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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:
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(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.

§ 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 
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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).

(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).
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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

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).
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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).

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 
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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).

(HHV)i = Measured high heat value of the fuel, for 

month “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 

month “i,” from company records (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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n = Number of months in the year that the fuel is 

burned in the unit.

(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).

EF = Fuel-specific default CO2 emission factor, from 

Table C–1 of this subpart (kg CO2/mmBtu).
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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).

Fuel = Annual volume of the liquid fuel combusted 

(gallons). The volume of fuel combusted must 

be measured directly, using fuel flow meters 
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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.

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.
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(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 
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documented in the GHG Monitoring Plan required under 

§98.3(g)(5).

(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).
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(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 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 site-specific moisture percentage on the number 

of moisture runs allowed by the RATA regulation. Calculate each 
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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).

%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 F–14b (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. 
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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.

(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 
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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 
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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.

(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 
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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.

(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 
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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 

1.1 to convert it to metric tons.
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(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 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 LM–11 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 

1.1 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 O2monitor is used, 

convert the hourly average O2readings to CO2 using Equation F–14a 
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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 

1.1 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 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.
Page 21 of 95

(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.

(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.
Page 22 of 95

(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:
Page 23 of 95

(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.
Page 24 of 95

(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.

(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.
Page 25 of 95

(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.

(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 
Page 26 of 95

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 
Page 27 of 95

or 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:
Page 28 of 95

(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).

(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.
Page 29 of 95

(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).

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.
Page 30 of 95

(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:

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 
Page 31 of 95

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.

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).
Page 32 of 95

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.

(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 
Page 33 of 95

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)Aas 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)Afor 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)Aobtained 

from the electronic data reports under §75.64 of this chapter 

may be attributed exclusively to the fuel with the highest Ffactor, 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, 
Page 34 of 95

engineering analysis) to estimate the value of (HI)Afor 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.

(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)Afor 

each fuel type, whenever fuel-specific 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, 
Page 35 of 95

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”;

(C) Calculate the annual CH4 and N2O emissions from 

component “i”, using Equation C–8, 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 
Page 36 of 95

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 

CaCO3and 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.

(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 
Page 37 of 95

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.
Page 38 of 95

(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 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).
Page 39 of 95

(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 

O2concentration (%CO2).

Qh = Hourly average stack gas volumetric flow rate, 

measured by the stack gas volumetric flow rate 

monitor (scfh).

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 VCO2 hvalues 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:
Page 40 of 95

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, semiannually, 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.

(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:
Page 41 of 95

(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.

(i) Use an applicable CO2 emissions calculation method in 

this section to quantify the total annual CO2 mass emissions from 

the unit.
Page 42 of 95

(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.
Page 43 of 95

(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 

C–15 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 

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 nonbiomass-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).
Page 44 of 95

(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 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 F-factor 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 
Page 45 of 95

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-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.
Page 46 of 95

(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 
Page 47 of 95

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:

(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.
Page 48 of 95

(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 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 
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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 heatweighting 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 
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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.

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, 
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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.

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 
Page 52 of 95

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)iin Equation 

C–17 for fuel A will be 0.50/(0.50 + 0.30) = 0.625, and for fuel 

B, (Fuel)iwill 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 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.
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(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, 

http://www.api.org), and the North American Energy Standards 

Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, 
Page 54 of 95

(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 consensus-based 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, 
Page 55 of 95

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.

(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 
Page 56 of 95

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).

(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.
Page 57 of 95

(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. 
Page 58 of 95

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 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.
Page 59 of 95

(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.

(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.
Page 60 of 95

(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 manner described in §98.33(a)(2)(ii). Also 
Page 61 of 95

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, 
Page 62 of 95

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).

(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 
Page 63 of 95

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 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 
Page 64 of 95

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 D6866–08 Standard Test 

Methods for Determining the Biobased Content of Solid, Liquid, 
Page 65 of 95

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 sampling and the ASTM D6866–08 

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 
Page 66 of 95

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 D6866–08 (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 nonbiogenic fuels are co-fired in the 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 
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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).

§ 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 
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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 
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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 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 emissions data in paragraphs (b) 

through (d) of this section (as applicable) and the emissions 

verification data in paragraph (e) of this section.

(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.
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(4) Each type of fuel combusted in the unit during the 

report year.

(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 CO2 e; 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 
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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, and the annual CH4 and N2O emissions 

for each of these fuels, expressed in metric tons of each gas 

and in metric tons of CO2e.

(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:
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(i) Group ID number, beginning with the prefix “GP”.

(ii) [Reserved]

(iii)[Reserved]

(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 CO2 e. If any of the units burn 

both fossil fuels and 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).
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(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 off-gases, and 

all of the effluent comes from a single unit (e.g., a furnace, 

kiln, petrochemical production unit, or smelter).

(iii) Combined maximum rated heat input capacity of the 

units sharing the common stack or duct (mmBtu/hr). This data 
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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 during 

the report year in the units sharing the common stack or duct 

during the report year, and, for each of these fuels, 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 CO2 e.

(x) [Reserved]

(xi) If applicable, the plant code (as defined in §98.6).
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(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 

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 
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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 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) [Reserved]

(iii) The highest maximum rated heat input capacity of any 

unit served by the common pipe (mmBtu/hr).
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(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 

CO2 e.

(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 

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 
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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 unitlevel information:
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(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.

(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 CO2 e.

(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 CO2 e, except where the 
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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.

(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.
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(F) Annual CO2 emissions at each monitored location, across 

all fuel types, expressed in metric tons of CO2 e.

(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 CO2 e.

(I) Annual CO2 mass emissions from the combustion of 

biomass, expressed in metric tons CO2 e, 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:

(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.
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(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 CO2 e.

(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 CO2 e.

(I) Annual CO2 mass emissions from the combustion of 

biomass, expressed in metric tons CO2 e, 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.
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(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.

(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 yearround, 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 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.

(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 
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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 month in which HHV 

determination is required. If multiple values are obtained in a 

given month, report the arithmetic average value for the month. 

Indicate whether each reported HHV is a measured value or a 

substitute data value.

(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.

(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 
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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 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.
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(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).
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(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.

(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.
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(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:

(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.
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(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 D6866–08 (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 D6866–08 (incorporated by reference, see §98.7) 

are used in accordance with §98.34(e) to determine the biogenic 
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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 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).
Page 91 of 95

(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.

§ 98.37 Records that must be retained.

In addition to the requirements of §98.3(g), you must 

retain the applicable records specified in §§98.34(f) and (g), 

98.35(b), and 98.36(e).

§ 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—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 × 10−3 53.06
Page 92 of 95

Fuel type

Default high heat 

value

Default CO2

emission 

factor

Petroleum products mmBtu/gallon kg CO2/mmBtu

Distillate Fuel Oil No. 1 0.139 73.25

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)1

0.092 61.71

Propane1 0.091 62.87

Ethane1 0.068 59.60

Ethanol 0.084 68.44

Ethylene2 0.058 65.96

Isobutane1 0.099 64.94

Isobutylene1 0.103 68.86

Butane1 0.103 64.77

Butylene1 0.105 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

Petroleum Coke 0.143 102.41

Special Naphtha 0.125 72.34

Unfinished Oils 0.139 74.54

Heavy Gas Oils 0.148 74.92

Lubricants 0.144 74.27
Page 93 of 95

Fuel type

Default high heat 

value

Default CO2

emission 

factor

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

Other fuels-solid mmBtu/short ton kg CO2/mmBtu

Municipal Solid Waste 9.953 90.7

Tires 28.00 85.97

Plastics 38.00 75.00

Petroleum Coke 30.00 102.41

Other fuels—gaseous mmBtu/scf kg CO2/mmBtu

Blast Furnace Gas 0.092 × 10−3 274.32

Coke Oven Gas 0.599 × 10−3 46.85

Propane Gas 2.516 × 10−3 61.46

Fuel Gas4 1.388 × 10−3 59.00

Biomass fuels—solid mmBtu/short ton kg CO2/mmBtu

Wood and Wood Residuals(dry 

basis)5

17.48 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 × 10−3 52.07

Other Biomass Gases 0.655 x 10-3 52.07

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
Page 94 of 95

Fuel type

Default high heat 

value

Default CO2

emission 

factor

Vegetable Oil 0.120 81.55

1The HHV for components of LPG determined at 60oF and saturation 

pressure with the exception of ethylene.

2Ethylene HHV determined at 41oF (5oC) 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 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—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 (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

Municipal Solid 

Waste

3.2 × 10−02 4.2 × 10−03

Tires 3.2 × 10−02 4.2 × 10−03

Blast Furnace Gas 2.2 × 10−05 1.0 × 10−04
Page 95 of 95

Fuel type

Default CH4 emission 

factor (kg CH4/mmBtu)

Default N2O emission 

factor (kg N2O/mmBtu)

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 x 10-03 3.6 x 10-03

Biomass FuelsGaseous (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.