vvEPA
United States
Environmental Protection
Agency
May 2008
EPA430-K-08-003
www.epa.gov/climateleaders
Office of Air and Radiation
CLIMATE LEADERS
GREENHOUSE GAS INVENTORY PROTOCOL CORE MODULE GUIDANCE
Direct Emissions from
Stationary Combustion Sources
CLIMATE
U.S. Environmental Protection Agency
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The Climate Leaders Greenhouse Gas Inventory Protocol is based on the Greenhouse Gas Protocol (GHG Protocol)
developed by the World Resources Institute (WRI) and the World Business Council for Sustainable Development
(WBCSD). The GHG Protocol consists of corporate accounting and reporting standards and separate calculation
tools. The Climate Leaders Greenhouse Gas Inventory Protocol is an effort by EPA to enhance the GHG Protocol to fit
more precisely what is needed for Climate Leaders. The Climate Leaders Greenhouse Gas Protocol consists of the fol-
lowing components:
Design Principles Guidance
Core Modules Guidance
Optional Modules Guidance
All changes and additions to the GHG Protocol made by Climate Leaders are summarized in the Climate Leaders
Greenhouse Gas Inventory Protocol Design Principles Guidance.
For more information regarding the Climate Leaders Program, visit us on the web at www.epa.gov/climateleaders.
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Stationary Combustion Sources Guidance
1. Introduction 1
1.1. Greenhouse Gases Included 1
1.2. Biofuels 2
1.3. Waste Fuels 2
1.4. Non-Combustion Emission Sources 2
2. Methods for Estimating CO2 Emissions 3
2.1. Use of Continuous Emissions Monitoring System (CEMS) Data 3
2.2. Fuel Analysis Approach 4
3. Methods for Estimating CH4 and N2O Emissions 8
4. Choice of Method for Calculating CO2 Emissions 1O
5. Choice of Activity Data and
Emission Calculation Factors 11
5.1. Activity Data Source 11
5.2. Activity Data Units 12
5.3. Emission Calculation Factors 12
6. Completeness 17
7. Uncertainty Assessment 18
8. Reporting and Documentation 19
9. Inventory Quality Assurance and Quality Control 2O
Appendix A: Calculating CH4 and N2O Emissions
from Stationary Combustion Sources 21
Appendix B: Default Factors for Calculating
CO2 Emissions 23
CO2 Emissions Factors Based on Fuel Energy 27
CO2 Emissions Factors Based on Fuel Mass or Volume 29
Waste Fuels 31
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Cources Guidance
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Stationary Combustion Sources Guidance
Introduction
Combustion of fossil fuels in stationary
combustion sources results in the fol-
lowing greenhouse gas (GHG) emis-
sions: carbon dioxide (C02), methane (CH^)
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 streams.
This document presents guidance for estimating
direct GHG emissions resulting from stationary
(non-transport) combustion of fossil fuels at
owned/operated sources. This guidance applies
to all companies whose operations involve sta-
tionary combustion of fossil fuel.
1.1. Greenhouse
Gases Included
The three GHGsC02, CH4, and N20are emit-
ted during the combustion of fossil fuels. C02
accounts for the majority of the GHG emissions
from stationary combustion sources. In the
U.S., C02 emissions represent over 99% of the
total C02-equivalent' GHG emissions from all
commercial, industrial, and electricity genera-
tion and industrial stationary combustion
sources. CH4 and N20 emissions together rep-
resent less than 1% of the total C02-equivalent
emissions from the same sources2.
Given the relative emissions contributions of
each gas, CH4 and N20 emissions are often
excluded by assuming that they are "not mate-
rial". However, as outlined in Chapter 1 of the
Climate Leaders Design Principles, the materiali-
ty 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 avail-
able data should be developed for all sources
and categories of GHGs, and included in a
Partner's GHG inventory.
The approach to estimate C02 emissions from
stationary combustion sources varies signifi-
cantly from the approach to estimate CH4 and
N20 emissions. While C02 can be reasonably
estimated by applying an appropriate carbon
content and fraction of carbon oxidized factor
to the fuel quantity consumed, estimating CH4
and N20 depends not only upon fuel character-
istics, but also on technology type and com-
bustion characteristics, usage of pollution con-
trol 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. Due to this complex-
ity, a much greater effort is required to esti-
mate CH4 and N20 emissions from stationary
sources, and a much higher level of uncertain-
ty exists.
Due to the relative emission contribution of
each gas and the complexity involved in esti-
mating CH4 and N20 emissions, this document
primarily deals with guidance for estimating
C02 emissions from stationary combustion
sources. The guidance on estimating CH4 and
N20 emissions is limited to the screening
approach in Section 3 and the associated set of
1 See Chapter 6 of the Climate Leaders Design Principles document for a discussion of C02-equivalents.
2 Tables 3-3, 3-16, & 3-17 of U.S. EPA 2007 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, EPA430-R-07-002, April 2007.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
default emission factors. However, for Partners
that wish to examine CH4 and N20 emissions
from stationary combustion sources in more
detail, a list of references for estimating these
emissions is included in Appendix A.
1.2. Biofuels
Non-fossil carbon bearing fuels (e.g., wood and
wood waste, etc.) may also be combusted in
stationary sources. The C02 emissions from
combustion of these fuels are treated as bio-
mass C02 emissions. Partners are required to
list biomass C02 emissions in terms of total
amount of gas emitted as part of their Climate
Leaders reporting requirements. However, bio-
mass C02 emissions are not included in the
overall C02-equivalent emissions inventory
used to track Partners' progress towards their
Climate Leaders reduction goal. This is
because it is assumed that combustion of bio-
fuels do not contribute to net addition of C02
to the atmosphere3.
1.3. Waste Fuels
Waste products in solid, liquid, and gaseous
form may be combusted in stationary sources
as well. Typical waste products 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 fuels are treated like any other
fuels in a Partner's inventory. Therefore, any
GHG produced from combustion of a fossil-
based waste product is reported in a Partner's
inventory. Any C02 emissions from combustion
of a non-fossil waste are listed as biomass C02
as described in Section 1.2. This applies to
entire waste streams or portions of the waste
stream. For example, the C02 produced from
combusting the biomass portion of MSW (e.g.,
yard waste, paper products, etc.) is reported
as biomass C02. The C02 produced from com-
busting the fossil portion of the MSW (e.g.,
plastics, etc.) is reported as C02 and is includ-
ed in a Partner's inventory.
Emissions from waste fuels only include the
actual emissions from the combustion process
and do not include any "offsets" from use of
the waste fuel. Future guidance may be devel-
oped around offsets obtained from the burning
of waste fuels and they would be included in
the Climate Leaders Optional Module on off-
sets. These offsets would be reported separate-
ly on a Partner's Climate Leaders inventory.
1.4. Non-Combustion
Emission Sources
The combustion of fuel does not account for all
GHG emissions from stationary combustion
sources. For example, use of natural gas may
result in fugitive methane emissions from leak-
ing gas transportation lines owned by the
Partner. Storage of fuels may also result in fugi-
tive emissions, for example, VOC emissions
from fuel storage tanks (often regarded as a
significant VOC source in air pollution studies)
and methane emissions from coal piles.
Typically these sources are minor compared to
C02 combustion emissions, however, Partners
should account for these non-combustion
sources. Climate Leaders guidance on estimat-
ing these other sources will be developed as
necessary.
3 This assumes that there is no net loss of biomass-based carbon associated with the land use practices used to produce these fuels,
U.S. EPA 2007Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2005, EPA430-R-07-002, April 2007.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Methods for Estimating CO2
Emissions
T
here are two main methods for esti-
mating C02 emissions from stationary
combustion sources:
Direct measurement
Analysis of fuel input
Direct measurement of C02 emissions is per-
formed through the use of a Continuous
Emissions Monitoring System (CEMS). Fuel
analysis is essentially a mass balance approach
where carbon content and carbon oxidation
factors are applied to fuel input to determine
emissions. Both methods are described in
more detail in the following sections.
2.1. Use of
Continuous Emissions
Monitoring System
(CEMS) Data
Continuous emissions monitoring is the contin-
uous measurement of pollutants emitted into
the atmosphere in exhaust gases from combus-
tion or industrial processes. Several U.S. EPA
regulatory programs (e.g., Acid Rain Program,
New Source Performance Standards, and
Maximum Available Control Technology
Standards) have provisions regarding CEMS.
CEMS can be used to measure C02 emissions.
Title IV of the U.S. Clean Air Act requires own-
ers or operators of electricity generating units
to report C02 emissions from affected units
under the Acid Rain Program4. 40 CFR Part 75
which establishes requirements for the moni-
toring, recordkeeping, and reporting from
affected units under the Acid Rain Program
outlines two approaches for determining C02
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 volumet-
ric flow rate of flue gas can be used to
determine C02 mass emissions. Annual C02
emissions are determined based on the
operating time of the unit.
A monitor measuring 02 concentration per-
cent by volume of flue gas and a flow moni-
toring system measuring the volumetric
flow rate of flue gas combined with theoreti-
cal C02 and flue gas production by fuel
characteristics can be used to determine
C02 flue gas emissions and C02 mass emis-
sions. Annual C02 emissions are determined
based on the operating time of the unit.
If a Partner has reported quality assured C02
emissions data from one of the above CEMS
approaches to satisfy their Title IV require-
ments, they should report these same C02
emissions directly to the Climate Leaders pro-
gram. Partners that collect C02 emissions data
from a CEMS that does not conform to the spe-
cific requirements prescribed under 40 CFR
Part 75 should use the fuel analysis approach-
es outlined in Section 2.2 below, or may
request that Climate Leaders review the CEMS
data as provided in Chapter 6 of the Climate
Leaders Design Principles.
4 Units over 25 megawatts and new units under 25 megawatts that use fuel with a sulfur content greater than 0.05 percent by weight
are required to measure and report sulfur dioxide (S02), nitrogen oxide (NOx), and C02 emissions under the U.S. EPA's Acid Rain
Program.
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Stationary Combustion Sources Guidance
2.2. Fuel Analysis
Approach
The fuel analysis approach to estimate C02
emissions involves determining a carbon con-
tent of fuel combusted and applying that to the
amount of fuel burned to get C02 emissions.
For affected units under the Acid Rain
Program, 40 CFR Part 75 (Appendix G)
describes fuel analysis methods for calculating
C02 emissions based on the measured carbon
content of the fuel, adjusted for any unburned
carbon, and the amount of fuel combusted5.
If a Partner is measuring and reporting C02
emissions under their Title IV requirements
using the fuel analysis methods outlined in 40
CFR Part 75, they should report these same
C02 emissions results directly to the Climate
Leaders program.
For Partners not reporting C02 emissions
under the Acid Rain Program, this guidance
provides a default fuel analysis approach that
Partners should use to calculate their C02
emissions. The default approach uses carbon
content factors that are based on energy units
as opposed to mass or volume units. Carbon
content factors based on energy units are less
variable than carbon content factors per mass
or volume units because the heat content or
energy value of a fuel is more closely related to
the amount of carbon in the fuel than to the
total physical quantity of fuel. Carbon content
factors stated in terms of carbon per energy of
the fuel are generally less variable than those
expressed in terms of mass or volume so there
is less chance for error (see Section 5).
Equation 1 presents an overview of the default
fuel analysis approach. Fuel types with default
heat contents, carbon content coefficients, and
fraction-oxidized factors are listed in Appendix
B. This method can be applied using the emis-
sion factors provided or using custom coeffi-
cients. The steps involved with estimating C02
emissions with the fuel analysis approach are
shown on the following page.
5 Units reporting CO 2 emissions under the Acid Rain Program, through either the CEMS or fuel analysis approach, are required to
include C02 emissions from sorbent use (e.g., limestone used in flue gas desulfurization equipment). Partners not required to
report under the Acid Rain Program should be sure to include any C02 emissions from sorbent use in their Climate Leaders inven-
tory. Procedures to estimate these emissions are outlined in 40 CFR Part 75 Appendix G, Section 3.
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Stationary Combustion Sources Guidance
Equation 1: Fuel Analysis Approach for Estimating CO2
Emissions
Emissions = ^ Fuelj x HCj x Cj x FOj x
where:
Fuelj
HCj
C,
Mass or Volume of Fuel Type i Combusted
energy
energy "\
mass or volume of fuel J
(massC "\
1
energy J
FOj = Fraction Oxidized of Fuel Type i
C02 (m.w.) = Molecular weight of C02
C (m.w.) = Molecular Weight of Carbon
Step 1: Determine the amount of fuel com-
busted. This can be based on fuel receipts,
purchase records, or through direct meas-
urement at the combustion device. If pur-
chase records are used, care should be
taken to subtract out fuel used to produce
feedstocks or materials such as plastics
where the carbon is ultimately stored.
Section 5.1 describes in more detail the dif-
ferent sources that can be used to deter-
mine amount of fuel combusted.
Step 2: Convert the amount of fuel combusted
into energy units. As discussed in Section
5.2, the amount of fuel combusted is meas-
ured in terms of physical units (e.g., mass
or volume). This needs to be converted to
amount of fuel used in terms of energy units
in order to apply the default carbon content
coefficients. The heating value 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. Heating
value can also be determined by fuel sam-
pling and analysis.* If heating value data is
available, either from the fuel supplier or
sampling and analysis results, then that
data should be used. If this is not the case
then default fuel specific heating values list-
ed in Appendix B can be applied.
Step 3: Estimate carbon content of fuels con-
sumed. To estimate the carbon content,
multiple energy content for each fuel by
fuel-specific carbon content coefficients
(mass C/energy). Carbon content can also
be determined by fuel sampling and analy-
sis.* If carbon content data is available,
either from the fuel supplier or sampling
and analysis results, then that data should
be used. U.S. average default carbon con-
tent coefficients are provided in Appendix B
if fuel specific data is not available from the
fuel supplier or sampling and analysis.
Fuel sampling and analysis should be performed periodically with the frequency dependant on the type of fuel. The sampling fre-
quency should be greater for more variable fuels (e.g., coal, wood, sold waste) than for more homogenous fuels (e.g., natural gas,
diesel fuel). The sampling and analysis methodologies used should be detailed in the Partners IMP. Refer to 40 CFR Part 75,
Appendix G for recommended sampling rates and methods.
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Stationary Combustion Sources Guidance
Example CO2 Calculation
A Climate Leaders Partner has an on-site natural gas boiler. The Partner does not meter the gas that enters the
boiler directly. However, the Partner 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:
Month
January
February
March
April
May
June
July
August
September
October
November
December
Total
Amount of Gas Purchased
(scf)
550,000
580,000
530,000
480,000
500,000
490,000
510,000
390,000
480,000
540,000
490,000
460,000
6,000,000
Heat Content
(Btu/scf)
1,025
1,025
1,025
1,025
1,025
1,025
1,025
1,025
1,025
1,025
1,025
1,025
Amount of Gas Purchased
(therms)
5,637.5
5,945
5,432.5
4,920
5,125
5,022.5
5,227.5
3,997.5
4,920
5,535
5,022.5
4,715
61,500
Note: scf = standard cubic feet, 1 therm = 100,000 Btu
Steps 1 & 2 are combined in that the fuel supplier has already converted fuel use into energy units based on a
fuel specific heating value as shown in the table above.
Step 3 calls for estimating the amount of carbon in the fuel consumed. The default factor provided in Appendix
B is used for this calculation.
Default factor = 14.47 (kg Carbon/mmBtu)
Converting the annual gas data: 61,500 therms x 0.1 mmBtu/therm = 6,150 mmBtu
Multiply by the default carbon content coefficient: 6,150 mmBtu x 14.47 kg C/mmBtu = 88,990.5 kg C
Step 4 is to account for the small portion of carbon in the fuel that is not oxidized. The default factor provided
in Appendix B is used, which equals 1.00. The result of Step 4 is the amount of carbon in the fuel that is oxi-
dized into C02.
Multiply the result of Step 3 by the carbon oxidation factor: 88,990.5 kg C x 1.00 = 88,990.5 kg C
Step 5 multiplies the amount of carbon released by the molecular weight ratio of C02 to carbon (44/12), in order
to calculate the mass of C02 emissions.
88,990.5 kg C x (44/12) kg C02/kg C = 326,298.5 kg C02
OR
326 metric tons of C02 emissions for the reporting year in question.
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Stationary Combustion Sources Guidance
Step 4: Estimate carbon emitted. When fuel is cent unless specific supplier information is
burned, most of the carbon is eventually available.
oxidized to C02 and emitted to the atmos-
phere. To account for the small fraction that SteP 5: Convert to CO2 emitted. To obtain
is not oxidized and remains trapped in the total C02 emitted> multiP!y carbon emis-
ash, multiply the carbon content by the sions by the molecular weight ratio of C02
fraction of carbon oxidized. The amount of (m'w- 44) to carbon (m'w- 12) (44/12>
carbon oxidized is assumed to be 100 per-
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Methods for Estimating CH4 and
N2O Emissions
The basic calculation procedure for esti-
mating CH4 and N20 emissions from
stationary combustion is represented
by Equation 2.
Equation 2: Estimation
Method for CH4 and N2O
Emissions
= As x EFps
where,
p = Pollutant (CH4 or N20)
s = Source Category
A = Activity Level
EF = Emission Factor
For both pollutants, the source category varies
depending on the level of detail attained in
analyzing fuel use data. As mentioned, CH4 and
N20 emissions depend not only on the fuel
characteristics but also on the combustion
technology type, combustion characteristics,
and control technologies. At the lowest level of
detail, emissions can be calculated by knowing
the type of fuel. A more detailed approach
would use fuel type and sector (utilities,
industrial use, etc.). At the highest level of
detail, calculations would use information on
fuel type and specific type of combustion
equipment.
Appendix A provides a set of default factors for
calculating CH4 and N20 emissions from sta-
tionary combustion sources. The default fac-
tors provided are in terms of fuel type and by
sector of where the fuel is consumed. It is rec-
ommended that these factors be used primarily
as a screening approach to determine the mag-
nitude of CH4 and N20 emissions in relation-
ship to C02 emissions from stationary combus-
tion. If it is determined that CH4 and N20 are a
significant source of GHG emissions from sta-
tionary combustion, it is recommended that
the Partner look into more specific emissions
factors. Appendix A lists several sources where
more specific emission factors can be found.
The activity level used to estimate emissions of
CH4 and N20 depends on the type of emission
factor used and could be in terms of fuel input
(mass, volume, or energy) to a source catego-
ry. The default factors provided in Appendix A
are in terms of emissions per fuel energy input
to a category of fuel use. Fuel energy input
data is often tracked as part of determining
C02 emissions from stationary combustion
sources and can also be used to estimate CH4
and N20 emissions with the factors provided in
Appendix A.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Example CH4 and N2O Calculation
From the previous example, a Partner uses 6,150 mmBtu of natural gas per year. The emissions
factors from Appendix A can be applied to estimate emissions of CH4 and N20. Appendix A lists
several different emissions factors for different fuels and different end-use sectors, the industrial
end-use sector for natural gas fuel is chosen to best represent this example.
For CH4, 6,150 mmBtu x 4.75 g CH4/mmBtu = 29,213 g or 29.2 kg of CH4 emissions
For N20, 6,150 mmBtu x 0.095 g N20/mmBtu = 584 g or 0.584 kg of N20 emissions
Global Warming Potentials (GWPs) of 21 and 310 can then be applied to the CH4 and N20 emis-
sions respectively. See Chapter 6 of the Climate Leaders Design Principles for more discussion on
GWPs. These emissions can then be compared to the C02 emissions from the same source as cal-
culated in the previous example.
29.2 kg of CH4 x 21 = 613 kg or 0.613 metric tons of C02-equivalent emissions
0.584 kg of N20 x 310 = 181 kg or 0.181 metric tons of C02-equivalent emissions
Therefore, the total C02-equivalent emissions for natural gas stationary combustion of the
reporting entity, including the C02 emissions from the previous example = 326 metric tons.
The contribution of CH4 and N20 emissions combined is less than 0.25% of the total GHG emis-
sions. The Partner includes this estimate of CH4 and N20 emissions in their inventory and does
not need to consider any further detail of CH4 and N20 emission factors (e.g., by specific combus-
tion device).
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Choice of Method for
Calculating CO2 Emissions
Partners reporting C02 emissions data to
the U.S. EPA under Title IV of the Clean
Air Act, primarily electricity generating
units, can report the same emissions data to the
Climate Leaders program. The C02 emissions
can be determined using any of the methods
outlined in 40 CFR Part 75 (e.g. CEMS or fuel
analysis approach). If the C02 data is deemed to
be quality assured and is accepted to satisfy a
Partners Title IV requirements then this data
should be reported as part of their GHG inven-
tory under the Climate Leaders program.
For Partners not currently reporting C02 data
to the U.S. EPA under Title IV of the Clean Air
Act, the choice of method depends on data
availability. If a CEMS is installed or if the fuel
characteristic data is available from sampling,
the Partner may use the fuel analysis methods
outlined in 40 CFR Part 75 (Appendix G) to cal-
culate C02 emissions and report this data to
Climate Leaders. If there is not CEMS or sam-
pling data available that will allow the fuel
analysis methods outlined in 40 CFR Part 75 to
be used, the Partner should use the default fuel
analysis methods outlined in this guidance. C02
emissions data from CEMS other than those
used to report under Title IV of the Clean Air
Act, or from other generally accepted C02 esti-
mation protocols for stationary sources may be
accepted by Climate Leaders as part of a
Partners GHG inventory. See Chapter 6 of the
Climate Leaders Design Principles for acceptance
of data from procedures not specifically provid-
ed under the Climate Leaders GHG Inventory
Protocol Core Module guidance documents.
i o
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Stationary Combustion Sources Guidance
Choice of Activity Data and
Emission Calculation Factors
This section discusses choices of activi-
ty data and factors used for calculating
C02 emissions with the default fuel
analysis approach provided in Section 2.2. This
guidance has been structured to accommodate
a wide range of Partners with varying levels of
information, and measurements in various
units. If the Partner has a CEMS installed or
has carbon content data based on fuel sam-
pling information, they should refer to guid-
ance in 40 CFR Part 75 to calculate C02 emis-
sions. In the case of those with more than one
exhaust stack, such as those with a heat recov-
ery system generator (HRSG) or duct burner, a
CEMS may not account for all combustion
emissions.
5.1. Activity Data
Source
When calculating C02 emissions with the fuel
analysis approach, the first piece of informa-
tion that needs to be determined is the quanti-
ty of fuel combusted. One method of determin-
ing the amount of fuel combusted at a facility
is to measure the fuel input into each combus-
tion 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 diesel, or the weight of fuel
combusted, such as coal feed belt scales. If fuel
use data is not directly measured then fuel pur-
chase records can be used to estimate the
amount of fuel combusted.
There are several factors that could lead to dif-
ferences between the amount of fuel purchased
and the amount of fuel combusted during a
reporting period, for example:
Changes in fuel storage inventory
Fugitive releases or spills of fuel
Fuel used as feedstock
For changes in fuel storage inventory, Equation
3 can be used to convert fuel purchase data to
estimates of actual fuel use:
Equation 3: 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
Fuel purchase data is 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 loss-
es before it actually reaches the combustion
device. These losses are particularly important
for natural gas, which could be lost due to fugi-
tive releases from facility valves and 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 feed-
stock for products produced by the reporting
entity. In this case the carbon in the fuel would
be stored in the product as opposed to being
released through combustion. Climate Leaders
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Stationary Combustion Sources Guidance
Partners are only responsible for direct emis-
sions at their facilities, if carbon leaves the
facility stored in a product it should not be
counted as a release even if the product is sub-
sequently burned or otherwise releases the
stored carbon. Therefore, Partners should sub-
tract any amount of fuel that is used as feed-
stock from the amount of fuel purchased before
calculating emissions.
5.2. Activity Data Units
Fuel is metered in terms of physical units (i.e.,
mass or volume) and it is recommended that
Partners track fuel use in terms of these physi-
cal units as they represent the primary measure-
ment data. However, Partners that do not direct-
ly measure how much fuel they use need to rely
on data from fuel suppliers. Furthermore, fuel
purchasers are mostly interested in the amount
of fuel they purchase in terms of energy units
and may not obtain data on the physical quanti-
ties of fuel used. Therefore, it is recommended
that Partners obtain data on the physical quan-
tities of fuel purchased as well as the heating
values used to convert these physical quantities
into energy values from fuel suppliers. It is also
recommended that Partners use fuel supplier or
analysis heating values over the default heating
values listed in Appendix B to convert fuel use
in physical units into energy units, as these val-
ues should better represent the characteristics
of the specific fuel consumed. It is also good
practice to track these heating values and indi-
cate if they are variable, updated over time, etc.
It is possible that Partners may only know the
dollar amount spent on a type of fuel, however,
this is the least accurate method of determining
fuel use and is not recommended for Climate
Leaders reporting. If dollar amount spent on fuel
is the only information available, it is recom-
mended that Partners contact their fuel supplier
to get more information. If absolutely no other
information is available, Partners should be
very clear on how price data is converted to
physical or energy units. Price varies widely for
a specific fuel, especially over the spatial and
time frames typically established for reporting
C02 emissions (e.g., entity wide reporting on an
annual basis for Climate Leaders).
The approaches for measuring or recording the
amount of fuel used are listed in order of prefer-
ence below.
1. Partner has fuel quantity purchased data by
fuel type in terms of physical units either
measured on site or provided from supplier
with accurate data on heat content of the
specific fuel as determined by the fuel sup-
plier or through measurement or testing.
2. Partner has data on the physical quantity of
fuel purchased but not the heat content so
the Partner must apply default fuel heat con-
tent values.
3. Partner only has data on dollar amount of
fuels purchased and has to convert to physi-
cal quantity based on dividing total expendi-
tures by average prices, and the Partner
must apply default fuel heat content values.
5.3. Emission
Calculation Factors
Once the amount of fuel combusted is deter-
mined, the next step in calculating C02 emis-
sions is to determine how much carbon is in the
fuel. 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
1 2
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
the fuel. The most accurate method to deter-
mine a fuel's carbon content data is through
chemical analysis of the fuel. This data may be
obtained directly from the fuel supplier. If the
specific carbon content of a fuel is not meas-
ured, default values could be used. Default val-
ues for the carbon content of fuels are available
by physical units (e.g., percent carbon and by
weight or volume), however these values vary
widely by region of the country, time of year,
fuel supplier, etc.
Fuel heat content data can be obtained from
sampling and analysis or from the fuel supplier.
Fuel suppliers often provide the heating value of
a fuel with mass/volume measurements. Fuel
purchasers are interested in the energy content
of fuels purchased as it better represents the
use of the fuel as opposed to mass or volume
(fuel pricing is often based on energy, not physi-
cal units). Fuel heat content factors can be used
to convert fuel use data in terms of physical
units to fuel use data in terms of energy units as
described in Section 5.2.
The Climate Leaders default fuel analysis
approach for calculating C02 emissions from
stationary combustion sources is based on a
carbon factor per unit of fuel energy as shown
in Section 2.2. Default values for fuel carbon
content per energy units are provided in
Appendix B. These carbon content factors per
energy units are less variable than carbon con-
tent factors per physical units because the heat
content or energy value of a fuel is more closely
related to the amount of carbon in the fuel than
to the total physical quantity of fuel.6
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. Due to the variability and non-standard-
ized nature of waste fuels, some guidance and
sources of information on determining carbon
content factors for waste fuels are provided in
Appendix B, but the preferred approach is that
Partners use factors specific to the waste fuels
used.
A fuel's carbon content is never fully oxidized
into C02 emissions through combustion. A por-
tion of the carbon remains in the form of ash or
unburned carbon. Consequently, it is necessary
to use an oxidation factor when calculating C02
emissions from stationary combustion sources.
Default oxidation factors to account for
unburned carbon can be found in Appendix B.
However, it is recommended that Partners use
their own oxidation factors, if available, to bet-
ter represent the fuel properties and the com-
bustion device's operating characteristics. It is
important to note that there are also intermedi-
ate combustion products from stationary com-
bustion sources such as carbon monoxide (CO)
and hydrocarbons that may eventually get oxi-
dized into C02 in the atmosphere. The carbon
oxidation factor does not account for carbon in
these intermediate combustion products, but
only the amount of carbon that remains as ash,
soot or particulate matter.
After calculating a fuel's oxidized carbon con-
tent it is necessary to convert carbon into C02
emissions. A fuel's oxidized carbon is convert-
ed into C02 emissions by multiplying the car-
bon emissions by the molecular weight ratio of
6 This relative accuracy is only true if the specific fuel heating value is known. If the default heating value is used to convert fuel use
in terms of mass or volume to energy then the same result for carbon in the fuel would be derived from using default carbon con-
tent per mass or volume and carbon content per unit of energy.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Example: Determining an Emission Factor for a Gas Waste
Stream
A Climate Leaders Partner has a thermal oxidizer destroying a waste gas stream of different com-
ponents. The Partner has data on volume of gas combusted and on the mole fraction of the dif-
ferent 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 is based on the assumed temperature and pressure of the gas. Assuming conditions of 1 atm
and 25° C, there are 2.55 x 10~3 Ibmole of gas per cubic foot of gas. This factor could be adjusted to
meet the specific temperature and pressure conditions of the Partner's waste gas stream. An emis-
sion factor is then determined per cubic feet of gas based on the following Equation EX-1:
Equation EX-1: Determining Emission Factor for Gas Waste Stream
7ib.cS ^
Emission Factor I , 3 I = 2-i MFj x Moles x m.w. x
where:
.j
1=1
(Ibmole i "\
Moles J
(Ibmole "\
fp)
(... » '
Ibmole i J
f Ib.C "\
CFj = Carbon Fraction of Gas Component i I rrp~ I
The following Table EX-1 shows an example gas waste stream with the mole fractions of different
components.
Table EX-1: Example Gas Waste Stream
Gas Component
C02
CH4
C3H8
C6H6
Other non-C
Total
Mole %
5%
30%
20%
35%
10%
100%
Ibmole
1.28 x ID4
7.66 x 10-4
5.10 x lO4
8.93 x lO4
2.55 x lO4
2.55 x 10-3
m.w.
44
16
44
78
?
%C
27%
75%
82%
92%
0%
Ib.C
0.001531
0.009188
0.018376
0.064315
0
0.093409
Based on Table EX-1 it can be seen that the emission factor for this example gas waste stream is
0.0934 lb. C per ft3 of waste gas. This emission factor can be used in conjunction with the total
amount of gas combusted as well as an oxidation factor and converted to C02 in order to obtain
total emissions from waste gas combustion.
14 CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
C02 to carbon (44/12). Whenever possible, cus- heat content of the fuel and the fraction car-
tomized factors for heating values, carbon con-
tent, and fraction of carbon oxidized for each
fuel type should be used. Otherwise, default
emission factors are provided in Appendix B.
Appendix B provides default factors for heating
value, carbon content in terms of amount of
carbon per energy value of fuel, and fraction of
carbon oxidized for different fuels. Other
sources of C02 emissions factors sometimes
combine the different fuel and combustion ele-
ments into one emission factor value. For
example, if the carbon content of the fuel is
combined with the carbon oxidation factor and
the carbon to C02 ratio, a C02 emission factor
can be obtained in terms of mass of C02 per
unit of fuel energy. Furthermore, if the carbon
content factor is combined with the default
bon oxidized as well as the carbon to C02
ratio, a C02 emission factor can be obtained in
terms of mass of C02 per mass or volume unit
of fuel.
If one of these alternate emissions factors is
used, care should be taken to determine the
source of the data and what it represents (e.g.,
published factors may assume a carbon oxida-
tion factor other than 100%). Values are provid-
ed in Appendix B for C02 emission factors in
terms of energy and mass/volume fuel units.
These were created based on the Climate
Leaders default values provided for heating
value, carbon content in terms of amount of
carbon per energy value of fuel, and fraction of
carbon oxidized for different fuels.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Example: Measuring Fuel Use in Energy Units Lower and
Higher Heating Values
When measuring fuel use data in energy units, it is important to distinguish between lower heat-
ing values (LHV) and higher heating values (HHV) (also called net and gross calorific values
respectively). Heating values describe the amount of energy released when a fuel is burned com-
pletely, and LHVs and HHVs are different methods to measure the amount of energy released.7 A
given fuel, therefore, always has two heating value numbers, a LHV and a HHV number. Whereas
HHVs are typically used in the U.S. and in Canada, other countries use LHVs. 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.
For example, natural gas has a LHV of 924 Btu/standard cubic foot (scf) and a HHV of 1,027
Btu/scf. When calculating C02 emissions by multiplying fuel use data in energy units by a carbon
content coefficient, it is important to be mindful of LHV or HHV specific coefficients in the emis-
sions calculation. The LHV specific carbon content coefficient for natural gas is 16.08 kg
C/mmBtu and the HHV specific carbon content coefficient is 14.47 kg C/mmBtu.
Therefore, to calculate C02 emissions from burning 1 million scf of natural gas:
Based on LHV:
924 Btu 1 mmBtu 16.08 kg C 44 kg CO,
Ixl06scfx x - x ^ x . =54,479 kg C02
Based on HHV:
Ixl06scfx
scf
1,027 Btu
scf
1 x 106 Btu
mmBtu
12kgC
1 mmBtu 14.47 kg C 44 kg C02
1 x 106 Btu
mmBtu
12kgC
= 54,489 kg C02
1 6
7 The heating value is dependent on the phase of water/steam in the combustion process. Higher heating value is the heat evolved
when all of the products of combustion are cooled to atmospheric temperature and pressure. The lower heating value is the heat
evolved when the products of combustion are cooled so that water remains as a gas. HHVs are around 105% of LHVs; for natural
gas, the factor is 110%.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Completeness
In order for a Partner's GHG corporate
inventory to be complete it must include
all emission sources within the company's
chosen inventory boundaries. See Chapter 3 of
the Climate Leaders Design Principles for
detailed guidance on setting organizational
boundaries and Chapter 4 of the Climate
Leaders Design Principles for detailed guidance
on setting operational boundaries of the corpo-
rate inventory.
On an organizational level the inventory should
include emissions from all applicable facilities
or fleets of vehicles. Completeness of corpo-
rate wide emissions can be checked by com-
paring the list of sources included in the GHG
emissions inventory with those included in
other emission's inventories, environmental
reporting, financial reporting, etc.
At the operational level, a Partner should
include all GHG emissions from the sources
included in their corporate inventory. Possible
GHG emission sources are stationary fuel com-
bustion, combustion of fuels in mobile sources,
purchases of electricity, HFC emissions from
air conditioning equipment and process or
fugitive related emissions. Partners should
refer to this guidance document for calculating
emissions from stationary combustion sources
and to the Climate Leaders Core Guidance doc-
uments for calculating emissions from other
sources.
Operational completeness of stationary com-
bustion sources can be checked by comparing
the sources included in the GHG inventory
with those reported under regulatory pro-
grams (e.g., Title V air permit), or in annual
fuel use surveys. Examples of typical types of
fuel combustion sources that should be includ-
ed 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 Climate
Leaders Design Principles, there is no materiali-
ty threshold set for reporting emissions. The
materiality of a source can only be established
after it has been assessed. This does not nec-
essarily require a rigorous quantification of all
sources, but at a minimum, an estimate based
on available data should be developed for all
sources.
The inventory should also accurately reflect
the timeframe of the report. In the case of
Climate Leaders, the emissions inventory is
reported annually and should represent a full
year of emissions data.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Uncertainty Assessment
There is uncertainty associated with all
methods of calculating C02, CH4, and
N20 emissions from stationary combus-
tion sources. As outlined in Chapter 7 of the
Climate Leaders Design Principles, Climate
Leaders does not require Partners to quantify
uncertainty as +/- % of emissions estimates or
in terms of data quality indicators.
It is recommended that Partners attempt to
identify the areas of uncertainty in their emis-
sions estimates and make an effort to use the
most accurate data possible. If the CEMS
approach is used to estimate emissions, it is
recommended that the Partner follow the
QA/QC guidance and good practices associated
with that method as outlined in the Acid Rain
Program Rule8. Entities utilizing CEMS to com-
ply with Clean Air Act regulations are required
to develop a quality assurance plan. This plan
should address C02 emissions measurement.
The accuracy of estimating emissions from fos-
sil fuel combustion in stationary sources from
the fuel analysis approach is partially deter-
mined 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 pur-
chased should also be an accurate representa-
tion of fuel combusted, given that any neces-
sary adjustments are made for changes in fuel
inventory, fuel used as feedstock, etc. However,
uncertainty may arise if only dollar value of
fuels purchased is used to estimate fuel con-
sumption.
The accuracy of estimating emissions from sta-
tionary combustion sources with the fuel
analysis approach 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 exam-
ple, carbon content factors for coal vary great-
ly, depending on its characteristics, chemical
properties, and annual fluctuations in the fuel
quality. Therefore, using the U.S. default car-
bon content coefficient for coal may result in a
more uncertain estimate than for other fuels if
the local fuel supplies do not match the default
fuel characteristics.
1 8
8 Part 75.21 and Appendix B of the regulation discuss the QA/QC plan.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Reporting and Documentation
Partners are required to complete the
Climate Leaders Reporting
Requirements and report annual corpo-
rate level emissions. In order to ensure that
estimates 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 be reported in the Partner's Inventory
Management Plan (IMP).
For both the CEMS and fuel analysis approach-
es, it is recommended that Partners measure
the C02 emissions and supporting data by
facility (as opposed to aggregated entity wide
emissions only). This method increases the
accuracy and credibility of the inventory.
Table 1: Documentation Sources for Stationary Combustion
Data Documentation Source
Fuel consumption data9
Heat contents and emission
factors used other than
defaults provided
Prices used to convert dollars of
fuel purchased to amount or
energy content of fuel consumed
All assumptions made in estimating
fuel consumption, heat contents,
and emission factors
Purchase receipts, delivery receipts, contract purchase or
firm purchase records, stock inventory documentation,
metered fuel documentation
Purchase receipts; delivery receipts; contract purchase or
firm purchase records; EIA, EPA or industry reports
Purchase receipts; delivery receipts; contract purchase or
firm purchase records; EIA, EPA or industry reports
All applicable sources
9 If purchase receipts, delivery receipts, etc. are used to proxy fuel consumption data then feedstock use has to be taken into
account; otherwise, there is an overestimation of emissions.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Inventory Quality Assurance and
Quality Control
Chapter 7 of the Climate Leaders Design
Principles provides general guidelines
for implementing a QA/QC process for
all emission estimates. For stationary combus-
tion sources, activity data and emission factors
can be verified using a variety of approaches:
Fuel consumption data by source or facili-
ty 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 Department of Energy or
other EPA reports or surveys.
If emission estimates were obtained from
CEMS, this data can be compared to emis-
sions estimated using the fuel analysis
approach.
If any emission factors were calculated or
obtained from the fuel supplier, these fac-
tors can be compared to U.S. average emis-
sion factors.
The rate at which suppliers change/update
heating values can be examined to approxi-
mate accuracy.
Depending on the end-use, some non-energy
uses of fossil fuels, such as for manufactur-
ing plant feedstocks, can result in long term
storage of some or all of the carbon con-
tained in the fuel. This guidance addresses
fuels 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 cal-
culate site-specific emissions factors, or
emissions.
2O
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Stationary Combustion Sources Guidance
Appendix A: Calculating CH4
and N2O Emissions from
Stationary
As mentioned earlier, CH4 and N20
emissions depend not only on fuel
characteristics but also on technolo-
gy type, combustion characteristics and con-
trol technology. The emission factors provided
in Table A-l are those used by the U.S. EPA
when calculating the national GHG inventory10
and are the emission factors recommended by
the Intergovernmental Panel on Climate
Change (IPCC) 2006 Guidelines11. The emission
factors for pulping liquors are from the
National Council for Air and Stream
Improvement, Inc.12 The emission factors were
converted from g/GJ to g/mmBtu based on the
Table A-1: CH4 and N2O Emission Factors by Fuel Type and
Sector
Fuel/End-Use Sector
CH4
(g/GJ-HHV)
N2O CH4
(g/GJ-HHV) (g/mmBtu)
N2O
(g/mmBtu)
Coal
- Residential
- Commercial
- Industry
- Electricity Generation
Petroleum
- Residential
- Commercial
- Industry
- Electricity Generation
Natural Gas
- Residential
- Commercial
- Industry
- Electricity Generation
Wood
- Residential
- Commercial
- Industry
- Electricity Generation
Pulping Liquors
- Industry
300
10
10
1
10
10
3
3
5
5
1
1
300
300
30
30
2.4
1.5
1.5
1.5
1.5
0.6
0.6
0.6
0.6
0.1
0.1
0.1
0.1
4
4
4
4
1.9
316
11
11
1
11
11
3
3
5
5
1
1
316
316
32
32
2.5
1.6
1.6
1.6
1.6
0.6
0.6
0.6
0.6
0.1
0.1
0.1
0.1
4.2
4.2
4.2
4.2
2.0
10 U.S. Environmental Protection Agency 2007. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 - 2005. EPA 430-R-07-002.
11 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.
12 National Council for Air and Stream Improvement, Inc. (NCASI), 2004 Calculation Tools for Estimating Greenhouse Gas Emissions
from Pulp and Paper Mills. Version 1.1, Research Triangle Park, NC.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
2 1
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Stationary Combustion Sources Guidance
conversion factor of 0.95 mmBtu/GJ to be more
consistent with other factors presented in
these guidelines.
The factors provided in Table A-l represent
emissions in terms of fuel type and end-use
sectors (i.e., residential, commercial, industrial,
electricity generation). Other references,
including those listed below, are emission fac-
tors by more specific combustion technology
type (e.g., natural gas industrial boilers >293
MW). These references are recommended for
Partners interested in performing a more accu-
rate estimate of CH4 and N20 emissions.
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, 2002 & 2003, AP-42,
U.S. EPA Office of Air Quality Planning and
Standards, Research Triangle Park, North
Carolina.
State and Territorial Air Pollution Program
Administrators and the Association of Local
Air Pollution Control Officials
(STAPPA/ALAPCO) and the U.S. EPA.
Emissions Inventory Improvement Program
(EIIP) Vol. VIII, Chapter 2, Methods For
Estimating Methane And Nitrous Oxide
Emissions From Stationary Combustion,
August 2004.
22
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Stationary Combustion Sources Guidance
Appendix B: Default Factors for
Calculating CO2 Emissions
This appendix contains default factors
for use in calculating C02 emissions
from the fuel analysis approach
described by in Section 2.2 of this document.
Table B-l contains default Heat Contents,
Carbon Content Coefficients, and Fraction of
Carbon Oxidized for different fossil fuels to be
used in this approach.
Table B-1: Default Factors for Calculating CO2 Emissions
from Fossil Fuel Combustion
Fossil Fuel
Heat Content (HHV)
Carbon Content
Coefficients
Fraction Oxidized
Coal and Coke
Anthracite Coal
Bituminous Coal
Sub-bituminous Coal
Lignite
Unspecified (industrial coking)
Unspecified (industrial other)
Unspecified (electric utility)
(mmBtu/ton)
25.09
24.93
17.25
14.21
26.27
22.05
19.95
Unspecified (residential/commercial) 22.05
Coke
Natural Gas
Natural Gas
Petroleum
Distillate Fuel Oil (#1, 2, & 4)
Residual Fuel Oil (#5 & 6)
Kerosene
Petroleum Coke
LPG (average for fuel use)
Common LPG Components:
Ethane
Propane
Isobutane
n-Butane
Waste Tires
Waste Tires
24.80
(Btu/scf)
1,029
(mmBtu/Barrel)
5.8250
6.2870
5.6700
6.0240
3.8492
2.9160
3.8240
4.1620
4.3280
(mmBtu/ton)
28.00
(kg C/mmBtu)
28.26
25.49
26.48
26.30
25.56
25.63
25.76
26.00
31.00
(kg C/mmBtu)
14.47
(kg C/mmBtu)
19.95
21.49
19.72
27.85
17.23
16.25
17.20
17.75
17.72
(kg C/mmBtu)
30.77
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
Note:
Values for fuels may change over time so it is recommended that Partners update factors on a regular basis. Factors shown here are
appropriate for years 2000-2005.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Sources:
CoalCarbon Content Coefficients from the
Documentation for Emissions of Greenhouse
Gases in the United States 2005, DOE/EIA-
0573(2005), Energy Information Administration,
Office of Integrated Analysis and Forecasting,
U.S. Department of Energy, November 2006.
Heat Contents calculated by EPA based on the
same approach used to determine Carbon
Content Coefficients. The approach utilizes
coal physical characteristics from the CoalQual
Database Version 2.0, U.S. Geological Survey,
1998, and coal production data from the Annual
Coal Report 2005, U.S. Department of Energy,
Energy Information Administration, Washington
DC. As well as coal heat content information
from the Annual Energy Review 2006, U.S.
Department of Energy, Energy Information
Administration, Washington, DC. Fractions
Oxidized from the Inventory of U.S. Greenhouse
Gas Emissions and Sinks: 1990-2005, EPA430-R-
07-002, U.S. EPA, Washington, DC, April 2007.
CokeHeat Content from the Annual Energy
Review 2006, U.S. Department of Energy,
Energy Information Administration,
Washington, DC. Carbon Content Coefficient
and Fraction Oxidized from the Inventory of
U.S. Greenhouse Gas Emissions and Sinks:
1990-2005, EPA430-R-07-002, U.S. EPA,
Washington, DC, April 2007.
Natural Gas and Petroleum (except LPG)
Heat Contents from the Annual Energy Review
2006, U.S. Department of Energy, Energy
Information Administration, Washington, DC.
Carbon Content Coefficients and Fractions
Oxidized from the Inventory of U.S. Greenhouse
Gas Emissions and Sinks: 1990-2005, EPA430-R-
07-002, U.S. EPA, Washington, DC, April 2007.
LPGCarbon Content Coefficients for LPG
components from the Inventory of U.S.
Greenhouse Gas Emissions and Sinks:
1990-2005, EPA430-R-07-002, U.S. EPA,
Washington, DC, April 2007. Carbon Content
Coefficient value for LPG from Annual Energy
Review 2006, U.S. Department of Energy,
Energy Information Administration,
Washington, DC. Heat Content value for LPG
and its components from the Inventory of U.S.
Greenhouse Gas Emissions and Sinks:
1990-2005. EPA430-R-07-002, U.S. EPA,
Washington, DC, April 2007. Fractions Oxidized
also from the EPA inventory report. The
Fractions Oxidized for LPG components are
assumed to be the same as for LPG.
If a partner knows the specific blend of LPG
that they are using, heat content and carbon
content coefficients for different blends of LPG
can be calculated based on the percent mix
and individual component characteristics
shown in Table B-l.
Table B-2 contains default Heat Contents,
Carbon Content Coefficients, and Fraction of
Carbon Oxidized for different non-fossil fuels to
be used in the fuel analysis approach.
24
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Stationary Combustion Sources Guidance
Table B-2: Default Factors for Calculating CO2 Emissions
from Non-Fossil Fuel Combustion
Non-Fossil Fuel
Heat Content (HHV) Carbon Content Fraction Oxidized
Coefficients
Solid
(mmBtu/ton)
Wood and Wood Waste (12% moisture) 15.38
Kraft Black Liquor
(North American hardwood)
Kraft Black Liquor
(North American softwood)
Gas
Landfill Gas (50% CH4/50% C02)
Wastewater Treatment Biogas
11.98
12.24
(Btu/scf)
502.50
varies
(kg C/mmBtu)
25.60
25.75
25.95
14.20
14.20
1.0
1.0
1.0
1.0
1.0
Sources:
Wood and Wood WasteHeat Content and
Carbon Content Coefficient from Inventory of
U.S. Greenhouse Gas Emissions and Sinks:
1990-2005, EPA 430-R-07-002, U.S.
Environmental Protection Agency, Washington,
DC April 2007. Chapter 3 text describing the
methodology used to calculate emissions from
Wood Biomass and Ethanol Consumption. Heat
Content is assumed to be representative of
wood and wood waste used in the industrial
sector. Carbon Content Coefficient calculated
from the value listed, 434 kg C/metric ton, and
the assumed heat content. Fraction Oxidized
also from the EPA inventory report and
assumed to be the same as for coal combus-
tion. The factors presented in Table B-2 repre-
sent emissions from wood combustion only
and do not include any emissions or sinks from
wood growth or harvesting.
GasHeat Content for landfill gas based on
heat content of methane, 1,005 Btu/standard
ft3, and assumed landfill gas composition of
50% CH4 and 50% C02 by volume. Heat Content
for wastewater treatment gas can be calculated
based on methane heat content and percent
methane in the gas. Carbon Content
Coefficients represent pure methane. Fraction
Oxidized from the Inventory of U.S. Greenhouse
Gas Emissions and Sinks: 1990-2005. EPA430-R-
07-002, U.S. EPA, Washington, DC, April 2007
and assumed to be the same as for natural gas.
Kraft Black LiquorBlack liquor default emis-
sion factors based on the carbon content of
the liquors and include any carbon exiting with
smelt from a recovery furnace. Therefore, for
kraft mills, the liquor emission factors estimate
biomass carbon emissions from both the
recovery furnace and from the lime kiln. The
emission factors from International Council of
CLIMATE LEADERS GHG INVENTORY PROTOCOL
25
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Stationary Combustion Sources Guidance
Forest and Paper Associations (ICFPA) and the
National Council for Air and Stream
Improvement (NCASI) spreadsheets for calculat-
ing GHG emissions from pulp and paper manu-
facturing (Version 1.2). (The ICFPA/NCASI tool
assumes a 1% correction for unoxidized car-
bon, the emission factors in this guidance doc-
ument assume 100% of the carbon is oxidized).
Black liquor data for the ICFPA/NCASI tool were
obtained from: Chapter 1-Chemical Recovery,
by Esa Vakkilainen, 1999. In: Papermaking
Science and Technology, Book 6B: Chemical
Pulping. Gullichsen, J., and Paulapuro, H.
(eds.). Helsinki, Finland: Fapet Oy.
Waste TiresHeat content for waste tires from
Rubber Manufacturers Association (RMA), Scrap
Tire Markets in the United States, November
2006. The carbon content for waste tires from
the Inventory of U.S. Greenhouse Gas Emissions
andSkinks: 1990-2005. EPA430-R-07-002, U.S.
EPA, Washington, DC, April 2007.
26
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
CO2 Emissions Factors
Based on Fuel Energy
Sources of C02 emissions factors sometimes
combine the different fuel and combustion ele-
ments into one emission factor value. For
example, if the carbon content of the fuel is
combined with the carbon oxidation factor and
the carbon to C02 ratio, a C02 emission factor
can be obtained in terms of mass of C02 per
unit of fuel energy.
Therefore, the default factors shown in Tables B-
1 and B-2 can be combined (with the C02/C ratio
of 44/12) to determine emission factors in terms
of mass of C02 per unit of fuel energy. Table B-3
contains default heat content and emission fac-
tors for different fossil fuels and Table B-4 con-
tains default heat content and emission factors
for different non-fossil fuels as calculated from
the default factors listed previously.
Table B-3: CO2 Emission Factors (mass CO2/fuel energy) for
Fossil Fuel Combustion
Fossil Fuel Heat Content (HHV)
Coal and Coke
Anthracite Coal
Bituminous Coal
Sub-bituminous Coal
Lignite
Unspecified (industrial coking)
Unspecified (industrial other)
Unspecified (electric utility)
Unspecified (residential/commercial)
Coke
Natural Gas
Natural Gas
(mmBtu/ton)
25.09
24.93
17.25
14.21
26.27
22.05
19.95
22.05
24.80
(Btu/scf)
1,029
CO2 Content Coefficient
(kg C02/mmBtu)
103.62
93.46
97.09
96.43
93.72
93.98
94.45
95.33
113.67
(kg C02/mmBtu)
53.06
Petroleum
Distillate Fuel Oil (#1, 2, & 4)
Residual Fuel Oil (#5 & 6)
Kerosene
Petroleum Coke
LPG (average for fuel use)
Common LPG Components:
(mmBtu/Barrel)
5.8250
6.2870
5.6700
6.0240
3.8492
(kg C02/mmBtu)
73.15
78.80
72.31
102.12
63.16
Ethane
Propane
Isobutane
n-Butane
Waste Tires
Waste Tires
2.9160
3.8240
4.1620
4.3280
(mmBtu/ton)
28.00
59.58
63.07
65.08
64.97
(kg C02/mmBtu)
112.84
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Table B-4: CO2 Emission Factors (mass CO2/fuel energy) for
Non-Fossil Fuel Combustion
Fossil Fuel Heat Content (HHV) CO2 Content Coeffecient
Solid (mmBtu/ton) (kg C02/mmBtu)
Wood and Wood Waste (12% moisture) 15.38 93.87
Kraft Black Liquor 11.98 94.41
(North American hardwood)
Kraft Black Liquor 12.24 95.13
(North American softwood)
Gas (Btu/scf)
Landfill Gas (50% CH4/50% C02) 502.50 52.07
Wastewater Treatment Biogas varies 52.07
28 CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
CO2 Emissions
Factors Based on Fuel
Mass or Volume
If the carbon content factor is combined with
the default heat content of the fuel, fraction
carbon oxidized, and carbon to C02 ratio, a
C02 emission factor can be obtained in terms
of mass of C02 per mass or volume unit of fuel.
Therefore, the default factors shown in Tables
B-3 and B-4 can be combined with the heat
content of the fuels to determine emission fac-
tors in terms of mass of C02 per unit of fuel
mass or volume. Table B-5 contains default
emission factors for different fossil fuels and
Table B-6 contains default emission factors for
different non-fossil fuels as calculated from the
default factors listed previously.
Table B-5: CO2 Emission Factors (mass CO2/fuel mass or
volume) for Fossil Fuel Combustion
Fossil Fuel
Emission Factor
Coal and Coke
Anthracite Coal
Bituminous Coal
Sub-bituminous Coal
Lignite
Unspecified (industrial coking)
Unspecified (industrial other)
Unspecified (electric utility)
Unspecified (residential/commercial)
Coke
Natural Gas
Natural Gas
Petroleum
Distillate Fuel Oil (#1, 2, & 4)
Residual Fuel Oil (#5 & 6)
Kerosene
Petroleum Coke
LPG (average for fuel use)
Common LPG Components:
Ethane
Propane
Isobutane
n-Butane
Waste Tires
Waste Tires
(kg C02/ton)
2,599.83
2,330.04
1,674.86
1,370.32
2,462.12
2,072.19
1,884.53
2,102.29
2,818.93
(kg C02/scf)
0.0546
(kg C02/Barrel)
426.10
495.39
409.98
615.15
243.12
173.75
241.17
270.88
281.20
(kg C02/ton)
3,159.49
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Table B-6: CO2 Emission Factors (mass CO2/fuel mass or
volume) for Non-Fossil Fuel Combustion
Fossil Fuel
Emission Factor
Solid
Wood and Wood Waste (12% moisture)
Kraft Black Liquor (North American hardwood)
Kraft Black Liquor (North American softwood)
Gas
Landfill Gas (50% CH4/50% C02)
Wastewater Treatment Biogas
(kg C02/ton)
1,443.67
1,130.76
1,164.02
0.0262
varies
3O
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Stationary Combustion Sources Guidance
Waste Fuels
Emissions from combustion of waste fuels of
both fossil and biomass origin are treated the
same as emissions of other fossil or biomass
fuels. No specific default values for carbon con-
tent of waste fuels are provided due to the vari-
ability of the different waste fuels.
The cement industry in particular is a large
user of waste fuels. Guidance developed by
that industry for calculating emissions has spe-
cific default values to calculate emissions for
different waste fuels. C02 Accounting and
Reporting Standard for the Cement Industry,
Version 2.0, June 2005, World Business Council
for Sustainable Development.
The U.S. EPA also has data on waste fuel com-
bustion that is used to calculate the National
Inventory of GHG emissions. Inventory of U.S.
Greenhouse Gas Emissions and Sinks:
1990-2005, EPA 430-R-07-002, U.S.
Environmental Protection Agency, Washington,
DC April 2007.
Annex 3, Section 3.6, of the U.S. EPA inventory
report has information on emissions from com-
bustion of Municipal Solid Waste (MSW).
Emission factors for some waste fuels can be
determined by taking the emission factor that
most closely represents the waste fuel. For
example, using the factor for fuel oil to repre-
sent waste oil combustion. In general however,
Climate Leaders encourages the use of the
most accurate methodologies. The data quality
tiers that should be used for any fuel combus-
tion in stationary sources are: (a) direct moni-
toring, (b) mass balance using actual fuel char-
acteristics data, (c) mass balance using a com-
bination of actual and default fuel characteristi-
ics data and (d) default C02 emission factors
by fuel type.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
3 1
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CLIMATEri
LEADERS,
U.S. Environmental Protection Agency
Climate Protection Partnerships Division
Office of Atmospheric Programs
U.S. Environmental Protection Agency
May 2008
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