Summary: This is an extract from Appendix B - Accounting for Energy-Related Emissions Throughout the Value Chain
Accounting in a grid-connected electricity value chain
For scope 2 reporting, differences in the regulatory structure of electricity supply chains can impact overall energy procurement options and what emissions are included in a supplier-specific emission factor. They also determine which entity reports which emissions in the energy value chain, as shown below.
The mechanics of electricity distribution on any grid function largely the same way, with the four supply chain phases including: (1) material or fuel extraction and processing; (2) generation; (3) transmission and distribution; and (4) sales to, and consumption by, end users. Different regulatory structures at a regional, national, and subnational level can influence what entities are involved throughout the phases of energy generation, transmission, distribution, and service. For instance:
- In some markets, the utility owns the generation assets, transmission and distribution (also known as T&D) infrastructure, and interfaces with the consumer to deliver energy. These entities would report all generation emissions in scope 1, and no T&D losses would be reported separately since the emissions would be already reported in scope 1.
- In others, power generators may be independent entities from which the utility buys power.
- In fully deregulated or competitive markets, each activity in the supply chain could be conducted by a different company. For instance, a customer may interface with energy retailers or suppliers who only sell electricity but who do not own generation assets or T&D equipment. Because these entities purchase and sell, but do not produce or consume the energy, they do not record either scope 1 or scope 2 emissions from the energy they sell.
Figure B.1 illustrates in which scope each entity in the electricity supply system (depicted in the rows) accounts for the emissions occurring during these different phases of electricity generation, distribution, and use (depicted as phases in the column).
See Appendix A of the Corporate Standard for more information on these relationships.
Accounting for energy-related emissions in scope 3
Scope 2 emissions from different value chain partners form the basis of almost all fifteen scope 3 categories. Therefore, companies obtaining energy emissions data from their suppliers to be used in scope 3 calculation should ask which scope 2 method was used to calculate the results. In turn, companies should be transparent about which scope 2 method total they share with others in their value chain.
Category 3: Upstream fuel and energy-related activities
For an energy consumer, category 3 includes upstream emissions from fuel extraction and processing prior to its combustion (known as the cradle-to-gate emissions) as well as the energy consumed (e.g. “lost”) during transmission and distribution. Because of T&D losses, the actual amount of electricity generated at a power plant will be greater than the total electricity consumed by customers alone.1 On-site generation does not incur T&D losses, as there is virtually no “line” in which transmission and energy losses occur.
The energy quantity consumed and reported in scope 2 serves as the basis for determining T&D activity data.
One example of how this can be calculated is by applying the grid loss factor (ex: 7 percent grid loss rate for 100MWh consumption would mean 7MWh lost in T&D).Companies may also get information on line losses from the entity that controls the lines. Companies would need to apply an emissions factor to that line loss consumption to determine emissions associated with the loss. Companies should disclose which calculation method they are using to calculate and report T&D losses in scope 3 category 3, but do not need to “dual report” this. For instance, if companies, their suppliers, or other value chain partners have purchased energy attribute certificates to cover the quantity of grid losses, they can report this calculation based on the market-based method procedures in this Guidance. If not, companies should use the location-based method emission factors.
Companies should also disclose which scope 2 results— location-based or market-based—they are using as the basis for calculating upstream fuel extraction and processing emissions. For example, a scope 3 category 3 assessment based on the results of a location-based scope 2 report could reflect the upstream profile of the mix of grid resources (natural gas, coal). A category 3 assessment based on the results of a market-based scope 2 report could reflect the upstream emissions associated with producing renewable energy.
Category 15. Investments.
Any investments in energy generation facilities or other projects not associated with a contractual arrangement reflected in scope 2 can report emissions from these investments in category 15.
For scope 3 calculation procedures, see GHG Protocol Value Chain (Scope 3) Standard and Scope 3 Calculation Guidance.
