Each tool generally involves the use of ‘emission factors,’ which relate the amounts of greenhouse gases emitted by a business to a set amount of activity performed by that business. Default values are always provided for the emission factors in case businesses cannot develop custom values. So, in many cases companies need only activity data, such as the amount of distance traveled or fuel combusted, to calculate their emissions.
The default emission factors are averages based on the most extensive data sets available and they are largely identical to those used by the Intergovernmental Panel on Climate Chage (IPCC), the premier authority on accounting practices at the national level. However, the GHG Protocol recommends that businesses should use custom values whenever possible. This is because the industrial processes or the composition of fuels used by businesses may differ with time and by region.
The GHG Protocol defines direct and indirect emissions as follows:
- Direct GHG emissions are emissions from sources that are owned or controlled by the reporting entity.
- Indirect GHG emissions are emissions that are a consequence of the activities of the reporting entity, but occur at sources owned or controlled by another entity.
The GHG Protocol further categorizes these direct and indirect emissions into three broad scopes:
- Scope 1: All direct GHG emissions.
- Scope 2: Indirect GHG emissions from consumption of purchased electricity, heat or steam.
- Scope 3: Other indirect emissions, such as the extraction and production of purchased materials and fuels, transport-related activities in vehicles not owned or controlled by the reporting entity, electricity-related activities (e.g. T&D losses) not covered in Scope 2, outsourced activities, waste disposal, etc
The calculations tools are electronic Excel spreadsheets with accompanying step-by-step guidance documents. A guidance document includes:
- An overview of the protocol with information on the sector, sources, and process(es) that it covers;
- One or more approaches for determining CO2 and other GHG emissions, e.g., direct measurement, mass balance, etc.;
- Guidance on collecting activity data and selecting appropriate emission factors;
- Likely emissions sources and the scopes they fall under (specific to a particular sector);
- Additional information, such as quality control practices and program specific information.
The spreadsheets help carry out any necessary emissions calculations.
These tools were developed in partnership with industry experts and represent best practice quantification methodologies. The calculation tools are available on the GHG Protocol website and are meant to complement the Protocol and make calculations easier, but their use is not mandatory.
The following guidelines for T&D emission losses should be followed to help avoid double counting. Note that published electricity grid emission factors do not generally include T&D losses.
For a company that purchases its electricity from a T&D system, but does not own any part of the system, T&D losses should not be included in a Scope 2 inventory. They may be included in a Scope 3 inventory labeled “generation of electricity that is consumed in a T&D system”.
For a company that purchases its electricity and transports it through a T&D system, T&D losses should be included in Scope 2 emissions, since the losses are a portion of direct emissions from the “use” (loss) of purchased electricity.
For a company that owns the T&D system and also produces the electricity that runs through it, T&D losses should be included in Scope 1 emissions. This is because the emissions are a direct emission resulting from the production of a good.
According to the GHG Protocol Corporate Standard, emissions resulting from the use of sold products may be included as Scope 3 emissions in an inventory. However, since these emissions are often very difficult to quantify, the benefits of including them in a corporate inventory should first be weighed against the potentially high costs of collecting the data.
Due to the biogenic differences between fossil fuels and biomass, they are categorized differently in national inventories. Emissions of CO2 from the combustion of biomass are reported for informational purposes, but not included in national totals. This is because any net additions of CO2 to the atmosphere resulting from biomass combustion should be captured by analyzing land-use, land-use change activities and their associated effects on terrestrial biomass carbon stocks. In other words, the “emissions” are counted when the trees are cut, not when they are burned. If, at the national level, biomass harvests exceed growth and regeneration, the resultant depletion of national biomass stocks result in a net “emission” (flux to the atmosphere).
When reporting corporate-level greenhouse gas inventories, the accounting of terrestrial carbon stock changes associated with harvesting and combustion of biomass may fall within the organizational boundaries of different companies, i.e., the wood being burned is not cut on land owned by the company. Recognizing this situation, and considering the national inventory practices, the Corporate Standard requires that CO2 emissions from biomass combustion be reported separately from the other scopes in a memo item.
When calculating emissions from the burning of biomass by electricity providers, the amount of CO2 emissions would reflect the amount of biomass they use, i.e., if they burn only biomass, their emission factor would be zero. Unlike CO2 emissions, the combustion of biomass does in all cases result in net additions of CH4 and N2O to the atmosphere, and therefore emissions of these two greenhouse gases as a result of biomass combustion should be accounted for in emission inventories under Scope 1.
No. WRI and WBCSD are not regulatory bodies. Their role is to initiate and guide the development of high quality GHG accounting and reporting protocols and standards, which may be used by regulatory bodies and any other entities interested in GHG accounting and reporting.