Scope Type: Indirect Emissions
Description of Emissions
Emissions resulting from the generation of purchased utilities (electricity, steam, hot water, chilled water, etc) that are consumed by a company’s owned or controlled operations or equipment are reported as indirect emissions. For many companies, purchased utilities (primarily electricity) represent one of the largest sources of GHG emissions, as well as the most significant opportunity to reduce these emissions. Accounting for indirect emissions allows companies and institutions to assess the risks and opportunities associated with changing utility (primarily electricity) and GHG emissions costs.
Companies and institutions can reduce their use of electricity and other purchased utilities by investing in energy efficient technologies and energy conservation. Additionally, emerging green power markets provide opportunities for some companies to switch to less GHG- intensive sources of electricity. Reporting of indirect emissions allows transparent accounting of GHG emissions and reductions associated with such opportunities.
Emission Factors
The most appropriate and practical method to measure GHG emissions associated with the consumption of purchased electricity, heat, and/or steam is based on the emission factor-based methodology. The emission factor-based methodology estimates GHG emissions by multiplying a level of activity data (e.g., kWh of electricity consumed by a facility) by an emission factor (e.g., grams of CO2 per kWh).
The calculation of indirect emissions resulting from the purchase of utilities is a fairly straightforward equation:
The activity data that should be collected to measure GHG emissions is the quantity of purchased electricity, heat, and/or steam consumed. Electricity consumption is generally measured in kilowatt hours (kWh) or megawatt hours (MWh). Data on heat and/or steam use is often collected in British thermal units (Btu), joules (J), therms, or pounds.
Emissions factors for electricity, heat, and/or steam vary with season, time of day, and supplier. There is also the issue of whether to use marginal or average rates when calculating CO2 emissions associated with electricity, heat, and/or steam consumption. As it is usually not practical to take all of these variables into account, and since marginal rates are often not widely available, the use of average rates in the calculation of an entity’s indirect emissions is the most practical method. Emission factors can be determined from one of three methods: site specific, regional/power pool, or national average listings. They are each outlined below:
- Site-specific emission factors: This is the most accurate option, but it generally only applies to large industrial customers who have a direct supply and transmission contract with a specific electricity, heat, and/or steam supplier in the vicinity. In this case, the emission factor should be based on the actual fuel fired and the technology employed by the electricity, heat, and/or steam supplier.Regional/power pool emission factors: This is a generic, regional or power pool emissions factor that has been published by the government in the country where the facility is located. Government statistics may be aggregated by power pool region or state. For example, the US EPA’s eGRID provides aggregated data for regions and sub-regions of the power grid, as well as information for every power plant and generating company in the US. The Canadian GHG Challenge Registry publishes provincial emission factors in the Registry Guide. Regional power pool data is preferable to state data, as transmission and distribution grids often cover multiple states. Power pool data more accurately reflects the generation mix for a region.
- National average emission factors: If regional or power pool emission factors are not available, use an appropriate, generic national average factor for the entire country’s grid. These statistics have been developed by the International Energy Agency (IEA) and UNEP and do not include transmission losses.
