Technical Support Document for Stationary Fuel Combustion Emissions:
Proposed Rule for Mandatory Reporting of Greenhouse Gases
Office of Air and Radiation
U.S. Environmental Protection Agency
January 30, 2009
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January 30, 2009
Table of Contents
Page
1.0 Source Category Description 1
1.1 GHG Emissions 1
1.2 GHG Emissions Sources 1
1.3 Stationary Fuel Combustion Categories Covered by this Document 3
1.4 Costs Associated with GHG Reporting Rule and Emission Thresholds 3
2.0 Review of Existing GHG Reporting Programs 3
3.0 Measurement and Quantification Methods 4
3.1 CO2 Emission Methodologies for Electric Generating Sources 5
3.1.1 Part 75 CO2 Monitoring and Reporting Overview 5
3.1.2 Part 75 CEMS 6
3.1.3 Part 75, Appendix G Mass Balance Based Calculation Methods 8
3.1.4 Low Mass Emitters 9
3.2 CO2 Emission Methodologies for Stationary Combustion 10
3.2.1 Tier 4 Methodology - CEMS 11
3.2.2 Tier 3 Methodology - Fuel Carbon Content 13
3.2.3 Tier 2 Methodology - Fuel Heat Content 14
3.2.4 Tier 1 Methodology - Default Heat Content 15
3.2.5 CO2 Emissions from Carbonate Sorbents 15
3.3 CO2 Emissions Methodologies for Units that Burn Biomass 16
3.3.1 Biomass Fuels except for Municipal Solid Waste 17
3.3.2 Municipal Solid Waste 17
3.4 Calculating CH4 and N2O Emissions from Stationary Fuel Combustion Sources 18
3.5 Other Quantification Options Considered 19
3.5.1 Require Part 75 CO2 Emissions Quantification and Monitoring Requirements for All
Stationary Combustion Sources 19
3.5.2 Require a Tier 4 CEMS Methodology for all Non-Part 75 Solid Fuel-Burning Sources
that Have a Rated Heat Capacity Greater Than 250 Million Btus per Hour 19
3.5.3 Allow Tier 2 Methodology Calculation for All Gas and Oil Fired Sources 19
3.5.4 Provide Methodology Flexibility through Guidelines and Minimum Standards 20
3.5.5 De minimis Source Exemptions 21
4.0 Substitute Data Procedures 21
4.1 Part 75 Missing Data 21
4.2 Other Stationary Combustion Units 22
4.3 Other Missing Data Options 23
5.0 Quality Assurance/Quality Control 23
5.1 Quality Assurance for CEMS 23
5.2 Quality Assurance for Calculation Approaches 23
5.3 Monitoring Plan and QA/QC Plan 24
6.0 Types of Emissions Information to be Reported 25
6.1 Data Elements Reported Under Existing Programs 25
6.1.1 Acid Rain Program EGUs 25
6.1.2 NEI Report Formats 26
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6.1.3 Other GHG Reporting Programs 27
6.2 Proposed Reporting Elements 27
6.2.1 Consolidated Reporting of Unit Data 28
6.2.2 Verification Data 29
7.0 References 29
Appendix A A-l
Appendix B B-l
Appendix C C-l
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List of Tables and Figures
Page
Table 1: Stationary Combustion Source Sector GHG Emissions 2
Figure 1: 2006 Stationary Combustion Emissions (Percent of Total) 2
Table 2: Mandatory and Voluntary GHG Reporting Programs 3
Table 3: CO2 Measurement Methodologies in 40 CFR Part 75 5
Table 4: 2006 Mass Emissions by CO2 Measurement Methodology 6
Table 5: Required Sampling and Analysis Frequency by Fuel in 40 CFR Part 75,
Appendix G 8
Table 6: Default Factors for Part 75 Low Mass Emitters (From Part 75, Tables
I.Y1-3 and I.Y1-5) 10
Table 7: Large Unit NSPS Diluent CEMS - 40 CFR Part 60 12
Table 8: Sampling and Analysis Frequency 13
Table 9: GWP Factors - CI I , and \:0 18
Table 10: DOE 1605(b) Measurement and Estimation Method Ratings 20
Table 11: Overview of General Stationary Combustion Missing Data Values 22
Table 12: Part 75 Monitoring Plan Contents 24
Table 13: Emission Reporting Elements for all Stationary Combustion Units 28
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1.0 Source Category Description
The stationary fuel combustion source category consists of equipment that converts the
chemical energy in solid, liquid, or gaseous fuels to high temperature heat energy by oxidation.
During stationary combustion, fossil fuels, or waste fuels such as coal, oil, natural gas, refinery
gas, municipal waste, and biomass are burned to produce high temperature heat which produces
useful heat and work for use in electricity generation and industrial sources, and space heating.
Combustion can also be used to incinerate waste in order to reduce the volume of waste or
destroy chemical compounds. Stationary fuel combustion sources are located in all sectors of the
economy and include boilers, heaters, engines, furnaces, kilns, ovens, flares, incinerators, dryers,
and any other equipment or machinery that burns fuel.
1.1 GHG Emissions
The stationary combustion of carbon-based fuels produces three significant greenhouse
gases: carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O). The amount of CO2
emitted is directly related to the carbon content of the fuel. Typically, nearly 100 percent of the
fuel carbon is oxidized to CO2. The CH4 and N2O emissions from stationary combustion are
much smaller and are indirectly related to the carbon and nitrogen contents of the fuel. In the
U.S., CO2 emissions represent over 99 percent of the total COj-equivalent1 (COje) GHG
emissions from all commercial, industrial, and electricity generation stationary combustion
sources. CH4 and N2O emissions together represent less than one percent of the total COje
emissions from the same sources (U.S. EPA, 2008 - Inventory of U.S. Greenhouse Gases and
Sinks).
1.2 GHG Emissions Sources
The largest stationary combustion category from a fuel usage and GHG emissions
standpoint is electricity generation (See Table 1). The electric power industry, as illustrated
here, includes all power producers, consisting of both regulated utilities and non-utilities (e.g.,
independent power producers, qualifying cogenerators, and other small power producers) and
contributed just over 62 percent of stationary combustion GHG emissions in 2006. Stationary
combustion by industrial sources also contributes a significant portion of total GHG emissions.
CO2 emissions from industrial sources such as steel production, chemical manufacture,
petroleum refining, and pulp and paper production comprised roughly 23 percent of total GHG
emissions in 2006.
1 C02-equivalent is the equivalent global warming potential of an amount of a greenhouse gas other than C02 in
terms of CO; emissions CH , and N:0 both have higher global warming potentials than CO;. The C02e of one ton
of CH., is 21 tons, and one ton of N:0 is equivalent to 310 tons of CO;.
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January 30, 2009
Table 1
Stationary Combustion Source Sector GHG Emissions
Stationary Combustion Source
Sector
2006 C02e Emissions
(million metric tons)
Percent of Category C02e
Emissions
Electric Power
2,338.9
62.4
Industrial
866.8
23.1
Commercial
211.3
5.6
Residential
330.4
8.8
Total
3747.4
-
Source: U.S. EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks, April 2008
Figure 1
2006 Stationary Combustion Emissions (Percent of Total)
8.8%
The commercial and residential sectors emitted about 14 percent of GHG emissions from
stationary fuel combustion. The commercial sector includes emissions from fuel combustion in
commercial and institutional buildings (space heating and cooling, water heating, cooking and
baking, and dryers). The residential sector includes emissions from household fuel combustion
(space heating, water heating, and cooking).
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1.3 Stationary Fuel Combustion Categories Covered by this Document
This document addresses monitoring and reporting methods for stationary fuel
combustion sources at electric generating facilities, and stationary combustion sources.
Electric Generating Facilities are facilities which include equipment on a contiguous
property that are constructed for the purpose of supplying electrical output to any utility
power distribution system. Stationary fuel combustion equipment at the facilities includes,
but is not limited to, conventional boilers, combustion turbines, or engines that provide
energy to one or more electric generation turbines.
Stationary Fuel Combustion Facilities are combustion sources that occur at facilities other
than electric generating facilities.
1.4 Costs Associated with GHG Reporting Rule and Emission Thresholds
Cost information and discussion associated with facilities' compliance with the GHG
Reporting Rule are presented in the Regulatory Impact Analysis (RIA) associated with this rule.
All of the emission thresholds discussion is contained in the Thresholds Technical Support
Document (Docket # EPA-HQ-OAR-2008-0508-046).
2.0 Review of Existing GHG Reporting Programs
EPA reviewed a variety of existing mandatory and voluntary stationary source GHG
reporting programs to obtain information on appropriate quantification and reporting
methodologies, and to incorporate existing requirements where possible. Table 2 lists the GHG
reporting programs that were reviewed by EPA in developing the stationary combustion
requirements. Program quantification method comparison tables are provided in Appendix A.
Table 2
Mandatory and Voluntary GHG Reporting Programs
GHG Reporting Program
Reported GHGs from
Stationary Combustion
Mandatory or Voluntary
Program Participation
U.S. EPA Acid Rain Program,
40 CFR Part 75
C02
Mandatory
California ARB Mandatory GHG Reporting
Rule - Proposed
co2, ch4, n2o
Mandatory
Regional Greenhouse Gas Initiative (RGGI)
co2
Mandatory
European Union Emissions Trading Scheme
(EU ETS)
co2
Mandatory
Australian National GHG Reporting System -
Proposed
co2, ch4, n2o
Mandatory
Canadian GHG National Reporting Program
co2, ch4, n2o
Mandatory
California Climate Action Registry (CCAR)
co2, ch4, n2o
Voluntary
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The Climate Registry (TCR)
co2, ch4, n2o
Voluntary
U.S. EPA Climate Leaders
co2, ch4, n2o
Voluntary
U.S. DOE 1605(b) Voluntary Reporting of
GHGs Program, 10 CFR 300
co2, ch4, n2o
Voluntary
In addition, EPA reviewed inventory-related guidance and protocols used for national
inventories including the U.S. EPA's "Inventory of U.S. Greenhouse Gas Emissions and Sinks,"
and the 2006 Guidelines for National Greenhouse Gas Inventories from the Intergovernmental
Panel on Climate Change (IPCC). Also, many of the programs reviewed relied on the World
Resources Institute (WRl)AVorld Business Council for Sustainable Development (WBCSD)
GHG Protocol. The WRI/WBCSD GHG Protocol consists of corporate accounting and reporting
standards and separate calculation tools.
The existing programs, including the mandatory federal CO2 emission reporting under the
Acid Rain Program, all share the same quantification methodologies for the determination of
combustion GHG emissions - either direct stack emission measurements using a continuous
emissions monitoring system (CEMS), or a calculation approach based on fuel measurements.
Specifically, the program methodologies include:
A direct measurement approach for CO2 using a CEMS to measure stack CO2 or O2
concentration and a stack flow rate monitor;
A calculation approach for CO2 derived from mass balance principles and fuel
measurements; and
A calculation approach for CH4 and N2O based on fuel usage and generic or source
specific emission factors derived from source tests.
A number of programs, both voluntary and mandatory, tier the methodologies to assign
or recommend a particular quantification method. The IPCC Guidelines and Good Practice
Guidance for the development of national inventories have developed the tier concept for GHG
monitoring methodologies. Tiers represent levels of methodological complexity: Tier 1 is the
basic method; Tier 2 is the intermediate; and Tier 3 the most demanding in terms of complexity
and data requirements. Tiers 2 and 3 are sometimes referred to as higher tier methods and are
generally considered to be more accurate (IPCC, 2006). The IPCC recommends the use of
higher tier methods for sources that are determined to be significant within the context of overall
emissions from an inventory.
3.0 Measurement and Quantification Methods
EPA examined a combination of direct measurement and fuel-based approaches to
quantify stationary combustion GHG emissions. The following section describes the CO2
quantification methods used in the electric power sector by Acid Rain Program electric
generating units (EGUs), and a tier-based approach for CO2 that assigns monitoring methods
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January 30, 2009
based on source size and uncertainty in the emission estimate. EPA considered only a fuel-based
quantification approach for CH4 and N2O consistent with existing GHG programs.
3.1 CO2 Emission Methodologies for Electric Generating Sources
A significant portion of stationary combustion sources in the electric power sector are
subject to CO2 monitoring, recordkeeping, and reporting requirements under the Title IV Acid
Rain Program in 40 CFR Part 75. Congress required that EPA include CO2 monitoring under the
Acid Rain Program, and these systems generally rely on monitor components that are also used
for SO2 and NOx data reporting. The Acid Rain Program includes EGUs that burn fossil fuels,
and that serve a generator with a nameplate capacity greater than 25 megawatts. There are
approximately 1,200 facilities with a total of over 3,400 units subject to the CO2 emission
monitoring and reporting requirements of Part 75 under Title IV.
The mandatory and voluntary GHG reporting programs in the U.S. reviewed by EPA all
require or recommend that Acid Rain Program EGUs report the annual CO2 emissions measured
and reported to EPA under the Acid Rain Program. The California Mandatory GHG Reporting
Program and the RGGI Program also reference compliance with Part 75 certification and QA/QC
requirements for EGUs subject to Part 75. RGGI, which is limited to EGUs, also requires the
use of Part 75 electronic data recordkeeping and reporting.
3.1.1 Part 75 CO2 Monitoring and Reporting Overview
The Part 75 methods for CO2 include both direct measurement approaches using CEMS,
and mass balance-based calculation approaches. Part 75 also includes certification and QA/QC
requirements to ensure that data validity is confirmed at the beginning of a monitoring program
and then maintained over time. Missing data requirements encourage monitoring availability.
There are also electronic data reporting and recordkeeping requirements. The Part 75 monitoring
methods for CO2 are summarized in Table 3, and the usage of those methods by Acid Rain
Program sources is shown in Table 4. Each of the methods is briefly described in the following
section.
Table 3
CO2 Measurement Methodologies in 40 CFR Part 75
Rule C'iliition
Kli^ihlo I nits
Methodology
§ 75.13(a)
All units
Measurement method - C02 CEMS and flow monitor.
§ 75.13(b) and App. G §
2.1
All units
Calculation method based on fuel sampling and analysis for
fuel carbon content, and fuel consumption measurements.
Sampling frequency varies by fuel type.
§ 75.13(b) and
App. G § 2.2
Coal units
Calculation method based on weekly fuel sampling and
analysis for fuel and fly ash carbon content, fuel
consumption measurements, and the collected amount of fly
ash.
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§ 75.13(b) and
App. G § 2.3
Gas and oil units
Calculation method based on measured heat content, hourly
fuel consumption, and carbon based F-factors.*
§ 75.13(b) and
App. G§ 3.1
Fluidized bed boilers
or units with sorbent
injection
Calculation method based on measured daily sorbent usage
and either stoichiometric ratios or CEMS measured S02
removal rates. Absorbent C02 emissions are added to fuel
based emissions estimated per App. G §§ 2.1 and 2.2.
§ 75.13(c)
All units
Measurement Method - 02 CEMS and flow monitor.
§ 75.13(d) and
§ 75.19(c)
Low mass emission
gas and oil units
Calculation method based on default emission factors and
maximum rated heat input and operating time, or quarterly
fuel consumption records.
*F-factors are ratios of the gas volume of the products of combustion to the heat content of the fuel.
Table 4
2006 Mass Emissions by CO2 Measurement Methodology
Miiss Kmission ( nlcuhition
Methodology
Reported 2006 ( O,
Miiss Emissions
(million metric tons)
Percent of Tolnl
( ¦¦>: Miiss
Emissions
Percent ol Totid
Number of I nits
Reporting
CEMS (§ 75.13)
1,925
85%
33%
Fuel sampling and analysis for
carbon and daily fuel use
measurements
(App. G)
27
1%
5%
Heat content, F-factor, and daily
Appendix D fuel use(App. G)
309
14%
59%
Low Mass Emission Units -
default emission factors and
quarterly fuel use or maximum
rated fuel use (§ 75.19)
0.7
0%
3%
All Methods
2,263
100%
100%
3.1.2 Part 75 CEMS
About 85 percent of CO2 mass emissions reported under the Acid Rain Program are
based on CEMS measurements, and all coal fired Acid Rain Program units use CEMS for CO2
measurement. Part 75 CEMS for CO2 mass emission measurements consist of either a CO2 or
O2 CEMS combined with a flow monitoring system. Part 75 systems consist of a sampling
interface between the stack gas and analyzer or sensor, the analyzer or sensor, and data
acquisition and handling system (DAHS).
These systems continuously measure the gas concentration and volumetric stack flow to
calculate emissions in pounds per hour and tons per year. Most Part 75 CO2 CEMS measure on
a wet basis, without removing the stack moisture prior to the analyzer. This matches the flow
monitors which also measure the stack flow without removing the stack gas water vapor. If CO2
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is measured on a dry basis (stack moisture removed prior to the analyzer), the calculation must
include a correction for stack gas moisture content to so that the volumetric concentration
matches the volumetric flow basis. This may be done either using a measured moisture
percentage with a continuous moisture monitor or a default moisture percentage. If an O2 CEMS
is used, the CO2 concentration is back calculated from the O2 concentration based on fuel based
F-factors (F-factors are provided in Appendix B of this document). Simplified data calculations
are shown below. Emission calculation equations are in Appendix F of Part 75.
A. Wet CO2 CEMS Mass Rate Calculation
CO 2 = KCc02wQs
Where:
C02 = C02 mass emission rate (tons per hour);
Cco2w = Hourly average CO2 concentration (percent by volume, wet basis);
Qs = Hourly average stack gas volumetric flow rate (scfh); and
K = Conversion factor (converts CO2 volume to CO2 mass based on CO2 molecular weight),
5.7 x 10"7 C02/scf C02/%C02.
B. Dry CO2 CEMS Mass Rate Calculation
(100-%H2O)
CO2 - KCc02d Qs
100
Where:
Cco2d = Hourly average CO2 concentration (percent by volume, dry basis); and
%H20 = Stack moisture concentration (percent by volume).
C. O2 CEMS - CO2 Concentration Calculation
Wet basis 02 CEMS: Cr
100 F
20.9 F
20.9
(100 -%h2o^
100
-Cr
Dry basis O2 CEMS: C,
COld
F 20 9 -C
= 100 c °2d
F
20.9
Where
Co2w = Hourly average O2 concentration (percent by volume, wet basis);
Co2d = Hourly average O2 concentration (percent by volume, dry basis);
F= Oxygen-based F-factor;
Fc = Carbon-based F-factor; and
20.9 = concentration of O2 in ambient air (percent by volume).
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3.1.3 Part 75, Appendix G Mass Balance Based Calculation Methods
Part 75, Appendix G outlines alternative calculation methods for estimating C02
emissions based on mass balance principles and fuel measurements. In summary, the methods
require sampling of the fuel, analyses for the carbon or heat content of the fuel, and measuring
the quantity of fuel consumed. Daily emissions are calculated based on the quantity of fuel
burned and carbon fraction (assumes 100 percent oxidation of fuel carbon to CO2), or the
quantity of fuel burned and heat content of the fuel, and a heat content based emission factor (F-
factor). The rule specifies fuel-specific sampling and analysis methods (industry consensus
standards are incorporated by reference) for determining carbon or heat content (gross calorific
value or high heating value). The sampling frequencies depend on the fuel type, and are shown
in Table 5.
Table 5
Required Sampling and Analysis Frequency by Fuel in 40 CFR Part 75, Appendix G
l-'uel C omhuslccl
S;ini|)lin<> iiiul Aiiiilvsis Ircqucncv
Coal
One sample per week representative of the fuel bunkered
or burned.
Oil fuel in lots
One sample per delivery.
Gaseous fuel in lots
One sample per delivery.
Gaseous fuel that is not pipeline natural gas or natural
gas and is not delivered in shipments or lots
One sample per day or hour based on the variability in the
fuel heat content.
Pipeline natural gas or natural gas
One sample per month.
Acid Rain Program units that use the calculation methods in Appendix G of Part 75
compile daily fuel feed rates from company records for all fuels. Gas and oil units measure fuel
use on an hourly basis using volumetric or mass fuel flow meters that are also used to calculate
SO2 or NOx emissions under the non-CEMS alternatives in Appendices D and E of Part 75.
A. Calculating CO2 Emissions Using Carbon Content (Appendix G, Section 2.1)
The carbon analysis approach is only used by about five percent of Acid Rain units, and
no coal fired units are using this method. One reason is that Part 75 requires Acid Rain units to
use diluent monitors (CO2 or O2) as part of the NOx rate CEMS. These same monitors are then
used for CO2 emissions. Another reason is that sources do not typically measure the fuel carbon
content but do measure heat content as part of fuel purchasing, and gas or oil fired units measure
heat content under the alternative non-CEMS methods for SO2 and NOx in Appendices D and E
of Part 75.
The basic equation for the carbon-based calculation is shown below:
(MWC + MW0J XWC
Wro7
2,000 MWc
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Where:
Wco2 = CO2 emitted from combustion, tons/day;
MWC = Molecular weight of carbon (12.0);
MW02 = Molecular weight of oxygen (32.0); and
Wc = Carbon burned, lbs/day, based on fuel carbon concentration and fuel feed rates.
B. Calculating CO2 Emissions Using Heat Content (Appendix G, Section 2.3)
Almost 60 percent of Acid Rain units calculate CO2 emissions based on the measured
heat content and emission factor approach in Section 2.3 of Appendix G. This approach is
limited to gas-fired and oil-fired units and uses fuel-specific F factors for the emission factors.
An F-factor is a fuel specific ratio that numerically defines the relationship between the volume
of CO2 produced by combustion and the caloric heat content of the fuel combusted. Appendix G
specifies the F-factors for a number of fuels, but also allows the source to calculate an F-factor
specific to its fuel (Part 75 F-factors are listed in Appendix B). The basic heat-content based
calculation is shown below:
FcxH xjjfxMWCOi
Where:
Wco2 = CO2 emitted from combustion, tons/hour;
MWco2 = Molecular weight of CO2 (44);
Fc = Carbon based F-factor, 1040 scf/mmBtu for natural gas; 1,420 scf/mmBtu for crude,
residual, or distillate oil; and calculated according to the procedures in section 3.3.5 of
appendix F of Part 75 for other gaseous fuels;
H = Hourly heat input in mmBtu (heat content x hourly fuel use - weight basis); and
Uf= 1/385 scf CCVlb-mole at 14.7 psia and 68°F.
C. Additional Appendix G Methods
There are also two Appendix G methods that are not currently used by any Acid Rain
Program source. One method in Section 2.2 of Appendix G supplements the fuel carbon based
approach for coal fired units with sampling and analysis of the collected fly ash for unburned
carbon. The carbon captured in the fly ash is deducted from the fuel carbon in the CO2 emission
calculation. The other method in Section 3 of Appendix G accounts for the carbon in carbonate
absorbents used in fluidized bed combustors or injected downstream of the boiler for acid gas
control. The method relies on the measured daily sorbent usage and the stoichiometric ratios for
the sorbent - acid gas reaction.
3.1.4 Low Mass Emitters
Under the Acid Rain Program gas-fired or oil-fired units that emit no more than 25 tons
per year of SO2 and less than 100 tons per year of NOx are defined as low mass emission units
(LME) in Part 75. The units may use a simpler calculation and reporting approach with default
or unit specific emission factor, measured or default heat content, and quarterly fuel
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measurements or maximum rated fuel use (§75.19(c)). The basic calculation is similar to the
heat content based calculation in Appendix G:
WC02 = EFC02 X HIhr
Where:
Wco2 = CO2 emitted from fuel combustion, tons/hour;
HIhr = Hourly heat input in mmBtu (heat content x hourly fuel use - weight basis); and
EFco2 = CO2 emission factor (ton CO2 /mmBtu).
The main difference in this method from the Appendix G heat content method is in the
heat input determination. LME sources have the option of either using the equipment's
maximum rated heat input capacity (no fuel measurement required), or to measure fuel use on a
long term basis (quarterly) instead of the hourly fuel metering required for the Appendix G heat
content based calculation. The quarterly fuel measurement is apportioned to each hour based on
load. The heat content can be based on default values (specified in Part 75) or measured heat
content (similar to Appendix G).
Natural gas and oil fired units are required to use default emission factors specified in
Part 75. Units burning a gaseous fuel other than natural gas are required to develop an emission
factor from unit specific fuel sampling and analysis.
Table 6
Default Factors for Part 75 Low Mass Emitters (From Part 75, Tables LM-3 and LM-5)
l-'iiol C ombusted
Doliiiill 11 i<>li llcitliiiii Ysilue
(1IIIV)
Default CO: Kinission l-':iclor
Pipeline Natural Gas
1,050 Btu/scf
0.059 short ton C02/mmBtu
Other Natural Gas
1,100 Btu/scf
Diesel Fuel
20,050 Btu/lb or 167,500 Btu/gallon
0.081 short ton C02/mmBtu
Residual Oil
19,700 Btu/lb or 151,700 Btu/gallon
There are only about 100 Acid Rain units that use the LME methodology for CO2. These
are mainly peaking units that operate during high electricity demand periods, usually during the
summer air conditioning season.
3.2 CO2 Emission Methodologies for Stationary Combustion
There are many stationary fuel combustion sources that could be covered under a
mandatory GHG reporting program that are not regulated under 40 CFR Part 75, or do not have
process-specific monitoring methods specified for other source categories. For these sources,
four methods described below could be considered for calculating CO2 emissions. These
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methodologies are similar to those in Part 75, and include a CEMS measurement-based
methodology and calculation methodologies.
The methodologies are classified according to methodological complexity using a four
tier system. As discussed in the beginning of this section, the IPCC Guidelines and Good
Practice Guidance for the development of national inventories developed the tier concept for
GHG monitoring methodologies. Under the IPCC system Tier 1 is the basic method; Tier 2 is
the intermediate; and Tier 3 the most demanding in terms of complexity and data requirements.
Higher tier methods are generally considered to be more accurate, and IPCC recommends the use
of higher tier methods for significant sources
Given the general hierarchy of methods described in the review, a direct measurement
(CEMS) approach would be a Tier 4 method and require the most rigorous monitoring. Tiers 3
and 2 could be defined by measurement strategies using a combination of direct fuel
measurement and the application of a combination of fuel-specific factors. The least rigorous
tier, Tier 1, could be met by using quarterly fuel consumption records combined with default
factors. Each of the tiers is discussed below.
3.2.1 Tier 4 Methodology - CEMS
The Tier 4 methodology is a continuous monitoring approach similar to Part 75, that
includes CEMS for each affected unit at a facility and the recording of emissions and fuel data.
The CEMS include a CO? or O2 concentration monitor and a flow monitor. Emissions are
calculated in the same manner as described for a Part 75 CEMS.
One option might be to make Tier 4 the minimum requirement for large solid fuel-fired
units that already have an existing certified diluent CEMS or stack flow rate monitor, as well as
smaller solid fuel fired units that have both a certified diluent CEMS and a flow monitor. This
would not result in significant burden on reporters, as the monitoring equipment is already
installed, while leading to the highest confidence in the emissions data reported.
A diluent CEMS is included under many existing air pollution requirements so that
sources can convert concentrations measured by a pollutant CEMS into the terms of the pollutant
limitation (pounds of pollutant per million Btu or concentration of the pollutant corrected to
percent CO2 or O2). Table 7 identifies emission standards, under the New Source Performance
Standards (NSPS) in 40 CFR Part 60 that include a diluent CEMS requirement.
A large unit could be a solid fossil fuel fired unit with a maximum rated heat input
capacity greater than 250 mmBtu/hr or a municipal waste combustor with a capacity greater than
250 tons/day of municipal solid waste (MSW). These large unit cutoffs are the same as in the
NSPS for EGUs in 40 CFR Part 60, Subparts D and Da, and for municipal waste combustors in
Subparts Ea and Eb.
Sources with Part 60 CEMS could be required to continue to operate the diluent CO2 or
O2 monitor per Part 60 performance specifications and quality assurance requirements, and, if
necessary, install a stack flow monitor.
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Municipal solid waste combustion sources with an O2 diluent CEMS could be required to
install a CO2 diluent CEMS instead of back calculating CO2 based on O2 concentrations. F-
factors for different fuels have been found to be consistent within the fossil fuel categories (e.g.,
bituminous coal, subbituminous coal, natural gas). MSW and other alternative waste fuels,
however, are more variable, and therefore will have more variation in the F-factor, increasing the
emission uncertainty.
Exemptions could be included for units that operate not more than 1,000 hours in any one
year since 2005. This would reduce the burden on sources with much lower emissions than
reflected by the unit capacity.
Table 7
Large Unit NSPS Diluent CEMS - 40 CFR Part 60
I'iirl 60
Suhpjul
Title
Sl;ili(>ii;ii'Y C ombustion Source Type"
D
Standards of Performance for Fossil-Fuel-
Fired Steam Generators for Which
Construction Is Commenced After
August 17, 1971.
Fossil-fuel and wood-residue-fired steam generating unit
of more than 73 MW heat input rate (250 mmBtu/hr).
Gas fired units are exempt from the CEMS requirement.
Da
Standards of Performance for Electric
Utility Steam Generating Units for Which
Construction Is Commenced After
September 18, 1978.
Electric utility steam generating unit capable of
combusting more than 73 MW (250 mmBtu/hr) heat
input of fossil fuel (either alone or in combination with
any other fuel). Similar sized combined cycle gas
turbines burning 50 percent or more solid derived fuel for
which construction commenced after February 28, 2005.
Db
Standards of Performance for Industrial-
Commercial-Institutional Steam
Generating Units.
Coal or oil fired steam generating unit that has a heat
input capacity from fuels combusted of greater than 29
MW (100 mmBtu/hr).
Ea
Standards of Performance for Municipal
Waste Combustors for Which
Construction is Commenced After
December 20, 1989 and on or Before
September 20, 1994.
Municipal waste combustor unit with a capacity greater
than 225 megagrams per day (250 tons per day) of
municipal solid waste.
Eb
Standards of Performance for Municipal
Waste Combustors for Which
Construction is Commenced After
September 20, 1994.
Municipal waste combustor unit with a combustion
capacity greater than 250 tons per day of municipal solid
waste.
AAAA
Standards of Performance for Small
Municipal Waste Combustion Units for
Which Commenced After August 30,
1999 or for Which Modifications or
Reconstruction is Commenced After June
6, 2001.
Municipal waste combustion unit with the capacity to
combust at least 35 tons per day but no more than 250
tons per day of municipal solid waste or refuse-derived
fuel.
*Describes general type of unit subject to diluent CEMS requirements. There may be fuel, size, and other specific
exemptions to the CEMS requirement.
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January 30, 2009
3.2.2 Tier 3 Methodology - Fuel Carbon Content
A Tier 3 methodology would use the carbon content and the amount of fuel burned to
determine the CO2 mass emissions. This could be a minimum requirement for any unit with a
heat input capacity greater than 250 mmBtu/hr. Fuel combusted could be obtained from
company records for solid fuels, and is measured directly for liquid and gaseous fuels, usually
using either fuel flow meters or tank drop measurements. CO2 mass emissions are estimated by
multiplying the carbon content of the fuel by the fuel consumption for each fuel combusted.
This methodology assumes all carbon is converted to CO2.
The minimum frequencies of the fuel sampling for fuel carbon content deemed necessary
are specified in Table 8. To ensure the greatest certainty in the data, the sampling and analysis
could be required to be done according to voluntary consensus standards.
Table 8
Sampling and Analysis Frequency
l-'iiol C ombusted
S;ini|)lin<> l-'ivqik'iicv
Aiiiilvsis l-Ycqucncv
Coal
Weekly
Monthly*
Other Solid Fuel
Weekly
Monthly*
Natural Gas
Monthly
Monthly
Fuel Oil
Monthly
Monthly
Other Liquid Fuels
Monthly
Monthly
Other Gaseous Fuels (e.g., refinery
gas, process gas)
Daily
Daily
*Composite of weekly samples.
The sampling and analysis frequency in Table 8 is comparable to the frequency required
by Part 75, Appendix G (see Table 5), and the California reporting rule with minimum sampling
baselines of monthly for natural gas and fuel oil, weekly for solid fuels, and daily sampling for
more variable process gas (e.g., refinery fuel gas, coke oven gas, blast furnace gas). The
minimum daily sampling and analysis requirement for process gas is also consistent with EU
ETS requirements.
13
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January 30, 2009
For solid or liquid fuels, the formula to calculate CO2 annual mass emissions using the
Tier 3 methodology is:
n 44
COi = I TT * (Fm')n " (CCX
p=1 AZ
Where:
CO2 = Annual CO2 combustion emissions, tons;
(Fuel)n = Mass of the fuel combusted in the month, week, or day "n";
(CC) = Carbon content of the fuel for the time period "n" expressed as a decimal
fraction; and
44/12 = Ratio of the molecular weights of CO2 to carbon.
In the case of gaseous fuel consumption, the formula will be adjusted to include the ratio
of the molecular weight of the gaseous fuel to the molar volume conversion factor (MW/MVC):
CO, =s £.(>*<(cc\^
Facilities which use the same liquid or gaseous fuel source for all units at a facility or a
group of units could calculate facility-wide CO2 emissions or group CO2 emissions based on
measurements of the common fuel source (e.g., a natural gas meter at the facility gate).
3.2.3 Tier 2 Methodology - Fuel Heat Content
Tier 2 would be most appropriate for small units with capacity equal or less than 250
mmBtu/hr or 250 tons of MSW/hr. Tier 2 data collection is similar to Tier 3 except annual CO2
mass emissions are estimated using measured fuel heat content (HHV) or fuel heat content
provided by the fuel suppliers. Emissions are estimated by multiplying the fuel heat content by
the amount of fuel burned and a default fuel specific emission factor (emission factor is in terms
of CO2 mass emissions for a given fuel heat input). The minimum sampling and analysis
frequency would be monthly for all fuels. Sampling and analysis could be required to be
performed using voluntary consensus standards. The basic equation is shown below:
C02=Yj\x 10~3 {Fuel)n * (HHV)n * EF
P=1
Default emission factors are shown in Appendix C.
The Tier 2 approach would be modified for municipal solid waste combustion because of
the variable heat content of solid waste, and greater difficulty in collecting a representative solid
waste sample for the heat content analysis. The source measures the steam output, and uses the
ratio of the maximum rated heat input to design steam output (mmBtu/lb steam) to estimate heat
input. A similar approach is used by California in their rule. The calculation is shown below:
C02 = (Steam) (B) (EF)
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January 30, 2009
Where:
Steam = Total mass of steam generated by MSW combustion during the year;
B = Ratio of boiler's maximum rated heat input capacity to its design rated steam output
capacity (mmBtu/lb); and
/'/' = Fuel-specific default CO2 emission factor (kg CCVmmBtu).
3.2.4 Tier 1 Methodology - Default Heat Content
Tier 1 methodology is the simplest and least rigorous methodology and its use could be
limited to small units that combust homogenous fuels. For each type of fuel combusted, the
source could be required to estimate the annual CO2 mass emissions based on a fuel specific
default CO2 emission factor, a default heat content, and the annual fuel consumption from
company records, using the following formula:
CO2 = Fuel * HHVd * EF
Default fuel-specific high heat values and CO2 emission factors are compiled in
Appendix D.
3.2.5 CO2 Emissions from Carbonate Sorbents
In addition to the four method tiers, facilities could also be required to report emissions
resulting from the use of a carbonate sorbent. Absorbent use will occur when a source has a wet
flue gas desulfurization system, has a fluidized bed boiler, or uses sorbent injection for acid gas
emissions control in another manner. In most cases, these emissions will be measured by a
CEMS, as has been the experience for Acid Rain Program sources.
If emissions from sorbent usage are not otherwise quantified, a methodology similar to
the sorbent calculation methodology in Appendix G of Part 75 could be used to quantify
absorbent CO2 emissions. This method requires measurement and recording of absorbent use,
and the calculation is shown below:
C02=S*R*
f MW ^
iVJ ₯₯ CO2
MWS
Where:
CO2 = CO2 emitted from sorbent for the report year (metric tons);
S = Limestone or other sorbent used in the report year (metric tons);
R = Stoichiometric ratio of moles of CO2 released upon capture of one mole of acid gas;
MWc02 = Molecular weight of carbon dioxide; and
MWS = Molecular weight of sorbent (100 if calcium carbonate).
The CO2 emitted from the sorbent is added to the CO2 emitted from fuel combustion to
determine the total CO2 mass emissions for the unit.
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January 30, 2009
3.3 CO2 Emissions Methodologies for Units that Burn Biomass
The existing CO2 reporting programs reviewed by EPA, except for the Acid Rain
Program, allow the segregation and separate reporting of CO2 emissions from the combustion of
biomass derived non-fossil fuels. CO2 emissions from biomass combustion are segregated
because it is assumed that the carbon released during stationary source combustion of biomass is
recycled as U.S. forests and crops regenerate. Emissions of CH4 and N2O from the combustion
of biomass and biomass-based fuels are not segregated, since these emissions are not based on
the natural carbon cycle.
Biomass is defined as non-fossilized and biodegradable organic material originating from
plants, animals and micro-organisms, including products, byproducts, residues and waste from
agriculture, forestry and related industries as well as the non-fossilized and biodegradable
organic fractions of industrial and municipal wastes, including gases and liquids recovered from
the decomposition of non-fossilized and biodegradable organic material. This is the same
definition as used by the EU Emissions Trading Scheme and California's mandatory GHG
reporting rule. In addition, biomass-derived fuels or biomass fuels could also mean fuels derived
from biomass.
This treatment of biomass fuels is consistent with the IPCC Guidelines and annual
Inventory of Greenhouse Gas Emissions and Sinks, which accounts for the release of these CO2
emissions in accounting for carbon stock changes from agriculture, forestry, and other land use.
In this case, the carbon flux that occurs in land-use is estimated on a national basis in national
inventories.
Other programs use a more restrictive definition of biomass. For example, RGGI adds
additional sustainable harvest criteria to define fuels that are eligible for biomass treatment and
exclusion from fossil-fuel CO2 reporting: "Eligible biomass includes sustainably harvested
woody and herbaceous fuel sources that are available on a renewable or recurring basis
(excluding old growth timber), including dedicated energy crops and trees, agricultural food and
feed crop residues, aquatic plants, unadulterated wood and wood residues, animal wastes, other
clean organic wastes not mixed with other solid wastes, biogas, and other neat liquid biofuels
derived from such fuel sources." (RGGI Model Rule - final with corrections, 2007).
Biomass fuels are combusted alone (100 percent biomass) or in combination with fossil
fuel. There are also waste fuels that are a mix of materials derived from biomass and fossil fuels;
for example, municipal solid waste (MSW) may include materials derived from both biomass
(paper waste) and fossil fuels (plastic waste).
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January 30, 2009
3.3.1 Biomass Fuels except for Municipal Solid Waste
For sources that burn a combination of pure biomass and fossil fuel, and measure total
CO2 emissions with a CEMS, sources could be required to estimate the percent CO2 from
biomass fuels by estimating the volume of fossil CO2 emissions based on a calculation approach.
The calculation approach uses the total amount of fossil fuel burned, the fuel heat content, and
carbon based F-factor; the biomass CO2 mass emissions is the difference between the CEMS
measured CO2 volume and calculated fossil fuel CO2 volume. This approach is similar to the
approaches in both the California reporting rule and EU Emissions Trading Scheme.
If the source uses a calculation methodology, CO2 emissions from pure biomass fuels or a
mixture of pure biomass and fossil fuels are calculated and reported in the same manner as CO2
emissions for fossil fuels or emissions from carbonates. The annual CO2 emissions from each
fuel are summed, and the biomass percentage is determined by dividing the sum of biomass fuel
CO2 emissions by the total annual CO2 emissions.
3.3.2 Municipal Solid Waste
Several different approaches were considered for a source that elects to report the
biomass portion of CO2 emissions, when a mixed fuel (MSW) is combusted in an affected unit.
The California rule requires sources that combust MSW to determine the biomass-derived
portion of CO2 emissions using ASTM D6866-06a every three months. The ASTM D6866-06
method is a carbon dating approach that measures the radiocarbon (14C) composition of a gas
sample, and compares it with the 14C content of a modern reference sample. The 14C isotope is
present in all plant material, while absent in all fossil fuels. Each sample is taken during normal
operating conditions over at least 24 consecutive hours. The average proportionalities between
plant material carbon and fossil carbon determined by the analyses are used to apportion CO2
emissions between fossil and biomass fuels.
The EU ETS program allows a variety of methods to apportion the biomass and non-
fossil portions of a mixed fuel. Approaches include a manual sorting approach to determine
component fractions, differential methods determining heating values of a binary mixture and its
two pure components, and a similar isotopic analysis as the ASTM D6866-06a analysis
approach. For fuels or materials originating from a production process with defined and
traceable input streams, the operator may alternatively base the determination of the biomass
fraction on a mass-balance of fossil and biomass carbon entering and leaving the process. In any
case, the methodology must be approved by the regulatory agency.
EPA determined that the California approach of quarterly source testing that collects an
integrated gas sample per ASTM D7459-08, and an analysis of the sample per ASTM D6866-
06a provides a standardized, consistent, and low cost approach for the determination of the
biogenic CO2 fraction for mixed fuels like MSW. The integrated gas sample can be easily taken
from stacks which already have CEMS, which is the case with the source population affected by
this requirement
ASTM D6866-06a was originally developed to support the U.S. Department of
Agriculture's Biobased Products Preferred Procurement Program, and is the required method for
17
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January 30, 2009
the determination of biobased content under 7 CFR Part 2902. EPA is also currently reviewing
the method for the Renewable Fuel Standard Requirements in 40 CFR Part 80.
To ensure confidence in the emissions data reported, sources could be required to
perform the ASTM D6866-06a analysis at least once in every calendar quarter in which MSW,
or other mixed fuel, is combusted in the unit. Each gas sample could be taken using ASTM
D7459-08, during normal unit operating conditions while MSW is the only fuel being
combusted, for at least 24 consecutive hours (or for as long as is necessary to obtain a sample
large enough to meet the specifications of ASTM D6866-06a). The owner or operator would
divide total CO2 emissions between biogenic emissions and non-biogenic emissions, using the
average proportionalities of all samples analyzed during the report year. If there is a common
fuel source of MSW that feeds multiple units at the facility, performing the testing at only one of
the units is sufficient.
3.4 Calculating CH4 and N2O Emissions from Stationary Fuel Combustion Sources
To estimate CH4and N2O emissions, the methodology is based on fuel consumption and
default CH4 and N2O emission factors. Part 75 units measuring and reporting heat input on a
year round basis according to §§75.10(c) and 75.64 could calculate the annual CH4 and N2O
emissions in metric tons using the cumulative annual heat input from the electronic data report
required under §75.64, multiplied by a the corresponding fuel specific emission factor.
For all other units, the annual CH4 and N2O emissions in metric tons could be based on
the mass or volume of fuel combusted multiplied by the fuel heat content and the corresponding
fuel specific emission factor. Default heat contents may be used by sources using a Tier 1
methodology for CO2.
The annual CH4 and N2O emissions are converted to metric tons CO2 equivalent by the
global warming potential (GWP) factors in Table 9.
Table 9
GWP Factors - CH4 and N20
(iriTiihoiisc (l.is
Clohiil \\ ;irmin<> I'olcnliiil ((JW l>)
C02
1
ch4*
21
n2o
310
*The CH4 GWP includes the direct effects and those indirect effects due to the production of tropospheric ozone and
stratospheric water vapor. The indirect effect due to the production of C02 is not included.
Source: IPCC Climate Change 1995: The Science of Climate Change. (1996) Intergovernmental Panel on Climate
Change, J.T. Houghton, L.G. MeiraFilho, B.A. Callander, N. Harris, A. Kattenberg, andK. Maskell, eds.
Cambridge University Press, Cambridge U.K.
18
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January 30, 2009
3.5 Other Quantification Options Considered
3.5.1 Require Part 75 CO2 Emissions Quantification and Monitoring Requirements
for All Stationary Combustion Sources
Another approach to quantify CO2 emissions would be to extend the Acid Rain Program
CO2 monitoring requirements in 40 CFR Part 75 to all affected facilities, instead of the separate
four tier approach for non-Acid Rain combustion sources. This approach would add extensive
electronic data capture and reporting. This approach has the advantage of ensuring a high level
of transparency, accuracy, and consistency among reporters. The disadvantage of this approach
is that it would be more costly than the option described above, and may not be deemed
necessary for a GHG reporting program designed to collect data to support a range of future
policies. The Part 75 program was designed to support a cap and trade emission control
program, and the requirements for that program are necessary to assure that allowances are
consistently valued, and that emission reductions are in fact achieved.
3.5.2 Require a Tier 4 CEMS Methodology for all Non-Part 75 Solid Fuel-Burning
Sources that Have a Rated Heat Capacity Greater Than 250 Million Btus per Hour
Another option would be to require the use of CEMS for all solid fuel burning sources
that have a rated heat input capacity of greater than 250 million Btus per hour. CEMS can have a
higher degree of measurement accuracy than sampling and calculation methodologies for solid
fuels due to the increased sampling required to achieve representative sampling of a
heterogeneous solid fuel. The cost of installing and maintaining a CEMS, however, is
significantly higher than the cost of calculating emissions using a carbon content or heat input
based methodology. In addition, the variability of carbon content across samples of the same
coal rank is significantly less than the variability of sulfur and other elements. Therefore
representative sampling is not as difficult for carbon as it would be for sulfur, and can be
achieved if the overall sampling strategy meets ASTM standards.
When considering the cost associated with the addition of CEMS as compared to the
added benefit for the CO2 measurement and reporting process, it could be argued that requiring
sources to purchase and install a complete system with a CO2 CEMS and flow monitor would
place an unnecessary burden for emissions reporting program. However, if the measurement and
reporting provisions under this program are used in the future as part of specific compliance
program, EPA would need to reexamine this decision to ensure a consistent and effective
compliance oversight process.
3.5.3 Allow Tier 2 Methodology Calculation for All Gas and Oil Fired Sources
Another option would be to allow oil-fired and gas-fired units of all sizes (other than
units burning facility-produced process gas) to use the Tier 2 methodology. Unlike Tier 3, which
requires sampling for fuel carbon content, Tier 2 uses measured fuel heat content and a fuel-
specific default CO2 emission factor.
An approach similar to the Tier 2 approach without any size limit is allowed under
Appendix G of Part 75 for all gas- or oil-fired Acid Rain Program units firing fuels with low heat
19
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January 30, 2009
content variability. The Appendix G approach requires compilation of daily fuel consumption
based on hourly records, while Tier 2 and Tier 3 would require less frequent fuel consumption
compilation (the frequency varies dependent on fuel type).
3.5.4 Provide Methodology Flexibility through Guidelines and Minimum Standards
In lieu of required monitoring methods, EPA considered a method guideline approach
similar to the approach taken by the voluntary DOE 1605(b) GHG reporting program, which sets
minimum standards for methodologies and data. The 1605(b) program requires reporters who
wish to register their reductions to "rate" their data and emission estimation methods. The
program also establishes minimum standards for the methods and data used to calculate overall
emissions. This approach was adopted by DOE to resolve a number of difficulties associated
with adapting emissions inventory methods to the problem of calculating "entity" emissions and
using such entity estimates to register reductions.
The emission rating system is similar to the tier approach described above. It is an
ordinal rating of emission estimation methods by sector and emission source. The best available
method, based on the four evaluation criteria of accuracy, reliability, verifiability and practical
application, is usually rated "A," and given a value of four points. An A rating is restricted to
methodologies where computations are based on a preponderance of values indicative of on-site
conditions over multiple periods. The next best method, or best method in those cases where no
methodology qualifies for an A rating , will be rated "B" and given a value of three points; the
next best rated "C" and given a value of two points; and the least accurate method rated "D" and
given a value of one point.
Reporters assign the rating provided in the program's Technical Guidelines to each source
for each year in which emissions are reported. The average rating (weighted by emissions) of all
of the entity's reported emissions (and sequestration in this program's case) must be 3.0 or higher
in the base period and any year in which reductions are reported in order for the reductions or
sequestration to qualify as "registered reductions."
Table 10 is taken from the Technical Guidelines and broadly describes the method rating
system. The Technical Guidelines also provide fuel specific monitoring methodology ratings for
the stationary combustion sector, and default factors for heat content and emissions.
Table 10
DOE 1605(b) Measurement and Estimation Method Ratings
Killing
Points
Tvpicsil Description
A
4
Continuous direct measurement (CEMS) of actual emission source; or emission factor
based upon multiple recent, regularly repeated, on-site direct measurements of sources,
multiplied by measured activity data. Activity data measure actual use rather than
purchases (if applicable).
B
3
Emission factor based on limited direct measurements of source or representative sample
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January 30, 2009
multiplied by measured activity data. Activity data measure actual use, rather than
purchases (if applicable).
c
2
Default emission factor multiplied by measured activity data; or emission factor based on
single measurement multiplied by estimated activity data.
D
1
Default emission factor multiplied by estimated activity data or static one-time
monitoring.
From Table l.A.l., DOE Technical Guidelines, Voluntary Reporting of GHGs 1605(b) Program, January, 2007.
3.5.5 De minimis Source Exemptions
The California mandatory reporting rule allows alternative monitoring methods of the
operator's choosing for de minimis sources. The de minimis category under the CARB rule can
include one or more units that collectively produce no more than three percent of the facility's
total CC>2e emissions, but in no case exceeding 20,000 metric tons C02e. The EU ETS has a de
minimis category that can cover minor sources selected by an operator that emit 1,000 tons or
less per year, or that contribute less than two percent of total annual CO2 emissions (up to no
more than 20,000 tons). Monitoring and emission quantification may be performed for these
units using non-tier methods. One way to alleviate burden to smaller sources would be to
provide the simple Tier 1 methodology for smaller sources.
4.0 Substitute Data Procedures
The existing federal CO2 emissions reporting under the Acid Rain Program and
California's GHG reporting rule both provide for the use of substitute data during periods when
quality assured monitoring data are not available to quantify emissions. EPA also proposes to
include missing data requirements in the federal GHG reporting rule to help ensure data quality.
Acid Rain Program EGUs could be required to continue to use the missing data procedures in
Part 75, Subpart D and Appendix G. Stationary fuel combustion sources could estimate missing
data using a simple averaging approach of the most recent quality assured data.
4.1 Part 75 Missing Data
Part 75 requires affected Acid Rain Program units to record CO2 emissions data for every
hour that they operate, including periods of start-up, shutdown, and malfunction. If one of the
required monitoring systems is not working or is out-of-control (e.g., if it fails one of its required
quality assurance tests), data from an approved backup monitor or from an EPA reference
method may be reported, or missing data substitution procedures must be used to estimate
emissions.
The missing data routines for CEMS in Subpart D of Part 75, consists of mathematical
algorithms that are used to determine an appropriate substitute value for any unit operating hour
in which quality-assured data are not obtained for a monitored parameter. The routines generally
use historic quality-assured monitoring data to determine the substitute data values. The Part 75
missing data procedures for CEMS (gas and stack flow) are designed to provide conservatively
high substitute data values, to ensure that emissions are not underestimated during monitor
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January 30, 2009
outages. The missing data algorithms also become increasingly conservative (biased towards
higher emissions) as monitor downtime increases so that sources have an incentive to maintain
high data availability.
The standard Part 75 missing data algorithms for fuel flow rate metering are fuel-specific
and load-based. The substitute data value for each hour is simply an arithmetic average of the
data in the corresponding load bin, based on a look back through 720 hours of quality-assured
data. If data are missing for that load bin, the next higher load bin is used. Missing data
substitution for fuel heat content data is designed to provide conservatively high substitute
values, but missing substitute data for fuel carbon content can be either the last quality assured
value or a default value.
4.2 Other Stationary Combustion Units
Table 11 summarizes potential missing data methodologies for units using GHG emission
calculation methodologies in Tiers 2, 3, and 4. For each missing value of the heat content,
carbon content, or molecular weight of the fuel, and any CEMS measured CO2 concentration or
stack gas moisture, the substitute data value could be the arithmetic average of the quality-
assured values of that parameter immediately preceding and immediately following the missing
data incident. If, for a particular parameter, no quality-assured data are available prior to the
missing data incident, the substitute data value could be the first quality-assured value obtained
after the missing data period.
For missing fuel flow rates and stack flow rates under Tiers 3 and 4, the substitute data
values would be the best available estimates of these parameters, based on process and operating
data (e.g., production rate, load, unit operating time, etc.) This same substitute data approach
would be used when fuel usage data and sorbent usage data are missing.
Table 11
Overview of General Stationary Combustion Missing Data Values
I'sirsuneler
Missing Ysilue
Fuel heat content, carbon content,
and molecular weight.
Arithmetic average of quality-assured values immediately preceding and
immediately following missing data period. The first quality-assured value
after the missing data is used, if no value is available preceding the missing
data period.
C02 concentration and stack gas
moisture content (CEMS).
Fuel flow and fuel use rates.
Best available estimates of these parameters, based on process and
operating data (e.g., production rate, load, unit operating time, etc.)
Stack gas flow rate (CEMS).
Carbonate absorbent usage.
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4.3 Other Missing Data Options
None of the routines for general stationary combustion units are biased high to ensure
against under reporting or to encourage high monitor availability. Sources under a GHG
emission inventory reporting program do not have the same incentives as Part 75 sources to
report lower emissions, and compliance with an emission cap is not an issue. Therefore the Part
75 approach, based on data availability might not be appropriate for stationary combustion since
those routines have a bias for higher emissions.
Alternatively for Part 75 sources, the potential bias in existing methods based on data
availability is acceptable versus the complexity of having Acid Rain Program EGUs calculate
two different sets of CO2 emissions data based on different missing data routines. Also, because
data availability in the Acid Rain Program is very high, over reporting due to data substitution
will be minimal, and not at a level that would warrant requiring all Acid Rain Program sources to
prepare, record, and report two sets of missing data calculations.
5.0 Quality Assurance/Quality Control
5.1 Quality Assurance for CEMS
Sources using CEMS to quantify CO2 emissions could be required to meet existing
quality assurance requirements that apply to the CEMS under 40 CFR Parts 60 or 75, or a State's
program.
5.2 Quality Assurance for Calculation Approaches
Acid Rain Program EGUs using the non-CEMS calculation methods in Appendix G
could be required to meet the current applicable Part 75 quality assurance requirements for the
fuel data used in mass balance and emission factor calculations. These include fuel flow meter
calibration and accuracy test procedures in Appendix D of Part 75.
For stationary combustion sources using the Tiers 1 through 3, specific consensus
standards similar to those in Part 75 for fuel sampling and analysis for carbon, heat content, and
density could be required.
Oil and gas fuel flow meter calibrations could also be required following consensus
standards or procedures recommended by the instrument manufacturer. Sources could also use
the procedures in Appendix D to Part 75. An initial calibration could be required, as well as on-
going calibrations. The on-going tests could be required once per year, or less frequently based
on manufacturer's recommendations. The annual schedule is similar to Part 75, which requires
fuel flow meter accuracy testing every four fuel flowmeter QA operating quarters, with
conditions to extend the period between tests.
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5.3 Monitoring Plan and QA/QC Plan
Some version of a monitoring plan and QA/QC plan that outlines the standard operating
procedures for emission quantification and quality assurance are required by many of the
existing or proposed GHG reporting programs.
Acid Rain Program sources currently submit detailed monitoring plans that include
collection of CO2 related data. Except for certain diagrams and blueprints, the monitoring plan
data are submitted electronically. Table 12 summarizes Part 75 monitoring plan contents.
Table 12
Part 75 Monitoring Plan Contents
Toi'innl
Monitoring Phi 11 Klenionts
Electronic
Unit information, such as the unit type, the maximum heat input capacity, the operating range
of the unit (in terms of MWs or steam load), the type(s) of fuel combusted, the type(s) of
emission controls, etc.
Unit-stack configuration information, indicating how the effluent gases from the unit discharge
to the atmosphere (i.e., through a single stack or multiple stacks, or through a common stack
shared with other units.)
A description of the methodology used to monitor each pollutant or parameter (e.g., CEMS,
Appendix D, Appendix E, etc.)
Monitoring system information (e.g., the pollutant or parameter monitored by the system, the
make, model and serial number of each analyzer, span and range information, etc.)
Mathematical formulas used to calculate emissions and heat input.
Hard Copy
Schematic diagrams and blueprints.
Data flow diagrams.
A separate QA/QC plan detailing those activities is also required by Part 75, QA/QC
plants are retained on-site and are not submitted to EPA. Part 75 QA/QC plan elements include:
QA test procedures, and monitor adjustment procedures;
Emissions and QA test recordkeeping and reporting procedures;
Missing data procedures related to add-on control equipment; and
Preventive maintenance procedures.
Required monitoring or QA/QC plan requirements in other GHG reporting programs,
except for the EU ETS are not as extensive as those in the Acid Rain Program. California's GHG
rule requires facilities to document the data acquisition and handling activities for the calculation
and reporting of emissions. The activities include parameter measurements, monitoring, fuel
analysis, recordkeeping, and the emission calculations. The documentation is not submitted to
the State, but is used in the third party verification process. The EU ETS, which is an emission
24
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January 30, 2009
trading program, has specific monitoring plan requirements similar to the Acid Rain Program,
and requires submittal and approval prior to data collection.
Minimal requirements for a GHG reporting program could be to document the process
used to collect the necessary data for the GHG emission calculations, identify key facility
personnel involved in calculating and reporting the GHG emissions, and log any changes to the
GHG emission accounting methods.
Facilities could also be required to prepare and maintain a Quality Assurance Project Plan
that documents the procedures used to ensure the accuracy of the estimates of fuel usage and/or
sorbent usage (as applicable), including calibration of weighing equipment, fuel flow meters, and
other measurement devices. The estimated accuracy of measurements made with these devices
shall also be recorded, as well as the technical basis for these estimates.
Submittal of the plans prior to monitoring, although necessary in a trading or compliance
based program, might not be required for an emissions reporting program.
6.0 Types of Emissions Information to be Reported
In order to support data collection for a range of future climate policies, additional data
beyond actual GHG emissions data could be required to be reported. For example, additional
information on the number, types, and size of combustion sources could be required to be
reported. Sufficient fuel and quantification methodology information could be required to
support the reported emissions, and to allow a level of EPA verification of emissions. EPA's
intention is to develop a reporting scheme that where practicable, integrates the new reporting
requirements with existing data collection and data management systems.
6.1 Data Elements Reported Under Existing Programs
Many of the stationary fuel combustion sources that would be affected by the proposed
GHG Reporting Rule currently report criteria and hazardous pollutant emissions or other
emissions related data to EPA or to the States under the Clean Air Act. Section 821 of the Clean
Air Act required reporting of CO2 emissions from Acid Rain Program EGUs. Under section 110
of Title I of the Clean Air Act, EPA has long required State Implementation Plans (SIPs) to
provide for the submission by States to EPA of emission inventories containing information
regarding the emissions of criteria pollutants and their precursor compounds. In addition a
number of States have developed their own GHG reporting programs. Data elements reported
under the Acid Rain Program, National Emissions Inventory (NEI), and other GHG reporting
programs are briefly outlined below.
6.1.1 Acid Rain Program EGUs
Acid Rain Program EGUs currently report extensive CO2 emissions data and monitoring
information directly to EPA through quarterly electronic reports. Part 75 requires affected units
to record CO2 emissions data for every hour that they operate, including periods of start-up,
shutdown, and malfunction.
25
-------
January 30, 2009
Most of the detailed records are kept electronically, for a minimum of three years, using a
DAHS, although some monitoring plan information and QA test support data is kept in hard
copy. The DAHS records all data from the monitoring systems, translates it into the required
units of measure, and stores the data. When emissions data are missing, the DAHS automatically
performs missing data substitution. The DAHS also electronically records and stores operating
data for the combustion unit, monitoring plan data, and the results of QA checks and tests.
Facilities submit electronic data on a unit basis in Part 75 quarterly reports. Quarterly
reports include:
Facility information;
The hourly CO2 emissions data, operating data, results of the required QA tests, and other
information specified in the monitoring plan and recordkeeping sections of Part 75;
For Appendix D units, the type of gas or oil fuel burned in the hour, amounts, and fuel
heat input;
Unit operating hours for the quarter and cumulative operating hours for the calendar year;
Short tons of CO2 emitted during the quarter and cumulative CO2 mass emissions for the
calendar year; and
Total heat input (mmBtu) for quarter and cumulative heat input for calendar year.
6.1.2 NEI Report Formats
States report their criteria and hazardous pollutant inventories to the NEI. The facility
based reports for point sources include data elements down to the unit and process (fuel) level.
Reported data elements required by the Consolidated Emissions Reporting Rule (CERR) that are
relevant to GHG reporting include:
Facility information;
Point and process identification and a process-level code that describes the equipment
and/or operation which is emitting pollutants;
Fuel ash, sulfur, and heat content on an annual average basis;
Activity or throughput on a daily average and annual basis; and
Emission factors and annual emissions.
26
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January 30, 2009
6.1.3 Other GHG Reporting Programs
There are a number of other GHG reporting programs (See Table 2, above) including
mandatory programs (such as the California reporting rule and EU ETS) and voluntary programs
(EPA's Climate Leaders and The Climate Registry). California, EU ETS, and The Climate
Registry have third party verification, while Climate Leaders relies on EPA's own verification.
Under California's GHG rule, electric generating facilities are required to report unit level
combustion GHG emissions, nameplate generating capacity, fuel consumption, heat content by
fuel type, and carbon content if measured. Operators are permitted to aggregate information for
multiple generating units that combust the same fuel type if the facility lacks the necessary
equipment to report by generating unit. For general stationary fuel combustion sources,
California requires facility reporting of total annual GHG emissions, annual GHG emissions by
fuel type, the amount of each fuel burned, fuel heat content, carbon content if measured, and
GHG emission factors.
The EU ETS program also requires reporting at the facility level. For all emission
sources and/or source streams, facilities report annual total CO2 emissions, the quantification
approach (measurement or calculation), chosen tiers and method (if applicable), activity data
(fuel use), heat content, and emission factors. If a mass balance approach is used, the carbon
content is also reported.
EPA's voluntary Climate Leaders program requires only limited reporting of the annual
total GHG emissions. Another voluntary GHG reporting program, The Climate Registry,
requires reporting of total stationary combustion GHG emissions and identification of the
associated quantification methodology tier.
6.2 Proposed Reporting Elements
Table 13 includes the type of information that could be required to be reported in a
mandatory GHG reporting rule.
27
-------
January 30, 2009
Table 13
Emission Reporting Elements for all Stationary Combustion Units
Diilii Klcmcnt
Description
Unit identifier
Assigned by facility.
Unit type
Boiler, combustion turbine, engine, process heater, etc.
Unit capacity
Maximum rated heat input of the unit in mmBtu/hr
(boilers, combustion turbines, engines, and process
heaters only).
Fuel Type and Amount
Each type of fuel combusted in the unit during the
report year, and the amount consumed in the year.
Fuel Characteristics
Heat content and carbon content (carbon content if
measured).
Emission Methodology
The method used to calculate C02 emissions for each
type of fuel (e.g., Part 75, Tier 1, Tier 2, etc.)
Part 75 Methodology
If applicable, which one of the monitoring and reporting
methodologies in Part 75 was used to quantify the C02
emissions.
GHG emissions for each fuel
Annual C02, CH4, and N20 emissions for each fuel in
metric tons.
C02 emissions from sorbent use (if applicable)
Annual C02 emissions in metric tons per year.
The total GHG emissions
Annual C02e emissions from the unit in metric tons.
6.2.1 Consolidated Reporting of Unit Data
The direct dependence of CO2 emissions on the fuel carbon content and amount of fuel
burned, rather than type of combustion equipment, allows for aggregation of reported data above
the unit level. Also the default CH4 and N2O emission factors are based strictly on the type of
fuel burned, and not the type of combustor. Therefore, a facility could be allowed to report the
combined GHG emissions from the facility, instead of unit information, if it combusts the same
type of homogeneous oil or gaseous fuel through a common supply line.
To further reduce burden, aggregation of small units at a facility could be allowed as long
as the total rated heat input of the group does not exceed 250 mmBtu/hr. Unit specific fuel usage
still would be quantified. In this case the data elements in Table 13 could be reported as a group.
The 250 mmBtu/hr level corresponds to the large combustion source cutoff for the monitoring
tiers.
For units using CEMS to monitor CO2 emissions and stack gas flow at a common stack,
or measuring fuel flow and characteristics at a common pipe for multiple units, the source could
group units that are ducted to that stack and similarly report the data elements in Table 13 as a
group as described for small units.
28
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January 30, 2009
6.2.2 Verification Data
If the mandatory GHG reporting rule relies on EPA verification, additional data would
have to be provided on the quantification methods to allow for EPA to perform its own offsite
verification review. No additional data would be needed for Acid Rain Program units since that
data is already provided to EPA. The Part 75 electronic reports provide hourly measurements as
well as quality assurance test results. For the tiered methods, the basic unit level reporting
requirement assists in emission verification. A potential verification is outlined below:
Tier 1 would require a check of the total quantity of each type of fuel combusted during
the report year.
For Tier 2, EPA could check emissions if the quantity of each type of fuel combusted
during each measurement period (day or month) is reported, along with all high heat
values used in the emission calculations, the methods used to determine the HHVs, and
flags indicating which HHVs (if any) are substitute data values.
Tier 3 data verification requirements are similar to Tier 2 with the addition of carbon
content values for each measurement period, and if required, fuel molecular weight. Fuel
flow meter calibrations could be reported to verify the data quality of the fuel
measurements.
For the CEMS based Tier 4 method, the number of unit operating days and hours could
be reported, along with daily CO2 mass emission totals, and substitute data hours. This is
similar to data reported in NSPS summary reports. The results of the initial CEMS
certification tests and the major on-going QA tests would be reported to verify data
quality. Units burning MSW could also be required to report the results of the quarterly
sample analyses used to determine the biogenic percentage of CO2 emissions, the annual
volumes of biogenic and fossil CO2, and the F-factors and fuel heat content values used
in the calculations.
Finally, units with acid gas scrubbing that do not use a CEMS could report the type and
amount of sorbent used.
7.0 References
Australian Department of Climate Change, Regulation Policy Paper, National Greenhouse and
Energy Reporting System, February 2008.
http://www.climatechange.gov.au/inventorv/methodologv/index.html
Australian Department of Climate Change, Overview Paper - Technical Guidelines for the
Estimation of Greenhouse Emissions and Energy at Facility-Level (Energy, Industrial Process,
and Waste Sectors in Australia), December 2007.
http://www.climatechange.gov.au/inventorv/methodologv/index.html
29
-------
January 30, 2009
California Air Resources Board (CARB), Attachment A: Modified Regulatory Language,
including Appendix A, Proposed Regulation for the Mandatory Reporting of Greenhouse Gas
Emissions as modified in May 2008. http://www.arb.ca. gov/regact/2007/ghg2007/ghg2007.htm
California Climate Action Registry (CCAR)
http ://www. climateregistrv. org/tools/protocols/ general-reporting-protocol. html
Canada Gazette, Vol. 142, No. 7, February 16, 2008, Notice with respect to reporting of
greenhouse gases (GHGs) for 2008.
http://canadagazette.gc. ca/partl/2008/20080216/html/notice-e.html#dl08
European Union, Emission Trading Scheme (ETS) - Guidelines for Monitoring and Reporting
Greenhouse Gas Emissions (Pursuant to Directive 2003/87/EC of the European Parliament and
of the Council), July 18, 2007. http://ec. europa. eu/environment/climat/emission/mrg en.htm
International Panel on Climate Change (IPCC), 2006 IPCC Guidelines for National Greenhouse
Gas Inventories, Vol. 3 (Provides methodologies for estimating national inventories of
anthropogenic emissions by sources and removals by sinks of greenhouse gases).
http://www.ipcc-nggip.iges.or.ip/public/2006gl/index.htm
Regional Greenhouse Gas Initiative (RGGI), Regional Greenhouse Gas Initiative Model Rule,
(Final with corrections), January 5, 2007. http://www.rggi.org/modelrule.htm
Shigehara, R. T., EMI, Inc., Memorandum to John Schakenbach, U.S. EPA Clean Air Markets
Division, January 8, 2008.
The Climate Registry (TCR), General Reporting Protocol of the Voluntary Reporting Program,
May 2008. http://www.theclimateregistrv.org/reference.html
U.S. Department of Energy (DOE), Technical Guidelines for the Voluntary Reporting of
Greenhouse Gases (1605(b)) Program, January 2007.
http://www.pi.energv.gov/enhancingGHGregistrv/technicalguidelines.html
U.S. Environmental Protection Agency, Greenhouse Gas Inventory Core Module Guidance,
Direct Emissions from Stationary Combustion Sources, May 2008, EPA430-K-08-003.
http://www.epa.gov/stateplv/resources/cross-sector.html
U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990 - 2006, April 2008, US EPA 430-R-08-005.
http://www.epa.gov/climatechange/emissions/usinventorvreport.html
U.S., Federal Register, Vol. 67, No. Ill, June 10, 2002, page 39602 - Consolidated Emissions
Reporting, Final Rule, http://www.epa.gov/ttn/chief/cerr/cerr.pdf
30
-------
January 30, 2009
U.S., Title 10, Code of Federal Regulations, Part 300 - Guidelines for Voluntary Greenhouse Gas
Reporting (Guidelines for the voluntary greenhouse gas reporting program under Section 1605b
of the Energy Policy Act of 1992).
http://www.pi.energy.gov/enhancingGHGregistrv/generalguidelines.html
U.S., Title 40, Code of Federal Regulations, Part 75 - Continuous Emission Monitoring
(Requirements for the monitoring, recordkeeping, and reporting of SO2, NOx, CO2, and Hg
emissions, volumetric flow, and opacity data from affected units under the Acid Rain Program,
NOx, mass and Hg emission reduction programs).
http://www.epa.gov/airmarkets/emissions/consolidated.html
U.S., Title 40, Code of Federal Regulations, Part 60 - Standards of Performance for New
Stationary Sources, http://www.epa. gov/lawsregs/search/40cfr.htm
31
-------
January 30, 2009
[This page intentionally left blank.]
32
-------
Appendix A
GHG Methods and Reporting
Reporting
IVogriim/
(i lliclitlK'C
1 uel
Monitoring Methods iind/or (II 1(1
(iilcuhilion Methods
Input Diitii
used to
Ciileuhile
emissions
(Source of
Diitii)
Miindiitorv or
\ 01 u nt ;< r>
Projtrsi 111/
Reporting
Requirement
Qiiiilily
Assurance/
Qiiiililv
Control
Procedures
IPC C or
WRI/WIK SI)
Klcmcnls
California
ARB
Mandatory
Reporting
Rule
(Proposed)
Biomass fuel,
municipal
waste
Use CEMS data if CEMS used is in compliance
with 40 CFR Parts 60 or 75; otherwise,
calculate emissions by measuring steam output
and combining with default emission factors. If
a mix of fossil and non-fossil fuels are burned,
C02 emissions are generally apportioned by
determining the fossil fuel C02 emissions using
a calculation method and subtracting from
CEMS total mass emissions; however, sources
that combust fuels or fuel mixtures that are at
least five percent biomass by weight and not
pure biomass, except waste-derived fuels that
are less than 30 percent biomass by weight of
total fuels combusted for the report year, shall
determine the biomass-derived portion of C02
emissions using ASTM D6866-06a. If using
CEMS, source must also monitor net energy
output. Use fuel consumption and default
emission factor based on measured or default
heat content to calculate CH4 and N20.
Stack gas
concentration
and flow
(CEMS
only), fuel
burned and
net energy
output.
Mandatory/Annual
reporting.
Third party
verification.
Uses some IPCC
emission factors,
requires third party
verification.
(cont.)
-------
GHG Methods and Reporting (cont.)
Reporting
IVognim/
(¦ u icl :i 11 co
1 uel
Monitoring Methods iind/or (II 1(1
C itlculitlioii Methods
Input Diitii
used to
Ciileuhile
emissions
(Source of
Miindiitorv or
\ 01 u nt ;< r>
Projtrsi 111/
Reporting
Requirement
Qiiiilily
Assurance/
Qiiiililv
Control
Procedures
IPC C or
WRI/WIK SI)
Klcmcnls
California
ARB
Mandatory
Reporting
Rule
(Proposed)
Refinery fuel
gas, other low
Btu gases
Use CEMS data if CEMS used is in compliance
with 40 CFR Parts 60 or 75; otherwise calculate
emissions using daily gas consumption, and
carbon content or heat content for each fuel gas
that is measured daily or weekly based on
refinery size. Refinery gas carbon content is
calculated three times per day (every eight
hours) and flexi-coker gas, once per day. May
use in-line continuous monitor for carbon
content. For CH4 and N20, use fuel
consumption and a default emission factor
based on measured heat content if available, or
default heat content. If using CEMS, must also
monitor net energy output. Use fuel
consumption and default emission factor based
on measured or default heat content to calculate
CH4 and N20.
Stack gas
concentration
and flow
(CEMS
only), fuel
burned and
net energy
output.
Mandatory/Annual
reporting
Third party
verification.
Uses some IPCC
emission factors,
requires third party
verification.
(cont.)
-------
GHG Methods and Reporting (cont.)
Reporting
I'rognim/
(i uid
-------
GHG Methods and Reporting (cont.)
Reporting
I'rognim/
(i uid
-------
GHG Methods and Reporting (cont.)
Reporting
I'rognim/
(i iiiiliincc
1 uel
Monitoring Methods iind/or (II 1(1
C'iik-iihition Methods
Input Diitii
used to
Ciilciihile
emissions
(Source of
Diitii)
Miindiitorv or
Voluntary
Projtrsi m/
Reporting
Requirement
Qiiiility
Assurance/
Qiiiility
Control
Procedures
IPC C or
WRI/WIK SI)
Klements
The Climate
Registry
(TCR)
All fuels
Use CEMS data if measured in accordance with
40 CFR Part 75; otherwise calculate emissions.
Preferably measure each unit's fuel use, but may
use purchase records. Measure fuel heat and
carbon content on a frequency determined by
fuel variability to develop emission factors.
May also use default fuel-based emission
factors. Optional method for CHP facilities to
apportion emissions to electric and heat output.
To calculate CH4 and N20 emissions, multiply
fuel burned by a default emission factor.
CEMS data
or fuel
burned.
Voluntary/Annual
reporting.
Third party
verification.
Uses IPCC tier
approach for
measurement
methods, and
requires third party
verification.
Accounting and
reporting principles
are consistent with
the WR1/WBCSD
Protocol Initiative;
the inventory quality
guidance is from the
WRI/WBCSD GHG
Protocol Corporate
Standard (Revised
Edition), Chapter 7.
Chicago
Climate
Exchange
(CCX)
All fuels
Use CEMS data, or calculate emissions using
CCX and WR1/WBCSD protocols.
CEMS data
or fuel
burned.
Voluntary/Annual
reporting.
Third party
verification.
Uses WRI/WBCSD
measurement
protocols and
emission factors.
(cont.)
-------
GHG Methods and Reporting (cont.)
Reporting
IVognim/
(¦ u icl :i 11 co
1 ucl
Monitoring Methods iind/or (II 1(1
C itlculitlioii Methods
Input Diitii
used to
c;ilcul;ile
emissions
(Source of
l):itii)
Miindiitorv or
\ olunliirv
I'rogmm/
Reporting
Requirement
Qiiiilily
Assurance/
Qiiiililv
Control
Procedures
IPC C or
WRI/WIK SI)
Klcmcnls
Regional
Greenhouse
Gas
Initiative
(RGGI)
Biomass
(does not
include
biomass
mixed with
other waste)
Use 40 CFR Part 75, and include additional
biomass fuel and net energy output monitoring
measurements. Biofuel measurements include:
1) sampling and analysis of each shipment
received for carbon content, heating value, and
moisture content; 2) mass or volumetric
measurement of fuel burned; and 3) operating
hours. Sampling and analysis should be done
per methods in the New York State Renewable
Energy Portfolio Standard Biomass Guidebook,
May 2006. As-fired biomass C02 emissions
shall be the lower of the CEMS when biomass
fired alone, or calculation method when
combined with other fuels.
Same as 40
CFR Part 75
plus net
energy
output.
Mandatory/Quarterly
reporting.
As required by
40 CFR Part 75.
No.
Regional
Greenhouse
Gas
Initiative
(RGGI)
Fossil fuels
Use 40 CFR Part 75, plus net energy output
monitoring.
Same as 40
CFR Part 75
plus net
energy
output.
Mandatory/Quarterly
reporting.
As required by
40 CFR Part 75.
No.
Regional
Greenhouse
Gas
Initiative
(RGGI)
Natural gas,
fuel oil,
refinery fuel
gas, blast
furnace gas,
other fossil
fuel derived
gases
Use 40 CFR Part 75, plus net energy output
monitoring.
Same as 40
CFR Part 75
plus net
energy
output.
Mandatory/Quarterly
reporting.
As required by
40 CFR Part 75.
No.
(cont.)
to
o
o
VO
-------
GHG Methods and Reporting (cont.)
Reporting
IVognim/
(¦ u icl :i 11 co
1 uel
Monitoring Methods iind/or (II 1(1
(iilcuhition Methods
Input Diilii
used to
Ciilciihite
emissions
(Source of
l):it
Projtrsi 111/
Reporting
Requirement
Qiiiility
Assurance/
Qiiiility
Control
Procedures
IPC C or
WRI/WIK SI)
Klements
U.S. DOE
1605(b)
Biomass fuel,
municipal
waste, other
waste
Use CEMS emissions data or calculate
emissions using fuel burned based on measured
purchases or consumption. May use measured,
contractual, or default calorific values (GCV).
Default emission factors may be used from
AP42 or IPCC Revised Guidelines. Do not
calculate C02 emissions for biomass fuels;
estimate biomass fraction of municipal solid
waste or landfill gas by sampling and analysis
or using EIA default factors.
Fuel burned.
Voluntary/Annual
reporting. Do not
report biomass C02
emissions.
No
requirement.
Uses IPCC Revised
Guidelines as a
source of emission
factors.
U.S. DOE
1605(b)
Refinery fuel
gas
Calculate mass emissions using fuel burned
based on measured purchases or consumption.
Use EIA default emission factors for refinery
gas or develop C02 emission factor based on
gas analysis.
Fuel burned.
Voluntary/Annual
reporting.
No
requirement.
Uses IPCC Ordinal
rating system for
emissions
calculations.
U.S. DOE
1605(b)
Fuel Oil
Use CEMS emissions data or calculate
emissions using fuel burned based on measured
purchases or consumption. May use measured,
contractual, or default calorific values (GCV)
provided in the guidelines by oil type.
Fuel burned.
Voluntary/Annual
reporting.
No
requirement.
Uses IPCC Ordinal
rating system for
emissions
calculations.
(cont.)
-------
GHG Methods and Reporting (cont.)
Reporting
IVognim/
(¦ u icl :i 11 co
1 uel
Monitoring Methods iind/or (II 1(1
(iilcuhition Methods
Input Diilii
used to
Ciilciihite
emissions
(Source of
l):it
Projtrsi 111/
Reporting
Requirement
Qiiiility
Assurance/
Qiiiility
Control
Procedures
IPC C or
WRI/WIK SI)
Klements
U.S. DOE
1605(b)
Coal,
petroleum
coke
Use CEMS data if CEMS used is in compliance
with 40 CFR Part 75; otherwise, do a mass
balance calculation. For the coal mass balance
calculation, use fuel burned, carbon content,
and fraction combusted to calculate emissions.
For the petroleum coke mass balance equation,
use measured consumption and actual carbon
content based on periodic samples if available;
otherwise, use consumption estimates and/or
default emissions factors. To calculate CH4 and
N20 emissions, multiply fuel burned by a
default emission factor (factors prepared by
EPA and IPCC).
Fuel burned,
carbon
content, and
fraction
combusted
and/or default
emissions
factors.
Voluntary/Annual
reporting.
No
requirement.
Uses IPCC Ordinal
rating system for
emissions
calculations.
U.S. DOE
1605(b)
Natural gas
Calculate mass emissions using fuel burned
based on measured purchases or consumption,
measured, contractual, or default calorific
values (GCV), and default emission factors.
Reporters burning natural gas with a Btu
content < 975 Btu/scf or >1,100 Btu/scf should
develop an emission factor based on gas
analysis.
Fuel burned.
Voluntary/Annual
reporting.
No
requirement.
Uses IPCC Ordinal
rating system for
emissions
calculations.
(cont.)
-------
GHG Methods and Reporting (cont.)
Reporting
IVognim/
(¦ u icl :i 11 co
1 uel
Monitoring Methods iind/or (II 1(1
(iilcuhition Methods
Input Diilii
used to
Ciilciihite
emissions
(Source of
l):it
Projtrsi 111/
Reporting
Requirement
Qiiiility
Assurance/
Qiiiility
Control
Procedures
IPC C or
WRI/WIK SI)
Klements
U.S. EPA 40
CFR Part 75
Refinery fuel
gas, blast
furnace gas,
other fossil
fuel derived
gases
Use a C02 or 02 diluent CEMS and a stack flow
monitor, or calculate mass emissions using
daily or hourly fuel sampling for GCV and
carbon content (monthly if fuel demonstrates
low GCV variability), and fuel flow monitoring.
May use an on-line GCV calorimeter or gas
chromatograph. Use carbon content (or GCV
and F-factor) combined with daily mass fuel
flow to calculate daily emissions.
Stack gas
concentration
and flow
(CEMS only)
or fuel
burned and
carbon
content or
hourly heat
input or
defaults.
Mandatory/Quarterly
reporting.
Monitoring
plan,
performance
specifications,
certification
and on-going
quality
assurance test
requirements.
No.
U.S. EPA 40
CFR Part 75
Fuel Oil
Use a C02 or 02 diluent CEMS and a stack flow
monitor, or calculate mass emissions using one
of three methods: 1) sample each fuel oil
shipment or delivery, and measure fuel flow; 2)
use the percent carbon content (or fuel GCV
and F-factor) and mass fuel flow; or 3) use an
F-factor and hourly heat input.
Stack gas
concentration
and flow
(CEMS only)
or fuel
burned and
carbon
content or
hourly heat
input or
defaults.
Mandatory/Quarterly
reporting.
Monitoring
plan,
performance
specifications,
certification,
and on-going
quality
assurance test
requirements.
No.
(cont.)
-------
GHG Methods and Reporting (cont.)
Reporting
IVognim/
(¦ u icl :i 11 co
1 uel
Monitoring Methods iind/or (II 1(1
(iilcuhition Methods
Input Diilii
used to
Ciilciihite
emissions
(Source of
l):it
Projtrsi 111/
Reporting
Requirement
Qiiiility
Assurance/
Qiiiility
Control
Procedures
IPC C or
WRI/WIK SI)
Klements
U.S. EPA 40
CFR Part 75
Coal,
petroleum
coke
Use a C02 or 02 diluent CEMS and a stack flow
monitor, or calculate mass emissions using fuel
sampling for percent carbon content (or fuel
GCV and F-factor) and fuel flow monitoring for
mass fuel flow.
Stack gas
concentration
and flow
(CEMS only)
or fuel
burned and
carbon
content or
hourly heat
input or
defaults.
Mandatory/Quarterly
reporting.
Monitoring
plan,
performance
specifications,
certification
and on-going
quality
assurance test
requirements.
No.
U.S. EPA 40
CFR Part 75
Natural gas
Use a C02 or 02 diluent CEMS and a stack flow
monitor, or calculate mass emissions using fuel
sampling for percent carbon content (or fuel
GCV and F-factor) and fuel flow monitoring for
mass fuel flow.
Stack gas
concentration
and flow
(CEMS only)
or fuel
burned and
carbon
content or
hourly heat
input or
defaults.
Mandatory/Quarterly
reporting.
Monitoring
plan,
performance
specifications,
certification
and on-going
quality
assurance test
requirements.
No.
-------
GHG Methods and Reporting (cont.)
Reporting
IVognim/
(¦ u icl :i 11 co
1 uel
Monitoring Methods iind/or (II 1(1
C itlculitlioii Methods
Input Diitii
used to
Ciilciihile
emissions
(Source of
Miindiitorv or
\ 01 u nt ;< r>
Projtrsi 111/
Reporting
Requirement
Qiiiilily
Assurance/
Qiiiililv
Control
Procedures
IPC C or
WRI/WIK SI)
Klcmcnls
U.S. EPA
Climate
Leaders
Biomass fuel,
municipal
waste, other
waste
Use CEMS data if measured in accordance with
40 CFR Part 75; otherwise, use calculation
method based on fuel use and emission factors.
Sample and analyze waste fuels to determine
waste fuel emission factors instead of provided
default factors when possible. Part 75 units
should use Part 75 non-CEMS methods (found
in Appendix G). Other units should collect the
amount of fuel burned, and use supplier or
sampled energy content data.
CEMS data
or fuel
burned.
Voluntary/Annual
reporting.
EPA review or
third party
verification.
CEMS should
be quality
assured per 40
CFR Part 75.
Uses IPCC third
party verification
concept. Uses
WRI/WBCSD
measurement
protocols and
emission factors.
U.S. EPA
Climate
Leaders
All
commercial
fossil fuels
Use CEMS or non-CEMS (Appendix G) data if
measured/calculated in accordance with 40 CFR
Part 75; otherwise, use a calculation method
based on fuel burned, the heating value of fuel
(energy content), and emission factors. To
calculate CH4 and N20 emissions, multiply fuel
burned by U.S. EPA fuel-type and sector-
specific default factors.
CEMS data
or fuel
burned with
heating value
of fuel.
Voluntary/Annual
reporting.
EPA review or
third party
verification.
CEMS should
be quality
assured as
required by 40
CFR Part 75.
Uses IPCC third
party verification
concept. Uses
WRI/WBCSD
measurement
protocols and
emission factors.
-------
GHG Methods and Reporting (cont.)
Reporting
I'rogmm/
(¦ u icl :i 11 co
1 uel
Monitoring Methods iind/or (II 1(1
C itlculitlioii Methods
Input Diitii
used to
Ciilciihite
emissions
(Source of
Miindiitorv or
\ 01 u nt ;< r>
Projtrsi 111/
Reporting
Requirement
Qiiiility
Assurance/
Qiiiility
Control
Procedures
IPC C or
WRI/WIK SI)
Klcmcnls
Australian
National
GHG and
Energy
Reporting
System
(Proposed)
Fossil and
non-fossil
fuels
Use CEMS data or a calculation method
according to following tier protocol: the
highest quality, Tier 1, uses CEMS; Tier 2
calculates emissions using an emission factor
based on direct sampling and analysis
conforming to Australian standards or
equivalent; Tier 3 calculates emissions using an
emission factor based on a representative bias
free method but not conforming to a standard;
and the least stringent, Tier 4, uses default
emission factors.
Fuel burned.
Mandatory/Annual
reporting.
Estimation of
facility-specific
emission
factors should
be conducted in
accordance
with existing
recognized
standards
(Australian,
ISO, ASTM).
Measurement
approaches are rated
in a manner similar
to IPCC tiers, and
third party audits are
required. Emission
categories based on
WRI/WBCSD
(Scope 1 direct,
Scope 2 indirect,
Scope 3 indirect).
Canadian
GHG
National
Reporting
Program
Fossil fuels,
Biomass fuels
CEMS may be used for C02 when a C02
diluent monitor is installed for measurements of
other pollutants. Calculation methods: 1)
reference Annex FCCC/CP/2002/8, IPCC
Inventory Guidelines and Good Practices; 2)
measure facility or unit fuel consumed; and 3)
use an emission factor (default or source
derived). These are Tier 3 (IPCC) approaches.
Biomass C02 emissions must be separated if
blended fuels are burned.
Fuel burned,
or stack gas.
Mandatory/Annual
reporting.
Use standard
measurement
methods (e.g.,
ISO methods),
calibrate and
maintain
measurement
equipment, and
have a QA/QC
process that
enables
verification.
Requires
methodologies in
UNFCCC Decision
18/CP.8 and Annex
FCCC/CP/2002/8,
which reference
Inventory Guidelines
and Good Practices.
(cont.)
-------
GHG Methods and Reporting (cont.)
Reporting
IVognim/
(¦ u icl :i 11 co
1 uel
Monitoring Methods iind/or (II 1(1
(iilcuhition Methods
Input Diilii
used to
Ciilcuhite
emissions
(Source of
l):it
Projtrsi 111/
Reporting
Requirement
Qiiiility
Assurance/
Qiiiility
Control
Procedures
IPC C or
WRI/WIK SI)
Klements
EU
Emissions
Trading
Scheme
Biomass fuel
(non-
fossilized and
biodegradable
organic
material
originating
from plants,
animals, and
micro-
organisms:
specifically
identifies
fuels in
guidelines)
Emissions are determined using a mass balance
approach. Fuel consumption for blended fuels
is determined with a maximum uncertainty of 5
- 1.5%, based on facility size, which is similar
to fossil fuels. Activity or fuel content
measurements must be done using a
standardized method that limits sampling and
measurement bias and has a known level of
uncertainty. Pure biomass source streams (<3%
non-biomass) may use non-tier methods, and
have an emission factor of zero. Mixed fuel
streams (biomass and fossil) shall identify the
biomass portion through approved sampling
methods using CEN, ISO, or national standards.
A biomass portion uses a zero emission factor.
If determination of the biomass portion is not
feasible, assume 100% fossil. Sources may use
C02 CEMS combined with a stack flow
monitor or a mass balance flow determination if
they can demonstrate that CEMS achieves
greater accuracy than the highest tier
calculation approach; the methodology must
apportion the biomass fraction of CEMS
emissions. The CEMS methodology also
requires verification against a mass-balance
estimate.
Fuel burned
and heat
content from
fuel supplier
or derived
from operator
measurement.
Mandatory/Annual
reporting.
Accreditation
according to
EN ISO 17025;
third party
verification.
Applies monitoring
method uncertainty
tiers similar to IPCC
based on facility size
(emissions), uses
IPCC emission
factors, and requires
third party
verification.
(cont.)
-------
GHG Methods and Reporting (cont.)
Reporting
IVognim/
(¦ u icl :i 11 co
1 uel
Monitoring Methods iind/or (II 1(1
(iilcuhition Methods
Input Diilii
used to
Ciilcuhite
emissions
(Source of
l):it
Projtrsi 111/
Reporting
Requirement
Qiiiility
Assurance/
Qiiiility
Control
Procedures
IPC C or
WRI/WIK SI)
Klements
EU
Emissions
Trading
Scheme
Solid fuel and
non-
commercial
gaseous or
liquid fuels
Emissions are determined using a mass balance
calculation approach. Fuel consumption is
determined with a maximum uncertainty of 5 -
1.5%, based on facility size. Heat content is
measured by the operator or contracted
laboratory, and the sampling procedure and
frequency are designed to ensure that the annual
average has a maximum uncertainty of less than
1/3 of the maximum uncertainty required by the
approved activity data tier level. Country
specific emission factors may be used for
sources with C02 < 500,000 tonnes/year.
Sources may use C02 CEMS combined with a
stack flow monitor or a mass balance flow
determination to calculate mass emissions if
they can demonstrate that CEMS achieves
greater accuracy than the highest tier
calculation approach. The CEMS methodology
also requires performing supplementary
calculations or a mass balance-based emissions
estimate to compare with CEMS results.
Fuel burned
and heat
content
derived from
operator
measurement
or default
factors.
Mandatory/Annual
reporting.
Accreditation
according to
EN ISO 17025;
third party
verification.
Applies monitoring
method uncertainty
tiers similar to IPCC
based on facility size
(emissions), uses
IPCC emission
factors, and requires
third party
verification.
(cont.)
-------
GHG Methods and Reporting (cont.)
Reporting
IVognim/
(¦ u icl :i 11 co
1 uel
Monitoring Methods iind/or (II 1(1
(iilcuhition Methods
Input Diilii
used to
Ciilciihite
emissions
(Source of
l):it
Projtrsi 111/
Reporting
Requirement
Qiiiility
Assurance/
Qiiiility
Control
Procedures
IPC C or
WRI/WIK SI)
Klements
EU
Emissions
Trading
Scheme
Commercial
gaseous and
liquid fuels
Emissions are determined using a mass balance
calculation approach. Fuel consumption is
determined with a maximum uncertainty of 5 -
1.5%, based on facility size. NCV is provided
by the fuel supplier, provided it is based on
accepted standards, or determined using country
specific factors as reported in latest UNFCCC
inventory. Emission factors are country
specific or derived based on measurements
using a standardized method that limits
sampling and measurement bias and has a
known level of uncertainty. Sources may use
C02 CEMS combined with a stack flow
monitor or a mass balance flow determination
to calculate mass emissions if they can
demonstrate that CEMS achieves greater
accuracy than the highest tier calculation
approach. The CEMS methodology also
requires performing supplementary calculations
or a mass balance-based emissions estimate to
compare with CEMS results.
Fuel burned
and heat
content from
fuel supplier
or derived
from operator
measurement.
Mandatory/Annual
reporting.
Accreditation
according to
EN ISO 17025;
third party
verification.
Applies monitoring
method uncertainty
tiers similar to IPCC
based on facility size
(emissions), uses
IPCC emission
factors, and requires
third party
verification.
-------
January 30, 2009
[This page intentionally left blank.]
A-16
-------
January 30, 2009
Appendix B
Part 75 F- and Fc- Factors1
(from Appendix F, Table 1)
1 lid
1-"-I'iiclor
(ilsc 17in in lit ii)
I", -I'iiclor
(scf C ();/lllllll}lll)
Coal (as defined by ASTM D3 88-992):
Anthracite
10,100
1,970
Bituminous
9,780
1,800
Subbituminous
9,820
1,840
Lignite
9,860
1,910
Petroleum Coke
9,830
1,850
Tire Derived Fuel
10,260
1,800
Oil
9,190
1,420
Gas:
Natural gas
8,710
1,040
Propane
8,710
1,190
Butane
8,710
1,250
Wood:
Bark
9,600
1,920
Wood residue
9,240
1,830
1 Determined at standard conditions: 20 °C (68 °F) and 29.92 inches of mercury.
2 Incorporated by reference under 40 CFR 75.6.
Municipal Solid Waste F- and Fc- Factors1
(from Part 60, Appendix B, Method 19, Table 19-2)
1 ucl
1"-I'iiclor
(else 17in in lit ii)
I ", - I'iiclor
(scl(():/iiiinl}ni)
Municipal Solid Waste
9,570
1,820
1 Determined at standard conditions: 20 °C (68 °F) and 29.92 inches of mercury.
B-l
-------
January 30, 2009
[This page intentionally left blank.]
B-2
-------
January 30, 2009
Appendix C
Default CO2 Emission Factors and High Heat Values for Various Types of Fuel
l-uel Type
( oiil iiiid Coke
Doliiiill lli»h llcsil Vsilue
111111 lilu/shori ion
Doliiiill CO: Kmission
Tiiclor
ku ( (Win 111 lilu
Anthracite
25.09
103.54
Bituminous
24.93
93.40
Sub-bituminous
17.25
97.02
Lignite
14.21
96.36
Unspecified (Residential/Commercial)
22.24
95.26
Unspecified (Industrial Coking)
26.28
93.65
Unspecified (Other Industrial)
22.18
93.91
Unspecified (Electric Power)
19.97
94.38
Coke
24.80
102.04
Niilui'iil Ciiis
111111 ISlii/scI'
ku ( (Will 111 lilu
I ns|xvilial 1 Wei di led 1 S \\erauei
IVlrok-11111 Products
1 o:_\ iu
111111 lilu/iM lion
5' u:
k}» (O^/niin l$l 11
Asphalt & Road Oil
0.158
75.55
Aviation gasoline
0.120
69.14
Distillate Fuel Oil (# 1, 2, & 4)
0.139
73.10
Jet Fuel
0.135
70.83
Kerosene
0.135
72.25
LPG (energy use)
0.092
62.98
Propane
0.091
63.02
Ethane
0.069
59.54
Isobutane
0.099
65.04
(cont.)
C-l
-------
January 30, 2009
Default CO2 Emission Factors and High Heat Values for Various Types of Fuel (cont.)
I'ucl Type
Delimit lli»h 1 kill Vsiluc
Default CO: Kinission
I'iiclor
Petroleum Products (com.)
111111 ISlu/uiilloii
k«i ( (WmniBlii
n-Butane
0.103
64.93
Lubricants
0.144
74.16
Motor Gasoline
0.124
70.83
Residual Fuel Oil (# 5 & 6)
0.150
78.74
Crude Oil
0.138
74.49
Naphtha (< 401 deg. F)
0.125
66.46
Natural Gasoline
0.110
66.83
Other Oil (> 401 def. F)
0.139
73.10
Pentanes Plus
0.110
66.83
Petrochemical Feedstocks
0.129
70.97
Petroleum Coke
0.143
102.04
Special Naphtha
0.125
72.77
Unfinished Oils
0.139
74.49
Waxes
0.132
72.58
Biom;iss-dcri\cd l-'ucls (solid)
111111 Blu/shorl Ion
kii ( O^/ni in l$l 11
Wood and Wood waste (12% moisture
content) or other solid biomass-derived fuels
15.38
93.80
Biom;iss-dcri\cd l-'ucls ((>:is)
111111 ISlii/scI'
kii ("(Will 111 Bin
Biogas
Varies
52.07
Note: Heat content factors are based on higher heating values (HHV). Also, for petroleum products, the default heat
content values have been converted from units of mmBtu per barrel to mmBtu per gallon.
Sources: U.S. EPA, Inventory of Greenhouse Gas Emissions and Sinks: 1990-2005 (2007), Annex 2.1,Tables A-28,
A-31, A-32, A-35, and A-36, except: Heat Content factors for Unspecified Coal (by sector),Coke, Naphtha (<401
deg. F), and Other Oil (>401 deg. F) (from U. S. Energy Information Administration, Annual Energy Review 2005
(2006), Tables A-l, A-4, and A-5); Heat Content factors for Coal (by type) and LPG and all factors for Wood and
Wood Waste, Landfill Gas, and Wastewater Treatment Biogas (from EPA Climate Leaders, Stationary Combustion
Guidance (2004), Tables B-l and B-2).
C-2
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