Summary: This is an extract from Chapter 6. This chapter outlines key requirements, steps, and procedures involved in calculating scope 2 emissions according to each method.
Once the inventory boundary has been established, companies generally calculate GHG emissions using the following steps:
- Identify GHG emission sources for scope 2 emissions
- Determine whether the market-based approach applies
- Collect activity data and choose emission factors for each method
- Calculate emissions
- Roll up GHG emissions data to corporate level.
Additional guidance on general calculation procedures and GHG Protocol calculation tools can be found in Chapter 6 of the Corporate Standard.
6.1 Identify GHG emissions sources for scope 2
Scope 2 includes emissions from all purchased/acquired and consumed electricity, heat, steam, or cooling.
Companies can identify these energy uses on the basis of utility bills or metered energy consumption at facilities within the inventory boundary.
6.2 Determine whether the market-based method applies for any operations
Companies can determine whether the market-based method for scope 2 calculation applies to their inventory by assessing whether differentiated energy products in the form of contractual instruments (including direct contracts, certificates, or supplier-specific information) are available in a given market. Markets are increasingly developing and refining purchasing options, and the list is not exhaustive. Currently this includes EU member states and economic area, the U.S., Australia, most
Latin American countries, Japan, India, and many others. Figure 6.1 illustrates this determination.
- The presence of contractual information in any market where a company has operations triggers the requirement to report according to the market-based method. The contractual instruments themselves must be assessed for their conformance with Scope 2 Quality Criteria. If they do not meet the Scope 2 Quality Criteria, then other data (listed in Table 6.3) shall be used as an alternative in the market-based method total. In this way, all companies required to report according to the market- based method will have some type of data option.
- If a multi-regional company has any operations within the corporate inventory where the market-based method applies, then a market-based method total shall be calculated for the entire corporate inventory to ensure completeness and consistency. For any individual operations in the corporate inventory where market- based method data on the hierarchy is not applicable or available, data from the location-based method should be used to represent the emissions from the facility (see Table 6.3). For these operations, the calculated scope 2 according to the market-based method will be identical to the location-based.
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.
6.3 Collect activity data
For electricity use disclosure required by this guidance, activity data includes all electricity purchased/acquired and consumed during the reporting period, including from owned/operated generation facilities that may not be included as activity data for scope 2 calculation.
For scope 2 calculation, activity data includes all energy purchased/acquired and consumed from an entity outside of the organization or from owned/operated generation facilities where energy attributes (e.g. certificates) have been sold or transferred. Table 6.1 indicates how different energy distribution methods should be treated.
To determine activity data, metered electricity consumption or utility bills specifying consumption in MWh or kWh units can provide the most precise activity data. In some cases these may not be available, as with consumption occurring in a shared space without energy metering. In these cases, estimations may be used such as allocating an entire building’s electricity usage to all tenants on the basis of the reporter’s square footage and the building’s occupancy rate (called the Area Method).1
6.4 Identify distribution scenarios and any certificate sales
All of the distribution scenarios identified in Section 5.4 can entail the generation and sale of energy attribute certificates or other contractual instruments. The sale or retention of these instruments impacts the accounting of the consumed energy, as shown in Table 6.1.
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). By the conveyance of energy attributes or certificates to a third party separate from the electricity, users of the null power electricity cannot claim to be buying or using renewable energy in the absence of owning the certificate. Instead, companies consuming energy from owned/operated facilities or direct-line transfers where certificates are sold off, shall calculate that consumption using 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).
6.4.1 How certificate sales affect on-site energy consumption in the location-based method
****Companies who are consuming energy directly from a generation facility that has sold certificates (either owned/ operated equipment or a direct line) forfeit not only the right to claim those emissions in the market-based method (requiring the use of some other market-based data source such as other “replacement” certificates, a supplier-specific emission factor, or residual mix) but also the right to claim that emissions profile in the location-based method. Overall, the location-based method is designed to show emissions from the production supporting the local consumption without reference to any contractual relationships. However, the attributes contained in certificates usually carry legally enforceable claims, which should take precedence.
For instance, the U.S. Federal Trade Commission Green Guides2 prevent any kind of claim about using, consuming, or hosting renewable energy or its attributes if the REC from that production has been sold off. This includes a claim in the form of location-based calculations of “zero emissions power consumption.” Therefore, in the event of certificate sales from owned/operated energy production and consumption, companies should still use the location- based emission factor hierarchy (see Table 6.2).
Taken to its logical conclusion, these kind of legally enforceable rights and claims could call into question the validity of any kind of location-based reporting (since even a grid average will include a mix of power whose RECs have been claimed by someone else). However, for the purposes of a GHG inventory, location-based accounting and reporting are still required in order to improve comparability across multiple markets over time and to show risks/opportunities that are better evaluated based on average emissions in a grid. Companies should avoid using location-based totals for goal tracking where certificates convey these claims and/or carry legally enforceable claims.
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. Table 6.2 indicates these preferences for the location-based method, and Table 6.3 for the market-based method. Table 6.3 does not represent a preferred hierarchy of procurement methods (e.g., purchasing renewable energy from a supplier vs. through a contract with a generator), as these are dependent on local market options and company-specific conditions. Instead, it represents a hierarchy of instruments based on the most precise (e.g., energy attribute certificates issued in units that match consumption units, e.g. MWh) to least precise (averages of attributes representing all unclaimed production in a region).
Companies using the market-based method shall ensure that any contractual instrument from which an emission factor is derived meets the Scope 2 Quality Criteria listed in Chapter 7. Where contractual instruments do not meet the Scope 2 Quality Criteria requirements, and no other market- based method data are available, the location-based data should be used.
6.6 Match emission factors to each unit of electricity consumption
Each unit of electricity consumption should be matched with an emission factor appropriate for that consuming facility’s location or market. For the market-based method, this means choosing a contractual instrument or information source for each unit of electricity. For instance, if 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.
Companies centrally purchasing energy attribute certificates on behalf of all its operations in a single country or region should indicate how they match these purchases to individual site consumption.
Companies may also use certificates conveyed to them by their supplier, separately from the other supplier mix information. This ensures equivalent treatment of certificates regardless of how they are sourced.
For example, 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.
6.7 Calculate emissions
To calculate scope 2 emissions according to one or both methods, the following procedure applies:
- Multiply activity data from each operation by the emission factor for that activity for each applicable GHG. Some electricity emission factor sets may include emission rates for CO2, CH4, and N2O; others may only provide CO2 emission rates (see Box 6.1)
- Multiply global warming potential (GWP) values by the GHG emissions totals to calculate total emissions in CO equivalent (COe).
- Report final scope 2 by each method in metric tons of each GHG (where available) and in metric tons of COe.
Example calculations are provided for the location-based method and market-based method in Table 6.4 and Table 6.5, respectively.
6.8 Roll up GHG emissions data to corporate level
To report a corporation’s total GHG emissions, companies will usually need to gather and summarize data from multiple facilities, possibly in different countries and business divisions. It is important to plan this process carefully to minimize the reporting burden, reduce the risk of errors that might occur while compiling data, and ensure that all facilities are collecting information on an approved, consistent basis. Ideally, corporations will integrate GHG reporting with their existing reporting tools and processes, and take advantage of any relevant data already collected and reported by facilities to division or corporate offices, regulators, or other stakeholders. The two basic approaches to gather data on GHG emissions from facilities include a centralized and decentralized approach. For more guidance on this process, see Chapter 6 of the Corporate Standard.
6.9 Optional: Calculate any avoided emissions and report separately
Companies can report the estimated grid emissions avoided by low-carbon energy generation and use, separately from the scopes. This type of analysis reflects the impacts of generation on the rest of the grid: for example, the emissions from fossil-fuel or other generation backed down or avoided due to the low-carbon generation. These avoided emissions estimations inherently represent impacts outside the inventory boundary. Avoided emissions estimations are not necessarily equivalent to global emissions reductions from additional projects and should therefore not be used to reduce a company’s footprint. However, quantifying avoided emissions provide several technical and strategic benefits, including:
- Identifying where low-carbon energy generation can have the biggest GHG impact on system, based on the operating margin.
- Demonstrating that grid-connected generation provides a system-wide service in addition to conveying a specific emission rate at the point of production.
This estimation should follow project-level methodology; see GHG Protocol Project Protocol or Guidelines for Grid- Connected Electricity Projects. This may be most beneficial
where a company has taken actions that avoid higher- carbon generation dispatch at the margins. These actions could include:
- Installing a low-carbon energy generation facility on-site that sells energy to the grid (any emissions from owned/ operated facilities are reported in scope 1)
- Installing a cogeneration facility providing both heat and electricity outputs, which may increase a company’s scope 1 reporting but reduce the electricity it needs to purchase from the grid
- Securing a contract to purchase power from a new low- carbon energy generation facility
- Undertaking a significant energy efficiency effort.
However, if the project operates in a jurisdiction with an emissions cap on the power sector, or comes from an energy generation facility also producing verified emission reductions (also termed a GHG offset), the company should not make public claims about avoided emissions. The avoided grid emissions will either be zero, in the case of a cap as regulated entities may emit up to the level of the cap,3 or already represented in claims by the offset purchaser. Any offsets produced from the project, or any voluntary allowances retired on behalf of the purchase associated with the project, should be reported separately.
6.10 Location-based emission factors
The emission factors necessary to estimate location-based scope 2 emissions include GHG emission intensity factors for energy production in a defined local or national region. Where advanced studies or real-time information is available, companies may report scope 2 estimations separately as a comparison to location-based grid average estimation (see Box 6.2). Companies should be aware of the following caveats about location-based emission factors:
- location-based is not supplier-specific.
The location-based grid average emission factors should be distinguished from supplier-specific information, even if the electricity supplier is the sole energy provider in a region and produces a supplier-specific emission factor that closely resembles the overall regional grid average emission factor. In these cases, the service territory
may still be a smaller region than the grid distribution area serving a given site of consumption; conversely, many utilities are in competitive markets where multiple suppliers can compete to serve consumers in the same region. Therefore, this method only looks at a broader grid emissions profile serving the local load, regardless of supplier relationships.
- Grid average emission factors do not factor out contractual purchases.
Grid average emission factors in the location-based method should not reflect any adjustments or removals for market-based contractual claims by suppliers or
end-users. By contrast, a residual mix in the market- based method should represent all unclaimed energy emissions, which is formulated by removing contractual claims data from energy production data (often the same as grid average data).
- Grid average emission factors are different from marginal grid emission factors.
Grid average emission factors should represent all the emissions from energy generation occurring within a defined geographic region, and thereby best represent the purpose of the location-based method. By contrast, marginal emission factors only represent the emissions from those power plants operating “at the margin,” which can be more useful for avoided emissions analyses. Companies shall not use marginal emission factors such as those provided by CDM for a location- based scope 2 calculation.
6.10.1 Grid average emission factors
The term “grid average” emission factors reflects a short- hand for a broad category of data sets that characterize all the GHG emissions associated with the quantity of electricity generation produced from facilities located within a specified geographic boundary. Many of these data sets have been compiled for purposes other than corporate accounting and can vary in their inclusion of energy-generation emissions (e.g., which GHG gases
are included, and how biomass and CHP emissions are treated) and perhaps most significantly, in the spatial facility-inclusion boundaries. Greater consistency in grid average emission factors globally can improve location- based inventory results that encompass multiple global operations parameters. A simplified illustration of the type of data aggregation and calculation that contributes to a grid average emission factor is shown in Table 6.6.
- Spatial boundaries.
The most appropriate spatial boundaries for emission factors serving the location-based method are those that approximate regions of energy distribution
and use, such as balancing areas. All generation and emissions data within this boundary should be aggregated and any net physical energy imports/ exports and their related emissions should be taken
into account. 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.
- Other data quality.
Companies can evaluate emission factor data based on quality indicators including their reliability, completeness, and geographic, temporal, and technological representativeness. Grid-average emission factors in particular may face challenges
with temporal representativeness due to time delays between the year in which energy generation and
resulting emissions occurred, and the year in which the data is published and made available to users.
For U.S. eGRID or IEA, these delays can be 2–3 years.
This delay can make grid average emissions factors a less relevant indication of corporate performance or risk assessment when analyzed in the inventory year. Companies should take this into account when analyzing location-based scope 2 results.
6.11 Market-based emission factors data
Under the market-based method, different contractual instruments become carriers of GHG-emission rate information that function as emission factors for consumers to use to calculate their GHG emissions. To ensure this, instruments shall include the GHG emission rate attribute. If companies have access to
multiple market-based emission factors for each energy- consuming operation, they should use the most precise for each operation based on the list in Table 6.3.
6.11.1 Energy attribute certificates
Certificates form the basis of energy attribute tracking in the market-based method, often being conveyed with contracts for energy and integrating into supplier- specific emission rates. See Chapter 10 for more background on certificate types and treatment.
6.11.2 Contracts such as power purchase agreements (PPAs)
These types of contracts allow a consumer, typically larger industrial or commercial entities, to form an agreement with a specific energy generator. The contract itself specifies the commercial terms, including delivery, price, payment, etc. In many markets, these contracts secure a long-term stream of revenue for an energy project.
Where certificates are issued: In these cases, the certificates themselves serve as the emission factor for the market- based method. 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.
When certificates are not used in the jurisdiction or for the technology/resource: Where certificates are not issued by a tracking system, a PPA may nevertheless convey generation attributes if the PPA includes language that confers attribute claims to the power recipient. This more explicitly renders the PPA a GHG attribute-claims carrier. Where the PPA is silent on attributes and where attributes are not otherwise conveyed or tracked, the contract for power can be used as a proxy for delivery of attributes.
As shown in the Scope 2 Quality Criteria, an audit trail or other mechanism is needed to demonstrate that no other entity is claiming the attributes from this generation.
When the power received in the PPA is resold: If the power purchased in a PPA is resold to the wholesale or retail market, then the company receiving-and-reselling the power cannot claim the “use” of the attributes in markets where certificates are not used. In markets with certificates, the company may retain the certificates from the power generation to use for its own claims while it resells the power.
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.
6.11.3 Supplier-specific emission rate
Electricity suppliers or load-serving entities function differently across markets. In some deregulated markets, there may be retail competition within the group of entities that interface directly with customers. In other regulated monopoly markets, a single utility may supply an entire service territory. In all cases, an energy supplier can provide information to its consumers regarding the GHG intensity of delivered electricity. The utility or supplier-specific emission factor may be a standard product offer or a differentiated product (e.g. a renewable energy product or tariff). When using a supplier-specific emission factor, companies should seek to ensure that:
- The emission rate is disclosed, preferably publicly, according to best available information, and where possible using best practice methods such as The Climate Registry Electric Power Sector Protocol. Methods for calculating and disclosing the mix and related attributes may also be specified by regulation.
- That the utility or supplier discloses whether and how certificates are used in the emission factor calculation, unless there is third-party certification of the utility product. In particular, companies should seek to ensure that if the supplier has a differentiated product (e.g. a renewable energy product or tariff), the certificates or other contracts used for that product should be used only for that product and not counted in the standard product offer.
- That the supplier-specific emission factor includes emissions from all the energy delivered by the utility, not just the generation assets owned by the supplier (e.g. what is required by some fuel mix disclosure rules). Many suppliers purchase significant portions of their energy from other generators via contracts, or through the spot market. The emission factor should reflect the emissions from all of these purchases. A supplier-specific emission rate can also reflect certificates retired for compliance purposes (such as U.S. state RPS programs) which also convey attributes for public benefit and claims.
Consumers should not attempt to calculate a supplier- specific emission rate themselves based on a fuel mix disclosure due to the variations in fuel mix disclosure rules, which may reduce the accuracy of the resulting GHG emission factor.
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.
6.11.4 Residual mix
To prevent double counting of GHG emission rate claims tracked through contractual instruments, the market-based method requires an emission factor that characterizes the emission rate of untracked or unclaimed energy. This emission factor creates a complete data set under the market-based method, and represents the regional emissions data that consumers should use if they operate in a market with choice for consumers, differentiated products, and supplier specific data, but did not purchase certificates or a specified product, do not have a contract with a specified source, or do not have supplier-specific information.
Depending on the region and percentage of tracked electricity, this residual mix may closely resemble a “grid average” data set, or may be significantly different. In the U.S. overall, an estimation of the adjusted mix in 2009 did not differ significantly from the location-based grid average data. In fact, according to a paper by the Environmental Tracking Network of North America (ETNNA 2010), the difference is currently less than one half of one percent.
Companies should not attempt to calculate their own residual mix.
- If a residual mix is not available. Other unadjusted grid average emission factors such as those used in the location-based method may be used. Companies shall document in the inventory that a residual mix was not available.
6.12 Treatment of biofuel emissions
Biogenic materials—including biomass, biofuels, and biogas—are increasingly used as a resource for energy generation on-site and on the grid. While biomass can produce fewer GHG emissions than fossil fuels and may be grown and used on a shorter time horizon, it still produces GHG emissions and should not be treated with a “zero” emission factor. 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 practice, this means that any market-based method data that includes biofuels should report the CO2 portion of the biofuel combustion separately from the scopes.
For the location-based approach, most commonly used grid average emission factor—including those issued by EPA eGRID (U.S.), Defra (U.K.), and the International Energy Agency (for all countries worldwide)—do not note the percentage of biomass in the emission factor and do not separately report the biogenic CO2, effectively treating it as “zero” emissions. Companies should document this omission in any grid average emission factors used.