Introduction to the Calculator

The EPA’s Simplified GHG Emissions Calculator is designed to help businesses of all sizes take control of their environmental impact. This user-friendly tool looks at both Scope 1 direct emissions and Scope 2 indirect emissions, providing a comprehensive view of your carbon footprint. Leveraging the calculator is essential for accurately tracking and managing emissions, enabling organizations to identify key areas for improvement and make informed decisions that drive sustainability efforts.

The EPA Simplified GHG Emissions Calculator is a user-friendly tool that helps organizations estimate their yearly greenhouse gas emissions in the US. It uses the latest guidelines and data from the United States Environmental Protection Agency (EPA) to calculate emissions. By inputting their activity data, organizations can determine both their direct and indirect emissions for the year. The Calculator allows the user to estimate GHG emissions from Scope 1 (direct), Scope 2 (indirect), and some Scope 3 (other indirect) sources.

This article focuses on Scope 2 emissions by reviewing each tab individually to help you navigate the tool. For a general overview of concepts review within the calculator, check out my Simplified Guide to Greenhouse Gas Management for Organizations. For a more detailed guide to setting up your organization’s Scope 1 GHG inventory using the EPA calculator, check out my Scope 1 Guide to EPA’s Simplified GHG Emissions Calculator.

Operational Boundaries

With regards to emission sources, a typical office-based organization will likely have the following (Scope 1 and 2) emissions sources: stationary combustion, refrigeration and air conditioning, and electricity. For those in the industrial sector, such as pulp and paper, cement, chemicals, and iron and steel, you may have sector- specific emission sources that are not covered by the Calculator. Instead, look to EPA’s Greenhouse Gas Reporting Program (GHGRP) which provides guidance and tools that can aid in the calculation and reporting of these emissions.

If you answer “yes” to a scope question below, that emissions source should be included in your Scope 2 inventory.

Scope 2 inventory inclusion:

1. Electricity: Does your inventory include facilities that use electricity?
2. Steam: Do you purchase steam for heating or cooling in your facilities?
3. Market-Based Emission Factors: Do you purchase renewable energy certificates (RECs) or green power products? Do you purchase electricity through a power purchase agreement (PPA)? Do you have supplier-specific emission factors?

While Electricity and Steam are their own separate tabs within the Calculator, market-based emission factor data is entered as part of the Electricity and or Steam sections.

Emissions from the Purchase of Electricity

Scope 2 emissions from the purchase of electricity come from the electricity your organization buys to power its operations. These emissions are calculated using two methods: a location-based method and a market-based method. Both methods need to be reported in your GHG inventory. The location-based method uses average emission factors from the electricity grids that supply power to your locations. The market-based method accounts for specific contracts your organization may have, such as purchasing renewable energy.

Data Collection Checklist:

1. Total annual electricity purchased in kilowatt-hours (kWh) for each facility or site.
2. eGRID subregion for each facility or site.

Location-Based Method for Purchased Electricity

The location-based method calculates emissions using the average emission factors associated with the electricity grids that supply power to your facilities. This method reflects the overall mix of energy sources used by the grid, such as coal, natural gas, nuclear, and renewables, regardless of any specific contractual arrangements your organization might have. It provides a more generalized view of emissions by considering the typical energy generation mix in the region where your facilities are located. This approach ensures that all electricity consumption is accounted for, based on the regional grid’s average emissions, offering a standardized way to estimate Scope 2 emissions.

The location-based method relies on standardized emission factors tied to the facility’s geographic location. This method uses eGRID subregions to determine the appropriate emission factors, based on the regional energy mix of the grid. This ensures that emissions reflect the typical sources of electricity generation in the specific geographic area where the facility is located. The appropriate eGRID subregions can be found using an eGRID Subregion Map (see image below). A more detailed eGRID subregion map which includes CO₂ total output emission rate (lb/MWh) is available from the EPA’s Data Explorer. If the subregion cannot be determined from the map nor the explorer, you can find the correct subregion by entering the location’s zip code into EPA’s Power Profiler.

For the market-based method, if your organization has specific emission factors from contracts, enter these in the yellow cells within the Calculator. If no specific factors apply, use the eGRID subregion factors provided. For example, your facility purchases Renewable Energy Certificates (RECs) for 100% of its electricity, you would enter a market-based emission factor of 0.

Market-Based Method for Purchased Electricity

The market-based method involves calculating Scope 2 emissions based on specific contracts your organization has with energy providers. These contracts determine the emission factors you should use, depending on where and how your electricity is generated. Here’s a breakdown of the types of market-based emission factors you might encounter, listed in order of preference:

1. Energy Attribute Certificates (EACs): These certificates represent renewable energy, like Renewable Energy Certificates (RECs) or Guarantees of Origin (GOs). If you hold a certificate with an associated emission factor, use that factor in your calculations. Typically, RECs represent zero emissions, but they might have a non-zero factor if fossil fuels were involved in generation.
2. Contracts: If your organization has a contract, such as a Power Purchase Agreement (PPA), to buy electricity from a specific facility, use the emission factor linked to that contract. This applies regardless of where the facility is located or how far it is from your operations.
3. Supplier-Specific Emission Factor: Some electricity suppliers provide their customers with an emission factor that reflects all the electricity they generate or purchase. If you have this information, use it.
4. Residual Mix Factor: If certificates, contracts, or supplier-specific factors don’t apply, a residual mix factor can be used. This factor accounts for emissions after the removal of certificates and contracts. Residual mix factors aren’t always available, so check annually when completing your GHG inventory.
5. Regional Emission Factor: If no residual mix factor is available, use the regional grid average emission factor. This is the default option and aligns with the location-based method.
6. National Emission Factor: This factor is generally not applicable for companies reporting U.S.-based emissions, as regional factors are usually available.

Quality Criteria for Contractual Instruments:

To ensure accuracy, any contractual instruments used in the market-based method should meet the following criteria:

1. Direct GHG Emission Rate: The instrument must convey the direct GHG emission rate of the electricity produced.
2. Exclusive Attribute Claim: It must be the only instrument that carries the GHG emission attribute claim for that quantity of electricity.
3. Tracked and Redeemed: The instrument should be tracked and redeemed, retired, or canceled by or on behalf of the reporting entity.
4. Vintage Match: The vintage (date of the energy generation) should match as closely as possible to the reporting period.
5. Market Sourcing: The instrument should come from the same market as the organization’s electricity-consuming operations.

The EPA encourages the use of renewable energy to reduce environmental impacts. Organizations can lower their market-based Scope 2 emissions by purchasing renewable energy through differentiated products, direct contracts, or RECs. These RECs must be acquired and retired to count.

If your organization purchases electricity from a specific source that doesn’t cover 100% of your facility’s consumption, it’s important to allocate the kWh correctly:

• Building A: 100,000 kWh total consumption, 25,000 kWh with RECs, and the remainder without specific factors.
• Building B: 50,000 kWh total consumption, all purchased from a local utility.

In this example, enter data for Building A in two rows—one for the RECs and another for the remaining electricity. Ensure total kWh is accurate without double counting. If no market-based factor is available, use location-based emissions as your fallback.

Emissions from the Purchase of Steam

Like electricity, the purchase of steam falls under Scope 2 indirect emissions because it involves the consumption of energy that is generated off-site by a third party, which is then delivered to the site. Purchased steam is typically delivered to a facility through a network of insulated pipes designed to maintain high temperatures and minimize heat loss during transport. Although the actual emissions occur at the generating facility (i.e. “off-site” from the reporting company), since the reporting (purchasing) company benefits from the energy, it bears responsibility for the associated emissions.     By including purchased steam under Scope 2, the GHG Protocol ensures that organizations are accountable for emissions tied to their energy consumption, even if those emissions occur off-site.

Once the steam reaches the facility, it can be used for various purposes, such as powering turbines, heating spaces, providing heat for industrial processes, or humidifying environments. The purchasing facility often has systems to monitor the flow and usage of steam to manage costs and optimize energy efficiency. This delivery process allows facilities to benefit from steam without having to generate it on-site, enabling them to focus on their core operations while utilizing an efficient, often centralized energy source.

The calculator’s output for purchased steam will be in metric tons of CO2e and divided out by location-based and market-based electricity emissions. Both stationary combustion (Scope 1) and purchased steam (Scope 2) use fuel-specific heat content for conversions. If you are sharing a facility with other tenants and don’t have specific steam consumption data, estimate your steam usage by multiplying the total facility’s steam consumption by the percentage of the floor area occupied by your organization.

Data Collection Checklist:

1. Amount of steam purchased in mmBtu (British thermal units). Heat content units may need conversion.
2. Fuel Type” used to generate the steam.
3. Either the supplier-specific emission factors or the boiler efficiency. If boiler efficiency is not known, a default value of 80% is provided.

Purchased steam fuel types listed in the calculator are:

• Natural Gas
• Distillate Fuel Oil No. 2
• Residual Fuel Oil No. 6
• Kerosene
• Liquified Petroleum Gases (LPG)
• Anthracite Coal
• Bituminous Coal
• Sub-bituminous Coal
• Lignite Coal
• Mixed (Electric Power Sector)
• Coal Coke
• Wood and Wood Residuals
• Landfill Gas

Methodologies for Calculating Emissions from Purchased Steam

A. Preferred Method (Supplier-Provided Emission Factors):

In this method, companies use emission factors provided by the steam supplier to calculate emissions associated with purchased steam. These factors are typically expressed in terms of pounds (or kilograms) of CO₂, CH₄, and N₂O per unit of energy (e.g., per mmBtu of steam). This is the most accurate method, as the emission factors reflect the specific fuel mix and efficiency of the supplier’s steam generation process.

If the supplier is able to provide emission factors for CO₂, CH₄, and N₂O, use those. If no factors are available, leave calculator cells blank. Emission factors should be expressed in lbs/mmBtu of steam (convert using appropriate heat factors if necessary). Boiler efficiency does not need to be entered if supplier emission factors are provided. Typically, the supplier emission factors apply to both location-based and market-based emissions. If market-based emission factors differ, be sure to update the calculator to reflect this.

Key Steps:

1. Obtain Supplier-Specific Emission Factors: The steam supplier provides emission factors for CO₂ (carbon dioxide), CH₄ (methane), and N₂O (nitrous oxide).
2. Input Data into Calculation Models: These factors are used to calculate the total emissions based on the amount of steam purchased.
3. Calculate Emissions: Multiply the amount of steam purchased (in energy units such as mmBtu) by the respective emission factors for each greenhouse gas.
4. Include Both Location-Based and Market-Based Emissions: Typically, the same emission factors apply for both location-based and market-based reporting, though sometimes market-based factors differ (e.g., if renewable energy credits are involved).

B. Alternative Method (No Supplier-Specific Emission Factors):

When supplier-specific emission factors are not available, companies can estimate emissions using default boiler efficiency values and general emission factors for the fuel types typically used to generate steam. In this case, emissions are calculated based on an assumed efficiency of the boiler that produced the steam and a standard set of emission factors for the fuel. This method provides a reasonable estimate when specific data is not available, while still allowing companies to account for steam-related emissions without relying on supplier-provided data.

The calculator suggests using 80% efficiency as a default if no data is available. The alternative method is used as an alternative to the input of market-based emission factors, which means those should not be included if selecting this method.

Key Steps:

1. Estimate Boiler Efficiency: If the exact boiler efficiency is not known, a default boiler efficiency (usually 80%) is used.
2. Use Standard Emission Factors: Standardized emission factors (e.g., from the GHG Protocol or government databases) for CO₂, CH₄, and N₂O are used based on the fuel type (e.g., natural gas, coal, etc.).
3. Calculate Emissions: The amount of purchased steam (in energy units) is multiplied by the default emission factors, adjusted for boiler efficiency.

Market-Based Emission Factors

The market-based method accounts for contractual agreements through which an organization sources electricity from specific providers, including fossil, renewable, or other types of generation facilities. The emission factors used in the market-based method are aligned with these procurement arrangements. The EPA encourages using renewable energy, such as RECs, to reduce market-based Scope 2 emissions. Organizations can also contract directly with renewable energy generators or purchase green power from their suppliers.

Types of Market-Based Emission Factors (in order of preference)

1. Energy Attribute Certificates (EACs): These include renewable energy certificates (RECs) or Guarantees of Origin (GOs). If an energy attribute certificate includes an emission factor, it can be used to quantify emissions. EACs typically have zero emission factors because they represent renewable energy, but may have non-zero values if fossil fuel or biomass components are involved.
2. Contracts: An organization can have a contract, such as a power purchase agreement (PPA), to buy electricity directly from a specific generating facility. If certificates are not available, the contract itself carries the emission factor associated with the generation, regardless of the energy source.
3. Supplier-Specific Emission Factors: Some regulated or deregulated electricity suppliers provide emission factors for the electricity they sell. To be valid for market-based reporting, the factor must account for all the electricity delivered by the supplier, including any it purchases from other generators.
4. Residual Mix Factor: This factor represents the emissions that remain after certificates and contracts have been claimed. It’s less commonly available, but organizations should check each year for its availability during GHG inventory calculations.
5. Regional Emission Factor: If none of the above options are available, a regional grid average emission factor can be used. This calculator relies on eGRID subregion emission factors in such cases.
6. National Emission Factor: For U.S.-based emissions, this factor is generally not applicable, as regional factors are available.

Quality Criteria for Contractual Instruments:

To use contractual instruments for market-based reporting, they must meet the following criteria:

1. Convey the GHG emission rate associated with the electricity produced.
2. Be the only instruments representing GHG claims for that quantity of electricity.
3. Be tracked and retired, canceled, or audited by the reporting entity.
4. Have a vintage (date) that closely matches the reporting period.
5. Be sourced from the same market as the consuming entity.

The EPA’s guidance on purchased electricity includes best-practice recommendations that go beyond these minimum requirements.

Example Scenario:

In the example provided, a company procures electricity for two buildings. One building uses 25,000 kWh of RECs and 75,000 kWh from the local utility, while the second building purchases all its electricity from the local utility. The data entry involves allocating market-based emissions correctly between these two sources, ensuring that the total electricity consumption for each building is accurate and avoiding double counting.

For market-based reporting, emission factors for RECs may be zero, but supplier-specific factors must be entered for electricity purchased from the utility. If there is no market-based mechanism, the market-based emissions will equal the location-based emissions.

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