Greenhouse Gas Inventory Guidance: Indirect Emissions from Purchased Electricity


CENTER FOR CORPORATE

CLIMATE
LEADERSHIP

U.S. Environmental Protection Agency

Supporting organizations in GHG measure-merit and management * www.epa.gov/climateleadership

Greenhouse Gas Inventory Guidance

Indirect Emissions from
Purchased Electricity

SEPA

United States
Environmental Protection
Agency

December 2020

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

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

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Table Contents

Table of Contents

Section 1: Introduction	1

1.1 Greenhouse Gases Included	2

Section 2: Calculating Emissions	3

2.1	Calculation Steps	3

2.2	Allocating Emissions from Combined Heat and Power	3

Section 3: Choice of Activity Data and Emission Factors	5

3.1	Activity Data Sources	5

3.2	Activity Data Units	6

3.3	Emission Factors	6

3.3.1	Location-Based Electricity Emission Factors	6

3.3.2	Market-Based Electricity Emission Factors	7

3.3.3	Applying Emission Factors to Consumption	9

3.3.4	Steam, Heat, and Cooling Emission Factors	9

3.3.5	Updating Emission Factors over Time	10

3.3.6	Treatment of Biomass	10

3.3.7	Sale of Certificates from On-site or Direct Line Generation	11

Section 4: Quality Criteria	12

Section 5: Completeness	14

Section 6: Uncertainty Assessment	15

Section 7: Documentation	16

Section 8: Inventory Quality Assurance and Quality Control	17

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Indirect Emissions from Purchased Electricity Guidance

Section 1: Introduction

Indirect emissions are those that result from an organization's activities, but are actually emitted from sources owned by
other entities. Scope 2 emissions are indirect emissions that occur through the use of purchased electricity, steam, heat,
or cooling. Steam, heat (in the form of hot water), and cooling (in the form of chilled water) can be delivered to an
organization's facilities through a localized grid called a district energy system or through a direct line connection. The
term "electricity" will be used in this guidance to refer to purchased electricity, steam, heat, or cooling, except when
addressing issues specific to each energy source, such as emission factors.

Carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) are emitted to the atmosphere as fuels are burned to
produce heat and power. Therefore, activities that use purchased electricity indirectly 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. This document presents guidance on calculating scope 2 indirect emissions resulting from these sources.
Emissions associated with on-site generation of electricity in equipment owned by the organization are direct scope 1
emissions and are not addressed in this document.

The GHG Protocol Scope 2 Guidance provides a comprehensive discussion of issues related to quantification and reporting
of scope 2 emissions, and organizations are encouraged to consult that guidance. This document is aligned with the
principles and methodologies defined in the GHG Protocol Scope 2 Guidance. However, it does not attempt to address all
scope 2 issues. Guidance for quantifying two scope 2 emissions totals, using a location-based method and a market-based
method is included in this document. The organization should quantify and report both totals in its GHG inventory. The
location-based method considers average emission factors for the electricity grids that provide electricity. The market-
based method considers contractual arrangements under which the organization procures power from specific sources,
such as renewable energy.

GHG reduction goals that include scope 2 emissions can be based on either the location-based or market-based method.
If the organization adds scope 1 and scope 2 to report a total GHG inventory, the organization may report two inventory
totals based on both methods, or they may report the total based on only one method, provided that is the same method
used for their goal. The organization must specify which method is used for goal setting and for a scope 1 and scope 2
total inventory. If scope 2 base year emissions were calculated using different methodologies than those specified in this
guidance, base year emissions should be recalculated to be consistent with this guidance and include both location-based
and market-based emissions, so that emissions are comparable over time.

Other key updates include a shift to quantifying the impact of renewable energy purchases based on an emission factor
approach using a hierarchy of possible emission factors, rather than based on avoided emissions.1 This document also
defines quality criteria for contractual instruments used in the market-based method. These represent a change from
previous guidance, which defined a practice-based additionality test.

EPA encourages organizations to use renewable energy as a way to reduce the environmental impacts associated with the
electricity they purchase. Organizations can reduce their market-based scope 2 emissions by purchasing renewable
energy, or "green power." They can do this by choosing a differentiated electricity product from their utility or electricity

1 The GHG Protocol Scope 2 Guidance discusses approaches for optional reporting of avoided emissions from low-carbon electricity purchases, which
can be done separately from the organization's GHG inventory.

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Section 1: Introduction

supplier, by contracting directly with a renewable energy generator (if the regulatory rules allow), or by purchasing
unbundled renewable energy certificates (RECs). In any case, the RECs must be acquired and retired.

1.1 Greenhouse Gases Included

The greenhouse gases CO2, CH4, and N2O are emitted duringthe combustion of fuels to generate electricity. In the U.S.,
CChemissions represent approximately 99 percent of the total CCh-equivalent GHG emissions from fuels combusted for
electricity production. ChUand N2O together represent approximately one percent of the total CCh-equivalent emissions
from the same sources.2

Organizations should account for all CO2, CH4, and N2O emissions associated with purchases of electricity. Given the
relative emissions contributions of each gas, ChUand N2O emissions are sometimes excluded by assuming that they are
not material. However, as outlined in Chapter 1 of the GHG Protocol Corporate Standard, the materiality of a source can
only be established after it has been assessed. This does not necessarily require a rigorous quantification of all sources,
but at a minimum, an estimate based on available data should be developed for all sources and categories of GHGs, and
included in an organization's GHG inventory. This guidance can be used to calculate CO2, CH4, and N2O emissions from
purchases of electricity.

2 See Table 3-7 of U.S. EPA Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2018, EPA430-R-20-002, April 2020.
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Indirect Emissions from Purchased Electricity Guidance

Section 2: Calculating Emissions

This section presents guidance to calculate GHG emissions from purchased electricity, steam, heat, and cooling. This
guidance is applicable to calculation of emissions in both the location-based and market-based methods. It is
recommended that organizations calculate emissions for each of their facilities separately, as opposed to aggregating
multiple facilities to calculate emissions. This increases the accuracy and credibility of the inventory.

2.1 Calculation Steps

For both the location-based and market-based methods, emissions are calculated by multiplying the purchased electricity
by appropriate emission factors. The steps involved with calculating emissions from consumption of purchased electricity
are shown below. The same approach is applicable to steam, heat, and cooling.

Step 1: Determine the amount of electricity purchased.

See Section 3.1 for a discussion of possible data sources.

Step 2: Determine emission factors.

See Section 3.2 for guidance on selecting appropriate emission factors for
the location-based and market-based methods.

Step 3: Calculate emissions.

Use Equation 1 to calculate the emissions of CO2, CH4, and N2O.

Multiply the emissions of ChUand N2O by the respective global warming
potential (GWP) to calculate CCh-equivalent emissions. The GWPs are 25 for
CH4 and 298 for N2O, from the Intergovernmental Panel on Climate Change
(IPCC), Fourth Assessment Report (AR4), 2007. Sum the CO2equivalent
emissions from CFUand N2O with the emissions of CChto calculate the total
CCh-equivalent (CChe) emissions.

2.2 Allocating Emissions from Combined Heat and Power

In a cogeneration or combined heat and power (CHP) plant, the same fuel supply is used to generate electricity together
with steam, heat, and/or cooling. The emissions from the CHP plant are based on type of fuel used and must be allocated
proportionally to the each of the various energy streams. It is not appropriate to assign all the emissions to only one of
the energy streams. For more description of available allocation methods, organizations may refer to the GHG Protocol's
guidance Allocation of GHG Emissions from a Combined Heat and Power (CHP) Plant.3

There are several methods for allocating emissions from CHP production and these differences could depend on the CHP
prime mover technology. However, in some cases there is little physical basis to separate the allocation between electric
and thermal output. There are advantages and disadvantages inherent to each approach. It is important to have a

Equation 1:

Emissions = Electricity x EF
Where:

Emissions = Mass of CO2,
CH4, or N2O emitted

Electricity = Quantity of
electricity purchased

EF = CO2, CH4, or N2O
emission factor

3 Greenhouse Gas Protocol. Allocation of Emissions from a Combined Heat and Power (CHP) Plant. September 2006.
https://ghgprotocol.org/sites/default/files/CHP guidance vl.O.pdf https://ghgprotocol.org/sites/default/files/CHP tool vl.O.xIs.

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Indirect Emissions from Purchased Electricity Guidance	Section 2: Calculating Emissions

consistent method used by both the producer and any number of purchasers of steam and electricity to ensure accurate
reporting of emissions and no double counting between multiple users of CHP output.

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Indirect Emissions from Purchased Electricity Guidance

Section 3: Choice of Activity Data and Emission Factors

This section discusses choices of activity data and emission factors used for calculating emissions from purchases of
electricity, steam, heat, and cooling. This guidance has been structured to accommodate a wide range of organizations'
facilities with varying levels of available information.

3.1 Activity Data Sources

To quantify scope 2 emissions, the activity data needed are the amount of electricity that is purchased. Utility bills or
other purchase records can be used to determine the amount of electricity purchased. This information on the electricity
entering the organization's facility is considered the best type of activity data as opposed to sub-metering data from
within the facility, which may be incomplete.

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

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

If electricity is delivered through a grid, the amount of electricity actually generated to deliver this purchased electricity is
usually more than what is purchased, due to transmission and distribution losses. It is the responsibility of the owner of
the transmission lines to report scope 2 emissions from transmission and distribution losses. Therefore, the scope 2
emissions for end-users only include the emissions associated with the amount of electricity they purchase and consume
within their facilities.

The organization's facilities may have on-site generation systems that produce electricity to meet the demand of that
facility. These systems may be owned and operated by the reporting organization or by an external party. The ownership
determines the appropriate means of accounting for emissions from these on-site systems.

For on-site generation that is owned by the organization, the emissions from the system are direct scope 1 emissions. As
such, the quantity of electricity generated and consumed on-site is not included in the activity data used to quantify scope
2 emissions from purchased electricity. If the organization sells electricity from its owned on-site system to another
organization directly or to the grid, the quantity of electricity sold in this manner should not be deducted from total
electricity purchases when quantifying scope 2 emissions.

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Section 3: Choice of Activity Data and Emission Factors

If the on-site generation is not owned by the organization, the electricity used on-site should be treated as purchased
generation in scope 2 even if the organization is the host. This is an example of a direct-line connection between the
reporting organization and the electricity generating source, which is discussed further in Section 3.3.

3.2 Activity Data Units

The units of measure in which activity data are reported on utility bills or other purchase records can vary between
electricity, steam, heat, and cooling. For electricity, heat, and cooling, activity data are typically reported in energy units.
For electricity, kilowatt-hours (kWh) or megawatt-hours (MWh) are most common. Heat and cooling can be reported in a
variety of energy units. A common unit of measure for cooling is a ton-hour, which equals 12,000 Btu.

Steam may be reported in energy units or in mass units. Because steam emission factors are expressed per unit of energy,
activity data in mass units should be converted to energy units. The steam's pressure and temperature can be used with
standard steam tables to calculate the steam's energy value. In some cases, not all of the energy entering an
organization's 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 appropriate energy value selected from the steam table should reflect this.

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

3.3 Emission Factors

Emission factors are necessary to calculate the emissions attributable to electricity, steam, heat, and cooling purchases.
Emission factors reflect the renewable or fossil energy resource used and the efficiency of converting input energy into
useful energy output. Emission factors should be chosen based on the guidance below. Scope 2 emissions are emitted
from sources owned by other entities, and include indirect emissions from generation only, meaning the emissions that
occur through the use of purchased electricity, steam, heat, or cooling and are quantified at the point of generation.
Therefore, emission factors for electricity, steam, heat, or cooling should not include the impact of transmission and
distribution losses, nor emissions from fuel extraction or other activities upstream of the generation facility.

Organizations should calculate and report scope 2 emissions using two methods: one using location-based emission
factors, and one using market-based emission factors. Both results should be clearly labeled according to the method
used.

3.3.1 Location-Based Electricity Emission Factors

The location-based method considers average emission factors for the electricity grids that provide electricity. The
following are the types of location-based emission factors available, listed in order of preference based on the precision of
the factors.

1. Direct Line Emission Factor

An organization may purchase electricity through a direct line connection (as opposed to an electricity distribution grid)
from a known electric generation source, such as a generation facility located at a central plant of a campus or other

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Section 3: Choice of Activity Data and Emission Factors

nearby building, or an on-site generation facility that is owned or operated by another organization. In such a case, the
emission factor for that generation facility is preferred for calculating emissions in the location-based method. If
certificates from the generation facility are sold to a party other than the electricity purchaser, see Section 3.3.7. If
electricity is purchased from a CHP plant, refer to Section 2.2 for guidance.

In cases where an organization purchases electricity both through a direct line connection and from the grid, the
organization should pro-rate the indirect emissions using a direct line emission factor for the portion of the electricity
purchased from the specific known source, and one of the grid average factors described below for the portion of the
electricity purchased from the grid.

2. Regional Emission Factor

If an organization purchases electricity that is delivered through a grid, the organization should use published emission
factors based on the geographic location of each of its facilities, corresponding to the average emission factor of
generation facilities supplying power to the grid. It is recommended to use regional or subnational emission factors,
representing a grid distribution area.

Regional factors are available for several countries through national governments or other sources. For operations in the
U.S., the recommended regional factors are the total output subregion grid factors published by the EPA's Emission &
Generation Resource Integrated Database (eGRID)4. The total output factors represent average emission factors for all
plants generating electricity for the grid, including baseload, intermediate, and peaking units. An eGRID subregion
represents a portion of the U.S. power grid that is contained within a single North American Electric Reliability Council
(NERC) region. 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.

EPA publishes an Emission Factors Hub that contains the most recent eGRID subregion emission factors. This is available
at https://www.epa.gov/climateleadership/center-corporate-climate-leadership-ghg-emission-factors-hub. There may be
a delay between the release of a new version of eGRID and the update of the Emission Factors Hub. The most recent
version of eGRID, along with supporting documentation and resources, is available at https://www.epa.gov/egrid.

If an organization does not know what eGRID subregion its facility is located in, they can use the Power Profiler Tool,
available at https://www.epa.gOv/egrid/power-profiler#/. This tool allows users to enter their facility zip code and utility
name to obtain the associated eGRID subregion.

3. National Emission Factor

If regional factors are not available, national average emission factors can be used, such as those published by national
governments or by the International Energy Agency (IEA).

3.3.2 Market-Based Electricity Emission Factors

The market-based method considers contractual arrangements under which the organization procures power from
specific sources, such as fossil, renewable, or other generation facilities. Market-based emission factors reflect these

4The Emissions & Generation Resource Integrated Database (eGRID) is a comprehensive source of data on the environmental characteristics 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
https://www.epa.gov/egrid.

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Section 3: Choice of Activity Data and Emission Factors

arrangements. The following are the types of market-based emission factors available, listed in order of preference based
on the precision of the factors.

1. Energy Attribute Certificates

If an energy attribute certificate carries with it an emission factor, that factor can be used to quantify emissions in the
market-based method. Examples are renewable energy certificates (RECs) or Guarantees of Origin (GOs) in Europe. Refer
to the quality criteria in Section 4 to ensure that an emission factor can be claimed based on the certificate. The emission
factor is based on the specific source that the certificate represents, regardless of the energy resource used. Typically,
these certificates represent renewable energy and may have an emission factor of zero, but they may in some cases have
a non- zero emission factor (e.g., if there is a fossil-fuel or biomass generation component).

2. Contracts

An organization may have a contract, such as a power purchase agreement (PPA), to purchase electricity from a specified
generating facility, which may be located at the organization's facility, at a nearby location with a direct line connection to
the organization, or located remotely. If there are no certificates available, the contract itself carries the emission factor
associated with the generation facility, regardless of the energy resource used. Refer to the quality criteria in Section 4 to
ensure that an emission factor can be claimed based on the contract. If certificates are issued to the generating facility,
the emission factor is conveyed by the certificates, rather than the contract. If the certificates are bundled with the
contract, the purchaser can claim the emission factor (option 2 above). If the certificates are sold to another entity, the
purchaser cannot make that claim, and the energy should be assigned the residual mix factor.

3. Supplier-Specific Emission Factor

An electricity supplier, such as a regulated utility or a deregulated supplier, may provide information to its customers on
the emission factor associated with its electricity product. The product may be a standard product or a differentiated
product. To be used in the market-based method, the emission factor must include all the electricity delivered by the
supplier, including electricity it generates as well as electricity it purchases from others. Some supplier emission factors
only include generation facilities owned by the supplier, which does not represent the full electricity delivered.

4. Residual Mix Factor

A residual mix emission factor represents the emissions and generation that remain after certificates, contracts, and
supplier-specific factors have been claimed and removed from the calculation. It can be a regional or national factor.
Residual mix factors are the preferred market-based default emission factors for any of an organization's electricity for
which it cannot apply one of the more-preferred emission factors above. This is because the use of residual mix emission
factors avoids double counting of the emissions attributes of contractual instruments. Currently, residual mix factors are
not widely available. For example, they are not available across the U.S., though some regional certificate tracking systems
report a residual mix factor. Development of residual mix factors for the U.S. is under consideration. Organizations must
disclose the lack of residual mix factors as part of their scope 2 reporting. As with other emission factors, organizations
are encouraged to check for available residual mix factors each year when they complete their GHG inventory.

5. Regional Emission Factor

If residual mix factors are not available, organizations can use a regional grid average emission factor as the default. See
Section 3.3.1 for a description.

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Section 3: Choice of Activity Data and Emission Factors

6. National Emission Factor

If residual mix factors or regional factors are not available, organizations can use a national grid average emission factor as
the default. See Section 3.3.1 for a description.

3.3.3 Applying Emission Factors to Consumption

In order to accurately quantify emissions using the location-based and market-based methods, the selected emission
factors must be multiplied by the appropriate quantity of electricity purchases. In cases where the electricity for an
organization's facility is purchased entirely from a single source, the entire quantity purchased is multiplied by one
location-based emission factor and one market-based emission factor. If electricity is purchased from multiple sources,
then multiple factors may be required. For each distinct quantity that is purchased from a different source, the
organization should select the appropriate emission factor for that purchase and that source. For example, a portion of
the electricity for an organization's facility may be purchased through a direct line connection, and this quantity would be
multiplied by the direct line emission factor. The remainder of the electricity may be purchased from a grid supplier, and
this quantity would be multiplied by the appropriate factor from the hierarchy. Another example is a case where a portion
of the electricity for an organization's facility is purchased through RECs or a PPA, and the rest from the grid.

Organizations may also need to determine at which of their facilities to apply emission factors. If a contractual instrument
is purchased by a specific facility or is intended to apply to a specific facility, the emission factor associated with that
instrument should be applied to that facility. One example of this is the purchase of green power for a facility's green
building rating. Another example is a case where a specific facility has a PPA. The use of supplier-specific emission factors
is another example, because these factors should be applied based on the supplier serving a specific facility.

Another common means of purchasing contractual instruments is at an organization-wide level, with the instruments not
applied to any specific facilities. An example of this is an organization-wide purchase of RECs. In this case, it is
recommended that the contractual instruments be distributed evenly across all facilities proportional to their electricity
consumption, so that each facility has the same percentage of their consumption met by the contractual instrument.

3.3.4 Steam, Heat, and Cooling Emission Factors

Steam, heat (in the form of hot water), and cooling (in the form of chilled water) are typically purchased through a direct
line connection with a generating facility. These energy sources are also commonly distributed through a district energy
system, which is a grid system covering a limited geography supplying multiple end-users with energy produced by one or
more energy generating facilities.

The organization should quantify and report emissions from steam and heat purchases using both the location-based and
market-based methods. As such, the location-based and market-based emission factor hierarchies in Section 3.3.1 and
3.3.2 also apply to steam and heat. However, there are generally fewer emission factor options for purchased steam,
heat, or cooling.

Direct line emission factors are applicable, as are regional grid factors that consider the extent of a district energy system.
In both cases, appropriate emission factors should be obtained directly from the suppliers. If factors are not available, the
organization can calculate emission factors based on the fuels used for generation and the efficiency of generation. An
emission factor per unit energy for purchased steam or heat is equal to the emission factor per unit energy of the fuel
used divided by the thermal efficiency of the generation. If necessary, default values of natural gas fuel and 80 percent
thermal efficiency can be assumed. An emission factor for purchased cooling that is generated by an electric chiller is

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Section 3: Choice of Activity Data and Emission Factors

equal to the emission factor for the electricity consumed in the chiller divided by the chiller's coefficient of performance
(COP). If energy is supplied from a CHP plant, refer to Section 2.2 for guidance.

Emission factors associated with energy attribute certificates or contracts may also apply to purchases of steam, heat, or
cooling if an organization uses these contractual instruments and they meet the quality criteria in Section 4.

3.3.5 Updating Emission Factors over Time

All scope 2 emission factors represent the emissions profile for generation during a specific period of time. This emissions
profile can change over time, due to changes in the resource mix and generation efficiency supplying the electricity. As a
result, the emission factors may be updated periodically to reflect these changes. Organizations may also make different
choices in their purchase decisions over time, such as beginning to buy RECs. These represent real changes in the
emissions associated with an organization's electricity purchases. As such, it is recommended that organizations use the
newest emission factors available at the time they calculate emissions for a reporting year. Because these changes in
emission factors do not represent a methodology change, prior years' emissions need not be adjusted to reflect new
factors.

At times, there may be changes in the methodology used to develop emission factors. In addition, an organization may
change the type of emission factors being used due to availability of factors. These are examples of a methodology change
in the organization's GHG inventory, and in such cases, prior years' emissions should be adjusted in a manner consistent
with the organization's base year adjustment policy.

3.3.6 Treatment of Biomass

For electricity generated through combustion of biomass (non-fossil) fuels (e.g., forestry-derived, agriculture-derived,
biomass-derived gases), CH4 and N20 are to be included in the reported scope 2 emissions, and C02 is to be reported
separately from the scopes. This applies to both location-based and market-based emissions. In order to accomplish this,
electricity emission factors used for scope 2 calculations should include biomass ChU and N20 emissions. Separate factors
for biomass C02are also needed. Note that currently, eGRID and other commonly used grid average emission factors do
not include biomass C02 emissions, so biomass C02 emissions might not be reflected when using grid average emission
factors. However, there are specific biomass fuel combustion emission factors available from the EPA Greenhouse Gas
Reporting Program. These are provided in Appendix A of the Center's Direct Emissions from Stationary Combustion
Sources guidance document and in the U.S. EPA Center for Corporate Climate Leadership GHG Emission Factors Hub.

In cases where waste materials are combusted for energy rather than landfilled, the biogenic portion of combusted waste
materials should be considered as biomass and accounted for accordingly.

Recently, there has been increased scientific inquiry into accounting for biomass in energy production. The EPA's Science
Advisory Board recently found that "there are circumstances in which biomass is grown, harvested and combusted in a
carbon neutral fashion but carbon neutrality may not an appropriate assumption; it is a conclusion that should be reached
only after considering a particular feedstock's production and consumption cycle. There is considerable heterogeneity in
feedstock types, sources and production methods and thus net biogenic carbon emissions will vary considerably." 5
According to the GHG Protocol Corporate Standard, "consensus methods have yet to be developed under the GHG
Protocol Corporate Standard for accounting of sequestered atmospheric carbon as it moves through the value chain of

5 EPA Science Advisory Board Review of the 2011 Draft Accounting Framework for CO? Emissions for Biogenic Sources Study. 2012.
https://vosemite.epa.gOv/sab/sabproduct.nsf/0/2F9B572C712AC52E8525783100704886PQpenDocument.

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biomass-based industries," though some general considerations for accounting for sequestered atmospheric carbon are
discussed in Chapter 9 and Appendix B of the GHG Protocol Corporate Standard.

3.3.7 Sale of Certificates from On-site or Direct Line Generation

An on-site energy generation facility owned by the organization may generate certificates that are eligible for sale in
voluntary or compliance markets. If the organization sells the certificates, they transfer to the buyer the energy attributes
associated with the generation, including the type of energy and its emission factor. In this situation, the organization
should add the emissions associated with the sold certificates to its scope 2 emissions. The organization would multiply
the quantity of generation represented by the sold certificates by grid average emission factors for the location-based
method and by residual mix emission factors for the market-based method.

Alternatively, an organization may have a direct line connection with a generation facility that generates certificates. This
could be a generation facility located off-site, or an on-site generation facility that is owned or operated by another
organization. If the organization has not acquired the certificates from the direct line generation facility, emissions from
the electricity purchased from the facility must be quantified using grid average emission factors for the location-based
method and residual mix emission factors for the market-based method. A common example of this is a case where an
on-site renewable energy system is owned by an external party. The electricity may be sold to the reporting organization,
but the RECs may be sold to another party.

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Indirect Emissions from Purchased Electricity Guidance

Section 4: Quality Criteria

The following are scope 2 quality criteria defined by the GHG Protocol Scope 2 Guidance. All contractual instruments used
in the market-based method for scope 2 accounting shall:

1. Convey the direct GHG emission rate attribute associated with the unit of electricity produced. This can be achieved
in the following situations: a certificate conveys all environmental attributes; multiple certificates are generated for
the same MWh of generation, and only one (or a pairing of multiple instruments) conveys claims about the energy
type and GHG emission rate; or certificates do not specify attributes, but no other consumer is claiming emission rate
attributes.

2. Be the only instruments that carry the GHG emission rate attribute claim associated with that quantity of electricity
generation.

3. Be tracked and redeemed, retired, or canceled by or on behalf of the reporting entity. This can be done through a
tracking system, an audit of contracts, third-party certification, or other means.

4. Have a vintage that matches as closely as possible to the date of the reporting period to which the instruments are
applied. The vintage of the instrument is based on the date of the energy generation that the instrument represents.
EPA's recommended best practice is for instruments to be applied to a reporting period if the associated energy
generation occurred within the reporting period, up to six months prior to the reporting period, or up to three
months after the reporting period.

5. Be sourced from the same market in which the reporting entity's electricity-consuming operations are located and to
which the instrument is applied. A market is defined as a geographical area which has a common system for trading
and retiring contractual instruments. Markets are defined more by national borders than by electricity grid
boundaries. For example, for this purpose the U.S. constitutes a single market, despite regional grid boundaries. A
single country is also an appropriate market, even if there are electricity grid interconnections with other countries, if
those countries have not defined a common system for instruments. In cases where a common system is defined
across multiple countries, that can be considered a single market. The EU is such a market.

The following are EPA best-practice recommendations that go beyond the minimum requirements in the GHG Protocol
Scope 2 Guidance.

EPA recommends that organizations procure instruments that are surplus to supply quotas, such as state renewable
portfolio standards (RPS), mandates placed on utilities, or load-serving entities or consent decrees. An example would be
purchasing a voluntary REC that is properly retired and cannot be used to meet an RPS. The following are examples where
regulatory surplus is not achieved for the electricity generation associated with the instrument. This would most typically
apply to renewable generation, but could also apply to generation with other technologies.

1. Electricity generation is used to satisfy RPS mandates or goals imposed by federal, state or local governments on
utilities or load serving entities.

2. Electricity generation is included in an undifferentiated power product (e.g., standard electricity service or utility
system mix).

3. Electricity generation is being paid for by all customers (e.g., in a utility's standard rates).

4. Electricity generation comes from an eligible renewable generator that has been mandated by a local, state or federal
government agency (e.g., in a consent decree).

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Indirect Emissions from Purchased Electricity Guidance

Section 4: Quality Criteria

5. Electricity generation is purchased instead of paying a system benefits charge for renewable electricity (e.g., a self-
directed system benefits charge).

6. Electricity generation is purchased as part of a Supplemental Environmental Project (SEP) under a Clean Air Act
enforcement action.

7. Electricity generation is sourced from a state that has a mandatory GHG cap in place for power plant emissions or
similar regulatory mechanism, unless emission allowances are retired on behalf of the energy buyer, such as in the
Regional Greenhouse Gas Initiative (RGGI) and California's cap and trade program. For purchases from those states to
be eligible, organizations should communicate with their provider about whether the necessary administrative steps
are being taken to secure this result.

The following are circumstances in which EPA has recognized a purchase of electricity generation as surplus to other
mandatory requirements:

1. The purchase is a result of an obligation placed on federal, state, or local government agencies as end-users of energy
via a state or federal executive order.

2. The purchase is included as a voluntary measure in a State Implementation Plan (SIP) under the federal NOx Budget
Cap and Trade Program. Although SIPs are mandated, they do not set mandatory requirements for the use or
purchase of renewable energy. Therefore, a purchase of green power under a SIP is considered a voluntary purchase.

For organizations purchasing green power products, EPA's Green Power Partnership (GPP) identifies additional best-
practice quality criteria that organizations may consider. For example, eligible sources of green power are identified
(generating facilities 15 years old or newer that utilize wind, solar, geothermal, eligible biomass, or low-impact
hydropower resources). In addition, EPA strongly encourages organizations to buy green power products that are certified
by an independent third-party as a matter of best practice. Buying a certified green power product offers a higher
certainty to customers that they are receiving the desired environmental benefits.

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Indirect Emissions from Purchased Electricity Guidance

Section 5: Completeness

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

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

At the operational level, an organization should include all GHG emissions from the sources included in their inventory.
Possible GHG emission sources are stationary fuel combustion, combustion of fuels in mobile sources, purchases of
electricity, emissions from air conditioning equipment and process or fugitive emissions. Organizations may refer to this
guidance document for calculating indirect emissions from electricity purchases and to the Center's GHG Guidance
documents for calculating emissions from other sources. The completeness of facility level data can be checked by
comparing the facility energy bills against accounting records of expenditures for electricity.

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

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Indirect Emissions from Purchased Electricity Guidance

Section 6: Uncertainty Assessment

There is some level of uncertainty associated with all methods of calculating GHG emissions from purchases of electricity.
EPA does not recommend that organizations quantify uncertainty as +/- % of emissions calculations or as data quality
indicators. The effort spent performing such analysis is better spent pursuing high quality inventory data. It is
recommended that organizations attempt to identify the areas of most uncertainty in their emissions calculations and
consider options for improving the quality of this data in the future.

The accuracy of calculating emissions from purchases of electricity is partially determined by the availability of data
concerning the quantity of electricity purchased. For example, if the amount of electricity 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 calculating emissions from purchased electricity is also determined by the emission factors used to
convert purchases into indirect emissions. Average grid emission factors are not completely accurate because the factors
vary by time of day and season based on what units are operating (e.g., base load vs. peaking load). Factors may be even
more uncertain if the data are calculated for a year that differs from the year of purchase. If using emission factors from
eGRID, keep in mind that data may be out of date.

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Indirect Emissions from Purchased Electricity Guidance

Section 7; Documentation

Section 7: Documentation

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

Table 1: Documentation Sources for Purchased Electricity

Data

Documentation Source

Amount of electricity purchased

Purchase receipts or utility bills, contract purchase
or firm purchase records

Quantity of energy attribute certificates purchased

Purchase receipts, contracts

Location-based and market-based emission factors

Records from contracts, suppliers, or published

used

sources

Prices used to convert cost of electricity to amount

Purchase receipts or utility bills contract purchase or

of electricity consumed

firm purchase records; EIA, EPA, or industry reports

Any assumptions made

All applicable sources

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Indirect Emissions from Purchased Electricity Guidance	Section 8: Inventory Quality Assurance and Quality Control

Section 8: Inventory Quality Assurance and Quality
Control

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

•	Electricity bills can also be compared to actual meter readings to verify they are accurate representations and not
estimates.

•	Data on electricity use can be compared with data provided to the Department of Energy or other EPA reports or
surveys.

•	If sub-meter data on electricity use is the basis for determining electricity use, then care should be taken to
ensure that the sum of the sub-meters represents the full electricity consumption of the organization's facility.

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