Emissions of Greenhouse Gases in the United States 1997

The organization of this appendix generally follows the organization of the body of the report: the discussion is divided by greenhouse gas and by emissions source.

Carbon Dioxide

Most U.S. anthropogenic carbon dioxide emissions result from energy consumption. Energy production contributes a small amount from the flaring of natural gas at oil and gas wells, and a number of industrial processes also emit carbon dioxide through noncombustion processes. The largest single source of emissions from these processes is the calcination of limestone in cement production. Other sources include lime manufacture, limestone and dolomite consumption, soda ash manufacture and consumption, industrial carbon dioxide manufacture, and aluminum production. Lastly, some small adjustments are made to reach the total for national emissions. This appendix describes each carbon dioxide emissions source, the estimation methods used, and the data sources.

Several emissions sources are excluded from the carbon dioxide emissions presented in this report, due either to the uncertainty of estimates or because they are based on biomass combustion (which is assumed to be consumed sustainably with a net flux of carbon dioxide to the atmosphere equal to zero). Should the energy use of biomass fuels result in a long-term decline in the total carbon embodied in standing biomass (e.g., forests), the net release of carbon would be treated as a land use issue (see Chapter 6).

Energy Consumption

Emissions Sources

Most U.S. commercial energy is produced through the combustion of fossil fuels, such as coal, natural gas, and petroleum. Chemically, the main components of fossil fuels are hydrocarbons, made up of molecules containing hydrogen and carbon atoms. When these fuels are burned, atmospheric oxygen combines with the hydrogen atoms to create water vapor and with the carbon atoms to create carbon dioxide. In principle, if the amount of fuel burned and the amount of carbon in the fuel are known, the volume of carbon dioxide emitted into the atmosphere can be computed with a high degree of precision. In practice, however, a combination of real-world complexities can reduce the precision of the estimate. These complexities are discussed further in this appendix. Nonetheless, energy-related carbon dioxide emissions are known with greater reliability than are other greenhouse gas emissions sources, and the uncertainty of the estimate is probably 10 percent or less. Appendix C, "Uncertainty in Emissions Estimates," contains an extended discussion of the nature and sources of uncertainty in the estimates presented in this report.

One real-world complexity is that not all the carbon in fuel is perfectly combusted. About 1.5 percent of the carbon in fossil fuels is emitted in the form of carbon monoxide, which swiftly decays into carbon dioxide in the atmosphere. Another 1 percent is emitted in the form of volatile organic compounds (including methane), which also eventually decay into carbon dioxide. The carbon dioxide emissions reported in Chapter 2 include all "potential" carbon dioxide emissions from the sources covered, including both carbon dioxide emitted directly and carbon emitted in other forms (such as carbon monoxide) that rapidly decay into carbon dioxide in the atmosphere.

Estimation Methods

Carbon emissions in this report were calculated by multiplying energy consumption for each fuel type by an associated carbon emissions coefficient. The result was then modified by subtracting carbon sequestered by nonfuel use. This section describes the derivation of information on energy consumption, emissions coefficients, and carbon sequestered by nonfuel use.

Consumption Data

The Energy Information Administration (EIA) collects a wide variety of information from primary suppliers on a frequent basis and from energy consumers less often, but still in a timely manner. Thus, levels of energy consumption in the United States are fairly well known by end-use sector and detailed fuel type.⁽⁹⁷⁾ To estimate carbon dioxide emissions, the EIA uses annual data from the four end-use sectors (residential, commercial, industrial, and transportation) and for all the fossil fuels (coal, natural gas, and the full slate of petroleum products). The petroleum products include asphalt and road oil, aviation gasoline, distillate fuel, jet fuel, kerosene, liquefied petroleum gases (LPG), lubricants, motor gasoline, residential fuel, and other petroleum products. Definitions and chemical characteristics of the fossil fuels are documented in the appendixes of the EIA's recurring reports: the Annual Energy Review (AER) and State Energy Data Report (SEDR), as well as the Petroleum Supply Annual, Coal Industry Annual, and Natural Gas Annual. This approach to estimating emissions enables EIA to provide detailed information about trends in sources of emissions.

Information about consumption of "other petroleum" is derived from unpublished EIA data. In recent years, these products have included crude oil, naphtha <401^oF, other oil 401^oF, motor gasoline blending components, miscellaneous products, petroleum coke, pentanes plus, still gas, special naphthas, waxes, and unfinished oils.

Emissions Coefficients

The amount of carbon released when a fossil fuel is burned depends on the density, carbon content, and gross heat of combustion of the fuel.⁽⁹⁸⁾ Most of the coefficients for major fuels are assumed to be constant over time. However, for motor gasoline, LPG, jet fuel, and crude oil, EIA developed annualized carbon emissions coefficients to reflect changes in chemical composition or product mix over the years. Appendix B contains a more detailed discussion of the methods employed for developing the coefficients. Table B1 in Appendix B presents a full listing of emissions factors for crude oil, natural gas, and the complete slate of petroleum products.

Corrections to Energy Consumption Information

While, in general, emissions can be estimated simply by multiplying fuel consumption by the appropriate emissions coefficients, several small adjustments to EIA energy statistics are necessary to eliminate double counting or miscounting of emissions. Usually the adjustments amount to less than 0.1 percent of energy-related carbon emissions. They include:

Ethanol. About 70 million barrels of ethanol are included in annual U.S. gasoline consumption after 1992. Because ethanol is a biofuel, the carbon it contains should not be counted as an emission. Hence, carbon from ethanol is deducted from transportation gasoline consumption. Ethanol consumption is reported in the Renewable Energy Annual and the Petroleum Supply Annual.

Synthetic gas from coal. Small amounts of "supplemental gas"--particularly, gas from the Great Plains Coal Gasification Plant in North Dakota--are manufactured from coal. The coal is counted in industrial energy consumption, and the gas is shipped into the pipeline system. EIA deducts the carbon in synthetic gas (as reported in the Natural Gas Annual) from industrial coal emissions.

Still gas to pipelines. Several refineries sell small volumes of "still gas" as supplemental gas to pipelines. EIA deducts the carbon in still gas sales to pipelines (as reported in the Natural Gas Annual) from industrial "other petroleum" consumption.

Biogas. The Natural Gas Annual reports that small volumes of "supplemental gas" of biological origin (probably landfill gas) are incorporated in U.S. pipeline gas supplies. In keeping with the accounting rule of excluding carbon of biological origin, these supplies are deducted from U.S. natural gas consumption.

Carbon dioxide in geothermal steam. Geothermal steam at The Geysers in Guerneyville, California, where most U.S. geothermal electric power is generated, contains appreciable amounts of carbon dioxide dissolved in the steam, which is released into the atmosphere when the steam is brought to the Earth's surface for power production. EIA includes emissions from this source, at a rate of less than 0.1 million metric tons of carbon per year.

Carbon Sequestration: Nonfuel Use of Fossil Fuels

Gross emissions can be estimated by multiplying fossil fuel consumption by an emissions factor embodying the estimated carbon content of the fuel. However, portions of the fossil fuels consumed are not actually combusted but are used as chemical feedstocks, construction materials, lubricants, solvents, or reducing agents (Table A1). The EIA estimates "nonfuel" use of fossil fuels annually in Table 1.15 of the Annual Energy Review.⁽⁹⁹⁾ For this report, EIA has gone one step further and determined the fate of the carbon in fuels used for nonfuel purposes (see Table 8 in Chapter 2), based on the rates of sequestration shown in Table A2. In some cases, the carbon winds up in the atmosphere; in other cases, it does not. The principal nonfuel uses of fossil fuels, the methods of estimating nonfuel consumption, and the fate of the carbon are listed below.

Natural Gas. Nonfuel use of natural gas is based on periodic (1985, 1988, 1991, and 1994) reports in EIA's Manufacturing Energy Consumption Survey (MECS). Based on MECS, nonfuel use is divided into three categories: nitrogenous fertilizers, other chemical use, and all other nonfuel uses. Feedstock use of natural gas to make nitrogenous fertilizers is a nonsequestering use, since the underlying chemical in nitrogenous fertilizers is ammonia (NH₃), which is manufactured by steam reforming of natural gas and reacting the synthesis gas with atmospheric nitrogen, leaving the carbon in the feedstock literally "up in the air." In many cases, the carbon dioxide is recovered to make urea or for industrial use. However, carbon in urea and industrial carbon dioxide are generally only temporarily delayed on their way to the atmosphere. EIA assumes that other nonfuel uses in the chemical industry result in 100-percent carbon sequestration. Natural gas is used as a feedstock for a range of chemical products other than ammonia, particularly methanol. Although the methanol used to make methyl tertiary butyl ether (MTBE) winds up in the gasoline pool and is combusted, EIA already counts the carbon in MTBE in gasoline emissions, and to count it again in the feedstock would be double counting. Future research on the fate of the carbon in feedstocks for other chemical industry uses will probably gradually reduce the 100-percent sequestration share currently assumed.

Liquefied Petroleum Gases. Nonfuel use of LPG (ethane, propane, and butane) is estimated on the basis of sales of these products to the chemical industry, as reported by the American Petroleum Institute (API) in its annual survey, Sales of Natural Gas Liquids and Liquefied Refinery Gases, from which EIA deducts chemical industry fuel use of LPG as reported periodically in the MECS. Most of the ethane, propane, and butane used by the chemical industry is used to manufacture ethylene, propylene, and butadiene, respectively, all of which are intermediate products for plastics. Following the recommendation of the Intergovernmental Panel on Climate Change (IPCC), EIA assumes that 80 percent of nonfuel use is sequestered in plastics, synthetic rubber, and related products.⁽¹⁰⁰⁾

Asphalt and Road Oil. EIA assumes that asphalt and road oil use is nonfuel use by definition, and that all carbon in asphalt and road oil is sequestered.

Pentanes Plus. "Pentanes plus" are hydrocarbons heavier than butane extracted from natural gas at gas processing plants. Their principal uses are as contributors to the gasoline pool and as petrochemical feedstocks. Nonfuel use of pentanes plus is estimated on the basis of the API's annual survey of natural gas liquids and refinery gases sold to the chemical industry. Following IPCC practice for LPG, EIA assumes that 80 percent of the carbon in pentanes plus used by the chemical industry is sequestered.

Petrochemical Feedstocks. The EIA's petroleum surveys recognize two categories of products called "petrochemical feedstocks." These are presumably naphtha and gas oils destined for ethylene crackers, and probably some mix of aromatic hydrocarbons (benzene, toluene, and xylene) and feedstocks used to make aromatic hydrocarbons. All petrochemical feedstock supplies are included in nonfuel use by definition, and, following the practice of the IPCC, EIA assumes that 75 percent of the carbon in synthetic feedstocks and 50 percent of the carbon in gas oil feedstock is sequestered in plastics, synthetic fibers, and related products.

Distillate and Residual Fuels. The MECS reports small volumes (10 million barrels and 1 million barrels, respectively) of distillate and residual oils used for nonfuel purposes in the chemical industry. Following the practice for gas oil petrochemical feedstocks, EIA assumes 50-percent sequestration. Future research may shed more light on the industrial processes that use these fuels.

Petroleum Coke. Petroleum coke is a coal-like solid, about 90 percent carbon by weight, created after intensive extraction of lighter hydrocarbons from petroleum feedstocks by oil refiners. Most petroleum coke is used in the refineries as fuel or as a catalyst. EIA estimates nonfuel use by taking the quantity of petroleum coke supplied and deducting all known fuel uses (refinery use from the Petroleum Supply Annual, electric utility use from the Electric Power Annual, and industrial use from the MECS). EIA assumes that 50 percent of the carbon in petroleum coke for nonfuel use is sequestered. It should be noted, however, that significant sequestering nonfuel uses of petroleum coke in the United States are difficult to identify. The principal identified nonfuel use is for sacrificial anodes in primary aluminum smelting, a nonsequestering use that EIA counts separately under process emissions (see the next section). It appears that petroleum coke is also used in small quantities by many different industries as a reducing agent (a source of carbon monoxide that, in turn, can be used to scour oxygen from products such as lead oxide (to produce lead) or iron oxide (to produce iron). These are, however, nonsequestering uses.

Still Gas. Still gas is the gas that floats to the top of distillation columns in oil refineries. Its chemical composition is a highly variable blend of free hydrogen, methane, carbon monoxide, and heavier hydrocarbons, depending on the refinery process, the feedstock, and process conditions. EIA estimates nonfuel use by deducting all known fuel uses (refinery fuel use from the Petroleum Supply Annual and pipeline gas supplies from the Natural Gas Annual). The remainder is assumed to be dispatched to chemical plants as a feedstock. Following the IPCC practice for LPG, EIA assumes that 80 percent of the carbon in still gas is sequestered.

Special Naphtha. "Special naphtha" is a catch-all for an array of hydrocarbon-based solvents, such as hexane and the volatile oils used in petroleum-based paint. In general, solvents evaporate into the atmosphere as "nonmethane volatile organic compounds" after use and swiftly weather into atmospheric carbon dioxide. EIA assumes that all special naphthas are for nonfuel use and that no carbon in special naphtha is sequestered.

Lubricants. The most common petroleum-based lubricant is motor oil, but the category also includes numerous other products, such as industrial greases. Following the IPCC, EIA assumes that 50 percent of the carbon in lubricants is sequestered. The ultimate fate of lubricants is not easy to determine. For example, it is often the case that "recycling" motor oil means burning it as boiler fuel.

Waxes and Polishes. The principal use of waxes is to make wax paper and food packaging materials, which usually end up in landfills. Following the IPCC, EIA assumes 100-percent nonfuel use and 100-percent carbon sequestration for these materials.

Miscellaneous. EIA assumes 100-percent nonfuel use and 100-percent carbon sequestration for this category.

Coal. Arguably, the manufacture of coke is the largest nonfuel use of coal. By convention, however, coke manufacture is treated as a fuel use. This is not unreasonable, because coke is almost always ultimately combusted. Coke is manufactured by "cooking" high-grade coal in huge ovens in the absence of oxygen. Volatile materials, moisture, and certain categories of impurities are driven off, leaving behind a high-carbon material suitable for metallurgical use. Among the byproducts of the process are "coal tars" or "coal liquids," which typically are rich in aromatic hydrocarbons, such as benzene. Coal tars generally are used as feedstocks in the chemical industry. "Nonfuel use" of coal, as defined for this report, consists of the coal tars driven off during the manufacture of coke. Coal tar production was obtained, for years prior to 1995, from the International Trade Commission's Synthetic Organic Chemicals. Since 1995, production has been estimated on the basis of the ratio of 1994 coke production to coal tar production. Following the IPCC guidelines, EIA assumes that 75 percent of the carbon in coal tars is sequestered.

Carbon Sequestration: Fraction Combusted

A small amount of carbon sequestration is associated with the combustion of fossil fuels. Using IPCC assumptions, EIA assumes that oxidation of liquid and solid fuels during combustion is 99 percent complete, and that 1 percent of the carbon remains sequestered. Oxidation of gaseous fuels (LPG and natural gas) is assumed to be 99.5 percent complete.⁽¹⁰¹⁾ Conceptually, fuel may be "lost" before combustion due to evaporation, leaks, or spills; it may be subject to incomplete combustion and vented to the atmosphere in the form of volatile organic compounds or particulates; or it may remain at the site of combustion in the form of carbon-containing ash or soot.

Data Sources

Fossil Fuel Consumption (1980-1995): Energy Information Administration, State Energy Data Report 1995, DOE/EIA-0214(95) (Washington, DC, September 1997). (1996-1997): Energy Information Administration, Monthly Energy Review, DOE/EIA-0035(98/07) (Washington, DC, July 1998); Petroleum Supply Annual 1997, DOE/ EIA-0340(97) (Washington, DC, June 1998); Natural Gas Annual 1996, DOE/EIA-0131(96) (Washington, DC, October 1997); and Renewable Energy Annual 1997, DOE/EIA-0603(97) (Washington, DC, March 1998).

Nonfuel Use of Energy and Biofuels Consumption: Energy Information Administration, Annual Energy Review 1997, DOE/EIA-384(97) (Washington, DC, July 1998); Energy Information Administration, Manufacturing Energy Consumption Survey 1991, DOE/EIA-0512(91) (Washington, DC, December 1994); Energy Information Administration, Manufacturing Consumption of Energy 1994, DOE/EIA-0512(94) (Washington, DC, December 1997), and previous years (1985, 1988, and 1991); American Petroleum Institute, Sales of Natural Gas Liquids and Liquefied Refinery Gas (various years); U.S. International Trade Commission, Synthetic Organic Chemicals, USITC Publication 2933 (various years through 1994); and Intergovernmental Panel on Climate Change, Greenhouse Gas Inventory Reference Manual: Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Vol. 3 (Paris, France, 1997), p. 1.28, web site www.iea.org/ipcc/ invs6.htm.

Adjustments to U.S. Energy Consumption

In recent years, there have been several estimates of U.S. carbon emissions, some of which differ by as much as 5 percent. Two significant reasons for the differences in emissions estimates (beyond those associated with differences in coefficients) are the definitions of "energy consumption" and "the United States" employed by researchers. Subtle differences in definition can produce variations of several percentage points in reported energy consumption and, hence, in carbon emissions. Some estimates include U.S. territories while others exclude them. If consumption is estimated as "apparent consumption" based on production plus imports minus exports plus stock change, then statistical discrepancies will be included in consumption. International bunkers are sometimes counted as domestic consumption and sometimes as exports. This section describes how each adjustment is accommodated in the EIA estimates.

U.S. Territories

Emissions Sources

EIA's energy data for the United States cover only the 50 States and the District of Columbia. In contrast, energy data produced by the International Energy Agency for the United States cover the 50 States plus U.S. territories, including Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, Micronesia, and Wake Island. Annual energy consumption in the U.S. territories is only about 0.5 quadrillion Btu (Table A3). Because all the U.S. territories are islands, their consumption consists primarily of petroleum products. For the territories as a group, oil consumption ranges between 200,000 and 250,000 barrels per day, and coal consumption averages about 300,000 short tons per year, mostly in Puerto Rico.

Estimation Methods

Energy consumption for U.S. territories is converted to carbon emissions by using the same emissions coefficients applied to U.S. energy data. Carbon emissions for U.S. territories range from 10 to 12 million metric tons per year (see Table 6 in Chapter 2). Because a large portion of reported energy consumption in U.S. territories is from "other petroleum," there is a degree of uncertainty about the correct emissions factor to be used in this area, as well as the reliability of underlying data.

Data Sources

1980-1996: Energy Information Administration, International Energy Annual, DOE/EIA-0219 (Washington, DC, various years), and unpublished estimates for Wake Island, American Samoa, and the Pacific Trust Territories, which are included as "Other" in the Far East and Oceania region in the International Energy Annual. 1997: EIA estimate.

International Bunker Fuels

Emissions Sources

The term "international bunker fuels" refers to fuel purchased by merchant ships in U.S. ports and by international air carriers in U.S airports. By convention, trade statistics treat sales of bunker fuels as exports by the selling country, because the purchaser promptly hauls the fuel outside national boundaries. This convention is followed by organizations that prepare international energy statistics, such as the United Nations and the International Energy Agency.

Bunker fuels, however, are an export without a corresponding import, because the purchasing ship generally burns the fuel on the high seas. EIA energy statistics, which are based on domestic sales of products, treat bunker fuels sales in the same way as sales of other fuels, i.e., as domestic energy consumption. Carbon emissions from bunker fuels are, therefore, already counted in the domestic energy consumption of the United States--primarily as transportation-related consumption of residual oil. Those who wish to understand the differences between emissions inventories based on international energy statistics and EIA data will, however, need to know the amount of energy consumption and the amount of carbon emissions associated with international bunkers. Table A3, therefore, shows U.S. international bunker fuel usage.⁽¹⁰²⁾ The amount is about 1.1 quadrillion Btu (or 500,000 barrels per day), largely of residual oil. It accounts for emissions of about 19 to 24 million metric tons of carbon annually (see Table 6 in Chapter 2).

Estimation Methods

The appropriate carbon coefficient is applied to estimated annual consumption for several fuels (including residual and distillate fuels, as well as kerosene-type jet fuels), with the assumption that 99 percent of the fuel is combusted.

Data Sources

Distillate and Residual Fuels (1980-1990): Energy Information Administration, International Energy Annual, DOE/EIA-0219 (Washington, DC, 1980-1990). (1991-1997): Energy Information Administration, Fuel Oil and Kerosene Sales, DOE/EIA-0535 (Washington, DC, 1991-1997). Jet Fuels (1980-1996): Oak Ridge National Laboratory, Transportation Energy Data Book (Oak Ridge, TN, various years). 1997: EIA estimate.

Industrial Sources

Carbon dioxide emissions from "industrial sources" are industrial emissions that are not caused by the combustion or feedstock use of commercial fossil fuels. These emissions typically are created either by the combustion of waste products containing fossil carbon (natural gas flaring) or by chemical reactions with carbon-containing minerals (for example, calcining sodium carbonate [limestone] to make lime or cement).

Energy Production

Emissions Sources

U.S. energy production also generates small volumes of carbon dioxide emissions. The two principal sources are flaring of natural gas and venting of carbon dioxide produced in conjunction with natural gas.⁽¹⁰³⁾ When a field is developed for petroleum extraction, any natural gas associated with that field may be flared if its use is not economically justifiable. This is typically the case for remote sites or when the gas is of poor quality or minimal volume. During natural gas production, flaring may be used for disposal of waste products (e.g., hydrogen sulfide), capacity testing, or as a result of process upsets.

Emissions from the second source, carbon dioxide produced in conjunction with natural gas, occur during production activities. Natural gas is actually a mixture of several different gases including carbon dioxide. If the carbon dioxide content of natural gas is large enough to reduce the heating value of the gas below the specification for pipeline gas (870 Btu per standard cubic foot), the carbon dioxide is typically extracted by amine scrubbing. The extracted carbon dioxide generally is released to the atmosphere.

Estimation Methods

The method for estimating emissions from natural gas flaring is based on the volume of vented and flared gas reported to the EIA (assuming that all gas is flared). To calculate carbon emissions, the figures are aggregated, converted into Btu, and then multiplied by an emissions coefficient of 14.92 million metric tons of carbon per quadrillion Btu.

As estimates presented in Chapter 2 indicate, natural gas flaring is a minor source of emissions, accounting for only about 2 to 5 million metric tons of carbon annually. There is some uncertainty associated with this estimate, given that operators in the field are not required to meter gas that is vented or flared.

The carbon dioxide produced in conjunction with natural gas is estimated by multiplying regional production data by regional carbon dioxide contents from a Gas Research Institute (GRI) study. The estimates of carbon dioxide emitted during transmission and distribution are derived by multiplying pipeline and end-use consumption data by the carbon dioxide content of natural gas delivered to consumers from a second GRI study. Emissions associated with production activities are calculated by subtracting consumption-related emissions from the total carbon dioxide initially produced.

Data Sources

Flaring (1980-1996): Energy Information Administration, Natural Gas Annual, DOE/EIA-0131 (Washington, DC, various years). (1997): Natural Gas Monthly, DOE/EIA-0130(98/06) (Washington, DC, June 1998). Carbon Dioxide Produced with Natural Gas: Composition (1980-1997): Gas Research Institute, Chemical Composition of Discovered and Undiscovered Natural Gas in the United States--1993 Update, GRI-93/0456.1. Gas Research Institute, Variability of Natural Gas Composition in Select Major Metropolitan Areas of the United States, GRI-92/0123. Production (1980-1996): Dwight's Energy Data Lease/ Well Production File. (1997): Energy Information Administration, Natural Gas Monthly, DOE/EIA-0130 (Washington, DC, 1997). Transmission and End-Use Consumption (1980-1996): Energy Information Administration, Natural Gas Annual, DOE/EIA-0131 (Washington, DC, various years). (1997): Energy Information Administration, Natural Gas Monthly, DOE/EIA-0130 (Washington, DC, 1998).

Industrial Processes

In addition to energy-related emissions, carbon dioxide is also produced during certain industrial processes. The primary source of industrial emissions is the calcination of limestone (CaCO₃) to create lime (CaO). These two compounds are basic materials in a variety of manufacturing processes, particularly cement, iron and steel, and glass. Other sources of industrial emissions include the production and use of soda ash (Na₂CO₃), the manufacture of carbon dioxide, and aluminum production.

For this source category, emissions estimates are based on the compound used in the industrial process. Table A4 shows activity data for industrial processes. By multiplying the amount of production or consumption of the compound by a carbon coefficient (the relative amount of carbon in that compound), a process-specific estimate is derived. In recent years, industrial sources have accounted for about 17 to 18 million metric tons of carbon annually. Each industrial process, emissions source, and estimation method is discussed below.

Cement Manufacture

More than half of the carbon dioxide emissions from industrial sources originate from cement manufacturing (see Chapter 2).

Emissions Sources. Four basic materials are required to make cement: calcium, silicon, aluminum, and iron. Substrates of these materials are ground into a powder and heated in a kiln. While in the kiln, limestone (the predominant source of calcium) is broken down into carbon dioxide and lime. The carbon dioxide is driven off into the atmosphere. After the kilning process has been completed, cement clinker is left.

Estimation Methods. One mole of calcined limestone produces one mole of carbon dioxide and one mole of lime. Since virtually all of the lime produced is absorbed into the clinker, the lime content of clinker is assumed to be representative of the amount of carbon dioxide emitted. In order to estimate emissions from cement manufacture, a carbon coefficient must be calculated. The EIA has adopted the IPCC recommendation that 64.6 percent of cement clinker is lime.⁽¹⁰⁴⁾ Multiplying this lime content factor by the ratio of carbon produced to lime produced yields the coefficient for cement clinker. A separate coefficient is necessary for estimating emissions from the additional lime used to produce masonry cement. In this case, the amount of lime not accounted for as clinker is assumed to be 3 percent.⁽¹⁰⁵⁾ This factor is then multiplied by the same production ratio of carbon to lime, generating the carbon coefficient for masonry cement.

Lime Manufacture

Lime is an important chemical with a variety of industrial, chemical, and environmental applications.

Emissions Sources. Lime production involves three main stages: stone preparation, calcination, and hydration. Carbon dioxide is generated during the calcination stage, when limestone is roasted at high temperatures, just as it is released during clinker production. The carbon dioxide is driven off as a gas and normally exits the system with the stack gas.

Estimation Methods. Based on the ratio of the molecular weight of carbon dioxide to the weight of calcium carbonate, the EIA assumes that 785 metric tons of carbon dioxide, or 214 metric tons of carbon, are released for every 1,000 metric tons of lime produced. This factor is applied to annual levels of lime manufacture to estimate potential emissions. The EIA does not account for the instances in which the carbon dioxide is recovered or reabsorbed. Representatives of the National Lime Association believe that 10 to 20 percent of the carbon dioxide emitted in lime manufacture is recovered for industrial use or reabsorbed from the atmosphere by chemical reactions induced by the use of lime.

Limestone and Dolomite Consumption

These are basic raw materials used by a wide variety of industries, including the construction, agriculture, chemical, and metallurgical industries.

Emissions Sources. Limestone (including dolomite) can be used as a flux or purifier in metallurgical furnaces, as a sorbent in flue gas desulfurization (FGD) systems in utility and industrial plants, or as a raw material in glass manufacturing. Limestone is heated during these processes, generating carbon dioxide as a byproduct.

Estimation Methods. Assuming that limestone has a carbon content of 12 percent and dolomite 13.2 percent, the EIA applies the appropriate factor to the annual level of consumption in the iron smelting, steelmaking, and glass manufacture industries, and in flue gas desulfurization systems that use this sorbent. This amounts to 120 metric tons of carbon for every 1,000 metric tons of limestone consumed, or 132 metric tons of carbon for every 1,000 tons of dolomite consumed (when dolomite is distinguished in the data).

Soda Ash Manufacture and Consumption

Commercial soda ash (sodium carbonate) is used in many familiar consumer products, such as glass, soap and detergents, paper, textiles, and food.

Emissions Sources. Two methods are used to manufacture natural soda ash in the United States. The majority of production comes from Wyoming, where soda ash is manufactured by calcination of trona ore in the form of naturally occurring sodium sesquicarbonate. For every mole of soda ash created in this reaction, one mole of carbon dioxide is also produced and vented to the atmosphere. The other process used to manufacture soda ash is carbonation of brines; however, the carbon dioxide driven off in this process is captured and reused.

Once manufactured, most soda ash is consumed in glass and chemical production. Other uses include water treatment, flue gas desulfurization, soap and detergent production, and pulp and paper production. As soda ash is processed for these purposes, additional carbon dioxide may be emitted if the carbon is oxidized. Because of the limited availability of specific information about such emissions, only certain uses of soda ash are considered in this report. Sodium silicate and sodium tripolyphosphate are included as chemicals manufactured from soda ash and components of detergents.

Estimation Methods. For soda ash manufacture, in order to ensure that carbon dioxide from the carbonation of brines is not included in emissions estimates, the calculations in this report are derived solely from trona ore production figures. Approximately 1.8 metric tons of trona ore are required to yield 1 metric ton of soda ash. This amounts to 97 million metric tons of carbon for every 1,000 tons of trona ore produced annually. For soda ash consumption, the EIA applies a factor of 113 metric tons of carbon for every 1,000 metric tons of soda ash consumed in glass manufacturing or in flue gas desulfurization.

Carbon Dioxide Manufacture

Emissions Source. Carbon dioxide is produced from a small number of natural wells and as a byproduct of chemical (i.e., ammonia) manufacturing. The Freedonia Group has determined that, in the United States, there is an 80 percent to 20 percent split between carbon dioxide produced as a byproduct and carbon dioxide produced from wells.⁽¹⁰⁶⁾ Emissions of byproduct carbon dioxide are incorporated into the natural gas energy consumption estimates as nonfuel, nonsequestered carbon and therefore are not included here to avoid double counting.

Most carbon dioxide produced from wells is injected back into the ground for enhanced oil recovery. This process sequesters the carbon dioxide, at least in the short run. Conceptually, only carbon dioxide produced from wells and diverted to industrial use is emitted to the atmosphere.

Estimation Methods. The Freedonia Group estimates that nonsequestering industrial use of carbon dioxide resulted in emissions of 1.3 million metric tons of carbon in 1993.⁽¹⁰⁷⁾ If 20 percent of this industrial use is supplied by wells, emissions can be estimated at 0.26 million metric tons of carbon. Based on the Freedonia report, the 1997 estimate is calculated by assuming an annual 4.2-percent increase, implying emissions of 0.31 million metric tons of carbon.

Aluminum Manufacture

Aluminum is an element used in alloys. Because it is light in weight, malleable, and not readily corroded or tarnished, it is used as a principal material for kitchen utensils, aircraft, some automobiles, bicycles, and other manufactured products. The United States is a major producer of aluminum and also an importer, depending on market conditions.

Emissions Sources. As part of the primary aluminum smelting process, alumina (aluminum oxide, Al₂O₃) is vaporized by a powerful electric current. Emissions from the electricity used to generate the current are included with emissions from industrial electricity consumption and are not counted separately. The current also vaporizes a carbon "sacrificial anode," typically manufactured from petroleum coke. This is a nonsequestering nonfuel use of a fossil fuel. To avoid double counting, 50 percent of nonfuel use of petroleum coke is carried as "sequestering." Thus, process emissions from aluminum smelting can be considered as a deduction from the sequestering portion of nonfuel use of petroleum coke.

Estimation Methods. In previous years, following the work of Abrahamson, EIA has used the midpoint of a range of emissions factors of 1.5 to 2.2 metric tons of carbon dioxide (0.41 to 0.60 metric tons of carbon) emitted per metric ton of aluminum smelted.⁽¹⁰⁸⁾ The 1994 MECS indicated that nonfuel use of fuels by aluminum smelters (SIC 3334) totaled 40 trillion Btu in 1994.⁽¹⁰⁹⁾ The composition of nonfuel use by fuel type has been withheld for confidentiality purposes, but it is probable that most of the 40 trillion Btu consists of petroleum coke, which would imply an emissions factor of about 0.338 metric tons of carbon per metric ton of aluminum smelted (0.04 quadrillion Btu of coke � 27.85 million metric tons of carbon per quadrillion Btu / 3.295 million metric tons of aluminum smelted in 1994). EIA now uses an emissions factor of 0.4 metric tons carbon per metric ton of aluminum smelted, which is at the low end of Abrahamson's range and also equals the mass balance for a "typical" aluminum smelter from another source.⁽¹¹⁰⁾

Data Sources for Industrial Processes

The U.S. Geological Survey reports listed below can be found on the Internet at minerals.er.usgs.gov/pubs/ commodity.

Cement and Clinker Production (1980-1996): U.S. Department of the Interior, U.S. Geological Survey, Cement Annual Report (Washington, DC, various years). (1997): U.S. Department of the Interior, U.S. Geological Survey, Office of Minerals, Faxback Service.

Lime Manufacture: (1980-1997): U.S. Department of the Interior, U.S. Geological Survey, Mineral Commodity Summaries (Washington, DC, various years).

Limestone Consumption in Iron Smelting, Steelmaking, and Glass Manufacture: (1980-1996): U.S. Department of the Interior, U.S. Geological Survey, Crushed Stone Report (Washington, DC, various years). (1997): EIA estimate. Limestone Consumption in Flue Gas Desulfurization: (1980-1995): Energy Information Administration, unpublished survey data, Form EIA-767, "Steam Electric Plant Operation and Design Report" (Washington, DC, various years).

Soda Ash Manufacture and Soda Ash Consumption in Glass Making (1980-1997): U.S. Department of the Interior, U.S. Geological Survey, Soda Ash Report (Washington, DC, various years). Soda Ash Consumption in Flue Gas Desulfurization (1980-1996): Energy Information Administration, unpublished survey data, Form EIA-767, "Steam Electric Plant Operation and Design Report" (Washington, DC, various years). (1997): EIA estimate. Sodium Silicate and Sodium Tripolyphosphate: (1980-1996): Chemical Manufacturers Association, U.S. Chemical Industry Statistical Handbook 1997 (Washington, DC, September 1997), pp. 37-38. (1997): EIA estimate.

Carbon Dioxide: Freedonia Group, Inc., Carbon Dioxide, Business Research Report B286 (Cleveland, OH, November 1991), and Carbon Dioxide, Industry Study 564 (Cleveland, OH, February 1994).

Aluminum (1980-1997): U.S. Department of the Interior, U.S. Geological Survey, Aluminum Report (Washington, DC, various years).

Methane

Energy Sources

Oil and Gas Production, Processing, and Distribution

Emissions Sources

Because methane is the principal constituent of natural gas (representing about 95 percent of the mixture), releases of natural gas result in methane emissions. Methane emissions can be grouped into three categories: (1) fugitive or unintentional leaks emitted from sealed surfaces such as pipelines, gaskets, and flanges; (2) vented or intentional releases from process vents, maintenance blowdowns, and pneumatic devices; and (3) releases from incomplete combustion in compressor engines, burners, and flares.⁽¹¹¹⁾ The natural gas industry can be divided into four source segments:

Gas Production. This segment consists of gas and oil wells, surface equipment to produce gas, and gathering pipeline. Leakage occurs from valves, meters, and flanges. Pneumatic valves release gas when they are reset. Gathering pipeline may be emptied for maintenance or may have fugitive emissions.

Gas Processing. When gas is processed, liquefied petroleum gases and natural gasoline are removed for sale or further refining. Water is also removed, and gas is conformed to commercial pipeline quality and heat content. Methane is released during maintenance, via leaks, and during system upsets when sudden increases in pressure require a gas release or result in a system rupture.

Transmission and Storage. High-pressure transmission pipelines are used to transport natural gas from production fields and gas processing facilities to distribution pipelines. Natural gas may escape through leaky pipes and valves. Methane may be emitted as part of compressor exhaust. Gas is often stored near consumption centers to meet peak demand during periods of high consumption. These storage facilities emit methane in compressor exhaust and from dehydrators.

Distribution. The pressure of gas received from the transmission system is lowered at the gate station and is forwarded to distribution pipeline for delivery to residential, commercial, and industrial consumers. Leaks may occur at gate stations, through leaky pipes, and at customer meters.

Methane may also be emitted during oil refining and transportation. These emissions occur when methane is separated from crude oil during refining. After oil is transferred to storage tanks methane may be emitted by vapor displacement. Vapor displacement also occurs during loading and unloading of oil barges and tankers.

Estimation Methods

Natural Gas Systems. Previous EIA estimates of emissions from the natural gas system were scaled to commonly available activity data such as number of wells in operation, miles of gathering pipeline, gas throughput, gas volumes processed, miles of transmission pipeline and miles of distribution pipeline. The activity data were multiplied by emissions factors derived from point-in-time emissions estimates for 1992 developed in a study sponsored jointly by the U.S. Environmental Protection Agency (EPA) and the Gas Research Institute (EPA/GRI).⁽¹¹²⁾ The EPA/GRI study, however, provides activity data and disaggregated emissions factors for 86 separate gas industry process components. In an effort to take advantage of this level of detail, this report estimates the number of each process component for the years 1990-1997. Each process component is scaled to a widely available metric, such as gas withdrawals or pipeline miles most related to the process activity. The derived activity data are then applied to the component emissions factor from the EPA/GRI report.

Oil Wells. The number of operating oil wells in the United States is multiplied by a per-well emissions factor from the EPA's report to Congress, Anthropogenic Methane Emissions in the United States.⁽¹¹³⁾

Oil Refining and Transportation. Estimates are calculated by using emissions from a 1992 Radian Corporation report⁽¹¹⁴⁾ in conjunction with refinery data collected by EIA.

Data Sources

Natural Gas Systems. Emission factors and activity data for 1992 are from the joint EPA/GRI study: National Risk Management Research Laboratory, Methane Emissions From the Natural Gas Industry, Vol. 2, Technical Report, GRI-94/0257.1 and EPA-600-R-96-08 (Research Triangle Park, NC, June 1996). Activity data for all other years are scaled to data from the following sources: gas wellheads, gross gas withdrawals, gas processing and gas removed from storage can be found in EIA's Natural Gas Annual (various years); transmission and distribution pipeline mileage are published annually by the American Gas Association in Gas Facts.

Oil Wells. The number of operating oil wells is available annually in the February issue of the World Oil journal.

Oil Refining and Transportation. Data on the volume of crude oil refined and the volume of crude oil transported on marine vessels can be found in EIA's Annual Energy Review, DOE/EIA-0384 (Washington, DC, various years), and Petroleum Supply Annual, DOE/EIA-0340 (Washington, DC, various years).

Coal Mining

Emissions Sources

As coal is formed from organic material by natural chemical and physical processes, methane is also produced. The methane is stored in the pores (open spaces) of the coal itself and in cracks and fractures within the coalbed. As coal is mined, the pressure surrounding the stored methane decreases, allowing much of it to be released into the operating coal mine (in the case of an underground mine) or into the atmosphere (in the case of a surface mine). The methane remaining in the coal pores is emitted when the coal is transported and pulverized for combustion. There are five avenues for methane emissions from coal mines:

Ventilation Systems in Underground Mines. Methane in concentrations over 5 percent is explosive and presents a mortal danger to coal miners. To meet safety standards set by the Mine Safety and Health Administration (MSHA) requiring levels of methane concentration to be maintained well below the 5 percent threshold, mine operators use large fans to provide a steady airflow across the mine face and ventilate the mine shaft. Typically, these ventilation systems release substantial quantities of methane in the fan exhaust.

Degasification Systems in Underground Mines. When the volume of gas in underground mines is too high to be practically reduced to safe levels by standard ventilation techniques, degasification systems are employed. Degasification may take place before mining or may take the form of gob-wells or in-mine horizontal boreholes. Methane captured by degasification systems may be vented, flared, or recovered for energy. There are currently 25 mines in the United States employing degasification drainage systems, 15 of which are recovering and using the methane as an energy resource.

Surface Mines. Because coal mined from the surface has formed at lower temperature and pressure than coal from underground mines, its methane content is lower. Further, because the coal is located near the surface, methane has had ample opportunity to migrate to the atmosphere before mining. Thus, while methane emissions from surface mines are heterogeneous in nature, they are systematically smaller than emissions from underground mines.

Post-Mining Emissions. Methane that remains in coal pores after either underground or surface mining will desorb slowly as the coal is transported (typically by train) to the end user. Because coal that is consumed in large industrial or utility boilers is pulverized before combustion, methane remaining in the coal pores after transport will be released prior to combustion.

Methane Recovery for Energy. In some cases (for example, in some mining degasification systems), methane is emitted from coal mines in sufficiently high volumes and concentrations to permit commercial recovery of the gas as either pipeline gas or fuel for electric power generation. Since coal mine methane recovered commercially is combusted, the quantities recovered are subtracted from estimates of total coal mine methane emissions.

Estimation Methods

Ventilation Systems in Underground Mines. Emissions from this source are segregated into two classes: emissions from "gassy" mines and emissions from "nongassy" mines.⁽¹¹⁵⁾ Because methane concentrations and airflows in gassy mines are carefully monitored by the MSHA, a fairly reliable set of data can be derived for emissions from ventilation systems in gassy mines. However, MSHA data are voluminous, inconsistent in format, and difficult to compile, and they are available for only a subsample of years (1980, 1985, 1988, 1990, 1993, 1994, 1996, and 1997). Thus, the available data are used in conjunction with coal production data for those years to develop emissions factors per ton of coal mined on a basin-by-basin level.⁽¹¹⁶⁾ Emissions factors for nonsample years are interpolated or extrapolated. The resulting emissions factors are then multiplied by production data to estimate emissions from this source (for detailed production data, see Table A5).

Emissions from nongassy mines make up less than 2 percent of all emissions from underground mines.⁽¹¹⁷⁾ Basin-level emissions factors for nongassy mines were established by dividing 2 percent of each basin's estimated emissions from nongassy mines for 1988 by that year's production levels. The resulting emissions factors are applied to annual production data.

Degasification Systems in Underground Mines. Degasification emissions are not monitored by any regulatory agency. Where degasification does occur, the method of disposition (e.g., venting, flaring, sale for energy) may not be tabulated. Estimated emissions from degasification systems during the period 1993 through 1996 are based data collected by the EPA's Office of Air and Radiation, Coalbed Methane Outreach Program, and published in Identifying Opportunities for Methane Recovery at U.S. Coal Mines.⁽¹¹⁸⁾ For years prior to 1993, emissions from degasification systems are estimated by multiplying annual production in mines known to have degasification systems in place by a per-ton emissions factor. Because mine-by-mine production data are not yet available for the current year, 1997 emissions from degasification systems are scaled to increases in underground coal production.

Surface Mines. Emissions from U.S. surface mines have not been systematically measured. However, studies on surface coal mines in the United States, England, France, and Canada suggest a range of 0.3 to 2.0 cubic meters per metric ton of coal mined.⁽¹¹⁹⁾ This report adopts the central value of that range and multiplies it by U.S. surface coal production.

Post-Mining Emissions. Like emissions from surface mines, post-mining emissions are not measured systematically. Thus, global average emissions factors must be applied. Post-mining emissions for coal mined from the surface are estimated to be very low, between 0.0 and 0.2 cubic meters per metric ton of coal mined. In contrast, post-mining emissions from underground coal are estimated to be more significant, between 0.9 and 4.0 cubic meters of methane per metric ton of coal mined.⁽¹²⁰⁾ The central values of these ranges are adopted and multiplied by annual production data for this report.

Methane Recovery for Energy. Methane recovery for energy is restricted to a small sample of mines that typically meter their gas sales. Thus, total methane recovery can be estimated from the volume and heat content of sales.

Data Sources

Ventilation Systems in Underground Mines. Coal mine ventilation data for the approximately 200 gassiest U.S. mines were drawn from a database prepared by the Department of Interior's Bureau of Mines for the years 1980, 1985, 1988, 1990, and 1993. Ventilation data for 1994, 1996, and 1997 were obtained from the EPA, Atmospheric Pollution Prevention Division, Coalbed Methane Outreach Program. Coal production data are reported to the EIA on Form EIA-7A, "Coal Production Report." Basin-level emissions for nongassy mines in 1988 were calculated by the EPA's Office of Air and Radiation, in Anthropogenic Methane Emissions in the United States: Estimates for 1990 (Washington, DC, April 1993), pp. 3-19-3-24.

Degasification Systems in Underground Mines. Data on drainage from degasification systems from 1993 through 1996 are from the EPA's Office of Air and Radiation, Identifying Opportunities for Methane Recovery at U.S. Coal Mines, EPA 430-R-97-020 (Washington, DC, September 1997). Emissions factors for this source are derived from estimates of 1988 emissions from degasification systems prepared by the EPA's Office of Air and Radiation, in Anthropogenic Methane Emissions in the United States: Estimates for 1990 (Washington, DC, April 1993), pp. 3-19-3-24. Annual production figures are reported to the EIA on Form EIA-7A, "Coal Production Report."

Surface Mines. Emissions factors for surface mines are found in Intergovernmental Panel on Climate Change, Greenhouse Gas Inventory Reference Manual: Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Vol. 3 (Paris, France, 1997), web site www.iea.org/ ipcc/invs6.htm. Coal production data are reported to the EIA on Form EIA-7A, "Coal Production Report."

Post-Mining Emissions. Emissions factors for post-mining emissions are found in Intergovernmental Panel on Climate Change, Greenhouse Gas Inventory Reference Manual: Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Vol. 3 (Paris, France, 1997), web site www.iea.org/ipcc/invs6.htm. Coal production data are reported to the EIA on Form EIA-7A, "Coal Production Report."

Methane Recovery for Energy. Methane recovery estimates for 1990 from EPA's Office of Air and Radiation, in Anthropogenic Methane Emissions in the United States: Estimates for 1990 (Washington, DC, April 1993). Volumes of methane recovered during 1993 were obtained from U.S. Environmental Protection Agency, Office of Air and Radiation, Identifying Opportunities for Methane Recovery at U.S. Coal Mines: Draft Profiles of Selected Gassy Underground Coal Mines (Washington, DC, September 1994), p. 6-6. Recovery volumes for 1996 were obtained from the EPA's Office of Air and Radiation, Identifying Opportunities for Methane Recovery at U.S. Coal Mines, EPA 430-R-97-020 (Washington, DC, September 1997). Recovery estimates for intervening years were extrapolated.

Stationary Combustion

Emissions Sources

The principal products of fuel combustion are carbon dioxide and water vapor. When fuel combustion is incomplete, methane may also be released. The volume of methane released varies according to the efficiency and temperature of the combustion process. Most stationary sources are large, comparatively efficient boilers, such as those found in the industrial and utility sectors, and thus have low levels of methane emissions. However, a significant amount of wood is consumed in residential woodstoves and fireplaces, which are typically inefficient combustion chambers. Wood combustion in these devices produces most of the U.S. methane emissions from stationary sources.

Estimation Methods

An emissions factor based on fuel type (for example, coal, wood, natural gas) and combustion technology (for example, utility boiler, industrial boiler, woodstove) is applied to consumption data for each fuel and technology type.

Data Sources

Emissions coefficients for stationary fuel were obtained from the EPA's Office of Air Quality Planning and Standards, Compilation of Air Pollutant Emission Factors, AP-42, and Intergovernmental Panel on Climate Change, Greenhouse Gas Inventory Reference Manual: Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Vol. 3 (Paris, France, 1997), web site www.iea.org/ipcc/invs6.htm. Fuel consumption data were drawn from EIA's State Energy Data Report 1995, DOE/EIA-0214(95) (Washington, DC, September 1997) for 1980-1995; and Monthly Energy Review, DOE/EIA-0035(98/07) (Washington, DC, July 1998) for 1996-1997. Residential woodfuel consumption data were derived from EIA's Annual Energy Review 1997, DOE/EIA-0384(97) (Washington, DC, July 1998).

Mobile Combustion

Emissions Sources

Methane emissions from mobile combustion are, like those from stationary combustion, the result of incomplete fuel combustion. In automobiles, methane emissions result when oxygen levels in the combustion chamber drop below levels sufficient for complete combustion. The effects of incomplete combustion in automobiles may be moderated somewhat by post-combustion emissions controls, such as catalytic converters. Methane emissions are also generated by fuel combustion in other modes of transport, including aircraft, ships, and locomotives. There is, however, some evidence that jet airplane engines may consume ambient methane during flight, reducing their net emissions.

Estimation Methods

Methane emissions from highway vehicles, such as automobiles, light-duty trucks, motorcycles, buses, and heavy-duty trucks, are estimated by applying emissions factors (per vehicle mile traveled) to vehicle use data. The emissions factors vary by vehicle type. Because of improving technology and more stringent environmental regulations, they have declined over time. For nonhighway sources, emissions coefficients in terms of volume of fuel consumed are applied directly to consumption data without year-to-year modifications.

Data Sources

Emissions factors for all vehicles are provided in Intergovernmental Panel on Climate Change, Greenhouse Gas Inventory Reference Manual: Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Vol. 3 (Paris, France, 1997), pp. 1.65-1.75, web site www.iea.org/ ipcc/invs6.htm. The EIA collects data on miles traveled in personal transportation vehicles (cars and light-duty trucks) as part of its triennial Residential Transportation Energy Consumption Survey (RTECS): Energy Information Administration, Household Vehicles Energy Consumption 1994, DOE/EIA-0464(94) (Washington, DC, July 1996, and previous years). This survey contains data for the years 1983, 1985, 1988, 1991, and 1994. Emissions for intervening years were estimated by interpolating between the weighted average estimates of survey years. Vehicle miles traveled for nonhousehold vehicles (fleets, rental cars, etc.), motorcycles, buses, and heavy-duty trucks were obtained from the U.S. Department of Transportation, Federal Highway Administration, Highway Statistics 1996 (Washington, DC, 1997), web site www.fhwa.dot.gov/ohim/1996/index.html.

Data on fuel consumption for ships, locomotives, farm equipment, and construction equipment are available in EIA's Fuel Oil and Kerosene Sales 1997, DOE/EIA-0535(97) (Washington, DC, September 1998). Fuel consumption data for jet and piston-powered aircraft are contained in EIA's Petroleum Supply Annual 1997, DOE/EIA-0340(97/1) (Washington, DC, May 1998). Data on fuel consumption by recreational boats are taken from S.C. Davis and S.G. Strang, Transportation Energy Data Book, Edition 17, ORNL-6919 (Oak Ridge, TN: Oak Ridge National Laboratory, Center for Transportation Analysis, August 1997), web site www.cta. ornl.gov/cta/data/tedb17/tedb17.html.

Landfill Methane Emissions

Emissions Sources

After organic wastes (e.g., food, paper, yard waste) are placed in landfills, they begin to decompose. Aerobic bacteria, consuming oxygen, convert organic material to carbon dioxide, heat, and water. When available oxygen is depleted, anaerobic bacteria, including methanogens, begin digesting the waste and producing methane. Methanogenic anaerobes are highly sensitive to temperature, pH, and moisture levels. Because U.S. sanitary landfills are essentially closed systems designed to minimize entry and exit of moisture, conditions within a landfill are largely a product of the composition of the waste it contains. Thus, methane is likely to be produced at different rates and volumes both across different landfills and within a single landfill.

The biogas produced in a landfill is typically between 35 and 50 percent methane. At these levels, methane is highly explosive. Often, landfill operators put methane control systems in place to prevent migration of high concentrations to buildings. Methane captured by control systems may be vented to the atmosphere or flared, but it is also a potentially valuable energy resource. Where landfills produce steady, large volumes of methane and landfill gas-to-energy prices are competitive with other energy alternatives, recovered gas may be used as an energy resource. In most cases, the gas is converted to electricity and used for on-site energy needs or sold to local utilities. In some cases, the gas is transported via pipeline to a local end user.

Estimation Methods

Data on methane emissions from landfills are limited to those landfills with methane recovery systems in place. For more than 100 U.S. landfills with gas recovery systems in place, Thorneloe et al. measured or estimated methane emissions at 2.1 million metric tons for 1992.⁽¹²¹⁾ Methane emissions from landfills without gas recovery systems have not been measured, and even the number of landfills is subject to considerable uncertainty. Emissions from a given landfill are largely the product of the composition of the waste it contains and an array of site-specific factors. Waste composition data on a landfill-specific basis are nonexistent; however, national-level waste flow and waste composition data are available, and their reliability has improved over time. Thus, for this report, all waste not disposed of in a landfill with measured emissions is treated as if it has flowed to one very large national landfill.

To estimate methane emissions from all waste not disposed of in a landfill with measured emissions, waste volumes are subjected to a slightly modified version of the EMCON Methane Generation Model.⁽¹²²⁾ This model divides the waste into three categories: readily decomposable, moderately decomposable, and slowly decomposable, each with its own set of emissions characteristics. The EMCON model provides both a high methane yield scenario and a low methane yield scenario. For each category of decomposable waste, a time lag until methane generation begins is estimated, as well as a time constant during which the methane yield of the waste is realized. The methane yield represents the total amount of methane that a given amount of waste will produce over its lifetime. For example, under a low methane yield scenario, slowly decomposing waste will begin producing methane after a 5-year lag and will continue emitting over a 40-year period. Table A6 shows the EMCON methane generation model parameters.

Waste flows were estimated from 1940 through 1997. Waste in place in the Nation's landfills was assumed to represent the waste stream for all previous years plus the current year's additions. The landfills examined by Thorneloe et al. contained 9.2 percent of the waste estimated to be in place in the Nation's landfills during 1992. This report assumes that the share of waste in these landfills and the share in all other landfills remained constant over time. Thus, the EMCON model was applied to 90.8 percent of the waste generated each year.

To estimate emissions from those landfills with measured data for 1992 but no data for other years, the EMCON model was recalibrated to produce the 2.1 million metric tons of measured emissions in 1992. The recalibrated model, with methane yields almost twice as large as the original, was then applied to 9.2 percent of the waste stream for all years. These much higher yields are not unexpected, as gas recovery systems are most economically employed in high-emitting landfills.

Data Sources

Data on waste generated and landfilled for the period 1988 through 1997 (Table A7) were drawn from "Nationwide Survey: The State of Garbage in America," Biocycle (1988-1997). These data were not collected by Biocycle before 1988. Waste generated and landfilled for the period 1960 through 1987 was estimated from data produced by Franklin Associates. On behalf of the EPA's Office of Solid Waste and Emergency Response, Franklin Associates have estimated municipal solid waste (MSW) generated and landfilled for the years 1960 through 1996: Franklin Associates, Ltd., Characterization of Municipal Solid Waste in the United States, Worksheets, 1992 update, Prepared for the U.S. Environmental Protection Agency, Municipal Solid and Industrial Solid Waste Division (July 1992). See U.S. Environmental Protection Agency, Office of Solid Waste and Emergency Response, Characterization of Municipal Solid Waste in the United States: 1996 Update, EPA-530-S-96-001 (Washington DC, March 1997). In contrast to the Biocycle data, which include all waste going to landfills, including construction and demolition (C&D) waste and sludge, the Franklin data include only MSW going to landfills.

In order to account for categories of waste other than MSW going to landfills between 1960 and 1987, an average ratio of waste generation estimated by Biocycle and waste generation estimated by Franklin Associates for 1988 through 1997 was calculated. The annual average ratio during this period was 1.47 to 1. Thus, all Franklin estimates for 1960 through 1987 were multiplied by 1.47 to estimate overall waste generation and landfilling for those years. To further extend waste generation estimates back to 1940, a regression equation relating waste generation to GNP and population was developed.

Methane recovery data for 1992 were estimated from the measured recovery data provided by S.A. Thorneloe, M.R.J. Doorn, L.A. Stefanski, M.A. Barlaz, R.L. Peer, and D.L. Epperson, "Estimate of Methane Emissions from U.S. Landfills," prepared for U.S. Environmental Protection Agency, Office of Research and Development (April 1994). Methane recovery data for 1997 from Mike McGuigan, SCS Engineers, "GHG Emission Reductions from Landfill Gas Emissions," presented at the 21st Annual Landfill Gas Symposium (Austin, Texas, March 23-26, 1998). Recovery estimates for 1993 through 1996 were interpolated from the 1992 and 1997 data.

Domestic and Commercial Wastewater Treatment

Emissions Sources

Emissions of methane from the treatment of wastewater occur when liquid waste streams containing high concentrations of organic materials are treated anaerobically (in the absence of oxygen). Treatment processes used in the United States are anaerobic digestion, aerobic, and facultative (combining aerobic and anaerobic processes) stabilization lagoons, septic tanks, and cesspools.⁽¹²³⁾ Treatment of wastewater solids using anaerobic digestion is the most obvious potential source of methane emissions; however, emission of significant quantities of methane from this process requires that the digester gas be vented rather than recovered or flared. Anaerobic and facultative lagoons involve retention of wastewater in impoundments, where the organic materials in the wastewater undergo bacterial decomposition. The growth of algae, which absorb carbon dioxide and release oxygen as a result of photosynthesis, sustains aerobic conditions at least near the surface of the lagoon. Bacteria deplete oxygen at the bottom of the lagoon, producing conditions suitable for methanogenic bacteria. The extent of the resulting anaerobic zone and the associated methane generation depend on such factors as organic loadings and lagoon depth. In facultative lagoons, unlike anaerobic lagoons, a significant aerobic zone persists.

Nearly 75 percent of U.S. households are served by sewers that deliver domestic wastewater to central treatment plants. Septic tanks or cesspools treat domestic wastewater from most of the remaining households (24 percent).⁽¹²⁴⁾ Anaerobic digestion is frequently used to treat sludge solids at U.S. municipal wastewater treatment plants; however, anecdotal evidence suggests that neither recovery nor flaring of digester gas is common in the United States and that equipment for recovery and flaring of digester gas is poorly designed or maintained, allowing most of the methane produced to be released to the atmosphere.⁽¹²⁵⁾

Estimation Methods

Insufficient information is available to develop separate estimates of methane emissions from each of the sources discussed above. Information on the type of treatment used by the thousands of municipal and industrial treatment facilities is simply not available. For instance, no reliable statistics were found for the use of anaerobic digestion at municipal treatment facilities. Knowledge regarding the emissions of methane from lagoons, septic systems, and cesspools is limited. Another difficulty is the overlap between municipal and industrial treatment systems. Many industrial concerns discharge wastewater, which may or may not have been treated, into municipal systems. Therefore, it is necessary to base the current estimate of methane emissions from wastewater treatment on the highly simplified approach recommended by the IPCC,⁽¹²⁶⁾ which assumes that each person in a developed nation contributes 0.05 kilogram of BOD₅ to domestic wastewater annually, and 15 percent of this wastewater is treated anaerobically, yielding 0.22 kilogram of methane per kilogram of BOD₅ in the wastewater.⁽¹²⁷⁾ It is assumed that recovery of methane at municipal wastewater treatment facilities is negligible.

Data Source

Estimate of the U.S. resident population on July 1 of each year were obtained from the U.S. Census Bureau.

Agricultural Sources

Enteric Fermentation in Domesticated Animals

Emissions Sources

The breakdown of carbohydrates in the digestive track of herbivores (including insects and humans) results in the production of methane.⁽¹²⁸⁾ The volume of methane produced from this process (enteric fermentation) is largest in those animals that possess a rumen, or forestomach, such as cattle, sheep, and goats. The forestomach allows these animals to digest large quantities of cellulose found in plant material. This digestion is accomplished by microorganisms in the rumen, some of which are methanogenic bacteria. These bacteria produce methane while removing hydrogen from the rumen. The majority (about 90 percent) of the methane produced by the methanogenic bacteria is released through normal animal respiration and eructation. The remainder is released as flatus.

Estimation Methods

The level of methane emissions from enteric fermentation in domesticated animals is a function of several variables, including quantity and quality of feed intake, the growth rate of the animals, their productivity (reproduction and/or lactation), and their mobility. To estimate emissions from enteric fermentation, the animals are divided into distinct, relatively homogeneous groups. For a representative animal in each group, feed intake, growth rate, activity levels, and productivity are estimated. An emissions factor per animal is developed from these variables. The factor is then multiplied by population data for the animal group to calculate an overall emissions estimate. The method for developing these factors differs somewhat for cattle as opposed to all other animals.

Cattle. Because emissions from cattle represent about 95 percent of U.S. emissions from enteric fermentation, they are given particular scrutiny. The U.S. cattle population is separated into dairy and beef cattle. Dairy cattle are then divided into replacement heifers 0-12 months old, replacement heifers 12-24 months old, and mature cows. Dairy cattle are further subdivided into regional populations in an effort to capture variations in diet and feed quality. Beef cattle are divided into six classes: replacements 0-12 months old, replacements 12-24 months old, mature cows, bulls, steers and heifers raised for slaughter under the weanling system, and steers and heifers raised for slaughter under the yearling system. These populations are then multiplied by emissions factors developed for each category of cattle based on their energy intake requirements.⁽¹²⁹⁾

Because characteristics critical in determining energy intake, and thus emissions rates, for cattle--such as growth rates and milk production--change annually, an effort is made to scale emissions factors to these changes. For dairy cattle, emission factors are scaled to average milk production per cow on a regional basis. For beef cattle, emissions rates are pegged to average slaughter weights for calves and adult cattle respectively (Table A8).

Other Animals. For sheep, pigs, goats, and horses, populations are not disaggregated below the species level. Emissions factors for each animal group are multiplied by their respective populations. Emissions factors are drawn from the work of Crutzen et al.⁽¹³⁰⁾

Data Sources

Population and slaughter weight data for cattle and population data for sheep and swine were obtained from the U.S. Department of Agriculture, National Agricultural Statistics Service, Livestock, Dairy, and Poultry Branch, web site www.mannlib.cornell.edu. Population data for goats and horses were extrapolated from U.S. Department of Commerce, Economics and Statistics Administration, Bureau of the Census, Census of Agriculture, United States Summary and State Data, Vol. 1, "Geographic Area Series," Part 51 (Washington, DC, 1982, 1987, and 1992).

Solid Waste of Domesticated Animals

Emission Sources

When the solid waste of animals is allowed to decompose under anaerobic conditions, methane is produced. The volume of methane produced varies according to the amount of organic material susceptible to decomposition within the waste (volatile solids) and the manner in which the waste is managed. Liquid-based waste management systems, in addition to providing a suitable anaerobic environment, provide the moisture necessary for methanogenic bacterial cell production and acid stabilization.⁽¹³¹⁾ Thus, they result in the most substantial methane emissions.

Estimation Methods

Methane emissions from the solid waste of domesticated animals are estimated by linking emissions to the volume of solid waste produced by a given animal, the volatile solids in that waste, and the manner in which the waste is managed. The volume of waste produced is controlled by the animal's size, diet, and energy requirements. Typical animal sizes for beef cattle, swine, poultry, goats, sheep, and horses are drawn from a 1990 inventory of livestock emissions prepared by the EPA.⁽¹³²⁾ Animal sizes for beef cattle are adjusted annually on the basis of live slaughter weights as reported by the U.S. Department of Agriculture. Volatile solids produced per kilogram of animal weight, maximum methane-producing capacity of each animal's waste, and the share of waste managed in each management system are adopted from the work of Safley et al.⁽¹³³⁾ For all animals except dairy cattle, the share of waste managed in each management system is also drawn from Safley et al.

Methane conversion factors for dairy cattle are adopted on a State-by-State basis and are calculated from a weighted average of each State's manure management technique. Dairy cattle size and volatile solid production are drawn from the EPA.⁽¹³⁴⁾ Resulting emissions factors are applied to State population data acquired from the U.S. Department of Agriculture, National Agricultural Statistics Service, Livestock, Dairy and Poultry Branch.

Data Sources

Population and slaughter weight data for cattle, and population data for sheep, poultry, and swine were obtained from the U.S. Department of Agriculture (USDA), National Agricultural Statistics Service, Livestock, Dairy, and Poultry Branch, web site www. mannlib.cornell.edu. Average broiler chicken populations for each year were estimated by multiplying the estimated number of broiler chickens slaughtered annually by 0.1425, based on their 7-week life cycle as recommended by the USDA's Economic Research Service.⁽¹³⁵⁾ Population data for goats and horses were extrapolated from U.S. Department of Commerce, Economics and Statistics Administration, Bureau of the Census, Census of Agriculture, United States Summary and State Data, Vol. 1, "Geographic Area Series," Part 51 (Washington, DC, 1982, 1987, and 1992).

Rice Cultivation

Emissions Sources

Methane is produced when organic material in flooded rice fields decomposes in the absence of oxygen (anaerobically). Between 60 and 90 percent of the methane generated is oxidized by bacteria in the soil, while an additional portion leaches into the groundwater. The majority of the methane that remains is transported through rice plants and is transpired into the atmosphere. A smaller amount of methane reaches the atmosphere by bubbling from the soil and by diffusing through the water column.

Estimation Methods

A range of daily emissions rates has been developed from studies of rice fields in California,⁽¹³⁶⁾ Louisiana,⁽¹³⁷⁾ and Texas.⁽¹³⁸⁾ The high and low ends of the range, 0.1065 and 0.5639 grams of methane per square meter of land cultivated, are applied to the growing season length and the harvested area for each State that produces rice. In States with a second ("ratoon") crop, the additional area harvested is incorporated into the estimates.

Data Source

Rice area harvested and length of growing season data were obtained from the USDA, National Agricultural Statistics Service, Crop Production (annual reports).

Burning of Crop Residues

Emissions Sources

Between 40 and 50 percent of dry matter in crop residue is carbon.⁽¹³⁹⁾ When crop residues are burned for fodder, land supplementation, or fuel, incomplete combustion produces methane emissions.

Estimation Methods

As reported by the EPA,⁽¹⁴⁰⁾ this report assumes that 3 percent of all crop residues are burned, with the exception of rice grown in California.⁽¹⁴¹⁾ The share of rice crop residues in California estimated to be combusted declines in straight-line fashion from 99 percent in 1990 to 50 percent in 1996. The 50 percent estimate is held constant for 1997. These estimates of crop residues burned are in contrast to earlier estimates of 10 percent for all crops, adopted from default values provided by the IPCC. To derive methane emissions, the dry weight and carbon content of each crop were determined and then multiplied by estimated combustion efficiencies (Table A9).

Data Sources

Crop harvest sizes were obtained from U.S. Department of Agriculture, National Agricultural Statistics Service, Crop Production (Annual Reports); and U.S. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-1996, Review Draft (Washington, DC, March 1998), web site www.epa.gov/ globalwarming/inventory/1998-inv.html.

Industrial Processes

Chemical Production

Emissions Sources

A wide variety of organic compounds (those containing carbon) are used as feedstocks in chemical production. High temperatures are often used to "crack" the molecular bonds of the compounds, with different temperatures producing specific chemicals. The process of cracking produces a number of chemical byproducts, including methane.

Estimation Methods

The IPCC has published emissions factors for methane emitted during the manufacture of ethylene, ethylene dichloride, styrene, methanol, and carbon black (Table A10). Production figures for the chemicals are multiplied by those emissions factors.

Data Source

Chemical production figures were obtained from the Chemical Manufacturers Association, U.S. Chemical Industry Statistical Handbook (Washington, DC, various years).

Iron and Steel Production

Emissions Sources

Coke, sinter, and pig iron are the principal material inputs for the production of iron and steel. Coke is produced by heating coal in the absence of oxygen. One of the gaseous byproducts of this process is methane. During the next step in the production process, coke, iron ore, and flux materials are combined to form sinter. The coke is burned to create heat, causing the sinter to agglomerate. During agglomeration, methane is released. Coke and iron are then added to flux materials in a blast furnace and reduced to iron, slag, and exhaust gases. Methane is one of the exhaust gases.

Estimation Methods

The IPCC has published emissions factors for methane emitted during the production of coke, sinter, and pig iron.⁽¹⁴²⁾ Production figures for iron and steel inputs are multiplied by those emissions factors.

Data Source

Coke, sinter, and pig iron production data are published annually by the American Iron and Steel Institute in its Annual Statistical Report (Washington, DC, various years).

Nitrous Oxide

Most anthropogenic nitrous oxide emissions in the United States can be attributed to energy and agricultural sources. In particular, motor vehicle fuel combustion accounts for approximately 55 percent of 1997 estimated emissions of nitrous oxide. Another 33 percent of emissions are attributable to nitrogen fertilizer use and animal manure management. It should be noted that the range of uncertainty associated with emissions from mobile combustion and fertilizer use is quite large. Emissions estimates in this report include: mobile source combustion from passenger cars, buses, motorcycles, trucks, and other minor sources; stationary source combustion from the commercial, residential, industrial, and electrical utility sectors; fertilizer application; burning of crop residues; livestock manure management; human sewage; waste combustion; and industrial production of adipic acid and nitric acid.

Energy Use

Mobile Combustion

Emissions Sources

Nitrous oxide emissions are produced as a byproduct of fuel combustion. During combustion, nitrous oxide (N₂O) is produced as a result of chemical interactions between nitrogen oxides (NO, NO₂ and NO₃)and other combustion products. Since nitrous oxide decomposes at high temperatures, most stationary combustion systems (such as electric power generation) emit little nitrous oxide. However, under some conditions, the catalytic converters fitted as pollution control devices on most U.S. vehicles will convert nitrogen oxides into nitrous oxide. The relevant conditions appear to be when the catalytic converter is just warming up, but before it reaches normal operating temperature, if the catalytic converter is not working properly, or if the catalyst is affected by excessive levels of sulfur in the gasoline.

Estimation Methods

In general, EIA estimates of nitrous oxide emissions for road vehicles are based on multiplying an emissions factor (grams of nitrous oxide per mile driven) by national-level vehicle miles traveled. Research indicates that emissions rates differ by vehicle type and by type of catalytic converter (associated with the vintage of the motor vehicle). Consequently, the EIA partitions national-level vehicle miles traveled by vehicle type (car, light-duty truck, bus, motorcycle, heavy-duty truck), and then again by motor vehicle vintage (model year).

For non-highway sources, an emissions factor in grams of nitrous oxide per unit of fuel consumed is applied to fuel consumption data. Since off-road vehicles rarely have catalytic converters (and vintage data scarce) no attempt is made to track vehicle vintages for the non-highway sources.

Data Sources

Emissions factors for motor vehicle nitrous oxide have been the subject of considerable discussion and new research over the past year. Last summer, the IPCC released its Greenhouse Gas Inventory Reference Manual: Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (Paris, France, 1997). This document included revised nitrous oxide emissions factors for motor vehicles that were four times higher those used in the previous reference manual and in the previous edition of this report. However, the EPA's Office of Mobile Sources, stimulated by the IPCC report, undertook an automotive testing program in the summer of 1998. The Office of Mobile Sources results were published in U.S. Environmental Protection Agency, Emissions of Nitrous Oxide from Highway Mobile Sources, EPA-420-R-98-009 (Washington, DC, August 1998), and have been used in this report. These emissions factors are considerably lower than the emissions factors in the IPCC report but somewhat higher than emissions factors used in last year's EIA report and higher than the emissions factors suggested by the IPCC for use with European vehicles.

The EIA collects data on miles traveled in personal transportation vehicles (cars and light-duty trucks) as part of its triennial Residential Transportation Energy Consumption Survey (RTECS)--Energy Information Administration, Household Vehicles Energy Consumption 1994, DOE/EIA-0464(94) (Washington, DC, July 1996, and previous years). This survey contains data for the years 1983, 1985, 1988, 1991, and 1994. Emissions for intervening years were estimated by interpolating between the weighted average estimates of survey years. Vehicle miles traveled for non-household vehicles (fleets, rental cars, etc.), motorcycles, buses, and heavy-duty trucks were obtained from the U.S. Department of Transportation, Federal Highway Administration, Highway Statistics 1996 (Washington, DC, 1997), web site www.fhwa.dot.gov/ohim/1996/index.html.

Data on fuel consumption for ships, locomotives, farm equipment, and construction equipment are available in EIA's Fuel Oil and Kerosene Sales 1997, DOE/EIA-0535(97) (Washington, DC, September 1998). Fuel consumption data for jet and piston-powered aircraft are contained in EIA's Petroleum Supply Annual 1997, DOE/EIA-0340(97)/1 (Washington, DC, May 1998). Data on fuel consumption by recreational boats are taken from S.C. Davis and S.G. Strang, Transportation Energy Data Book, Edition 17, ORNL-6919 (Oak Ridge, TN: Oak Ridge National Laboratory, August 1997), web site www.cta.ornl.gov/cta/data/tedb17/tedb17.html.

Stationary Combustion

Emissions Sources

As with mobile sources, nitrous oxide emissions are produced as a byproduct of fuel combustion. The three fuels of primary importance burned by stationary sources are coal, fuel oil, and natural gas. Combustion systems powered by coal produce the most nitrous oxide, approximately 76 percent of annual emissions. As a sector, electric utilities consistently account for more than one-half of total emissions. Other important sources are commercial facilities, industrial facilities, and residences.

Estimation Methods

Nitrous oxide emissions from stationary combustion are estimated by multiplying fuel consumption figures for each fuel type and stationary source by emissions factors for each type of fuel. The emissions factors used in this report differ from those used in previous years; therefore, emissions estimates may also be different from those presented in last year's report. Emissions are estimated by applying emissions factors for coal, oil, and natural gas to EIA's consumption data for each fuel in the commercial, residential, industrial, and electric utility sectors.

Data Sources

Fuel consumption data are from the EIA's State Energy Data Report (EIA-0214) database. The emissions factors used in this report are those recommended by the IPCC as derived from studies of numerous conventional systems: G.G. De Soete, "Nitrous Oxide From Combustion and Industry: Chemistry, Emissions and Control," in A.R. van Amstel (ed.), International IPCC Workshop Proceedings: Methane and Nitrous Oxide, Methods in National Emissions Inventories and Options for Control (Bilthoven, Netherlands: RIVM, 1993), pp. 287-337.

Agriculture

Nitrogen Fertilization of Agricultural Soils

Emissions Sources

Nitrous oxide is a waste product of certain classes of bacteria normally present in soil. When nitrogen (in the form of natural or artificial fertilizers) is added to natural or agricultural soils, the action of these bacteria is stimulated. However, the extent to which adding nitrogen stimulates nitrous oxide emissions is highly uncertain. The bacteria that emit nitrous oxide have natural competitors, which may be more or less successful in particular settings. In addition, conditions may be more or less propitious for bacterial action: the soil may be too moist or too dry, too compacted, too acid or alkaline, too warm or too cold. The form in which nitrogen is applied may be subject to faster or slower release to the waiting bacteria. Further, excess nitrogen will escape from the location of application through runoff and will be subject to decomposition in diverse natural environments. Thus, measured emissions from even large numbers of specific sites are exceptionally difficult to generalize into an estimate of national emissions.

The most recent estimation methods of the IPCC have been revised to take a more comprehensive view of nitrous oxide emissions from this source. It broadens consideration of the sources of nitrogen applied to soils and considers nitrous oxide emissions downstream from the site of emissions.

Estimation Methods

Following the most recent IPCC Reference Manual, this report estimates nitrogen applications to soils from three sources:

Use of nitrogen fertilizers (computed directly from fertilizer data)

Nitrogen in animal manure applied to agricultural soils (estimated from animal populations)

Nitrogen in crop residues applied to agricultural soils (estimated from crop production statistics).

Only the first source (nitrogen fertilizers) was covered last year. Following the IPCC, we assume that 1.25 percent of the nitrogen applied is emitted to the atmosphere as nitrous oxide, while 30 percent of the nitrogen is assumed to escape into the environment. Some 2.5 percent of the nitrogen that escapes is ultimately converted into nitrous oxide in the form of emissions from streams and bodies of water. A further 10 percent of the nitrogen applied to soils is assumed to be released as gas in the form of nitrogen oxides and ammonia, and 1 percent of that nitrogen is assumed to be ultimately converted into nitrous oxide.⁽¹⁴³⁾

Data Sources

Estimates of total U.S. fertilizer consumption were obtained from reports by the Tennessee Valley Authority Fertilizer Research Center for various years through 1994--J.T. Berry et al., Commercial Fertilizers (Muscle Shoals, AL: Tennessee Valley Authority, Fertilizer Research Center, Reports for 1986-1991 and 1993-1994)-- and The Fertilizer Institute for 1995 through 1997. For nitrogen in animal manure, see the section on "Solid Waste of Domesticated Animals." For nitrogen in crop residues, see the section on "Crop Residue Burning" under methane or nitrous oxide.

Crop Residue Burning

Emissions Sources

Crop residues are commonly disposed of by incorporation into the soil, spreading over the soil surface to prevent erosion, as animal bedding, or through burning. Burning crop residues releases nitrous oxide into the atmosphere. The burning of crop residues occurs throughout the United States, although it is illegal in certain areas. There are no accurate estimates of the amount of crop residue burned in the United States.

Estimation Methods

As reported by the EPA, this report assumes that 3 percent of all crop residues are burned, with the exception of rice grown in California.⁽¹⁴⁴⁾ The share of rice crop residues in California estimated to be combusted declines in straight-line fashion from 99 percent in 1990 to 50 percent in 1996. The 50 percent estimate is held constant for 1997. These estimates of crop residues burned are in contrast to earlier estimates of 10 percent for all crops, adopted from default values provided by the IPCC. The amount of crop residue burned is discounted by an assumed combustion efficiency, multiplied by its dry matter content and nitrogen content, and then converted to nitrous oxide using a standard ratio of nitrous oxide to nitrogen content.

Data Sources

Solid Waste of Domesticated Animals

Emissions Sources

Nitrous oxide is emitted as part of the denitrification of animal manure. The volume of nitrous oxide emissions is a function of the amount of manure produced, the nitrogen content of the manure, and the method for handling the animal waste. Waste managed by a solid storage or pasture range method may emit 20 times the nitrous oxide per unit of nitrogen content that is emitted from anaerobic lagoon or other liquid systems.

Estimation Methods

Nitrous oxide emissions from the solid waste of domesticated animals are estimated by linking emissions to the volume of solid waste produced by a given animal, the volatile solids in that waste, the nitrogen content of the waste, and the manner in which the waste is managed. Animal populations are divided into distinct, relatively homogeneous groups. The U.S. cattle population is separated into dairy and beef cattle. Emissions of nitrous oxide from poultry, sheep, pigs, goats, and horses are also estimated. For each group of animals, a per-head volatile solids production and an associated nitrogen content within the volatile solids are assigned. These values are multiplied by animal populations to derive total nitrogen excreted. For each animal group, excretions are distributed among the manure management systems used. The ratio of nitrous oxide production to nitrogen content for each management technique is applied to provide an emissions estimate for each animal group, broken down by manure management system. The emissions are then summed to calculate an overall emissions estimate.

Data Sources

Population and slaughter weight data for cattle and population data for sheep, poultry, and swine were obtained from the U.S. Department of Agriculture (USDA), National Agricultural Statistics Service, Livestock, Dairy, and Poultry Branch, web site www. mannlib.cornell.edu. Average broiler chicken populations for each year were estimated by multiplying the estimated number of broiler chickens slaughtered annually by 0.1425, based on their 7-week life cycle as recommended by the USDA's Economic Research Service.⁽¹⁴⁵⁾ Population data for goats and horses were extrapolated from U.S. Department of Commerce, Economics and Statistics Administration, Bureau of the Census, Census of Agriculture, United States Summary and State Data, Vol. 1, "Geographic Area Series," Part 51 (Washington, DC, 1982, 1987, and 1992). Volatile solids content, nitrogen content of wastes by species, manure management systems, and nitrogen to nitrous oxide conversion rates were taken from Intergovernmental Panel on Climate Change, Greenhouse Gas Inventory Reference Manual: Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories, Vol. 3 (Paris, France, 1997), pp. 4.88-4.93, web site www.iea.org/ipcc/ invs6.htm.

Waste Management

Waste Combustion

Emissions Sources