Greenhouse Gas Inventory Guidance Direct Emissions from Stationary Combustion Sources


4»EPA CENTER FOR CORPORATE

CLIMATE
LEADERSHIP

U.S. Environmental Protection Agency

Supporting organizations in GHG measurement and management • www.epa.gov/climateleadership

Greenhouse Gas Inventory Guidance

Direct Emissions from Stationary
Combustion Sources

SrEPA

United States
Environmental Protection
Agency

December 2020

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The U.S. EPA Center for Corporate Climate Leadership's (The Center) Greenhouse Gas guidance is based on The
Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard (GHG Protocol) developed by the World
Resources Institute (WRI) and the World Business Council for Sustainable Development (WBCSD). The Center's GHG
guidance is meant to extend upon the GHG Protocol to align more closely with EPA-specific GHG calculation
methodologies and emission factors, and to support the Center's GHG management tools.

For more information regarding the Center for Corporate Climate Leadership, visit www.epa.gov/climateleadership.

U.S. EPA Center for Corporate Climate Leadership - GHG Inventory Guidance

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Table of Contents

Table of Contents

Section 1: Introduction	1

1.1	Greenhouse Gases Included	1

1.2	Biomass Fuels	1

1.3	Waste-Derived Fuels	2

1.4	Non-Combustion Emission Sources	2

Section 2: Calculating Emissions	3

2.1	Continuous Emissions Monitoring System (CEMS) Method	3

2.2	Fuel Analysis Method	4

Section 3: Choice of Activity Data and Emission Factors	8

3.1	Activity Data Sources	8

3.2	Activity Data Units	9

3.3	Fuel Carbon Content and Heat Content	10

3.4	Emission Factors	10

Section 4: Completeness	13

Section 5: Uncertainty Assessment	14

Section 6: Documentation	15

Section 7: Inventory Quality Assurance and Quality Control	16

Appendix A: Default Emission Factors	17

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Direct Emissions from Stationary Combustion Sources

Section 1: Introduction

Combustion of fuels in stationary (non-transport) combustion sources results in the following greenhouse gas (GHG)
emissions: carbon dioxide (C02), methane (CH4), and nitrous oxide (N20). Sources of emissions from stationary
combustion include boilers, heaters, furnaces, kilns, ovens, flares, thermal oxidizers, dryers, and any other equipment or
machinery that combusts carbon bearing fuels or waste stream materials.

This document presents guidance for calculating scope 1 direct GHG emissions resulting from stationary combustion of
fuels at owned/operated sources. This guidance applies to all organizations whose operations involve stationary
combustion of fuel.

1.1 Greenhouse Gases Included

The greenhouse gases C02, CH4, and N20 are emitted during the combustion of fuels. C02 accounts for the majority of the
GHG emissions from stationary combustion sources. In the U.S., C02 emissions represent more than 99 percent of the
total C02-equivalent GHG emissions from all commercial, industrial, and electricity generation combustion sources. CH4
and N20 emissions together represent less than one percent of the total C02-equivalent emissions from the same
sources.1

Organizations should account for all C02, CH4, and N20 emissions associated with stationary combustion. Given the
relative emissions contributions of each gas, CH4 and N20 emissions are sometimes excluded by assuming that they are
not material. However, as outlined in Chapter 1 of the GHG Protocol, the materiality of a source can only be established
after it has been assessed. This does not necessarily require a rigorous quantification of all sources, but at a minimum, an
estimate based on available data should be developed for all sources and categories of GHGs, and included in an
organization's GHG inventory.

Emissions of CH4 and N20 depend not only upon fuel characteristics, but also on technology type and combustion
characteristics, application of pollution control equipment, and ambient environmental conditions. Emissions of these
gases also vary with the size, efficiency, and vintage of the combustion technology, as well as maintenance and
operational practices. However, the methods used to calculate C02 emissions can also be used to calculate emissions of
CH4 and N20 with reasonable accuracy when applying appropriate CH4 and N20 emission factors.

For organizations that wish to examine CH4 and N20 emissions from stationary combustion sources in more detail, a list of
references for calculating these emissions is included in Appendix A.

1.2 Biomass Fuels

Not all stationary combustion sources burn fossil fuels. Biomass (non-fossil) fuels (e.g., forestry-derived, agriculture-
derived, biomass-derived gases) may be combusted in stationary sources independently or co-fired with fossil fuels. The
emission calculation methods discussed in this document can be used to calculate C02, CH4, and N20 emissions from
combustion of these fuels. The GHG Protocol requires that C02 emissions from biomass combustion at stationary sources
are reported as biomass C02 emissions (in terms of total amount of biogenic C02 emitted) and are tracked separately
from fossil C02 emissions. Biomass C02 emissions are not included in the overall C02-equivalent emissions inventory for

1 See Table 3-7 of U.S. EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2018, EPA430-R-20-002, April 2020.

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Direct Emissions from Stationary Combustion Sources

Section 1: Introduction

organizations following this guidance. CH4 and N20 emissions from biomass are included in the overall C02-equivalent
emissions inventory. There has been increased scientific inquiry into accounting for biomass in energy production. The
EPA's Science Advisory Board found that "there are circumstances in which biomass is grown, harvested and combusted
in a carbon neutral fashion but carbon neutrality may not an appropriate assumption; it is a conclusion that should be
reached only after considering a particular feedstock's production and consumption cycle. There is considerable
heterogeneity in feedstock types, sources and production methods and thus net biogenic carbon emissions will vary
considerably."2 According to the GHG Protocol Corporate Standard, "consensus methods have yet to be developed under
the GHG Protocol Corporate Standard for accounting of sequestered atmospheric carbon as it moves through the value
chain of biomass-based industries," though some general considerations for accounting for sequestered atmospheric
carbon are discussed in Chapter 9 and Appendix B of the GHG Protocol Corporate Standard.

If an organization purchases biogas that is delivered through a shared natural gas pipeline, see Appendix A of the GHG
Protocol Scope 2 Guidance for a discussion of appropriate GHG accounting for this situation.

1.3 Waste-Derived Fuels

Waste-derived fuels in solid, liquid, and gaseous form may be combusted in stationary sources as well. Typical waste
derived fuels include, but are not limited to, used tires, used motor oils, municipal solid waste (MSW), hazardous waste,
landfill gas, and by-product gases. These waste-derived fuels are treated like any other fuels in an organization's
inventory. Therefore, any GHG produced from combustion of a fossil-based waste product is reported in an organization's
inventory. Any CO2 emissions from combustion of a biomass waste are treated as biomass C02 as described in Section 1.2.
This applies to entire waste streams or portions of the waste stream. For example, the CO2 produced from combusting
the biomass portion of MSW (e.g., yard waste, paper products) is reported as biomass C02. The C02 produced from
combusting the fossil portion of the MSW (e.g., plastics) is reported as C02 and is included in an organization's inventory.

Emissions from waste-derived fuels only include the actual emissions from the combustion process and do not include any
"offsets" from use of the waste-derived fuel.

1.4 Non-Combustion Emission Sources

The combustion of fuel does not account for all GHG emissions related to stationary combustion sources. For example,
use of natural gas may result in fugitive methane emissions from leaking gas transportation lines owned by the
organization. Storage of fuels may also result in fugitive emissions. For example, methane is emitted from fuel storage
tanks or from coal piles. Typically, these sources are minor compared to combustion emissions, however, organizations
should account for these non-combustion sources using guidance specific to the fugitive emissions from their sector.

2 EPA Science Advisory Board Review of the 2011 Draft Accounting Framework for C02 Emissions for Biogenic Sources Study. 2012.
https://vosemite.epa.eov/sab/sabproduct.nsf/0/2F9B572C712AC52E8525783100704886?QpenDocument.

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Direct Emissions from Stationary Combustion Sources

Section 2: Calculating Emissions

There are two main methods for estimating GHG emissions from stationary combustion sources:

• Direct measurement

• Analysis of fuel input

Direct measurement of CO2 emissions is performed through the use of a Continuous Emissions Monitoring System
(CEMS). Fuel analysis is essentially a mass balance approach in which carbon content factors are applied to fuel input to
determine emissions. Both methods are described in more detail in the following sections.

For both the CEMS and fuel analysis approaches, it is recommended that organizations calculate emissions by facility as
opposed to aggregated entity-wide emissions only. This method increases the accuracy and credibility of the inventory.

2.1 Continuous Emissions Monitoring System (CEMS) Method

Continuous emissions monitoring is the continuous measurement of pollutants emitted into the atmosphere in exhaust
gases from combustion or industrial processes. Several U.S. EPA regulatory programs (e.g., Acid Rain Program, New
Source Performance Standards, Greenhouse Gas Reporting Program [GHGRP], and Maximum Available Control
Technology Standards) have provisions regarding CEMS.

CEMS can be used to measure CO2 emissions. Title IV of the U.S. Clean Air Act requires owners or operators of electricity
generating units to report C02 emissions from affected units under the Acid Rain Program. 40 CFR Part 75, which
establishes requirements for the monitoring, recordkeeping, and reporting from affected units under the Acid Rain
Program, outlines two approaches for determining CO2 emissions using CEMS (see Appendix F of 40 CFR Part 75):

• A monitor measuring C02 concentration percent by volume of flue gas and a flow monitoring system measuring
the volumetric flow rate of flue gas can be used to determine CO2 mass emissions. Annual C02 emissions are
determined based on the operating time of the unit.

• A monitor measuring 02 concentration percent by volume of flue gas and a flow monitoring system measuring the
volumetric flow rate of flue gas combined with theoretical C02 and flue gas production by fuel characteristics can
be used to determine C02 flue gas emissions and C02 mass emissions. Annual C02 emissions are determined
based on the operating time of the unit.

40 CFR Part 98 also includes these same two approaches for organizations that use a CEMS to report to the GHGRP. If an
organization has reported quality assured C02 emissions data from one of the above CEMS approaches to satisfy their
Title IV or GHGRP requirements, it is recommended that they report these same C02 emissions in their GHG inventory.
Organizations that collect C02 emissions data from a CEMS that does not conform to the specific requirements prescribed
under 40 CFR Part 75 or 40 CFR Part 98, and organizations with no CEMS installed, should use the fuel analysis methods
outlined in Section 2.2 below. Because a CEMS cannot be used to calculate CH4 and N20 emissions, organizations should
use the fuel analysis method for those emissions.

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Section 2: Calculating Emissions

2.2 Fuel Analysis Method

The fuel analysis method to calculate C02 emissions involves determining a carbon content of fuel combusted using either
fuel-specific information or default emission factors, and applying that carbon content to the amount of fuel burned to
quantify C02 emissions.

For affected units under the Acid Rain Program, 40 CFR Part 75 (Appendix G) describes fuel analysis methods for
calculating CO2 emissions based on the measured carbon content of the fuel, adjusted for any unburned carbon, and the
amount of fuel combusted.3 For organizations that report under the GHGRP, Subpart C of 40 CFR Part 98 describes fuel
analysis methods applicable to that program.

If an organization is measuring and reporting GHG emissions under their Title IV or GHGRP requirements using the fuel
analysis methods outlined in 40 CFR Part 75 or 40 CFR Part 98, it is recommended that they report these same emissions
in their organizational GHG inventory.

For organizations not reporting GHG emissions under the Acid Rain Program or GHGRP, this guidance provides a fuel
analysis method to calculate their GHG emissions. One of three equations below can be used in the fuel analysis method
to calculate CO2 emissions for each type of fuel combusted. Two of
these equations can also be used to calculate CH4, and N20
emissions, using appropriate emission factors. The appropriate
equation to use depends on what is known about the characteristics
of the fuel being consumed.

Equation 1 is recommended when fuel consumption is known only
in mass or volume units, and no information is available about the
fuel heat content or carbon content. This equation is the least
preferred. It has the most uncertainty because its emission factors
are based on default fuel heat content, rather than actual heat
content.

Equation 1:

Emissions = Fuel x EF,

Where:

Emissions = Mass of C02, CH„ or N20
emitted

Fuel = Mass or volume of fuel combusted
EF, = C02, CH4, or N20 emission factor per
mass or volume unit

3 Units reporting CO? emissions under the Acid Rain Program or GHGRP, through either the CEMS or fuel analysis approach, are required to include
CO? emissions from sorbent use (e.g., limestone used in flue gas desulfurization equipment). Organizations not required to report under these
programs should be sure to include any CO? emissions from sorbent use in their GHG inventory. Procedures to calculate these emissions are
outlined in 40 CFR Part 75 Appendix G, Section 3 and 40 CFR Part 98, Subpart C.

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Section 2: Calculating Emissions

Equation 2 is recommended when the actual fuel heat content is provided by the fuel supplier or is otherwise known. It is
also recommended when the fuel use is provided in energy units (e.g., therms of natural gas). In such cases, the fuel use
in energy units can be multiplied directly by the emission factor (EF2). Equation 2 is a preferable approach over Equation 1

because it uses emission factors that are based on energy units as
opposed to mass or volume units. Emission factors based on
energy units are less variable than factors per mass or volume
units because the carbon content of a fuel is more closely related
to the heat content of the fuel than to the total physical quantity
of fuel.

Equation 3 is recommended to calculate C02 emissions when the
actual carbon content of the fuel is known. Carbon content is
typically expressed as a percentage by mass, which requires fuel
use data in mass units. This equation is most preferred for CO2
calculations because C02 emissions are directly related to the
fuel's carbon content. Because Equation 3 is only applicable to C02
emissions, Equation 1 or 2 should be used in conjunction to
calculate CH4 and N20 emissions.

Follow the steps below to calculate emissions.

Step 1: Select the appropriate equation.

Based on the information available on the characteristics of the
fuel being consumed, select the appropriate equation to use in
calculating emissions. See the discussion above on the three
possible equations.

Step 2: Determine the amount of fuel combusted.

Each fuel type should be quantified separately. This can be based
on fuel receipts, purchase records, or through direct
measurement at the combustion device. If purchase records are
used, care should be taken to subtract out any fuel used to
produce feedstocks or materials such as plastics where the carbon is ultimately stored. Section 3 describes in more detail
the different sources that can be used to determine the amount of fuel combusted and the possible units in which fuel
combustion may be measured.

Step 3: Determine equation inputs.

The selected equation specifies which inputs are needed to calculate emissions. As appropriate, determine the fuel
carbon content, fuel heat content, and/or emission factors associated with each fuel consumed. Further guidance is given
in Section 3, and emission factors are provided in Appendix A.

Step 4: Calculate emissions.

Use the appropriate equation with the fuel consumption and other equation inputs to calculate the emissions of C02, CH4,
and N20. Multiply the emissions of CH4 and N20 by the respective global warming potential (GWP) to calculate C02-
equivalent emissions. The GWPs are 25 for CH4 and 298 for N20, from the Intergovernmental Panel on Climate Change

Equation 2:

Emissions = Fuel x HHV x EF2
Where:

Emissions = Mass of C02, CH4, or N20 emitted
Fuel = Mass or volume of fuel combusted
HHV = Fuel heat content (higher heating
value),in units of energy per mass or volume
of fuel

EF2 = C02, CH4, or N20 emission factor per
energy unit

Equation 3:

Emissions = Fuel x CC x 44/12
Where:

Emissions = Mass of C02 emitted
Fuel = Mass or volume of fuel combusted
CC = Fuel carbon content, in units of mass of
carbon per mass or volume of fuel

44/12 = ratio of molecular weights of C02 and
carbon

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Section 2: Calculating Emissions

(IPCC), Fourth Assessment Report (AR4), 2007. Sum the CO2 equivalent emissions from CH4 and N20 with the emissions of
C02 to calculate the total C02-equivalent (C02e) emissions.

Example Emissions Calculation

An organization has an on-site natural gas boiler. The organization does not meter the gas that enters the boiler directly.
However, the organization does have a record of the natural gas utility bills for the annual reporting period in question.
The bills list the amount of fuel purchased in terms of energy (e.g., therms) as well as the cubic feet of gas purchased and
the heating value of the gas. It is assumed that there are no fugitive releases of gas, there is no inventory of natural gas
stored on-site, and that all the natural gas purchased is combusted (i.e., no feedstock use of gas). The following
information is available from the fuel supplier:

Table 1: Example Emissions Calculation

Month

Amount of Gas

Heat Content (Btu/scf)

Amount of Gas

Purchased (scf)

Purchased (therms)

January

550,000

1,025

5,637.5

February

580,000

1,025

5,945

March

530,000

1,025

5,432.5

April

480,000

1,025

4,920

May

500,000

1,025

5,125

June

490,000

1,025

5,022.5

July

510,000

1,025

5,227.5

August

390,000

1,025

3,997.5

September

480,000

1,025

4,920

October

540,000

1,025

5,535

November

490,000

1,025

5,022.5

December

460,000

1,025

4,715

Total

6,000,000

61,500

Note: scf = standard cubic feet, 1 therm = 100,000 Btu

Step 1: The amount of fuel combusted has been determined based on purchase data on utility bills from the supplier.

Step 2: Carbon content is not known, so Equation 3 cannot be used. Sufficient information is available to use either
Equation 1 or 2, because fuel consumption and actual fuel heat content are available. Equation 2 is selected because this
is the preferred approach if the actual fuel heat content is known.

Step 3: Fuel heat content has been provided by the supplier. Table A-l is used to determine the emission factors per
energy unit for natural gas: 53.06 kg C02/mmBtu, 1.0 g CH4/mmBtu, 0.10 g N20/mmBtu.

Step 4: The emissions are calculated as follows:

Natural use is converted to mmBtu: 61,500 therms x 0.1 mmBtu/therm = 6,150 mmBtu

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Section 2: Calculating Emissions

Because fuel use is known in energy units, it can be multiplied directly by emission factors:

6,150 mmBtu x 53.06 kg C02/mmBtu x 10~3 metric tons/kg = 326.3 metric tons C02
6,150 mmBtu x 1.0 g CH4/mmBtu x 10~3 kg/g = 6.15 kg CH4
6,150 mmBtu x 0.10 g N20/mmBtu x 10~3 kg/g = 0.615 kg N20

CH4 and N20 emissions are converted to C02 equivalent emissions:

6.15 kg CH4 x 25 GWP x 10~3 metric tons/kg = 0.2 metric tons C02e
0.615 kg N20 x 298 GWP x 10~3 metric tons/kg = 0.2 metric tons C02e

The C02e emissions from CH4 and N20 are summed with the emissions of C02 to calculate total C02e emissions:
326.3 metric tons C02 + 0.2 metric tons C02e + 0.2 metric tons C02e = 326.7 metric tons C02e

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Direct Emissions from Stationary Combustion Sources

Section 3: Choice of Activity Data and Emission Factors

This section discusses choices of activity data and factors used for calculating emissions with the default fuel analysis
method provided in Section 2.2. This guidance has been structured to accommodate a wide range of organizations with
varying levels of information and measurements in various units. If the organization has a CEMS installed or has carbon
content data based on fuel sampling information, it should refer to guidance in 40 CFR Part 75 or 40 CFR Part 98 to
calculate C02 emissions. In the case of systems with more than one exhaust stack, such as those with a heat recovery
system generator (HRSG) or duct burner, a CEMS may not account for all combustion emissions.

3.1 Activity Data Sources

When calculating GHG emissions with the fuel analysis method, the first piece of information that needs to be determined
is the quantity of fuel combusted for each fuel type. One method of determining the amount of fuel combusted at a
facility is to measure the fuel input into each combustion device and to sum the measured data of each combustion
device in the facility. Typical fuel measurement systems measure the volume of fuel combusted, such as fuel flow meters
for natural gas and fuel oil, or the weight of fuel combusted, such as coal feed belt scales.

If fuel use data are not directly measured then fuel purchase records can be used to determine the amount of fuel
combusted. Records could include monthly utility bills for natural gas or periodic invoices for deliveries of fuel oil. If a
particular fuel type is used for both stationary and mobile sources, care should be taken to avoid double counting the fuel
use.

Commodity natural gas may be purchased from a provider other than the local distribution utility. In this situation, the
reporting organization may receive natural gas invoices from both the commodity supplier as well as from the local
distribution utility, who charges a fee for gas deliveries. It is
recommended that the consumption from the local utility be used
as the activity data, because this is based on fuel meters located
at the organization's facility. To avoid counting the same
consumption twice, ensure that consumption from the
commodity supplier is not also included in the activity data.

There are several factors that could lead to differences between
the amount of fuel purchased and the amount of fuel actually
combusted during a reporting period, for example:

• Changes in fuel storage inventory

• Fuel used as feedstock

• Fugitive releases or fuel spills

For changes in fuel storage inventory, Equation 4 can be used to calculate actual fuel use. Fuel purchase data are usually
reported as the amount of fuel provided by a supplier as it crosses the gate of the facility. However, once fuel enters the
facility there could be some losses before it actually reaches the combustion device. Before calculating emissions,
organizations should subtract the amount of fuel lost in fugitive releases or spills from the amount of fuel purchased.
These losses are particularly important for natural gas, which could be lost due to fugitive releases from facility valves and

Equation 4: Accounting for Changes in Fuel
Inventory

Fuel B = Fuel P + (Fuel ST- Fuel SE)
where:

Fuel B = Fuel burned in reporting period
Fuel P = Fuel purchased in reporting period
Fuel St = Fuel stock at start of reporting period

Fuel SE = Fuel stock at end of reporting period

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Section 3: Choice of Activity Data and Emission Factors

piping, as these fugitive emissions could be significant. These fugitive natural gas releases (essentially methane emissions)
should be accounted for separately from combustion emissions.

Purchased fuels could also be used as feedstock for products produced by the reporting organization. In this case the
carbon in the fuel would be stored in the product as opposed to being released through combustion. In their scope 1
emissions, organizations only include direct emissions from their facilities. If carbon leaves the facility stored in a product,
even if the product is subsequently burned or otherwise releases the stored carbon, this would be included in an
organization's scope 3 emissions, not their scope 1 emissions. Therefore, organizations should subtract any amount of
fuel that is used as feedstock from the amount of fuel purchased before calculating scope 1 emissions.

For certain equipment, such as emergency generators, gathering fuel consumption data through direct measurement or
based on fuel purchases may not be practical. If such equipment generally represents an insignificant source of GHG
emissions, an acceptable method to estimate fuel consumption is to multiply measured or estimated operating hours by
the hourly fuel consumption rate.

If fuel consumption data are not available for certain facilities or operations, an estimate should be made for
completeness. The fraction of total GHG emissions that is estimated should be limited so as not to have a significant
impact on accuracy. If the organization is one of many tenants in a facility and does not have the actual amount of fuel
used in its space, the organization may estimate its fuel consumption by multiplying the fuel use of the entire facility by
the percentage of the floor area that the organization occupies. Organizations may also estimate fuel consumption using
published values for average energy consumption per square foot of floor area. For example, such values are provided by
the U.S. Energy Information Administration's Commercial Building Energy Consumption Survey.

3.2 Activity Data Units

Fuel is measured in terms of physical units (i.e., mass or volume). For organizations that directly measure their own fuel
consumption, it is recommended that they track fuel use in terms of these physical units as they represent the primary
measurement data. Organizations that do not directly measure how much fuel they use need to rely on data from fuel
suppliers. Suppliers may provide data in physical units or in energy units (e.g., therms of natural gas). Suppliers may also
be able to provide data on carbon content or heat content of the fuel, which is discussed further in Section 3.3.

It is possible that organizations may only know the cost of fuels purchased. This is the least accurate method of
determining fuel use and is not recommended for GHG reporting. If the amount spent on fuel is the only information
initially available, it is recommended that organizations contact their fuel supplier to request data in physical or energy
units. If absolutely no other information is available, organizations should use fuel prices to convert the amount spent to
physical or energy units, and should document the prices used. Price varies widely for specific fuels, especially over the
geographic area and timeframe typically established for reporting GHG emissions.

The approaches for measuring or recording the amount of fuel used are listed in order of preference below.

1. An organization has fuel consumption data by fuel type in terms of physical units either measured on site or provided
by a supplier with accurate data on carbon content of the specific fuel as determined by the fuel supplier or by fuel
sampling and analysis (see Section 3.3).

2. An organization has fuel consumption data by fuel type in terms of physical units with accurate data on heat content
of the specific fuel as determined by the fuel supplier or by fuel sampling and analysis (see Section 3.3). Alternatively,
organization has fuel consumption data from the supplier in energy units.

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Section 3: Choice of Activity Data and Emission Factors

3. An organization has data on the physical quantity of fuel purchased but not the carbon or heat content.

4. An organization only has data on cost of fuels purchased and has to convert to physical quantity based on dividing
total expenditures by average prices.

3.3 Fuel Carbon Content and Heat Content

Emissions of C02 from fuel combustion are dependent on the amount of carbon in the fuel, which is specific to the fuel
type and grade of the fuel. It is recommended that organizations determine the actual carbon content of the fuels
consumed, if possible. The most accurate method to determine a fuel's carbon content data is through chemical analysis
of the fuel. This data may be obtained directly from the fuel supplier.

Carbon content can also be determined by fuel sampling and analysis. Fuel sampling and analysis should be performed
periodically with the frequency dependent on the type of fuel. The sampling frequency should be greater for more
variable fuels (e.g., coal, wood, MSW) than for more homogenous fuels (e.g., natural gas, fuel oil). The sampling and
analysis methodologies used should be detailed in the organization's Inventory Management Plan (IMP). Refer to 40 CFR
Part 75, Appendix G or 40 CFR Part 98, Subpart C for recommended sampling rates and methods.

If actual fuel carbon content is available, either from the supplier or from sampling and analysis, Equation 3 in Section 2.2
may be used to calculate C02 emissions. Because Equation 3 is only applicable to C02 emissions, Equation 1 or 2 should be
used in conjunction to calculate CH4 and N20 emissions. It is also good practice to track the carbon content values used
and to indicate if they vary over time.

If carbon content is not available, it is recommended that organizations determine the actual heat content of the fuel, if
possible. The heat content of purchased fuel is often known and provided by the fuel supplier because it is directly related
to the useful output or value of the fuel. Heat content can also be determined by fuel sampling and analysis, using
methods discussed above. It is recommended that organizations use heat contents determined by one of these methods
rather than default heat content, as these should better represent the characteristics of the specific fuel consumed. If
actual fuel heat content is available, either from the supplier or from sampling and analysis, then Equation 2 in Section 2.2
may be used to calculate C02, CH4, and N20 emissions. It is also good practice to track the heat content values used and to
indicate if they vary over time.

When determining fuel heat content or tracking fuel use data in energy units, it is important to distinguish between lower
heating values (LHV) and higher heating values (HHV), also called net calorific value and gross calorific value, respectively.
Heating values describe the amount of energy released when a fuel is burned completely, and LHV and HHV are different
methods to measure the amount of energy released. A given fuel, therefore, always has both a LHV and a HHV. The LHV
assumes that the steam released during combustion remains as a gas. The HHV assumes that the steam is condensed to a
liquid, thus releasing more energy. HHV is typically used in the U.S. and in Canada, while other countries typically use LHV.

All emission factors and default heat content values in this guidance are based on HHV. Therefore, if fuel consumption is
measured in LHV units, this must be converted to HHV before calculating emissions. To convert from LHV to HHV, a
simplified convention used by the International Energy Agency can be used. For coal and petroleum, divide energy in LHV
by 0.95. For natural gas, divide by 0.90.

3.4 Emission Factors

If actual fuel carbon content is not available, the fuel analysis method for calculating emissions relies on default emission
factors. These factors approximate the carbon content of fuel to quantify the amount of C02 that will be released when

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Section 3: Choice of Activity Data arid Emission Factors

the fuel is combusted. Emission factors also assume typical combustion technology to quantify the amount of CFU and
N20 that will be released.

Appendix A provides two main types of default emission factors: factors defined per unit of fuel mass or volume (Table A-
1 and A-2), and factors defined by per unit of fuel energy content (Table A-3 and A-4). As discussed in Section 2.2, using
the emission factors per energy unit, along with Equation 2, is preferable to using emission factors per mass or volume.

Not all stationary combustion devices burn standard fuels. Combustion devices could also burn waste fuels, for example,
MSW, with mixed biomass and fossil carbon content. Flares and thermal oxidizers could burn waste gas streams. These
combustion sources and waste fuels are treated like other combustion sources and fuel types. If the carbon content of the
waste fuel is known, Equation 3 can be used to quantify emissions. If the carbon content is not known, determining the
appropriate emission factors can be challenging due to the variability and non-standardized nature of waste fuels.

Emission factors are provided in Appendix A for waste fuels such as MSW, tires, and used oil. For more complex waste gas
streams, an example calculation is provided below. If none of these options are possible, emission factors for some waste
fuels can be determined by using the emission factor for a fuel that most closely represents the waste fuel.

Example: Determining an Emission Factor for
a Gas Waste Stream

An organization has a thermal oxidizer
destroying a waste gas stream of different
components. The organization has data on
volume of gas combusted and on the mole
fraction of the different components of the
waste gas stream.

The first step is to determine the total number
of moles in the waste stream per a specific
volume. This step is based on the assumed
temperature and pressure of the gas.

Assuming conditions of 1 aim and 25° C, there are 2.55 x 10-3 lb mole of gas per cubic foot of gas. This factor could be
adjusted to meet the specific temperature and pressure conditions of the organization's waste gas stream. An emission
factor is then determined per cubic feet of gas based on the following Equation 5.

The following Table 2 shows an example gas waste stream with the mole fractions of different components.

Table 2: Example Gas Waste Stream

Gas Component

m.w.

Lb C / ft3 gas

CO,

2.55 x 1CT3

27%

0.0015

CH4

30%

2.55 x 10"3

75%

0.0092

20%

2.55 x 10"3

82%

0.018

QH,

35%

2.55 x ICS'3

92%

0.064

Other non-C

10%

2.55 x 1CT3

0.0

Total

100%

0.093

Equation 5: Determining Emission Factor for Gas Waste Stream

(*=)-£¦

Emission Factor ( — | MFiXMCg3Sxm.w.jXCFi

i=l

Where:

( lb-mole i "s

MFi = Molar fraction of gas component i

Vlb-mole gas>

/lb-mole gas^i
MC„S = Molar concentration of gas ;

B V ft3 gas

/ lb 1 \

m.w.j = Molecular weight of gas component i ;—

Vlb-mole i/

/lbc\

CFj = Carbon fraction of gas component i —-I

V lb i /

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Direct Emissions from Stationary Combustion Sources

Section 3: Choice of Activity Data and Emission Factors

Based on Table 2 it can be seen that the emission factor for this example gas waste stream is 0.093 lb C per ft3 of waste
gas. To obtain total C02 emissions from this waste gas combustion, the emission factor can be multiplied by the total
amount of gas combusted and by 44/12, the ratio of the molecular weights of C02 and carbon.

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Direct Emissions from Stationary Combustion Sources

Section 4: Completeness

in order for an organization's GHG inventory to be complete it must include all emission sources within the organization's
chosen inventory boundaries. See Chapter 3 of the GHG Protocol for detailed guidance on setting organizational
boundaries and Chapter 4 of the GHG Protocol for detailed guidance on setting operational boundaries of the inventory.

On an organizational level, the inventory should include emissions from all applicable facilities or fleets of vehicles.
Completeness of organization-wide emissions can be checked by comparing the list of sources included in the GHG
emissions inventory with those included in other emissions inventories, environmental reporting, financial reporting, etc.

At the operational level, an organization should include all GHG emissions from the sources included in their inventory.
Possible GHG emission sources are stationary fuel combustion, combustion of fuels in mobile sources, purchases of
electricity, emissions from air conditioning equipment, and process or fugitive emissions. Organizations may refer to this
guidance document for calculating emissions from stationary combustion sources and to the Center's GHG Guidance
documents for calculating emissions from other sources. Operational completeness of stationary combustion sources can
be checked by comparing the sources included in the GHG inventory with those reported under regulatory programs (e.g.,
Title V air permit), or in annual fuel use surveys. Examples of typical types of fuel combustion sources that should be
included are as follows:

• Boilers/furnaces

• Internal combustion engines

• Turbines

• Flares

• Process heaters/ovens

• Incinerators

• Cooling systems (e.g., natural gas chillers)

As described in Chapter 1 of the GHG Protocol, there is no materiality threshold set for reporting emissions. The
materiality of a source can only be established after it has been assessed. This does not necessarily require a rigorous
quantification of all sources, but at a minimum, an estimate based on available data should be developed for all sources.

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Direct Emissions from Stationary Combustion Sources

Section 5: Uncertainty Assessment

There is uncertainty associated with all methods of calculating C02, CH4, and N20 emissions from stationary combustion
sources.

EPA does not recommend that organizations quantify uncertainty as +/- % of emissions or in terms of data quality
indicators.

It is recommended that organizations attempt to identify the areas of uncertainty in their emissions calculations and make
an effort to use the most accurate data possible. If the CEMS approach is used to calculate emissions, it is recommended
that the organization follow the QA/QC guidance and good practices associated with that method as outlined in the Acid
Rain Program Rule4 or in 40 CFR Part 98. Entities utilizing CEMS to comply with Clean Air Act regulations are required to
develop a quality assurance plan. This plan should address C02 emissions measurement.

The accuracy of calculating emissions from fuel combustion in stationary sources from the fuel analysis method is partially
determined by the availability of data on the amount of fuel consumed or purchased. If the amount of fuel combusted is
directly measured or metered before entering the combustion device, then the resulting uncertainty should be fairly low.
Data on the quantity of fuel purchased should also be an accurate representation of fuel combusted, provided that any
necessary adjustments are made for changes in fuel inventory, fuel used as feedstock, fugitive releases, or spills.
Uncertainty will be higher if only prices of fuels purchased are used to estimate fuel consumption, or if an estimation
approach is used.

The accuracy of calculating emissions from stationary combustion sources with the fuel analysis method is also
determined by the factors used to convert fuel use into emissions. Uncertainty in the factors is primarily due to the
accuracy in which they are measured, and the variability of the supply source. For example, carbon content factors for
coal vary greatly, depending on its characteristics, chemical properties, and annual fluctuations in the fuel quality.
Therefore, using the U.S. default emission factors for coal may result in greater uncertainty than for other fuels if the local
fuel supplies do not match the default fuel characteristics.

4 Part 75.21 and Appendix B of the regulation discuss the QA/QC plan.

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Direct Emissions from Stationary Combustion Sources

Section 6: Documentation

Section 6: Documentation

in order to ensure that emissions calculations are transparent and verifiable, the documentation sources listed in Table 1
should be maintained. These documentation sources should be collected to ensure the accuracy and transparency of the
related emissions and should also be included in the organization's Inventory Management Plan (IMP).

Table 3: Documentation Sources for Stationary Combustion

Data

Documentation Source

Fuel consumption data

Purchase receipts or utility bills; delivery receipts;



contract purchase or firm purchase records; stock



inventory documentation; metered fuel documentation

Heat contents and carbon contents used other than

Purchase receipts or utility bills; delivery receipts;

defaults provided

contract purchase or firm purchase records; other



documentation from suppliers; EIA, EPA, or industry



reports

Prices used to convert cost of fuels purchased to

Purchase receipts; delivery receipts; contract purchase

amount or energy content of fuel consumed

or firm purchase records; EIA, EPA, or industry reports

All assumptions made in calculating fuel

All applicable sources

consumption, heat contents, and emission factors



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Direct Emissions from Stationary Combustion Sources Section 7; Inventory Quality Assurance and Quality Control

Section 7: Inventory Quality Assurance and Quality
Control

Chapter 7 of the GHG Protocol provides general guidelines for implementing a QA/QC process for all emissions
calculations. For stationary combustion sources, activity data and emission factors can be verified using a variety of
approaches:

• Fuel consumption data by source or facility can be compared with fuel purchasing data, taking into account any
changes in inventory.

• Fuel energy use data can be compared with data provided to the U.S. Department of Energy or other U.S.
Environmental Protection Agency reports or surveys.

• If emission calculations were obtained from CEMS, this data can be compared to emissions calculated using the
fuel analysis method.

• If any emission factors were calculated or obtained from the fuel supplier, these factors can be compared to U.S.
average emission factors.

• The rate at which suppliers change/update heating values can be examined to approximate accuracy.

• Depending on the end-use, some non-energy uses of fossil fuels, such as for manufacturing plant feedstocks, can
result in long term storage of some or all of the carbon contained in the fuel. This guidance addresses fuel use for
combustion purposes only. Therefore, all fuel consumption for other purposes should be excluded from this
analysis.

• Examining the quality control associated with equipment used for facility level fuel measurements and equipment
used to calculate site-specific emission factors, or emissions.

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Appendix A: Default Emission Factors

This appendix contains default factors for use in calculating emissions from the fuel analysis method described in Section
2.2 of this document.

The emission factors in Table A-l and A-2 can be used in Equation 1 from Section 2.2 to calculate GHG emissions if fuel
use is known only in mass or volume units, and no information is available about the fuel heat content or carbon content.
These emission factors are developed by multiplying the emission factors in Table A-3 and A-4 by the default heat content
of the fuels, which is also shown in Table A-l and A-2.

The emission factors in Table A-3 and A-4 can be used in Equation 2 from Section 2.2 to calculate GHG emissions when
the actual fuel heat content is known or when the fuel use is provided in energy units.

All C02 emission factors assume that 100% of the carbon content of the fuel is oxidized to C02, as is recommended by the
Intergovernmental Panel on Climate Change (IPCC).

The ChU and N20 emission factors provided represent emissions in terms of fuel type and assume typical combustion
technology for industry. Other references, including those listed below, provide emission factors by end-use sector (i.e.,
residential, commercial, industrial, electricity generation) or by more specific combustion technology type (e.g., natural
gas industrial boilers >293 MW). These references are recommended for organizations interested in performing a more
accurate calculation of ChU and N20 emissions.

• Intergovernmental Panel on Climate Change (IPCC). 2006. Guidelines for National Greenhouse Gas Inventories,
Intergovernmental Panel on Climate Change, Organization for Economic Co-Operation and Development. Paris,
France.

• U.S. EPA 1995. Compilation of Air Pollutant Emission Factors, Vol. 1: Stationary Point and Area Sources, 5th
edition, Supplements A, B, C, D, E, F, Updates 2001-2011, AP-42, U.S. EPA Office of Air Quality Planning and
Standards, Research Triangle Park, North Carolina.

Table A-l: Emission Factors for Equation 1 (EFi) - Emissions per Mass or Volume Unit for Fossil Fuel

Combustion

Fuel

Heat Content

(HHV)

(mmBtu/ton)

Emission Factors

Coal and Coke

Anthracite Coal
Bituminous Coal
Sub-bituminous Coal
Lignite Coal

Mixed (Commercial Sector)
Mixed (Electric Power Sector)
Mixed (Industrial Coking)
Mixed (Industrial Sector)

Coal Coke

(kg C02/ton)

(g CH4/ton)

(g N20/ton)

25.09
24.93
17.25
14.21
21.39
19.73
26.28
22.35
24.80

2,602
2,325
1,676
1,389
2,016
1,885
2,468
2,116
2,819

276
274
190
156
235
217
289
246
273

40
40
28
23
34
32
42
36
40

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Appendix A: Default Emission Factors

Table A-l: Emission Factors for Equation 1 (EFi) - Emissions per Mass or Volume Unit for Fossil Fuel
Combustion

Fuel

Heat Content
(HHV)



Emission Factors



Fossil Fuel-derived Fuels (Solid)

(mmBtu/ton)

(kg C02/ton)

(g CH4/ton)

(g N20/ton)

Municipal Solid Waste

9.95

902

318

42

Petroleum Coke (Solid)

30.00

3,072

960

126

Plastics

38.00

2,850

1,216

160

Tires

28.00

2,407

896

118

Natural Gas

(mmBtu/scf)

(kg C02/scf)

(g CH4/scf)

(g N20/scf)

Natural gas

0.001026

0.05444

0.00103

0.00010

Fossil Fuel-derived Fuels (gaseous)

(mmBtu/scf)

(kg C02/scf)

(g CH4/scf)

(g N20/scf)

Blast Furnace Gas

0.000092

0.02524

0.000002

0.000009

Coke Oven Gas

0.000599

0.02806

0.000288

0.000060

Fuel Gas

0.001388

0.08189

0.004164

0.000833

Propane Gas

0.002516

0.15463

0.007548

0.001510

Petroleum Products

(mmBtu/gal)

(kg C02/gal)

(g CH4/gal)

(g N20/gal)

Asphalt and Road Oil

0.158

11.91

0.47

0.09

Aviation Gasoline

0.120

8.31

0.36

0.07

Butane

0.103

6.67

0.31

0.06

Butylene

0.105

7.22

0.32

0.06

Crude Oil

0.138

10.29

0.41

0.08

Distillate Fuel Oil No. 1

0.139

10.18

0.42

0.08

Distillate Fuel Oil No. 2

0.138

10.21

0.41

0.08

Distillate Fuel Oil No. 4

0.146

10.96

0.44

0.09

Ethane

0.068

4.05

0.20

0.04

Ethylene

0.058

3.83

0.17

0.03

Heavy Gas Oils

0.148

11.09

0.44

0.09

Isobutane

0.099

6.43

0.30

0.06

Isobutylene

0.103

7.09

0.31

0.06

Kerosene

0.135

10.15

0.41

0.08

Kerosene-type Jet Fuel

0.135

9.75

0.41

0.08

Liquefied Petroleum Gases (LPG)

0.092

5.68

0.28

0.06

Lubricants

0.144

10.69

0.43

0.09

Motor Gasoline

0.125

8.78

0.38

0.08

Naphtha (<401 deg F)

0.125

8.50

0.38

0.08

Natural Gasoline

0.110

7.36

0.33

0.07

Other Oil (>401 deg F)

0.139

10.59

0.42

0.08

Pentanes Plus

0.110

7.70

0.33

0.07

Petrochemical Feedstocks

0.125

8.88

0.38

0.08

Petroleum Coke

0.143

14.64

0.43

0.09

Propane

0.091

5.72

0.27

0.05

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Appendix A: Default Emission Factors

Table A-l: Emission Factors for Equation 1 (EFi) - Emissions per Mass or Volume Unit for Fossil Fuel
Combustion

Fuel

Heat Content
(HHV)



Emission Factors



Propylene

0.091

6.17

0.27

0.05

Residual Fuel Oil No. 5

0.140

10.21

0.42

0.08

Residual Fuel Oil No. 6

0.150

11.27

0.45

0.09

Special Naphtha

0.125

9.04

0.38

0.08

Unfinished Oils

0.139

10.36

0.42

0.08

Used Oil

0.138

10.21

0.41

0.08

Table A-2: Emission Factors for Equation 1 (EFi) - Emissions per Mass or Volume Unit for Biomass Fuel

Combustion









Fuel

Heat Content
(HHV)



Emission Factors



Biomass Fuels (Solid)

(mmBtu/ton)

(kg C02/ton)

(g CH4/ton)

(g N20/ton)

Agricultural Byproducts

8.25

975

264

35

Peat

8.00

895

256

34

Solid Byproducts

10.39

1,096

332

44

Wood and Wood Residuals

17.48

1,640

126

63

Fossil Fuel-derived Fuels (Solid)

(mmBtu/scf)

(kg CO,/scf)

(g CH/scf)

(g N,0/scf)

Landfill Gas

0.000485

0.025254

0.001552

0.000306

Other Biomass Gases

0.000655

0.034106

0.002096

0.000413

Biomass Fuels (Liquid)

(mmBtu/gal)

(kg C02/gal)

(g CH4/gal)

(g N20/gal)

Biodiesel (100%)

0.128

9.45

0.14

0.01

Ethanol (100%)

0.084

5.75

0.09

0.01

Rendered Animal Fat

0.125

8.88

0.14

0.01

Vegetable Oil

0.120

9.79

0.13

0.01



Table A-3: Emission Factors for Equation 2 (EF ) - Emissions per Energy Unit for Fossil Fuel Combustion

Fuel





Emission Factors



Coal and Coke



(kg C02/mmBtu)

(g CH4/ mmBtu)

(g N20/ mmBtu)

Anthracite Coal



103.69

11

1.6

Bituminous Coal



93.28

11

1.6

Sub-bituminous Coal



97.17

11

1.6

Lignite Coal



97.72

11

1.6

Mixed (Commercial Sector)



94.27

11

1.6

Mixed (Electric Power Sector)



95.52

11

1.6

Mixed (Industrial Coking)



93.90

11

1.6

Mixed (Industrial Sector)



94.67

11

1.6

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Appendix A: Default Emission Factors

Table A-3: Emission Factors for Equation 2 (EF ) -

Emissions per Energy Unit for Fossil Fuel Combustion

Fuel



Emission Factors



Coal Coke

113.67

11

1.6

Fossil Fuel-derived Fuels (Solid)







Municipal Solid Waste

90.70

32

4.2

Petroleum Coke (Solid)

102.41

32

4.2

Plastics

75.00

32

4.2

Tires

85.97

32

4.2

Natural Gas







Natural Gas

53.06

1.0

0.10

Fossil Fuel-derived Fuels (gaseous)







Blast Furnace Gas

274.32

0.022

0.10

Coke Oven Gas

46.85

0.48

0.10

Fuel Gas

59.00

3.0

0.60

Propane Gas

61.46

3.0

0.60

Petroleum Products







Asphalt and Road Oil

75.36

3.0

0.60

Aviation Gasoline

69.25

3.0

0.60

Butane

64.77

3.0

0.60

Butylene

68.72

3.0

0.60

Crude Oil

74.54

3.0

0.60

Distillate Fuel Oil No. 1

73.25

3.0

0.60

Distillate Fuel Oil No. 2

73.96

3.0

0.60

Distillate Fuel Oil No. 4

75.04

3.0

0.60

Ethane

59.60

3.0

0.60

Ethylene

65.96

3.0

0.60

Heavy Gas Oils

74.92

3.0

0.60

Isobutane

64.94

3.0

0.60

Isobutylene

68.86

3.0

0.60

Kerosene

75.20

3.0

0.60

Kerosene-type Jet Fuel

72.22

3.0

0.60

Liquefied Petroleum Gases (LPG)

61.71

3.0

0.60

Lubricants

74.27

3.0

0.60

Motor Gasoline

70.22

3.0

0.60

Naphtha (<401 deg F)

68.02

3.0

0.60

Natural Gasoline

66.88

3.0

0.60

Other Oil (>401 deg F)

76.22

3.0

0.60

Pentanes Plus

70.02

3.0

0.60

Petrochemical Feedstocks

71.02

3.0

0.60

Petroleum Coke

102.41

3.0

0.60

Propane

62.87

3.0

0.60

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Appendix A: Default Emission Factors

Table A-3: Emission Factors for Equation 2 (EF ) - Emissions per Energy Unit for Fossil Fuel Combustion

Fuel	Emission Factors

Propylene

67.77

3.0

0.60

Residual Fuel Oil No. 5

72.93

3.0

0.60

Residual Fuel Oil No. 6

75.10

3.0

0.60

Special Naphtha

72.34

3.0

0.60

Unfinished Oils

74.54

3.0

0.60

Used Oil

74.00

3.0

0.60

Table A-4: Emission Factors for Equation 2 (EF2) - Emissions per Energy Unit for Biomass Fuel Combustion

Fuel

Biomass Fuels (Solid)

Agricultural Byproducts
Peat

Solid Byproducts
Wood and Wood Residuals

(kg CCh/mmBtu)
118.17
111.84
105.51
93.80

Emission Factors

(gCbU/mmBtu) (gN20/mmBtu)

32
32
32
7.2

4.2
4.2
4.2
3.6

Biomass Fuels (Gaseous)

Landfill Gas
Other Biomass Gases

52.07
52.07

3.2
3.2

0.63
0.63

Biomass Fuels (Liquid)

Biodiesel (100%)

Ethanol (100%)

Rendered Animal Fat
Vegetable Oil

Biomass Fuels (Kraft Pulping Liquor, by Wood Furnish)

North American Softwood

North American Hardwood

Bagasse

Bamboo

Straw

73.84
68.44
71.06
81.55

94.4
93.7

95.5
93.7
95.1

1.1
1.1
1.1
1.1

1.9
1.9
1.9
1.9
1.9

0.11
0.11
0.11
0.11

0.42
0.42
0.42
0.42
0.42

Source for the emission factors in this appendix: Federal Register EPA; 40 CFR Part 98; e-CFR, June 13, 2017 (see link below). Table C-l, Table
C-2, Table AA-1. https://www.ecfr.gov/cgi-bin/text-

idx?SID=ae265d7d6f98ec86fcd8640b9793a3f6&mc=true&node=pt40.23.98&rgn=div5#ap40.23.98 19.1

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