Summary: This is an extract of Chapter 4. This chapter provides an overview of the two scope 2 accounting methods required by this guidance. It outlines how these methods’ results can inform decisions that contribute to reductions in the electricity sector.
Approaches to accounting scope 2
Calculating scope 2 emissions requires a method of determining the emissions associated with electricity consumption. Primarily two methods have been used by companies, programs, and policy makers to “allocate” the GHG emissions created by electricity generation to the end consumers of a given grid. Consumer GHG accounting in scope 2 completes this allocation process through emission factors applied to each unit of energy consumption. This guidance terms these methods the (a) location-based and
(b) market-based methods. In short, the market-based method reflects emissions from electricity that companies have purposefully chosen (or their lack of choice), while the location-based method reflects the average emissions intensity of grids on which energy consumption occurs.
Table 4.1 compares the methods in terms of their objectives and the aspects of corporate purchasing and consuming of electricity that are emphasized. Chapter 6 lists the emission factors associated with each method.
Location-based method
This method can apply in all locations since the physics of energy production and distribution functions the same way in almost all grids, with electricity demand causing the need for energy generation and distribution. It emphasizes the connection between collective consumer demand for electricity and the emissions resulting from local electricity production. This includes an overall picture of the mix of resources required to maintain grid stability (see Box 4.1). The location-based method is based on statistical emissions information and electricity output aggregated and averaged within a defined geographic boundary and during a defined time period.
Grid average emission factors should be distinguished from supplier-specific emission factors. While utilities may be the sole energy provider in a region and produce a supplier- specific emission factor that closely resembles the overall regional grid average emissions factor, this utility-specific information should still be categorized as market-based method data due to the wide variation in utility service areas and structures. For instance, the utility service territory may 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 the broader energy generation profile for a region, regardless of supplier relationships.
Market-based method
The market-based method reflects the GHG emissions associated with the choices a consumer makes regarding its electricity supplier or product. These choices—such as choosing a retail electricity supplier, a specific generator, a differentiated electricity product, or purchasing unbundled energy attribute certificates—are conveyed through agreements between the purchaser and the provider.
Under the market-based method of scope 2 accounting, an energy consumer uses the GHG emission factor associated with the qualifying contractual instruments it owns. In contrast to the location-based method, this allocation pathway represents contractual information and claims flow, which may be different from underlying energy flows in the grid. The certificate does not necessarily represent the emissions caused by the purchaser’s consumption of electricity. One company choosing to switch suppliers does not directly or in the short-term impact the entire operation of the grid and its emissions. Over time, the collective consumer demand for particular energy types and their resulting attributes (e.g., zero GHG emissions from generation) can send a market signal to support building more of those types of generation facilities, just as purchasing any product sends the market signals to produce more of that product.
While only a few countries around the world have established markets for certificates that support this method, large electricity consumers in many other markets may find opportunities to purchase a differentiated product or enter into contracts directly. The market-based method has historically been associated with green power purchasing options. However, it is designed to integrate with, and include, existing systems for supplier portfolio disclosure and nonrenewable energy contract types as well. Since no market has instituted comprehensive energy tracking by contractual instruments,2 this method uses some of the same energy production and emissions data from the location-based method for any energy not tracked by an instrument. The emissions from all untracked and unclaimed energy comprise a residual mix emission factor. Consumers who do not make specified purchases or who do not have access to supplier data should use the residual mix emission factor to calculate their market-based total.
With this method, individual energy consumers have the opportunity to make decisions about their product and supplier, which can then be reflected as a supplier or product-specific emission factor in scope 2.
Emission rate approach
These scope 2 accounting methods have several features in common, including:
- They use generation-only emission factors (e.g. emissions assessed at the point of energy generation), designed to label emissions associated with a quantity of electricity delivered and consumed. The emission factors do not include T&D losses or upstream life- cycle emissions associated with the technology or fuel used in generation. Instead, these other categories of upstream emissions should be quantified and reported in scope 3, category 3 (emissions from fuel- and energy-related activities not included in scope 1 or scope 2). In the case of supplier-specific emission factors, the emission factor should reflect emissions from all delivered energy, not just from generation facilities owned/operated by the utility.
- They represent emission rates that allocate emissions at generation to end-users. This type of treatment
is consistent with corporate inventory approaches across other scopes, particularly with product-specific emission factors or labels. Both methods should
be applied comprehensively to ensure all energy generation emissions within a defined region have been accounted for.
- This guidance does not support an “avoided emissions” approach for scope 2 accounting due to several important distinctions between corporate accounting and project-level accounting. However, companies can report avoided grid emissions from energy generation projects separately from the scopes using a project-level accounting methodology.
The decision-making value of each method’s results
The Corporate Standard notes that reductions in indirect emissions (changes in scope 2 or 3 emissions over time) may not always capture the actual emissions reduction accurately. This is because there is not always a direct cause-effect relationship between the single activity of the reporting company (purchasing and consuming energy) and the resulting GHG emissions on the grid.3 Generally, as long as the accounting of indirect emissions over time recognizes activities that in aggregate change global emissions, any such concerns over accuracy should not inhibit companies from reporting their indirect emissions.
These two scope 2 accounting methods each provide a different “decision-making value” profile—that is, different indications of performance and risks, revealing different levers to reduce emissions and reduce risks. Ultimately, system-wide emission decreases are necessary over time to stay within safe climate levels. Achieving this requires clarity on what kinds of decisions individual consumers can make to reduce both their own reported emissions as well as contribute to emission reductions in the grid. Working backward from those decisions to the methods used to calculate emissions, there are three types of decisions companies can make that impact overall electricity grid emissions. These decisions include facility siting, the level and timing of demand, and supporting supply shifting.
While companies may make decisions related to these categories for non-GHG considerations, all the decisions carry GHG implications.
Facility and operations-siting decisions
A company’s decisions about where to locate its office buildings, industrial facilities, distribution centers, or data centers carries GHG implications. The physical location of these points of energy consumption impacts what existing, or future, energy resources may be able to be deployed to meet demand. For instance, locating new facilities on a GHG-intensive grid means that in the near term, energy demand will be met with a higher GHG emissions profile, assuming that the energy is consumed locally. By contrast, locating operations in areas with low-carbon natural resources, or additional benefits such as natural ambient cooling or heat, can reduce these GHG emissions risks (as shown in the location-based method).5 Ambient heat/cooling will also be reflected in lower use of heat/cooling and will be seen in both the location-based and market-based methods. Companies considering electric transportation fleets also need to ensure the availability of charging infrastructure and the GHG-intensity of the grids where that transportation would occur.
The physical location also aligns with a national or subnational set of regulatory rules governing what types of energy product or energy supplier choices a consumer can make. This location highlights different pathways and options for corporate influence over the energy supply mix over time (as shown in the market-based method).
Therefore, a company’s shift in facility location will result in changes in scope 2 based on:
- location-based. The use of a different grid average emission factor, and possibly a shift in energy supply overall, if the new location allows for on-site energy generation or is locating near an energy development where a direct line connection can be made.
- Market-based. Changes in supplier (new utility service area), changes in other types of contractual instruments, actions of other consumers in the market, or the residual mix used in that location.
Decisions on the level and timing of demand Once a company has established a location for its operations, it can reduce its emissions through energy demand reduction.6 A company can reduce energy consumption through measures such as choosing an energy-efficient building, carrying out energy-efficient retrofits, using more efficient electronics or lighting, and making behavioral decisions. Increasingly, “smart grid”7 information and systems are allowing more geographically and temporally precise data to support energy demand management at a consumer level, including end-use equipment timing (e.g., running dishwashers or washing machines during optimal times of day such as low-cost, or non-peak times). Utilities may also provide this type of data to energy-intensive consumers as part of demand-side management (DSM) programs and peak-shaving efforts. The location-based method assumes that local demand impacts local generation and distribution patterns, which ultimately impact total GHG emissions from the system (taking into account physical energy imports/exports). While demand is met with incremental resources, grid-average emission factors provide more readily available averages calculated over the course of a year.
Therefore, a company’s shift in energy demand quantity and timing will entail changes in reported scope 2 primarily through activity data. In both methods, a decrease in electricity consumption can decrease total reported scope 2.
- location-based.
Collective changes in consumption contribute to changes in the the grid average emission factor over time. Shifting energy consumption to periods with of low-emissions generation on the grid (often non-peak hours) can further contribute to system-wide reductions. Advanced grid studies can better highlight the emissions impacts of these individual consumption decisions (see Chapter 6).
- Market-based.
Reducing electricity demand can minimize the additional costs associated with purchasing contractual instruments at a premium above standard electricity costs. However, the market- based method runs the risk of providing less visibility on energy demand reduction if the price of this premium (and therefore the price of achieving “zero emissions”) is low. But efficiency can generally be pursued with financial gain regardless of the specific emissions associated with electricity consumption.
Decisions to influence grid mix of generation technologies
Many variables impact the mix of generation technologies on a given grid, including the historical regulatory, financial, and physical characteristics of the jurisdiction
as well as the current market dynamics of supply/
demand for particular resources. An electricity consumer can pursue a variety of actions to try to influence these factors directly or indirectly, conveying stronger or weaker market signals (see Chapter 11). If consumers want to support low-carbon technologies, they can:
- Create on-site low-carbon energy projects
- Establish contracts, that include certificates, such as PPAs directly with low-carbon generators
- Negotiate with their supplier or utility to supply low- carbon energy to the company
- Switch to a low-carbon electricity supplier or electricity product, where available
- Purchase certificates from low-carbon energy generation.
Substantially changing a grid’s resource mix over time generally requires aggregate consumer decisions, or a large-scale corporate consumer representing a significant percentage of a utility’s load. But all of these interventions benefit from, and depend on, a contractual instrument (e.g. certificate) that confers specific GHG- emission attribute claims associated with purchases, functioning as a demand-signaling mechanism.
Therefore, efforts to shift grid supply through procurement will entail changes in reported scope 2 based on:
- location-based.
Cumulative effect of consumer or supplier choices over time that change the grid average emissions factor. (Other factors such as economics and environmental regulation can also impact this.) But individual corporate choices regarding electricity contracts, supplier choices, or certificate purchases are not directly reflected in an individual’s scope 2 inventories using the location- based method.
- Market-based.
Individual corporate choices of electricity product or supplier, or the lack of a differentiated choice, which requires the use of a residual mix. Many market-based tracking systems currently only reflect renewable generation contractual instruments, but the method should reflect any type of contract or supplier-specific emission factor that meets the Scope 2 Quality Criteria. Chapter 11 addresses how companies can use the market-based method to drive supply change.