of the demonstration in the unit's monitoring plan. If the 

types of fuels and their relative proportions are not consistent throughout the year, an optional 

sampling approach that facilities may wish to consider to obtain a more representative sample is 

to collect an integrated sample by extracting a small amount of flue gas (e.g., 1 to 5 cc) in each 

unit operating hour during the quarter. Separate the total annual CO2 emissions into the biogenic 

and non-biogenic fractions using the average proportion of biogenic emissions of all samples 

analyzed during the reporting year. Express the results as a decimal fraction (e.g., 0.30, if 30 

percent of the CO2 is biogenic). When MSW is the primary fuel for multiple units at the facility, 

and the units are fed from a common fuel source, testing at only one of the units is sufficient.

(e) For other units that combust combinations of biomass fuel(s) (or heterogeneous fuels 

that have a biomass component, e.g., tires) and fossil (or other non-biogenic) fuel(s), in any 

proportions, ASTM D6866-12 (incorporated by reference, see §98.7) and ASTM D7459-08 

(incorporated by reference, see §98.7) may be used to determine the biogenic portion of the CO2

emissions in every calendar quarter in which biomass and non-biogenic fuels are co-fired in the 
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unit. Follow the procedures in paragraph (d) of this section. If the primary fuel for multiple units 

at the facility consists of tires, and the units are fed from a common fuel source, testing at only 

one of the units is sufficient.

(f) The records required under §98.3(g)(2)(i) shall include an explanation of how the 

following parameters are determined from company records (or, if applicable, from the best 

available information):

(1) Fuel consumption, when the Tier 1 and Tier 2 Calculation Methodologies are used, 

including cases where §98.36(c)(4) applies.

(2) Fuel consumption, when solid fuel is combusted and the Tier 3 Calculation 

Methodology is used.

(3) Fossil fuel consumption when §98.33(e)(2) applies to a unit that uses CEMS to 

quantify CO2 emissions and that combusts both fossil and biomass fuels.

(4) Sorbent usage, when §98.33(d) applies.

(5) Quantity of steam generated by a unit when §98.33(a)(2)(iii) applies.

(6) Biogenic fuel consumption and high heating value, as applicable, under §§98.33(e)(5) 

and (e)(6).

(7) Fuel usage for CH4 and N2O emissions calculations under §98.33(c)(4)(ii).

(8) Mass of biomass combusted, for premixed fuels that contain biomass and fossil fuels 

under §98.33(e)(1)(iii).

[74 FR 56374, Oct. 30, 2009, as amended at 75 FR 79146, Dec. 17, 2010]
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§98.35 Procedures for estimating missing data.

Whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS 

malfunctions during unit operation or if a required fuel sample is not taken), a substitute data 

value for the missing parameter shall be used in the calculations.

(a) For all units subject to the requirements of the Acid Rain Program, and all other 

stationary combustion units subject to the requirements of this part that monitor and report 

emissions and heat input data year-round in accordance with part 75 of this chapter, the missing 

data substitution procedures in part 75 of this chapter shall be followed for CO2 concentration, 

stack gas flow rate, fuel flow rate, high heating value, and fuel carbon content.

(b) For units that use the Tier 1, Tier 2, Tier 3, and Tier 4 Calculation Methodologies, 

perform missing data substitution as follows for each parameter:

(1) For each missing value of the high heating value, carbon content, or molecular weight 

of the fuel, substitute the arithmetic average of the quality-assured values of that parameter 

immediately preceding and immediately following the missing data incident. If the “after” value 

has not been obtained by the time that the GHG emissions report is due, you may use the 

“before” value for missing data substitution or the best available estimate of the parameter, based 

on all available process data (e.g., electrical load, steam production, operating hours). If, for a 

particular parameter, no quality-assured data are available prior to the missing data incident, the 

substitute data value shall be the first quality-assured value obtained after the missing data 

period.

(2) For missing records of CO2 concentration, stack gas flow rate, percent moisture, fuel 

usage, and sorbent usage, the substitute data value shall be the best available estimate of the 
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parameter, based on all available process data (e.g., electrical load, steam production, operating 

hours, etc.). You must document and retain records of the procedures used for all such estimates.

§ 98.36 Data reporting requirements.

(a) In addition to the facility-level information required under § 98.3, the annual GHG 

emissions report shall contain the unit-level or process-level data specified in paragraphs (b) 

through (f) of this section, as applicable, for each stationary fuel combustion source (e.g., 

individual unit, aggregation of units, common pipe, or common stack) except as otherwise 

provided in this paragraph. For the data specified in paragraphs (b)(9)(iii), (c)(2)(ix), (e)(2)(i), 

(e)(2)(ii)(A), (e)(2)(ii)(C), (e)(2)(ii)(D), and (e)(2)(iv)(A), (e)(2)(iv)(C), (e)(2)(iv)(F), and 

(e)(2)(ix)(D) through (F) of this section, the owner or operator of a stationary fuel combustion 

source that does not meet the criteria specified in paragraph (f) of this section may elect either to 

report the data specified in this sentence in the annual report or to use verification software 

according to § 98.5(b) in lieu of reporting these data. If you elect to use this verification 

software, you must use the verification software according to § 98.5(b) for all of these data that 

apply to the stationary fuel combustion source.

(b) Units that use the four tiers. You shall report the following information for stationary

combustion units that use the Tier 1, Tier 2, Tier 3, or Tier 4 methodology in § 98.33(a) to 

calculate CO2 emissions, except as otherwise provided in paragraphs (c) and (d) of this section:

(1) The unit ID number.

(2) A code representing the type of unit.

(3) Maximum rated heat input capacity of the unit, in mmBtu/hr.

(4) Each type of fuel combusted in the unit during the report year.
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(5) The methodology (i.e., tier) used to calculate the CO2 emissions for each type of fuel 

combusted (i.e., Tier 1, 2, 3, or 4).

(6) The methodology start date, for each fuel type.

(7) The methodology end date, for each fuel type.

(8) For a unit that uses Tiers 1, 2, or 3:

(i) The annual CO2 mass emissions (including biogenic CO2), and the annual CH4, and 

N2O mass emissions for each type of fuel combusted during the reporting year, expressed in 

metric tons of each gas and in metric tons of CO2e; and

(ii) Metric tons of biogenic CO2 emissions (if applicable).

(9) For a unit that uses Tier 4:

(i) If the total annual CO2 mass emissions measured by the CEMS consists entirely of 

non-biogenic CO2 (i.e., CO2 from fossil fuel combustion plus, if applicable, CO2 from sorbent 

and/or process CO2), report the total annual CO2 mass emissions, expressed in metric tons. You 

are not required to report the combustion CO2 emissions by fuel type.

(ii) Report the total annual CO2 mass emissions measured by the CEMS. If this total 

includes both biogenic and non-biogenic CO2, separately report the annual non-biogenic CO2

mass emissions and the annual CO2 mass emissions from biomass combustion, each expressed in 

metric tons. You are not required to report the combustion CO2 emissions by fuel type.

(iii) An estimate of the heat input from each type of fuel listed in Table C-2 of this 

subpart that was combusted in the unit during the report year

(iv) The annual CH4 and N2O emissions for each type of fuel listed in Table C–2 of this 

subpart that was combusted in the unit during the report year, expressed in metric tons of each 

gas and in metric tons of CO2e.
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(10) Annual CO2 emissions from sorbent (if calculated using Equation C-11 of this 

subpart), expressed in metric tons.

(11) If applicable, the plant code (as defined in § 98.6).

(c) Reporting alternatives for units using the four Tiers. You may use any of the 

applicable reporting alternatives of this paragraph to simplify the unit-level reporting required 

under paragraph (b) of this section:

(1) Aggregation of units. If a facility contains two or more units (e.g., boilers or 

combustion turbines), each of which has a maximum rated heat input capacity of 250 mmBtu/hr 

or less, you may report the combined GHG emissions for the group of units in lieu of reporting

GHG emissions from the individual units, provided that the use of Tier 4 is not required or 

elected for any of the units and the units use the same tier for any common fuels combusted. If 

this option is selected, the following information shall be reported instead of the information in 

paragraph (b) of this section:

(i) Group ID number, beginning with the prefix “GP”.

(ii)[Reserved]

(iii) Cumulative maximum rated heat input capacity of the group (mmBtu/hr). The 

cumulative maximum rated heat input capacity shall be determined as the sum of the maximum 

rated heat input capacities for all units in the group, excluding units less than 10 (mmBtu/hr).

(iv) The highest maximum rated heat input capacity of any unit in the group (mmBtu/hr).

(v) Each type of fuel combusted in the group of units during the reporting year.

(vi) Annual CO2 mass emissions and annual CH4, and N2O mass emissions, aggregated 

for each type of fuel combusted in the group of units during the report year, expressed in metric 

tons of each gas and in metric tons of CO2e. If any of the units burn both fossil fuels and 
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biomass, report also the annual CO2 emissions from combustion of all fossil fuels combined and 

annual CO2 emissions from combustion of all biomass fuels combined, expressed in metric tons.

(vii) The methodology (i.e., tier) used to calculate the CO2 mass emissions for each type 

of fuel combusted in the units (i.e., Tier 1, Tier 2, or Tier 3).

(viii) The methodology start date, for each fuel type.

(ix) The methodology end date, for each fuel type.

(x) The calculated CO2 mass emissions (if any) from sorbent expressed in metric tons.

(xi) If applicable, the plant code (as defined in § 98.6).

(2) Monitored common stack or duct configurations. When the flue gases from two or 

more stationary fuel combustion units at a facility are combined together in a common stack or 

duct before exiting to the atmosphere and if CEMS are used to continuously monitor CO2 mass 

emissions at the common stack or duct according to the Tier 4 Calculation Methodology, you 

may report the combined emissions from the units sharing the common stack or duct, in lieu of 

separately reporting the GHG emissions from the individual units. This monitoring and reporting 

alternative may also be used when process off-gases or a mixture of combustion products and 

process gases are combined together in a common stack or duct before exiting to the atmosphere. 

Whenever the common stack or duct monitoring option is applied, the following information 

shall be reported instead of the information in paragraph (b) of this section:

(i) Common stack or duct identification number, beginning with the prefix “CS”.

(ii) Number of units sharing the common stack or duct. Report “1” when the flue gas 

flowing through the common stack or duct includes combustion products and/or process offgases, and all of the effluent comes from a single unit (e.g., a furnace, kiln, petrochemical 

production unit, or smelter).
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(iii) Combined maximum rated heat input capacity of the units sharing the common stack

or duct (mmBtu/hr). This data element is required only when all of the units sharing the common 

stack are stationary fuel combustion units.

(iv) Each type of fuel combusted in the units during the year.

(v) The methodology (tier) used to calculate the CO2 mass emissions, i.e., Tier 4.

(vi) The methodology start date.

(vii) The methodology end date.

(viii) Total annual CO2 mass emissions measured by the CEMS, expressed in metric tons. 

If any of the units burn both fossil fuels and biomass, separately report the annual non-biogenic 

CO2 mass emissions (i.e., CO2 from fossil fuel combustion plus, if applicable, CO2 from sorbent 

and/or process CO2) and the annual CO2 mass emissions from biomass combustion, each 

expressed in metric tons.

(ix) An estimate of the heat input from each type of fuel listed in Table C-2 of this 

subpart that was combusted in the units sharing the common stack or duct during the report year.

(x) For each type of fuel listed in Table C–2 of this subpart that was combusted during 

the report year in the units sharing the common stack or duct during the report year, the annual 

CH4 and N2O mass emissions from the units sharing the common stack or duct, expressed in 

metric tons of each gas and in metric tons of CO2e.

(xi) If applicable, the plant code (as defined in § 98.6).

(3) Common pipe configurations. When two or more stationary combustion units at a 

facility combust the same type of liquid or gaseous fuel and the fuel is fed to the individual units 

through a common supply line or pipe, you may report the combined emissions from the units 

served by the common supply line, in lieu of separately reporting the GHG emissions from the 
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individual units, provided that the total amount of fuel combusted by the units is accurately 

measured at the common pipe or supply line using a fuel flow meter, or, for natural gas, the 

amount of fuel combusted may be obtained from gas billing records. For Tier 3 applications, the 

flow meter shall be calibrated in accordance with § 98.34(b). If a portion of the fuel measured (or 

obtained from gas billing records) at the main supply line is diverted to either: A flare; or another 

stationary fuel combustion unit (or units), including units that use a CO2 mass emissions 

calculation method in part 75 of this chapter; or a chemical or industrial process (where it is used 

as a raw material but not combusted), and the remainder of the fuel is distributed to a group of 

combustion units for which you elect to use the common pipe reporting option, you may use 

company records to subtract out the diverted portion of the fuel from the fuel measured (or 

obtained from gas billing records) at the main supply line prior to performing the GHG 

emissions calculations for the group of units using the common pipe option. If the diverted 

portion of the fuel is combusted, the GHG emissions from the diverted portion shall be 

accounted for in accordance with the applicable provisions of this part. When the common pipe 

option is selected, the applicable tier shall be used based on the maximum rated heat input 

capacity of the largest unit served by the common pipe configuration, except where the 

applicable tier is based on criteria other than unit size. For example, if the maximum rated heat 

input capacity of the largest unit is greater than 250 mmBtu/hr, Tier 3 will apply, unless the fuel 

transported through the common pipe is natural gas or distillate oil, in which case Tier 2 may be 

used, in accordance with § 98.33(b)(2)(ii). As a second example, in accordance with § 

98.33(b)(1)(v), Tier 1 may be used regardless of unit size when natural gas is transported through 

the common pipe, if the annual fuel consumption is obtained from gas billing records in units of 
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therms or mmBtu. When the common pipe reporting option is selected, the following 

information shall be reported instead of the information in paragraph (b) of this section:

(i) Common pipe identification number, beginning with the prefix “CP”.

(ii) Cumulative maximum rated heat input capacity of the units served by the common 

pipe (mmBtu/hr). The cumulative maximum rated heat input capacity shall be determined as the 

sum of the maximum rated heat input capacities for all units served by the common pipe, 

excluding units less than 10 (mmBtu/hr).

(iii) The highest maximum rated heat input capacity of any unit served by the common 

pipe (mmBtu/hr).

(iv) The fuels combusted in the units during the reporting year.

(v) The methodology used to calculate the CO2 mass emissions (i.e., Tier 1, Tier 2, or 

Tier 3).

(vi) If the any of the units burns both fossil fuels and biomass, the annual CO2 mass 

emissions from combustion of all fossil fuels and annual CO2 emissions from combustion of all 

biomass fuels from the units served by the common pipe, expressed in metric tons.

(vii) Annual CO2 mass emissions and annual CH4 and N2O emissions from each fuel type 

for the units served by the common pipe, expressed in metric tons of each gas and in metric tons 

of CO2e.

(viii) Methodology start date.

(ix) Methodology end date.

(x) If applicable, the plant code (as defined in § 98.6).

(4) The following alternative reporting option applies to facilities at which a common 

liquid or gaseous fuel supply is shared between one or more large combustion units, such as 
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boilers or combustion turbines (including units subject to subpart D of this part and other units 

subject to part 75 of this chapter) and small combustion sources, including, but not limited to, 

space heaters, hot water heaters, and lab burners. In this case, you may simplify reporting by 

attributing all of the GHG emissions from combustion of the shared fuel to the large combustion 

unit(s), provided that:

(i) The total quantity of the fuel combusted during the report year in the units sharing the 

fuel supply is measured, either at the “gate” to the facility or at a point inside the facility, using a 

fuel flow meter, billing meter, or tank drop measurements (as applicable);

(ii) On an annual basis, at least 95 percent (by mass or volume) of the shared fuel is 

combusted in the large combustion unit(s), and the remainder is combusted in the small 

combustion sources. Company records may be used to determine the percentage distribution of 

the shared fuel to the large and small units; and

(iii) The use of this reporting option is documented in the Monitoring Plan required under 

§ 98.3(g)(5). Indicate in the Monitoring Plan which units share the common fuel supply and the 

method used to demonstrate that this alternative reporting option applies. For the small 

combustion sources, a description of the types of units and the approximate number of units is 

sufficient.

(d) Units subject to part 75 of this chapter. (1) For stationary combustion units that are 

subject to subpart D of this part, you shall report the following unit-level information:

(i) Unit or stack identification numbers. Use exact same unit, common stack, common 

pipe, or multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, 

CS001, MS1A, CP001, etc.) that are reported under § 75.64 of this chapter.
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(ii) Annual CO2 emissions at each monitored location, expressed in both short tons and 

metric tons. Separate reporting of biogenic CO2 emissions under § 98.3(c)(4)(ii) and § 

98.3(c)(4)(iii)(A) is optional only for the 2010 reporting year, as provided in § 98.3(c)(12).

(iii) Annual CH4 and N2O emissions at each monitored location, for each fuel type listed 

in Table C-2 that was combusted during the year (except as otherwise provided in § 

98.33(c)(4)(ii)(B)), expressed in metric tons of CO2e.

(iv) The total heat input from each fuel listed in Table C-2 that was combusted during the 

year (except as otherwise provided in § 98.33(c)(4)(ii)(B)), expressed in mmBtu.

(v) Identification of the Part 75 methodology used to determine the CO2 mass emissions.

(vi) Methodology start date.

(vii) Methodology end date.

(viii) Acid Rain Program indicator.

(ix) Annual CO2 mass emissions from the combustion of biomass, expressed in metric 

tons of CO2e, except where the reporting provisions of §§ 98.3(c)(12)(i) through (c)(12)(iii) are 

implemented for the 2010 reporting year.

(x) If applicable, the plant code (as defined in § 98.6).

(2) For units that use the alternative CO2 mass emissions calculation methods provided in 

§ 98.33(a)(5), you shall report the following unit-level information:

(i) Unit, stack, or pipe ID numbers. Use exact same unit, common stack, common pipe, or 

multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, CS001, 

MS1A, CP001, etc.) that are reported under §75.64 of this chapter.
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(ii) For units that use the alternative methods specified in § 98.33(a)(5)(i) and (ii) to 

monitor and report heat input data year-round according to appendix D to part 75 of this chapter 

or §75.19 of this chapter:

(A) Each type of fuel combusted in the unit during the reporting year.

(B) The methodology used to calculate the CO2 mass emissions for each fuel type.

(C) Methodology start date.

(D) Methodology end date.

(E) A code or flag to indicate whether heat input is calculated according to appendix D to 

part 75 of this chapter or §75.19 of this chapter.

(F) Annual CO2 emissions at each monitored location, across all fuel types, expressed in 

metric tons of CO2e.

(G) Annual heat input from each type of fuel listed in Table C-2 of this subpart that was 

combusted during the reporting year, expressed in mmBtu.

(H) Annual CH4 and N2O emissions at each monitored location, from each fuel type 

listed in Table C-2 of this subpart that was combusted during the reporting year (except as 

otherwise provided in § 98.33(c)(4)(ii)(D)), expressed in metric tons CO2e.

(I) Annual CO2 mass emissions from the combustion of biomass, expressed in metric tons 

CO2e, except where the reporting provisions of §§ 98.3(c)(12)(i) through (c)(12)(iii) are 

implemented for the 2010 reporting year.

(J) If applicable, the plant code (as defined in § 98.6).

(iii) For units with continuous monitoring systems that use the alternative method for 

units with continuous monitoring systems in § 98.33(a)(5)(iii) to monitor heat input year-round 

according to part 75 of this chapter:
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(A) Each type of fuel combusted during the reporting year.

(B) Methodology used to calculate the CO2 mass emissions.

(C) Methodology start date.

(D) Methodology end date.

(E) A code or flag to indicate that the heat input data is derived from CEMS 

measurements.

(F) The total annual CO2 emissions at each monitored location, expressed in metric tons 

of CO2e.

(G) Annual heat input from each type of fuel listed in Table C-2 of this subpart that was 

combusted during the reporting year, expressed in mmBtu.

(H) Annual CH4 and N2O emissions at each monitored location, from each fuel type 

listed in Table C-2 of this subpart that was combusted during the reporting year (except as 

otherwise provided in § 98.33(c)(4)(ii)(B)), expressed in metric tons CO2e.

(I) Annual CO2 mass emissions from the combustion of biomass, expressed in metric tons 

CO2e, except where the reporting provisions of §§ 98.3(c)(12)(i) through (c)(12)(iii) are 

implemented for the 2010 reporting year.

(J) If applicable, the plant code (as defined in § 98.6).

(e) Verification data. You must keep on file, in a format suitable for inspection and 

auditing, sufficient data to verify the reported GHG emissions. This data and information must, 

where indicated in this paragraph (e), be included in the annual GHG emissions report.

(1) The applicable verification data specified in this paragraph (e) are not required to be 

kept on file or reported for units that meet any one of the three following conditions:

(i) Are subject to the Acid Rain Program.
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(ii) Use the alternative methods for units with continuous monitoring systems provided in 

§ 98.33(a)(5).

(iii) Are not in the Acid Rain Program, but are required to monitor and report CO2 mass 

emissions and heat input data year-round, in accordance with part 75 of this chapter.

(2) For stationary combustion sources using the Tier 1, Tier 2, Tier 3, and Tier 4 

Calculation Methodologies in § 98.33(a) to quantify CO2 emissions, the following additional 

information shall be kept on file and included in the GHG emissions report, where indicated:

(i) For the Tier 1 Calculation Methodology, report:

(A) The total quantity of each type of fuel combusted in the unit or group of aggregated 

units (as applicable) during the reporting year, in short tons for solid fuels, gallons for liquid 

fuels and standard cubic feet for gaseous fuels, or, if applicable, therms or mmBtu for natural 

gas.

(B) If applicable, the moisture content used to calculate the wood and wood residuals wet 

basis HHV for use in Equations C-1 and C-8, in percent.

(ii) For the Tier 2 Calculation Methodology, report:

(A) The total quantity of each type of fuel combusted in the unit or group of aggregated 

units (as applicable) during each month of the reporting year. Express the quantity of each fuel 

combusted during the measurement period in short tons for solid fuels, gallons for liquid fuels, 

and scf for gaseous fuels.

(B) The frequency of the HHV determinations (e.g., once a month, once per fuel lot).

(C) The high heat values used in the CO2 emissions calculations for each type of fuel 

combusted during the reporting year, in mmBtu per short ton for solid fuels, mmBtu per gallon 

for liquid fuels, and mmBtu per scf for gaseous fuels. Report a HHV value for each calendar 
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month in which HHV determination is required. If multiple values are obtained in a given month, 

report the arithmetic average value for the month. 

(D) If Equation C-2c of this subpart is used to calculate CO2 mass emissions, report the 

total quantity (i.e., pounds) of steam produced from MSW or solid fuel combustion during each 

month of the reporting year, and the ratio of the maximum rate heat input capacity to the design 

rated steam output capacity of the unit, in mmBtu per lb of steam.

(E) For each HHV used in the CO2 emissions calculations for each type of fuel 

combusted during the reporting year, indicate whether the HHV is a measured value or a 

substitute data value.

(iii) For the Tier 2 Calculation Methodology, keep records of the methods used to 

determine the HHV for each type of fuel combusted and the date on which each fuel sample was 

taken, except where fuel sampling data are received from the fuel supplier. In that case, keep 

records of the dates on which the results of the fuel analyses for HHV are received.

(iv) For the Tier 3 Calculation Methodology, report:

(A) The quantity of each type of fuel combusted in the unit or group of units (as 

applicable) during each month of the reporting year, in short tons for solid fuels, gallons for 

liquid fuels, and scf for gaseous fuels.

(B) The frequency of carbon content and, if applicable, molecular weight determinations 

for each type of fuel for the reporting year (e.g., daily, weekly, monthly, semiannually, once per 

fuel lot).

(C) The carbon content and, if applicable, gas molecular weight values used in the 

emission calculations (including both valid and substitute data values). For each calendar month 

of the reporting year in which carbon content and, if applicable, molecular weight determination 
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is required, report a value of each parameter. If multiple values of a parameter are obtained in a 

given month, report the arithmetic average value for the month. Express carbon content as a 

decimal fraction for solid fuels, kg C per gallon for liquid fuels, and kg C per kg of fuel for 

gaseous fuels. Express the gas molecular weights in units of kg per kg-mole.

(D) The total number of valid carbon content determinations and, if applicable, molecular 

weight determinations made during the reporting year, for each fuel type.

(E) The number of substitute data values used for carbon content and, if applicable, 

molecular weight used in the annual GHG emissions calculations.

(F) The annual average HHV, when measured HHV data, rather than a default HHV from 

Table C-1 of this subpart, are used to calculate CH4 and N2O emissions for a Tier 3 unit, in 

accordance with § 98.33(c)(1).

(G) The value of the molar volume constant (MVC) used in Equation C-5 (if applicable).

(v) For the Tier 3 Calculation Methodology, keep records of the following:

(A) For liquid and gaseous fuel combustion, the dates and results of the initial 

calibrations and periodic recalibrations of the required fuel flow meters.

(B) For fuel oil combustion, the method from § 98.34(b) used to make tank drop 

measurements (if applicable).

(C) The methods used to determine the carbon content and (if applicable) the molecular 

weight of each type of fuel combusted.

(D) The methods used to calibrate the fuel flow meters).

(E) The date on which each fuel sample was taken, except where fuel sampling data are 

received from the fuel supplier. In that case, keep records of the dates on which the results of the 

fuel analyses for carbon content and (if applicable) molecular weight are received.
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(vi) For the Tier 4 Calculation Methodology, report:

(A) The total number of source operating hours in the reporting year.

(B) The cumulative CO2 mass emissions in each quarter of the reporting year, i.e., the 

sum of the hourly values calculated from Equation C-6 or C-7 of this subpart (as applicable), in 

metric tons.

(C) For CO2 concentration, stack gas flow rate, and (if applicable) stack gas moisture 

content, the percentage of source operating hours in which a substitute data value of each 

parameter was used in the emissions calculations.

(vii) For the Tier 4 Calculation Methodology, keep records of:

(A) Whether the CEMS certification and quality assurance procedures of part 75 of this 

chapter, part 60 of this chapter, or an applicable State continuous monitoring program were used.

(B) The dates and results of the initial certification tests of the CEMS.

(C) The dates and results of the major quality assurance tests performed on the CEMS 

during the reporting year, i.e., linearity checks, cylinder gas audits, and relative accuracy test 

audits (RATAs).

(viii) If CO2 emissions that are generated from acid gas scrubbing with sorbent injection 

are not captured using CEMS, report:

(A) The total amount of sorbent used during the report year, in short tons.

(B) The molecular weight of the sorbent.

(C) The ratio (“R”) in Equation C-11 of this subpart.

(ix) For units that combust both fossil fuel and biomass, when biogenic CO2 is 

determined according to § 98.33(e)(2), you shall report the following additional information, as 

applicable:
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(A) The annual volume of CO2 emitted from the combustion of all fuels,i.e., Vtotal, in scf.

(B) The annual volume of CO2 emitted from the combustion of fossil fuels, i.e., Vff, in 

scf. If more than one type of fossil fuel was combusted, report the combustion volume of CO2 for 

each fuel separately as well as the total.

(C) The annual volume of CO2 emitted from the combustion of biomass,i.e., Vbio, in scf.

(D) The carbon-based F-factor used in Equation C-13 of this subpart, for each type of 

fossil fuel combusted, in scf CO2 per mmBtu.

(E) The annual average HHV value used in Equation C-13 of this subpart, for each type 

of fossil fuel combusted, in Btu/lb, Btu/gal, or Btu/scf, as appropriate.

(F) The total quantity of each type of fossil fuel combusted during the reporting year, in 

lb, gallons, or scf, as appropriate.

(G) Annual biogenic CO2 mass emissions, in metric tons.

(x) When ASTM methods D7459-08 (incorporated by reference, see § 98.7) and D6866-

12 (incorporated by reference, see § 98.7) are used to determine the biogenic portion of the 

annual CO2 emissions from MSW combustion, as described in § 98.34(d), report:

(A) The results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if 

the biogenic fraction of the CO2 emissions from MSW combustion is 30 percent, report 0.30).

(B) The annual biogenic CO2 mass emissions from MSW combustion, in metric tons.

(xi) When ASTM methods D7459-08 (incorporated by reference, see § 98.7) and D6866-

12 (incorporated by reference, see § 98.7) are used in accordance with § 98.34(e) to determine 

the biogenic portion of the annual CO2 emissions from a unit that co-fires biogenic fuels (or 

partly-biogenic fuels, including tires if you are electing to report biogenic CO2 emissions from 

tire combustion) and non-biogenic fuels, you shall report the results of each quarterly sample 
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analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the CO2 emissions is 30 

percent, report 0.30).

(3) Within 30 days of receipt of a written request from the Administrator, you shall 

submit explanations of the following:

(i) An explanation of how company records are used to quantify fuel consumption, if the 

Tier 1 or Tier 2 Calculation Methodology is used to calculate CO2 emissions.

(ii) An explanation of how company records are used to quantify fuel consumption, if 

solid fuel is combusted and the Tier 3 Calculation Methodology is used to calculate CO2

emissions.

(iii) An explanation of how sorbent usage is quantified.

(iv) An explanation of how company records are used to quantify fossil fuel consumption 

in units that uses CEMS to quantify CO2 emissions and combusts both fossil fuel and biomass.

(v) An explanation of how company records are used to measure steam production, when 

it is used to calculate CO2 mass emissions under § 98.33(a)(2)(iii) or to quantify solid fuel usage 

under § 98.33(c)(3).

(4) Within 30 days of receipt of a written request from the Administrator, you shall 

submit the verification data and information described in paragraphs (e)(2)(iii), (e)(2)(v), and 

(e)(2)(vii) of this section.

(f) Each stationary fuel combustion source (e.g., individual unit, aggregation of units, 

common pipe, or common stack) subject to reporting under paragraph (b) or (c) of this section 

must indicate if both of the following two conditions are met:

(1) The stationary fuel combustion source contains at least one combustion unit 

connected to a fuel-fired electric generator owned or operated by an entity that is subject to 
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regulation of customer billing rates by the public utility commission (excluding generators that 

are connected to combustion units that are subject to subpart D of this part).

(2) The stationary fuel combustion source is located at a facility for which the sum of the 

nameplate capacities for all electric generators specified in paragraph (f)(1) of this section is 

greater than or equal to 1 megawatt electric output.

§ 98.37 Records that must be retained.

In addition to the requirements of § 98.3(g), you must retain:

(a) The applicable records specified in §§ 98.34(f), 98.35(b), and 98.36(e).

(b) Verification software records. For each stationary fuel combustion source that elects 

to use the verification software specified in § 98.5(b) rather than report certain data specified in 

paragraphs (b)(9)(iii), (c)(2)(ix), (e)(2)(i), (e)(2)(ii)(A), (e)(2)(ii)(C), (e)(2)(ii)(D), and 

(e)(2)(iv)(A), (e)(2)(iv)(C), (e)(2)(iv)(F), and (e)(2)(ix)(D) through (F) of this section, you must 

keep a record of the file generated by the verification software for the applicable data specified in 

paragraphs (b)(1) through (b)(36) of this section. Retention of this file satisfies the recordkeeping 

requirement for the data in paragraphs (b)(1) through (b)(36) of this section.

(1) Mass of each solid fuel combusted (tons/year) (Equation C-1 of § 98.33).

(2) Volume of each liquid fuel combusted (gallons/year) (Equation C-1).

(3) Volume of each gaseous fuel combusted (scf/year) (Equation C-1).

(4) Annual natural gas usage (therms/year) (Equation C-1a of § 98.33).

(5) Annual natural gas usage (mmBtu/year) (Equation C-1b of § 98.33).

(6) Mass of each solid fuel combusted (tons/year) (Equation C-2a of § 98.33).

(7) Volume of each liquid fuel combusted (gallons/year) (Equation C-2a).

(8) Volume of each gaseous fuel combusted (scf/year) (Equation C-2a).
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(9) Measured high heat value of each solid fuel, for month (which may be the arithmetic 

average of multiple determinations), or, if applicable, an appropriate substitute data value 

(mmBtu per ton) (Equation C-2b of § 98.33).

(10) Measured high heat value of each liquid fuel, for month (which may be the 

arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data 

value (mmBtu per gallons) (Equation C-2b).

(11) Measured high heat value of each gaseous fuel, for month (which may be the 

arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data 

value (mmBtu per scf) (Equation C-2b).

(12) Mass of each solid fuel combusted during month (tons) (Equation C-2b).

(13) Volume of each liquid fuel combusted during month (gallons) (Equation C-2b).

(14) Volume of each gaseous fuel combusted during month (scf) (Equation C-2b).

(15) Total mass of steam generated by municipal solid waste or each solid fuel 

combustion during the reporting year (pounds steam) (Equation C-2c of § 98.33).

(16) Ratio of the boiler's maximum rated heat input capacity to its design rated steam 

output capacity (MMBtu/ pounds steam) (Equation C-2c).

(17) Annual mass of each solid fuel combusted (short tons/year) (Equation C-3 of § 

98.33).

(18) Annual average carbon content of each solid fuel (percent by weight, expressed as a 

decimal fraction) (Equation C-3).

(19) Annual volume of each liquid fuel combusted (gallons/year) (Equation C-4 of § 

98.33).
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(20) Annual average carbon content of each liquid fuel (kg C per gallon of fuel) 

(Equation C-4).

(21) Annual volume of each gaseous fuel combusted (scf/year) (Equation C-5 of § 

98.33).

(22) Annual average carbon content of each gaseous fuel (kg C per kg of fuel) (Equation 

C-5).

(23) Annual average molecular weight of each gaseous fuel (kg/kg-mole) (Equation C-5).

(24) Molar volume conversion factor at standard conditions, as defined in § 98.6 (scf per 

kg-mole) (Equation C-5).

(25) Identify for each fuel if you will use the default high heat value from Table C-1, or 

actual high heat value data (Equation C-8 of § 98.33).

(26) High heat value of each solid fuel (mmBtu/tons) (Equation C-8).

(27) High heat value of each liquid fuel (mmBtu/gallon) (Equation C-8).

(28) High heat value of each gaseous fuel (mmBtu/scf) (Equation C-8).

(29) Cumulative annual heat input from combustion of each fuel (mmBtu) (Equation C10 of § 98.33).

(30) Total quantity of each solid fossil fuel combusted in the reporting year, as defined in 

§ 98.6 (pounds) (Equation C-1 of § 98.333).

(31) Total quantity of each liquid fossil fuel combusted in the reporting year, as defined 

in § 98.6 (gallons) (Equation C-13).

(32) Total quantity of each gaseous fossil fuel combusted in the reporting year, as defined 

in § 98.6 (scf) (Equation C-13).

(33) High heat value of the each solid fossil fuel (Btu/lb) (Equation C-13).
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(34) High heat value of the each liquid fossil fuel (Btu/gallons) (Equation C-13).

(35) High heat value of the each gaseous fossil fuel (Btu/scf) (Equation C-13).

(36) Fuel-specific carbon based F-factor per fuel (scf CO2/mmBtu) (Equation C-13).

(37) Moisture content used to calculate the wood and wood residuals wet basis HHV 

(percent), if applicable (Equations C-1 and C-8).

§98.38 Definitions.

All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A 

of this part.

Table C-1 to Subpart C of Part 98—Default CO2 Emission Factors and High Heat Values 

for Various Types of Fuel

Default CO2 Emission Factors and High Heat Values for Various Types of Fuel

Fuel type Default high heat value

Default CO2

emission

factor

Coal and coke mmBtu/short ton kg CO2/mmBtu

Anthracite 25.09 103.69

Bituminous 24.93 93.28

Subbituminous 17.25 97.17

Lignite 14.21 97.72

Coal Coke 24.80 113.67

Mixed (Commercial sector) 21.39 94.27

Mixed (Industrial coking) 26.28 93.90

Mixed (Industrial sector) 22.35 94.67

Mixed (Electric Power sector) 19.73 95.52

Natural gas mmBtu/scf kg CO2/mmBtu

(Weighted U.S. Average) 1.026 × 10−353.06

Petroleum products—liquid mmBtu/gallon kg CO2/mmBtu

Distillate Fuel Oil No. 1 0.139 73.25
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Distillate Fuel Oil No. 2 0.138 73.96

Distillate Fuel Oil No. 4 0.146 75.04

Residual Fuel Oil No. 5 0.140 72.93

Residual Fuel Oil No. 6 0.150 75.10

Used Oil 0.138 74.00

Kerosene 0.135 75.20

Liquefied petroleum gases (LPG)10.092 61.71

Propane10.091 62.87

Propylene20.091 67.77

Ethane10.068 59.60

Ethanol 0.084 68.44

Ethylene20.058 65.96

Isobutane10.099 64.94

Isobutylene10.103 68.86

Butane10.103 64.77

Butylene10.105 68.72

Naphtha (<401 deg F) 0.125 68.02

Natural Gasoline 0.110 66.88

Other Oil (>401 deg F) 0.139 76.22

Pentanes Plus 0.110 70.02

Petrochemical Feedstocks 0.125 71.02

Special Naphtha 0.125 72.34

Unfinished Oils 0.139 74.54

Heavy Gas Oils 0.148 74.92

Lubricants 0.144 74.27

Motor Gasoline 0.125 70.22

Aviation Gasoline 0.120 69.25

Kerosene-Type Jet Fuel 0.135 72.22

Asphalt and Road Oil 0.158 75.36

Crude Oil 0.138 74.54
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Petroleum products—solid mmBtu/short ton kg CO2/mmBtu

Petroleum Coke 30.00 102.41

Petroleum products—gaseous mmBtu/scf kg CO2/mmBtu

Propane Gas 2.516 × 10−361.46

Other fuels—solid mmBtu/short ton kg CO2/mmBtu

Municipal Solid Waste 9.95390.7

Tires 28.00 85.97

Plastics 38.00 75.00

Other fuels—gaseous mmBtu/scf kg CO2/mmBtu

Blast Furnace Gas 0.092 × 10−3274.32

Coke Oven Gas 0.599 × 10−346.85

Fuel Gas41.388 × 10−359.00

Biomass fuels—solid mmBtu/short ton kg CO2/mmBtu

Wood and Wood Residuals (dry basis)517.48 93.80

Agricultural Byproducts 8.25 118.17

Peat 8.00 111.84

Solid Byproducts 10.39 105.51

Biomass fuels—gaseous mmBtu/scf kg CO2/mmBtu

Landfill Gas 0.485 × 10−352.07

Other Biomass Gases 0.655 × 10−352.07

Biomass Fuels—Liquid mmBtu/gallon kg CO2/mmBtu

Ethanol 0.084 68.44

Biodiesel (100%) 0.128 73.84

Rendered Animal Fat 0.125 71.06

Vegetable Oil 0.120 81.55

1

The HHV for components of LPG determined at 60 °F and saturation pressure with the 

exception of ethylene.

2

Ethylene HHV determined at 41 °F (5 °C) and saturation pressure.

3Use of this default HHV is allowed only for: (a) Units that combust MSW, do not generate 

steam, and are allowed to use Tier 1; (b) units that derive no more than 10 percent of their annual 
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heat input from MSW and/or tires; and (c) small batch incinerators that combust no more than 

1,000 tons of MSW per year.

4Reporters subject to subpart X of this part that are complying with §98.243(d) or subpart Y of 

this part may only use the default HHV and the default CO2 emission factor for fuel gas 

combustion under the conditions prescribed in §98.243(d)(2)(i) and (d)(2)(ii) and §98.252(a)(1) 

and (a)(2), respectively. Otherwise, reporters subject to subpart X or subpart Y shall use either 

Tier 3 (Equation C-5) or Tier 4.

5Use the following formula to calculate a wet basis HHV for use in Equation C-1: HHVw = ((100 

− M)/100)*HHVd where HHVw = wet basis HHV, M = moisture content (percent) and HHVd = 

dry basis HHV from Table C-1.

Table C-2 to Subpart C of Part 98—Default CH4 and N2O Emission Factors for Various 

Types of Fuel

Fuel type

Default CH4 emission 

factor (kg CH4/mmBtu)

Default N2O emission 

factor (kg N2O/mmBtu)

Coal and Coke (All fuel types in Table 

C-1)

1.1 × 10−02 1.6 × 10−03

Natural Gas 1.0 × 10−03 1.0 × 10−04

Petroleum Products (All fuel types in 

Table C-1)

3.0 × 10−03 6.0 × 10−04

Fuel Gas 3.0 × 10−03 6.0 × 10−04

Other Fuels—Solid 3.2 × 10−02 4.2 × 10−03

Blast Furnace Gas 2.2 × 10−05 1.0 × 10−04

Coke Oven Gas 4.8 × 10−04 1.0 × 10−04

Biomass Fuels—Solid (All fuel types in 

Table C-1, except wood and wood 

residuals)

3.2 × 10−02 4.2 × 10−03

Wood and wood residuals 7.2 × 10−03 3.6 × 10−03

Biomass Fuels—Gaseous (All fuel types 

in Table C-1)

3.2 × 10−03 6.3 × 10−04

Biomass Fuels—Liquid (All fuel types 

in Table C-1)

1.1 × 10−03 1.1 × 10−04

Note: Those employing this table are assumed to fall under the IPCC definitions of the “Energy

Industry” or “Manufacturing Industries and Construction”. In all fuels except for coal the values 

for these two categories are identical. For coal combustion, those who fall within the IPCC 

“Energy Industry” category may employ a value of 1g of CH4/mmBtu.
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