Units for Measuring Greenhouse Gases 

In this publication, EIA reports information in forms that are most likely to be familiar to users of the document. Therefore, energy and industrial data are reported in their native units. For example, oil production is reported in thousand barrels per day, and energy production and sales are reported in British thermal units (Btu). For readers familiar with metric units, Btu can be a relatively intuitive unit because an exajoule is only 5 to 6 percent larger in energy content than a quadrillion Btu. 

Emissions data are reported in metric units. This report uses the familiar “million metric tons” common in European industry instead of “gigagram,” which is equal to 1,000 metric tons and is the term favored by the scientific community. Metric tons are also relatively intuitive for users of English units, because a metric ton is only about 10 percent heavier than an English short ton. 

Emissions of most greenhouse gases are reported here in terms of the full molecular weight of the gas (as in Table ES1). In Table ES2, however, and subsequently throughout the report, carbon dioxide and other greenhouse gases are reported in carbon dioxide equivalents. In the case of carbon dioxide, emissions denominated in the molecular weight of the gas or in carbon dioxide equivalents are the same. It is important to note that, in previous issues of this report, greenhouse gas emissions were reported in carbon equivalents. This change is being made to be consistent with the current trend, both domestically and internationally, to report greenhouse gas emissions in carbon dioxide equivalents. 

Emissions of other greenhouse gases (such as methane) can also be measured in “carbon dioxide equivalent” units by multiplying their emissions (in metric tons) by their global warming potentials (GWPs). Carbon dioxide equivalents are the amount of carbon dioxide by weight emitted into the atmosphere that would produce the same estimated radiative forcing as a given weight of another radiatively active gas. Carbon dioxide equivalents are computed by multiplying the weight of the gas being measured (for example, methane) by its estimated GWP (which is 23 for methane). GWPs are discussed later in this chapter and delineated in Chapter 1, Table 3.

Comparison of Global Warming Potentials from the IPCC’s Second and Third Assessment Reports 

Printer Friendly Version Comparison of 100-year GWP Estimates from the IPCC's Second (1996) and 'third (2001) Assessment Reports Gas  1996 IPCC GWP  2001 IPCC GWP  Methane  21  23  Nitrous Oxide  310  296  HFC-23  11,700  12,000  HFC-125  2,800  3,400  HFC-134a  1,300  1,300  HFC-143a  3,800  4,300  HFC-152a  140  120  HFC-227ea  2,900  3,500  HFC-236fa  6,300  9,400  Perfluoromethane (CF4)  6,500  5,700  Perfluoroethane (C2F6)  9,200  11,900  Sulfur Hexafluoride (SF6)  23,900  22,200

Global warming potentials (GWPs) are used to compare the abilities of different greenhouse gases to trap heat in the atmosphere. GWPs are based on the radiative efficiency (heat-absorbing ability) of each gas relative to that of carbon dioxide (CO₂), as well as the decay rate of each gas (the amount removed from the atmosphere over a given number of years) relative to that of CO₂. The GWP provides a construct for converting emissions of various gases into a common measure, which allows climate analysts to aggregate the radiative impacts of various greenhouse gases into a uniform measure denominated in carbon or carbon dioxide equivalents. The table at the right compares the GWPs published in the Second and Third Assessment Reports of the Intergovernmental Panel on Climate Change (IPCC). 

In compiling its greenhouse gas emission estimates, EIA attempts to employ the most current data sources. For that reason, and because the IPCC is generally considered the authoritative source for GWPs, the GWP values from the IPCC’s Third Assessment Report are used in this report. It is important to point out, however, that countries reporting to the United Nations Framework Convention on Climate Change (UNFCCC), including the United States, have been compiling estimates based on the GWPs from the IPCC’s Second Assessment Report. The UNFCCC Guidelines on Reporting and Review, adopted before the publication of the Third Assessment Report, require emission estimates to be based on the GWPs in the IPCC Second Assessment Report. This will probably continue in the short term, until the UNFCCC reporting rules are changed. Following the current rules, the U.S. Environmental Protection Agency (EPA), which compiles the official U.S. emissions inventory for submission to the UNFCCC, intends to present estimates based on the GWPs published in the Second Assessment Report in its report, Inventory of  U.S. Greenhouse Gas Emissions and Sinks: 1990-2002, scheduled for release in April 2004.

The table below shows U.S. carbon dioxide equivalent greenhouse gas emissions calculated using the IPCC’s 1996 (Second Assessment Report) and 2001 (Third Assessment Report) GWPs. The estimate for total U.S. emissions in 2002 is 0.6 percent higher when the revised GWPs are used. The estimates for earlier years generally follow the same pattern. Using the 2001 GWPs, estimates of carbon dioxide equivalent methane emissions are 9.5 percent higher, and carbon-equivalent nitrous oxide emissions are 4.5 percent lower. Carbon dioxide equivalent emissions of HFCs, PFCs, and SF₆ are lower for some years and higher for others, depending on the relative shares of the three gases.

What’s New in This Report 

This year, we have written expanded documentation that will be published in a separate volume. As a result, there are only three appendixes to this volume: Common Conversion Factors (Appendix A), Emissions of Energy-Related Carbon Dioxide in the United States, 1949-2002 (Appendix B), and Energy-Related Carbon Dioxide Emissions by State (Appendix C). 

Chapter 2 

• Beginning with this year’s report, EIA is reporting carbon dioxide emissions at the full weight of the gas. For consistency, all other gases are reported in carbon dioxide equivalent units. The ratio of carbon dioxide to carbon alone is approximately 44/12. 

Chapter 3 

• The animal population data and methodologies used to estimate methane emissions from the solid waste of domesticated animals and those produced by cattle from enteric fermentation have been revised, affecting estimates of methane emissions for all years. The revised population estimates eliminate previous double counting of beef cattle in feedlots, reducing the estimates of emissions from enteric fermentation and solid waste from beef cattle for 1990 through 2002. The revised methodology for enteric fermentation in cattle changed the trend of emissions from this source. For both the old and new methods, enteric fermentation emissions peaked in 1995; however, the results of the new method show emissions decreasing since then. The changes to the model of emissions from solid waste from domesticated animals reduced the magnitude of emissions but produced similar emissions trends for each animal category since 1990. 

• To estimate emissions produced by cattle from enteric fermentation, EIA applied adjusted methane emissions factors, which reflect the greater detail that the U.S. Environmental Protection Agency (EPA) incorporated into the Tier 2 methodology outlined in the IPCC’s Good Practice Guidance.^a For other animal categories, EIA continued to apply the Tier 1 emission factors recommended in the Revised 1996 IPCC Guidelines.^b Emissions factors for sheep and goats have been revised, reducing the estimates of methane emissions from sheep and goats. 

• To estimate methane associated with solid waste from domesticated animals, EIA revised the typical animal mass for all animal categories, including revising swine sizes to correspond more closely with the classifications used by the U.S. Department of Agriculture. In addition, EIA updated the volatile solids factors and altered the distribution of waste management systems to reflect the general shift to larger, more managed farms. 

Chapter 4 

• Estimates of nitrous oxide (N₂O) emissions from the application of sewage sludge have been included in EIA’s calculation of N₂O emissions from agricultural sources. EIA’s emissions estimate for sewage sludge was calculated by multiplying EPA estimates of annual sludge generation, annual percentage applied to land, and a figure for average nitrogen content. 

Chapter 5 

• The data presented in Chapter 5 for other gases (HFCs, PFCs, and SF₆) are provided by the EPA. Revisions in historical emissions estimates are explained below: 

• Electricity Transmission and Distribution. The primary change in the methodology for calculating emissions from electricity transmission and distribution was an increase in the assumed rate of emissions from equipment manufacturing. This revision resulted in an average annual increase in estimated SF₆ emissions of 3.7 percent for the period 1990 through 2000. 

• Magnesium Production and Processing. The emissions estimates for this report were revised to reflect new activity data for magnesium production and processing and a revised emissions factor for die-casting. The combination of these changes and the methodological revision described above resulted in an average annual decrease in estimated SF₆ emissions of about 1.9 percent for the period 1990 through 2000. 

• Substitution of Ozone-Depleting Substances. The EPA updated assumptions for its Vintaging Model in the fire-extinguishing sector. These changes resulted in an average annual decrease  in estimated HFC and PFC emissions of 0.7 percent for the period 1994 through 2000. 

• Aluminum Production. In cooperation with the EPA’s Voluntary Aluminum Industrial Partnership program, participants provided additional smelter-specific information on aluminum production and the frequency and duration of anode effects. The new information resulted in a decrease in estimated PFC emissions of 0.3 percent for 2000. 

Chapter 6 

• The data for net carbon dioxide fluxes due to changes in carbon stocks in forests, urban trees, agricultural soil, and landfilled yard trimmings are provided by the U.S. Forest Service. This year, all values are presented in million metric tons carbon dioxide equivalent. Updates are provided on treatment of land use issues under current climate change negotiations, scientific research detailing uncertainty in the ability of forest soils to store carbon, and the status of carbon dioxide capture and geologic storage technologies.
  

^aIPCC National Greenhouse Gas Inventories Programme, Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories (J. Penman, D. Kruger, et al., editors) (Tokyo, Japan: Institute for Global Environmental Strategies, 2000), Chapter 4, “Agriculture,” web site www.ipcc-nggip.iges.or.jp/public/gp/gpgaum.htm. 

^bIntergovernmental Panel on Climate Change, Greenhouse Gas Inventory Reference Manual: Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Vol. 3 (Paris, France, 1997), p. 4.10, web site www.ipcc.ch/pub/guide.htm.

Trends in U.S. Carbon Intensity and Total Greenhouse Gas Intensity 

Figure Data

Historical Growth Rates for U.S. Carbon Intensity Printer Friendly Version Decade  Overall Change in Intensity (Percent)  Average Annual Change in Intensity (Percent)  Carbon Dioxide  Total GHG  Carbon Dioxide  Total GHG  History    1950-1960  -12.9  —  -1.4  —    1960-1970    -3.1  —  -0.3  —    1970-1980  -18.1  —  -2.0  —    1980-1990  -23.1  -18.3  -2.6  -2.0    1990-2000  -15.2  -17.9  -1.6  -2.0

From 2001 to 2002, the greenhouse gas intensity of the U.S. economy fell from 747 to 731 metric tons per million 1996 dollars of GDP (2.1 percent), continuing a trend of decreases in both carbon intensity (see figure at right) and total greenhouse gas intensity. As shown in the table below, declines in carbon intensity by decade have ranged from a low of 3.1 percent in the 1960s to 23.1 percent in the 1980s. From 1990 to 2002, total U.S. greenhouse gas intensity fell by 21.4 percent, at an average rate of 2 percent per year. 

The carbon intensity and greenhouse gas intensity of the U.S. economy move in lockstep, because carbon dioxide emissions make up most of the total for U.S. greenhouse gas emissions. Energy-related carbon dioxide emissions represent approximately 82 percent of total U.S. greenhouse gas emissions. As such, trends in energy-related carbon dioxide emissions have a significant impact on trends in total greenhouse gas emissions. Historical trends in U.S. carbon intensity (energy-related carbon dioxide emissions per unit of economic output) are described below. 

The carbon intensity of the economy can largely be decomposed into two basic elements: (1) energy intensity, defined as the amount of energy consumed per dollar of economic activity; and (2) carbon intensity of energy supply, defined as the amount of carbon emitted per unit of energy. As illustrated by the formulas below, the multiplication of the two elements produces a numerical value for U.S. carbon intensity, defined as the amount of carbon dioxide emitted per dollar of economic activity: 

Energy Intensity x Carbon Intensity of Energy Supply = Carbon Intensity of the Economy   , 

or, algebraically, 

(Energy/GDP) x (Carbon Emissions/Energy) =
(Carbon Emissions/GDP)   . 

Components of Energy Intensity. Since World War II the U.S. economy has been moving away from traditional “smokestack” industries towards more service-based or information-based enterprises. This has meant that over the second half of the 20th century economic growth was less tied to growth in energy demand than it was during the period of industrialization in the 19th and early 20th century. Other factors contributing to decreases in energy intensity include: 

• Improvements in the energy efficiency of industrial equipment as new materials and methods improved performance in terms of energy inputs versus outputs 

• Increased efficiency of transportation equipment as lighter materials and more efficient engines entered the marketplace 

• Improvements in commercial and residential lighting, refrigeration, and heating and cooling equipment 

• Developments in new electricity generating technologies, such as combined-cycle turbines. 

Further reductions in energy intensity, which are projected to continue, will among other things promote deeper reductions in U.S. carbon intensity. 

Components of the Carbon Intensity of Energy Supply. Changes in the carbon intensity of energy supply have been less dramatic than changes in energy intensity. There was a slow but steady decline from 1949 until about the mid-1990s, after which it has remained relatively unchanged. The primary reason  for the decline has been the development of nuclear power, which is carbon-free and therefore weights the fuel mix toward lower carbon intensity; however, with nuclear generation projected to plateau between 2005 and 2015, this trend is expected to stabilize. Other factors that can decrease the carbon intensity of the energy supply include: 

• Development of new renewable resources, such as wind power, for electricity generation 

• Substitution of natural gas for coal and oil in power generation 

• Transportation fuels with a higher biogenic component, such as ethanol

Energy-Related Carbon Dioxide Emissions in Manufacturing

Manufacturing is the single largest source of energy-related carbon dioxide emissions in the U.S. industrial sector. This industrial subsector, which excludes agriculture, mining, and construction, accounts for 84 percent of both industrial energy-related carbon dioxide emissions and industrial energy consumption. The table below shows estimates of energy-related carbon dioxide emissions from the manufacturing subsector in 1998, based on energy consumption statistics from EIA’s Manufacturing Energy Consumption Survey (MECS), which surveys more than 15,000 manufacturing plants every 4 years. The most recent MECS data available are from the 1998 survey. The table on page 21 shows estimates of manufacturing emissions by fuel, based on statistics from the 1991, 1994, and 1998 surveys.

The 1991 MECS reported energy consumption (for fuel and nonfuel purposes) that yielded carbon dioxide emissions from the manufacturing subsector as a whole totaling 1,251.4 million metric tons. The corresponding estimate for 1998 is 1,485.8 million metric tons—an increase of 234.4 million metric tons or 18.7 percent. Over the same interval, the demand for manufacturing products (as measured by the value of shipments) increased by 36.4 percent. Therefore, the overall carbon intensity of U.S. manufacturing, measured as metric tons of carbon dioxide emitted per million 1996 dollars of product shipments, was 408.8 in 1991 but had dropped to 356.0 by 1998, a decrease of 12.9 percent.

Carbon Dioxide Emissions from Manfacturing by Fuel, 1991, 1994, and 1998  Printer Friendly Version   Fuel Type SICa Code Other Mfg. Total 29 28 33 26 20 32 1991 CO2 Emissions (Million Metric Tons)   Petroleum    149.9      42.1        3.4      13.6        3.7        6.4      10.4    229.6   Natural Gas      44.2    102.3      37.4      29.1      27.0      20.1      46.4    306.6   Coal        1.4      25.2      83.2      28.3      14.4      27.9      12.8    193.2   Electricity      19.8      83.1      94.3      38.0      31.9      19.8    160.8    447.8   Other      61.0        9.7        3.0        0.2        0.0        0.0        0.5      74.3     Total    276.3    262.4    221.3    109.2      77.0      74.3    230.8 1,251.4 Share of Total Value of Shipments (Percent)   5.5 11.1   4.9   4.9 14.2 2.2 57.2 100.0 Share of Total Energy Use (Percent) 24.8 23.3 13.2 11.9   5.3 4.5 17.0 100.0 Share of Total CO2 Emissions (Percent) 22.1 21.0 17.7   8.7   6.2 5.9 18.4 100.0 1994 CO2 Emissions (Million Metric Tons)   Petroleum    174.8      42.3        4.9      15.7        4.3        7.4      10.1    259.4   Natural Gas      42.8    117.7      42.8      30.4      33.3      22.8      53.1    343.0   Coal        0.0      28.5      96.1      28.6      15.6      26.4      12.9    208.2   Electricity      21.9      94.1      89.2      40.4      35.8      22.3    177.0    480.6   Other      60.6        4.4        3.5        1.1        0.4        0.2        1.6      71.8     Total    300.1    287.1    236.5    116.0      89.4      79.1    254.6 1,363.0 Share of Total Value of Shipments (Percent)   4.9 10.4   5.0   4.7 13.3   2.2 59.6 100.0 Share of Total Energy Use (Percent) 24.4 23.6 12.8 11.5   5.9   4.4 17.4 100.0 Share of Total CO2 Emissions (Percent) 22.0 21.1 17.4   8.5   6.6   5.8 18.7 100.0 1998 CO2 Emissions (Million Metric Tons)   Petroleum    174.8      56.5        3.6      15.1        3.0        6.7      10.4    270.1   Natural Gas      53.2    127.7      47.9      31.1      31.8      23.4      59.7    374.9   Coal        0.0      26.9      94.3      25.8      13.6      27.7      10.0    198.3   Electricity      22.9    103.2    101.8      45.6      41.8      24.4    221.9    561.6   Other      69.5        4.9        3.4        0.8        0.1        0.7        1.5      80.9     Total    320.4    319.2    251.0    118.4      90.4      82.9    303.6 1,485.8 Share of Total Value of Shipments (Percent)   4.3   9.6   4.6   4.0 11.9   2.2 63.4 100.0 Share of Total Energy Use (Percent) 25.2 24.0 12.2 10.8   5.2   4.1 18.4 100.0 Share of Total CO2 Emissions (Percent) 21.6 21.5 16.9   8.0   6.1   5.6 20.4 100.0

The overall carbon intensity of the U.S. manufacturing subsector is the ratio of its total carbon dioxide emissions (C) to manufacturing output (Y), as measured by the value of shipments (in constant 1996 dollars). That ratio (C/Y) is calculated as the product of the subsector’s aggregate carbon dioxide emission coefficient— carbon dioxide emissions (C) per unit of energy consumed (E)—and its energy intensity—energy consumed (E) per unit of product shipped (Y). That is:

C/Y = (C/E) x (E/Y)   .

For the manufacturing subsector as a whole, energy intensity (the ratio E/Y) is a function primarily of the energy intensities of different production groups and their contributions to the total product mix in the subsector. The subsector’s emission coefficient (the ratio C/E) is determined primarily by the mix of energy fuel inputs and the mix of fuel and nonfuel (sequestering) uses of the inputs. Thus, the carbon intensity of manufacturing (C/Y) is a combination of the energy intensity of manufacturing output and the carbon emission coefficient of the fuels consumed to meet manufacturing energy demand.^a

The overall carbon intensity of the manufacturing subsector (C/Y) fell by 12.9 percent from 1991 to 1998; however, the reduction was largely the result of a structural shift in the subsector. The energy intensity for the “all other manufacturing” category declined by 12 percent, and at the same time its share of total manufacturing output grew from 57.2 percent in 1991 to 63.4 percent in 1998, as newer, less energy-intensive industries accounted for an increasing share of manufacturing activity. In 1991 the four most energy-intensive industries (petroleum, chemicals, primary metals, and paper) accounted for 26.3 percent of total manufacturing output, but by 1998 their share had fallen to 22.5 percent. For three of the seven manufacturing categories, energy intensity increased from 1991 to 1998 (petroleum by 15.3 percent, chemicals 7.4 percent, and food 5.7 percent). For paper and allied products, energy intensity remained unchanged. For nonmetallic minerals (stone, clay, and glass products) and for primary metals, energy intensity declined by 15.8 percent and 12.8 percent, respectively.

The mix and quantity of energy fuels consumed by manufacturers (for both fuel and nonfuel uses) affect the subsector’s aggregate carbon dioxide emission coefficient (C/E). Overall, manufacturing industries had aggregate carbon dioxide coefficients of 50.92 and 49.42 million metric tons carbon dioxide equivalent per quadrillion Btu for 1991 and 1998, respectively; however, the carbon dioxide factors of the various industries differed markedly.

The petroleum and chemical industries both transform some energy fuel into products that sequester carbon, such as petrochemical feedstocks, asphalt, and plastics. Because of that use, both the petroleum and chemical industries have lower aggregate coefficients than the manufacturing average (45.27 and 42.32 million metric tons carbon dioxide equivalent per quadrillion Btu for the petroleum industry and 45.84 and 44.26 for the chemicals industry in 1991 and 1998, respectively).

The paper industry makes extensive use of wood byproducts as an energy source. Carbon dioxide emissions from wood consumption are considered to be zero, because the carbon that is emitted has been sequestered recently, and the regrowing of trees will again sequester an equivalent amount of carbon dioxide. Consequently, the paper industry has a relatively low carbon dioxide emission coefficient, at 37.41 and 36.32 million metric tons carbon dioxide equivalent per quadrillion Btu in 1991 and 1998, respectively. In contrast, the primary metals industry, which uses large amounts of coal and other carbon-intensive fuels, has a high emission coefficient: 68.18 in 1991 and 68.52 in 1998.

Between 1994 and 1998, manufacturing industries had statistically significant increases in carbon dioxide emissions associated with their use of electricity (81.0 million metric tons or 16.9 percent) and natural gas (31.9 million metric tons or 9.3 percent). Moreover, electricity use continues to account for the largest share of manufacturers’ energy-related carbon dioxide emissions: 35.3 percent (480.6 million metric tons) in 1994 and 37.8 percent (561.6 million metric tons) in 1998.

Changes in Key Measures of Carbon Intensity in Manufacturing, 1991-1998 Printer Friendly Version Industry Group SICa Code 1991 1998 Percent Change, 1991-1998 E/Y C/E C/Y E/Y C/E C/Y E/Y C/E C/Y Petroleum 29 36 45.26 1,647.2 42 42.32 1,776.3  15.3 -6.5    7.8 Chemicals 28 17 45.84    771.3 18 44.25    800.0    7.4 -3.5    3.7 Metals 33 22 68.17 1,484.4 19 68.53 1,301.3 -12.8  0.5 -12.3 Paper 26 20 37.40    731.9 20 36.32    709.6   -0.2 -2.9   -3.0 Food 20   3 59.05    176.9   3 57.37    181.6    5.7 -2.9    2.6 Glass 32 16 67.76 1,104.7 14 66.57    913.7 -15.8 -1.8 -17.3 Other Manufacturing   2 55.20    131.7   2 54.81    114.7 -12.3 -0.7 -12.9 Total   8 50.91    408.8   7 49.42    356.0 -10.3 -2.9 -12.9 Total Without Structural Shift   8      —          —   8      —          —    0.7    —      —

As a result of the above changes in energy intensity, in combination with the structural shift in the subsector, overall manufacturing energy intensity (E/Y) declined by 10.3 percent from 1991 to 1998. When the influence of the structural shift is removed, however,^b decomposition analysis suggests an increase in energy intensity across the manufacturing sector of 0.7 percent from 1991 to 1998.

See Energy Use in Manufacturing Website

^aThe ratios presented here are estimated as aggregations of several manufacturing industries. Specifically, 20 manufacturing industries were aggregated into 7 groups for the calculation of industry-specific E/Y and C/Y ratios. Therefore, quantifying influences on the change in overall carbon intensity is valuable to the extent that these groupings represent changes in the U.S. manufacturing sector. It should be noted, however, that these ratios are based on survey data that are subject to sampling errors.

Methane Emissions from Industrial Wastewater Treatment

Industries generating high volumes of wastewater that includes large amounts of organic material are likely to generate methane emissions from the anaerobic decomposition of that organic material. Industries that fit this description include pulp and paper manufacturing, meat and poultry packing, and vegetable, fruit and juice processing. Determining total wastewater outflows, organic loadings, and the portion of anaerobic degradation of the loadings for each industry is difficult. Further, the emissions contribution of other industries is impossible to quantify at this time. Thus, EIA has chosen to exclude this emissions source from its estimates of overall methane emissions. In its report, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2001, the U.S. Environmental Protection Agency (EPA), makes some assumptions about the level of anaerobic decomposition of organic wastes in wastewater for the three industries referenced above.^aFor those three industries, the EPA estimates 900,000 metric tons of methane emissions in 2001, an amount equal to EIA’s current estimate of methane emissions from wastewater treatment and equivalent to 2.5 percent of total estimated U.S. methane emissions

^aU.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2001, EPA-430-R-03-004 (Washington, DC, April 2003), web site http://yosemite.epa.gov/oar/globalwarming.nsf/content/ResourceCenterPublicationsGHG EmissionsUSEmissionsInventory2003.html.

EPA Revises Emissions Estimation Methodology 

The primary source for the emission estimates presented in this chapter is data obtained from the U.S. Environmental Protection Agency (EPA), Office of Air and Radiation, which also prepares an annual inventory of greenhouse gas emissions.^a The data supporting the EPA inventory include emissions estimates through 2002, incorporating a number of revisions to the estimates of HFC, PFC, and SF₆ emissions for 2001 and earlier years. Those changes are reflected in the estimates presented in this chapter. 

The changes to the historical emission estimates are the result of revisions to the data and estimation methodologies used by the EPA: 

• Electrical Transmission and Distribution. The primary change in the methodology for calculating emissions from electrical transmission and distribution is an increase in the assumed emission rate from equipment manufacturers. Previously, the emission rate was assumed to be 3 percent of the SF₆ charged into new equipment. The revised 2001 estimate bases the quantity of SF₆ charged into new equipment on statistics compiled by the National Electrical Manufacturers Association. The revised 10-percent emission rate is the average of the “ideal” and “realistic” manufacturing emission rates (4 percent and 17 percent, respectively), as identified in a paper prepared under the auspices of the International Council on Large Electric Systems (CIGRE).^b This revision resulted in an average annual increase of 3.7 percent in SF₆ emissions for the period 1990 through 2000. 

• Magnesium Production and Processing. The emissions estimates in this report were revised to reflect new activity data for magnesium production and processing, which affected the emission factor for die casting. The new, lower emission factor was adjusted to account for lower emission rates reported by participants in EPA’s SF₆ Emission Reduction Partnership for the Magnesium Industry, including nearly 100 percent of all die casting operations in the United States. The combination of these changes and the methodological revision described above resulted in an average annual decrease of about 1.9 percent in SF₆ emissions for the period 1990 through 2000. 

• Substitution of Ozone-Depleting Substances. The EPA updated assumptions for its Vintaging Model in the fire-extinguishing sector. These changes resulted in an average annual decrease of 0.7 percent in HFC and PFC emissions for the period 1994 through 2000. 

• Aluminum Production. In cooperation with the EPA’s Voluntary Aluminum Industrial Partnership program, participants provided additional smelter-specific information on aluminum production and the frequency and duration of anode effects. The new information resulted in a decrease of 0.3 percent in PFC emissions for 2000. 

^aThe information presented in this text box was obtained from U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2001, EPA-430-R-03-004 (Washington, DC, April 2003), web site http://yosemite.epa.gov/oar/ globalwarming.nsf/content/ResourceCenterPublicationsGHGEmissionsUSEmissionsInventory2003.html. 

^bP. O’Connell, F. Heil, J. Henriot, G. Mauthe, H. Morrison, L. Neimeyer, M. Pittroff, R. Probst, and J.P. Tailebois, SF₆ in the Electric Industry, Status 2000 (CIGRE, February 2002).

The EPA Vintaging Model: Estimation Methods and Uncertainty 

The U.S. Environmental Protection Agency (EPA) uses a detailed Vintaging Model for equipment and products containing ozone-depleting substances (ODS) and ODS substitutes to estimate actual versus potential emissions of various ODS substitutes, including hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs). The model estimates the quantities of equipment and products sold each year that contain ODS and ODS substitutes, and the amounts of chemicals required for their manufacture and/or maintenance over time. Emissions from more than 40 different end uses are estimated by applying annual leak rates and release profiles, which account for the lag in emissions from equipment as it leaks over time. 

For most products (refrigerators, air conditioners, fire extinguishers, etc.), emissions calculations are split  into two categories: emissions during equipment lifetime, which arise from annual leakage and service losses plus emissions from manufacture; and disposal emissions, which occur when the equipment is discarded. By aggregating the data over different end uses, the model produces estimates of annual use and emissions of each compound.^a 

The EPA is consistently making improvements to the model to use more accurate data from the industries and to reduce uncertainty. The level of detail incorporated in the EPA Vintaging Model is higher than that of the default methodology used by the Intergovernmental Panel on Climate Change, reducing the uncertainty of model inputs, such as equipment characteristics and sales figures. 

^aU.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2001, EPA-430-R-03-004 (Washington, DC, April 2003), web site http://yosemite.epa.gov/oar/globalwarming.nsf/content/ResourceCenterPublicationsGHG EmissionsUSEmissionsInventory2003.html.

IPCC Good Practice Guidance for Land Use, Land Use Change and Forestry (LULUCF) 

International guidelines—the Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC Guidelines)—were adopted 7 years ago to support accounting for the storage and emission of greenhouse gases from various sources. The guidelines were developed before the adoption of the Kyoto Protocol and thus do not fully represent the new requirements for accounting for carbon fluxes resulting from LULUCF activities. 

To address a variety of limitations of the IPCC Guidelines, the Parties to the UNFCCC in 1998 called for the IPCC to produce Good Practice Guidance to the IPCC Guidelines. The first volume of the Good Practice Guidance was completed in 2000 and adopted by the Sixth Conference of the Parties to the UNFCCC (COP-6) in May 2000. For several reasons, however, the first volume did not cover LULUCF activities. At the time that the Good Practices Guidance was being developed, the IPCC was also preparing a Special Report on LULUCF, and simultaneous work on the two documents carried the risk of delivering inconsistencies. Further, significant negotiations on LULUCF activities were underway in the UNFCCC international climate change negotiations, and the IPCC believed it would be best to develop the guidance for LULUCF after completion of the negotiations. 

The IPCC was requested to develop Good Practice Guidance for LULUCF under decision 11/CP.7, agreed to at COP-7 in Marrakech in November 2001. As part of this process, a wide range of countries nominated expert authors to be involved in the development of LULUCF guidance. Three meetings of expert authors were held during 2002 in order to prepare a first draft of the Good Practice Guidance for LULUCF, which was released for review in December 2002. Submission of comments on the draft document was completed at the end of January 2003, with more than 6,000 comments received from governments and experts. The expert author teams considered the comments during meetings held in early April 2003, and a second draft document was issued. 

The second draft of the Good Practice Guidance for LULUCF was released in May 2003 for review by experts and governments. Submission of comments on the second draft document was completed at the end of June 2003. The IPCC author teams are currently in the process of revising the second draft in response to comments received. A final draft of the Good Practice Guidance for LULUCF will be provided to governments in October 2003 for final comment, before their anticipated acceptance at the COP-9 meeting in December 2003.^{a, b} 

^aThe Cooperative Research Centre for Greenhouse Accounting, “Good Practice for Land Use, Land-Use Change, and Forestry,” web site www.greenhouse.crc.org.au/goodpractice/ (2003). 

^bG.-J. Nabuurs and N.H. Ravindranath, “Task 1, Chapter 3: Good Practice Guidance for National GHG Inventory for LULUCF Sector.” Presentation at the IPCC-NGGIP Side Event at SB-18 (Bonn, Germany, June 6, 2003), web site http://www.ipcc-nggip.iges.or.jp/ SBSTA18/LULUCF_SBSTA18_side-event.htm.

Inventory of Woody Residuals in the United States 

The U.S. Forest Service (USFS) conducts analyses to estimate the quantity of woody residuals in the United States. The USFS estimates both the types and amounts of woody residuals generated, as well as the portion of those tonnages that are available for recovery.^a The data from the USFS analyses are useful to wood recycling enterprises, because they help to identify sources for processing and markets for services that help foresters clear and process downed woody debris that poses a significant fire threat. 

The four major sources of solid waste wood generated in the United States that are analyzed by the USFS are municipal solid waste (MSW), construction and demolition debris, processing residues from primary timber mills, and logging residues. Determining the amounts recoverable involves estimating total waste generated, less amounts currently recovered, combusted, or  considered unusable. The total amounts of recoverable wood from the four sources in 2001 were as follows: (1) 9.6 million tons from MSW, (2) 18.1 million tons from construction and demolition debris, (3) 1.9 million tons from primary timber processing, and (4) 74.5 million tons from logging residues. 

Logging residues represent the largest fraction of solid waste wood generated in the United States that is available for recovery. Currently, however, this material remains in the forest, contributing to “down woody material” (the portion of trees that have fallen and remain on the forest floor or in forest streams). Advances are being made in the collection, processing, and utilization of recoverable solid wood waste, but there still are some technical and economic obstacles to improved utilization. 

^aD. McKeever, “Taking Inventory of Woody Residuals,” BioCycle, Vol. 44, No. 7 (July 2003), pp. 31-35.

USDA Agriculture and Forestry Greenhouse Gas Inventory 

The U.S. Department of Agriculture (USDA) Global Change Program Office is currently compiling an Agriculture and Forestry Greenhouse Gas Inventory for the United States. The USDA inventory is intended to provide a comprehensive assessment of the contribution of agriculture and forestry to nationwide greenhouse gas emissions. The document was prepared to support and expand on information provided in the U.S. Environmental Protection Agency’s Inventory of U.S. Greenhouse Gas Emissions and Sinks. The USDA inventory provides detailed data on trends in agriculture and forestry greenhouse gas emissions and sinks, including information by source and sink at State and regional levels. The report is structured primarily from a land use perspective. It contains a chapter on forests, which details carbon sequestration in forests, soils, urban trees, and wood products for the year 2002. The USDA inventory is currently in draft form; however, EIA plans to publish the 2002 sequestration values in next year’s report.

Carbon Dioxide Capture and Geologic Storage 

Figure Data

The capture and permanent storage of carbon dioxide in geologic formations has gained increasing attention as an option for sequestering carbon dioxide emissions from industrial processes and coal-fired power generation. As part of the February 2002 introduction of the Global Climate Change Initiative, President Bush announced that the U.S. Government will develop policies to encourage geologic sequestration, which the Initiative describes as “critical to long-term emission reductions.” Federal support for sequestration technologies include $20 million for regional partnerships to test potential capture technologies and storage reservoirs, creation of the Carbon Sequestration Leadership Forum to encourage multilateral carbon sequestration  projects, and the Integrated Sequestration and Hydrogen Research Initiative, FutureGen, which is a $1 billion government/industry partnership to design a “nearly emission-free” coal-fired plant to produce electricity and hydrogen. 

The increased attention to geologic sequestration stems from the significant potential to store anthropogenic carbon dioxide in underground geologic formations. In the United States alone, geologic formations, such as depleted oil and gas reservoirs, deep unmineable coalbeds, and deep saline formations, may have the potential to store 140 to 670 billion to store 140 to 670 billion metric tons of captured carbon dioxide.^a These underground formations, which can be found all over the world, have the potential structure and porosity necessary for permanent sequestration, in that they already have stored crude oil, natural gas, brine, and naturally occurring carbon dioxide for millions of years. The two figures below show the estimated capacity range of each domestic geologic storage option in the United States and potential locations for geologic storage.

The geologic storage process involves the separation and capture of carbon dioxide from an anthropogenic source, such as a power plant or industrial facility; compression and transport of the carbon dioxide to the storage reservoir; and injection of the carbon dioxide into a geologic reservoir. As shown in the table below, geologic carbon dioxide storage projects can be divided into two categories. The first category consists of value-added capture and storage projects, in which captured carbon dioxide is reused for chemical or other industrial processes or to enhance resource recovery, such as enhanced oil, gas, and coalbed methane production. For this type of project, some of the cost of carbon dioxide storage is mitigated by the potential revenue expected from the sale of recovered oil or natural gas. In addition, the technologies for value-added storage are already mature. About 10 percent of enhanced oil recovery operations in the United States use waste carbon dioxide from industrial processes rather than naturally occurring carbon dioxide extracted directly from the ground.^b 

The second category includes storage projects undertaken specifically to reduce carbon dioxide emissions, without the incentive of other value-added benefits. So far, one such large-scale geologic sequestration project has been implemented. In 1996, prompted by the Norwegian tax on carbon dioxide, the oil company Statoil began taking unwanted carbon dioxide from the Sleipner West field in the Norwegian North Sea and storing it 1,000 meters beneath the seabed in a saline aquifer reservoir. Since 1996, about 1 million metric tons of carbon dioxide per year has been injected into the Utsira saline aquifer, an amount roughly equal to one-third of the carbon dioxide output of a 300-megawatt coal-fired power plant. 

The main challenge to geologic storage of carbon dioxide is not the technical feasibility of injection and storage, but the economics of capturing carbon dioxide from a point source. Carbon dioxide is never produced in a pure form and must therefore be separated from other products of combustion, making it more economical and practical to collect carbon dioxide from large point sources or power plants. The cost of capturing carbon dioxide is competitive in cases where the waste carbon dioxide stream is relatively pure, such as from natural gas processing or fertilizer and methanol production. Capture from stationary power plants is more costly, however, particularly from natural-gas-fired plants where the carbon dioxide content of the flue gas is lower. A number of commercial technologies to capture carbon dioxide have been developed, but they are energy-intensive and reduce the power plant’s net output while increasing costs and contributing to atmospheric emissions. The estimated “energy penalty” of  installing capture technology at a power plant ranges from 13 to 25 percent, depending on the type of combustion technology used.^c 

As shown in the table below, the cost of capturing carbon dioxide from integrated gasification combined cycle (IGCC), new pulverized coal (PC), and natural gas combined cycle (NGCC) power plants range from $17 to $61 per metric ton of carbon dioxide emissions avoided. Capturing and sequestering 90 percent of the carbon dioxide from a new power plant in the United States is estimated to add $0.02 per kilowatthour to the cost of electricity, with 75 to 80 percent of the added cost attributable to the capture and combustion process.^d Because capture technology must be an integral part of plant design, installing capture technology at existing facilities would be even more expensive. Thus, current research to improve the feasibility of capture and storage is focused on methods to decrease costs and energy use, as well as demonstrating that geologic sequestration is safe and environmentally sound. 

EIA’s national inventory does not consider carbon dioxide injected into oil, natural gas, or other geologic reservoirs as an emission but, instead, requires the reporting of carbon dioxide vented and flared during the production and processing of oil and gas. For active operations using enhanced oil recovery techniques, however, no estimate of carbon dioxide emissions is included in the annual inventory, because most of the carbon dioxide recovered with the oil is recycled and reinjected, and because currently there is no sound basis for estimating the quantity of carbon dioxide leaked from such operations. 

^aCO₂ Capture and Storage Working Group, NCCTI Energy Technologies Group, Office of Fossil Energy, U.S. Department of Energy, CO₂ Capture and Storage in Geologic Formations, Revised Draft (Washington, DC, January 8, 2002), web site www.netl.doe.gov/ coalpower/sequestration/pubs/CS-NCCTIwhitepaper.pdf. 

^bU.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory, Carbon Sequestration Technology Roadmap and Program Plan (Washington, DC, March 12, 2003), web site www.fe.doe.gov/programs/sequestration/publications/program_plans/03/. 

^cInternational Energy Agency (IEA), Solutions for the 21st Century: Zero Emissions Technologies for Fossil Fuels (Paris, France, May 2002), web site www.iea.org/impagr/zets/strategy/strategic_layout.pdf. 

^dJ. David, Economic Evaluation of Leading Technology Options for Sequestration of Carbon Dioxide. M.S. Thesis (Cambridge, MA: Massachusetts Institute of Technology, May 2000), web site http://sequestration.mit.edu/pdf/JeremyDavid_thesis.pdf.

Released: October 2003