GHG Emission Tracking Setup Procedure

The GHG tracking module in EnergyCAP complies with the IPCC requirements to track the emissions from six internationally-recognized types of greenhouse gases relating to human activity: carbon dioxide (CO₂), methane (CH₄), nitrous oxide (N₂O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF₆).

Emissions are reported in metric tons of CO₂ equivalent (MT CO₂ Eq) as the “universal” reporting standard but various conversions may also be applied if users determine other reporting units are desired.  Under the Kyoto protocol, it was decided that the values of GWP calculated for the IPCC Second Assessment Report (SAR) are to be used for converting the various greenhouse gas emissions into comparable CO₂ equivalents.  The more current IPCC Third Assessment Report (TAR) or Fourth Assessment Report (AR4) GWP values have yet to be adopted. The SAR is used so current estimates of aggregate greenhouse gas emissions for 1990 through 2004 are consistent and comparable with estimates developed prior to the publication of the TAR or AR4.

The GHG Protocol Initiative standards identify operational boundaries for corporations and institutions to ‘scope’ their sources of emissions in order to provide accountability for prevention of “double counting” or conversely, “double credits.”   They categorize emissions as three distinct scopes that form the backbone of the GHG inventory and reporting format: 

• Scope 1 Emissions: Includes all “direct” sources of GHG emissions from sources that are owned or controlled by the corporation or institution, including (but not limited to): production of electricity, heat, or steam in owned or controlled boilers, furnaces, etc; transportation (using corporate or fleet vehicles) of materials, products, waste, and community members; and fugitive emissions (from unintentional leaks).
• Scope 2 Emissions: Accounts for “indirect” sources GHG emissions from the generation of purchased utilities consumed by the corporation or institution. A purchased utility is defined as one that is bought or otherwise brought into the organizational boundary of the company. Scope 2 emissions physically occur at the facility where the utility is generated and thus are separated from direct emissions reported by the utility company in order to avoid double counting.
• Scope 3 Emissions: GHG Protocol Initiative considers this an optional reporting category that allows for the treatment of all other “indirect emissions”. Scope 3 emissions are a consequence of the activities of the company or institution, but occur from sources not owned or controlled by the company. Some examples of scope 3 activities are extraction and production of purchased materials; transportation of purchased fuels; and use of sold products and services.

Concern is often expressed that accounting for indirect emissions will lead to double counting when two different companies include the same emissions in their respective inventories.  Whether or not double counting occurs depends on how consistently companies with shared ownership or trading program administrators choose the same approach to set the organizational boundaries.  Whether or not double counting matters, depends on how the reported information is used.

Double counting must be avoided when compiling national inventories under the Kyoto Protocol, but these are usually compiled via a top-down exercise using national economic data, rather than aggregation of bottom-up company data.  Compliance regimes are more likely to focus on the “point of release” of emissions (i.e., direct emissions) and/or indirect emissions from use of electricity or other purchased utilities.  For GHG risk management and voluntary reporting, double counting is less important.

For participating in GHG markets or obtaining GHG credits, it would be unacceptable for two organizations to claim ownership of the same emissions commodity.  Therefore, it is necessary to make sufficient provisions to ensure that this does not occur between participating companies.

Any emissions should be categorized by the particular scope under which they fall.  This way, emissions can be reported to government agencies or tracked from a number of different viewpoints.  For the typical EnergyCAP user, 90% of the GHG emissions will be related to energy and will fall under scope 1 or scope 2 emissions.  Scope 3 emissions tracking is not available in EnergyCAP at this time because they represent a small portion of overall emissions and are much more subjective and difficult to track.

The EnergyCAP GHG Tracking feature allows users to select from one of two scope types (direct or indirect emissions) per commodity.  Within each of the scope types the user can choose the appropriate scope such as, direct-mobile, direct-stationary, indirect-purchased electricity, indirect-purchased steam, etc.  

Each of the scope types entails different calculation methods. These are detailed in the specific software manual sections on Indirect and Direct Emissions.

In order to begin utilizing the GHG Tracking feature, it is necessary to either import or create GHG emission factors.  EnergyCAP, Inc. has created XML files containing GHG emission factors from a variety of sources (IPCC, egrid, etc.).  If you opt not to utilize the XML files prepared by EnergyCAP, Inc., EnergyCAP provides functionality to develop user-created emission factors.

Importing GHG Factors from XML Files

1. From the Facility Manager top menu, click Greenhouse Gases and select the Import GHG Factors option from the drop-down menu.
   
2. From the Open window, select the GHG emission factor file.  
   
3. Click Open.  The factors included in the file will be imported.

NOTE: Depending on the size of the import file, EnergyCAP may take a minute or two to complete the import process.

User-Created GHG Emission Factors

The Create Factor form allows you to develop a conversion factor for a given commodity. This converts units of the commodity to units of GHG. 

To input user-created emission factors:

From the Facility Manager (Setup > Facilities) click Greenhouse Gases and select the Create Factor option. 

The Create Factor window will open.

Setting the Default GHG Reporting Scope and Emission Factor

After you import or create the emission factors, the next step is to set the default reporting scope and emission factor(s) for each of the commodities where GHG emission tracking is desired. Once the defaults have been set, new meters created for the commodity will inherit the GHG default settings when the GHG Processor is run.

Procedure:

1. From the Facility Manager top menu, click Greenhouse Gases and select the Set Default GHG Reporting Scope and Factor Type submenu option. 
   
   
   
   The Default Reporting Scope and Emission Factor Settings window will open.
2. Use the drop-down arrows to select the Default Reporting Scope and Emission Factor Type for each commodity being tracked.
   
   
3. When done, click OK.

NOTE: If the Show All Commodities checkbox is checked, all existing commodities in the EnergyCAP database will be displayed. If unchecked, only those commodities represented by existing meters or counters in EnergyCAP will be displayed.

Running the GHG Processor

The last step in the setup procedure is to link the meter(s) for which emission tracking is desired to the GHG emission factors previously imported. This is accomplished with the GHG Processor.

1. From the Facility Manager (Setup>Facilities) select the GHG Processor option from the Greenhouse Gases submenu. 
   
2. The Assign Factors and Calculate GHG Emissions window will open.
3. Use the radio button options to select the date range for which the factor will be applied.
4. Use the radio button options to select which meters to process:
• Select Process All Meters if meters are to be updated globally.
• Select Process Unassigned Meters if only meters without factors are to be updated.
• Select This Meter Only if the Processor is to run for only the currently-selected meter.
5. Click Apply. Meters will be processed and displayed in the kickout window. Any errors will be easily visible.

NOTE: Once a factor has been linked to a meter it is necessary to refresh the screen (Edit/Refresh) prior to viewing GHG emission information.

GHG Power Views

After importing and linking GHG factors to meters, GHG emissions are calculated and available for display in power views, charts and for generating reports.  There are two levels of power views:

• The meter level
• The place level

The images below depict the information presented in the power view panels at both levels.

NOTE: Associated chart data can be easily viewed and copied to other applications by clicking the Display Chart Data hyperlink from the Place Properties or Meter Properties display pane. The Data Viewer window will open, displaying the graph and associated data in a tabular format. Click and drag to select desired data (or right-click and click Select All from the popup menu). Then copy (Ctrl-C) and paste (Ctrl-V) to the desired Windows application.

The meter/device level power view panel (shown below) provides a bar graph indicating the annual GHG emissions (in metric tons of CO₂ equivalent) associated with the given meter/device.  In addition to the bar graph, the meter/device level power view panel provides information regarding the emission factors linked to the meter/device, as well as manual entries/GHG credits associated with the meter.

 

The place level power view panel (shown below) provides bar graphs indicating the total annual GHG emissions and annual emissions by category (in metric tons of CO₂ equivalent) associated with the given place.  At the bottom of the place level power view panel there are three pie charts that breakdown GHG emissions over the most recent 12 month period, by category, commodity, and gas type.

 

GHG Reports

EnergyCAP provides you with the ability to generate GHG reports which summarize emissions by scope type, category and gas type in addition to indicating the total emissions.  Report filters can be set to allow you to generate a variety of reports. 

 

A greenhouse gas inventory is an accounting of the amount of greenhouse gases emitted to or removed from the atmosphere over a specific period of time (e.g., one year).  A greenhouse gas inventory also provides information on the activities that cause emissions and removals, as well as,  background on the methods used to make the calculations.  Policymakers use greenhouse gas inventories to track emission trends, develop strategies and policies and assess progress.  Scientists use greenhouse gas inventories as inputs to atmospheric and economic models.

The U.S. Environmental Protection Agency (EPA), in cooperation with other U.S. government agencies, prepares the Inventory of U.S. Greenhouse Gas Emissions and Sinks.  A wide range of agencies and individuals are involved in supplying data to, reviewing, or preparing portions of the Inventory—including federal and state government authorities, research and academic institutions, industry associations, and private consultants.

Within the EPA, the Office of Atmospheric Programs (OAP) is the lead office responsible for the emission calculations provided in the Inventory, as well as, the completion of the National Inventory Report and the Common Reporting Format tables. The Office of Transportation and Air Quality (OTAQ) is also involved in calculating emissions for the Inventory. While the U.S. Department of State officially submits the annual Inventory to the UNFCCC, EPA’s OAP serves as the focal point for technical questions and comments on the U.S. Inventory.

Several other government agencies contribute to the collection and analysis of the underlying activity data used in the Inventory calculations.  Formal relationships exist between the EPA and other U.S. agencies that provide official data for use in the Inventory.  The U.S. Department of Energy’s Energy Information Administration provides national fuel consumption data.  The U.S. Department of Defense provides military fuel consumption and bunker fuels data.  Informal relationships also exist with other U.S. agencies to provide activity data for use in  the EPA’s emission calculations.  Finally, the U.S. Department of State officially submits the Inventory to the UNFCCC each April.

Emission calculations for individual sources are the responsibility of individual source leads, who are most familiar with each source category and the unique characteristics of its emissions profile.  The individual source leads determine the most appropriate methodology and collect the best data to use in the emission calculations.  They base this upon their expertise in the source category, as well as coordinate with researchers and contractors familiar with the sources.  A multi-stage process for collecting information from the individual source leads and producing the Inventory is undertaken annually to compile all information and data.

The EPA’s Emission Inventory Improvement Program (EIIP) was established in 1993 to promote the development and use of standard procedures for collecting, calculating, storing, reporting, and sharing air emissions data.  The EIIP is designed to promote the development of emission inventories that have targeted quality objectives, are cost-effective, and contain reliable and accessible data for end users.

Volume 8 of the EIIP Technical Report establishes the standards and emission factors for calculating GHG emissions from various sources.  Unfortunately, this volume is undergoing revision to:

1. Increase consistency with the national inventory of GHG emissions and sinks
2. Incorporate state-level data sources, methods and emission factors where applicable
3. Update the text and examples for clarity
4. Include references to a MS Excel® based tool designed to assist states in the estimation of emissions

The revised guide is in final draft form and is currently undergoing review.

One of the most useful tools available for estimating emissions from point, area, and mobile sources is the emission factor.  An emissions factor is a representative value that attempts to relate the quantity of a pollutant released to the atmosphere with an activity associated with the release of that pollutant.  These factors are usually expressed as the weight of pollutant divided by a unit weight, volume, distance, or duration of the activity emitting the pollutant (e.g., kilograms of particulate emitted per megagram of coal burned). Such factors facilitate estimation of emissions from various sources of air pollution.  In most cases, these factors are simply averages of all available data of acceptable quality, and are generally assumed to be representative of long-term averages for all facilities in the source category (i.e., a population average). The general equation for emissions estimation is:

    where:
    E = emissions;
    A = activity rate;
    EF = emission factor, and
    ER =overall emission reduction efficiency, %

Specific emissions measurement is generally the best and most accurate method to quantify emissions; however, source data are not always available.  As an alternative, documents and databases containing emission factors and models can be used as tools to estimate air pollutant emissions for inventory purposes.  The EPA’s Factor Information Retrieval System (FIRE) is a consolidation of emission factors for criteria pollutants that includes emission factors from EPA documents such as AP-42 (the compilation of air pollutant emission factors first developed back in the late 1960’s).

Each emission factor in FIRE also includes information about the pollutant (Chemical Abstract Service (CAS) numbers and chemical synonyms) and about the source (Standard Industrial Classification (SIC) codes and descriptions, and Source Classification Codes (SCCs) and descriptions).  Each emission factor entry includes comments about its development, in terms of the calculation methods and/or source conditions, as well as references to where the data was obtained.  The emission factor entry also includes a data quality rating.

The IPCC Emission Factor Database (EFDB) is an additional reference source for emission factor data.  The EFDB is meant to be a recognized library, where users can find emission factors and other parameters with background documentation or technical references that can be used for estimating greenhouse gas emissions and removals.  The responsibility of using this information appropriately will always remain with the users themselves.

EFDB at present contains only the IPCC default data (default data presented in the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories and the IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories). It also contains the data from CORINAIR94, but please note that these data records may be renewed in due course in accordance with the latest version of CORINAIR data set (i.e., data in the Joint EMEP/CORINAIR Atmospheric Emission Inventory Guidebook, Third Edition. Copenhagen: European Environment Agency, 2001). It is highly recommended to consult the website at http://reports.eea.eu.int/EMEPCORINAIR4/en for details on CORINAIR data.

The Greenhouse Gas Protocol (GHG Protocol) Initiative is a multi-stakeholder partnership of businesses, non-governmental organizations (NGOs), governments, and others convened by the World Resources Institute (WRI) (a U.S.-based, environmental non-governmental organization (NGO)), and the World Business Council for Sustainable Development (WBCSD) (a Geneva-based coalition of 170 international companies)).   First launched in 1998, the Initiative’s mission is to develop internationally-accepted GHG accounting and reporting standards for business as well as to promote their broad adoption.

The GHG Protocol Initiative comprises two separate but linked standards:

• Corporate Accounting and Reporting Standards: Provides a step-by-step guide for companies to use in quantifying and reporting their GHG emissions.

• Project Accounting Protocol and Guidelines: Provides a guide for quantifying reductions from GHG mitigation projects.

These standards contain tools and descriptions that provide step-by-step guidance and electronic worksheets to help users calculate GHG emissions from specific sources or industries.  The tools are consistent with those proposed by the IPCC (and subsequently followed by the EPA) for compilation of emissions at the national level.  They have been refined to be user-friendly for non-technical company staff and to increase the accuracy of emissions data at a company level.  The GHG Protocol Initiative is more focused on the methods and procedures of GHG tracking and doesn’t focus as much on the software aspect.  Therefore, it serves as an excellent model and guide for tracking GHG emissions.

Description of Emissions

Direct GHG emissions are principally the result of the following types of activities occurring at companies or institutions:

• Generation of electricity, heat, or steam:  These emissions result from combustion of fuels in stationary sources, such as, boilers, furnaces, turbines, etc.

• Physical or chemical processing:  Most of these emissions result from manufacturing or processing chemicals and materials, such as, cement, aluminum, adipic acid, ammonia, and waste.

• Transportation of materials, products, waste, and employees:  These emissions result from the combustion of fuels in company owned/controlled mobile combustion sources (e.g., trucks, trains, ships, airplanes, buses, and cars).

• Fugitive emissions:  These emissions result from intentional or unintentional releases, e.g., equipment leaks from joints, seals, packing, and gaskets; methane emissions from coal mines and venting; HFC emissions during the use of refrigeration and air conditioning equipment; and methane leakages from gas transport.

Emissions from Combustion

The combustion of fuels produce emissions of carbon dioxide (CO₂), methane (CH₄) and nitrous oxide (N₂O).  Carbon dioxide accounts for the majority of greenhouse gas emissions from most combustion units.  When weighted by their GWPs, CO₂ typically represents over 99 percent of the greenhouse gas emissions from the combustion of fossil fuels.  Therefore, only basic guidance is necessary on the estimation of CH₄ and N₂O emissions from the combustion.

The energy content of a fuel is an inherent chemical property that is a function of the number and types of chemical bonds in the fuel.  The carbon content of a fuel (i.e., the fraction or mass of carbon atoms relative to the total mass or number of atoms in the fuel) is also an inherent chemical property.  The vast majority of the energy released during combustion results from the breaking of chemical bonds between carbon and hydrogen atoms and the formation of a double bond between those same carbon atoms and oxygen atoms in the ambient air.  Therefore,both the amount of heat released from the combustion process and the amount of CO₂ produced are functions of the amount of carbon in the fuel.  A small fraction of the carbon in the fuel can escape oxidation and remain as a solid after combustion in the form of soot or ash.  The nature of the combustion process allows CO₂ emissions to be estimated based on a simple mass balance approach that accounts for the mass of carbon entering the combustion process in the form of fuel and the amount of carbon exiting the process in the form of CO₂, other carbon containing gases, soot, or ash.

The approach used to estimate CO₂ emissions varies significantly from that required to estimate CH₄ and N₂O emissions.  Methane and N₂O emissions depend not only upon fuel characteristics, but also on the combustion technology type, conditions within the combustion chamber, usage of pollution control equipment, and ambient environmental conditions.  However, since the amount of CH₄ and N₂O emissions is a small fraction of the CO₂ emissions, an approximation of these two emissions may be sufficient.  Users have the ability to enter their own custom values based on flue gas lab tests, but the default coefficients should suffice for the majority of users.
 
Calculation based methods typically entail the collection of :

• Activity data:  in the form of the quantity of fuel consumed for combustion purposes

• Emission factor data:  in the form of information on the characteristics of the fuel combusted and the efficiency of the oxidation process

Calculation of CO₂ Emissions

To calculate CO₂ emissions using fuel consumption and emission factor data, the following equations can be applied:

        where:
        E = Mass emissions of CO₂ (short tons or metric tons)
        A_f,v = Volume of fuel consumed (e.g., L, gallons, ft³, m³)
        A_f,m = Mass of fuel consumed (e.g., short tons or metric tons)
        A_f,h = Heat content of fuel consumed (GJ or million Btu)
        F_c,v = Carbon content of fuel on a volume basis (e.g., short tons C/gallon or metric tons C/m³)
        F_c,m = Carbon content of fuel on a mass basis (e.g., short tons C/short ton or metric tons C/metric ton)
        F_c,h = Carbon content of fuel on a heating value basis (e.g., short tons C/million Btu or metric tons C/GJ)
        F_ox = Oxidation factor to account for fraction of carbon in fuel that remains as soot or ash
        (44/12) = The ratio of the molecular weight of CO₂ to that of carbon

Depending on the type of fuel, the volume, mass, or heat content can be converted directly from EnergyCAP bills and converted to one of the usable units required for the equation above.  Appendices B, C, D, and E list the appropriate factors.

Determining coal, and to a lesser extent oil and natural gas, consumption can problematic.  It may be necessary to estimate the amount of coal in storage piles (or oil and natural gas in storage tanks) at the beginning of the year and at the end of the year to determine stock changes.  Using purchase and delivery records can also be problematic, as fuel from one delivery may not be used up before the end of the year.  For these reasons, a combination of fuel metering and purchase and delivery records may be needed to ensure the estimation of the amount of fuel consumed each year is complete and consistent over time.

In cases where combustion units are co-fired with a mix of fossil and biomass fuels, the biomass and fossil fuel components of the CO₂ emissions should be calculated separately, using carbon content and oxidation factors related to the specific fuels.  The resulting emissions from biogenic carbon should be reported separately.

Calculation of CH₄ and N₂O Emissions  

Fuel characteristics (e.g., calorific value), the type of technology (e.g., combustion, operating and maintenance regime, the size and the vintage of the equipment), and emission controls, are major factors in determining rates of emissions of CH₄ and N₂O gases from stationary sources.  Specifically, N₂O emissions are closely related to air-fuel mixes and combustion temperatures, as well as the composition and operating temperature of any catalytic emission control equipment employed.  Methane emissions from stationary combustion are primarily a function of the CH4 content of the fuel and combustion efficiency.

Unlike for CO₂, the emissions of CH₄ and N₂O from the combustion of biomass fuels should be included with emissions from the combustion of fossil fuels.

Given the dependence on specific combustion conditions and other characteristics, the preferred approach for estimating CH₄ and N₂O emissions is to use a method based on combustion unit-specific data.  This method generally calls for the use of detailed activity data and emissions factors that account for these characteristics.  Facility specific emission factors may also be based on direct measurements.  Additional information on more technologic and fuel-specific emission factors can be found in the IPCC Emission Factor Database, U.S. EPA’s AP-42, and the European Environment Agency’s EMEP/Corinair Emission Inventory Guidebook.

The IPCC Guidelines also provide default stationary combustion emission factors (which assume no emission controls are in place) for five sectors :

1. Energy Industry
2. Manufacturing Industry
3. The Commercial/Institutional Sector
4. The Residential Sector
5. Agriculture/Forestry/Fishing Sectors

The default emission factors are listed in Appendix F.  Emissions estimated using these factors have a degree of uncertainty associated with them.  Users can also select emission factors from one of the databases listed above or develop and input their own factors.

To calculate CH₄ emissions using fuel consumption and emission factor data, the following equations can be applied:

    where:
    E = Mass emissions of CH₄ (short tons or metric tons)
    A_f,h = Heat content of fuel consumed (GJ or million Btu)
    EFm,h = Emissions Factor for Methane from Appendix F on a heating value basis (lb/million Btu or Kg/GJ)
    C = control efficiency/utilization of any emission control equipment (percent)
    CF = Conversion Factor to correct to short tons or metric tons

Similarly, to calculate N₂O emissions using fuel consumption and emission factor data, the following equations can be applied:

    where:
    E = Mass emissions of N₂O (short tons or metric tons)
    Af,h = Heat content of fuel consumed (GJ or million Btu)
    EFn,h = Emissions Factor for Nitrous Oxide from Appendix F on a heating value basis (lb/million Btu or Kg/GJ)
    C = control efficiency/utilization of any emission control equipment (percent)
    CF = Conversion Factor to correct to short tons or metric tons

Calculation of Fluorinated Gas and Non Combustion Emissions 

 Calculating emissions from any of the three classes of fluorinated gases (HFCs, PFCs, and SF₆) are done approximately the same way. Users must know the quantity of each gas and multiply it by a corresponding GWP Emission Factor.  Also, additional emissions of CO₂, CH₄, and N₂O may occur as a consequence of a manufacturing or industrial process.  Those subsequent emissions would be calculated in a similar fashion.

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.

Greenhouse Effect

Temperature-regulating atmospheric gases, called "greenhouse gases" or GHGs, form a blanket around the earth and trap heat from the sun within the earth’s atmosphere.  This process keeps the planet warm and habitable.  The "greenhouse effect" is primarily a function of the concentration of water vapor, carbon dioxide (CO₂), and other trace gases in the atmosphere that absorb the terrestrial radiation leaving the surface of the Earth.  Changes in the atmospheric concentrations of these greenhouse gases can alter the balance of energy transfers between the atmosphere, space, land, and the oceans.

Climate models from the Intergovernmental Panel on Climate Change (IPCC), as well as, models from other scientific bodies, indicate that global concentrations of GHGs have been rising steadily over the past 100 years.  As atmospheric concentrations of GHGs increase, the greenhouse blanket gets thicker.  This causes heat to be trapped in the lower layers of the atmosphere and may cause global average temperatures to rise. 

Greenhouse Gases and Global Warming Potential

Naturally occurring GHGs include water vapor, carbon dioxide (CO₂), methane (CH₄), nitrous oxide (N₂O), and ozone (O₃).   CO₂, CH₄, and N₂O are  emitted and removed  continuously from the atmosphere by natural processes on earth.   Anthropogenous, or human-produced, activities can cause additional quantities of these and other GHGs to be emitted or removed, thereby changing the global average atmospheric concentrations.

The principal GHGs that enter the atmosphere because of human activities are:

• Carbon Dioxide (CO₂): CO₂ enters the atmosphere through the burning of fossil fuels (oil, natural gas, and coal), solid waste, trees and wood products.   It is also as a result of other chemical reactions (e.g., cement manufacturing).  CO₂ is removed from the atmosphere when it is absorbed by plants as part of the biological carbon cycle.

• Methane (CH₄): CH₄ is emitted during the production and transport of coal, natural gas, and oil.  CH₄ emissions also result from livestock and other agricultural practices , as well as, by the decay of organic waste in municipal solid waste landfills.

•  Nitrous Oxide (N₂O): N₂O is emitted during agricultural and industrial activities, as well as, during combustion of fossil fuels and solid waste.

•  Fluorinated Gases:  A classification of three types of manmade/synthetic, powerful greenhouse gases  including hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF₆).   Fluorinated gases, such as sulfur hexafluoride, are sometimes used as substitutes for ozone-depleting substances (i.e. CFCs, HCFCs, and halons).  Chlorofluorocarbons (CFCs) and hydrochlorofluorocarbons (HCFCs) are halocarbons that contain chlorine, while halocarbons that contain bromine are referred to as bromofluorocarbons (i.e., halons).   The other fluorine-containing halogenated substances—HFCs, PFCs, and SF₆ are typically emitted in smaller quantities.  They do not deplete stratospheric ozone, but because they are potent GHGs, they are sometimes referred to as High Global Warming Potential gases (“High GWP gases”).

Recognizing the problem of potential global climate change, the World Meteorological Organization (WMO) and the United Nations Environment Programme  (UNEP) established the Intergovernmental Panel on Climate Change  (IPCC) in 1988.  It is open to all members of the UN and WMO.  The role of the IPCC is to assess potential impacts (i.e., scientific, technical and socio-economic) and develop options for adapting and mitigating human-induced climate change on a comprehensive, objective, and  transparent basis.

The IPCC developed the Global Warming Potential (GWP) concept to compare the ability of each GHG to trap heat in the atmosphere relative to another gas.  The GWP of a GHG is defined as the ratio of the time-integrated radiative forcing from the instantaneous release of 1 kg of a trace substance relative to that of 1 kg of a reference gas (IPCC 2001).  Direct radiative effects occur when the gas itself is a GHG.  The reference gas used is CO₂, and therefore GWP-weighted emissions are measured in teragrams of CO₂ equivalent (Tg CO₂ Eq).  The relationship between gigagrams (Gg) of a gas and Tg CO₂ Eq can be expressed as follows:

where,
            Tg CO₂  Eq. = Teragrams of Carbon Dioxide Equivalents
            Gg = Gigagrams (equivalent to a thousand metric tons)
            GWP = Global Warming Potential
            Tg = Teragrams

Because of the sheer size of a teragram (one million metric tons), metric tons of CO₂ equivalent (MT CO₂ Eq) are generally used as the reporting unit of GHG.  A metric ton is equal to 1.1023 short tons, or 2,204.6 pounds. 

The GWP depends on both the efficiency of the molecule as a GHG and its atmospheric lifetime.  GWP is measured relative to the same mass of CO₂ and evaluated for a specific timescale (20, 100, or 500 years).  Thus, if a molecule has a high GWP on a short time scale (20 years, for example) but has only a short lifetime, it will have a large GWP on a 20 year scale but a small one on a 100 year scale. Conversely, if a molecule has a longer atmospheric lifetime than CO₂ its GWP will increase with time.

The IPCC also estimates the atmospheric lifetime of GHGs.  The atmospheric lifetime describes how long it takes to restore the system to equilibrium following a small increase in the concentration of the gas in the atmosphere.  Individual molecules may interchange with other reservoirs such as soil, the oceans, and biological systems, but the mean lifetime refers to decaying away the excess.

Some examples of the six primary types of GHGs follow:

Note that a substance's GWP depends on the timespan over which the potential is calculated.  A gas which is quickly removed from the atmosphere may initially have a large effect, but then the effect is minimized.  Thus methane, has a potential of 23 over 100 years, but 62 over 20 years; conversely sulfur hexafluoride has a GWP of 22,000 over 100 years but 15,100 over 20 years (IPCC TAR).  The GWP value depends on how the gas concentration decays over time in the atmosphere.  This is often not precisely known and hence the values should not be considered exact.  Therefore, when  a GWP  is quoted, it is important to reference the calculation.

The GHGs with relatively long atmospheric lifetimes (e.g., CO₂, CH₄, N₂O, HFCs, PFCs, and SF₆) tend to be evenly distributed throughout the atmosphere, and consequently global average concentrations can be determined.  However, the short-lived GHGs such as water vapor, carbon monoxide, tropospheric ozone, ozone precursors (e.g., NOx, and NMVOCs), and tropospheric aerosols (e.g., SO₂ products and carbonaceous particles),  vary regionally so it is difficult to quantify their global radiative forcing impacts.  No GWP values are attributed to these gases which are short-lived and spatially inhomogeneous in the atmosphere.

The IPCC published a first assessment report in 1990, a supplementary report in 1992, a second assessment report (SAR) in 1995, and a third assessment report (TAR) in 2001.  The fourth assessment report (AR4) CLIMATE CHANGE 2007, was published by the IPCC in 2008.  While the TAR and AR4 provide updated or revised GWP values, the GHG GWP values and atmospheric lifetimes established by the SAR are associated with the Kyoto Protocol and are therefore generally referenced in reporting protocols.

The United Nations Conference on Environment and Development (UNCED) conference was a major environmental conference (known by its popular title, the Earth Summit) held in Rio de Janeiro in June of 1992.  As part of the Summit, the United Nations Framework Convention on Climate Change  (UNFCCC or FCCC) treaty was developed.  On June 12, 1992, 154 nations signed the UNFCCC, that upon ratification committed signatories' governments to a voluntary "non-binding aim" to reduce atmospheric concentrations of greenhouse gases with the goal of "preventing dangerous anthropogenic interference with Earth's climate system."  These actions were aimed primarily at industrialized countries, with the intention of stabilizing their emissions of greenhouse gases at 1990 levels by the year 2000.  Other responsibilities would be incumbent upon all UNFCCC parties.

The treaty, as originally framed, set no mandatory limits on greenhouse gas emissions for individual nations and contained no enforcement provisions.  It is therefore considered legally non-binding.  Rather, the treaty included provisions for updates (called "protocols") that would set mandatory emission limits.  The principal and most famous update is the Kyoto Protocol, which has become much better known than the UNFCCC itself.

The treaty was negotiated in Kyoto, Japan in December 1997, opened for signature on March 16, 1998, and closed on March 15, 1999. The agreement came into force on February 16, 2005 following ratification by Russia on November 18, 2004.  As of December 2006, a total of 169 countries and other governmental entities have ratified the agreement (representing over 61.6% of emissions from Annex I countries).

Developing countries were exempt from the requirements of the Kyoto Protocol because they were not the main contributors to the greenhouse gas emissions during the industrialization period that is believed to be causing today's climate change.  Critics of Kyoto argue that developing countries will soon be the top contributors to greenhouse gases.  Also, without Kyoto restrictions on these countries, industries in developed countries will be driven towards these non-restricted countries, thus there is no net reduction in carbon dioxide emissions.

The UNFCCC standards consider GWPs for the six primary GHGs (CO₂, CH₄, N₂O, HFCs, PFCs, and SF₆) based on 100-year time horizons.

Under the Kyoto protocol, the Conference of the Parties decided that the values of GWP calculated for the IPCC Second Assessment Report are to be used for converting the various greenhouse gas emissions into comparable CO₂ equivalents when computing overall sources and sinks.  The Conference of Parties has yet to adopt the more current IPCC Third Assessment Report  (TAR) or Forth Assessment Report (AR4) GWP values. The SAR is used so that current estimates of aggregate greenhouse gas emissions for 1990 through 2004 are consistent and comparable with estimates developed prior to the publication of the TAR or AR4.

To comply with international reporting standards under the UNFCCC, official emission estimates are also reported by the United States using SAR GWP values.

Note that CFCs and HCFCs are not tracked or monitored by the UNFCC.  Halocarbons that contain fluorine (HFC) are tracked by the UNFCC as a GHG.  However, halocarbons that contain chlorine (CFCs, HCFCs, methyl chloroform, and carbon tetrachloride) and bromine (halons, methyl bromide, and hydrobromofluorocarbons [HBFCs]) result in stratospheric ozone depletion and are therefore controlled by the Montreal Protocol.  Ozone depletion has only a minor role in the greenhouse effect, although it is often confused with global warming.  Although CFCs and HCFCs include potent global warming gases, their net radiative forcing effect on the atmosphere is reduced because they cause stratospheric ozone depletion, which itself is an important greenhouse gas.  In addition, they shield the earth from harmful levels of ultraviolet radiation. Under the Montreal Protocol, the United States phased out the production and importation of halons by 1994 and of CFCs by 1996.