Conducting a Greenhouse Gas Emission Inventory

Issue 11 and Volume 111.

By Jerry Bauer, P.E., Burns & McDonnell Engineering

Global climate change, or the extent to which human activities are contributing to global climate change, is currently the most discussed and contentious issue in the environmental arena.

Regardless of when, what type and even if GHG legislation mandating nationwide reductions is passed, conducting a GHG inventory now is sound environmental policy.
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While the scientists, politicians and activists struggle with what actions may be needed, the corporate environmental managers are faced with the question of what to do now.

Regardless of the means used to reduce greenhouse gas (GHG) emissions, a GHG inventory will be the measuring stick used to verify the United States is meeting its GHG targets and that individual companies are meeting their obligations. Regardless of when, what type and even if GHG legislation mandating nationwide GHG reductions is passed, conducting a GHG inventory now is sound environmental policy.

One adage that has been preached by organizations such as the World Resources Institute as justification for conducting a GHG inventory is “what gets measured gets managed.” The implication is that companies have limited understanding of what processes are generating GHGs and that the inventory is necessary before methods to reduce GHG emissions can be evaluated. The adage has less relevance to industries such as the electric power industry. Electric generating plants know exactly how and where GHGs are emitted: in fuel combustion processes that directly or indirectly drive the turbines that generate electricity.

A more realistic justification for conducting a GHG inventory is quite simple: because the public and the investment community are demanding it. Although a recent United States Supreme Court ruling allows/requires the Environmental Protection Agency to regulate GHG emissions as other air pollutants, no federal regulatory requirement currently mandates a GHG inventory. However, a number of groups representing investors have been and will continue to evaluate companies with respect to GHG performance.

Other justifications for conducting a GHG inventory include the following:

  • It is likely that baseline GHG allowances will be allocated to companies based on actual emissions in a prescribed year. Companies that can demonstrate reductions prior to the prescribed year have the potential to realize more favorable allowances
  • The GHG market will be a multi-billion-dollar industry. For example, assuming electric utility GHG emissions of approximately 2,500 million metric tons and a market value of $20.00/metric ton, the potential market is $50 billion. There will be winners and losers. Responsible utilities should project the potential financial impact on their company using a variety of financial assumptions. The GHG inventory is the first step in making such projections.

Defining a GHG Inventory

A GHG inventory is an organization’s GHG emission sources, quantities, sinks and removals. Any inventory should include both direct emissions and indirect emissions. The inventory should also address GHG sinks (if applicable), such as forestration and sequestration projects, to the extent applicable.

The GHG inventory should be based on the following principles:

  • Relevance: Ensure that the GHG inventory appropriately reflects the company’s GHG emissions and serves the decision making needs of relevant users.
  • Completeness: Account for and report on all GHG emissions.
  • Consistency: Use consistent methods each year so that meaningful comparisons can be made over time.
  • Transparency: Address relevant issues in a factual manner disclosing relevant assumptions and appropriate references.
  • Accuracy: Ensure that quantification of GHG emissions is systematically neither above nor below actual emissions and that uncertainties are reduced as much as practicable.

A GHG inventory should be conducted in accordance with ANSI/ISO/NSF E 14064-1-2006 “Greenhouse Gases-Part 1: Specification with guidance at the organization level for quantification and reporting of greenhouse gas emissions and removals.” Those preparing the inventory and expecting ISO 14064 to be filled with emission factors to convert to CO2-e from various activities (such as fuel combustion) will likely be disappointed. ISO 14064 covers the procedures for conducting the inventory but provides little guidance in actually calculating emissions.

The WRI “Greenhouse Gas Protocol- A Corporate Accounting and Reporting Standard” provides more detailed explanations and examples than the ISO standard but does not provide much detail on making calculations.

However, any GHG inventory should address the following six compounds or group of compounds.

  • Carbon dioxide, CO2
  • Methane, CH4
  • Nitrous oxide, N2O
  • Hydrofluorocarbons (HFCs) and chlorofuorocarbons (CFCs) (covers 13 chemicals)
  • Perfluorocarbons, PFCs (covers seven chemicals)
  • Sulfur hexafluoride, SF6

Other compounds exist that may have properties that lend themselves to being classified as having “global warming potential.” However, these six chemicals/categories address the GHGs that are recognized worldwide.

Carbon Dioxide Equivalents

The scientific community recognizes that not all GHGs are equal. A parameter called “global warming potential” (GWP) was defined to compare the different GHGs to each other with respect to potential harm to the atmosphere. GWP is defined by the World Resources Institute as “A factor describing the radiative forcing impact (in other words, degree of harm to the atmosphere) of one unit of a given GHG relative to one unit of CO2”. GHG emissions are converted to CO2 equivalents (CO2-e) by multiplying the quantity of a specific GHG by its GWP. So, by definition, the GWP of CO2 is 1.0. GWPs of some of the more common GHGs are listed in Table 1 (page 82).

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An example of how emissions are converted to CO2-e is shown in Table 2 (page 82). The example is for illustrative purposes and obviously is not representative of a typical electric utility. Carbon dioxide emissions will account for well over 99 percent of the total GHG emissions for the typical electric utility.Sulfur hexafluoride is a GHG of particular concern to the electric utility industry. The chemical is used in electrical equipment as a replacement to PCBs. Although the quantity of sulfur hexafluoride appears insignificant when compared to CO2 emissions on an absolute basis, when sulfur hexafluoride emissions are converted to CO2-e, the emissions may not be so insignificant.

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GHG Inventory Considerations

Organizational Boundaries: The inventory needs to clearly identify “organizational boundaries” and also account for generating stations in which the utility has a partial ownership position. Organizational boundaries for facilities become a complex issue in the case of multiple owners and/or separate owner/operators. Generally, industry recommended practice is to base GHG emissions in accordance with the equity share. For example, if Acme Power Co. owns 50 percent of the Green Power Plant, then 50 percent of that plant’s GHG emissions are assigned to Acme, regardless of who operates the plant.

An example illustrating how distinguishing equity ownership can be complex is shown in Figure 1 (page 84).

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Operational Boundaries: Operational boundaries define the scope of emissions that will be addressed in the GHG inventory. Generally, GHG emissions can be divided into three categories:

  • Scope 1-Direct GHG emissions
  • Scope 2-Electricity indirect emissions
  • Scope 3-Other indirect GHG emissions.

Direct emissions occur from sources that are owned or controlled by the company. This may include combustion sources (boilers, turbines, emergency generators, fire water pumps and space heaters); company-owned vehicles; coal and ash handling equipment; decomposition of coal, wood, or solid waste (methane emissions); sulfur hexafluoride losses from electrical equipment; and CFC and HFC losses from chillers and air conditioning equipment.

Indirect emissions occur from the generation of purchased electricity (steam or chilled water) consumed by the company. Purchased electricity is electricity that is purchased or otherwise brought into the company’s organizational boundary.

Indirect emissions are a consequence of company activities, but result from sources not owned or controlled by the company. Such Scope 3 emissions include transportation of purchased material or goods (such as coal deliveries by rail car and fuel oil delivery by truck); employee business travel; employee commuting to and from work; and transportation of waste (such as ash).

Reporting Scope 1 and 2-type emissions is mandatory under the industry standards; reporting Scope 3 emissions is optional. Scope 1 and Scope 2 emissions should be reported separately to avoid double counting. For instance, if Acme Power from our earlier example generates 1,000 MWh of electricity and sells the electricity to Acme Chemical Co., the GHG emissions are a Scope 1 direct emission for Acme Power and a Scope 2 indirect emission for Acme Chemical Co.

Tracking Emissions Over Time: The inventory must include a base year, which provides a meaningful and consistent reference for comparing emissions over time. The choice of a base year varies by company. Generally, it is desirable to establish a base year of 1990 (consistent with the Kyoto protocol) or 2000. However, trying to track data in past years can be difficult. For electric utilities with continuous emission monitoring systems (CEMS), tracking GHG emissions to the 1990s may be realistic. For companies that have not previously identified a base year and for which historical data is difficult to obtain, the current year should serve as the base year.

Base year emissions may need to be recalculated as a company undergoes significant structural changes such as acquisitions, divestments and mergers. A structural change involves the transfer of ownership or control of emissions generating activities from one company to another. Essentially, base year emissions must be retroactively recalculated to reflect changes in the company that would otherwise skew the consistency and relevancy of the reported GHG emissions data. Base year emissions are not recalculated, however, for organic growth or decline. Such organic changes refer to increases or decreases in production output, changes in product mix and closures and openings of operating units that are owned by the company. Companies should have a policy in place that articulates the basis for recalculating base year emissions as organizational changes occur.

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An example of how the base year emissions would be recalculated over time are presented in Figure 2 (page 86).

Identifying and Calculating GHG Emissions: The recommended steps to identify and calculate GHG emissions including identifying sources, selecting the calculation approach, collecting data and choosing emission factors, calculating emissions from the source, converting the emissions to CO2 and summarizing data at the company data level as Scope I or Scope II emissions.

Most utilities will have CO2 emissions data from electric generation readily available from continuous monitoring data. Emissions from small generating units and other ancillary sources should be calculated using standard factors. A list of CO2 emissions factors expected to be useful in conducting the inventory (consult Reference 3, Appendix H cited below) for the combustion factor are summarized in Table 3.

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Emissions quantities of other GHGs (such as methane and nitrous oxide) are generally negligible in comparison to CO2 emissions but are generally available in references such as EPA’s “AP-42 Compilation of Emission Factors.” If the electricity is purchased and the facility does not know what type of fuel is used to generated the electricity, then Appendix F of Reference 3 (also listed below) may be helpful. Factors vary widely from 0.147 metric tons CO2-e /MW-hr in EPA Region 11 (which includes the states of Oregon, Washington and Idaho) to 0.909 metric tons CO2-e in Region 9 (which includes the states of Colorado, Utah, Nevada, Wyoming and Montana).

Emissions of the other GHGs (sulfur hexafluoride, CFCs and HCFCs) need to be accounted for using a mass balance approach. Purchasing records should be reviewed to develop the mass balance.

Accounting for GHG Removals: Sequestration is the process by which CO2 is removed from the atmosphere, either through a biologic or a physical process. The biologic approach generally involves planting trees or reforestation. Physical sequestration generally involves injecting CO2 into underground geologic formations that have sufficient pore space to hold large quantities of gas. Estimating CO2 removal is case-specific; no recognized standard appears to exist for making such calculations. CO2 removals (if applicable) should be included as optional information in the GHG inventory and not subtracted from GHG emissions totals.

Carbon Intensity Ratios: A number of companies report an intensity factor to normalize emissions. This factor is a ratio of GHG emissions to a production parameter. Examples of intensity factors include the following: the quantity of a particular product that is produced, vehicle miles traveled (particularly useful in the airline industry) and kilowatt-hours generated. Reporting a carbon intensity ratio is optional under industry standards, but is highly recommended for most utilities.

Electric utilities should take credit for GHG reduction projects, even if the project’s purpose was not necessarily GHG reduction. By definition, an “energy efficiency improvement” project generates a GHG reduction. Examples of energy efficiency improvement projects can include the following: boiler control upgrades; equipment (such as turbine, superheater and cooling tower) upgrades or replacements; transformer replacements; and precipitator intermittent energization.

Electric utilities that have not already done so should conduct an inventory in accordance with ISO standard and World Resource Institute. The inventory should address Scope 1 direct and Scope 2 indirect emissions in accordance with the standards. Reporting Scope 3 indirect emissions is not recommended in most cases because there is no obvious benefit to the additional effort required.

Utilities should document “energy efficiency improvement projects” and consider these as GHG reduction projects. In addition to the basic GHG reporting, utilities should calculate and document the “carbon intensity ratio” or GHG emissions as a function of kilowatt-hours generated. This ratio more accurately reflects the utility company’s success in reducing GHG emissions.


“Corporate Governance and Climate Change: Making the Difference,” a Publication of Ceres, Inc. Cogan, Douglas, March 2006.

Establishing a GHG Inventory for Voluntary Regulatory Reporting, September 2006, NSF Center for Continuing Education, Ann Arbor, Mich.

Technical Guidelines Voluntary Reporting of Greenhouse Gases (1605 (b))/Instructions for Form EIA-1605, April 2007, United States Department of Energy.

The Greenhouse Gas Protocol, Corporate Accounting and Reporting Standard, World Resources Institute.

Greenhouse Gases – Part 1: Specification with Guidance at the Organizational Level for Quantification and Reporting of Greenhouse Gas Emissions and Removals, ANSI/ISO/NSF E14064-1:2006.

Petroleum Industry Guidelines for Reporting Greenhouse Gas Emissions, December 2003, International Petroleum Industry Environmental Conservation Association, International Association of Oil and Gas Producers, American Petroleum Institute.


Jerry Bauer, P.E. is an an environmental engineer with Burns & McDonnell Engineering Co. specializing in air permitting and regulatory compliance. He has over 20 years experience and has completed GHG inventories for several clients. He has B.S degrees in Petroleum and Mechanical Engineering from the University of Kansas and a M.S. degree in Mechanical Engineering from Washington University.