5.6 Process for Calculating GHG Emissions
Once a reporting company has identified its Scope 2 emissions on the basis of its
organizational boundary (as previously discussed in Sections 5.4 through 5.4.4 and 5.5), it is ready to calculate its Scope 2 emissions. The company’s
process for calculating those emissions will generally include the following steps:
-
Identify GHG emission sources from purchased and consumed electricity.
-
Determine which accounting method(s) to use for Scope 2.
-
Collect activity data and determine GHG emission factors.
-
Calculate Scope 2 emissions.
-
Aggregate Scope 2 emission data for corporate reporting.
Connecting the Dots
As noted in Section 5.4, Scope 2 includes GHG
emissions from electricity purchased from another company and consumed by
the reporting company. Purchases of electricity that are resold are not
included in the reporting company’s Scope 2 emissions but are reflected in
Scope 3, Category 3.
The reporting company can identify its GHG emission sources of
purchased and consumed electricity through utility bills (generally representing the
most precise activity data) or meters at the facilities that are within the
company’s organizational boundary.
5.6.1 Determine Which Accounting Method(s) to Use for Scope 2
Companies are required to dually report their Scope 2 emissions under the
location-based method and the market-based method if they have any
operations in a market where product- or supplier-specific data in the form of
contractual instruments exist. These contractual instruments may include energy
attribute certificates, contracts for electricity (e.g., power purchase
agreements [PPAs]), and supplier-specific information (which may be a standard
or differentiated product). As markets continue to develop and provide further
options for companies with respect to their electricity purchases, the
market-based method will generally be a presumed requirement. Companies need to
be diligent in evaluating the markets in which they have operations to determine
whether the market-based method would not be applicable.
Connecting the Dots
If a company has operations in different regions or markets and the
market-based method applies, the company is required to calculate its
GHG emissions by using the market-based method for its entire Scope 2
inventory to adhere to the principles of completeness and
consistency.
Once a company has determined that the market-based method is applicable to its
Scope 2 inventory, it must assess whether the contractual instruments it holds
and uses under the market-based method meet the Scope 2 Quality Criteria (which
are discussed in Section 5.7.3). If the contractual
instruments do not meet the Scope 2 Quality Criteria, the company is required to
use alternative data (which are described in the table in Section
5.6.2.2.5) under the market-based method.
A reporting company with operations in different markets and regions may find
that market-based method data are inapplicable or unavailable for certain
operations within its corporate inventory boundary. In such a case, the
reporting company will use data under the location-based method for those
operations. As a result, the Scope 2 emissions for those operations will be
identical under the market-based and location-based methods, although it is
important to note that this outcome is specific to individual operations and
does not apply to the Scope 2 inventory as a whole. As noted in
Section 5.7.1, under the market-based method, a company
is required to disclose the categories of contractual instruments from which its
emission factors were derived (e.g., grid-average emission factors when more
accurate or precise emission factors are not available).
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 44
6.2 Determine Whether the Market-Based Method Applies
for Any Operations . . .
If no facilities in the entire organizational boundary of
the reporting entity are located in markets with
contractual claims systems, or where no instruments
within those systems meet Scope 2 Quality Criteria
required by this document, then only the location-based
method shall be used to calculate scope 2.
The decision tree below, which is adapted from Figure 6.1 of the Scope 2
Guidance, can help reporting companies determine which accounting method(s) to
use to calculate their Scope 2 emissions.
5.6.2 Determine Emission Factors for Each Method
The next step in the process is to determine the emission factors to use for
calculating Scope 2 emissions under the location-based method and the
market-based method.
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 45
6.5 Choose Emission Factors for Each Method
Companies should use the most appropriate, accurate,
precise, and highest quality emission factors available
for each method.
5.6.2.1 Location-Based Emission Factors
Location-based emission
factors represent the average emission factors for electricity generation in
a defined geographic area. The term “grid average” is often used in the
context of location-based emission factors. The following is a simple
illustration of a grid-average emission factor calculation:
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 54
6.11 Market-Based Emission Factors Data
Table 6.6 Example of Grid Average Emission
Factor Calculation
It is important for companies to understand the following concepts about
location-based emission factors:
-
Location-based emission factors are not the same as supplier-specific emission factors — Location-based emission factors are not synonymous with supplier-specific emission factors even if there is only one electricity supplier in the geographic area. That single supplier may produce a supplier-specific emission factor that approximates the location-based emission factor. However, the service territory of each electricity supplier may not be consistent with the regional grid distribution area (i.e., geographic boundary). As a result, the emission factor provided from that single supplier is not the same as the location-based emission factor for that area.
-
Location-based emission factors do not factor out contractual purchases — Location-based emission factors are not adjusted to exclude contractual instruments that have been claimed by suppliers or consumers. This is because the objective of the location-based method, as the Scope 2 Guidance indicates, is to “improve comparability across multiple markets over time and to show risks/opportunities that are better evaluated based on average emissions in a grid.”
-
Location-based emission factors are different from marginal grid emission factors — Location-based emission factors represent the average emission factors for electricity generation in a defined geographic area. Conversely, marginal grid emission factors represent the GHG emissions from certain generation facilities that operate “on the margin.” Throughout the day, grid operators monitor the demand for electricity against the supply. As demand increases, additional generation facilities may need to be brought online to meet it. Marginal grid emission factors are often used to evaluate avoided emissions.Scope 2 Guidance, Chapter 6, “Calculating Emissions,” Page 536.10 Location-Based Emission Factors . . .Companies shall not use marginal emission factors such as those provided by CDM for a location-based scope 2 calculation.
-
Spatial boundaries of location-based emission factors need to be consistent with energy distribution and use — Location-based emission factors represent the average emission factors for electricity generation in a defined geographic area. As a result, the spatial boundaries used in the calculation of location-based emission factors need to be consistent with the energy distribution and use of the defined geographic area or region, such as balancing areas. Balancing areas are defined geographic areas in which grid operators balance electricity supply and demand. All generation within this defined geographic area, including any electricity imports/exports that occurred, need to be considered in connection with the location-based emission factor.Scope 2 Guidance, Chapter 6, “Calculating Emissions,” Page 546.10.1 Grid Average Emission Factors . . .For multi-country regions with frequent and significant exchanges of energy throughout a year (as measured by percent of that country’s total generation), a multi-country regional grid average may be a better estimate than a production-only national emission factor without energy imports/exports adjustments. In turn, in a country with multiple distribution or balancing areas, these subnational regions would be a more precise spatial boundary for grid average emissions.
-
Companies need to evaluate the quality of location-based emission factors — Ensuring the relevance and timeliness of location-based emission factors is often a challenge because of the delay between the year in which electricity generation occurred and the publication of the corresponding location-based emission factors, which could be years. Companies need to consider this delay when evaluating their Scope 2 location-based results and determine whether more appropriate, accurate, and precise location-based emission factors are available.Scope 2 Guidance, Chapter 6, “Calculating Emissions,” Page 546.10.1 Grid Average Emission Factors . . .Companies can evaluate emission factor data based on quality indicators including their reliability, completeness, and geographic, temporal, and technological representativeness.
5.6.2.1.1 Location-Based Emission Factor Hierarchy
As noted in Section 5.6.2, the Scope 2
Guidance states, in part, that “[c]ompanies should use the most
appropriate, accurate, precise, and highest quality emission factors
available for each method.” To that end, the Scope 2 Guidance provides a
location-based emission factor hierarchy. The table below2 depicts the emission factor preferences for the location-based
method.
Scope 2 Guidance, Chapter 6, “Calculating
Emissions,” Page 47
6.5 Choose Emission Factors for Each Method .
. .
Table 6.2 Location-Based Method Emission
Factor Hierarchy
Data forms listed here should convey
combustion-only (direct) GHG emission rates,
expressed in metric tons per MWh or kWh.
5.6.2.2 Market-Based Emission Factors
The market-based method is applicable in markets where
contractual instruments, including supplier-specific products, are
available, regardless of whether the company purchases any contractual
instruments or supplier-specific products for the electricity consumption.
The market-based method reflects the GHG emissions associated with the
choices a company makes regarding the electricity it consumes.
Contractual instruments include GHG emission rate data that serve as GHG
emission factors for calculating GHG emissions. Any contractual instrument
used under the market-based method must include the GHG emission rate
data.
When applying the market-based method, companies are required to evaluate the
contractual instruments from which their GHG emission factors are derived to
ensure that those instruments meet the Scope 2 Quality Criteria (which are
further discussed in Section 5.7.3). If the contractual
instruments do not meet the Scope 2 Quality Criteria and alternative
market-based data are available, companies are required to use such data, in
which case it is recommended that they apply the market-based method
emission factor hierarchy from most precise to least precise (see
Section 5.6.2.2.5 for further discussion). If
alternative market-based data are not available, use of the location-based
emission factor data is recommended. Conversely, if multiple GHG emission
factors are available to the reporting company for one of its operations, it
is recommended that the company use the most appropriate, accurate, precise,
and highest quality emission factors available, in a manner consistent with
the market-based method emission factor hierarchy discussed below.
5.6.2.2.1 Energy Attribute Certificates
Energy attribute certificates are a type of contractual instrument that
conveys attributes about the generation of electricity. As electricity
is generated and supplied to the electric grid, electricity generated
from one source becomes physically indistinguishable from electricity
generated from other sources. As a result, as noted in Chapter 10 of the
Scope 2 Guidance, “allocation of energy attribute information is
necessary to facilitate product-specific consumer claims.” Energy
attribute certificates are the most common type of contractual
instrument used to convey energy attributes.
Scope 2 Guidance, Chapter 10, “Key Concepts and
Background in Energy Attribute Certificates and
Claims,” Page 80
10.2 Defining Energy Attribute Certificates .
. .
Historically, most certificates for policies or
consumer programs have been generated from
renewable energy resources, driven by demand for
these resources in particular, but depending on
their intended purpose or usage certificates can
be generated from any or all generation technology
types.
5.6.2.2.2 Contracts Such as PPAs
A PPA is a contract between the developer of a renewable energy project and a
buyer. Under a PPA, the developer will typically receive a fixed price for
each megawatt-hour of renewable energy produced, and the buyer will receive
the associated energy attribute certificates (also known as renewable energy
certificates [RECs] in the United States) over time as the project produces
and sells electricity. The recipient of the RECs (the buyer) will be able to
use them to reduce its gross Scope 2 emissions from purchased electricity.
In a PPA, physical energy must also be delivered to the buyer.
By contrast, in a virtual PPA, the buyer does not take physical delivery of
the power produced by the renewable energy source. Instead, the power
component of the transaction is financially settled while the buyer receives
all, or a predetermined amount, of the generated RECs for each year of the
contract term for an agreed-upon price. In a manner similar to that under
PPAs, the recipient of the RECs (the buyer) will be able to use the RECs to
reduce its gross Scope 2 emissions from purchased electricity.
5.6.2.2.2.1 Certificates Are Issued
When certificates are issued as part of the PPA, the certificates will
contain the emission factor that will be used under the market-based
method.
Scope 2 Guidance, Chapter 6, “Calculating
Emissions,” Page 55
6.11.2 Contracts Such as Power Purchase
Agreements (PPAs) . . .
If the certificates are bundled with the
contract, the purchaser can claim the
certificates. If the certificates are sold
separately, the power recipient cannot claim the
attributes of the specific generator.
5.6.2.2.2.2 Certificates Are Not Used in the Jurisdiction or for the Technology/Resource
When certificates are not issued as part of the PPA, the PPA may still
implicitly provide the attributes of the generated electricity if the
PPA itself includes terms that allow the electricity consumer to claim
such attributes. In addition, as stated in Chapter 6 of the Scope 2
Guidance, if the PPA does not contain any terms with respect to the
attributes, the PPA “can be used as a proxy for delivery of attributes,”
although the consumer of the electricity under the PPA will need to
demonstrate that no other consumer is claiming the same energy
attributes.
5.6.2.2.2.3 Power Received in the PPA Is Resold
There may be instances in which the company that has purchased
electricity through the PPA resells that electricity in the wholesale or
retail market. If a resale occurs, the company cannot claim the
attributes associated with that electricity in a market where
certificates are not used. That is, the attributes remain attached to
the electricity generation. However, if the company is operating in a
market where certificates are used, the company has the ability to
resell the electricity while maintaining ownership of the attributes,
which means that the company can claim the benefits of those attributes
as part of its Scope 2 emissions under the market-based method.
Scope 2 Guidance, Chapter 6, “Calculating
Emissions,” Page 55
6.11.2 Contracts Such as Power Purchase
Agreements (PPAs) . . .
To avoid double counting, companies making claims
based on contracts (where no certificate system
exists) should report the quantity of MWh and the
associated emissions acquired through contracts to
the entity that calculates the residual mix, and
request that their purchase be excluded from the
residual mix. Certain third-party certifications
of renewable energy may do this automatically.
5.6.2.2.3 Supplier-Specific Emission Factors
Supplier-specific emission factors represent the GHG intensity of electricity
delivered by a specific supplier. The Scope 2 Guidance recommends that these
factors include emissions from all electricity delivered to the electric
grid by the supplier, not just emissions from generation facilities that the
supplier owns or operates. Utilities may purchase electricity from other
generation facilities or on the spot market, and the Scope 2 Guidance
recommends providing a supplier-specific emission rate that reflects all of
these purchases.
When companies use a supplier-specific emission rate, it is recommended that
they determine that:
-
The supplier-specific emission rate is disclosed by the utility and indicates that it has been calculated on the basis of the best available information.
-
The disclosure from the utility includes information about how certificates are used in the calculation of the supplier-specific emission factor. The key point here is that if companies are purchasing a differentiated electricity product from the supplier (i.e., renewable energy), it is recommended that the energy attribute certificates attached to that product be applied to that product.
Companies are advised to seek supplier-specific emission factors from their
suppliers when calculating their Scope 2 emissions under the market-based
method. If such information is not provided by the utility, companies must
not calculate a supplier-specific emission factor on their own. Rather,
companies are required to use alternative data from the market-based Scope 2
data hierarchy (see Section 5.6.2.2.5).
Further, the supplier-specific emission rates exclude any
offsets that the supplier purchases.
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 56
6.11.3 Supplier-Specific Emission Rate . .
.
If an electricity supplier purchases offsets on
behalf of their customers, the reporting customers
should report the offsets separately from the
scopes. The supplier-specific emission rate used for
scope 2 should reflect supply only, and not
purchased offsets.
5.6.2.2.4 Residual Mix
Under the market-based method, a “residual mix” is necessary to convey the
GHG emissions from untracked or unclaimed electricity. As noted in Section
5.2.2, the objective of the market-based method is to reflect
the GHG emissions associated with the choices — or lack of a choice — a
company makes regarding the electricity it consumes. Depending on the market
in which the company operates, the residual mix may approximate the
grid-average emission factor or be quite different.
If a residual mix is not available, companies would move down the
market-based method emission factor hierarchy (see the table in
Section 5.6.2.2.5) and use emission factors
applicable under the location-based method (e.g., grid-average emission
factors). However, it is recommended that companies seek out residual mix
factors first before moving on to grid-average emission factors.
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 56
6.11.4 Residual Mix . . .
Companies should not attempt to calculate their own
residual mix.
If a residual mix is unavailable and a grid-average emission factor is used
instead, the reporting company is required to document in its GHG inventory
that the residual mix was unavailable.
5.6.2.2.5 Market-Based Method Emission Factor Hierarchy
As noted above, the Scope 2 Guidance states, in part, that “[c]ompanies
should use the most appropriate, accurate, precise, and highest quality
emission factors available for each method.” To that end, the Scope 2
Guidance provides a market-based method emission factor hierarchy. The
hierarchy does not indicate that the Scope 2 Guidance prefers companies to
enter into certain contractual arrangements as opposed to others. Rather,
the hierarchy presents the different instruments from most precise to least
precise.
The table below3 depicts the emission factor preferences for the market-based
method.
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 48
6.5 Choose Emission Factors for Each Method . .
.
Table 6.3 Market-Based Scope 2 Data Hierarchy
Examples
Data forms listed here should convey combustion-only
(direct) GHG emission rates, expressed in metric
tons per MWh or kWh. Reporting entities should
ensure that market-based method data sources meet
Scope 2 Quality Criteria. Instruments listed here
are not guaranteed to meet Scope 2 Quality Criteria,
but are indicative of instrument type.
5.6.3 Matching Emission Factors to Each Unit of Consumption and Calculation
Under both the location-based method and the market-based method, each unit of
electricity consumed by a facility of the reporting company is matched to an
appropriate emission factor.
If a company purchases energy attribute certificates centrally with the intent of
applying them to all of its operations in a single market, it is advisable for
the company to indicate its process for matching energy attribute certificates
to consumption by each of its facilities.
Further, suppliers may convey to their customers energy attribute certificates
that are separate and distinct from supplier-specific emission rates. In such
cases, the customers can apply the certificates against their consumption under
the market-based method.
5.6.3.1 Examples
The following examples from
the Scope 2 Guidance illustrate how emission factors are matched to
consumption under the market-based method:
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 49
6.6 Match Emission Factors to Each Unit of
Electricity Consumption . . .
[I]f a company has purchased certificates to apply to
half of a given operation’s electricity use, it will
need to use other instruments or information on the
emission factor hierarchy to calculate the emissions
for the remaining half.
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 49
6.6 Match Emission Factors to Each Unit of
Electricity Consumption . . .
[A] utility delivers 1,000 MWh in total to customers
and 200 MWh of that (20 percent) comes from
zero-emitting renewables for which the energy
attribute certificates have been retired. Any
customer of that utility would be able to claim that
20 percent of their electricity is renewable and
substantiated with certificates. If Customer A of
this utility consumes 2.5 MWh (of the total 1,000
MWh), they can claim 0.5 MWh of renewable energy (of
the 200 MWh total) without double counting, but
cannot claim any more than this. To cover all of
their electricity consumption with zero-emission
certificates, Customer A would only need to purchase
2 MWh of renewables on their own.
5.6.4 Biofuel Emissions
Biofuel is generally any kind of fuel that is generated from biomass. Although
biofuels may produce a lower level of GHG emissions than fossil fuel, they still
produce emissions. Therefore, the emission factor associated with biofuels is
not zero.
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 57
6.12 Treatment of Biofuel Emissions . . .
Based on the Corporate Standard,
any CH4 or N2O emissions from
biogenic energy sources use shall be reported in scope 2, while the
CO2 portion of the biofuel combustion shall be reported outside the
scopes.
In accordance with the excerpt above, the CO2 portion
of the biofuel combustion will be reported separately from any GHG emissions
reported in Scope 1, Scope 2, or Scope 3.
5.6.5 Calculate Emissions
Once the above information has
been gathered, Scope 2 emissions under both methods are calculated in the same
manner as Scope 1 emissions, as discussed in Section 4.2. The formula is as
follows:
Table 6.4 of the Scope 2 Guidance, which is reproduced below,4 shows an example of how to calculate total Scope 2 emissions under the
location-based method.
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 50
6.7 Calculate Emissions . . .
Table 6.4 Example Calculation for Location-Based
Method
Table 6.5 of the Scope 2 Guidance, which is reproduced below, shows an example of
how to calculate total Scope 2 emissions under the market-based method.
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 51
6.7 Calculate Emissions . . .
Table 6.5 Example Calculation for Market-Based
Method
5.6.6 Identify Distribution Scenarios and Any Certificate Sales
As discussed in Section 5.4, the Scope 2 Guidance identifies a number of
scenarios in which electricity can be generated and consumed. In each of these
scenarios, the company that owns the generation facility has the ability to sell
energy attribute certificates or other contractual instruments related to the
generated electricity.
The sale or retention of the energy attribute certificates or other contractual
instruments will affect how the reporting company accounts for the electricity
it consumes, as discussed in the section below and in Section 5.6.6.2.
5.6.6.1 Accounting for Scope 2 Emissions With Certificate Sales
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 44
6.4 Identify Distribution Scenarios and Any
Certificate Sales . . .
The creation of a certificate that conveys an energy
generation attribute claim means that the underlying
power — sometimes called “null power” — can no
longer be considered to contain the energy
attributes, including the type of energy (e.g., that
it is “renewable”) and its GHG emission rate (that
it is zero emissions/MWh).
When a company sells energy attribute certificates to a third party, thereby
separating the right to claim the energy attributes from the underlying
electricity, a consumer of the underlying electricity can no longer claim
the attributes associated with the generation of that electricity unless the
consumer is the party that acquired the energy attribute certificates. As a
result, the Scope 2 Guidance requires a consumer of the underlying
electricity that did not acquire the energy attribute certificates to use
“other market-based method emission factors such as ‘replacement’
certificates, a supplier-specific emission rate, or residual mix (for the
market-based method total) and the grid average emission factor (for the
location-based total).”
5.6.6.2 Summary Table — Accounting for Scope 2 Emissions With and Without Certificate Sales
The table below summarizes how Scope 2 emissions are accounted for under the
location-based method and the market-based method in different scenarios in
which energy attribute certificates (1) have not been generated or sold, (2)
have been retained, or (3) have been sold to a third party. For details
about the location-based and market-based method emission factor
hierarchies, to which the table refers, see Sections 5.6.2.1.1 and
5.6.2.2.5, respectively.
Scope 2 Guidance, Chapter 6, “Calculating Emissions,”
Page 46
6.5 Choose Emission Factors for Each Method . .
.
Table 6.1 Accounting for Scope 2 With and
Without Certificates Sales
Footnotes
2
The source text’s footnotes have been
omitted.
3
The source text’s footnotes have been omitted.
4
The reproduced table’s asterisked footnote reflects an April 2025 update
to the Corrections to the Scope 2 Guidance.