CLIMATE LEADERS GREENHOUSE GAS INVENTORY PROTOCOL
CORE MODULE GUIDANCE
Indirect Emissions from
Purchases/Sales of
Electricity and Steam
CLIMATED
U.S. Environmental Protection Agency
October 2OO4
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The Climate Leaders Greenhouse Gas Inventory Protocol is based on the Greenhouse Gas Protocol (GHG Protocol)
developed by the World Resources Institute (WRI) and the World Business Council for Sustainable Development
(WBCSD). The GHG Protocol consists of a corporate accounting and reporting standard and separate calculation
tools. The Climate Leaders Greenhouse Gas Inventory Protocol is an effort by EPA to enhance the GHG Protocol to fit
more precisely what is needed for Climate Leaders. The Climate Leaders Greenhouse Gas Protocol consists of the fol-
lowing components:
• Design Principles Guidance
• Core Modules Guidance
• Optional Modules Guidance
All changes and additions to the GHG Protocol made by Climate Leaders are summarized in the Climate Leaders
Greenhouse Gas Inventory Protocol Design Principles Guidance.
For more information regarding the Climate Leaders Program, visit us on the web at www.epa.gov/climateleaders
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Purchases/Sales of Electricity and Steam —
Guidance
1. Introduction 1
1.1. Non-Utility Sales of Electricity or Steam 1
1.2. Utility Reporting of Purchased Electricity or Steam 1
1.3. Emissions of CO2 versus CH4 and N2O for Purchases/Sales of Electricity and Steam 1
2. Methods for Estimating Emissions 3
2.1. Estimating Emissions from Purchased Electricity 3
2.2. Estimating Emissions from Purchased Steam 4
2.3. Estimating Emissions from Sales of Electricity and/or Steam 6
2.4. Allocating Emissions from a Co-Generation Facility to Separate
Electricity and Steam Outputs 7
3. Choice of Activity Data and Emissions Rates 1O
3.1. Activity Data 10
3.2. Emission Rates 10
3.2.1. Electricity Purchases 10
3.2.2. Steam Purchases 12
4. Completeness 13
5. Uncertainty Assessment 14
6. Reporting and Documentation 15
7. Inventory Quality Assurance and Quality Control 16
Appendix A: Example of Co-Generation
Allocation Methods 17
Appendix B: eGRID Subregion Emission Rates 2O
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Purchases/Sales of Electricity and Stea
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Introduction
Indirect emissions are those that result from
a Climate Leaders Partner's activities, but
are actually emitted from sources owned
by other entities. A major source of indirect
emissions occurs through the use of purchased
electricity or steam. Carbon dioxide (C02),
methane (CH4), and nitrous oxide (N20) are
emitted to the atmosphere as fossil fuels are
burned to produce heat and power. Therefore,
manufacturing operations and other activities
that use purchased electricity or steam indi-
rectly cause emissions of greenhouse gases
(GHG). The resulting emissions depend on the
amount of energy used and the mix of fuel that
goes into producing this electricity or steam.
EPA requires that Partners report the indirect
emissions associated with their use of pur-
chased steam and electricity. This document
presents guidance on estimating GHG indirect
emissions resulting from these sources. This
module also provides guidance on reporting
emissions from the sales of steam and electrici-
ty by non-utilities.
1.1. Non-Utility Sales
of Electricity or Steam
Manufacturing or processing facilities can have
onsite power plants that produce electricity
and/or steam to meet the demand of that facili-
ty. If there is excess capacity, the facility may
sell a portion of the electricity and/or steam
output to another company directly or to the
grid. Non-utility Partners' facilities (where heat
or power is not the primary output of the facili-
ty) that sell excess electricity and/or steam
report the emissions from producing the
electricity and/or steam as direct emissions.
This is done using the Climate Leaders guid-
ance for Direct Emissions from Stationary
Combustion Sources. The facility could also
report the emissions associated with the heat
or power sales as supplemental information in
their Climate Leaders inventory. The emissions
from energy sales are not included when
calculating a Partner's progress towards their
Climate Leader's normalized GHG reduction
goal. See the Climate Leaders Reporting
Requirements for more discussion on how this
is done.
1.2. Utility Reporting
of Purchased
Electricity or Steam
Electric utilities, like other entities, may also
need to purchase electricity or steam. This
heat or power could be sold for resale, sold to
end-users, or consumed at owned offices or
through transmission and distribution losses.
This guidance is for non-utilities only, separate
guidance for utilities is being developed.
1.3. Emissions of CO2
versus CH4 and N2O
for Purchases/Sales of
Electricity and Steam
Although C02, CH4, and N20 are all emitted
during the combustion of fossil fuels to pro-
duce electricity, C02 accounts for the majority
of all greenhouse gas emissions. In the U.S.,
C02 emissions represent over 99.5% of the
total CO^equivalent1 GHG emissions from fuels
combusted for electricity production, with CH4
and N20 together representing less than 0.5%
of the total emissions from the same sources2.
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Purchases/Sales of Electricity and Stea
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As with direct emissions from stationary
combustion sources, Partners should account
for all C02, CH4 and N20 emissions associated
with purchases of electricity and steam3. C02
emissions calculations are fairly straightfor-
ward while CH4 and N20 emissions are not as
easy to characterize, as explained in Section
1.1 of the Climate Leaders guidance for Direct
Emissions from Stationary Combustion Sources.
Given the relative emissions contributions
of each gas, CH4 and N20 emissions are often
excluded by assuming that they are not
material. However, as outlined in Chapter 1
of the Climate Leaders Design Principles, the
materiality of a source can only be established
after it has been assessed. This does not nec-
essarily require a rigorous quantification of all
sources, but at a minimum, an estimate based
on available data should be developed for all
sources and categories of greenhouse gases.
Therefore, this guidance provides information
on estimating C02 as well as CH4 and N20
emissions from purchases of steam and/or
electricity.
1 See Chapter 6 of the Climate Leaders Design Principles document for a discussion of C02-equivalents.
2 Tables 3-3, 3-14, & 3-15 of U.S. EPA 2004 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2002, EPA430-R-04-003.
3 Emissions of SF6 are associated with transport of electricity. However, SF6 emissions are considered outside the scope of indirect
emissions from electricity purchases. SF6 emissions are reported as direct emissions for owners of transmission and distribution
lines. It is also assumed that SF6 emissions are not directly affected by the total amount of electricity transmitted.
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Purchases/Sales of Electricity and Steam
Guidance
Methods for Estimating
Emissions
This section addresses the estimation
of GHG emissions from purchased and
sold electricity and steam. Both the
purchase and sales of electricity and steam
across Partner corporate boundaries should
be accounted for using these methods. Since a
variety of fuels may be used to generate elec-
tricity and steam, emission factors can vary
greatly. The preferred method for estimating
emissions is to use a source or facility-specific
approach ("bottom-up" approach) e.g., first
estimating the electricity purchases by facility
then summing across facilities to get the
Partner's total emissions. See Chapter 9 of the
Climate Leaders Design Principles for more
detail on reporting requirements.
Sections 2.1 through 2.3 present an overview
of the different methods that can be used to
calculate GHG emissions from electricity and
steam purchases and sales. Emissions from co-
generation sources are outlined in Section 2.4.
2.1. Estimating
Emissions from
Purchased Electricity
For electricity purchases from the grid
or through a direct contract, emissions are
estimated by multiplying the purchased elec-
tricity by average emission rates. Equation 1
describes the approach for estimating emis-
sions from purchased electricity.
The steps involved with estimating emissions
from consumption of purchased electricity are
shown below.
Step 1: Estimate amount of electricity pur-
chased. Utility bills or other records should
be used to provide the amount of purchased
electricity.
Emissions
where:
Emissions
EP
Equation 1: Estimating GHG Emissions from
Electricity Purchases
EP x ERate,
Emissions of gas i (mass)
Electricity purchased and consumed on-site (e.g., MWh)
Gas i emissions rate for electricity purchased
(e.g.,
mass CO
2
MWh
mass CH4
MWh
,or
mass N20
MWh
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Step 2: Determine emission rates. The
approach used by Climate Leaders is to
calculate electricity use emissions based on
average emission rates that best represent
the electricity actually purchased. The
recommended approach is to use emission
rates provided by the supplier. If they are
not available or if accuracy is unknown,
there are a number of published electricity
production emission rates with varying
degrees of accuracy as discussed in Section
3.2.1. Emission rates are typically provided
in terms of mass per energy unit (e.g., kWh,
MWh, Joules, etc.). If the electricity is pur-
chased from a co-generation facility, the
emission rates should represent only the
electricity produced at the facility, as
described in Section 2.4.
Step 3: Estimate emissions. To estimate
emissions, multiply purchased electricity
(e.g., MWh) by the appropriate emission
rate (e.g., mass C02/MWh).
2.2. Estimating
Emissions from
Purchased Steam
The preferred method for calculating emissions
associated with steam purchases is to use
emission factors obtained directly from the
steam suppliers. However, if factors are not
available, emissions can be calculated based
on assumed boiler efficiency, fuel mix, and fuel
emissions factors. Equation 2 describes the
approach for estimating emissions from pur-
chased steam based on factors provided by the
supplier.
The steps involved with estimating emissions
from consumption of purchased steam with the
emission factor approach are shown below.
Step 1: Estimate amount of steam purchased.
Utility bills or other records should be used
to provide amount of purchased steam (in
terms of energy, mass, or volume).
Emissions)
where:
Emissions)
SP
SRate,
Equation 2: Estimating GHG Emissions from
Steam Purchases Based on Factors
SP x SRate,
Emissions of gas i (mass)
Steam purchased and consumed on-site (energy, mass, or volume)
Gas i emissions rate for steam purchased
mass COo
mass
, or
mass N20
energy, mass, or volume energy, mass, or volume energy, mass, or volume
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Step 2: Determine emission rates. In this case,
emission rates are provided by the supplier
in terms of mass per unit of energy, mass,
or volume of steam depending on the units
used in Step 1. If the steam is purchased
from a co-generation facility, the emission
rates should represent only the steam
produced at the facility, as described in
Section 2.4.
Step 3: Estimate CO2 emissions. To estimate
emissions, multiply steam purchases (ener-
gy, mass, or volume) by the appropriate
emission factor (e.g., mass C02/ energy,
mass, or volume).
If emissions factors are not specifically known
for steam production, the emissions can be
calculated based on assumed boiler efficiency,
fuel mix, and fuel emissions factors. Equation 3
describes the approach for estimating emis-
sions from purchased steam based on this
approach.
The steps involved with estimating emissions
from consumption of purchased steam with the
boiler efficiency approach are shown below. If
steam is purchased from a co-generation facili-
ty it is recommended that Partners use the
previous approach, based on emission rates
provided by the supplier.
Step 1: Estimate the amount of steam
purchased. Utility bills or other records
should be used to provide the quantity of
purchased steam (in terms of energy). If
records are provided as mass or volume (or
dollars) they should be converted to energy
content of the steam.
Step 2: Calculate fuel energy input to produce
the steam. Divide the steam purchased (in
energy units) by the assumed efficiency of
typical steam production in a boiler to
derive total fuel input needed (energy
units). The steam supplier should be able to
provide this efficiency. If no value is avail-
able, a default of 80% can be used.
Step 3: Determine the fuel mix used to
produce the steam. Emission factors are
dependent on the mix of fuel burned to gen-
erate purchased steam. The steam supplier
should supply fuel mix data, if possible. The
Emissions)
where:
Emissions)
SP
BF
Equation 3: Estimating GHG Emissions from
Steam Purchases Based on Efficiency
SP
BF
x FSF
Emissions of gas i (mass)
Steam purchased and consumed on-site (energy)
(steam energy^
— ; I
fuel energy J
r . , , .,. , . f mass C09 mass CFL
Gas i fuel specific factor I L. i-
VJuel
or
mass N20 ~\
energy fuel energy fuel energyJ
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fuel mix data can then be used to calculate
the amount of energy used by fuel type.
Step 4: Estimate emissions. To estimate emis-
sions from steam purchased, multiply fuel
input by fuel type (in terms of energy) by
the emission factors for that fuel, as per the
methods described in the Climate Leaders
guidance for Direct Emissions from
Stationary Combustion Sources.
2.3. Estimating
Emissions from Sales
of Electricity and/or
Steam
Emissions from the generation of electricity or
steam that is sold off-site can be estimated by
multiplying the amount of electricity or steam
sold by an emission rate representative of the
heat or power produced on-site. This emission
rate can be calculated by dividing the total
emissions from the generation of on-site
electricity or steam (calculated based on
methods described in the Climate Leaders
guidance for Direct Emissions from Stationary
Combustion Sources') by the total amount of
electricity or steam produced. Equation 4
describes the approach for estimating
emissions from sales of electricity or steam.
The following steps outline the approach to
estimate emissions from electricity or steam
sales. If the electricity or steam was produced
in a co-generation facility, use the approach
outlined in Section 2.4 to replace steps 1-4
below.
Step 1: Estimate amount of electricity or
steam sold. An estimate of the amount of
electricity or steam sold can be obtained
from sales records or metering data.
Step 2: Estimate total emissions from the gen-
eration of electricity or steam. This is done
for each of the on-site sources that produce
electricity or steam for sale. The emissions
Equation 4: Estimating GHG Emissions from
Electricity or Steam Sales
Emissions
Sales x
where:
Emissions,
Sales
TE;
Prod
Prod
Emissions of gas i (mass)
Amount of electricity or steam sold
(e.g., MWh, Ibs. of steam, BTUs of steam)
Gas i emissions from total facility production of electricity or steam
(mass C02, CH4, or N20)
Total amount of electricity or steam produced at facility
(e.g., MWh, Ibs. of steam, BTUs of steam)
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are calculated based on the methods
described in the Climate Leaders guidance
for Direct Emissions from Stationary
Combustion Sources.
Step 3: Determine the total amount of elec-
tricity or steam produced. Determine the
total amount of electricity or steam pro-
duced from the on-site sources in Step 2.
The total amount should correspond to the
same time period as the emission calcula-
tions.
Step 4: Calculate emission rate for on-site
electricity or steam production. Divide
total emissions from on-site production by
the total amount of electricity or steam
produced on-site to get an emission rate
(e.g., mass C02/MWh). This should be done
for each of the different on-site sources that
produce electricity or steam for sales.
Step 5: Estimate emissions associated with
electricity sales. To estimate emissions
from sales, multiply the amount of electrici-
ty or steam sold (Step 1) by the emission
rates for the source from which it was
produced (Step 4).
The total emissions from a Partner's electricity
or steam production are reported to Climate
Leaders as direct emissions. The portion of
those direct emissions that are associated with
electricity or steam sales (as determined from
the above approach) can optionally be report-
ed separately as supplementary information.
2.4. Allocating
Emissions from a
Co-Generation Facility
to Separate Electricity
and Steam Outputs
In a co-generation or combined heat and power
(CHP) plant, electricity and steam are generat-
ed together from the same fuel supply. If a
Partner is purchasing or selling all of the out-
put from the CHP plant (or in the same
proportions as they are generated) then an
average emission rate is sufficient. An average
emission rate is obtained by dividing the total
emissions at the CHP plant by the total output
of the plant (steam and electricity outputs
have to be converted to the same units and
combined).
However, if only part of the electricity or steam
generated by the CHP facility is purchased or
sold, allocating total emissions to the different
generated energy streams (normally steam and
electricity) is necessary.
There are several methods for allocating
emissions from CHP production (e.g., heat
output, financial, etc.) and there are certain
advantages and disadvantages inherent to each
approach4. It is important to have a consistent
method used by both the producer and any
number of purchasers of steam and electricity
to insure accurate reporting of emissions and
no double counting between multiple users
of CHP output. The preferred method of
allocating emissions between the steam
and electricity output of a CHP plant is a
contractual agreement between all parties. In
4 For more description of the allocation methods available see the GHG calculation tool, Calculating C02 emissions from stationary
combustion, Guidance section (Feb. 2004 v2.0) developed by the World Resources Institute. Available at www.ghgprotocol.org.
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the absence of this sort of agreement, the
preferred Climate Leaders allocation method
is the efficiency approach. The efficiency
approach uses separate efficiencies for heat
and power production to allocate emissions
between the two types of CHP output.
To determine the share of emissions attributa-
ble to both heat and power production using
the efficiency approach, follow the steps below.
An example of this method is given in
Appendix A.
Step 1: Determine the total steam and elec-
tricity output and total emissions for the
CHP system. The CHP system from which
steam or electricity is either purchased or
sold could have multiple steam or electrici-
ty outputs. For this allocation approach
these different flows should be combined
into two separate values, one for steam
output, and one for electricity output.
Furthermore, these three flows should be in
the same units of energy (e.g., all expressed
as BTUs).
Note: Convert kWh of electricity to BTU
using a factor of 3,412 BTU/kWh.
Steam tables provide energy content
(enthalpy) values for steam at different tem-
perature and pressure conditions. Enthalpy
values multiplied by the quantity of steam
give energy output values. The GHG emis-
sions associated with total fuel input can
be calculated based on the fuel mix of the
CHP plant, and the methods described in
the Climate Leaders guidance for Direct
Emissions from Stationary Combustion
Sources.
Step 2: Estimate the efficiencies of steam and
electricity production. This method is
based on the assumption that conversion of
fuel energy to steam energy is more efficient
than converting fuel to electricity (thermal
efficiencies). The efficiencies are used to
determine the amount of fuel input, and
therefore emissions, associated with steam
vs. electricity production. If actual efficien-
cies are not known, default values can be
used as described in Appendix A.
Note: Use of default efficiency values may,
in some cases, violate the energy balance
constraints of some CHP systems. This is
not a significant issue but users should be
aware of energy balance. See Appendix A for
more detail.
Step 3: Determine the fraction of total emis-
sions to allocate to steam and electricity
production. Equations 5 and 6, found on the
next page, are used for this step.
Step 4: Calculate emission rates for steam and
electricity production. Divide the total
emissions from steam production (Step 3)
by the total amount of steam produced to
get an emission rate (e.g., mass C02/amount
of steam). Divide the total emissions from
electricity production (Step 3) by the total
amount of electricity produced to get an
emission rate (e.g., mass C02/amount of
electricity).
Step 5: Estimate emissions from purchases or
sales. To estimate emissions, multiply
the amount of steam or electricity either
purchased or sold by the appropriate
emission rate (Step 4). Note: units used
to report steam or electricity usage should
be the same units used to calculate the
emission rates.
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Equation 5: Allocating Emissions to
Steam Production from a CHP Plant
H
H
ET
where:
EH
H
P
emissions allocated to steam production
steam output (energy)
delivered electricity generation (energy)
assumed efficiency of steam production
assumed efficiency of electricity generation
total emissions of the CHP system
-and-
where:
ED
Equation 6: Allocating Emissions to
Electricity Production from a CHP Plant
ET EH
emissions allocated to electricity production
total emissions of the CHP system
emissions allocated to steam production (from Equation 5)
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Purchases/Sales of Electricity and Stea
Guidance
Choice of Activity Data and
Emissions Rates
This section discusses choices of
activity data and factors used for
calculating emissions from purchases
and sales of electricity and steam. This guid-
ance has been structured to accommodate a
wide range of facilities with varying levels of
available information.
3.1. Activity Data
For electricity purchases, utility bills are a good
measure of electricity used. Typically this is
reported as kWh or MWh. This information on
the electricity entering a facility is considered
the best type of activity data as opposed to sub-
metering data which may be incomplete.
In some cases it may be difficult for a Partner
to obtain utility bills or metering data for a
site included in their inventory, for example,
from leased office space. However, it is
recommended that they try to obtain utility
bills or metered data to calculate electricity
use activity data.
Steam is physically measured in terms of pres-
sure, temperature and flow rate. This
information can be used with standard steam
tables to calculate the steam's energy value.
Purchased steam, like purchased fuel, is typical-
ly reported in energy units to better reflect the
use of the steam. Unlike fuel, the conversion of
metered steam units to energy units is standard-
ized and based on steam tables. It is
recommended that steam purchasers record the
quantity (mass), characteristics (temp and pres-
sures), and total energy of the steam purchased.
In some cases, not all of the energy entering a
facility as steam is used in the facility's processes.
Some of the energy could be returned to the
steam supplier as condensate. If this is the case,
the returned energy should be reflected in a high-
er boiler efficiency or a lower steam emission
rate. It takes less fuel energy to produce the same
amount of steam if a high temperature conden-
sate is used as input as opposed to make up
water at a lower temperature.
For electricity and steam sales, it is preferred
that data on emissions and the amount of elec-
tricity and steam generated and sold be
obtained from each exporting generator or
boiler, if possible. Otherwise, this data can be
estimated at the facility level.
3.2. Emission Rates
Emission rates are necessary to calculate the
emissions attributable to electricity and steam
purchases. They should be chosen based on the
guidance below. This guidance deals primarily
with electricity and steam produced from
sources other than CHP. Allocating emissions
from a CHP plant involves applying factors other
than emission rates. Default values for these fac-
tors are discussed in Appendix A.
3.2.1. Electricity Purchases
Activity data is used to determine the amount
of electricity purchased. The amount of elec-
tricity actually generated to provide this
purchased electricity is usually more that what
is purchased due to transmission and distribu-
tion losses. On average in the U.S., nine
i o
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percent of the total electrical energy input is
lost in transmission and distribution5. It is the
responsibility of the owner of the transmission
lines to report on transmission and distribu-
tion losses. Therefore, Partners only report
emissions associated with the amount of elec-
tricity they purchase and consume within their
facilities. The emission rate for electricity gen-
eration depends on the method/type of fuel
used and the efficiency of converting input
energy into electricity. To some extent, electric-
ity purchasers have the ability to control the
environmental attributes of the electricity they
purchase. A Partner may choose to purchase
green or renewable energy as opposed to more
conventional electricity generation based on
the combustion of fossil fuels.
In states with competitive electricity markets,
purchasers have the ability to choose their
electricity supplier. Depending on the market,
suppliers may offer electricity that contains a
percentage of renewable or green power. In
states without competitive electricity markets,
purchasers also have the ability to purchase
green power through block products or green
power pricing6. With this method, purchasers
pay a premium for a certain amount of green
power which the electricity supplier then buys
to be added to the grid7. Climate Leaders is
currently developing guidance for how
Partners would report green power purchases.
Also, the emissions from electricity production
vary by season and even time of day because
different types of plants produce electricity
for the grid at given times. Base-load plants
operate continuously and provide a base level
of electricity to the grid. Intermediate and
peaking units come into operation when there
is a spike or increased demand for electricity.
Often the emissions associated with these two
types of power are very different. An average
electricity production rate includes all units
generating electricity for the grid including
base-load, intermediate and peaking units.
Under Climate Leaders, Partners should use
the emission rate that best represents the
average emissions from the electricity genera-
tion used to supply the electricity that they
purchase. Therefore, as a default approach
Partners should obtain, for each facility,
emission factors from the utilities that supply
their power. This includes all base-load,
intermediate, and peaking units as well as
the use of renewable energy sources, utility
or purchased power, where applicable.
Furthermore, it is recommended that these
emission rates be updated annually with each
new reporting period.
However, it is understood that some utilities
might not track this type of emission rate data.
In this case, published emissions rates could
be used. It is generally not possible to identify
the specific generator from which electricity
was purchased from the grid. However, average
emission rates can be developed based on the
mix of generators supplying power to the grid.
The U.S. Environmental Protection Agency's
Emissions & Generation Resource Integrated
5 Energy Information Administration, Annual Energy Review 1999, August 2000.
6 Another approach for companies to purchase green power is through the use of "Green Tags" or Renewable Energy Certificates (RECs).
This involves purchasing just the environmental attributes associated with green power.
The grid is the network of transmission lines that is used to deliver power to end-users.
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Database (eGRID)8 provides default emission
rates in varying level of detail including by
generating company, states, North American
Electric Reliability Council (NERC) regions, and
U.S. average. If published emissions rates are
used, the default approach is to use the eGRID
subregion grid factors available in the eGRID
2002 release. An eGRID subregion represents a
portion of the U.S. power grid that is contained
within a single NERC region. eGRID divides
the U.S. power grid into 27 different eGRID
subregions, plus an "Off-Grid" category for
plants that are not grid-connected. Most of
eGRID's subregions consist of one or more
power control areas (PCAs). eGRID subregions
generally represent sections of the power
grid that have similar emissions and resource
mix characteristics and may be partially
isolated by transmission constraints.
If a Partner does not know what eGRID
subregion a facility is located in, they can
use the Power Profiler Tool, available at
www.epa.gov/cleanenergy/powerprofiler.htm.
The tool allows users to enter their facility zip
code and utility name to obtain the associated
eGRID subregion.
The approach described above is applicable
for both CH4 and N20 as well as C02 emission
rates. Some utilities may have emission rates
available for CH4 and N20 emissions, which
could be applied to estimate indirect emissions
of these gases. However, eGRID does not
specifically list emission rates for CH4 and N20
emissions from electricity production, only
C02. Therefore, EPA has developed CH4 and
N20 emission rates for the eGRID subregions
based on the underlying fuel use data and fuel
specific CH4 and N20 emission factors (from
Section 3 and Appendix A of the Climate
Leaders guidance for Direct Emissions from
Stationary Combustion Sources'). A map of the
eGRID subregions and year 2000 C02, CH4, and
N20 emission rates are provided in Appendix
B. Partners should use emission rates corre-
sponding to the year of their inventory activity
data, if available. For example, a Partner's Year
2000 inventory is based on electricity use data
from the year 2000 and year 2000 emission
rates. Their 2001 inventory would be based on
2001 activity data and 2001 emission rates, etc.
Emission rates for current (post-2000) years
are being developed. Until the new rates are
available, Partners should use year 2000 emis-
sion rates to calculate year 2000-2003
emissions. When new emission rates are avail-
able, Partners should update their emission
rates and inventory accordingly.
3.2.2. Steam Purchases
Emissions associated with the production of
steam are highly dependent on the type of fuel
burned. Since purchased steam is produced
very close to the facility (due to the difficulties
associated with transporting steam over long
distances), it should be possible to determine
the source of the steam and which fuels were
combusted for its production. Therefore, type
of fuels used and appropriate emission factors
should be obtained directly from the steam
suppliers. If this data is not available, a Partner
may use the fuel types and boiler efficiencies
to calculate emissions. In this case, default
values of 80% boiler efficiency and natural gas
fuel can be assumed.
8 The Emissions & Generation Resource Integrated Database (eGRID) is a comprehensive source of data on the environmental charac-
teristics of all electric power generated in the United States. An integration of 23 different federal data sources, eGRID provides
information on air pollutant emissions and resource mix for individual power plants, generating companies, states, and regions of
the power grid. eGRID is available at http://www.epa.gov/cleanenergy/egrid/index.htm.
1 2
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Purchases/Sales of Electricity and Stea
Guidance
Completeness
In order for a Partner's GHG corporate
inventory to be complete it must include
all emission sources within the company's
chosen inventory boundaries. See Chapter 3
of the Climate Leaders Design Principles for
detailed guidance on setting organizational
boundaries and Chapter 4 of the Climate
Leaders Design Principles for detailed guidance
on setting operational boundaries of the
corporate inventory.
On an organizational level the inventory should
include emissions from all applicable facilities
or fleets of vehicles. Completeness of corpo-
rate wide emissions can be checked by
comparing the list of sources included in the
GHG emissions inventory with those included
in other emission's inventories/environmental
reporting, financial reporting, etc.
At the operational level, a Partner should
include all GHG emissions from the sources
included in their corporate inventory. Possible
GHG emission sources are stationary fuel com-
bustion, combustion of fuels in mobile sources,
purchases of electricity, HFC emissions from
air conditioning equipment and process or
fugitive related emissions. Partners should
refer to this guidance document for calculating
indirect emissions from electricity/steam pur-
chases and to the Climate Leaders Core
Guidance documents for calculating emissions
from other sources. The completeness of facili-
ty level data can be checked by comparing
thefacility energy bills against accounting
records of expenditures for electricity and
steam.
As described in Chapter 1 of the Climate
Leaders Design Principles, there is no materiali-
ty threshold set for reporting emissions. The
materiality of a source can only be established
after it has been assessed. This does not nec-
essarily require a rigorous quantification of all
sources, but at a minimum, an estimate based
on available data should be developed for all
sources.
The inventory should also accurately reflect
the timeframe of the report. In the case of
Climate Leaders, the emissions inventory is
reported annually and should represent a full
year of emissions data.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Purchases/Sales of Electricity and Stea
Guidance
Uncertainty Assessment
There is some level of uncertainty asso-
ciated with all methods of calculating
GHG emissions from purchases of
steam and electricity. As outlined in Chapter 7
of the Climate Leaders Design Principles,
Climate Leaders does not recommend Partners
quantify uncertainty as +/- % of emissions
estimates or as data quality indicators. The
effort spent performing such analysis is better
spent pursuing high quality inventory data. It
is recommended that Partners attempt to iden-
tify the areas of most uncertainty in their
emissions estimates and consider options for
improving the quality of this data in the future.
The accuracy of estimating emissions from
purchases of steam or electricity is partially
determined by the availability of data concern-
ing the quantity of electricity or steam
purchased. For example, if the amount of
electricity or steam purchased is taken directly
from utility bills, then the resulting uncertainty
should be fairly low. However, electricity use
based on adding sub-meter data may not be
as accurate as fuel bills because it may be
difficult to meter every source of electricity
use (e.g., lighting).
The accuracy of estimating emissions from
purchased electricity and steam is also deter-
mined by the emission rates used to convert
purchases into indirect emissions. Rates for
purchased steam should be fairly accurate if
specific data on the source of the steam is
known. However, average grid emission rates
must be used with many electricity purchases
because it is difficult to trace electricity pur-
chases from the grid to the actual electricity
production sources. These average emission
rates are not completely accurate because the
rates vary by time of day and season based on
what units are operating (e.g., base load vs.
peaking load). Published average rates are
even more uncertain especially if the data is
calculated for a year that differs from the
year of purchase. If using emission rates
from eGRID, keep in mind that data may be
out of date. EPA recommends updating an
inventory as more recent emission rates
become available.
EPA recommends Partners choose the most
accurate emission rate representing their
purchased electricity. This includes using
emission rates that coincide with the year of
electricity use, if available. Partners should be
as transparent as possible when reporting his-
torical activity data (amount of electricity or
steam purchased or sold) so that emission
rates may be changed at a future date if more
accurate emission rates become available.
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Purchases/Sales of Electricity and Steam —
Guidance
Reporting and Documentation
Partners are required to complete the
Climate Leaders Reporting Requirements
for purchases/sales of electricity and
steam and report annual corporate level emis-
sions. In order to ensure that estimates are
transparent and verifiable, the documentation
sources listed in Table 1 should be maintained.
These documentation sources should be
collected to ensure the accuracy and
transparency of the related emissions data,
and should be reported in the Partner's
Inventory Management Plan (IMP).
Data
Table 1: Documentation Sources for
Electricity and Steam Purchases
Documentation Source
Amount of electricity and steam purchased Meter records, purchase receipts, contract pur-
chase or firm purchase records
Amount of electricity and steam sold
Meter records, delivery or sales receipts, contract
or firm records
Prices used to convert dollars or electricity Purchase receipts; delivery or sales receipts;
and steam to amount (kWh or Btu) contract purchase or firm purchase records;
EIA, EPA, or industry reports
Any assumptions made
All applicable sources
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Purchases/Sales of Electricity and Steam —
Guidance
Inventory Quality Assurance and
Quality Control
Chapter 7 of the Climate Leaders Design
Principles provides general guidelines
for implementing a QA/QC process for
all emission estimates. For indirect electricity
and steam emissions, activity data and emis-
sion rates can be verified using a variety of
approaches:
• An energy audit could be performed at the
facility to determine all sources that use
electricity. Results can be compared to
electricity bills to verify use.
• Electricity bills can also be compared to
actual meter readings to verify they are
accurate representations and not estimates.
• Data on electricity or steam use can
be compared with data provided to the
Department of Energy or other EPA
reports or surveys.
If a Partner accounts for electricity or steam
exports, stationary combustion guidelines
should be followed to estimate emissions.
If sub-meter data on electricity use is the
basis for determining electricity use, then
care should be taken to insure that the
sum of the sub-meters represents the full
electricity demand of the facility.
Emission rates provided by electricity
or steam providers should be checked
against published rates and any major
discrepancies should be explained.
Use of electricity or steam generated on-site
should not be accounted for in indirect
emissions calculations. The emissions from
on-site electricity and steam production are
accounted for under direct emissions.
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Purchases/Sales of Electricity and Steam —
Guidance
Example of Co-Generation
Allocation Methods
Figure A-l presents an example flow
diagram of a gas-fired turbine combined
cycle (GTCC) CHP system that incorpo-
rates a heat recovery steam generator (HRSG)
with supplemental fuel firing. This CHP system
includes four energy output streams (two
steam streams, Hl and H2, and two power
outputs, Pj and P2) and incorporates two fuel
inputs (one to the gas-fired turbine and a
second to the HRSG). It can be assumed that
the power (Pl and P2) and heat outputs (Hl
and H2) are well characterised (energy content
is known). The fuel inputs to the CHP system
(Fuelj and Fuel2) are also known.
The efficiency allocation method described in
this guidance is applied to the above example
and the related C02 emission factors for the
different output streams are calculated. The
same approach is used to calculate CH4 and
N20 emission factors, however, only the calcu-
lation for C02 is shown here.
Note: All calculations are done on a yearly
basis.
Figure A-1: Gas-fired Turbine Combined Cycle CHP System
Fuel
Fuel Oil #2
68MMBTU/yr
Heat
Fue
Natural Gas
341 MMBTU/yr
Heat
Recovery
Generator
Steam
Gas-fired Turbine
-*- PI
30 MWh/yr
H,
Saturated Steam
145 psig
363°F
85,305 Ib/yr
P,
0.39 MWh/yr
Superheated Steam
14 psig
283°F
82,730 Ib/yr
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Purchases/Sales of Electricity and Stea
Guidance
Step 1: Convert steam output flows into units of energy using steam tables and quantity of steam
produced. Then combine all steam outputs, and electricity outputs into one value for each
and express the values in the same units.
H! = 1,196 BTU/lb. (from steam tables) x 85,305 Ib. = 102 MMBTU
H2 = 1,180 BTU/lb. (from steam tables) x 82,730 Ib. = 97.6 MMBTU
H = 102 MMBTU + 97.6 MMBTU = 200 MMBTU
P = (30 MWh + 0.39 MWh) x 3.412 MMBTU/MWh = 104 MMBTU
Convert energy input into C02 emissions using the Climate Leaders guidance for Direct
Emissions from Stationary Combustion Sources.
Natural Gas emissions = 341 MMBTU x 14.47 kg C/MMBTU x 0.995 x (44/12) =
18,002 kg C02 or 18 metric tons C02
Fuel Oil # 2 emissions = 68 MMBTU x 19.95 kg C/MMBTU x 0.99 x (44/12) =
4,924 kg C02 or 4.9 metric tons C02
Total C02 emissions = 18 metric tons C02 + 4.9 metric tons C02 = 22.9 metric tons C02
Step 2: Estimate the efficiencies of steam and electricity production. Assume Climate Leaders
default values of:
eH = 80% and ep = 35%
It may be helpful to ensure that use of these default efficiency values do not violate the con-
straints imposed on the system by the energy balance. This can be checked by comparing
the calculated assumed energy input with the actual energy input of the CHP plant.
Assumed energy input is calculated based on the heat and power output and the assumed
efficiencies as shown in the following equation
H P
Assumed Energy Input = +
eH ep
In this example:
200 MMBTU steam 104 MMBTU power
0.8 MMBTU steam/MMBTU fuel 0.35 MMBTU power/MMBTU fuel
The energy balance constraint has been violated because 547 MMBTU is more than the
fuel consumption of the CHP system (409 MMBTU). This is not a significant issue, since
total emissions are still allocated between the energy outputs. However, the user should be
18 • CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Purchases/Sales of Electricity and Steam —
Guidance
aware of the energy balance and if the constraints are not satisfied eH and ep can be modi-
fied until constrains are met. In this example, violation of the energy balance constraint is
not considered significant and the default factors eH and ep are not modified.
Step 3: Determine fraction of total C02 emissions to allocate to steam and electricity.
EH = {(200 / 0.80) / [(200 / 0.80) + (104 / 0.35)]} x 22.9 = 10.5 metric tons C02
Ep = 22.9 -10.5 = 12.4 metric tons C02
Step 4: Calculate C02 emission factors for steam and electricity production.
For steam: 10.5 metric tons C02 / 200 MMBTU =
0.052 metric tons of C02 per MMBTU of steam produced
For electricity: 12.4 metric tons C02 / 104 MMBTU =
0.120 metric tons of C02 per MMBTU of electricity produced
Steps 1-4 are repeated to calculate CH4 and N20 factors as well.
CLIMATE LEADERS GHG INVENTORY PROTOCOL
1 9
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APPENDIX B
Purchases/Sales of Electricity and Steam —
Guidance
eGRID Subregion Emission Rates
;&-**
R*gtol\ll tx>und*ri*» ««• upproxirrul*
Map
No.
1
2
3
4
5
6
7
8
9
Name
NPCC New England
NPCC NYC/Westchester
NPCC Long Island
NPCC Upstate New York
MAAC All
SERC Virginia/Carolina
SERC Tennessee Valley
SERC Mississippi Valley
SERC South
Abbr.
NEWE
NYCW
NYLI
NYUP
MAAC
SRVC
SRTV
SRMV
SRSO
Year
(Ibs. C02/MWh)
897.11
1,090.13
1,659.76
843.04
1,097.55
1,164.19
1,372.70
1,331.34
1,561.51
2000 Emissions
(Ibs. CH4/MWh)
0.0766
0.0343
0.0915
0.0228
0.0241
0.0276
0.0223
0.0335
0.0451
Rates
(Ibs. N20/MWh)
0.0159
0.0050
0.0143
0.0107
0.0162
0.0190
0.0215
0.0142
0.0263
20
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Pure
Map
No.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
hases/Sales of El
G uid
Name
FRCC All
ECAR Michigan
ECAR Ohio Valley
MAIN North
MAIN South
MAPP All
SPP North
SPP South
ERGOT All
WSCC Rockies
WSCC Southwest
WSCC Great Basin
WSCC Pacific Northwest
WSCC California
HICC Hawaii Miscellaneous
HICC Oahu
ASCC Alaska Miscellaneous
ASCC Alaska Grid
Off-Grid
US Total
e c t r i
a n c e
Abbr.
FRCC
ECMI
ECOV
MANN
MANS
MAPP
SPNO
SPSO
ERCT
ROCK
wssw
NWGB
NWPN
CALI
HIMS
HIOA
AKMS
AKGD
OFFG
TOTAL
city and St
Year
(Ibs. C02/MWh)
1,390.04
1,632.06
1,966.53
1,761.09
1,237.29
1,838.83
2,011.15
1,936.65
1,408.27
1,872.51
1,423.95
852.31
671.04
804.54
1,702.93
1,721.69
757.81
1,399.95
1,706.71
1,392.49
e a m —
2000 Emissions Rates
(Ibs. CH4/MWh) (Ibs
0.0439
0.0338
0.0230
0.0331
0.0144
0.0268
0.0225
0.0328
0.0207
0.0211
0.0169
0.0121
0.0222
0.0305
0.1121
0.0733
0.0230
0.0264
0.0309
0.0284
=
. N20/MWh)
0.0171
0.0243
0.0296
0.0276
0.0181
0.0279
0.0278
0.0244
0.0134
0.0263
0.0188
0.0123
0.0099
0.0073
0.0204
0.0183
0.0039
0.0079
0.0031
0.0194
CLIMATE LEADERS GHG INVENTORY PROTOCOL
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Purchases/Sales
of Electricity
Guidance
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&EPA
United States
Environmental Protection
Agency
Office of Air and Radiation (6202J)
EPA430-K-03-006
October 2004
www.epa.gov/climateleaders
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