| Overview | Carbon Dioxide | Methane | Nitrous Oxide | Criteria Pollutants | Land Use Issues |
Emissions estimates in this report are generated largely by multiplying some activity factor, such as coal or natural gas
consumption, by an emissions coefficient. The reliability of both the activity data and the emissions coefficients used
in this report varies widely. This appendix discusses the uncertainties associated with the estimates and extrapolations
presented in the report.
The uncertainties in emissions estimates come from collecting data from a limited number of sources. The data are
weighted or extrapolated to obtain national estimates for similar sources in each category or industry. This estimation
approach is a method to scale up the average emissions from a source, determined by a limited sample, to represent
the population of emissions from each category or fuel. This method uses the concepts of emissions coefficient and
activity factor for each category. For each category or fuel type:
Since each factor contains both bias and sampling errors, the estimate of the national emissions for a category is:
where EC is the emissions coefficient and AF is the activity factor. Bias is a systematic, nonrandom error which, in this
case, is usually imbedded in the AF term and results from systematic imperfections in the data collection process. The
random sampling error is generally attributed to small sample size, measurement and reporting errors, and timing
problems.
In general, estimates of carbon dioxide emissions are more reliable than estimates for other gases. Although this report
does not explicitly calculate uncertainty ranges, it is likely that the estimate of carbon dioxide emissions is accurate to
within 10 percent, suggesting an emissions range from 4.9 billion to 6.0 billion metric tons. To the extent that the
activity factor is somewhat understated within the point estimate, the actual (unobservable) value is likely to be
somewhat higher, because this report cannot capture all emissions sources.
Estimates of methane emissions are much more uncertain. The level of precision is probably on the order of 30 to 50
percent. Estimates of methane emissions are also likely to understate actual emissions, as a result of the exclusion of
sources that are unknown or difficult to quantify.
Nitrous oxide emissions estimates are by far the most unreliable. Estimates of emissions from nitrogenous fertilizers
are accurate only to an order of magnitude, making them either the largest source of nitrous oxide emissions or,
alternatively, an insignificant source. Coefficients for nitrous oxide emissions from fossil fuel combustion are not
available for all sources and, where available, may be unreliable. Additionally, several known sources of nitrous oxide
are not measured and therefore are excluded from estimated totals.
Most carbon dioxide emissions estimated in this report result from the combustion of fossil fuels. The uncertainties in estimates of emissions from fossil fuel combustion can be divided into four types:
In general, energy statistics produced by the Energy Information Administration (EIA) are most accurate for energy
industries that are highly concentrated and/or heavily regulated and least accurate for activities that are decentralized,
with large numbers of producers or consumers, and for fuels that have many heterogeneous states.
It is impossible to be certain about the absolute magnitude and distribution of errors in the energy data, but it is likely
that most are "bias errors" rather than random "sampling errors." The EIA collects the same data from nearly the same
respondents every year (although survey frames are systematically updated), using nearly the same methods. Product
flows that escape the coverage of the statistical system are likely to stay outside the statistical system from one year
to the next. Similarly, if respondents make undetected definitional or computational errors (for example, misclassifying
a petroleum product), they are likely to repeat their mistakes for prolonged periods.
There is indirect evidence in favor of the relative unimportance of random error in energy statistics, in the form of the
relative lack of variability of the statistics compared with other economic time series. That most EIA surveys are
censuses, with what is intended to be 100-percent coverage of eligible respondents, rather than small sample surveys,
reduces the scope for random errors.
If, as is suspected, random error is relatively unimportant, then most of the error is bias error, made in essentially the
same way every year. Therefore, while the level of U.S. emissions of carbon dioxide could be
systematically lower or higher than reported here, the reported trends over time are more likely to be reliable than the
uncertainties in the energy data would suggest. Since energy production and consumption are covered by multiple
surveys, it is possible to use this information to gain insight into the possible uncertainties in the energy data.
Coal. Coal production and consumption data are based on weight--short tons of coal. Coal consumption by regulated
electric utilities, including both tonnage and energy content, is universally reported to the EIA and the Federal Energy
Regulatory Commission (FERC). In 1996, utility coal consumption accounted for about 89 percent of U.S. coal
consumption.(205) There are likely to be only minor errors (around 1 percent) in reported utility coal consumption.
Industrial, residential, and commercial coal consumption estimates are subject to potentially larger errors, especially
in the counting of residential and commercial sector consumption.
The statistical discrepancy for coal production (the difference between reported consumption and reported production
less exports, plus imports, plus stock changes) averaged less than 8 million metric tons, or less than 1 percent of
consumption, in the period 1991-1996.(206)
Natural Gas. Most natural gas is sold or transported by State-regulated local distribution companies. Excluding
imports, the statistical discrepancy for natural gas has an average value of between 2 and 3 percent of consumption,
with reported consumption usually smaller than reported production. This may imply some systematic source of
underreporting of consumption.
Inaccuracies in natural gas volumetric data come from inherent limitations in the accuracy of natural gas metering, as
well as from the usual problems of misreporting and timing differences. For example, natural gas consumption by
electric utilities, as reported by the utilities, averaged about a 10-percent difference from natural gas consumption as
reported by natural gas sellers in 1995.(207)
Petroleum. U.S. petroleum consumption is estimated on the basis of "petroleum products supplied," which means the
volume of petroleum products shipped from primary storage facilities. Since there are only about 200 oil refineries in
the United States, coverage of crude oil inputs and refinery outputs is generally complete.
The EIA requires a detailed breakdown and accounting of petroleum products produced by refineries, including refinery fuel. There are several reporting anomalies in EIA petroleum data:
By definition, the source of "unaccounted for" crude oil is unknown. It is likely due to imprecisions in recorded crude
oil production, import, and stock change data. In EIA's State Energy Data Report, which presents consumption estimates,
unaccounted for crude oil is included in consumption.
The unfinished oil discrepancy is probably the result of asymmetric treatment of inter-refiner sales of unfinished oils.
To the buyer, who knows the intended use of the product, it is motor gasoline or distillate fuel. To the seller, it is an
unfinished oil. In the State Energy Data Report, the unfinished oil discrepancy is accounted for through an adjustment
to "other oils." The implication is that total oil consumption figures are more reliable than the exact distribution of
consumption across specific petroleum products. Overall, it is likely that petroleum consumption estimates are accurate
to within 5 percent.
Nonfuel Use. Data for nonfuel use of petroleum products are more uncertain than those for total use of petroleum products. There are two main methods of estimating nonfuel use:
The main uncertainty in estimating carbon sequestered from nonfuel use is not the amount of product used, but the
fate of its carbon. The sequestration percentages used in this report are estimates, originally based on the typical fate
of a particular class of products. The actual distribution of nonfuel uses of products is not always known with precision
and could vary considerably from the "typical" usage; however, because sequestration through nonfuel use corresponds
to only about 5 percent of total emissions, even large variations in the amount sequestered would have a small effect
on estimated total emissions.
EIA oil and gas data are collected in volumetric units-- barrels of oil and billion cubic feet of gas. Carbon emissions
factors for fossil fuels usually take the form of tons of carbon per unit of energy content. Emissions factors are
computed by dividing the carbon content (by weight) of a particular fuel by its energy content. Thus, in order to match
an emissions factor to a fuel accurately, it is necessary to know its energy content with precision; and in the case of fuel
quantity based on volumetric data, it is also necessary to know the density of the fuel.
Each step that transforms the data from native units into more useful units inevitably reduces the precision of the
resulting data, because the conversion factors are themselves statistical estimates or extrapolations, which may not
precisely match the actual composition of the fuel.
Coal. Coal data are collected by State, coal rank, and weight (short tons). Electric utilities are asked to report both the
rank and the energy content of the coal they burn. Since, in principle, utilities need to know the energy content of the
fuels they purchase with precision, the energy content data should be fairly accurate. On the other hand, there is
considerably more uncertainty in the rank or energy content of coal distributed outside the utility sector, which
in 1996 accounted for about 11 percent of U.S. coal consumption.
The quality of coal can vary considerably within States and within a particular rank. Lignite, for example, is defined
as containing 6,300 to 8,300 British thermal units (Btu) per pound, a range of about 15 percent. Subbituminous coal,
by definition, has a range of 8,300 to 11,500 Btu per pound.(211) Thus, there may be errors of up to 15 percent in the
industrial and residential/commercial coal conversion factors. On the other hand, residential/commercial and
industrial coal consumption accounts for only about 5 percent of total U.S. energy-related carbon emissions, and even
large errors would have only a small impact on the ultimate estimates.
Natural Gas. The composition of natural gas also varies considerably. In a recent survey of several thousand gas
samples taken from local distribution companies around the United States, the Btu content ranged from 970 to 1,208
Btu per thousand cubic feet.(212) However, 80 percent of the samples fell within a much narrower range of 1,006 to 1,048
Btu per thousand cubic feet. Further, the average and median values of the samples fell within 0.3 percent of the
national-level figure reported in EIA's Natural Gas Annual. This comparison suggests that EIA data on the energy
content of natural gas are accurate to within 0.5 percent. This is not surprising, because local distribution companies
monitor the energy content of natural gas to ensure adherence to contractual specifications, and they report the average
energy content to the EIA.
Petroleum. The energy content of petroleum products varies more by volume than by weight. The density and the
energy content of petroleum products are rarely measured by producers or consumers, and frequently they are not
known with precision. Electric utilities measure the energy content of the residual oil they burn and report it to the EIA.
Liquid petroleum gases (propane, butane, and ethane) are pure compounds, and their energy content can be computed
directly.
Liquid transportation fuels (jet kerosene, gasoline, and diesel fuel) are complex mixtures of many compounds, whose physical properties can vary considerably.
Neither their density nor their energy content is measured by consumers or directly defined by product specifications.
The EIA estimates the energy content of these fuels on the basis of standard or "typical" values for each product. The
standard energy contents for motor gasoline and kerosene-based jet fuel are drawn from a 1968 report produced by
the Texas Eastern Transmission Corporation.(213) The energy content of distillate fuel oil is drawn from a Bureau of
Mines Standard adopted in January 1950.(214) Jet fuel and diesel samples obtained for this report showed an average
energy content that differs from EIA estimates by about 2 percent. Samples of motor gasoline analyzed by the National
Institute of Petroleum and Energy Research displayed an average energy content that differs from EIA estimates by
less than 0.5 percent. Reformulated gasoline, with the additives MTBE, ETBE, and TAME typically representing about
10 percent of its volume, can be expected to have an energy content about 1 percent lower than the energy content of
standard gasoline. However, when collecting and disseminating motor gasoline data in units of energy, the EIA does
not use a distinct conversion factor for reformulated gasoline.
Carbon emissions coefficients are calculated by dividing the carbon content of a particular fuel (for example, 0.85
metric tons of carbon per metric ton of fuel) by the energy content of that fuel (say, 43 million Btu per metric ton) to
produce an emissions coefficient (in this example, 19.8 million metric tons of carbon per quadrillion Btu). Both the
energy content and the carbon content of the fuel are subject to a degree of uncertainty. The carbon content of fuels
has only an indirect and general bearing on their economic value and, consequently, is not necessarily collected by fuel
producers or consumers. While coefficients for coal and natural gas rely on analyses of a large set of fuel samples,
coefficients for several petroleum products are based on "typical" or "representative" values, which may or may not
perfectly reflect the underlying composition of the fuel. Variation in carbon content is limited to plus or minus 5 percent
by the standard ratios of carbon to hydrogen in the hydrocarbon compounds that compose petroleum.(215)
Coal. There are large variations in the carbon and energy content of coals in different parts of the United States. Lignite
may have as little as 12.6 million Btu per ton and contain 36 percent carbon, while anthracite may have as much as 98
percent carbon and an energy content as high as 27 million Btu per ton.(216)
The carbon and heating values of coal are, in general, controlled by two factors:
Most of the gross variation in both energy and carbon content (for example, between lignite and anthracite) is due to
variations in nonflammable impurities. Consequently, if the Btu content of coal is estimated accurately, most of the
variation in the carbon content is removed.
There is, however, residual uncertainty about the ratio of carbon to hydrogen and sulfur in particular coals. The carbon
content of any particular coal sample can be determined by chemical analysis, but characterizing the average carbon
content of national coal production creates some uncertainty. For this report, the EIA relied on chemical analyses of
several thousand coal samples, sorted by State of origin and coal rank, to compute national weighted average emissions
coefficients (in million metric tons of carbon per quadrillion Btu) for each coal rank.
Natural Gas. Natural gas also varies in composition, but the range of variation is much smaller than that for coal. The
emissions coefficient used in this report was based on an analysis of some 6,743 recent samples of U.S. natural gas.
While there is some residual uncertainty about the exact carbon content of average U.S. natural gas, it is on the order
of 1 percent or less.
Petroleum Products. Crude oil is refined into a wide range of petroleum products, each presenting a different set of
uncertainties. In general, the carbon content of petroleum products increases with increasing density. Uncertainties
in emissions coefficients arise primarily from estimating the wrong density for a fuel or from mismatching the carbon
and energy content of a particular fuel. The emissions factors for liquefied petroleum gas (LPG) and motor gasoline
are probably accurate to within 1 to 2 percent. Coefficients for jet fuel and diesel fuel are probably accurate to within
2 to 4 percent, with much of the uncertainty centered in the standard heat contents used. The estimate for residual fuel is
more uncertain but is probably accurate within 3 to 5 percent, as there are remaining uncertainties about the exact
density and carbon content of the fuel.
The uncertainty for some minor petroleum products remains large, in some cases because it has proven difficult to
identify exactly how reporters define particular product categories. Products with large remaining uncertainties include
petrochemical feedstocks (density and portion of aromatics), lubricants, and waxes and polishes. The uncertainty of
the emissions coefficients for these products is probably on the order of 10 percent. Because these products share a
large nonfuel use component, their impact on the total carbon emissions figure is muted. Still gas is a highly variable
byproduct of the refining process, which is then described as a petroleum product. Thus, the estimated emissions
coefficient for still gas may vary by as much as 40 percent.
U.S. Territories. Energy data for U.S. territories present certain problems. Published petroleum data for Puerto Rico
and the Virgin Islands are considerably less detailed than those for the mainland United States. In particular, there is
no estimate of nonfuel use for these territories, and much of the petroleum consumption that could potentially be
considered nonfuel use is lumped together into "other petroleum." Hence, the reliability of the emissions estimates is
lower than that of petroleum emissions estimates generally.
Flare Gas. Estimates of emissions from flare gas are subject to uncertainty from two sources: estimates of the volume
of gas flared, and the application of an appropriate emissions coefficient. Estimates of gas flared are based on State-reported volumes of gas "vented or flared" and a State-by-State estimate of the portion flared. The 1996 estimate of all
vented and flared gas was 269 billion cubic feet. States may define "vented" or "flared" gas differently. This suggests
that estimates may be upwardly biased by the inclusion of nonhydrocarbon gases, such as hydrogen sulfide or carbon
dioxide, in the statistics, but the degree of bias is unknown.
The emissions coefficient applied to flare gas represents the average coefficient for natural gas samples with heat
contents between 1,100 and 1,127 Btu per standard cubic foot. The EIA estimates the heat content of "wet"
gas at 1,106 Btu per standard cubic feet.(217) Anecdotal evidence suggests that most flared gas is flared at gas processing
facilities, where the wet gas energy content would be representative. However, if flared gas is mostly "rich" associated
gas with a heat content between 1,300 and 1,400 Btu per standard cubic feet, the current coefficient seriously biases the
estimates downward. Alternatively, it is possible that flare gas from treatment plants is "off spec" gas with a large
content of hydrogen sulfide or inert gas and, hence, an emissions coefficient lower than the one actually used.
The principal source of uncertainty in cement manufacture is the lime content of cement, which is estimated to within
about 3 percent. There may also be limitations on the inherent accuracy of the Interior Department data used to
calculate the estimate.
A second source of uncertainty, common to all the industrial estimates, is the use of stoichiometric computations to
estimate emissions. This method calculates an emissions factor on the basis of a chemical reaction known to have taken
place. It assumes, in effect, that the product (cement, lime, soda ash) is 100 percent pure, and that no raw materials are
wasted in its production. In practice, impurities in the output would tend to reduce emissions below the stoichiometric
estimate, whereas "wastage" of raw materials would tend to raise emissions above the estimate.
Appendix D lists several sources of emissions that are excluded because of uncertainty. Sources excluded because of
insufficient data include, for example, emissions from natural gas plants. Also, this year, because of another reversal
in the sign of the estimate (the 1996 value is negative), EIA has excluded unmetered gas. Whatever the sign, the impact
on total emissions is likely very small. Taking what is known about all excluded sources, additional emissions would
probably be less than 10 million metric tons, or less than 1 percent of estimated emissions. Nonetheless, their exclusion
does slightly bias the estimate downward. There are almost certainly other sources of carbon emissions unknown to
the authors of this report. There is no way to estimate the impact of such unknown additional sources.
Estimates of methane emissions are, in general, substantially more uncertain than those for carbon dioxide. Methane
emissions are rarely systematically measured. Where systematic measurements have been made, data are restricted
to a small portion of the emission sites and a few years. In order to use these data to estimate emissions for the full
population of emitters and to develop time-series emissions estimates, scaling mechanisms and sampling techniques
must be applied, which will introduce additional error.
Where no systematic measurements have been made, estimation methods rely on a limited set of data applied to a large
and diverse group of emitters. However, as additional data comes available each year, uncertainty in emissions
estimates declines or, at a minimum, is more clearly delineated. In this year's report, additional information on
emissions from coal mining was incorporated into the estimates, reducing uncertainty for this source.
Emissions from coal mines are currently the fourth-largest source of methane emissions in the United States--behind
landfills, oil- and gas-related emissions, and domestic livestock--and they account for approximately 13 percent of
national methane emissions. Methane emissions from coal mining have five sources: ventilation systems in
underground mines, degasification systems in underground mines, surface mines, post-mining activities, and
abandoned or closed mines. Only the first four are included in emissions estimates, because data on emissions from
abandoned mines are lacking. The uncertainty associated with estimates of emissions from each of the sources included
varies considerably and according to the year of the estimate. The exclusion of emissions from abandoned mines results
in a downward bias in the estimates, but the size of the bias is unknown. The overall uncertainty of the EIA estimates
for emissions from coal mines is probably about 35 percent.(218)
Emissions from ventilation systems in the Nation's gassiest mines are measured on a quarterly basis by the Mine Safety
and Health Administration (MSHA). A database, developed by the Bureau of Mines from MSHA reports for all mines
emitting more than 100,000 cubic feet of gas per day, is now maintained by EPA's Atmospheric Pollution Prevention Division. Data on emissions
from this source are available for 1985, 1988, 1990, 1993, 1994, and 1996. Although the measurements themselves should
be reasonably accurate, each measurement represents a point in time. Variations in methane emissions across time (e.g.,
resulting from changes in operating practices) suggest an uncertainty in the range of 10 to 40 percent.
Estimates of emissions from the ventilation systems of nongassy mines are scaled to emissions estimates for 1988
developed by the EPA.(219) The EPA estimates emissions from nongassy mines at 2 percent of total emissions from the
ventilation systems of underground coal mines. Thus, an error as high as 100 percent for this source would add less
than 1 percent to the total estimate.
Emissions from degasification systems may be the single largest source of uncertainty in estimates of emissions from
coal mines. The estimation method used in this report scales emissions to estimates of emissions for 1988 developed
by the EPA. Measurements of emissions were limited to a few mines, and the remainder of the estimate was based on
known emissions from ventilation systems and estimated recovery efficiencies of degasification systems. The recovery
efficiencies have an uncertainty in the neighborhood of 20 percent.
Reliable measurements of emissions from surface mines are available for only five sites. Thus, estimates for this report
were based on an emissions range supplied by the Intergovernmental Panel on Climate Change (IPCC).(220) The range
of emissions suggested by the IPCC implies an uncertainty range of plus or minus 75 percent. However, estimates of
emissions extrapolated from the five measured sites suggest an uncertainty level of less than 10 percent.(221) Assuming
the larger uncertainty level would add only about 10 percent to the overall uncertainty of estimates of emissions from
coal mines, because the volume of emissions from surface mines is relatively insignificant.
Emissions from post-mining activities are also estimated on the basis of an emissions range supplied by the IPCC,
which implies an uncertainty in the area of plus
or minus 60 percent. However, the magnitude of emissions from this source is similar to that of emissions from surface
mines, thus also contributing about 10 percent to the overall uncertainty of coal mine emissions estimates.
The uncertainty associated with emissions estimates from oil and gas operations is twofold: uncertainty associated with
estimates for production, transmission, and distribution; and uncertainty in estimates of emissions from gas venting.
Estimates of emissions from production, transmission, and distribution of natural gas are calculated by extrapolating
measured emissions data for a small number of emissions sources to the full U.S. natural gas system. Data obtained
from a sample of emissions sources are used to develop individual emissions factors for each of the components in the
natural gas system, such as engines, compressors, pipelines, wellheads, and regulators. Emissions factors are then
multiplied by an activity factor that represents either the number of units in the source category or the level of usage
for such units.
In previous editions of Emissions of Greenhouse Gases in the United States, the EIA adopted emissions factors used in a
1990 report on anthropogenic methane emissions prepared by the EPA.(222) These factors were based on very small or
nonrepresentative samples. Emissions factors from oil and gas wells were based on four model facilities. Emissions
factors for distribution pipeline were based on the distribution networks of two California utilities that consisted of
mostly new, low-leakage plastic pipeline. Because much of the Nation's distribution pipeline continues to be cast iron
with a greater propensity to leak, these emissions factors biased estimates substantially downward.
For this year's report, EIA adopted emissions factors from a more recent study funded jointly by EPA and the Gas
Research Institute (GRI).(223) The EPA/GRI study capitalized on an extended field sampling program and a statistical
framework to meet predetermined accuracy goals. The more recent study benefitted
from newly available data on emissions from pneumatic devices and compressors, the number of metering and
regulating stations, and emissions from customer meters. The EPA/GRI study also included distribution systems with
cast iron pipe in its measurement samples.(224) Together, these sources produced about 1.5 million metric tons more
methane in 1992 than had been estimated previously.
While the use of the improved emissions factors from the EPA/GRI report does reduce the overall uncertainty of EIA's
emissions estimate from more than 100 percent on the high end of the range, significant uncertainty remains. The
EPA/GRI study relies on assumptions about important variables, which contribute an unknown measure of
uncertainty to the estimates. The study did not use random sampling or stratified random sampling methods. Instead,
sites for measurement were selected at random from known lists of facilities, such as GRI or American Gas Association
(AGA) member companies. Selected companies were not, however, required to participate. Participating companies
were asked to choose representative sites for sampling rather than one-of-a-kind facilities;(225) however, full geographic
representation in the sample was not achieved. With this sampling technique, the uncertainty of the point estimate of
1992 emissions developed for the EPA/GRI report was plus or minus 35 percent.
The EIA developed time-series emissions estimates for the natural gas industry based on the estimate for 1992
produced by EPA/GRI. As capital stock is replaced or added to the natural gas system, emissions factors may change
somewhat. Thus, the use of time-series estimates probably adds some error. Nevertheless, overall uncertainty should
remain below plus or minus 50 percent.
Estimates of emissions from venting are also uncertain. The EIA maintains statistics on gas vented or flared as reported
on a State-by-State basis, but no distinction is made between venting and flaring in those statistics. Gas flared releases
carbon dioxide rather than methane. This report estimates the national share vented on the basis of the estimated share
vented for each State.
Additional uncertainty is associated with estimates of methane vented at "stripper wells." Associated natural gas
production at oil wells producing less than 10
barrels per day may be at pressures and volumes too low to be of commercial value. The gas may be vented, or it may
evaporate from storage tanks. Such emissions are not captured in any data series, and their magnitude is impossible
to estimate. Stripper wells contribute 14 percent of U.S. oil production.
Most methane emissions from stationary combustion are the result of wood burning in residential woodstoves. Because
estimates of wood consumption and of the condition and efficiency of residential woodstoves are highly uncertain,
estimates of emissions from this source may vary by more than an order of magnitude.
Methane emissions from mobile combustion may be larger than the estimate in this report, but it is unlikely that they
are significantly smaller. Emissions factors for mobile transportation assume a well-maintained fleet. A fleet of
inadequately maintained vehicles may have as much as 10 times the level of emissions of a fleet of well-maintained
or new vehicles. Although much of the U.S. fleet is well-maintained, a portion is old and/or poorly maintained.
Estimates of methane emissions from landfills were broken into two sources: emissions from waste contained in 105
mostly large landfills with gas recovery systems and emissions from waste contained in all other landfills. Uncertainties
associated with estimates of emissions for these two sources differ substantially.
Emissions for many of the 105 mostly large landfills were estimated for 1992 on the basis of volumes of gas recovered
and the efficiency of gas recovery.(226) Gas recovery efficiency was estimated with an associated uncertainty of plus or
minus 25 percent. For years other than 1992, emissions from this source were estimated by using a model of landfill
waste emissions that is benchmarked to the 1992 data. The model parameters include a low yield and high yield
scenario that imply an uncertainty of 35 percent.
Emissions from all other landfills were also estimated from an emissions model, with parameters that could vary by
30 percent from the mean. A crucial input into the model is the amount of waste in place, which was
calculated from estimates of waste landfilled annually between 1960 and 1996 and a regression equation to backcast
waste flows from 1940 to 1960. The range of published estimates for years in which multiple sources were available
suggests an uncertainty in the neighborhood of plus or minus 33 percent, and the error associated with the regression
equation probably adds another 2 to 10 percent uncertainty.(227)
The ratio of waste in place in the 105 landfills relative to that in all other landfills was assumed to remain constant over
time. This may be misleading, because the total number of landfills has been declining, with greater shares of waste
believed to be directed toward larger landfills. Because those landfills with measured emissions for 1992 are likely to
have higher-than-average emissions per ton of waste, estimates may be biased upward in earlier years.
Methane emissions from domestic and commercial wastewater treatment were estimated by IPCC's simplified
approach,(228) which is based on the following assumptions: (1) each person contributes 0.5 kilogram per day of BOD5
to municipal wastewater; (2) 15 percent of wastewater is treated anaerobically; and (3) anaerobic treatment yields 0.22
kilogram of methane per kilogram of BOD5 treated. These assumptions were derived for developed countries in
general, and there is considerable uncertainty about their specific applicability to the United States.
Per capita organic loadings of municipal wastewater in developed nations ranges from 0.024 to 0.091 kilogram BOD5 per day. Organic loadings depend on such factors as the amount of kitchen wastes discharged into sewers and the degree to which industrial wastewaters are discharged into municipal wastewater treatment systems. Wastewater treatment methods that are potential sources of methane include anaerobic digesters, facultative and anaerobic lagoons, and septic tanks. However, reliable information on the quantity of wastewater treated by each of these methods is not available. The IPCC emissions factor of 0.22 kilogram of methane per kilogram of BOD5 is based on an estimate for lagoons in Thailand.(229) The applicability of this factor to treatment methods in the United States is uncertain.
A further source of uncertainty is the ultimate fate of methane generated from wastewater in the United States. As in
the case of landfill methane, wastewater methane generated in sewage treatment plants is often combusted to control
odors or emissions of volatile organic compounds. Conceptually, the amount of methane combusted should be
deducted from estimated emissions, but the EIA is not aware of any information on the amount or extent of
combustion of off-gases from sewage treatment plants.
Estimates of methane emissions from enteric fermentation in domesticated animals are less uncertain than those for
other sources of methane emissions. Emissions estimates are a function of an emissions factor for each animal group,
based on their diet and energy usage multiplied by their population. Animal population data have recently been
revised by the U.S. Department of Agriculture, and the magnitude of revisions shows that population estimates are
likely to be accurate within 5 percent. The energy requirements and diets of cattle-- by far the largest source of
emissions from enteric fermentation--have been carefully studied. There is some uncertainty associated with estimates
of the energy requirements of other animals, but even if this uncertainty were as high as 50 percent, the impact on the
overall estimate would be no more than 3 percent.
There is also some uncertainty associated with the average size of cattle, which could affect the animals' energy
requirements. Cattle sizes have been changing rapidly over the past decade in response to market forces. This report
uses slaughter weights as a proxy for average animal size, a method that may be imperfect. The slaughter sizes vary
over time by approximately 33 percent.
The maximum amount of methane that a given amount of an animal's waste can produce under optimal anaerobic
conditions can be measured fairly accurately in the laboratory. The share of that production realized under various
waste management regimens is much more uncertain. The emissions vary with ambient air temperatures and,
depending on the waste management system, may change by anywhere from 1 to 60 percent
as the temperature changes. For this report, all animal waste was assumed to be managed at air temperatures between
59 and 77oF. Overestimating the average temperature at which waste is managed would bias emissions estimates
upward.
Emissions are tied to the amount of waste an animal produces. The amount of waste produced is a function of size and
diet. Thus, changes in animal sizes, which are difficult to monitor, create additional uncertainty. As discussed above,
slaughter weights have been used as an imperfect measure of changes in animal size. This proxy measure varies by
30 percent over time. Uncertainty in estimates of animal populations is on the order of 5 percent or less.
There are large uncertainties associated with the estimate of methane emissions from wetland rice cultivation.
Emissions estimates are based on several studies of rice paddies in the United States, which provide daily emissions
rate ranges. Studies have shown large seasonal and time-of-day variations in methane flux. Many variables affect
methane production in rice fields, including soil temperature, redox potential, and acidity; substrate and nutrient
availability; addition of chemical and/or organic fertilizers; rate of methane oxidation; and rice plant variety. The wide
range of emissions provided by different researchers suggests an uncertainty of several hundred percent.(230)
Estimates of emissions from the burning of crop residues are calculated according to the default method recommended by the IPCC,(231) which assumes a carbon content of about 45 percent of dry matter and that 10 percent of crop residues are burned. The carbon content probably is uncertain to plus or minus 10 percent, and the share of crop residues burned in the United States is likely to be much smaller than the 10 percent default parameter used. Thus, the estimates are likely to overstate actual emissions.
Estimates of methane emissions from chemical production are highly uncertain because of the wide variety of
production processes and inputs. Organic chemical production requires the cracking and reforming of hydrocarbon
bonds. How the bonds crack and reform depends on several variables, including the composition of the feedstock, the
temperature of the reaction, the catalyst used, and the reaction vessel. As a result, the quantities of products and
byproducts, including methane, vary. Methane may be released through leaks in seals and valves. Therefore, methane
emissions are dependent on the operation and maintenance practices of the producer.
There is substantial uncertainty associated with estimates of methane emissions from iron and steel production, with
the plausible range of estimates ranging from 80 percent below the point estimate presented in this report to 100
percent above the point estimate. Several factors mitigate methane emissions from iron and steel production. The
pollution controls used on coke ovens to prevent emissions of volatile organic compounds usually eliminate methane
as well. Exhaust gases from blast furnaces that are typically captured and used for fuel contain methane. Because the
emissions factors used in this report are global emissions factors provided by the IPCC,(232) they may not accurately
portray the level of emission controls found in U.S. plants. Further, the efficacy of pollution control systems is likely
to vary with operation and maintenance techniques.
Appendix D lists several sources excluded because of excessive uncertainty or insufficient data. Known sources
excluded from methane emissions estimates are industrial wastewater, abandoned coal mines, industrial landfills, and
open dumps. There are other sources of methane that have yet to be identified and thus are
absent from emissions estimates. Excluded sources would invariably add to total emissions, but the magnitude of the
additions is impossible to estimate.
A number of variables are necessary for accurate calculation of nitrous oxide emissions from the application of
fertilizer, including crop type, soil type, nutrient content of the fertilizer, agricultural management practices, and even
climate. In fact, researchers maintain different opinions about the effects, if any, of these variables. While it may be
possible to quantify some of the variables, it is highly unlikely that within the next few years sufficient studies will be
conducted to determine a precise emissions factor. Therefore, the uncertainty range for the estimate presented in this
report is an order of magnitude. Additionally, the estimate does not account for organic fertilizer from human or farm
animal excreta. Although the data are limited, emissions from this type of fertilizer are generally greater than those
from mineral fertilizer.(233) In 1995, nitrous oxide from fertilizer emissions represented approximately 32 percent of U.S.
emissions of nitrous oxides and more than 90 percent of nitrous oxide emissions from agricultural sources.
The accuracy of emissions estimates for crop residue burning is limited, because the practice of burning crop residues
in the United States has not been quantified. As described in Chapter 4, a default figure of 10 percent was used in the
calculation. That figure is believed to be a maximum representation of the practice and could possibly be as much as
an order of magnitude high.
As the result of improved studies, emissions factors recommended by the IPCC are now limited to one value for each
fuel type, regardless of application. Although the emissions factor for coal is 1.4 kilograms of nitrous oxide per terajoule
of energy input, emissions may range from 0 to 10 kilograms. For oil, the recommended emissions factor is 0.6
kilogram, with a possible range of 0 to 2.8 kilograms. The range is
smallest for natural gas (0 to 1.1 kilograms), with 0.1 kilogram as the suggested factor.(234)
The emissions factors were derived from studies of "conventional" combustion facilities (those equipped with burners
and grate combustion, with flame temperatures well beyond 1,000oC). Other types of facilities are used in the United
States, adding to the uncertainty of estimates presented in this report.
For adipic acid production, emissions estimates are based on three data inputs: production activity, an emissions factor,
and emissions abatement activity. The primary sources of uncertainty are the amount of production at plants with
emissions abatement and the effectiveness of the abatement techniques in eliminating nitrous oxide. Additionally, the
emissions factor for adipic acid production was determined by stoichiometry. Moreover, because plant-specific
production figures must be estimated by disaggregating total adipic acid production on the basis of existing plant
capacities, any national estimate will be an imprecise figure if the conversion of nitric acid to adipic acid is less than
100 percent efficient.
The emissions factor for nitric acid production is also uncertain. The DuPont data indicate a range of emissions from
2 to 9 grams of nitrous oxide per kilogram of acid production. Since the midpoint of this range was used in the
calculation, estimates may err by as much as 65 percent. As explained in Chapter 4, applying this emissions factor
range to total production also adds uncertainty, because the emissions reported at the DuPont plant may not be
representative of emissions at all nitric acid production plants.
The emissions estimates presented in Chapter 6 are taken from data in National Air Pollutant Emission Trends, 1900-1995,
a report published by the EPA Office of Air Quality Planning and Standards. Although true values of criteria pollutant
emissions are not known, the EPA states that, "beginning with the 1900 to 1992 report, EPA set the primary goal of
preparing emission trends that would also represent the best available
estimates of emissions."(235) The EPA also explains that one of the difficulties they experience in providing emissions
estimates is balancing consistency of estimation methods with completeness and accuracy of data. Therefore, as new
methods and data become available, emissions estimates may be revised.
Estimates of carbon flux from U.S. forests are subject to several potential sources of error. Uncertainty is introduced
into the estimation method when results of small-scale studies in specific ecosystems are applied to different
ecosystems or to large areas. This is particularly true for the estimate of soil carbon flux. Therefore, EIA provides low,
median, and high estimates for this component, ranging from 0 to 127 million metric tons. The estimates of forest
carbon flux are also subject to bias when data from past studies that do not represent all forest conditions are applied,
when modeling errors are made, and when errors are made in converting estimates from one reporting unit to another.
Forest Service researchers Richard Birdsey and Linda Heath (the primary source of data used by EIA in its estimates
of aggregate carbon flux) did not attempt to estimate the magnitude of these errors but believe that they are probably
small.
In addition, there are two methodological problems common to adding carbon sources and sinks derived from land use data to more conventional greenhouse gas emissions:
There are parts of the United States (some areas in national parks or parts of the interior of Alaska, for example)
that remain close to an undisturbed state and continue to add biomass without human intervention. It is less clear
that this carbon sequestration should "count" as anthropogenic. The broadest definition of anthropogenic would
take the view that because humans control all land use in the United States, all land use decisions, whether of
omission or commission, are anthropogenic acts. This argument might lead to the conclusion that by not cutting
down and burning all its forests, the United States has saved 50 billion metric tons of carbon emissions in each year
in which the forests were not cut down. Alternatively, too narrow a definition of anthropogenic could exclude
unambiguous reforestation activities. There is no single universally acceptable definition of anthropogenic for the
purpose of making an emissions inventory, and any decision that is made will inevitably be arbitrary to some
degree.
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